ITEM 1. BUSINESS
THE COMPANY
Virginia Electric and Power Company is a Virginia corporation with its principal office 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 Resources).
Virginia Electric and Power Company is a 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. 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 term "Virginia Power" refers to the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and all of our subsidiaries.
In Virginia we trade under the name "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.
Virginia Power had 8,981 full-time employees on December 31, 1998. A total of 3,126 of our employees are represented by the International Brotherhood of Electrical Workers under a contract extending to March 31, 2000.
COMPETITION
For most of this century, the structure of the electric industry in Virginia Power's service territory and throughout the United States has been relatively stable. Recently, however, there have been both federal and state developments toward less regulation and increased competition. Electric utilities have been required to open up their transmission systems for non- discriminatory use by potential 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 only competition for retail sales is if 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 implementing 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.
The Virginia General Assembly is actively considering in its current session, legislative proposals that would address more specifically the timetable for retail competition in the state; deregulation of the generation of electricity; transfer of management and control of transmission systems to a regional transmission entity; recovery of prudently incurred stranded costs and consumer protection issues. Additionally, we are in the process of developing a retail access pilot program for implementation in Virginia.
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 servicing traditional and future markets. In addition, we are developing certain "non-traditional" products and services as described in the above section entitled THE COMPANY 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).
REGULATION
GENERAL
The Virginia Commission and the North Carolina Commission regulate our rates for retail electric sales within their respective states. FERC approves our rates for electric sales to wholesale customers. A discussion of rate related matters is in the section below entitled RATES.
In addition to rates, many other 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.
Virginia Power holds certificates of public convenience and necessity issued by the Virginia Commission and the North Carolina Commission authorizing it 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 following sections discuss various regulatory proceedings in which we are or have recently been involved. Rate specific proceedings are discussed separately in the section below entitled RATES.
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.
On March 21, 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 Virginia Commission Staff and other interested stakeholders, to develop one or more ISO's and RPX's to serve the public interest in Virginia. In addition, the Order instructed Virginia Power and AEP-Virginia, as the Commonwealth's two largest investor-owned utilities, each to design and file a retail access pilot program. In response to the Order, we filed a report describing the details, objectives and characteristics of our proposed retail access pilot. For more details on the proposed retail access pilot program, see Future Issues -- COMPETITION -- REGULATORY INITIATIVES under MD&A.
We have sought approval from the Virginia Commission for the construction of four gas fired turbine generators in Virginia and is soliciting bids in accordance with the Virginia Commission's Order dated January 14, 1999. We have obtained the applicable zoning permits for the construction of the generators and have applied for other required environmental permits.
On January 28, 1999, the Virginia Commission issued an order approving the addition of two wholly-owned subsidiaries of Virginia Power Services, Inc., namely Virginia Power Services Energy Corp., Inc. (VPSE) and Virginia Power Energy Marketing, Inc. (VPEM), to the Affiliate Services Agreement approved by the Virginia Commission in its Order dated September 3, 1997. In connection with the organization of VPSE and VPEM, the Virginia Commission issued two related orders approving our transfer of certain contracts relating to the storage, transportation, procurement and management of our natural gas and oil inventory to these subsidiaries.
FERC
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 issued orders for third-party transmission service. FERC has also issued a number of rules of general applicability, 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, but 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.
On November 6, 1998, Virginia Power, along with American Electric Power (AEP), First Energy Corp. and Consumers Energy announced their agreement to move forward on a proposal to prepare a FERC filing to establish a regional transmission organization. For more detail on this proposal, see the INTERCONNECTIONS section below.
LG&E Westmoreland Southhampton (Southhampton) has requested waivers of FERC operating requirements with respect to its cogeneration facility in Franklin, Virginia. We have previously reported the existence and history of this proceeding. The parties have reached a settlement, which was accepted by FERC in December 1998.
ENVIRONMENTAL
We face substantial regulation and compliance costs with respect to environmental matters. For discussion of significant aspects of these matters, including our planned capital expenditures in 1999 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 Q 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.
NUCLEAR
All aspects of the operation and maintenance of our nuclear power stations 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 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 Commission Staff filed its Report recommending that adoption of a definitive policy on spent nuclear fuel disposal issues be delayed pending the outcome of litigation against the Department of Energy (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 Virginia Power's 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, Virginia Power 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, Virginia Power 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.
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 Future Issues -- NRC NUCLEAR DECOMMISSIONING RULE under MD&A and Note C to CONSOLIDATED FINANCIAL STATEMENTS.
RATES
Our electric service sales for 1998 included 64.3 million megawatt-hours of retail sales and 4.5 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.
FERC
Recent FERC proceedings relating to our rates include the following:
o In compliance with FERC's Order 889, on January 3, 1997, we filed our Procedures For Standards of Conduct for Unbundled Transmissions and Wholesale Merchant Function (Standards of Conduct) effective on that date. In July 1997, we filed several amendments to the Standards of Conduct in compliance with FERC's Order 889-A. On September 29, 1998 FERC accepted our revised Standards of Conduct with only minor modifications.
o On September 11, 1997, FERC authorized Virginia Power to make wholesale power sales under our Market-Based Sales Tariff but set a hearing to consider the effect of transmission constraints on our ability to exercise generation market power in localized areas within our service territory. Based upon a settlement in principle reached by the participants, the hearing schedule was suspended and we were directed to file a formal Offer of Settlement by May 11, 1998. The participants subsequently filed a formal Offer of Settlement that was accepted by FERC in January 1999. Under the Offer of Settlement, we agreed to refrain from wholesale power sales under our Market-Based Sales Tariff to loads located within our service territory. This settlement did not preclude us from requesting FERC authorization of such sales in the future, but until such authorization has been granted by FERC, agreements by Virginia Power to sell wholesale power to loads located within our service territory must be at cost-based rates accepted by FERC.
VIRGINIA
Recent Virginia proceedings related to our rates include the following:
o On June 8, 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. The Virginia Commission, by Order dated August 7, 1998, approved the settlement with only a minor redistribution of the agreed rate reduction among customer classes. The settlement defines a new regulatory framework for our transition to retail competition. For provisions of the settlement, see Note P to CONSOLIDATED FINANCIAL STATEMENTS.
o On October 31, 1997, we filed with the Virginia Commission an application for a reduction of $45.6 million in our fuel cost recovery factor for the period December 1, 1997 through November 30, 1998. The reduction became effective on an interim basis on December 1, 1997. Subsequently, as a result of amendments to two non-utility power purchase contracts, we proposed two additional reductions of approximately $30.2 million and $18 million for the same period, bringing the total proposed fuel factor reduction to $93.8 million. Both additional reductions were approved on an interim basis, effective March 1, 1998. On April 24, 1998, the Virginia Commission approved the decrease in the fuel factor effective May 1, 1998.
o On September 11, 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 February 24, 1999.
o On October 19, 1998, we filed an application with the Virginia Commission for an increase of $55 million in fuel rates. The increase was approved effective December 1, 1998.
NORTH CAROLINA
Recent North Carolina proceedings related to our rates include the following:
o On November 6, 1998, we filed for approval of a new Schedule 19 which governs purchases from cogenerators and small power producers. We proposed shortening the maximum term of contracts under Schedule 19 to three years. A public hearing took place on February 2, 1999. All proposed orders will be filed by March 12, 1999.
o On September 11, 1998, we filed an application with the North Carolina Commission for a $1.4 million increase in fuel rates. On December 23, 1998, 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, 1999.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
CONSTRUCTION AND NUCLEAR FUEL EXPENDITURES
Virginia Power's estimated construction and nuclear fuel expenditures for the three-year period 1999-2001, total $2.3 billion. We have adopted a 1999 budget for construction and nuclear fuel expenditures as set forth below:
- --------- * Includes amounts related to our proposed construction of four gas-fired turbine generator units in Fauquier County, Virginia. See FUTURE SOURCES OF POWER.
FINANCING PROGRAM
We currently have three shelf registrations on file with the Securities and Exchange Commission (SEC) providing us with $645 million of debt capital resources. We also have a Preferred Stock shelf registered with the SEC for $100 million in aggregate principal amount, which has not been utilized.
We intend to issue securities from time to time to meet our capital requirements, which include $321 million of long-term debt maturities in 1999.
Please see the 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 placed in a cold reserve status January 25, 1996.
(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 peak demand was 15,399 MW on July 22, 1998, and an all-time high one-hour integrated winter peak demand of 14,910 MW was reached on February 5, 1996.
SOURCES OF ENERGY USED, FUEL COSTS AND OPERATIONS
For information as to energy supply mix and the average fuel cost of energy supply, see Results of Operations under MD&A.
NUCLEAR OPERATIONS AND FUEL SUPPLY
In 1998, Virginia Power's four nuclear units achieved a combined capacity factor of 91.7 percent.
Virginia Power utilizes 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.
The DOE did not begin the acceptance of spent fuel in 1998 as specified in Virginia Power's contract with the DOE. However, on-site spent nuclear fuel 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 spent fuel.
For details on the issues of decommissioning and nuclear insurance, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.
