ITEM 1. BUSINESS
THE COMPANY
Virginia Electric and Power Company was incorporated in 1909 as a Virginia public service corporation. Its principal office is located at 701 East Cary Street, Richmond, Virginia 23219-3932. The telephone number is (804) 771-3000. All of our common stock is held by Dominion Resources, Inc., a Virginia corporation (Dominion).
Virginia Electric and Power Company is a public utility engaged in the power generation and electric service delivery business within a 30,000 square-mile service territory in Virginia and northeastern North Carolina. We supply energy at retail to approximately two million customers. In addition, we sell electricity at wholesale to rural electric cooperatives, power marketers and certain municipalities. Within this document the terms "Virginia Power" and the "Company" refer to the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and all of our subsidiaries.
In Virginia we trade under the name "Virginia Power." The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. In North Carolina we trade under the name "North Carolina Power" and serve retail customers located in the northeastern region of the state, excluding certain municipalities. We also engage in off- system wholesale purchases and sales of electricity and purchases and sales of natural gas and are developing trading relationships beyond the geographic limits of our retail service territory. The Federal Energy Regulatory Commission (FERC), the State Corporation Commission of Virginia (the Virginia Commission) and the North Carolina Utilities Commission (the North Carolina Commission) are the principal regulators of our electric operations.
Various factors are currently affecting the electric utility industry, including increasing competition and related regulatory changes, costs to comply with environmental regulations, and the potential for new business opportunities outside of traditional rate-regulated operations. To meet the challenges of this new competitive environment, we continue to consider new business opportunities, particularly those which allow us to use the expertise and resources developed through our regulated utility experience. Over the past several years we have developed a broad array of "non-traditional" products and services. Examples of non-traditional services include wholesale power marketing and telecommunications. We also market our services to other utilities in areas such as nuclear consulting and management and power distribution (i.e., transmission, distribution, engineering and metering services). We are continuing to focus on new and existing programs to enhance customer satisfaction and energy efficiency.
In preparation for transition to competition for electric generation in Virginia, we have begun to evaluate operating and financial information in the following business segments:
. generation related operations (referred to as the Generation Business). The Generation Business encompasses our generation portfolio, trading and marketing activities, nuclear consulting services and energy services activities.
. regulated electric transmission and distribution services (referred to as the Delivery Business). The Delivery Business includes bulk power transmission, distribution and metering services, and customer service and continues to be subject to cost-based regulation.
Notwithstanding our use of the business segments above, we continue to own and operate all of the Company's historical assets. See Note T to the consolidated financial statements for selected financial information about our business segments.
We had 9,065 full-time employees on December 31, 1999. A total of 3,534 of our employees are represented by the International Brotherhood of Electrical Workers under a contract extending to April 1, 2001.
However on February 1, 2000, approximately 900 of our employees were transferred to a service company called Dominion Resources Services, Inc. (Services), a wholly-owned subsidiary of Dominion, in connection with the merger transaction between Dominion and Consolidated Natural Gas Company (CNG) see ORGANIZATIONAL CHANGES below.
COMPETITION
The structure of the electric industry in our service territory and throughout the United States has been relatively stable for many years. Recently, however, there have been both federal and state developments restructuring regulation and increasing competition. Electric utilities are required to open up their transmission systems for non-discriminatory use by wholesale competitors. In addition, non-utility power marketers now compete with electric utilities in the wholesale generation market. At the federal level, retail competition is under consideration. Some states, including Virginia, have enacted legislation requiring retail competition.
Currently, as in the past, there is no general retail competition in our principal service area. Today our competition for retail sales arises when certain of our business customers move into another utility service territory, use other energy sources instead of electric power, or generate their own electricity. However, Virginia has adopted legislation requiring retail competition beginning in 2002 and North Carolina is considering retail competition. To the extent that competition is permitted, our ability to sell power at prices that will allow us to recover our prudently incurred costs may be an issue. Additionally, we are in the process of developing a retail access pilot program for implementation in Virginia that we expect to implement in the summer of 2000.
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 as described above in an effort to provide growth in future earnings.
For a more thorough review of our changing industry environment see Future Issues--Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A).
ORGANIZATIONAL CHANGES
On January 28, 2000, our parent company Dominion completed its merger transaction with CNG. CNG and its subsidiaries have become wholly-owned subsidiaries of Dominion and, as a result, Dominion has become a registered public utility holding company subject to regulation under the Public Utility Holding Company Act of 1935 (1935 Act). In connection with the merger, a number of organizational changes will be implemented within the Company. Some of these changes will be required as a result of Dominion's new status as a registered public utility holding company under the 1935 Act and some will be based on business decisions relating to the integration of the merged companies.
Dominion has established Services, a service company, to satisfy regulatory requirements and provide administrative and support services to all of Dominion's subsidiaries, including Virginia Power. CNG, which is also a registered public utility holding company, will maintain its existing service company CNG Services, Inc. (CNG Services) for approximately one year. Virginia Power may purchase services from either service company during such period under the terms and conditions set forth in the DRI Services Agreement effective January 1, 2000 between Virginia Power, Services and CNG Services. In addition, we may provide certain administrative and support services to Services under the Virginia Power Support Agreement between Virginia Power and Services effective January 1, 2000. Certain employees of Virginia Power, who have been performing administrative and support service functions, have been transferred to Services and will continue to provide services to Virginia Power as well as to other Dominion affiliates.
REGULATION
General
Many aspects of Virginia Power's business are presently subject to regulation by the Virginia Commission, the North Carolina Commission, FERC, the Environmental Protection Agency (EPA), Department of Energy (DOE), Nuclear Regulatory Commission (NRC), the Army Corps of Engineers and other federal, state and local authorities. Furthermore, with Dominion becoming a registered Public Utility Holding Company under the Act of 1935 both our Generation Business and Delivery Business are now subject to regulation by the Securities and Exchange Commission (SEC).
Virginia Power holds certificates of public convenience and necessity issued by the Virginia Commission and the North Carolina Commission authorizing us to construct and operate the electric facilities now in operation for which certificates are required, and to sell electricity to retail customers. However, we may not construct, or incur financial commitments for construction of, any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal governmental agencies.
The Virginia Commission and the North Carolina Commission regulate the bundled rates of our Generation Business and Delivery Business for retail electric sales and FERC approves our rates for electric sales to wholesale customers.
The following sections discuss various regulatory proceedings in which we are or have recently been involved. Rate specific proceedings are discussed separately in the RATES section below.
Virginia
Virginia Power is subject to the jurisdiction of the Virginia Commission, which has broad powers of supervision and regulation over public utilities, including rates, service regulations and sales of securities. The following is a description of recent Virginia proceedings.
In March 1998, the Virginia Commission issued an Order Establishing Investigation with regard to independent system operators (ISO's), regional power exchanges (RPX's) and retail access pilot programs. The Order directed all investor-owned electric utilities to begin, in conjunction with the Virginia Commission Staff and other interested parties, to develop one or more ISO's and RPX's to serve the public interest in Virginia. The Virginia Electric Utility Restructuring Act (Act), signed into law in 1999, requires that Virginia's incumbent electric utilities join or establish a regional transmission entity (RTE) by January 1, 2001, and seek authorization from the Virginia Commission to transfer operational control of their transmission facilities to such RTE. In May 1999, the Virginia Commission issued an Order Establishing Investigation and invited comments concerning the development of the rules required by the Act. Virginia Power submitted comments in June 1999 and reply comments in July 1999. In January 2000, the Virginia Commission issued an Order giving notice of, and requesting comments to, proposed rules and regulations establishing the elements of RTE structures to be applied by the Virginia Commission in determining whether to authorize the transfer of operational control of the transmission facilities to the RTE. We submitted comments on the proposed rules and regulations in February 2000. Under the proposed rules, we will be required to seek authorization to transfer operational control of our transmission facilities to a RTE on or before May 1, 2000.
In addition, the March 1998 Order instructed Virginia Power and American Electric Power-Virginia (AEP), as the Commonwealth's two largest investor-owned utilities, each to design and file a retail access pilot program. In response, we filed a report describing the details, objectives and characteristics of our proposed retail access pilot program and a hearing was held. We are currently awaiting a Final Order. For more details on the proposed retail access pilot program, see Future Issues--Competition --Regulatory Initiatives under MD&A.
In December 1999, the Virginia Commission issued orders approving the addition of two wholly-owned subsidiaries of Virginia Power Services, Inc., namely Evantage, Inc. (Evantage) and VP Property, Inc. (VP Property), to the Affiliate Services Agreement approved by the Virginia Commission in its September 1997 Order. In connection with the organization of Evantage and VP Property, the Virginia Commission issued two related orders approving our transfer of certain contracts and assets from Virginia Power to these subsidiaries.
In December 1999, in connection with the merger transaction between Dominion and CNG, the Virginia Commission issued an order approving the DRI Service Agreement and the Virginia Power Support Agreement. These agreements provide for administrative, management and other services for Dominion and its subsidiaries.
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 set a hearing date in May 2000 to consider the application.
Federal
The Federal Power Act subjects Virginia Power to regulation by FERC as a company engaged in the transmission or sale of wholesale electric energy in interstate commerce. The Energy Policy Act of 1992 (EPACT) and FERC's subsequent rulemaking activities allow FERC to order access for third parties to transmission facilities owned by another entity. This authority is limited, however, and does not permit FERC to issue orders requiring transmission access to retail customers. FERC has also issued a number of rules of general applicability for third-party transmission service including Orders 888 and 889.
Pursuant to FERC's final rules, we established an open access same-time information system (OASIS) which became operational January 1997. In addition, in July 1997 we filed amendments to our existing rate tariff with FERC so that we could make wholesale power sales at market-based rates. Under a FERC order conditionally accepting our market-based rate schedule, we began making market- based sales of wholesale power in 1997. FERC set for hearing the issue of whether transmission constraints limiting the transfer of power into our service territory would provide us with generation dominance in local markets. This issue was resolved through FERC's acceptance of an offer of settlement in which we agreed to refrain from making sales under our market-based tariff to loads located within our service territory. This settlement did not preclude us from requesting FERC authorization of such sales in the future. However until such authorization has been granted by FERC, agreements by Virginia Power to sell wholesale power to loads located within our service territory are to be at cost-based rates accepted by FERC. We filed an application with FERC in February 2000 to make sales under our market based rate tariff to retail loads within our service territory under our retail access pilot program. Also in February 2000, we filed an application with FERC to amend our open access transmission tariff to accommodate the retail access pilot program.
In June 1999, Virginia Power, along with AEP, First Energy Corp., Consumers Energy Company and The Detroit Edison Company, on behalf of themselves and their respective public utility operating company subsidiaries, filed with FERC applications under Sections 205 and 203 of the Federal Power Act for approval of a proposed regional transmission organization. For more detail on the application, see the INTERCONNECTIONS section below.
North Carolina
The 1997 session of the North Carolina General Assembly created a study commission on the Future of Electric Service in North Carolina. In October 1999, Duke Energy Corp. and Carolina Power and Light Company submitted a proposal to the study commission addressing certain municipal debt issues that must be resolved before a comprehensive restructuring plan can be developed. The North Carolina Commission continues to study the subject of deregulation in anticipation that the 2000 session of the General Assembly will consider the issue when it convenes in May of 2000.
Environmental
We face substantial regulation and compliance costs with respect to environmental matters predominantly in our Generation Business. For discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, see Future Issues-- Environmental Matters, Environmental Protection and Monitoring Expenditures, Clean Air Act Compliance, and Global Climate Change under MD&A.
From time to time we may be identified as a potentially responsible party (PRP) with respect to a superfund site. EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs, but the parties can then bring contribution actions against each other and seek reimbursement from their insurance companies. As a result of the Superfund Act or other laws or regulations regarding the remediation of waste, we may be required to expend amounts on remedial investigations and actions. We do not believe that any currently identified sites will result in significant liabilities. For a discussion of certain remediation efforts in which we are involved, see Environmental Matters, Note R to CONSOLIDATED FINANCIAL STATEMENTS.
In accordance with applicable Federal and state environmental laws, we have applied for or obtained the necessary environmental permits material to the operation of our generating stations. Many of these permits are subject to re- issuance and continuing review.
In April 1999, we were notified by the Department of Justice of alleged noncompliance with EPA's oil spill prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of our power stations. If, in a legal proceeding, such instances of noncompliance are deemed to have occurred, we may be required to remedy any alleged deficiencies and pay civil penalties. Settlement of this matter is currently in negotiation and is not expected to have a material impact on our financial condition or results of operations.
In August 1999, we identified matters at certain other power stations that EPA might view as not in compliance with the SPCC and FRP requirements. We reported these matters to EPA and in December 1999 submitted revised FRP and SPCC plans. Presently, EPA has not assessed any penalties against the Company, pending its review of our disclosure information. Future resolution of these matters is not expected to have a material impact on our financial condition or results of operations.
In November and September 1999, Virginia Power received notices from the Attorney Generals of Connecticut and New York, respectively, of their intention to file suit against the Company for alleged violations of the Clean Air Act. The notices question whether modifications at certain Virginia Power generating facilities were properly permitted under the Clean Air Act and allege that emissions from these facilities have damaged public health and the environment in the Northeast. To date, no suits have been filed. We believe that we are one of a number of companies with fossil fuel power generating stations in the southeast and central U.S. to have received such notifications. We believe that we have obtained the permits necessary in connection with its generating facilities and that any suits filed by the Attorney Generals will not have a material impact on our financial condition or results of operations.
Nuclear Generation
All aspects of the operation and maintenance of our nuclear power stations, which are a part of our Generation Business, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining our nuclear generating units.
One of the issues associated with the operation and decommissioning of nuclear facilities is disposal of spent nuclear fuel (SNF). The Nuclear Waste Policy Act of 1982 required the Federal Government to make available by January 31, 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel. The federal government has not made such a repository available.
