ITEM 1. BUSINESS THE COMPANY
Dominion Resources, Inc. (Dominion Resources), organized in 1983, has its principal office at 901 East Byrd Street, Richmond, Virginia 23219-4072, telephone (804) 775-5700. The principal assets of Dominion Resources are its investments in its subsidiaries.
At December 31, 1997, Dominion Resources owned directly or indirectly all of the outstanding common stock of its subsidiaries: Dominion Capital, Inc. (Dominion Capital); Dominion Energy, Inc. (Dominion Energy); East Midlands Electricity plc (East Midlands); and Virginia Electric and Power Company (Virginia Power), its largest subsidiary. Dominion Resources is currently exempt from registration as a holding company under the Public Utility Holding Company Act of 1935 (the 1935 Act).
Dominion Resources and its subsidiaries had 15,458 full-time employees as of December 31, 1997.
Dominion Capital
Dominion Capital, established as a subsidiary of Dominion Resources in 1985, is a diversified investment and financial services company. The principal assets of Dominion Capital are First Source Financial, LLP, a middle market commercial lender; Saxon Mortgage, Inc. and its affiliates, subsidiaries engaged in the origination, servicing and securitization of residential mortgages; Cambrian Capital Partners, LP, a merchant banking enterprise for emerging independent oil and natural gas producers; First Dominion Capital LLC, an integrated merchant bank and asset management business; a 50% limited partnership interest in a Louisiana hydroelectric project; investments in marketable securities and fixed income instruments; OptaCor Financial Services Company, a consumer lender and Rincon Securities, Inc., a subsidiary which holds a diversified portfolio of preferred stocks. Dominion Capital also has subsidiaries involved in planned community real estate development and management, a commercial real estate management company and investments in affordable housing.
Dominion Energy
Dominion Energy, established as a subsidiary of Dominion Resources in 1987, is active in the nonutility electric power generation businesses outside the territory served by Virginia Power and the development, exploration and operation of oil and natural gas reserves. Dominion Energy is involved in power projects in six states, Argentina, Bolivia, Belize and Peru, which total approximately 2,561 Mw. Domestic power projects in operation throughout 1997 in which Dominion Energy has an interest include three gas-fueled projects in Texas; two geothermal projects, two gas-fueled projects and one solar project in California; four small hydroelectric projects in New York; a waste coal-fueled project in West Virginia and a waste wood- and coal-fueled project in Maine. International power projects in operation throughout 1997 in which Dominion Energy has an interest include one hydroelectric and one gas-fired project in Argentina, two hydroelectric projects in Bolivia, a run-of-river hydroelectric project in Belize and two hydroelectric projects and six diesel oil-fueled projects in Peru. Dominion Energy is involved in oil and natural gas development and exploration in the Appalachian Basin, the Michigan Basin, the Illinois Basin, the Black Warrior Basin, the Uinta Basin, the Powder River Basin, the Gulf Coast and the Mid-Continent, and owns net proved oil and natural gas reserves in such areas totaling approximately 461 billion cubic feet (BCFE). In 1997, Dominion Energy added approximately 119 BCFE of natural gas reserves. Production from Dominion Energy's reserve holdings in 1997 totaled approximately 59 BCFE.
On March 29, 1996, a subsidiary of Dominion Energy, Kincaid Generation, L.L.C. (LLC) entered into an asset sale agreement with Commonwealth Edison Company (ComEd) to purchase ComEd's 1,108 Mw coal-fired Kincaid Power Station in Central Illinois and entered into a power purchase agreement with ComEd to sell, upon closing under the asset sale agreement, capacity and energy back to ComEd for a period of 15 years. The sale was completed on February 27, 1998.
On August 1, 1997, Dominion Energy sold to Chilgener S.A. 49% of its interest in Inversiones Dominion Peru S.A., a Peruvian company which holds a 60% interest in EGENOR S.A., a 405 megawatt electric generation business in which Dominion Energy had invested in Peru.
East Midlands
Dominion Resources purchased East Midlands, the principal operating subsidiary of our UK holding company, Dominion UK Holding, Inc. (Dominion UK) in the first quarter of 1997. East Midlands' principal businesses are the distribution
of electricity and the supply of electricity to approximately 2.3 million customers in the East Midlands region of the United Kingdom. East Midlands' primary business is its distribution business which is a regulated monopoly and its electricity supply business. Together these businesses produced substantially all of East Midlands' consolidated operating income. East Midlands is also focused on taking advantage of the opportunity in the domestic gas supply business.
East Midlands' Franchise Area (or service area) has a resident population of over five million and covers approximately 6,200 square miles extending from Coventry to the Lincolnshire coast and from Milton Keynes to Chesterfield of which the southernmost part is less than 60 miles from London
Dominion UK, through wholly-owned subsidiaries, holds an 80% interest in Corby Power Limited (Corby), a 350 MW gas-fired power station. Corby was commissioned in 1994 and is one of the earliest UK independent power generation projects in the deregulated UK.