FOSSIL OPERATIONS AND FUEL SUPPLY
Our fuel mix consists of coal, oil and natural gas. During 1998, 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
We purchase electricity under long-term contracts with other suppliers to meet a portion of our own system capacity requirements, as well as for short-term sales 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 with both utilities and non-utility generators. At the end of 1999, 900 MW of these purchases from other utilities will end, and by the first quarter of 2000, an additional 200 MW of diversity exchange transactions will be suspended. However, we continue to have contracts with 55 non-utility generators with a combined dependable summer capacity of 3,285 MW. During 1998, we entered into a long-term agreement to purchase 560 MW of electricity for sale to the wholesale market from two of three generating units at a plant being constructed in Mississippi. For information on the financial obligations under these agreements, see PURCHASED POWER CONTRACTS, Note Q 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, Virginia Power executed three agreements 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 will expire on December 31, 1999. We presently anticipate adding peaking capacity beginning in the year 2000 to meet our anticipated load growth. In addition, work is being done to return the North Branch unit to full operational capacity in the year 2000.
On August 11, 1998, Virginia Power filed an application with the Virginia Commission for a Certificate of Public Convenience and Necessity to construct five gas-fired combustion turbine generator units in Virginia. On October 21, 1998, we
modified our application to seek approval for one additional unit and expressed our intention to build four units in Fauquier County for operation in July 2000 and to build the remaining two units in Caroline County for operation in July 2001. On December 23, 1998, we further modified our application, withdrawing the pending request to construct the two combustion turbine units in Caroline County and seeking approval only for the four units to be constructed in Fauquier County for a total of 600 MW. We proposed to seek the additional capacity from the wholesale market.
A hearing before the Commission was held in January 1999 at which the Virginia Commission determined that the Rules Governing the Use of Bidding Programs to Purchase Electricity from Other Power Suppliers were applicable to the proposed transaction. The Virginia Commission issued an Order directing Virginia Power to issue a Request for Proposals (RFP) for the capacity needed. The Order further provided for the Virginia Commission Staff to review the solicitation process and set an expedited schedule that requires bidders to submit responses to our RFP no later than March 26, 1999. Our proposed build option will be considered as the benchmark for assessing the bid responses and, if our option represents the successful bid, we will be permitted to construct the four units proposed in our modified application. We have obtained the applicable zoning permits for construction of the combustion turbine generators in Fauquier County and have applied for other required permits including applicable environmental permits.
We also continue to pursue conservation and demand-side management (see CONSERVATION AND LOAD MANAGEMENT below).
CONSERVATION AND LOAD MANAGEMENT
Conservation and load management programs are evaluated in conjunction with our annual resource planning process. This process supports a conservation and load management portfolio, which contributes to the selection of low-cost resources to meet the future electricity needs of our customers.
Events in the evolving electric power marketplace and our regulatory and legislative environment continue to impact utility-sponsored conservation and load management programs. We continue to anticipate a greater reliance on price signals to convey information to our customers regarding energy-related costs, resulting in more efficient purchase decisions.
INTERCONNECTIONS
We maintain 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.
On November 6, 1998, Virginia Power, AEP, FirstEnergy Corp., and Consumers Energy announced their agreement to move forward on a proposal to prepare a FERC filing to establish a regional transmission organization. The proposed organization would operate the transmission systems of the companies, ensure transmission reliability and provide non-discriminatory access to the transmission grid. These companies have established a target date of Spring 1999 to prepare the filing.
As proposed, the governance and organization structures of the regional transmission organization will enable the formation of an ISO or a regional transmission company (TransCo). It will detail the mechanisms needed to transition from an ISO to a TransCo in the event the organization does not initially operate as a TransCo. It will be designed to meet the goals of reducing transmission costs that result from pancaked rates (accumulated transmission access fees resulting from transferring power over several transmission systems). It will also address transmission tariff, congestion management, operations and planning issues, as well as assisting in the development of a market approach to providing ancillary services.
While the companies are drafting the proposal and will be responsible to seek appropriate regulatory approval, the companies will continue to utilize the Alliance transmission development process established in December 1997. This is an open and cooperative effort, involving regular meetings and discussions with representatives from other investor-owned utilities, regulatory staff members, transmission customers, public power companies, municipal systems and rural electric cooperatives. This process provides input from diverse sources to assist in the formation of the organization.
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. 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.
We lease certain buildings and equipment. See Note G to CONSOLIDATED FINANCIAL STATEMENTS for details on our lease obligations.
See Virginia Power Generating Units under SOURCES OF POWER under Item 1. BUSINESS for a list of our principal generating facilities.
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. Management believes 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.
In December 1995, two civil actions were filed in the Virginia Circuit Court of the City of Norfolk against the City of Norfolk and Virginia Power, one for $15 million and one for $3 million. These matters have been resolved through settlement by the parties. On April 2, 1997, Doswell Limited Partnership (Doswell) filed a motion for judgment against Virginia Power in the Circuit Court of the City of Richmond. On the same date, Doswell also filed a complaint against Virginia Power in the United States District Court for the Eastern District of Virginia. These matters have been settled and the suits dismissed.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Dominion Resources 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
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.
The business and financial condition of Virginia Power 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, the EPA, the DOE, the NRC, the Virginia Commission and the 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,
recovery of the cost of purchased power, nuclear decommissioning costs, the ability of the Company, its suppliers, and its customers to successfully address Year 2000 compliance issues, 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 Virginia Power undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.
LIQUIDITY AND CAPITAL RESOURCES
OPERATING ACTIVITIES continue to be a strong source of cash flow, providing $1,094 million in 1998 compared to $1,091 million in 1997. Over the past three years, cash flow from operating activities, after dividend payments, has, on average, covered 137 percent of our total construction requirements and provided 83 percent of our total cash requirements. Our remaining cash needs are met generally 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 operations and the absence of major construction programs have reduced the Company's reliance on debt financing.
Cash from (used in) financing activities was as follows:
We have continued to take advantage of declining interest rates by issuing new debt at lower rates as higher-rate debt has matured. In 1998, $333.5 million of the Company's long-term debt securities matured with an average effective rate of 8.36 percent. As a partial replacement for this maturing debt, we issued $270 million of long-term debt securities during the year with an average effective rate of 6.71 percent.
We currently have three shelf registration statements effective with the SEC from which we can obtain additional debt capital: $400 million of Junior Subordinated Debentures; $375 million of Debt Securities, including First and Refunding Mortgage Bonds, Senior Notes and Senior Subordinated Notes; and $200 million of Medium-Term Notes, Series F. The remaining principal amount of debt that can be issued under these registrations totals $645 million. An additional capital resource of $100 million in preferred stock also is registered with the SEC.
The Company has 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 $221.7 million at December 31, 1998.
INVESTING ACTIVITIES in 1998 resulted in a net cash outflow of $581.9 million, primarily due to $450.8 million of construction expenditures and $80.9 million of nuclear fuel expenditures. The construction expenditures included approximately $281.8 million for transmission and distribution projects, $80.5 million for production projects, $57.9 million for information technology projects and $30.6 million for other projects.
Cash used in investing activities was as follows:
CAPITAL REQUIREMENTS
CAPACITY -- We anticipate that kilowatt-hour sales will grow approximately 3 percent a year through 2001. In addition, our purchase agreements with Hoosier (400 MW) and AEP (500 MW) will expire on December 31, 1999. To meet these requirements, we have developed plans to construct four 150 MW combustion turbines in Fauquier County, Virginia by midyear 2000 at a projected cost of $175 million to $190 million. However, on January 14, 1999, the Virginia Commission issued an Order directing the Company to solicit bids from independent suppliers to determine if a lower overall cost option is available.
FIXED ASSETS -- The Company's construction and nuclear fuel expenditures, during 1999, 2000 and 2001 are expected to total $802.5 million, $756.7 million and $762.7 million, respectively. We expect 1999 construction and nuclear fuel expenditures to be met through cash flow from operations, sales of securities and short-term borrowings.
We plan to install sulfur dioxide (SO2) emission control equipment at two coal fired generating units, and this will require a $115 million investment over the next four years. Management believes 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 oxides (NOx) reduction equipment at our coal fired generating stations at an estimated capital cost of $500 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. See Future Issues -- CLEAN AIR ACT COMPLIANCE.
LONG-TERM DEBT -- The Company will require $321 million to meet maturities of long-term debt in 1999, which we expect to meet with cash flow from operations and issuance of replacement debt securities. Other capital requirements will be met through a combination of sales of securities and short-term borrowings.
RESULTS OF OPERATIONS
The following is a discussion of results of operations for the years ended 1998 as compared to 1997, and 1997 as compared to 1996.
1998 COMPARED TO 1997
Balance available for common stock decreased by $239.3 million as compared to 1997, primarily due to settlement of the Company's rate case before the Virginia Commission in 1998. The settlement resulted in a rate reduction and refund and a writedown of regulatory assets. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
REVENUE changed from the prior year primarily due to the following:
ELECTRIC SERVICE REVENUE consists of sales to retail customers in our service territory at rates authorized by the Virginia and North Carolina commissions and sales to cooperatives and municipalities at wholesale rates authorized by FERC. The primary factors affecting this revenue in 1998 were a base rate refund and rate reduction arising from settlement of the Company's rate proceedings before the Virginia Commission and adjustments to annual fuel rates. See Note P to CONSOLIDATED FINANCIAL STATEMENTS. In addition, this revenue was affected by weather and customer growth.