In July 1995, the Virginia Commission instituted an investigation regarding SNF disposal. As directed, Virginia Power and others filed comments on legal and public policy issues related to spent nuclear fuel storage and disposal. In February 1996, the Virginia Commission Staff filed its Report recommending that adoption of a definitive policy on SNF disposal issues be delayed pending the outcome of litigation against the DOE concerning spent nuclear fuel acceptance, the outcome of proposed federal legislation concerning development of an interim storage facility and development of a vision of the likely outcome of the electric utility industry's restructuring efforts. The Virginia Commission consolidated the proceeding with our pending fuel cost recovery proceeding in October 1996. On March 20, 1997, the Virginia Commission returned the SNF disposal issue to a separate proceeding. No procedural order has been issued, but the proceeding is pending.
In response to DOE's insufficient progress towards providing a permanent repository for SNF, in January 1997, we and numerous other electric utilities requested the United States Court of Appeals for the District of Columbia Circuit (the DC Circuit) to order the DOE to begin accepting the utilities' SNF for disposal by January 31, 1998. In November 1997, the DC Circuit found that DOE's obligation to begin accepting SNF by the deadline is "unconditional" and that DOE may not excuse its delay on the grounds that delays were unavoidable. In February 1998, we and other electric utilities requested the DC Circuit to require DOE to begin moving SNF, prohibit DOE from using the Nuclear Waste Fund (NWF) to pay damages and relieve utilities of their obligation to pay NWF fees unless and until DOE complies with its obligations. In May 1998, the DC Circuit refused to require DOE to begin moving SNF and found that utilities should pursue their remedies under their SNF contracts with DOE. In November 1998 the U.S. Supreme Court denied DOE's request for review of the DC Circuit's decisions. We are considering whether to seek other remedies.
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 E to CONSOLIDATED FINANCIAL STATEMENTS.
We initiated the license renewal process for our nuclear power plants in mid-1999 with expected submission to the NRC in late 2003. 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.
RATES
The majority of our revenue is provided through bundled rate tariffs. Accordingly, the following discussion applies to both our Generation Business and Delivery Business. Our 1999 electric service sales included 70 million megawatt-hours of retail sales and 4.1 million megawatt-hours of sales to wholesale requirements contract customers and were composed of the following:
- -------- * Excludes power marketing sales which are also subject to FERC regulation.
Substantially all of our electric service sales are currently subject to recovery of changes in fuel costs either through fuel adjustment factors or periodic adjustments to base rates, each of which requires prior regulatory approval. Where cost-based rates are in effect, each of these jurisdictions has the authority to disallow recovery of costs it determines to be excessive or imprudently incurred. Various cost items may be reviewed on occasion, including costs of constructing or modifying facilities, on-going purchases of capacity or providing replacement power during generating unit outages.
Virginia
Recent Virginia proceedings related to our rates include the following:
. In June 1998, Virginia Power, the Staff of the Virginia Commission, the office of the Virginia Attorney General, the Virginia Committee for Fair Utility Rates and the Apartment and Office Building Association of Metropolitan Washington agreed to settle our pending rate proceedings before the Virginia Commission. In August 1998, the Virginia Commission approved the settlement with only a minor redistribution of the agreed rate reduction among customer classes. For provisions of the settlement, see Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
. In August 1998, we filed an application with the Virginia Commission to modify our cogeneration and small power production rates under Schedule 19. An evidentiary hearing was held on this matter in February 1999. The Chief Hearing Examiner's report was issued in February 2000. We filed comments to the Chief Hearing Examiner's report in March 2000.
. In December 1999, we filed an application with the Virginia Commission for an increase in annual fuel revenues of approximately $104 million. A hearing was held in February 2000.
North Carolina
In support of Dominion's request for approval by the North Carolina Commission of its proposed merger with CNG, the Company and Dominion reached an agreement with the North Carolina Utilities Commission whereby we agreed not to request an increase in North Carolina retail electric base rates for both our Generation Business and Delivery Business until after December 31, 2005, except for certain events that would have a significant financial impact on the Company. Such events could include any governmental action or an occurrence that is beyond our control and not attributable to our fault or negligence.
However fuel rates are still subject to change under the annual fuel cost adjustment procedures. The North Carolina Commission approved the merger subject to conditions agreed to by Dominion and Virginia Power in October 1999.
In September 1999, we filed an application with the North Carolina Commission for a $5.2 million increase in fuel rates for our Generation Business. In December 1999, the North Carolina Commission approved our request. This increases the annual fuel rates and charges paid by the retail customers of North Carolina Power effective on January 1, 2000.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Construction And Nuclear Fuel Expenditures
Our estimated construction and nuclear fuel expenditures for the three-year period 2000-2002 total $1.1 billion for the Generation Business and $1.3 billion for the Delivery Business. The estimated 2000 construction and nuclear fuel expenditures amount to $856 million consisting of $462 million for the Generation Business and $394 million for the Delivery Business.
Financing Program
We currently have three shelf registration statements on file with the SEC and the Virginia Commission providing us with a remaining aggregate amount of $740 million of capital resources for both our Generation Business and Delivery Business.
We intend to issue securities from time to time to meet our capital requirements, which include $375 million of long-term debt and preferred stock maturities due in 2000.
See Liquidity and Capital Resources section of MD&A for details about our financing program.
SOURCES OF POWER
Virginia Power Generating Units
- -------- (a) Includes an undivided interest of 11.6 percent (208 MW) owned by Old Dominion Electric Cooperative (ODEC). (b) Includes an undivided interest of 50 percent (441 MW) owned by ODEC. (c) This unit was returned to service in May 1999. (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).
Virginia Power'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.
SOURCES OF ENERGY USED, FUEL COSTS AND OPERATIONS
For information as to energy supply mix and the average fuel cost of energy supply, see Results of Operations under MD&A.
Generation Business
Nuclear Operations and Fuel Supply
. In 1999, our four nuclear units achieved a combined capacity factor of 95.2 percent.
. We utilize both long-term contracts and spot purchases to support our needs for nuclear fuel. We continually evaluate worldwide market conditions in order to ensure a range of supply options at reasonable prices. Current agreements, inventories and spot market availability will support our current and planned fuel supply needs for fuel cycles into the early 2000's. Beyond that period, additional fuel will be purchased as required to ensure optimum cost and inventory levels.
. In March 1999, Virginia Power, 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. Futhermore, 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 Virginia Power for all plant and site/facility modifications as well as other MOX fuel implementation costs. We expect to provide irradiation services beginning September 2007.
. The DOE did not begin the acceptance of SNF in 1998 as specified in our contract with the DOE. However, on-site SNF pool and dry container storage at the Surry and North Anna Power Stations is expected to be adequate for our needs until the DOE begins accepting SNF.
For details on the issues of decommissioning and nuclear insurance, see Note E to CONSOLIDATED FINANCIAL STATEMENTS.
Fossil Operations and Fuel Supply
The fuel mix utilized by our Generation Business fossil operations consists of coal, oil and natural gas. During 1999, we burned approximately 14 million tons of coal. We utilize both long-term contracts and spot purchases to support our coal needs. We presently anticipate sufficient supplies of coal will be available at reasonable prices for the next 5 to 10 years. A sufficient supply of oil and natural gas is expected over the same period with stable prices.
We use natural gas as needed throughout the year primarily for three combined-cycle units and at several combustion turbine units. For winter usage at the combined-cycle sites, gas is purchased and stored during the summer and fall and consumed during the colder months when gas supplies may not be available. We have firm transportation contracts for the delivery of gas to the Chesterfield combined-cycle units.
Purchases and Sales of Energy
Our Generation Business purchases electricity under contracts with other suppliers to meet a portion of our own system capacity requirements, and makes other wholesale electric power transactions in the eastern United States. In addition to wholesale electric power transactions, we also actively participate in the purchase and sale of natural gas in the open market.
From the mid-1980's until the start of the 1990's, we entered into a number of long-term purchase contracts for electricity now associated with our Generation Business. At the end of 1999, 900 MW of these purchases from other utilities ended, and by the end of the first quarter of 2000, an additional 200 MW of diversity exchange transactions will be suspended. However, we continue to have contracts with 56 non-utility generators with a combined dependable summer capacity of 3,273 MW. During 1998, we entered into a long- term agreement to purchase 566 MW of electricity for sale to the wholesale market from two of three generating units at a plant constructed in Mississippi. For information on the financial obligations under these agreements, see Purchased Power Contracts, Note R to CONSOLIDATED FINANCIAL STATEMENTS.
In a continuing effort to mitigate our exposure to above-market long-term purchased power contracts, we are evaluating our long-term purchased power contracts and negotiating modifications to their terms, including cancellations, where it is determined to be economically advantageous to do so.
In 1997, we executed three agreements associated with both our Generation Business and Delivery Business with ODEC which provide for the amendment of the parties' Interconnection and Operating Agreement (I&O Agreement). The first agreement provides for the transition from cost-based rates for capacity and energy purchases by ODEC to market-based rates by 2002. The second two agreements are the Service and Operating Agreements for Network Integration Transmission Service, which unbundled the transmission services provided to ODEC under the I&O Agreement.
FUTURE SOURCES OF POWER
Both the Hoosier 400 MW long-term purchase contract and the AEP 500 MW long- term purchase contract expired on December 31, 1999. We presently anticipate adding peaking capacity beginning in the year 2000 to meet our anticipated annual load growth of 2 percent. In addition, work was completed and the North Branch unit was returned to full operational capacity on in May 1999.
On May 14, 1999, the Virginia Commission approved our construction of four gas-fired combustion turbine generator units in Fauquier County, Virginia. A Petition to Appeal the approved units, filed by an opposing party in July 1999, was dismissed by the Virginia Supreme Court in December 1999; however, the opposing party filed a request for rehearing on December 31, 1999. The same party appealed the air permit issued to us by the Virginia Department of Environmental Quality; however, such appeal was withdrawn on January 18, 2000.
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 has set a hearing date in May 2000 to consider our request. Commercial operation is planned to begin June 2001.
INTERCONNECTIONS
Our Delivery Business maintains major interconnections with Carolina Power and Light Company, AEP, AE and the utilities in the Pennsylvania-New Jersey- Maryland Power Pool. Through this major transmission network, we have arrangements with these utilities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy.
In June 1999, Virginia Power, 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 Regional Transmission Organization (Alliance RTO).
In December 1999, FERC issued an Order under Section 203 of the Federal Power Act granting the application, subject to certain conditions and requirements discussed in the Order and directing the Alliance Companies to submit a compliance filing as discussed in the Order. On January 19, 2000, the Alliance Companies filed an application seeking rehearing of certain conditions and requirements of the Order. In February 2000, the Alliance Companies filed amendments to the Alliance RTO documents to comply with certain conditions and requirements of the Order.
Also in December 1999, FERC issued Order 2000 which amended its regulations to advance the formation of Regional Transmission Organizations (RTOs). The regulations require that each public utility that owns, operates, or controls transmission facilities make certain filings with respect to forming and participating in an RTO. FERC also codified minimum characteristics and functions that a transmission entity must satisfy in order to be considered an RTO. In January 2000, the Alliance Companies filed an application seeking rehearing of certain provisions of the Order.
See REGULATION--Virginia above for a discussion of that state's laws and proceedings relating to the establishment of regional transmission entities.
ITEM 2.
ITEM 2. PROPERTIES
We own our principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of Virginia Power's property is subject to the lien of a mortgage securing our First and Refunding Mortgage Bonds.
In connection with our Delivery Business, right-of-way grants from the apparent owners of real estate have been obtained for most of our electric lines, but underlying titles have not been examined except for transmission lines of 69 Kv or more. Where rights of way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly owned property, as to which permission for use is generally revocable. Portions of our transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line if any exists.
Our Generation Business and Delivery Business share certain leased buildings and equipment.
See Virginia Power Generating Units- SOURCES OF POWER under Item 1. BUSINESS for a list of the principal facilities utilized by our Generation Business.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. From time to time, there may be pending administrative proceedings on these matters. In addition, in the normal course of business, we are involved in various legal proceedings. We believe that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations.
See REGULATION and RATES under Item 1. BUSINESS for information on various regulatory proceedings to which we are a party.
Environmental Matters
In April 1999, we were notified by the Department of Justice of alleged noncompliance with the EPA's oil spill prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of our power stations. If, in a legal proceeding, such instances of noncompliance are deemed to have
occurred, we may be required to remedy any alleged deficiencies and pay civil penalties. Settlement of this matter is currently in negotiation and is not expected to have a material impact on our Company's financial condition or results of operations.
In August 1999, we identified matters at certain other power stations that the EPA might view as not in compliance with the SPCC and FRP requirements. We reported these matters to the EPA and our plan for correction thereof. Presently, the EPA has not assessed any penalties against us, pending its review of the disclosure information. Future resolution of these matters is not expected to have a material impact on the Company's financial condition or results of operations.
Clean Air Act Matters
On November 8, 1999 and September 21, 1999, we received notices from the Attorney Generals of Connecticut and New York, respectively, of their intention to file suit against the Company for alleged violations of the Clean Air Act. The notices question whether modifications at certain Virginia Power generating facilities were properly permitted under the Clean Air Act and allege that emissions from these facilities have contributed to damage to public health and the environment in the Northeast. To date, no suits have been filed. We believe, based on newspaper reports and other sources, that we are one of a number of companies with fossil fuel power generating stations in the southeast and central U.S. to have received such notifications. We believe that we have obtained the permits necessary in connection with our generating facilities and that suits, if any, filed by the Attorney Generals will not have a material impact on our Company's financial condition or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On January 21, 2000, by consent in lieu of a meeting, Dominion Resources, Inc., the sole holder of all the voting Common Stock of Virginia Power, elected the following persons to serve as Directors of the Company: Thos. E. Capps, Jean E. Clary, Thomas F. Farrell, II, Edgar M. Roach, Jr., William G. Thomas.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Dominion Resources, Inc. (Dominion) owns all of the Company's common stock.