Customer growth -- Sales resulting from new customer connections increased our revenue by $50.1 million in 1998 over 1997.
Weather -- The mild winter weather in 1998 caused customers to use less electricity than normal for heating. This reduction in sales was substantially offset by increased 1998 third quarter sales, as compared to third quarter 1997, resulting from warmer weather and increased usage by customers for cooling. This reduced 1998 revenue by $7.0 million as compared to 1997. Heating and cooling degree days were as follows:
Fuel rates -- The regulatory commissions having jurisdiction over the Company currently allow us to charge customers for the cost of fuel used in generating electricity. The decrease in fuel rate revenues is primarily attributable to lower fuel rates that went into effect December 1, 1997, and additional reductions effective March 1, 1998 and May 1, 1998 to recognize savings from negotiated changes to power supply contracts. These reductions were partially offset by an increase from the Company's annual fuel case that went into effect December 1, 1998. The rate changes decreased fuel revenues by $120.9 million as compared to 1997.
OTHER REVENUE includes sales of electricity beyond our service territory and sales of natural gas, net of the related cost of purchased commodities. It also includes revenue from nuclear consulting services and energy management services. Other revenue decreased in 1998 as compared to 1997 due to electricity trading revenues being reported net of purchased energy for the entirety of 1998 and only for the last four months of 1997. Such revenues are reported gross for the first eight months of 1997 as a result of being subject to cost of service rate regulation during that time.
EXPENSES changed from the prior year primarily due to the following:
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. However, the cost of power marketing purchases for the last four months of 1997 and the entirety of 1998 is being reported net of related revenues 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 ODEC's 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 (1) increased expenses associated with the restructuring of certain contracts and (2) the discontinuance of deferral accounting for such expenses. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
IMPAIRMENT OF REGULATORY ASSETS in 1998 is a write down of regulatory assets as a result of the Company's settlement of the rate proceeding before the Virginia Commission. See Note P to CONSOLIDATED FINANCIAL STATEMENTS. The 1996 and 1997 amounts represent a reserve for potential adjustments to regulatory assets.
OPERATIONS AND MAINTENANCE increased in 1998 as compared to 1997 primarily due to (1) costs to repair storm damage caused by December 1998 ice storms and by hurricane Bonnie in the third quarter of 1998 and (2) the cost of preparing the Company's computer systems for year 2000. See Future Issues -- YEAR 2000 COMPLIANCE.
RESTRUCTURING EXPENSES decreased in 1998 as compared to 1997. Although we are continuing to evaluate the Company's operations in anticipation of the restructuring of the electric industry, no significant restructuring expenses were incurred in 1998. See Note O to CONSOLIDATED FINANCIAL STATEMENTS.
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 P to CONSOLIDATED FINANCIAL STATEMENTS.
TAXES OTHER THAN INCOME increased in 1998 as compared to 1997 due to increased taxes associated with our wholesale power and natural gas marketing activities.
INCOME TAXES in 1998 decreased as compared to 1997 primarily due to the income tax provision associated with the effects of the settlement of our Virginia rate proceeding. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
1997 COMPARED TO 1996
ELECTRIC SERVICE REVENUES grew marginally in 1997 as compared to 1996. The primary factors affecting this revenue in 1997 were customer growth, weather, and fuel rates.
Customer growth -- There were more than 50,000 new customer connections to our system in 1997, the largest number of new connections in any year since 1990. This had the effect of increasing our sales by $55.8 million in 1997 over 1996.
Weather -- The mild weather in 1997 caused customers to use less electricity for heating and cooling, which reduced revenue by approximately $111.1 million from the previous year.
Fuel rates -- The increase in fuel rate revenues is primarily attributable to higher fuel rates, which went into effect December 1, 1996, increasing recovery of fuel costs by approximately $48.2 million.
OTHER REVENUE includes sales of electricity beyond our service territory, natural gas, nuclear consulting services and energy management services. The increase in revenue in 1997 compared to 1996 is primarily due to marketing of electricity beyond our service territory.
FUEL, NET increased in 1997 as compared to 1996, primarily due to the cost of the increased purchases of energy from other wholesale power suppliers associated with power marketing. Effective September 1997, these purchases are being reported in Other revenue with the related sales revenue. Prior to September 1997, this activity was subject to cost of service rate regulation.
OPERATIONS AND MAINTENANCE increased in 1997 as compared to 1996 as a result of costs associated with the growth in sales of energy management services. These higher costs were offset partially by a reduction in expenses attributable to the Company's strategic initiatives. See Note O to CONSOLIDATED FINANCIAL STATEMENTS. Expenses in 1996 include high storm damage costs resulting from destructive summer storms, including Hurricane Fran.
RESTRUCTURING EXPENSES decreased in 1997 as compared to 1996 due to lower expenses from the Company's strategic initiatives in anticipation of industry restructuring. Charges for restructuring primarily include employee severance costs, costs to restructure agreements to purchase power from third parties and, when necessary, to negotiate settlement and termination of these contracts and other costs. See Note O to CONSOLIDATED FINANCIAL STATEMENTS.
DEPRECIATION AND AMORTIZATION increased in 1997 as compared to 1996 due to the recognition of additional depreciation and nuclear decommissioning expense to reflect adjustments in the rate proceeding then pending before the Virginia Commission and higher depreciation expense related to Clover Unit 2, which began operations in March 1996.
FUTURE ISSUES
COMPETITION IN THE ELECTRIC INDUSTRY -- GENERAL
For most of this century, the structure of the electric industry in Virginia and throughout the United States has been relatively stable. We have recently seen, however, federal and state developments toward increased competition. Electric utilities have been required to open up 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 enacted legislation requiring the introduction of retail competition.
Today, Virginia Power faces competition in the wholesale market. There is no general retail competition in Virginia Power's 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. The legislation established the principle that just and reasonable net stranded costs would be recoverable, but it left the details as to how that would be accomplished to future enabling legislation.
At the time of this report, the General Assembly of Virginia is in session and is considering proposed legislation that would establish a detailed plan to restructure the electric utility industry in Virginia. We are actively supporting restructuring legislation, which would provide the necessary details to implement the legislation passed in 1998. See COMPETITION -- RETAIL AND COMPETITION -- LEGISLATIVE INITIATIVES below.
In addition to our legislative activity, we have responded to the trend toward competition by renegotiating long-term contracts with wholesale and large federal government customers. We have obtained regulatory approval of innovative pricing proposals for large industrial customers. Rate concessions resulting from these contract negotiations and innovative pricing proposals are expected to reduce the Company's 1999 revenue by approximately $45 million as compared to the amounts that would have been billed prior to such measures.
We have also 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
On September 11, 1997 FERC authorized us to make wholesale power sales under our Market Based Sales Tariff, but set a hearing to consider the effect of transmission constraints on our ability to exercise generation market power in localized areas within our service territory. In connection with such proceeding, the participants filed a formal Offer of Settlement that was accepted by FERC in January 1999. Under the Offer of Settlement, we agreed not to make wholesale power sales under our Market-Based Sales Tariff to loads located within our service territory. This settlement did not preclude us from requesting FERC authorization of such sales in the future, but 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 1998, sales to wholesale customers under requirements contracts represented approximately 4 percent of our total revenues from electric sales. 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 implemented a new arrangement with our largest wholesale customer that provides for a transition from cost-based rates to market-based rates. The reduced rates, offset in part by other revenues which may be earned under the agreement, are expected to decrease net income by approximately $21 million during the period 1999 through 2005.
As a result of the increased competitive pressures on sales to wholesale customers, we are reevaluating the recoverability of regulatory assets previously assigned to our wholesale customers from such customers or by reallocation to our retail customers. Based on the principles included in the settlement of our Virginia rate proceedings in 1998 and the restructuring legislation now before the Virginia General Assembly, recovery of these costs from our Virginia retail customers would be unlikely. Furthermore, although future federal legislation may ultimately address the restructuring of the electric utility industry, we do not believe it would provide for the recovery of regulatory assets from our wholesale customers. See COMPETITION -- SFAS 71.
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 only if certain of its business customers move into another utility service territory, use other energy sources instead of electric power, or generate their own electricity.
However, the 1998 Virginia General Assembly passed House Bill No. 1172 (HB1172) which established the principles and a schedule for Virginia's transition to retail competition in the electric utility industry. The new law, which became effective on July 1, 1998, requires the following:
o establishment of one or more independent system operators (ISO) and one or more regional power exchanges (RPX) for Virginia by January 1, 2001;
o deregulation of generating facilities beginning January 1, 2002;
o transition to retail competition to begin on January 1, 2002, with full retail competition to be completed on January 1, 2004;
o recovery of just and reasonable net stranded costs; and
o appropriate consumer safeguards related to stranded costs and consideration of stranded benefits.
This legislation established a timeline for deregulation of retail electric service but left the details regarding implementation to future enabling legislation. Such legislation is now under consideration by the Virginia General Assembly. See COMPETITION -- LEGISLATIVE INITIATIVES below.
North Carolina is also considering implementing retail competition.
COMPETITION -- LEGISLATIVE INITIATIVES
Virginia: We actively supported HB1172 during the 1998 General Assembly session and currently support comprehensive restructuring legislation being considered by the 1999 General Assembly. A special joint legislative subcommittee, which has been proactively examining electric industry restructuring for the past three years, has drafted and presented a bill to the
Senate for consideration during the 1999 session of the General Assembly. The major elements of the bill, which is supported by a broad coalition of consumer groups and utilities, include:
o phase-in of retail customer choice beginning in 2002 with full retail customer choice by 2004; the schedule is to be determined by the 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;
o no mandatory divestiture of generating assets;
o deregulation of generation in 2002;
o capped base rates from January 1, 2001 to July 1, 2007;
o recovery of net stranded costs through capped base rates or a wires charge paid by those customers opting, while capped rates are in effect, to purchase energy from a competitive supplier;
o consumer protection safeguards;
o establishment of default service beginning January 1, 2004; and
o creation of a Legislative Transition Task Force to oversee the implementation of the statute.
Under this proposed legislation, the Company's base rates would remain unchanged until July 2007. If this legislation is enacted, the generation portion of our Virginia jurisdictional operations would no longer be subject to cost-based rate regulation beginning in 2002, although recovery of generation-related costs would continue to be provided through the capped rates until July 2007.
The Senate approved this legislation in Senate Bill No. 1269 on February 9, 1999 (the Senate Bill). Whether all of the provisions of the Senate Bill will ultimately be included in enacted legislation is uncertain. We believe passage of Virginia restructuring legislation is likely in 1999 but cannot predict what provisions would be included, if restructuring legislation is ultimately enacted. See COMPETITION -- EXPOSURE TO POTENTIALLY STRANDED COSTS and COMPETITION -- SFAS 71.
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.
North Carolina: The 1997 Session of the North Carolina General Assembly created a Study Commission on the Future of Electric Service in North Carolina. The North Carolina Commission received and published comments from interested parties in May 1998. An interim report was expected in 1998 but has not yet been issued.
COMPETITION -- REGULATORY INITIATIVES
The Virginia Commission has been actively interested in industry restructuring and competition, as illustrated by its establishment of several generic and utility-specific restructuring related proceedings since 1995.
On March 20, 1998, the Virginia Commission issued an Order regarding the establishment of ISOs, RPXs and retail access pilot programs. In direct response to that Order, we filed a report on November 2, 1998, describing the details, objectives and characteristics of our proposed retail access pilot program. We are also complying with the Order by filing reports on a regular basis on activities concerning our efforts to establish an ISO and RPX.
Our proposed retail access pilot program envisions retail customer choice being available to 24,000 customers, or about 1% of our retail load under the jurisdiction of the Virginia Commission. The Virginia Commission created a generic proceeding to address issues common to both electric and gas retail access pilot programs throughout the Commonwealth of Virginia. On December 3, 1998, the Virginia Commission issued an Order setting our retail access pilot program proposal for hearing on June 29, 1999, to consider the remaining issues and details. It is anticipated that the regulatory proceedings will take much of 1999 to complete and delivery of competitively procured electricity under our pilot program will not occur until mid-2000.
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.
The Company's exposure to stranded costs is comprised of the following:
o long-term purchased power contracts that may be above market (see PURCHASED POWER CONTRACTS, Note Q to the CONSOLIDATED FINANCIAL STATEMENTS);
o costs pertaining to certain generating plants that may become uneconomic in a deregulated environment;
o regulatory assets for items such as income tax benefits previously flowed-through to customers, deferred losses on reacquired debt and other costs; (see Note F to CONSOLIDATED FINANCIAL STATEMENTS); and
o unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements (see Notes C and N to CONSOLIDATED FINANCIAL STATEMENTS).
As previously discussed under COMPETITION -- LEGISLATIVE INITIATIVES, any recovery of potentially stranded costs from Virginia retail customers under the Senate Bill would occur during the rate freeze period. See COMPETITION -- SFAS 71 below. If such legislation is enacted, the extent of our recovery for these costs would depend on many factors, including, but not limited to, weather, sales and load growth, future power station performance and unanticipated expenses (e.g., equipment failures and storm damage).
COMPETITION -- SFAS 71
Virginia Power's financial statements reflect assets and costs under cost-based rate regulation in accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71), ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION. SFAS 71 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. The presence of increasing competition that limits the utility's ability to charge rates that recover its costs, or a change in the method of regulation with the same effect, could result in the discontinued applicability of SFAS 71.
Rate-regulated companies are required to write off regulatory assets against earnings whenever those assets no longer meet the criteria for recognition as defined by SFAS 71. In addition, SFAS 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF, requires a review of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset would not be recoverable. Thus, events or changes in circumstances that cause the discontinuance of SFAS 71, and write-off of regulatory assets, would also require a review of utility plant assets for possible impairment. If such review indicates utility plant assets are impaired, the carrying amount of the affected assets would be written down. See Note D to CONSOLIDATED FINANCIAL STATEMENTS. This would result in a loss being charged to earnings, unless recovery of the loss is provided through operations that remain regulated. It would also be appropriate to review long-term purchase commitments for potential impairment in accordance with SFAS 5, ACCOUNTING FOR CONTINGENCIES. See PURCHASED POWER CONTRACTS, Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
At December 31, 1998, our regulated operations satisfied SFAS 71 requirements for continued recognition of regulatory assets. However, if the Senate Bill is enacted, the generation portion of our Virginia jurisdictional operations would no longer be subject to cost-based regulation beginning in 2002, although recovery of generation-related costs would continue to be provided through the capped rates until July 2007. When enacted legislation provides sufficient details about the transition to deregulation of generation, we would discontinue the application of SFAS 71 for the generation portion of our Virginia jurisdictional operations and determine the amount of regulatory assets to be written off.
In order to measure the amount of regulatory assets to be written off, we must evaluate to what extent recovery of regulatory assets would be provided through cost-based rates. We would not be required to write off regulatory assets for which recovery would be provided by either cost-based rates or a separate, stranded cost recovery mechanism. Emerging Issues Task Force 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 97-4), provides guidance about writing off regulatory assets when SFAS 71 is discontinued for only a portion of a utility's operations. However, until the final provisions of the Virginia legislation are known, we believe the measurement of regulatory assets to be written off under SFAS
71 and EITF 97-4 is uncertain. If a write-off of regulatory assets is required, such write-off could materially affect Virginia Power's financial position and results of operations. See Note F to CONSOLIDATED FINANCIAL STATEMENTS. At the time of this report, we believe passage of Virginia restructuring legislation is likely in 1999 but cannot predict what provisions would be included, if restructuring legislation is ultimately enacted.
We believe the stable rates that would be provided until July 2007 by the Senate Bill, coupled with the opportunity to pursue further reductions in our operating costs, would present a reasonable opportunity to recover a substantial portion of our potentially stranded costs. However, as discussed above, if the application of SFAS 71 is discontinued for any part of utility operations, we would also perform an impairment evaluation with respect to property, plant and equipment as well as long-term power purchase commitments. The impairment assessment may be required on a disaggregated basis rather than as an aggregate portfolio. Thus, the recognition of impairments, if any, could potentially not be mitigated by other assets or contracts with estimated values in excess of respective carrying amounts or contract payments. If our evaluation concludes that an impairment exists, an additional loss would be charged to earnings. Because the impairment evaluation has not been completed, we cannot estimate the amount of loss, if any, that would be recognized. However, such amount could materially affect the Company's financial position and results of operations.
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. These costs have been historically recovered from customers through utility rates. However, see COMPETITION -- LEGISLATIVE INITIATIVES for a discussion of legislation that, if enacted, would provide a transition from cost based to competitive pricing in Virginia.
ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
We incurred $71.9 million, $70.4 million, and $71.1 million (including depreciation) during 1998, 1997 and 1996, respectively, in connection with the use of environmental protection facilities, and we expect these expenses to be $71.1 million in 1999. In addition, capital expenditures to limit or monitor hazardous substances were $22.2 million, $24.6 million and $22.4 million for 1998, 1997 and 1996, respectively. The amount estimated for 1999 for these expenditures is $106.9 million.
CLEAN AIR ACT COMPLIANCE
The Clean Air Act, as amended in 1990, requires the Company to reduce its emissions of SO2 and NOx which are gaseous by-products of fossil fuel combustion.The Clean Air Act also requires us to obtain operating permits for all major emissions-emitting facilities. Permit applications have been submitted for the Company's power stations.
The Clean Air Act's SO2 reduction program is based on the issuance of a limited number of SO2 emission allowances, each of which may be used as a permit to emit one ton of SO2 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, purchase of emission allowances and installation of SO2 control equipment. In December 1998 we initiated a capital project to install SO2 control equipment on two units at our Mt. Storm power station at an estimated cost of $115 million.
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.