The Company paid quarterly cash dividends on its common stock as follows:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
- -------- (*) Revenue for 1995, 1996, and the first eight months of 1997 includes revenue associated with power marketing and gas sales with related cost of sales of such operations recorded as a component of fuel, net. The Company experienced significant growth in its power marketing operations in 1997 relative to prior years. Beginning in September 1997, the Company recorded the results of its power marketing and gas sales operations, not subject to cost-based rate regulation, as a component of other revenue net of related cost of sales. (**) Revenue for 1998 reflects the Company's settlement of base rate proceedings which included a one-time rate refund of $150 million and a base rate reduction of $100 million beginning in March 1998. Net income for 1998 reflects the aforementioned base rate refund and rate reduction as well as an impairment charge of $159 million to write-off net regulatory assets no longer considered recoverable as a result of the rate settlement. See Note Q to CONSOLIDATED FINANCIAL STATEMENTS. (***) In 1999, the Company discontinued the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, to its generation operations in connection with the deregulation of these operations in Virginia. The discontinuance of SFAS No. 71 for generation resulted in a $255 million after-tax charge recorded in the first quarter of 1999. See Note B to CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This Management's Discussion and Analysis of Financial Condition and Results of Operations contains "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including (without limitation) discussions as to expectations, beliefs, plans, objectives and future financial performance, or assumptions underlying or concerning matters discussed in this document. These discussions, and any other discussions, including certain contingency matters (and their respective cautionary statements) discussed elsewhere in this report, that are not historical facts, are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.
Our business and financial condition are influenced by a number of factors including political and economic risks, market demand for energy, inflation, capital market conditions, governmental policies, legislative and regulatory actions (including those of FERC, EPA, DOE, NRC, Virginia Commission and North Carolina Commission), industry and rate structure and legal and administrative proceedings. Some other important factors that could cause actual results or outcomes to differ materially from those discussed in the forward-looking statements include changes in and compliance with environmental laws and policies, weather conditions and catastrophic weather-related damage, present or prospective wholesale and retail competition, competition for new energy development opportunities, pricing and transportation of commodities, operation of nuclear power facilities, acquisition and disposition of assets and facilities, nuclear decommissioning costs, exposure to changes in the fair value of commodity contracts, counter-party credit risk and unanticipated changes in operating expenses and capital expenditures. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond the control of Virginia Power. New factors emerge from time to time and it is not possible to predict all such factors, nor can we assess the impact of each such factor on Virginia Power.
Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.
Business Segments
We manage our operations in a manner that requires disclosure of two business segments--the Generation Business and the Delivery Business. The Generation Business includes our portfolio of generating facilities and purchased power contracts, trading and marketing activities, nuclear consulting services, and energy services activities. The Delivery Business includes bulk power transmission, distribution and metering services, and customer service and continues to be subject to cost-based regulation.
The majority of our revenue is provided through bundled rate tariffs. Such revenue is allocated between the Generation Business and Delivery Business for internal reporting purposes and discussion herein. Certain activities discussed in Liquidity and Capital Resources are not managed currently at the segment level; however, specific references to segments are made as appropriate. Our discussion of trends and variations generally applies to the Company as a whole.
Liquidity And Capital Resources
Operating activities continue to be a strong source of cash flow, providing approximately $1.1 billion in each of the years 1999, 1998, and 1997, respectively. Over the past three years, cash flow from operating activities, after dividend payments, has, on average, covered 120 percent of our total construction requirements and provided 77 percent of our total cash requirements. Cash requirements not met by the timing or amount of cash flow from operations are generally satisfied with proceeds from the sale of securities and short-term borrowings.
Financing activities have represented a net outflow of cash in recent years as strong cash flow from operating activities have reduced our need for debt or equity financing.
Cash flow from (used in) financing activities was as follows:
During 1999, we issued $305 million in aggregate principal of unsecured debt securities. In June 1999, we issued $150 million in aggregate principal of unsecured Senior Notes, Series 1999-A, with an annual coupon rate of 6.7%, due June 2009; and $80 million of Medium-Term Notes, Series G, with an annual coupon rate of 6.3%, due June 2001. In November 1999, we issued $75 million in aggregate principal of unsecured Senior Notes, Series 1999-B, with an annual coupon rate of 7.2%, due 2004.
During 1999, we retired $321 million in aggregate principal amount of mandatory debt maturities. In July 1999, we repurchased $24 million in aggregate principal amount of First and Refunding Mortgage Bonds that became available through the open market.
As of December 31, 1999, we have $740 million of securities under effective shelf registrations with the Securities and Exchange Commission available for our use to meet capital requirements.
We have a commercial paper program that is supported by two credit facilities totaling $500 million. Proceeds from the sale of commercial paper are primarily used to provide working capital. Net borrowings under the program were $378 million at December 31, 1999.
Cash flow used in investing activities was as follows:
Plant and equipment expenditures for generation-related projects were approximately $327 million in 1999 and included significant expenditures for additional capacity and environmental upgrades--See Capital Requirements below. Transmission and distribution-related projects accounted for approximately $282 million of our total plant and equipment expenditures. These projects included routine capital improvements and expenditures associated with new connections. Remaining plant and equipment expenditures of $64 million reflect general projects and information technology enhancements. Our information technology projects include development of remote metering and dispatch technology and continued improvements to our financial systems.
Capital Requirements
Capacity--We anticipate that peak demand will grow approximately 2 percent a year through 2002. We expect to complete construction of four 150 MW combustion turbines in Fauquier County, Virginia by midyear 2000. We anticipate spending an estimated $190 million on the total project of which approximately $145 million has been incurred through December 31, 1999. In January 2000, we filed for approval from the Virginia Commission for the construction of two combustion turbines in Caroline County, Virginia. The Virginia Commission has set a hearing date in May 2000 to consider this request. We expect that any future additional capacity and energy requirements will be met through a combination of market purchases and Company-constructed generation.
Plant and equipment--Our construction and nuclear fuel expenditures during 2000, 2001 and 2002 are expected to total $856 million, $822 million and $760 million, respectively. We expect these construction and nuclear fuel expenditures to be met through cash flow from operations, sales of securities and short-term borrowings.
We are installing sulfur dioxide (SO\\2\\) emission control equipment at two coal-fired generating units. The total cost for this project is estimated to be $126 million of which $33 million has been incurred as of December 31, 1999. We believe the installation of scrubbers on these two units will provide the most cost effective means of complying with the Clean Air Act.
In response to a rule adopted by the EPA in September 1998, we plan to install nitrogen oxide (NOx) reduction equipment on some of our generating units at an estimated capital cost of $454 million over the next five years. Whether these costs are actually incurred is dependent on the implementation plans adopted by the states in which we operate. No significant costs have been incurred as of December 31, 1999. See Future Issues--Clean Air Act Compliance.
Maturities--We will require $375 million to meet maturities of securities in 2000.
We expect to fund our capital requirements and maturities with cash flow from operations and a combination of sales of securities and short-term borrowings.
Results Of Operations
General
This section provides a general discussion of factors that affect revenue of both our Generation and Delivery Businesses and a discussion of fluctuations in certain expenses, which are not allocated separately to the Generation and Delivery Businesses.
Total Revenue for fiscal years 1999, 1998, and 1997 was allocated to the Generation and Delivery Businesses as follows:
- -------- * See Note T to CONSOLIDATED FINANCIAL STATEMENTS for discussion of the nature of this line item.
The following factors contributed to the increase in Electric service revenue in 1999 over 1998 and the decrease in 1998 over 1997:
Electric service revenue consists primarily of sales to retail customers in our service territory at rates authorized by the Virginia Commission and North Carolina Commission, and sales to cooperatives and municipalities at wholesale rates authorized by FERC. Also included in electric service revenue are amounts received from others for use of our transmission system to transport electric energy under tariffs authorized by FERC. The primary factors affecting electric service revenue in both fiscal years 1999 and 1998 were customer growth and changes in rates.
Retail customer growth--Our retail customer base increased by approximately 39,000 in 1999 and 35,000 in 1998 over the respective prior year periods. These additional customers increased our electric service revenue by an estimated $68 million in 1999 compared to 1998, and an estimated $60 million in 1998 compared to 1997.
Weather--Weather typically has a significant impact on our electric service revenue. However, for the comparative periods presented, weather did not have a significant impact.
Base rate refund and base rate reduction--Electric service revenue in 1998 was less than electric service revenue in both 1999 and 1997 as a result of the one-time base rate refund of $150 million recorded in 1998 as part of our settlement to resolve then outstanding rate proceedings. In addition, we agreed to a two-phased rate reduction, $100 million effective March 1, 1998 and an additional $50 million effective March 1, 1999. This two-phased rate reduction reduced 1999 electric service revenue by $57 million compared to 1998, and it reduced 1998 revenue by $88 million compared to 1997. See Note Q to CONSOLIDATED FINANCIAL STATEMENTS. As a result of Virginia law enacted in 1999, our Virginia jurisdictional base rates will remain unchanged until July 2007. See Note B to CONSOLIDATED FINANCIAL STATEMENTS.
Fuel rates--Currently, we are permitted to recover the cost of fuel used in generating electricity through fuel rates approved by regulatory authorities. The decrease in 1998 fuel rate revenue, as compared to 1997, was primarily attributable to lower fuel rates that became effective in December 1997, March 1998 and May 1998. These reductions recognized savings from negotiated changes to power supply contracts in December 1998, our annual fuel case resulted in an increase in fuel rates. This increase partially offset the aforementioned fuel rate reductions in 1998 and favorably affected electric service revenue in 1999 as our overall fuel rates in 1999 exceeded those in 1998.
Other electric service revenue increased in 1999, as compared to 1998, due to increased revenue for electric transmission services. The decrease in other electric service revenue in 1998, as compared to 1997, reflected reduced revenue associated with certain renegotiated long-term wholesale requirements contracts partially offset by increased revenue for electric transmission services.
Certain expenses, which are not allocated separately to the Generation Business and Delivery Business, changed as follows when compared to the respective prior years:
1999 Compared to 1998
Impairment of regulatory assets in 1998 was a write down of regulatory assets as a result of our settlement of the Virginia rate proceeding. See Note Q to the CONSOLIDATED FINANCIAL STATEMENTS.
Interest expense, net decreased in 1999, as compared to 1998, due in part to the interest cost associated with the one-time base rate refund paid in 1998 as part of the settlement of our Virginia rate proceeding. See Note Q to CONSOLIDATED FINANCIAL STATEMENTS. In addition, upon discontinuance of SFAS No. 71, we began capitalizing interest in accordance with SFAS No. 34, Capitalization of Interest Cost, as part of our generation-related construction projects.
Extraordinary item--This extraordinary item was recorded in connection with the passage of new legislation in 1999 establishing a detailed plan to restructure the electric utility industry in Virginia. The legislation's deregulation of generation was an event that required discontinuation of SFAS No. 71 for our generation operations. Generation-related assets and liabilities not expected to be recovered through cost-based rates were written off in March 1999, resulting in an after-tax charge of $255 million. See Note B to CONSOLIDATED FINANCIAL STATEMENTS.
1998 Compared to 1997
Impairment of regulatory assets In 1998 there was a write down of regulatory assets on the result of our settlement of the Virginia rate proceeding. See Note Q to CONSOLIDATED FINANCIAL STATEMENTS. The 1997 amount represented a reserve for potential adjustments to regulatory assets.
Depreciation and amortization decreased in 1998 as compared to 1997 due to adjustments to the provision for depreciation and decommissioning expenses to reflect terms of the settlement of our Virginia rate proceeding. See Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
Generation Business
Net income for our Generation Business increased in 1999 as compared to 1998. This increase was primarily attributable to changes in the composition and the fair value of our portfolio of commodity contracts as well as the settlement of commodity contract liabilities using Company resources rather than market purchases. The decrease in our Generation Business net income in 1998, as compared to 1997, reflected primarily the impact of base rate reductions, as noted in our general discussion of electric service revenue above, and increased operating expenses. Selected financial information relevant to our Generation Business is as follows:
Other revenue includes sales of electricity beyond our service territory and sales of natural gas, nuclear consulting services, energy management services and other revenue. The increase in other revenue in 1999 over 1998 reflects primarily changes in the composition and fair value of our portfolio of commodity contracts. Other revenue decreased in 1998 as compared to 1997 due to electricity trading revenue being reported net of purchased energy for the entirety of 1998 and only for the last four months of 1997. Such revenue was reported gross for the first eight months of 1997 as a result of being subject to cost of service rate regulation during that time.
Fuel, net increased in 1999, as compared to 1998, primarily due to increased fuel costs resulting from higher production from our generating units and increased energy purchases. Fuel, net decreased in 1998, as compared to 1997, primarily due to the inclusion of the cost of power marketing purchases for the first eight months of 1997. The cost of power marketing purchases since September 1997 and the entirety of 1998 is reported net of related revenue in other revenue. Prior to September 1997, this activity was subject to cost of service rate regulation.
System energy output by energy source and the average fuel cost for each are shown below. Fuel cost is presented in mills (one tenth of one cent) per kilowatt hour.
- -------- (*) Excludes Old Dominion Electric Cooperative's (ODEC) 11.6 percent ownership interest in the North Anna Power Station. (**) Excludes ODEC's 50 percent ownership interest in the Clover Power Station.