However, in September 1998, the EPA adopted a rule which requires 22 states, including Virginia, North Carolina, and West Virginia, to reduce and cap NOx emissions beginning in 2003. The rule allows each state to determine how to achieve the required reduction in emissions. By September 1999, each affected state must develop and submit a plan to the EPA that details how the state will achieve its emission cap. If states adopt the approach suggested by the EPA, it is probable we will incur major capital expenditures, in the range of $500 million. These expenditures would satisfy the Clean Air Act Phase II standards for NOx, thereby eliminating the need under existing law to make additional investment beginning in 2008. We will closely monitor the development of NOx emission cap plans by the various states.
Evaluation and planning on future projects to comply with SO2 and NOx reduction requirements are ongoing and will be influenced by changes in the regulatory environment, availability of SO2 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 on December 10, 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.
NRC NUCLEAR DECOMMISSIONING RULE
Effective November 23, 1998, the NRC amended its nuclear decommissioning financial assurance requirements. In particular, the NRC limited the use of the sinking fund method to only that portion of a licensee's collections for decommissioning that is recovered through either traditional cost of service rate regulation or through non-bypassable charges. The majority of our decommissioning collections are currently recovered through cost of service rate regulation. However, a portion of our decommissioning collections are recovered through contracted rates, and we have established a parent company guarantee to satisfy the NRC's revised requirements. Furthermore, we will be evaluating the implications on our method of satisfying the NRC financial assurance requirements that may result from enactment of the legislation currently before the Virginia General Assembly. See COMPETITION -- LEGISLATIVE INITIATIVES.
RECENTLY ISSUED ACCOUNTING STANDARDS
In June 1998, the FASB issued SFAS No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. The statement 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. The statement requires that changes in a derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for the Company beginning in 2000; however, it may be adopted earlier. It cannot be applied retroactively to financial statements of prior periods.
We have not yet quantified the impacts of adopting SFAS No. 133 and have not yet determined the timing of, or method of, adoption. Since the impact is a function of market prices and other measures of fair value, any quantification would be subject to change. The adoption of the statement could increase volatility in earnings and other comprehensive income.
In November 1998, the Emerging Issues Task Force reached consensus on Issue No. 98-10, ACCOUNTING FOR CONTRACTS INVOLVED IN ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES (EITF Issue 98-10). We must adopt EITF Issue 98-10 in 1999. EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet with the changes in fair value included in earnings. The effects of the initial application of EITF Issue 98-10 will be reported as a cumulative effect of a change in accounting principle.
We manage a portfolio of energy contracts which are currently recorded at fair value on the balance sheet with the changes in fair value included in earnings as required by EITF Issue 98-10. However, we have not yet completed our review of other energy-related contracts held by the Company that could possibly be subject to EITF Issue 98-10. Thus, we have not yet quantified the impact of adoption.
YEAR 2000 COMPLIANCE
We are preparing our computer systems and computer-driven equipment and devices for the year 2000. Virtually every computer operation could be affected in some way by the rollover of the two-digit year value from 99 to 00. Systems or devices that use computer chips that do not properly recognize date-sensitive information when the year changes to 2000 could generate erroneous data or fail.
If not properly addressed, the year 2000 problem could result in computer and other equipment failures both within Virginia Power and at third parties with which we transact business. Because of the extensive use of technology throughout our business and the businesses of our suppliers and customers, failures in any of these areas could impact our business.
Our objective is to be year 2000 ready. "Year 2000 ready" means that critical systems, devices, applications and business relationships have been evaluated and are expected to be suitable for continued use into and beyond the year 2000.
We have organized formal year 2000 project teams to identify, correct or reprogram and test our systems for year 2000 readiness. These teams are addressing all critical aspects of our business, including information systems, embedded systems and external relationships with business partners. Information systems encompass traditional information technology systems such as financial reporting, accounting and purchasing systems. Embedded systems primarily represent specialized computers used to control, monitor or assist the operations of equipment. External relationships include suppliers and other service providers. The teams are overseen by an executive who reports regularly to the Board of Directors.
Our year 2000 remediation program involves completing four major phases: (1) inventorying of computer systems and embedded systems that could potentially be affected by the year 2000 problem; (2) screening to determine date sensitivity within the inventoried systems; (3) impact assessment; and (4) remediation and testing. We have completed the first three phases. Approximately 93% of our systems identified as critical to Company operations were year 2000 ready at December 31, 1998. We anticipate that 99% of such systems will be year 2000 ready in July 1999 with 100% completion prior to January 1, 2000.
In addition to these internal efforts, we are assessing the state of readiness of our major suppliers and service providers. We have implemented initiatives to prevent the future procurement of non-year 2000 compliant technology. We are also meeting with the non-utility power producers who supply us energy under power purchase contracts to share information about year 2000 readiness.
We expect year 2000 costs to be within the range of $30 million to $40 million, which is a change from our original estimate of $40 million to $50 million. This downward revision is due in part to completion of the assessment phase, progress made on the remediation and testing phase, and an increase in information from critical suppliers and other significant external sources.
Actual year 2000 costs as of December 31, 1998 are $10.8 million. The effort to date has been primarily focused on critical systems and the remaining expenditures are for critical and non-critical year 2000 preparedness. Some expenditure for non-critical systems will be incurred in the year 2000.
Maintenance and modification costs will be expensed as incurred, while the costs of new software and hardware will be capitalized and amortized over the asset's useful life. These costs do not include capital expenditures for major information systems that were initiated for normal business reasons without regard to year 2000 issues.
Congress has directed the Department of Energy (DOE) to ascertain the readiness of all electric utilities for year 2000. DOE has in turn asked the North American Electric Reliability Council (NERC) to coordinate and monitor year 2000 activities in the electric industry. NERC is comprised of ten regional councils whose members represent the major bulk power suppliers of the electric industry. We are actively participating with other NERC members, including our local regional council, the Southeastern Electric Reliability Council (SERC). Of primary importance is the reliability of the transmission network for delivery of energy to customers. This reliability is achieved by participation of many utilities in the supply to, and control of, their individually owned portions of the network. The failure of an individual utility to manage successfully its transmission network could affect this reliability which could have a material adverse effect on the Company.
Our contingency planning efforts to ensure continuity of operations into and beyond the year 2000 are on schedule to be completed by June 30, 1999. The Company and the U.S. electric utility industry already have extensive contingency plans in place for many events such as extreme heat, storms and equipment failures. Our Year 2000 contingency planning is an extension of these existing plans. We are coordinating our efforts with SERC and NERC, and will participate in the nationwide drills planned by NERC for April 9, 1999 and September 9, 1999. As part of this process, we must consider and evaluate reasonably likely worst case scenarios and their impact on critical business processes.
Based on our preliminary evaluations, which include SERC and NERC efforts to date, reasonably likely worst case scenarios could include:
o minor variations in voltage or frequency with no significant effect on electric service;
o temporary loss of a portion of generation capacity, including possibly non-utility generators; however, such loss is not expected to be sufficient to adversely affect electric service;
o temporary loss of some telecommunications functionality and other services with no impact expected on electric service; and
o temporary loss of a small portion of commercial and industrial customer loads.
We cannot estimate or predict the potential adverse consequences, if any, that could result from a third party's failure to effectively address the year 2000 issue but we believe that any impact would be short-term in nature and would not have a material adverse impact on our business or results of operations. The objective of the contingency planning process is to mitigate internal and external risks and assure a continuous and sustained delivery of electricity to all customers. Based on Company and industry analyses to date, we do not believe the reasonably likely worst case scenarios identified above, if they were to occur, would have a material adverse effect on our business or results of operations. We plan to have all contingency plans identified and tested prior to year-end 1999.
The descriptions herein of the elements of our year 2000 effort are forward-looking statements. Of necessity, this effort is based on estimates of assessment, remediation, testing and contingency planning activities and perceived problems not yet identified. There can be no assurance that actual results will not differ materially from expectations.
ITEM 7A.
ITEM 7A. MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT
Virginia Power is subject to market risk as a result of its use of various financial instruments and derivative commodity instruments. Interest rate risk generally is associated with our outstanding debt, preferred stock and trust-issued securities. We are also exposed to interest rate risk as well as equity price risk as a result of our nuclear decommissioning trust investments in debt and equity securities.
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 exchange-for-physical contracts, basis swaps, fixed price forward contracts and options which require physical delivery of the underlying commodity, 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, 1998 and 1997. This hypothetical 10% change in commodity prices would have resulted in a hypothetical loss of approximately $13.5 million and $2.5 million in the fair value of our commodity contracts as of December 31, 1998 and 1997, respectively. The commodity contracts' sensitivity to unfavorable price changes increased in 1998 as compared to 1997 primarily due to the increased volume of contracts and associated commodities.
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
Virginia Power uses both fixed rate and variable rate debt and preferred securities as sources of capital. The following table presents the financial instruments that are held or issued by the Company at December 31, 1998 and 1997, and are sensitive to interest rate changes in some way. Weighted average variable rates are based on implied forward rates derived from appropriate annual spot rate observations as of December 31, 1998 and 1997.
- --------- (1) Rates are based on average yield for entire portfolio at December 31, 1998 and 1997.