Purchased power capacity, net increased in 1998 as compared to 1997 primarily due to increased expenses associated with the restructuring of certain contracts and the discontinuance of deferral accounting for such expenses. See Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
Operations and maintenance increased in 1999 as compared to 1998, primarily as a result of: increased maintenance activities performed during planned outages at our fossil plants; adjustments to inventories related to the planned disposal of identified obsolete and excess materials and supplies; and the effect of certain accounting policy changes that resulted from the discontinuance of SFAS No. 71, including the recognition of losses on retirement of equipment and related removal costs. See Note A to CONSOLIDATED FINANCIAL STATEMENTS.
Delivery Business
Overall, net income associated with our Delivery Business increased in 1999, as compared to 1998, primarily due to an increase in revenue for electric transmission services and from retail electric service customer growth, offset in part by increased expenses associated with storm damage. The decrease in Delivery Business net income in 1998, as compared to 1997, reflects primarily the excess of increased storm damage costs and routine operational expenses over the increase in revenue for electric transmission services. Selected financial information relevant to our Delivery Business is as follows:
Electric service revenue increased in 1999 and 1998, as compared to the respective prior years, due to increased revenue for electric transmission services and from retail customer growth.
Operations and maintenance increased in 1999 and 1998, as compared to respective prior years, primarily due to increased service restoration costs associated with storm damage.
Future Issues
Competition--General
We have recently seen federal and state developments toward increased competition. Electric utilities have been required to open their transmission systems for use by potential wholesale competitors. In addition, non-utility power producers now compete with electric utilities in the wholesale generation market. At the federal level, retail competition is under consideration. Some states, including Virginia, have already enacted legislation requiring the introduction of retail competition.
Today, we face competition in the wholesale market. There is no general retail competition in our principal service area at this time. However, during its 1998 session, the Virginia legislature passed a law that requires a transition to retail competition between January 1, 2002 and January 1, 2004. See Competition--Retail and Competition--Legislative Initiatives below. We actively supported this restructuring legislation, which provided the necessary details to implement the legislation passed in 1998.
We have responded to the trend toward competition by cutting costs, re- engineering our core business processes, and pursuing innovative approaches to serving traditional markets and future markets. Our strategy also includes the development of non-traditional products and services with an objective of providing growth in future earnings. These products and services include electric energy and capacity in the emerging wholesale market; natural gas and other energy-related products and services; nuclear management and consulting services; power distribution and transmission related services, including engineering and metering; and telecommunication services. In addition, we may from time to time, identify and investigate opportunities to expand our markets through strategic alliances with partners whose strengths, market position and strategies complement those of Virginia Power.
Competition--Wholesale
We sell electricity in the wholesale market under our market based sales tariff authorized by FERC, but have agreed not to make wholesale power sales under this tariff to loads located within our service territory. However, we filed in February 2000 an application with FERC to make sales under our
market-based sales tariff to loads within our service territory to facilitate our retail access pilot program. Also, we filed in February 2000, an application with FERC to amend our open access transmission tariff to accommodate the retail access pilot program proposed in Virginia. See Competition-Regulatory Initiatives below. Until such authorization has been granted by FERC, any agreements which allow us to sell wholesale power to loads located within our service territory are to be at cost-based rates accepted by FERC.
During 1999, sales to wholesale customers under requirements contracts represented approximately 4 percent of our total electric service revenue. Since FERC issued its Order 888 requiring open access to transmission service, we have faced increased competitive pressures on sales to wholesale customers served under requirements contracts. In response, we have renegotiated long- term contracts with wholesale customers. We have also implemented a new arrangement with our largest wholesale customer that provides for a transition from cost-based rates to market-based rates.
Competition--Retail
Currently, we have the exclusive right to provide electricity at retail within our assigned service territories in Virginia and North Carolina. As a result, our Company now faces competition for retail sales to the extent our business customers move into another utility service territory, use other energy sources instead of electric power, or generate their own electricity.
However, in 1998, the Virginia General Assembly passed legislation that established a timeline for deregulation of retail electric service but left the details regarding implementation to future enabling legislation. In March 1999, the Governor of Virginia signed into law new legislation establishing a detailed plan to restructure the electric utility industry in Virginia which provides for customer choice beginning in 2002. Under this legislation, our base rates will remain unchanged until July 2007 and recovery of generation- related costs will continue to be provided through capped rates and a wires charge assessed to those customers opting for alternate suppliers. See Note B to CONSOLIDATED FINANCIAL STATEMENTS. For a discussion of the Company's pilot program for customer choice beginning in 2000, see Competition-Regulatory Initiatives below.
Competition--Legislative Initiatives
Virginia
As discussed above, the Governor of Virginia signed into law legislation establishing a detailed plan to restructure the electric utility industry. Under the legislation, the generation portion of the Company's Virginia jurisdictional operations will no longer be subject to cost-based rate regulation beginning in 2002.
Under the legislation, a transition task force has been charged to work with the Virginia Commission during the phase-in of retail competition. The task force has been charged with specific assignments including the monitoring of possible over or under-recovery of stranded costs by incumbent utilities. This monitoring begins at the onset of customer choice, and the task force will submit annual reports to the Governor and the General Assembly offering recommendations as it deems necessary.
The legislation also addressed divestiture, functional separation and other corporate relationships. Although mandatory divestiture is prohibited, functional separation is required and must be completed by January 1, 2002. Utilities must submit their plans to the Virginia Commission by January 1, 2001, outlining steps to be taken to functionally separate generation, transmission and distribution.
We are currently supporting certain technical amendments to the restructuring legislation being considered by the 2000 General Assembly.
North Carolina
The 1997 session of the North Carolina General Assembly created a study commission on the future of electric service in North Carolina. In October 1999, Duke Energy Corp. and Carolina Power and Light Company submitted a proposal to the study commission addressing certain municipal debt issues that must be
resolved before a comprehensive restructuring plan can be developed. The North Carolina Commission continues to study the subject of deregulation in anticipation that the 2000 session of the General Assembly will consider the issue when it convenes in May of 2000.
Federal
The U.S. Congress is expected to consider federal legislation in the near future authorizing or requiring retail competition. Virginia Power cannot predict what, if any, definitive actions the Congress may take.
Competition--Regulatory Initiatives
Virginia
In March 1998, the Virginia Commission issued an order instructing Virginia Power and AEP-Virginia as Virginia's two largest investor-owned utilities, each to design and file a retail access pilot program. We filed a report in November 1998, describing the details, objectives and characteristics of our proposed retail access pilot program. In August 1999, the Virginia Commission's hearing examiner issued a report interim rules for the introduction of electric and natural gas retail competition in Virginia. In September 1999, the Company, the Virginia Commission and two other parties entered into a stipulated agreement which resolved the size and scope of the proposed pilot program and the methodology for determining the market price of electricity used in calculating the wires charge assessed to those customers opting for alternate suppliers. The pilot program will initially give approximately 35,000 customers the ability to choose their electric supplier. The scope of the program will be expanded to include approximately 70,000 customers by year end 2000. A hearing was held in September 1999. The Hearing Examiner's Report was issued in November 1999, recommending certain changes to our pilot plan and a modification of the stipulated market price methodology. We filed comments and exceptions in December 1999. A Final Order from the Virginia Commission is anticipated in early 2000.
In March 1998, the Virginia Commission issued an Order Establishing Investigation with regard to independent system operators (ISO's), regional power exchanges (RPX's) and retail access pilot programs. The Order directed all investor-owned electric utilities to begin work, in conjunction with the staff of the Virginia Commission and other interested parties, to develop one or more ISO's and RPX's to serve the public interest in Virginia. The Virginia Electric Utility Restructuring Act (Act), signed into law in 1999, requires that Virginia's incumbent electric utilities join or establish regional transmission entities (RTE's) by January 1, 2001, and seek authorization from the Virginia Commission to transfer ownership or operational control of their transmission facilities to such RTE's. In May 1999, the Virginia Commission issued an Order Establishing Investigation and invited comments concerning the development of the rules required by the Act. We submitted comments in June 1999 and reply comments in July 1999. In January 2000, the Virginia Commission issued an Order giving notice of, and requesting comments to, the proposed rules and regulations establishing the elements of RTE structures. We submitted comments on the proposed rules and regulations in February 2000. Under the proposed rule, we will be required to seek authorization to transfer operational control of our transmission facilities on or before May 1, 2000.
Federal
Our Delivery Business maintains major interconnections with Carolina Power and Light Company, AEP, Allegheny Energy and the utilities in the Pennsylvania- New Jersey-Maryland Power Pool. Through this major transmission network, we have arrangements for coordinated planning, operation, emergency assistance and exchanges of capacity and energy.
In June 1999, Virginia Power, 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 Regional Transmission Organization (Alliance RTO).
In December 1999, FERC issued an Order under Section 203 of the Federal Power Act granting the application, subject to certain conditions and requirements discussed in the Order and directing the Alliance Companies to submit a compliance filing as discussed in the Order. In January 2000, the Alliance Companies filed an application seeking rehearing of certain conditions and requirements of the Order. In February 2000, the Alliance Companies filed amendments to the Alliance RTO documents to comply with certain conditions and requirements of the Order.
Also, in December 1999, FERC issued Order 2000 which amended its regulations to advance the formation of Regional Transmission Organizations (RTO's). The regulations require that each public utility that owns, operates or controls transmission facilities make certain filings with respect to forming and participating in an RTO. FERC also codified minimum characteristics and functions that a transmission entity must satisfy in order to be considered an RTO. In January 2000, the Alliance Companies filed an application seeking rehearing of certain provisions of the Order.
Competition--Exposure To Potentially Stranded Costs
Under traditional cost-based regulation, utilities have generally had an obligation to serve, supported by an implicit promise of the opportunity to recover prudently incurred 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, 1999, our 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, Note R to the CONSOLIDATED FINANCIAL STATEMENTS);
. 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 Note E and Note P to CONSOLIDATED FINANCIAL STATEMENTS).
We believe capped rates provided under the 1999 deregulation legislation present a reasonable opportunity to recover a substantial portion of our potentially stranded costs. In the absence of capped rates, we would have otherwise been exposed, on a pre-tax basis, to an estimated $3.2 billion of potential losses related to long-term power purchase commitments. See Note B to CONSOLIDATED FINANCIAL STATEMENTS. Recovery of our 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, decommissioning costs, inflation, increased capital costs, and recovery of certain other items.
Rate Matters
In support of Dominion's request for approval by the North Carolina Commission of its merger with Consolidated Natural Gas Company (CNG), we and Dominion reached an agreement with the Public Staff of the North Carolina Commission whereby we agreed not to request any increase in our North Carolina retail electric base rates until after December 31, 2005, except for certain events that would have a significant financial impact on our Company. Such events could include any governmental action or an occurrence that is beyond our control and not attributable to our fault or negligence. However, fuel rates are still subject to change under the annual fuel cost adjustment proceedings. The North Carolina Utilities Commission approved the merger, subject to conditions agreed to by Dominion and Virginia Power, in October 1999.
Establishment of a Service Company
On January 28, 2000, Dominion completed its merger with CNG. CNG and its subsidiaries have become wholly-owned subsidiaries of Dominion. As a result of the merger, Dominion has become a registered public utility holding company subject to regulation under the 1935 Public Utility Holding Company Act (1935 Act). In accordance with certain requirements of the 1935 Act, Dominion created a subsidiary service company, Dominion Resources Services, Inc., Services which will provide certain administrative and support services to Dominion subsidiaries, including Virginia Power. Employees of Dominion and Virginia Power who will perform those functions became employees of Services effective February 1, 2000. CNG also has a service company. Virginia Power may elect to purchase services from either service company; however, service company functions are expected to be moved into a single service company by March 31, 2001.
In addition, our business operations are being reviewed in conjunction with the merger of Dominion and CNG to identify opportunities for operational efficiencies. As a result of the formation of Services and this operational review, restructuring charges for items such as employee severance and other special termination benefits and the elimination of duplicate facilities, are likely to be incurred during 2000 and 2001 as we implement management's reorganization plans.
Environmental Matters
Virginia Power 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. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. Historically, we recovered these costs from customers through utility rates. 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, our results of operations will decrease. After that date, we may seek recovery for only those environmental costs related to transmission and distribution operations through regulated utility rates.
Environmental Protection And Monitoring Expenditures
We incurred approximately $78 million, $72 million, and $71 million (including depreciation) during 1999, 1998 and 1997, respectively, in connection with the use of environmental protection facilities, and we expect these expenses to be approximately $79 million in 2000. In addition, capital expenditures to limit or monitor hazardous substances were $74 million, $22 million, and $25 million for 1999, 1998 and 1997, respectively. The amount estimated for 2000 for these expenditures is $148 million.
Clean Air Act Compliance
The Clean Air Act, as amended in 1990, requires the Company 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 us to obtain operating permits for all major emissions-emitting facilities. Permit applications have been submitted for the Company's power stations.
The Clean Air Act's SO\\2\\ reduction program is based on the issuance of a limited number of SO\\2\\ emission allowances, each of which may be used as a permit to emit one ton of SO\\2\\ into the atmosphere or may be sold to someone else. The EPA administers the program. Our compliance plans are reviewed periodically and may include switching to lower sulfur coal, purchasing emission allowances and installing of SO\\2\\ control equipment. In December 1998 we initiated a capital project to install SO\\2\\ control equipment on two units at our Mt. Storm power station at an estimated cost of $126 million. These SO\\2\\ controls are expected to be operational by January 2002.
We began complying with Clean Air Act Phase I NOx limits at eight of our units in Virginia in 1997, three years earlier than otherwise required. As a result, the units will not be subject to more stringent Phase II limits until 2008. We have established a plan to comply with the Phase II limits at the remaining eight coal-fired units in Virginia subject to the Phase II limits.