(2) Interest rates on the tax-exempt bonds are based on short-term, tax-exempt market rates and are reset for periods of one to 270 days in length. We have the option to convert these bonds to fixed rate securities upon 40 days written notice. See Note H to CONSOLIDATED FINANCIAL STATEMENTS.
(3) Notional amount of contracts is $150 million. On February 5, 1999 these contracts were closed resulting in a gain of $5.6 million.
EQUITY PRICE RISK
The following table presents a description of marketable equity securities held by the Company at December 31, 1998 and 1997. In accordance with SFAS 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES, these securities are reported on the balance sheet at fair value. See Future Issues - -- NRC NUCLEAR DECOMMISSIONING RULE.
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 1998 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, composed entirely of directors who are not officers or employees of the Company, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters 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
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, 1998 and 1997, 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, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with 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 financial position of the Company at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
Richmond, Virginia February 8, 1999
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
The Company had no other comprehensive income reportable in accordance with SFAS 130, REPORTING COMPREHENSIVE INCOME.
The accompanying notes are an integral part of the financial statements.
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 SHAREHOLDERS' EQUITY
(*) As described in Note I to CONSOLIDATED FINANCIAL STATEMENTS, the 8.05% Junior Subordinated Notes totaling $139.2 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 applicable to regulated enterprises. 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., 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 revenues and expenses during the reporting period. Actual results could differ from those estimates.
REVENUES
Revenues are recorded on the basis of services rendered, commodities delivered or contracts settled and include amounts yet to be billed to customers. Revenues from trading activities include realized commodity contract revenues, net of related cost of sales, amortization of option premiums and unrealized gains and losses resulting from marking to market those commodity contracts not yet settled.
FUEL, NET
Fuel, net 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 90% of the Company's 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 revenues. Fuel, net includes the effect of this deferral accounting and may therefore show expenses that are marginally higher or lower than the actual cost of fuel consumed during the period.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at original cost, which includes labor, materials, services, AFC, where permitted by regulators, and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense and clearing 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 utility plant (other than nuclear fuel) is computed on the straight-line method based on projected useful service lives. The cost of depreciable utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation. The provision for depreciation provides for the recovery of the cost of assets including the estimated cost of removal, net of salvage, and is based on the weighted average depreciable plant using a rate of 3.2 percent for 1998, 1997 and 1996.
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 Resources.
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 Statement of Financial Accounting Standards No. 71 (SFAS 71), ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION. SFAS 71 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. See Note F and UTILITY RATE REGULATION, Note Q to CONSOLIDATED FINANCIAL STATEMENTS for information on the Company's regulatory assets and the potential impact of legislation on continued application of SFAS 71.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The applicable regulatory Uniform System of Accounts defines AFC as the cost during the construction period of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.
AFC rates for 1998, 1997 and 1996 were 6.7 percent, 6.6 percent and 8.1 percent, respectively. No AFC is accrued for approximately 87 percent of the Company's construction work in progress, which is instead included in rate base. A cash return is collected on the portion of construction work in progress included in rate base.
AMORTIZATION OF DEBT ISSUANCE COSTS
The Company defers and amortizes any expenses incurred in the issuance of long-term debt, including premiums and discounts associated with such debt, over the lives of the respective issues. Any gains or losses resulting from the refinancing of debt are also deferred and amortized over the lives of the new issues of long-term debt as permitted by the appropriate regulatory jurisdictions. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.
CASH AND CASH EQUIVALENTS
Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 1998 and 1997, the Company's accounts payable included the net effect of checks outstanding but not yet presented for payment of $48.6 million and $55.8 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 the utility operations, the Company uses exchange-for-physical contracts, basis swaps and exchange-traded futures and options.
Options, exchange-for-physical contracts, basis swaps and futures are marked to market with resulting gains and losses reported in earnings, unless such instruments are designated as hedges for accounting purposes. Fixed price forward contracts, initiated for trading purposes, also are marked to market with resulting gains and losses reported in earnings. For exchange-for-physical contracts, basis swaps, fixed price forward contracts and options which require physical delivery of the underlying commodity, 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. No commodity contracts were designated as hedges during 1998 and 1997.
Commodity contracts representing unrealized gain positions are reported as Commodity contract assets; commodity contracts representing unrealized losses are reported as Commodity contract liabilities. In addition, purchased options and options sold are reported as Commodity contract assets and Commodity contract liabilities, respectively, at estimated market value until exercise or expiration. Realized commodity contract revenues, net of related cost of sales, settlement of
futures contracts, amortization of option premiums and unrealized gains and losses resulting from marking positions to market are included in Other revenue. Cash flows from trading activities are reported in Net Cash Flow from Operating Activities.
RECLASSIFICATION
Certain amounts in the 1997 and 1996 financial statements have been reclassified to conform to the 1998 presentation. In addition, in the fourth quarter of 1998, the Company changed the way it reports energy commodity contracts. Thus, the reclassifications include netting the cost of commodities purchased for trading purposes, not subject to cost of service rate regulation, against commodity trading revenue in Other revenue. The gross amount of revenue and expense generated from these contracts had previously been reported in Other revenue and Fuel, net, respectively, within the Statements of Income.
B. 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:
The Company's net accumulated deferred income taxes consist of the following:
C. 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 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 $36.2 million per year for the period 1996 through 1998. However, an additional $9.6 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 $9.6 million. Therefore, the expense levels were $26.6 million, $45.8 million and $36.2 million in 1998, 1997 and 1996, respectively.
Net earnings of the trusts' investments are included in Other Income in the Company's Consolidated Statements of Income. In 1998, 1997 and 1996, net earnings were $17.5 million, $20.5 million and $16.0 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, 1998, the net unrealized gains were $230.5 million, which is an increase of $81.0 over the December 31, 1997, amount of $149.5 million. The accumulated provision for decommissioning at December 31, 1998 and 1997, was $703.9 million and $578.7 million, respectively.
The total estimated cost to decommission the Company's four nuclear units is $1.6 billion based upon a site-specific study that was completed in 1998. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. This method assumes that dismantlement and other decommissioning activities will begin shortly after cessation of operations, which under current operating licenses will begin in 2012 as detailed in the table below.
- --------- * Excludes an additional $1.3 million deposited into the trusts prior to the settlement of the Virginia rate case, which will be considered as a partial prepayment for calendar year 1999 contributions.
The Financial Accounting Standards Board (FASB) is reviewing the accounting for nuclear plant decommissioning. In 1996, FASB 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. If the industry's accounting were changed to reflect FASB's tentative proposal, the annual provisions for nuclear decommissioning would also increase. 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, including non-nuclear power plants. Therefore, any forthcoming standard also may change industry plant depreciation practices. Any impact related to other Company assets cannot be determined at this time.
INSURANCE
The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $9.7 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 $90.7 million (including a 3 percent insurance premium tax for Virginia) for each of its four licensed reactors not to exceed $10.3 million (including a 3 percent insurance premium tax for Virginia) 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 $28.8 million. Based on the severity of the incident, the board of directors of the Company's nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination, the Company has the financial responsibility for these losses.
The Company purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, 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 $6.8 million.
As part owner of the North Anna Power Station, ODEC 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.
D. PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, other than nuclear fuel, consists of the following:
E. JOINTLY OWNED PLANTS:
The following information relates to the Company's proportionate share of jointly owned plants at December 31, 1998:
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.
F. REGULATORY ASSETS
The Company's regulatory assets include the following:
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 $109 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.
Losses or gains on reacquired debt are deferred and amortized over the lives of the new issues of long-term debt. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.
The cost of preparing detailed design documentation of the Company's nuclear power stations required by the Nuclear Regulatory Commission has been deferred and is currently being recovered through rates over the life of the respective power stations.
The construction of North Anna Unit 3 was terminated in November 1982. All retail jurisdictions have permitted recovery of the incurred costs. For Virginia and FERC jurisdictional customers, the amounts deferred are being amortized from the date termination costs were first includible in rates. The recovery of these costs will be completed in 1999.
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. The Company does not earn a return on $15.4 million of regulatory assets, effectively excluded from rate base, to be recovered over various recovery periods up to 20 years, depending on the nature of the deferred costs.
For information about the impairment of regulatory assets resulting from the settlement of the Company's Virginia rate proceedings and the potential impact on regulatory assets if certain legislation currently being considered by the Virginia General Assembly is enacted, see Note P and UTILITY RATE REGULATION, Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
G. LEASES:
Property, plant and equipment under capital leases includes the following:
- --------- (*) The Company leases its principal office building from its parent, Dominion Resources. The capitalized cost of the property under that lease, net of accumulated amortization, represented $20 million and $22 million at December 31, 1998 and 1997, respectively. The rental payment for this lease was $3 million for each of the three years ended December 31, 1998, 1997 and 1996.
The Company is responsible for expenses in connection with the leases noted above, including maintenance.
Future minimum lease payments under noncancellable capital leases and for operating leases that have initial or remaining lease terms in excess of one year as of December 31, 1998, are as follows:
Rents on leases, which have been charged to operations expense, were $17.7 million, $17.6 million and $16.5 million for 1998, 1997 and 1996, respectively.
H. LONG-TERM DEBT:
Long-term debt includes the following:
- --------- (1) The First and Refunding Mortgage Bonds 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 the financings.
(3) Interest rates vary based on short-term, tax-exempt market rates. For 1998 and 1997, the weighted average daily interest rates were 3.49 percent and 3.74 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 (in millions): 1999 -- $321.0; 2000 -- $195.5; 2001 -- $160.7; 2002 -- $315.0; and 2003 -- $240.5.
I. 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 $139.2 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 $4.2 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.
J. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION:
The total number of authorized shares for all preferred stock (whether or not subject to mandatory redemption) is 10,000,000 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, 1998:
There were no redemptions of preferred stock during the years 1996 through 1998.
K. 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, 1998.
- --------- (*) 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 1998, 1997 and 1996, including fees for broker/dealer agreements, were 4.60 percent, 4.71 percent, and 4.48 percent, respectively.
L. 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, 1998.
M. 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, 1998, was $221.7 million with a weighted average interest rate of 5.38 percent. This represents a decrease of $4.5 million from the December 31, 1997, balance of $226.2 million and a weighted average interest rate of 5.88 percent.
N. 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 $20.5 million, $20.6 million and $24.8 million for 1998, 1997 and 1996, respectively, and the amounts funded by the Company were $20.5 million. $27.0 million and $28.4 million in 1998, 1997 and 1996, 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:
The following table sets forth the funded status of the plan:
Significant assumptions used in determining postretirement benefit obligations were:
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 Company is recovering these costs in rates on an accrual basis in all material respects, in all jurisdictions. However, see UTILITY RATE REGULATION, Note Q to CONSOLIDATED FINANCIAL STATEMENTS for a discussion of legislation that, if enacted, would provide the necessary details about the restructuring of the electric utility industry in Virginia. The funds collected for other postretirement benefits in rates, in excess of benefits actually paid during the year, are contributed to external benefit trusts under the Company's current funding policy.
O. RESTRUCTURING:
The Company announced a program in anticipation of industry restructuring in March 1995. This program has resulted in outsourcing, decentralization, reorganization and downsizing for portions of the Company's operations.
Restructuring charges of $18.4 million and $64.9 million were recorded in 1997 and 1996, respectively. These charges included severance costs, purchased power contract restructuring and negotiated settlement costs and other costs.
The Company established a comprehensive involuntary severance package for salaried employees who may no longer be employed as a result of these initiatives. The package provides for severance to be paid over a period of twenty months or less. The cost associated with employee terminations is being recognized in accordance with Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)", as management identifies the positions to be eliminated. The recognition of severance costs resulted in charges to operations of $1.8 million, $12.5 million and $49.2 million in 1998, 1997 and 1996, respectively. At December 31, 1998, management had identified 1,932 positions to be eliminated, of which 1,810 employees had been terminated and severance payments totaling $89 million had been paid. The 1998 severance costs were charged to operations and maintenance expense.
P. VIRGINIA RATE SETTLEMENT:
In 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 joined in a proposed agreement to settle the Company's outstanding base rate proceedings. The Virginia Commission approved the settlement by Order dated August 7, 1998.
The settlement defines a new regulatory framework for the Company's transition to electric competition. The major provisions of the settlement are as follows:
o 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;
o 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;
o An immediate, one-time refund of $150 million for the period March 1, 1997 through February 28, 1998;
o A discontinuation of deferral accounting for purchased power capacity expenses effective February 28, 1998;
o A write-off of a minimum of $220 million of regulatory assets in addition to normal amortization thereof during the base rate freeze period;
o An incentive mechanism until March 1, 2002 for earnings above the following return on equity (ROE) benchmarks: 1998 -- 10.5%; after 1998 -- 30-year Treasury bond rates plus 450 basis points. For rate incentive mechanism purposes, all earnings up to the ROE benchmark would benefit the Company's shareholder. Any earnings above the benchmark would be allocated one-third to the Company's shareholder and two-thirds to the $220 million write-off of regulatory assets; except that all earnings above the ROE benchmark plus 270 basis points (initially 13.2%), would be allocated to the write-off of regulatory assets.
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 71. Based on the uncertainty of the Company's earnings potential during the rate freeze period, management could no longer conclude that recovery of the $220 million is 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 $38.4 million in 1997 and $26.7 million in 1996, which were used to establish a reserve for potential impairment of regulatory assets. Accordingly, the Company charged $158.6 million to second quarter 1998 earnings, which when combined with the reserve for accelerated cost recovery accrued in 1996 and 1997, provides for the impairment of regulatory assets resulting from the settlement.
Q. 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. Except as described below under UTILITY RATE REGULATION, management believes that the final disposition of these proceedings will not have a material adverse effect on the operations or the financial position, liquidity or results of operations of the Company.
UTILITY RATE REGULATION
The current session of the General Assembly of Virginia is scheduled to end in late February 1999. The legislators are considering proposed legislation that would establish a detailed plan to restructure the electric utility industry in Virginia. The Senate approved restructuring legislation in Senate Bill No. 1269 on February 9, 1999 (the Senate Bill). If enacted, it would provide the necessary details to implement legislation passed in 1998 which established a timeline for the transition to retail competition in Virginia. Virginia Power is actively supporting the Senate Bill. Whether all of the provisions of the Senate Bill will ultimately be included in enacted legislation is uncertain. Virginia Power currently believes passage of Virginia restructuring legislation is likely in 1999 but cannot predict what provisions would be included, if restructuring legislation is ultimately enacted. Under the Senate Bill, the Company's base rates would remain unchanged until July 2007.
If the Senate Bill is enacted, the generation portion of the Company's Virginia jurisdictional operations would no longer be subject to cost-based regulation beginning in 2002, although recovery of generation-related costs would continue to be provided through the capped rates until July 2007. When enacted legislation provides sufficient details about the transition to deregulation of generation, the Company would discontinue the application of SFAS 71 for the generation portion of its Virginia jurisdictional operations and determine the amount of regulatory assets to be written off.
In order to measure the amount of regulatory assets to be written off, Virginia Power must evaluate to what extent recovery of regulatory assets would be provided through cost-based rates. Virginia Power would not be required to write off regulatory assets for which recovery would be provided by either cost-based rates or a separate, stranded cost recovery mechanism. Emerging Issues Task Force 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 97-4), provides guidance about writing off regulatory assets when SFAS 71 is discontinued for only a portion of a utility's operations. However, until the final provisions of the Virginia legislation are known, Virginia Power believes the measurement of regulatory assets to be written off under SFAS 71 and EITF 97-4 is uncertain. If a write-off of regulatory assets is required, such write-off could materially affect Virginia Power's financial position and results of operations. See Note F to CONSOLIDATED FINANCIAL STATEMENTS.
Management believes stable rates that would be provided until July 2007 by the Senate Bill, coupled with the opportunity to pursue further reductions in the Company's operating costs, would present a reasonable opportunity to recover a substantial portion of the Company's potentially stranded costs. However, as discussed above, if the application of SFAS 71 is discontinued for any part of utility operations, Virginia Power would perform an impairment evaluation with respect to property, plant and equipment as well as long-term power purchase commitments. See Note D and PURCHASED POWER CONTRACTS, Note Q to CONSOLIDATED FINANCIAL STATEMENTS. The impairment assessment may be required on a disaggregated basis rather than as an aggregate portfolio. Thus, the recognition of impairments, if any, could potentially not be mitigated by other assets or contracts with estimated values in excess of respective carrying amounts or contract payments. If the Company's evaluation concludes that an impairment exists, an additional loss would be charged to earnings. Because the impairment evaluation has not been completed, the Company cannot estimate the amount of loss, if any, that would be recognized. However, such amount could materially affect the Company's financial position and results of operations.
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 C.
CONSTRUCTION PROGRAM
The Company has made substantial commitments in connection with its construction program and nuclear fuel expenditures. Those expenditures are estimated to total $802.5 million (excluding AFC) for 1999. The Company presently estimates that 1999 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 55 non-utility purchase contracts with a combined dependable summer capacity of 3,285 MW.
The table below reflects the Company's minimum commitments as of December 31, 1998, 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 1998, 1997 and 1996 were $1,137 million, $1,381 million and $1,183 million, respectively.
FUEL PURCHASE COMMITMENTS
The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (millions): 1999 -- $328; 2000 -- $248; 2001 -- $205; 2002 -- $115; and 2003 -- $118.
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. These costs have been historically recovered through the ratemaking process. However, see UTILITY RATE REGULATION above for a discussion of legislation that, if enacted, would restructure the electric utility industry in Virginia. If material costs are incurred and not recovered through rates, the Company's results of operations and financial position could be adversely impacted.
SITE REMEDIATION
The EPA has identified the Company and several other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. The estimated future remediation costs for the sites are in the range of $61.8 million to $69.5 million. The Company's proportionate share of the cost is expected to be in the range of $1.6 million to $2.2 million, based upon allocation formulas and the volume of waste shipped to the sites. The Company has accrued a reserve of $1.7 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 has had remedial action responsibilities remaining at several coal tar sites. At December 31, the Company had expended $2 million on site studies and investigation and remedial efforts at these sites. No material expenditures
remain to be incurred by the Company. In addition, a civil suit, seeking compensatory damages of $2 million and punitive damages of $1 million, was filed against Virginia Power by a property owner who alleged that property was contaminated by toxic pollutants originating from one of the coal tar sites. This matter has been resolved through settlement by the parties.