In September 1998, the EPA adopted a rule requiring 22 states, including Virginia, West Virginia and North Carolina, to reduce and cap ozone season (May- September) NO\\x\\ emissions beginning in May 2003. The affected states were to submit a compliance plan to the EPA by September 1999, but a May 1999 ruling by the U.S. District Court of Appeals in the DC Circuit has granted an indefinite stay of the states' submittal requirements. However, in December 1999, the EPA issued a finding in support of petitions filed by several Northeastern states seeking relief from long-range pollutant transport from utility and large industrial sources that essentially enforces the same NOx emission caps beginning in May 2003 for 12 of the 22 states, including Virginia, West Virginia and North Carolina. In response to these requirements, we plan to install NOx reduction equipment at our coal-fired generating facilities at an estimated capital cost of approximately $454 million over the next several years. Whether these costs are actually incurred is dependent on both the outcome of pending litigation of these rules and on the implementation plans adopted by the states in which we operate.
Evaluation and planning on future projects to comply with SO\\2\\ and NOx reduction requirements are ongoing and will be influenced by changes in the regulatory environment, availability of SO\\2\\ allowances and emission control technology.
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 Virginia Power.
Recently Issued Accounting Standards
The Financial Accounting Standards Board (FASB) recently issued SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133, which defers the effective date of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133) from January 1, 2000 to January 1, 2001. SFAS No. 133 requires that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at fair value. This statement requires that changes in a derivative's fair value be recognized in current earnings unless specific hedge accounting criteria are met.
We have tentatively determined that our long-term purchased power contracts would not be subject to SFAS No. 133. Our trading portfolio of commodity contracts is currently marked to fair value and would not be affected by this statement. We are in the process of assessing the impact, method, and period of adoption of SFAS No. 133 and have not estimated the financial impact of adoption. To the extent that any of the contracts are subject to fair value accounting, implementing appropriate hedging strategies could possibly mitigate the potential impact on earnings volatility.
Year 2000 Readiness
We experienced a successful transition to the Year 2000. Immediately after the rollover and throughout the rollover weekend, our transmission and distribution systems and our generating units continued to operate smoothly. Our customers did not lose power as a result of a Year 2000 problem.
We are continuing to monitor systems for any Year 2000 issues through the transition to February 29, 2000. However, as with the rollover to January 1, 2000, no significant problems are expected.
We expect total Year 2000 costs to be approximately $28 million. Actual Year 2000 costs of $26 million have been expended as of December 31, 1999.
We cannot estimate or predict the potential adverse consequences that could result from a third party's failure to effectively address remaining Year 2000 issues, if any, but believe that any impact would be short-term in nature and would not have a material adverse impact on results of operations.
Market Risk Sensitive Instruments and Risk Management
We are exposed to market risk because we utilize financial instruments, derivative financial instruments and derivative commodity instruments. The market risks inherent in these instruments are represented by the potential loss due to adverse changes in commodity prices, equity security prices and interest rates as described below. Interest rate risk generally is related to our outstanding debt, preferred stock and trust-issued securities. We are exposed to equity price risk primarily as a result of equity securities held in nuclear decommissioning trusts. Commodity price risk is experienced in our power generation and commodity marketing and trading business due to the exposure to market shifts in the prices received and paid for natural gas and electricity.
We are using sensitivity analysis to disclose quantitative information about our exposure to commodity price and interest rate risks. Our sensitivity analysis estimates the potential loss of future earnings that may result from market risk sensitive instruments over a selected time period due to hypothetical changes in interest rates and commodity prices. The tabular presentation methodology continues to be used to disclose equity price market risk.
Commodity Price Risk
As part of our strategy to market energy from our generation capacity and to manage related risks, we manage a portfolio of derivative commodity contracts held for trading purposes. These contracts are sensitive to changes in the prices of natural gas and electricity. We employ established policies and procedures to manage the risks associated with these price fluctuations and use various commodity instruments, such as futures, swaps and options, to reduce risk by creating offsetting market positions. In addition, we seek to use our generation capacity, when not needed to serve customers in our service territory, to satisfy commitments to sell energy.
One of the techniques commonly used to measure risk in a commodity trading portfolio is sensitivity analysis, which determines a hypothetical change in the fair value of the portfolio which would result from an assumed change in the market prices of the related commodities. The fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, market value reflects our best estimates considering over-the- counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are marked to market based on closing exchange prices.
We have determined a hypothetical loss by calculating a hypothetical fair value for each contract assuming a 10% unfavorable change in the market prices of the related commodity and comparing it to the fair value of the contracts based on market prices at December 31, 1999 and 1998. This hypothetical 10% change in commodity prices would have resulted in a hypothetical loss of approximately $5 million and $13 million in
the fair value of our commodity contracts as of December 31, 1999 and 1998, respectively. The commodity contracts' sensitivity to unfavorable price changes decreased in 1999 primarily due to reduced price exposure from options included in the portfolio at December 31, 1999 as compared to December 31, 1998.
The sensitivity analysis does not include the price risks associated with utility operations, including those underlying utility fuel requirements. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks principally include credit risk, which is not reflected in the sensitivity analysis above.
Interest Rate Risk
We manage our exposure to interest rate risk by maintaining a portfolio of both fixed and variable-rate debt instruments. In addition, we participate in interest rate sensitive derivatives, such as interest rate swaps, to manage this risk. As part of our risk management policies, we may participate in similar types of derivatives in the future.
Our sensitivity analysis estimates the impact of a hypothetical change in interest rates on our variable-rate long-term and short-term financial instruments and interest rate sensitive derivatives. For financial instruments outstanding at December 31, 1999, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $8 million. A similar hypothetical increase in market interest rates, as determined at December 31, 1998, resulted in a decrease in annual earnings of $4 million.
Equity Price Risk
The following table presents a description of marketable equity securities held at December 31, 1999 and 1998. In accordance with SFAS No. 115, Accounting For Certain Investments In Debt And Equity Securities, these securities are reported on the balance sheet at fair value.
VIRGINIA ELECTRIC AND POWER COMPANY
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Market Risk Sensitive Instruments and Risk Management under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
REPORT OF MANAGEMENT
The Company's management is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the Company's annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.
Management maintains a system of internal accounting controls designed to provide reasonable assurance, at a reasonable cost, that the Company's assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control and, therefore, cannot provide absolute assurance that the objectives of the established internal accounting controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Management believes that during 1999 the system of internal control was adequate to accomplish the intended objective.
The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by the Board of Directors. Their audits were conducted in accordance with generally accepted auditing standards and included a review of the Company's accounting systems, procedures and internal controls, and the performance of tests and other auditing procedures sufficient to provide reasonable assurance that the Consolidated Financial Statements are not materially misleading and do not contain material errors.
The Audit Committee of the Board of Directors of Dominion Resources, Inc., composed entirely of directors who are not officers or employees of Dominion Resources, Inc. or its subsidiaries, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters of the Company and to ensure that each is properly discharging its responsibilities. Both the independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.
Management recognizes its responsibility for fostering a strong ethical climate so that the Company's affairs are conducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Company's Code of Ethics, which is distributed throughout the Company. The Code of Ethics addresses, among other things, the importance of ensuring open communication within the Company; potential conflicts of interest; compliance with all domestic and foreign laws, including those relating to financial disclosure; the confidentiality of proprietary information; and full disclosure of public information.
VIRGINIA ELECTRIC AND POWER COMPANY
/s/ J.A. Shaw /s/ M.S. Bolton, Jr. Senior Vice President, Senior Vice President Chief Financial -Financial Management Officer and Treasurer (Principal Accounting Officer)
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors of Virginia Electric and Power Company:
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the Company) as of December 31, 1999 and 1998, and the related consolidated statements of income, earnings reinvested in business, and cash flows for each of the three years in the period ended December 31, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. 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 consolidated financial position of the Company at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Richmond, Virginia January 28, 2000
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
The Company had no other comprehensive income reportable in accordance with Statement of Financial Accounting Standards (SFAS) No. 130, Reporting Comprehensive Income.
The accompanying notes are an integral part of the financial statements.
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VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDER'S EQUITY
- -------- (*) As described in Note J to CONSOLIDATED FINANCIAL STATEMENTS, the 8.05% Junior Subordinated Notes totaling $139 million principal amount constitute 100% of the Trust's assets.
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS REINVESTED IN BUSINESS
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Significant Accounting Policies
General
Virginia Electric and Power Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. The Company engages in off-system wholesale purchases and sales of electricity and purchases and sales of natural gas, and is developing trading relationships beyond the geographic limits of its retail service territory. Within this document, the terms "Virginia Power" and the "Company" shall refer to the entirety of Virginia Electric and Power Company, including, without limitation, its Virginia and North Carolina operations, and all of its subsidiaries.
The Company's accounting practices are in accordance with generally accepted accounting principles. The financial statements include the accounts of the Company and its subsidiaries, with all significant intercompany transactions and accounts being eliminated on consolidation.
The Company is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion), a Virginia corporation.
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, disclosure of contingent liabilities at the date of the financial statements and revenue and expenses during the reporting period. Actual results could differ from those estimates.
As discussed in Form 8-K, filed March 29, 1999, Virginia Power discontinued the application of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to its generation operations. The effect thereof was an after-tax charge of $255 million. See Note B.
In connection with the discontinuance of SFAS No. 71 to its generation- related utility operations, Virginia Power prospectively changed certain of its accounting policies to those used by non-regulated entities. These policy changes primarily relate to the capitalization of interest on and depreciation of generation-related property. The Company reevaluated the economic useful life estimates of its generation-related property in light of the scheduled deregulation of the generation business in Virginia. In addition, Virginia Power no longer provides for the cost of removal in its provision for depreciation of generation-related utility property, as prescribed by regulatory accounting practices. Effective April 1999, such costs are expensed as incurred. Also, Virginia Power no longer records retirements of generation- related utility property by charging accumulated depreciation. Rather, Virginia Power records gains and losses upon retirement of such property based upon the difference between proceeds received, if any, and the property's undepreciated basis at the retirement date. The overall impact of these changes was not material to the Company's results of operations and financial condition.
Revenue
Revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Revenue from trading activities includes realized commodity contract revenue, net of related cost of sales, amortization of option premiums and unrealized gains and losses resulting from marking to market those commodity contracts not yet settled.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Fuel, Net
Fuel, net represents fuel costs subject to rate regulation. It includes the cost of fossil fuel, nuclear fuel and purchased energy used to serve electric sales. It also includes the cost of purchased energy associated with power marketing sales subject to cost of service rate regulation.
Approximately 95 percent of rate regulated fuel costs are subject to deferral accounting. Deferral accounting provides that the difference between reasonably incurred actual expenses and the level of expenses included in current rates is deferred and matched against future revenue. Fuel, net includes the effect of this deferral accounting and may therefore show expenses that are marginally higher or lower than the actual cost of fuel consumed during the period.
Property, Plant and Equipment
Property, plant and equipment is recorded at original cost, which includes labor, materials, services, capitalized interest, and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense accounts. The cost of additions and replacements is charged to the appropriate utility plant account, except that the cost of minor additions and replacements is charged to maintenance expense.
Depreciation and Amortization
Depreciation of property, plant, and equipment (other than nuclear fuel) is computed on the straight-line method based on projected useful service lives. The cost of depreciable transmission and distribution property retired and related cost of removal, less salvage, are charged to accumulated depreciation. For generation-related property, cost of removal is charged to expense as incurred. The Company records gains and losses upon retirement of generation- related property based upon the difference between proceeds received, if any, and the property's undepreciated basis at the retirement date. The composite weighted-average depreciation rate, excluding nuclear fuel, was approximately 3.2% for 1999, 1998 and 1997.
Operating expenses include amortization of nuclear fuel, which is provided on a unit of production basis sufficient to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs.
Federal Income Taxes
The Company files a consolidated federal income tax return with Dominion.
Deferred investment tax credits are being amortized over the service lives of the property giving rise to such credits.
Regulatory Assets
The Company's financial statements reflect assets and costs in accordance with SFAS No. 71. This accounting standard provides that certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. At December 31, 1999, the Company's transmission and distribution operations continue to satisfy the requirements of SFAS No. 71. In addition, at
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999, regulatory assets included certain generation-related regulatory assets that continue to be recognized in accordance with Emerging Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the Pricing of Electricity Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises--Accounting for the Discontinuance of Application of FASB Statement No. 71" (EITF Issue 97-4). See Note B and Note H for information on the discontinuance of the application of SFAS No. 71 to the Company's generation-related operations and the Company's regulatory assets.
Amortization of Debt Issuance Costs
The Company defers and amortizes expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, over the lives of the respective issues. As permitted by appropriate regulatory jurisdictions, gains or losses resulting from the redemption of debt are deferred and amortized over the remaining lives of the redeemed issues. In the case of a refinancing, the Company amortizes such gains and losses over the lives of the new issues of long-term debt. Effective April 1999, gains or losses resulting from the retirement or refinancing of debt allocable to generation-related operations will be recorded in accordance with SFAS No. 4, Reporting Gains and Losses From Extinguishment of Debt.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 1999 and 1998, the Company's accounts payable included the net effect of checks outstanding but not yet presented for payment of $52 million and $49 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand and temporary investments purchased with an initial maturity of three months or less.
Commodity Contracts
As part of Virginia Power's strategy to market energy from its generation capacity and to manage the risks related thereto, the Company enters into contracts for the purchase and sale of energy commodities. The trading activities of Virginia Power's wholesale power group include fixed-price forward contracts and the purchase and sale of over-the-counter options that require physical delivery of the underlying commodity. Furthermore, in order to manage price risk associated with natural gas sales and fuel requirements for utility operations, the Company uses basis swaps and exchange-traded futures and options.