The Company generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 1998, any pending or possible claims were not recognized as an asset or offset against such obligations of the Company.
R. 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.
Cash and cash equivalents and short-term debt: The carrying amount of these items approximates fair value because of their short maturity.
Nuclear decommissioning trust funds: The fair value is based on available market information and generally is the average of bid and asked price.
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.
Money Market Municipal tax-exempt securities: The interest rates for these notes vary so that fair value approximates carrying value.
Convertible 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 current 30-year treasury note and such rates specified in the contracts. On February 5, 1999, these contracts were closed, resulting in a gain of $5.6 million.
S. BUSINESS SEGMENTS:
Effective December 31, 1998, Virginia Power implemented SFAS 131, DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION. Virginia Power's principal business segment is the regulated public utility business serving Virginia and northeastern North Carolina and is reported as Utility Operations. The All Other category includes the Company's wholesale power group's trading and marketing activities, its telecommunications subsidiary, its nuclear consulting services subsidiary and its energy services activities. Management's review of the Company's operations focuses on earnings before interest and income taxes. The Company purchases and sells power in regions outside of its traditional service territory, including marketing available generating capacity not required to serve native load customers. It also markets natural gas. Revenues from wholesale power trading activities include realized commodity contract revenues, net of related cost of sales, settlement of futures contracts, amortization of option premiums and unrealized gains and losses resulting from marking to market those commodity contracts not yet settled.
T. 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.
Certain accruals recorded in 1998 and 1997 were not ordinary, recurring adjustments. These adjustments included (1) the impact resulting from the 1998 settlement of the Company's Virginia rate proceeding and (2) 1997 restructuring costs.
RATE REFUND -- The Company recognized a $153.7 million provision for rate refund and related interest expense of $10.7 million and other taxes of $3.9 million in the second quarter of 1998 as a result of the settlement of the Company's rate proceeding in Virginia. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
IMPAIRMENT OF REGULATORY ASSETS -- The Company charged $158.6 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. The Company accrued $2.8 million, $28.3 million and $7.3 million during the second, third and fourth quarters of 1997, respectively, to provide for impairment of regulatory assets. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
RESTRUCTURING -- The Company expensed $6.3 million, $1.4 million and $10.7 million during the second, third and fourth quarters of 1997, respectively. See Note O to CONSOLIDATED FINANCIAL STATEMENTS.
DEPRECIATION AND AMORTIZATION -- The Company recorded adjustments of $27.6 million in the second quarter of 1998 decreasing the year-to-date provision for depreciation and decommissioning expenses to reflect terms of the Company's settlement of its Virginia rate proceedings. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
Charges for the rate refund and the impairment of regulatory assets, offset by the adjustments to depreciation and decommissioning expenses, reduced Balance Available for Common Stock by $201.0 million in the second quarter of 1998. Charges to provide for impairment of regulatory assets and for restructuring expenses reduced Balance Available for Common Stock by $5.9 million, $19.3 million, and $11.7 million in the second, third, and fourth quarters of 1997, respectively.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
NONE
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:
The Directors are divided into three classes, with staggered terms. Each class consists, as nearly as possible, of one-third of the total number of Directors. Each Director holds office until the annual meeting for the year in which their individual class term expires, or until their successors are duly qualified and elected as provided in the Company's Articles of Incorporation.
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.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Our directors and executive officers report their ownership of and transactions in our preferred stock pursuant to Section 16(a) of the Exchange Act. Through administrative oversight, the following individuals failed to file their initial statements of beneficial ownership on Form 3 on a timely basis: M. Stuart Bolton, Jr., Eugene S. Grecheck, Leslie N. Hartz. The required filings have now been made.
None of the individuals owned any of our preferred stock at the time their initial reports should have been filed nor have they or any other director or executive officer had any reportable transactions in the preferred stock which have not been timely reported.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The Summary Table below includes compensation paid by the Company for services rendered in 1998, 1997 and 1996 for the Chief Executive Officer and the four other most highly compensated executive officers (as of December 31, 1998) as determined under the SEC executive compensation disclosure rules.
SUMMARY COMPENSATION TABLE
- --------- (1) Amounts shown may 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) During 1998, with the agreement Virginia Power cancelled all shares of restricted Dominion Resources stock previously issued under existing incentive plans in order to convert to the new incentive compensation plan described in footnote 4 below. Consequently, as of December 31, 1998, none of the executives shown in this table held any restricted stock issued under Virginia Power compensation programs. Messrs. Askew and Farrell held restricted stock issued under Dominion Resources programs.
(4) Amounts in this column for 1998 represent payouts under the Incentive Compensation Plan for the three-year period 1996-1998. These amounts include both the cash award and the value of the restricted Dominion Resources shares as of the issue date February 19, 1999 ($42.25 per share). The performance measure used was economic value added for the same three-year period. Based on their accomplishment level, each executive received their award in the form of 50% cash as 50% restricted stock. Awards were made following goal confirmation by the Organization, Compensation
and Nominating Committee of the Board of Directors. They cannot be sold and will be forfeited if the executive terminates employment during the restricted period. Awards were paid as follows:
(5) For 1998, employer matching contribution on Employee Savings Plan contributions.
LONG-TERM INCENTIVE COMPENSATION
AWARDS IN THE LAST FISCAL YEAR 1998-2000 LONG-TERM INCENTIVE PLAN
The above table reflects the target awards that will be paid to these executives for the 1998-2000 performance cycle of the long-term incentive program if specified goals are achieved. The established goals for executives consist of two specific financial targets (Operating Profit and Net Cash Flow) for Virginia Power (50%) and consolidated net income for DRI (50%). Awards will be paid 50% in cash and 50% in restricted shares of Dominion Resources common stock. The stock will be restricted for two years. During this time it cannot be transferred and will be forfeited if the executive terminates employment. For the 1998-2000 performance period, a threshold award will be earned if minimum performance goals are achieved. The target award will be earned if the specified goals are fully achieved. A higher award is available for higher levels of achievement.
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 be 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 Organization, Compensation and Nominating Committee 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). In 1998, this adjustment was 11 percent. 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 1998 compensation, the estimated annual benefit under this plan for each of the executives named in the Summary Compensation Table are: Mr. Askew: $189,515; Mr. O'Hanlon: $127,989; Mr. Rigsby: $119,328; Mr. Farrell, II: $93,778; Mr. Girvin: $83,387.
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 Resources common stock. Distributions are made at the direction of the executive.
EMPLOYMENT AGREEMENTS
The Company has entered into employment continuity agreements (the Agreements) with its key management executives, including, Mr. Askew, Mr. O'Hanlon, Mr. E. Rigsby, Mr. Farrell, II, and Mr. Girvin, which provide benefits in the event of a change in control. Each Agreement has a three-year term and is automatically extended each year on its anniversary date for an additional year unless the Company decides not to extend it. If, following a change in control (as defined in the Agreements) of Dominion Resources or the Company, an executive's employment is terminated by the Company without cause, or by the executive within sixty days after a material reduction in the executive's compensation, benefits or responsibilities, the Company will be obligated to pay to the executive continued compensation equaling the average base salary and annual incentive payments for the thirty-six full month period of employment preceding the change in control or employment termination. In addition, the terminated executive will continue to be entitled to any benefits due under any stock incentive or other benefit plans. The Agreements do not alter the compensation and benefits available to an executive whose employment with the Company continues for the full term of the executive's Agreement. The amount of benefits provided under each executive's Agreement will be reduced by any compensation earned by the executive from comparable employment by another employer during the thirty-six months following termination of employment with the Company. An executive shall not be entitled to the above benefits in the event termination is for cause.
COMPENSATION OF DIRECTORS
FEES
During 1998, non-employee directors were paid an annual retainer of $19,000 in cash plus $19,000 in stock. Individuals who are directors of both Virginia Power and Dominion Resources receive one Annual Retainer Fee. They also received $900 in cash per Board or committee 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 Resources 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 Resources 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 Resources 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.
MATCHING GIFTS PROGRAM
Directors may give up to $1,000 per year to 501(c)3 organizations of their choice and the Company 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, the Company will match the donation on a 2-to-1 basis.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The table below sets forth as of February 19, 1999, except as noted, the number of shares of Common Stock of Dominion Resources 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 9,647 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 9,647 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 -- 33,153 shares; Mr. Askew -- 2,057; Mr. Farrell -- 14,467; Mr. Rigsby -- 1502; Mr. Girvin -- 794; Mr. O'Hanlon -- 972; and all directors and executive officers as a group -- 58,512.
(3) Mr. Farrell disclaims beneficial ownership of 399 shares held by his spouse.
(4) Includes 500 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 19, 1999.
(6) Beneficial ownership is disclaimed for a total of 622 shares.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Hazel & Thomas, a professional corporation, from time to time acts as counsel to the Company. Mr. Thomas, a Director of the Company, is a shareholder of Hazel & Thomas.
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 21.
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:
By THOS. (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 .