Swaps, futures, and options are marked to market with resulting gains and losses reported in earnings, unless such instruments are designated as hedges of fuel requirements for utility operation for accounting purposes. Forward contracts, initiated for trading purposes, also are 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 closing exchange 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 revenue, net of related cost of sales, settlement of futures contracts, amortization of option premiums and unrealized gains and losses resulting from marking positions to market are included in other revenue. Cash flows from trading activities are reported as operating activities in the Consolidated Statements of Cash Flow.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Interest Rate Swaps
The net of amounts paid and amounts received under interest rate swaps is reported as interest expense on the Consolidated Statements of Income.
Reclassification
Certain amounts in the 1998 and 1997 financial statements have been reclassified to conform to the 1999 presentation.
B. Extraordinary Item--Discontinuance of SFAS No. 71
During its 1998 session, the Virginia legislature passed a law that required a transition to retail competition between January 1, 2002 and January 1, 2004, but left the details as to how that would be accomplished to future enabling legislation.
In March 1999, the Governor of Virginia signed into law legislation establishing a detailed plan to restructure the electric utility industry in Virginia. The major elements of the bill included:
. Phase-in of retail customer choice beginning in 2002 with full retail customer choice by 2004; the schedule is to be determined by the State Corporation Commission of Virginia (Virginia Commission), which has the authority to accelerate or delay implementation under certain conditions; however, the phase-in of retail customer choice may not be delayed beyond January 1, 2005;
. No mandatory divestiture of generating assets;
. Deregulation of generation in 2002;
. Capped base rates from January 1, 2001 to July 1, 2007;
. Recovery of net stranded costs through capped rates or a wires charge paid by those customers opting, while capped rates are in effect, to purchase energy from a competitive supplier;
. Cost-based recovery of fuel expenses until July 2007;
. Consumer protection safeguards;
. Establishment of default service beginning January 1, 2004; and
. Creation of a Legislative Transition Task Force to oversee the implementation of the statute.
Under this legislation, the Company's base rates will remain unchanged until July 2007 and recovery of generation-related costs will continue to be provided through the capped rates. In addition, under companion legislation enacted by Virginia in 1999, providers of electric service will be subject to corporate income tax in lieu of gross receipts tax effective in 2001.
As discussed in Note A, the Company's financial statements reflect regulatory assets and liabilities under cost-based rate regulation in accordance with SFAS No. 71. Rate-regulated companies are required to write off regulatory assets against current earnings whenever changes in facts and circumstances result in those assets no longer satisfying criteria for recognition as defined by SFAS No. 71. The legislation's deregulation of generation is an event that required discontinuation of SFAS No. 71 for the Company's generation operations in the first quarter of 1999. The Company's transmission and distribution operations continue to meet the criteria for recognition of regulatory assets and liabilities as defined by SFAS No. 71. In addition, fuel continues to be subject to deferral accounting.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In order to measure the amount of regulatory assets to be written off, the Company evaluated to what extent recovery of regulatory assets would be provided through the capped rates during the transition period. EITF Issue 97- 4, provides guidance about writing off regulatory assets when SFAS No. 71 is discontinued for only a portion of a utility's operations. The provisions of the Virginia legislation provide an opportunity to recover generation-related costs, including certain regulatory assets, through capped rates prior to July 2007. Under EITF Issue 97-4 such generation-related regulatory assets will continue to be recognized until they are recovered through capped rates. Generation-related assets and liabilities that will not be recovered through the capped rates were written off in the first quarter of 1999, resulting in an after-tax charge to earnings of $255 million. See Note H for discussion of net regulatory assets at December 31, 1999.
In addition to the write-off of generation-related net regulatory assets, the $255 million charge included a write-off of approximately $18 million, after-tax, of other generation-related assets. Pursuant to EITF Issue 97-4, a corresponding regulatory asset of $23 million, representing the amount expected to be recovered during the transition period related to these assets, was established. The extraordinary item also included the write-off of approximately $38 million, after-tax, of deferred investment tax credits.
Also, the events or changes in circumstances that cause discontinuance of SFAS No. 71, and write-off of regulatory assets, also require a review of utility plant assets and long-term power purchase contracts for possible impairment. This review is based on estimates of possible future market prices, load growth, competition and many other assumptions. The Company evaluated its generation assets in accordance with the provisions of SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. Those evaluations included the effects of nuclear decommissioning and other currently identified environmental expenditures. Based on those analyses which were highly dependent on the underlying assumptions, no plant write-downs were appropriate at that time.
The Company reviewed its long-term purchased power commitments 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 of the Company's long-term power purchase contracts indicated no loss recognition was appropriate at that time. Other projections of possible future market prices indicated a possible loss of $500 million. In the absence of capped rates as provided by the legislation, the potential exposure related to the Company's power purchase contracts would have been approximately $3.2 billion.
Significant estimates were required in recording the effect of the deregulation legislation, including the resulting impact on the fair value determination of generating facilities and estimated purchases under long-term power purchase contracts. Such projections are highly dependent on future customer load projections, generating unit availability, the timing and type of future capacity additions in Virginia Power's market area and future market prices for fuel and electricity and are subject to future re-evaluation.
C. Recently Issued Accounting Standards
The Financial Accounting Standards Board (FASB) recently issued SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133, which defers the effective date of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133) from January 1, 2000 to January 1, 2001. SFAS No. 133 requires that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at fair value. This statement requires that changes in a derivative's fair value be recognized in current earnings unless specific hedge accounting criteria are met.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company has tentatively determined that its long-term purchased power contracts would not be subject to SFAS No. 133. The Company's trading portfolio of commodity contracts is currently marked to fair value and would not be affected by this statement. The Company is in the process of assessing the impact, method, and period of adoption of SFAS No. 133 and has not estimated the financial impact of adoption. To the extent that any of the contracts are subject to fair value accounting, implementing appropriate hedging strategies could possibly mitigate the potential impact on earnings volatility.
D. Income Taxes
Details of income tax expense are as follows:
Total federal income tax expense differs from the amount computed by applying the statutory federal income tax rate to pretax income for the following reasons:
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's net accumulated deferred income taxes consist of the following:
E. Nuclear Operations
Decommissioning
When the Company's nuclear units cease operations, the Company is obligated to decontaminate or remove radioactive contaminants so that the property will not require Nuclear Regulatory Commission (NRC) oversight. This phase of a nuclear power plant's life cycle is termed decommissioning. While the units are operating, amounts are currently being collected from ratepayers that, when combined with investment earnings, will be used to fund this future obligation. These dollars are deposited into external trusts through which the funds are invested.
The amount being accrued for decommissioning is equal to the amount being collected from ratepayers and is included in Depreciation and Amortization Expense. The decommissioning collections were $36 million per year for the period 1997 through 1999. However, an additional $10 million was expensed in 1997 based on an expected increase in the decommissioning collections for 1997 as provided in the Company's rate case then pending before the Virginia Commission. Since the Virginia rate case settlement did not include such an increase, the 1998 expense provision was decreased by $10 million. Therefore, the expense levels were $36 million, $26 million and $46 million in 1999, 1998 and 1997, respectively.
Net earnings of the trusts' investments are included in Other Income in the Company's Consolidated Statements of Income. In 1999, 1998 and 1997, net earnings were $17 million, $18 million and $21 million, respectively. The accretion of the decommissioning obligation is equal to the trusts' net earnings and is also recorded in Other Income.
The accumulated provision for decommissioning, which is included in Accumulated Depreciation in the Company's Consolidated Balance Sheets, includes the accrued expense and accretion described above and any unrealized gains and losses on the trusts' investments. At December 31, 1999, the net unrealized gains were $291 million, which is an increase of $60 million over the December 31, 1998, amount of $231 million. The accumulated provision for decommissioning at December 31, 1999 and 1998, was $818 million and $705 million, respectively.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The total estimated cost to decommission the Company's four nuclear units is $1.6 billion based upon a site-specific study that was completed in 1998. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. This method assumes that dismantlement and other decommissioning activities will begin shortly after cessation of operations, which under current operating licenses will begin in 2012 as detailed in the table below.
The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of the nuclear facilities. The Company's 1999 NRC minimum financial assurance amount, aggregated for the four nuclear units, was $1.0 billion and will be satisfied by a combination of surety bonds and the funds being collected in the external trusts.
FASB is reviewing the accounting for nuclear plant decommissioning. FASB has tentatively determined that the estimated cost of decommissioning should be reported as a liability rather than as accumulated depreciation and that a substantial portion of the decommissioning obligation should be recognized earlier in the operating life of the nuclear unit. During its deliberations, FASB expanded the scope of the project to include similar unavoidable obligations to perform closure and post-closure activities for other long-lived assets, possibly including non-nuclear power plants. Any forthcoming standard also may change regulated utility plant depreciation practices, the impact of which cannot be determined at this time.
Insurance
The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $9.5 billion for a single nuclear incident. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. The Company has purchased $200 million of coverage from the commercial insurance pools with the remainder provided through a mandatory industry risk sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $91 million for each of its four licensed reactors not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.
The Company's current level of property insurance coverage ($2.55 billion for North Anna and $2.40 billion for Surry) exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance are used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The Company's nuclear property insurance is provided by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $29 million. Based on the severity of the incident, the board of directors of the Company's nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination, the Company has the financial responsibility for these losses.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Virginia Power 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, the co-owner is responsible for its share of the nuclear decommissioning obligation and insurance premiums applicable to that station, including any retrospective premium assessments and any losses not covered by insurance.
F. Property, Plant and Equipment
Property, plant and equipment, other than nuclear fuel, consists of the following:
G. Jointly Owned Plants
The following information relates to the Company's proportionate share of jointly owned plants at December 31, 1999:
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interest. The Company's share of operating costs is classified in the appropriate operating expense (fuel, operations and maintenance, depreciation, taxes, etc.) in the Consolidated Statements of Income.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
H. Regulatory Assets
The Company's regulatory assets include the following:
The incurred costs underlying these regulatory assets may represent expenditures by the Company or may represent the recognition of liabilities that ultimately will be settled at some time in the future. See Note B and Note Q for information about the impairment of regulatory assets resulting from the 1999 Virginia legislation and the settlement of the Company's 1998 Virginia rate proceedings.
Where permitted by appropriate regulatory jurisdictions for the portion of the Company's operations that are subject to cost-based regulation, income taxes recoverable through future rates represent principally the tax effect of depreciation differences not normalized in earlier years for ratemaking purposes. These amounts are amortized as the related temporary differences reverse. Such amounts are net of related regulatory liabilities and $43 million associated with deferred income taxes which were established at rates in excess of the current Federal rate and are subject to Internal Revenue Code normalization requirements.
The cost of decommissioning the Department of Energy's (DOE) uranium enrichment facilities represents Virginia Power's required contributions to a fund for decommissioning and decontaminating the DOE's uranium enrichment facilities. Virginia Power is making such contributions over a 15-year period with escalation for inflation. These costs are currently being recovered in fuel rates.
Where permitted by appropriate regulatory jurisdictions for the portion of the Company's operations that are subject to cost-based regulation, gains or losses on refinanced debt are deferred and amortized over the lives of the new debt issues. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.
Deferred fuel accounting provides that the difference between reasonably incurred actual expenses and the recovery for such costs included in current rates is deferred and matched against future revenue.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
I. Long-Term Debt
Long-term debt includes the following:
- -------- (/1/)The first and refunding mortgage bonds and the fixed interest rate, tax- exempt financings are secured by a mortgage lien on substantially all of the Company's property. (/2/)Certain pollution control facilities at the Company's generating facilities have been pledged or conveyed to secure these financings. (/3/)Interest rates vary based on short-term, tax-exempt market rates. For 1999 and 1998, the weighted average daily interest rates were 3.34 percent and 3.49 percent, respectively. Although these bonds are re-marketed within a one year period, they are classified as long-term debt because the Company intends to maintain the debt, and they are supported by long-term bank commitments.
The following amounts of debt will mature during the next five years: 2000 - -- $195 million; 2001-- $241 million; 2002 -- $315 million; 2003 -- $240 million; and 2004 -- $325 million.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
J. Company Obligated Mandatorily Redeemable Preferred Securities Of Subsidiary Trust
Virginia Power Capital Trust I (VP Capital Trust) was established as a subsidiary of the Company for the sole purpose of selling $135 million of preferred securities (5.4 million shares at $25 par) in 1995. The Company concurrently issued $139 million of its 1995 Series A, 8.05% Junior Subordinated Notes (the Notes) in exchange for the $135 million realized from the sale of the preferred securities and $4 million of common securities of VP Capital Trust.
The preferred securities and the common securities represent the total beneficial ownership interest in the assets held by VP Capital Trust. The Notes are the sole assets of VP Capital Trust. The preferred securities are subject to mandatory redemption upon repayment of the Notes at a liquidation amount of $25 plus accrued and unpaid distributions, including interest. The Notes are due September 30, 2025. However, that date may be extended up to an additional ten years if certain conditions are satisfied.
K. Preferred Stock Subject To Mandatory Redemption
The total number of authorized shares for all preferred stock (whether or not subject to mandatory redemption) is 10 million shares. Upon involuntary liquidation, dissolution or winding-up of the Company, all presently outstanding preferred stock is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.
There are two series of preferred stock subject to mandatory redemption outstanding as of December 31, 1999:
There were no redemptions of preferred stock during the years 1997 through 1999.
The Company has classified the $180 million of preferred stock subject to mandatory redemption in Securities due within one year at December 31, 1999.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
L. Preferred Stock Not Subject To Mandatory Redemption
Shown below are the series of preferred stock not subject to mandatory redemption that were outstanding as of December 31, 1999.
- -------- (*) Money Market Preferred (MMP) dividend rates are variable and are set every 49 days via an auction process. The combined weighted average rates for these series in 1999, 1998 and 1997, including fees for broker/dealer agreements, were 4.82 percent, 4.49 percent, and 4.48 percent, respectively.
M. Common Stock
There were no changes in the number of authorized and outstanding shares of the Company's common stock during the three years ended December 31, 1999.
N. Short-Term Debt
The Company's commercial paper program has a maximum borrowing capacity of $500 million. It is supported by two credit facilities. One is a $300 million, five-year credit facility that expires in June 2001. The other is a $200 million credit facility that originated in June 1996 and is subject to annual renewal.
The total amount of commercial paper outstanding as of December 31, 1999, was $378 million with a weighted average interest rate of 6.11 percent. This represents an increase of $157 million from the December 31, 1998, balance of $221 million which had a weighted average interest rate of 5.38 percent.
O. Long-Term Incentives
Certain officers and key employees of Virginia Power participate in a stock- based compensation plan sponsored by Dominion. During 1999, approximately 2 million Dominion common stock options were granted to these individuals. These stock options vested on January 1, 2000. No compensation expense was recognized under the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. Had compensation expense been measured based on the fair value of the options on the date of grant, calculated under the provisions of SFAS No. 123, Accounting for Stock Based Compensation,
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
the Company's allocated share of such compensation expense would have reduced reported net income by approximately $5 million.
P. Retirement Plan, Postretirement Benefits And Other Benefits
Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
Retirement Plan
The Company participates in the Dominion Resources, Inc. Retirement Plan (the Retirement Plan), a defined benefit pension plan. The benefits are based on years of service and average base compensation over the consecutive 60-month period in which pay is highest.
The Company's pension plan expenses were $21 million, $21 million, and $21 million for 1999, 1998, and 1997, respectively, and the amounts funded by the Company were $21 million, $21 million, and $27 million in 1999, 1998, and 1997, respectively.
Other Postretirement Benefits
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. Health care benefits are provided to retirees who complete at least 10 years of service after attaining age 45. These and similar benefits for active employees are provided through insurance companies.
Net periodic postretirement benefit expense was as follows:
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following table sets forth the funded status of the plan:
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:
The funds collected for other postretirement benefits in rates, in excess of benefits actually paid during the year, are contributed to external benefit trusts. See Note R for a discussion of the impact of the 1999 deregulation legislation on the recoverability of potentially stranded costs.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Q. Virginia Rate Settlement
In 1998 Virginia Power agreed to settle its outstanding base rate proceedings. The Virginia Commission approved the settlement by Order dated August 7, 1998.
The settlement defined a new regulatory framework for the Company's transition to electric competition. The major provisions of the settlement were as follows:
. A two-phased base rate reduction: $100 million per annum beginning March 1, 1998 with one additional $50 million per annum reduction beginning March 1, 1999;
. A base rate freeze through February 28, 2002 unless a change is necessary to protect the legitimate interests of the Company, its shareholders or ratepayers;
. An immediate, one-time refund of $150 million for the period March 1, 1997 through February 28, 1998;
. A discontinuation of deferral accounting for purchased power capacity expenses effective February 28, 1998;
. A write-off of a minimum of $220 million of regulatory assets in addition to normal amortization by February 28, 2002;
Due to the required write-off of a minimum of $220 million of regulatory assets in addition to normal amortization thereof during the rate freeze period, the Company evaluated its regulatory assets for potential impairment under SFAS No. 71. Based on the uncertainty of the Company's earnings potential for regulatory purposes during the rate freeze period, management could no longer conclude that recovery of the $220 million was probable, i.e., that earnings above its authorized rate of return would be available to offset the $220 million write-off of regulatory assets. The Company had previously identified reductions in operating costs of $38 million in 1997 and $27 million in 1996, which were used to establish a reserve for potential impairment of regulatory assets. Accordingly, the Company charged $159 million to second quarter 1998 earnings, which when combined with the reserve for accelerated cost recovery accrued in 1996 and 1997, provided for the impairment of regulatory assets resulting from the settlement.
R. Commitments And Contingencies
The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will not have a material adverse effect on the Company's operations, financial position, liquidity or results of operations.
Utility Rate Regulation
As discussed in Note B, the Governor of Virginia signed into law legislation establishing a detailed plan to restructure the electric utility industry in Virginia. Under this legislation, the Company's base rates will remain unchanged until July 2007 and recovery of generation-related costs will continue to be provided through the capped rates. The legislation's deregulation of generation was an event that required discontinuation of SFAS No. 71 for the Company's generation operations in the first quarter of 1999.
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
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
capital costs. At December 31, 1999, the Company'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 E and P.
Retrospective Premium Assessments
Under several of the Company's nuclear insurance policies, the Company is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to these insurance companies. For additional information, see Note E.
Construction Program
The Company has made substantial commitments in connection with its construction program and nuclear fuel expenditures. Those expenditures are estimated to total approximately $856 million for 2000. The Company presently estimates that 2000 construction expenditures, including nuclear fuel, will be met through cash flow from operations and through a combination of sales of securities and short-term borrowing.
Purchased Power Contracts
The Company has entered into contracts for the long-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. The Company has 57 non-utility purchase contracts with a combined dependable summer capacity of 3,839 MW.
The table below reflects the Company's minimum commitments as of December 31, 1999, for power purchases from utility and non-utility suppliers.
In addition to the minimum purchase commitments in the table above, under some of these contracts, the Company may purchase, at its option, additional power as needed. Purchased power expenditures, subject to cost of service rate regulation, (including economy, emergency, limited term, short-term and long- term purchases) for the years 1999, 1998 and 1997 were $1.2 billion, $1.1 billion and $1.4 billion, respectively.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
See Note B for an evaluation of the Company's potential exposure under its long-term purchased power commitments.
Fuel Purchase Commitments
The Company's estimated fuel purchase commitments for the next five years for system generation are as follows: 2000 -- $334 million; 2001 -- $277 million; 2002 -- $156 million; 2003 -- $145 million; and 2004-- $143 million.
Lease Commitments
Total future minimum lease payments under the Company's noncancellable capital leases and operating leases that have initial or remaining lease terms in excess of one year was $145 million at December 31, 1999. Expected future minimum lease payments under these leases over the next five years are as follows: 2000--$30 million; 2001--$21 million; 2002--$16 million; 2003--$13 million; 2004--$11 million and $54 million for the year thereafter.
Sales of Power
The Company enters into agreements with other utilities and with other parties to purchase and sell capacity and energy. These agreements may cover current and future periods ("forward positions"). The volume of these transactions varies from day to day based on the market conditions, our current and anticipated load, and other factors. The combined amounts of sales and purchases range from 3,000 MW to 15,000 MW at various times during a given year. These operations are closely monitored from a risk management perspective.
Environmental Matters
The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations of the Company. Historically, the Company recovered these costs from customers through utility rates. However, to the extent environmental costs are incurred during the period ending June 30, 2007, in excess of the level currently included in Virginia jurisdictional rates, the Company's results of operations will decrease. After that date, Virginia Power may seek recovery from customers through utility rates of only those environmental costs related to transmission and distribution operations.
In 1987, the Environmental Protection Agency (EPA) identified the Company and 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 $106 million to $156 million. The Company's proportionate share of the total cost is expected to be in the range of $2 million to $3 million, based upon allocation formulas and the volume of waste shipped to the sites. The Company has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay the costs apportioned to them.
The Company generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 1999, any pending or possible claims were not recognized as an asset or offset against such obligations of the Company.
In April 1999, the Company was notified by the Department of Justice of alleged noncompliance with the EPA's oil spill prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of the Company's power stations. If, in a legal proceeding, such instances of noncompliance are deemed to have occurred, the Company may be required to remedy any alleged deficiencies
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
and pay civil penalties. Settlement of this matter is currently in negotiation and is not expected to have a material impact on the Company's financial condition or results of operations.
In August 1999, the Company identified matters at certain other power stations that the EPA might view as not in compliance with the SPCC and FRP requirements. The Company reported these matters to the EPA and in December 1999 submitted revised FRP and SPCC plans. Presently, the EPA has not assessed any penalties against the Company, pending its review of the Company's disclosure information. Future resolution of these matters is not expected to have a material impact on the Company's financial condition or results of operations.
On November 8, 1999 and September 21, 1999, Virginia Power received notices from the Attorney Generals of Connecticut and New York, respectively, of their intention to file suit against the Company for alleged violations of the Clean Air Act. The notices question whether modifications at certain Virginia Power generating facilities were properly permitted under the Clean Air Act and allege that emissions from these facilities have contributed to damage to public health and the environment in the Northeast. To date, no suits have been filed. Management believes, based on newspaper reports and other sources, that it is one of a number of companies with fossil fuel power generating stations in the southeast and central United States to have received such notifications. The Company believes that it has obtained the permits necessary in connection with its generating facilities and that suits, if any, filed by the Attorney Generals would not have a material adverse effect on its financial condition or results of operations.
S. Fair Value of Financial Instruments
The Company used available market information and appropriate valuation methodologies to estimate the fair value of each class of financial instrument for which it is practicable to estimate fair value. These estimates are not necessarily indicative of the amounts the Company could realize in a market exchange. In addition, the use of different market assumptions may have a material effect on the estimated fair value amounts.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Cash and cash equivalents: The carrying amount of cash and cash equivalents approximates fair value because of their short maturity.
Nuclear decommissioning trust funds: Fair value is based on available market information and generally is the average of bid and asked price.
Commodity-based swaps and options: Fair value reflects the Company's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments.
Short-term debt: The carrying amount of short-term debt approximates fair value because of its short maturity.
First and refunding mortgage bonds: Fair value is based on market quotations.
Medium-term notes: These notes were valued by discounting the remaining cash flows at a rate estimated for each issue. A yield curve rate was estimated to relate treasury bond rates for specific issues to the corresponding maturities.
Senior unsecured notes: Fair value is based on market quotations.
Money Market Municipal tax-exempt securities: The interest rates for these notes vary so that fair value approximates carrying value.
Convertible and fixed interest rate tax-exempt bonds and preferred stock subject to mandatory redemption: The fair value is based on market quotations or is estimated by discounting the dividend and principal payments for a representative issue of each series over the average remaining life of the series.
Preferred securities of subsidiary trust: Fair value is based on market quotations.
Forward treasury lock contracts: Fair value is based on the difference between the yield at December 31, 1998 on the 30-year treasury note and such rates specified in the contracts.
Interest rate swap agreements: Fair value was determined by the respective counterparties to the agreements and is based upon the present value of all estimated net future cashflows. A negative value indicates that the aggregate sum of the respective valuations results in a projected net payment by the Company.
T. Business Segments
The Company manages its operations along two primary lines of business, Generation and Delivery. The Generation Business encompasses the Company's generation portfolio, trading and marketing activities, nuclear consulting services and energy services activities. The Delivery Business includes bulk power transmission, distribution and metering services, and customer service and continues to be subject to cost-based regulation.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The majority of the Company's revenue is provided through bundled rate tariffs. Such revenue is generally allocated between the two business lines for management reporting based on prior cost of service studies. Interest allocations are based on internal management estimates. Income taxes are calculated using the Company's effective rate. Amounts in the column Other include the following: 1) transactions or events for which the segments are not held accountable for internal reporting purposes (including the 1999 extraordinary item discussed in Note B, the 1998 Virginia rate settlement discussed in Note Q and the 1997 reserve for potential impairment of regulatory assets); 2) adjustments to reconcile internal financial statement groupings to those used to prepare the externally reported consolidated financial statements; 3) intercompany eliminations, where applicable; and 4) assets of the Company's corporate operations that are not allocated to its Generation and Delivery Businesses for internal reporting purposes.
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
U. Quarterly Financial Data (Unaudited)
The following amounts reflect all adjustments, consisting of only normal recurring accruals (except as discussed below), necessary in the opinion of management for a fair statement of the results for the interim periods.
Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.
The following accruals and adjustments recorded in 1999 and 1998 were of an extraordinary, unusual, or infrequent nature:
Extraordinary item -- The legislation's deregulation of generation is an event that required discontinuation of SFAS No. 71 for the Company's generation operations in the first quarter of 1999. Generation-related assets and liabilities that will not be recovered through the capped rates were written off, resulting in an after-tax charge to earnings of $255 million. See Note B.
Rate refund -- The Company recognized a $154 million provision for rate refund and related interest expense of $11 million and other taxes of $4 million in the second quarter of 1998 as a result of the settlement of the Company's rate proceeding in Virginia. See Note Q.
Impairment of regulatory assets -- The Company charged $159 million to second quarter 1998 earnings to provide for the impairment of regulatory assets resulting from the settlement of the Company's rate proceeding in Virginia. See Note Q.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Information concerning directors of Virginia Electric and Power Company is as follows:
Mr. Thomas has entered into a Consent Decree with the Office of Thrift Supervision in connection with the lending and credit granting activities of Perpetual Savings Bank, FSB, which Mr. Thomas formerly served as a director. The Consent Decree requires that Mr. Thomas obtain approval from the appropriate federal banking agency before accepting certain positions involving lending or credit activities with an insured depository institution.
(b) Information concerning the executive officers of Virginia Electric and Power Company is as follows:
There is no family relationship between any of the persons named in response to Item 10.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The Summary Table below includes compensation paid by Virginia Power for services rendered in 1997, 1998 and 1999 for the Chief Executive Officer(s) and the four other most highly compensated executive officers (as of December 31, 1999).
Summary Compensation Table
- -------- (1) Amounts shown include vacation sold back to the Company. (2) None of the executive officers above received perquisites or other personal benefits in excess of either $50,000 or 10% of total cash compensation. (3) Dividends are paid on restricted stock. The closing price of the stock on December 31, 1999 was $39.25; For each of the above named executives, the aggregate number of shares of restricted stock held as of December 31, 1999 issued under Virginia Power compensation programs was as follows: Mr. Askew-0, Mr. Farrell-376, Mr. Roach-0, Mr. O'Hanlon-972, Mr. Rigsby-1,502, Mr. Shaw-221, Mr. White-132. (4) In May of 1999, upon approval by the Dominion Organization, Compensation and Nominating Committee of the Board of Directors, a grant of Non- Qualified Stock Options was issued to the executives. The grant price was $41.25 per share. All options vest on January 1, 2000. The 1999 stock option grant was designed to replace 50% of the 1998-2000 and 100% of the 1999-2001 long-term incentive plans. (5) Amounts in this column represent payouts under the Incentive Compensation Plan for the three-year period 1997-1999. These amounts include both the cash award and the fair market value of the restricted Dominion shares as of the issue date January 31, 2000 ($41.22 per share). For purposes of these calculations, fair market value is defined as the average of the high and low of the market value on the day prior to issue. Performance was measured based 50% on Virginia Power financial results (Net Earnings and Net Cash Flow) and 50% on Dominion's consolidated net income. Based on their accomplishment level, each executive received their award in the form of 50% cash and 50% restricted stock. Awards were
- -------- Footnotes:
1. Nonstatutory stock options were granted on May 17, 1999 to the named executives at an exercise price of $41.25 per share (the fair market value on the date of grant). Fair Market Value is defined as the average of the intra-day high and low as of the close of business on December 31, 1999. 2. One hundred percent of the options vested on January 1, 2000. The options will remain exercisable for 10 years from the date of grant. Upon a change in control the options become fully exercisable and remain exercisable until the original expiration date. 3. The binomial pricing model was used to calculate the present value of the stock options. The assumptions underlying this model are:
Aggregated Option/SAR Exercises in Last Fiscal Year And FY-End Option/SAR Values
- -------- (1) The Fair Market Value of the underlying options is defined as the average of the intra-day high and low as of the close of business on December 31, 1999. (2) Shares are exercisable January 1, 2000.
Stock Ownership
In 1999 Dominion adopted stock ownership guideline for its executive officers. Officers have up to five years to meet the guidelines outlined below. Although stated in share amounts, the guidelines are based approximately on a multiple of base salary as presented in parentheses.
Dominion Resources, Inc. Stock Ownership Guidelines
- -------- Footnotes:
1. Nonstatutory stock options were granted on May 17, 1999 to the named executives at an exercise price of $41.25 per share (the fair market value on the date of grant). Fair Market Value is defined as the average of the intra-day high and low as of the close of business on December 31, 1999. 2. Certain executives had their salaries split between Virginia Power and Dominion based on the estimated amount of time that they performed work for each organization. The number of options reflected in these tables is based on the percentage of salary which was paid by Virginia Power. 3. One hundred percent of the options vested on January 1, 2000. The options will remain exercisable for 10 years from the date of grant. Upon a change in control the options become fully exercisable and remain exercisable until the original expiration date. 4. The Black-Scholes pricing model was used to calculate the present value of the stock options. The assumptions underlying this model are:
Aggregated Option/SAR Exercises in Last Fiscal Year And FY-End Option/SAR Values
- -------- (1) Shares were exercisable January 1, 2000. (2) The Fair Market Value of the underlying options is defined as the average of the intra-day high and low as of the close of business on December 31, 1999.
Stock Ownership
In 1999 Dominion adopted stock ownership guidelines for its executive officers and those of its subsidiaries. Officers have up to five years to meet the guidelines outlined below. Although stated in share amounts, the guidelines are based approximately on a multiple of base salary as presented in parentheses.
Dominion Resources, Inc. Stock Ownership Guidelines
Stock Purchase and Loan Programs
At the end of 1999, Dominion approved a Stock Purchase and Loan Programs intended to encourage and facilitate executives' ownership of common stock through the availability of loans guaranteed by Dominion.
Under the programs loans must be used to purchase Dominion common stock. An executive can borrow up to ten times his or her base salary, subject to credit approval, with a term of five years. Executives who meet their target ownership level through their participation in the Program receive "bonus shares" equal to five percent of the number of shares purchased under the program. The dividends on the stock purchased through the programs are used to pay the interest on the loan. Dominion subsidizes the interest payments to the extent that the current dividend rate does not fully cover the payments. Dominion will end its subsidy of the loan if it is prepaid or if the stock is sold. As of February 3, 2000, our officers have borrowed in aggregate $67 million, for which they are personally liable and which Dominion has guaranteed.
Retirement Plans
The table below sets forth the estimated annual straight life benefit that would be paid following retirement under the benefit formula of the Dominion Resources, Inc. Retirement Plan (the Retirement Plan).
Estimated Annual Benefits Payable Upon Retirement
Benefits under the Retirement Plan are based on (i) average base compensation over the consecutive 60-month period in which pay is highest, (ii) years of credited service, (iii) age at retirement, and (iv) the offset of Social Security Benefits. Certain officers have entered into retirement agreements that give additional credited years of service for retirement and retirement life insurance purposes, and retirement medical benefit purposes contingent upon the officer reaching a specified age and remaining in the employ of the Company or an affiliate.
In addition, certain officers, if they reach a specified age while still employed, will be credited with additional years of service. For the executives named in the Summary Compensation Table, credited years of service at age 60, including any additional years earned in connection with the retirement agreements, would not exceed 30.
Virginia Power's executive compensation program places significant emphasis on incentive compensation opportunities linked to financial and operating performance. The Retirement Plan benefit formula recognizes base salary, but not incentive compensation payments. Therefore, each year the Board approves a market-based adjustment to executive base salaries for use in calculating the retirement benefit under the Dominion Resources, Inc. Benefit Restoration Plan (the Restoration Plan). This adjustment was not material in 1999. Also, the Internal Revenue Code limits the annual retirement benefit that may be paid from a qualified retirement plan and the amount of compensation that may be recognized by the Retirement Plan. To the extent that benefits determined under the Retirement Plan's benefit formula exceed the limitations imposed by the Internal Revenue Code, they will be paid under the Restoration Plan.
Executive Supplemental Retirement Plan
The Supplemental Plan provides an annual retirement benefit equal to 25 percent of a participant's final cash compensation (base pay plus target annual incentive plan payments). The normal form of benefit is monthly installments for 120 months to a participant with 60 months of service, who (i) retires at or after age 55 from the employ of the Company, (ii) has become permanently disabled, or (iii) dies. The accrued benefit vests proportionately between the time an officer is elected and when he or she reaches age 55 when the benefit is fully vested. If a participant dies while employed, the normal form of benefit will be paid to a designated beneficiary. If a participant dies while retired, but before receiving all benefit payments, the remaining installments will be paid to a designated beneficiary. A lump sum payment is available under certain conditions. Based on 1999 compensation, the estimated annual benefit under this plan for each of the executives named in the Summary Compensation Table are: Mr. Farrell, II-$34,932, Mr. Roach-$55,125, Mr. O'Hanlon-$71,558, Mr. Rigsby- $91,370, Mr. Shaw-$70,162, Mr. White-$86,050.
Executive Deferred Compensation Plan
Under this plan, executives may defer any portion of their base salary, annual incentive cash award and/or long term incentive cash award. Deferrals are credited at the executive's discretion, for bookkeeping purposes, with earnings and losses as if they were invested in any of several mutual fund options, or Dominion common stock. Distributions are made at the direction of the executive.
Employment Agreements
Messrs. Farrell and Roach have employment agreements with Dominion for a three year period ending September 12, 2000. During employment, each of these executives will continue to receive a salary at least equal to his salary on the date of the agreement and will be eligible for bonuses and all employee benefits provided to senior management. The agreements also provide executives with enhanced retirement benefits. If the executive's employment is terminated without cause or if his salary, incentives or benefits are reduced or not paid, or he is demoted to a position that is not a senior management position, the executive will (subject to notice and remedy provisions): (1) receive a lump sum payment equal to the present value of salary and cash bonus for the balance of the contract period, (2) vest in his outstanding restricted stock and (3) receive age and service credit and continued benefit plan coverage through the end of the contract period. The agreements also provide benefits in the event of death or disability. In the case of a change in control, the executive will not receive pay under this agreement as a result of his termination of employment for any reason if he receives payment under his employment continuity agreement (described below).
Messrs. Roach and Rigsby have agreements with the Company that provide that, as a result of certain years of service with the Company, they will, upon retirement or any other termination of employment receive a payment of one year's base salary (or six month's base salary and certain enhanced retirement benefits at the executive's election). They will also be indemnified for potential penalties under the Internal Revenue Code if they are applicable to the enforcement of this benefit. These amounts are in addition to any amounts to which they may be entitled under other agreements with the Company with the exception of employment continuity agreement payments which will replace these payments. These agreements also provide the executives with enhanced retirement benefits as does a separate agreement of Mr. O'Hanlon's.
Messrs. Shaw and White have employment agreements under which they are entitled to salary, annual and long term incentive program participation and all employee benefits provided by the Company to senior management. In the case of a change in control, these executives may also receive payments under their employment continuity agreements (described below).
Special Arrangements
The Company or Dominion have entered into employment continuity agreements with the executives named in the Summary Compensation Table (other than Mr. Askew), which provide benefits in the event of a change of control. Each agreement has a three-year term and is automatically extended for an additional year, unless cancelled by the Company.
The agreements provide for the continuation of salary and benefits for a maximum period of three years after either (1) a change of control, (2) termination without cause following a change in control or (3) a reduction of responsibilities, salary and incentives following a change in control (if the executive gives 60 days notice). Payment of this benefit will be made in either a lump sum or installments over three years. The Company is also obligated to pay outplacement fees for the executive. In addition, the agreements indemnify the executives for potential penalties related to the Internal Revenue Code and fees associated with the enforcement of the agreements. If an executive is terminated for cause, the agreements are not effective.
A change of control shall be deemed to have occurred if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, a merger or other business combination, sale of assets, or contested election, the Directors constituting the Dominion Board before any such transactions cease to represent a majority of Dominion or its successor's Board within two years after the last of such transactions.
Compensation Of Directors
Fees
During 1999, non-employee directors were paid an annual retainer of $19,000 in cash plus $19,000 in stock. They also received $900 in cash per Board or committee meeting attended. Beginning January 2000, non-employee directors will be paid an annual retainer of $20,000 in cash plus $20,000 in stock. They will also receive $1200 in cash per Board meeting attended.
Deferred Cash Compensation Plan
Directors may elect to defer their cash fees under this plan until they reach retirement or a specified age. The deferred fees are credited to either an interest bearing account or a Dominion common stock equivalent account. Interest or dividend equivalents accrue until distributions are made. A director will be paid in cash or stock according to the election made.
Stock Compensation Plan
The stock portion of the directors' retainer is paid under this plan. Directors have the option to defer receipt of the stock. If a director elects this option, the shares are held in trust until the director's retirement and the dividends on those shares are reinvested. However, the director retains all voting and other rights as a shareholder.
Stock Accumulation Plan
Upon election to the Board, a non-employee director receives a one-time award under this plan. The award is in Stock Units, which are equivalent in value to Dominion common stock. The award amount is determined by multiplying the director's annual cash retainer by 17, then dividing the result by the average price of Dominion common stock on the last trading days of the three months before the director's election to the Board. The Stock Units awarded to a director are credited to a book account. A separate account is credited with additional Stock Units equal in value to dividends on all Stock Units held in the director's account. A director must have 17 years of service to receive all of the Stock Units awarded and accumulated under this plan. Reduced distributions may be made where a director has at least 10 years of service.
Charitable Contribution Program
As part of its overall program of charitable giving, the Company offers the directors participation in a Directors' Charitable Contribution Program. The Program is funded by life insurance policies purchased by the Company on the directors. The directors derive no financial or tax benefits from the Program, because all insurance proceeds and charitable tax deductions accrue solely to the Company. However, upon the death of a director, the Company will donate an aggregate of $50,000 per year for ten years to one or more qualifying charitable organizations recommended by that director. Effective in January 2000, this program will not be offered to incoming directors.
Matching Gifts Program
Directors may give up to $1,000 per year to 501(c)(3) organizations of their choice and Virginia Power will match their donations on a 1-to-1 basis. If they volunteer more than 50 hours of work to any organization during a year, Virginia Power will match the donation on a 2-to-1 basis.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Beneficial Owners and Management
The table below sets forth as of February 18, 2000, except as noted, the number of shares of Dominion Common Stock owned by Directors and the executive officers named on the Summary Compensation Table.
- -------- (1) Amounts in this column represent share equivalents accumulated under the non-employee director Stock Accumulation Plan. Balances of shares are the amounts accumulated under the plan. Because of the plan's vesting provisions, these amounts will not necessarily be distributed to a director. Any balance in excess of is an amount of shares accumulated--at the director's election--under the Deferred Cash Compensation plan. That excess amount will be distributed in actual shares to the director. (2) Amounts include restricted stock as follows: Mr. Capps 29,932 shares; Mr. Askew 0; Mr. Farrell 6,525; Mr. Roach 693; Mr. Rigsby 5,062; Mr. Shaw 1,388; Mr. White 1,151; and all directors and executive officers as a group 64,953. (3) Mr. Farrell disclaims beneficial ownership of shares held by his spouse. (4) Includes shares held in trust under the Directors Stock Compensation Plan. (5) All current directors and executive officers as a group own less than one percent of the number of shares outstanding as of February 18, 2000. (6) Beneficial ownership is disclaimed for a total of 636 shares.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reed, Smith, Hazel & Thomas, LLP, a professional corporation, from time to time acts as counsel to the Company. Mr. Thomas, a Director of the Company, is a partner with Reed, Smith, Hazel & Thomas, LLP.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Form 10-K:
1. Financial Statements
See Index on page 31.
2. Exhibits
- -------- * Indicates management contract or compensatory plan or arrangement
(b) Reports on Form 8-K
None
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Virginia Electric and Power Company
Date:
/s/ Thos. E. Capps By: _________________________________ (Thos. E. Capps., Chairman of the Board Of Directors)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the day of March 7, 2000.
M. S. Bolton, Jr. (Principal Accounting Officer)