Distribution Business
East Midlands owns, manages and operates the electricity distribution network within its Franchise Area. The primary activity of the distribution business is the receipt of electricity from the national grid transmission system and its distribution to end users connected to East Midlands' power lines. Because East Midlands is the exclusive holder of a Public Electricity Supply (PES) license for its Franchise Area, virtually all electricity supplied (whether by East Midland's supply business or by other suppliers) to consumers in East Midland's Franchise Area is transported through East Midlands' distribution network. As a holder of a PES license, East Midlands is subject to a price control regulatory framework that retains economic incentives to increase the number of units of electricity distributed and to operate in a more cost-efficient manner.
In addition to the network division, East Midlands' distribution business also includes construction and metering divisions. The construction division provides construction, standby and maintenance services to the network as well as performing similar services for certain third-parties. East Midlands' metering division focuses on the ownership and management of metering and related assets as well as data collection and transmission service. While portions of construction and metering businesses are gradually opening to competition, the network division, which generates over 80% of the distribution business' profits, is expected to remain a regulated monopoly subject to price regulation.
Distribution Facilities
Electricity is transported across the national grid transmission system (the high voltage transmission system in UK that carries the generated electricity in bulk from power stations to regional and local distribution systems) at 400kv or 275kv to 14 grid supply points within East Midlands' distribution network, where East Midlands transforms the voltage to 132kv for entry into East Midlands' distribution system. Electricity is also transported to one national grid supply point located in a neighboring Regional Electric Companies (REC) franchise area, which is connected to East Midlands' distribution system by overhead lines and underground cables. Substantially all electricity which enters East Midlands' system is received at these 15 grid supply points.
East Midlands' distribution facilities also include approximately:
Substantially all substations are owned and the balance are leased under arrangements which will not expire for 10 years.
Supply Business
East Midlands' supply business consists of selling electricity to end users, purchasing electricity primarily from the Pool and arranging for its distribution to those end users. The Pool is the wholesale trading market that was established at the time of privatization (1990) for bulk trading of electricity in UK between generators and suppliers. Basically all electricity generated in UK must be sold and purchased through the Pool. The Pool does not buy or sell electricity. East Midlands' supply business supplies Franchise Supply Customers and Non-Franchise Supply Customers and is further developing its gas business to supply domestic and business customers. East Midlands currently supplies gas to approximately 6,000 customers and has contracted to supply gas to more than 80,000 customers.
Franchise Supply Market
East Midlands holds a PES License under which it currently has the exclusive right to supply electricity to Franchise Supply Customers, who have a peak demand of less than 100kW, within its Franchise Area. At the time that the electricity industry was privatized, "Franchise Supply Customers" included all customers whose supply peak demand was less than 1MW. The 1MW threshold was reduced to 100 kW on April 1, 1994. The exclusive right to supply Franchise Supply Customers is currently scheduled to be phased in over a 6 month period beginning June 1998 and ending in December 1998. On completion of this phase-in period, there will be no Franchise Supply Customers and all supply customers will have the ability to choose their electricity supplier. Supply prices of electricity from Franchise Supply Customers are based on the Supply Price Control Formula, whereby certain limits are placed on East Midlands as to the prices it can charge customers for the supply of electricity.
From April 1, 1998 there will be a revised Supply Price Control Formula in the form of price caps for all residential customers and small business customers.
Following the Supply Price Control Review in 1997, the supply prices to franchise customers will reduce by 6.4% from April 1998 and an additional 3% from April 1999.
Non-Franchise Supply Market
Non-Franchise Supply Customers are currently defined as customers whose peak demand equals or exceeds 100kW. In addition to competing for Non-Franchise Supply Customers in its Franchise Area, East Midlands holds a second tier license to compete with the RECs and other suppliers to provide electricity to Non-Franchise Supply Customers outside its Franchise Area.
The market to supply Non-Franchise Supply Customers is fully competitive, with the principal competitors being other RECs and major generators. Non-Franchise Supply Customers are typically supplied through individual 12-month contracts with competitively bid or negotiated prices.
Power Purchasing and Risk Management
In order to manage its power purchasing risks, the supply business enters into arrangements such as contracts for differences (CFDs) to hedge against Pool price volatility. CFDs are contracts predominantly entered into between generators and suppliers to fix the price of a contracted quantity of electricity over a specific period. Differences between the actual prices set by the Pool and the agreed prices give rise to difference payments between the parties to the particular CFD. At the present time, East Midlands' forecast franchise supply market demand for fiscal 1998 is substantially hedged through various types of agreements, including CFDs.
The most common contracts for supply to Non-Franchise Supply customers are for a twelve-month term and contain fixed rates. East Midlands is exposed to two principal-risks associated with such contracts: (a) purchasing price risk (East Midlands' cost of purchased electricity relative to the price East Midlands receives from the supply customer) and (b) load shape risk (the risk associated with a shift in the customer's usage pattern, including absolute amounts demanded and timing of amounts demanded). East Midlands seeks to hedge purchasing price risk through a variety of risk management tools, including management of its supply contract portfolio, CFDs, option arrangements and other means which mitigate risk of future Pool price volatility. Load shape risk is mitigated by paying detailed attention to forecasting demand.
Competition
The UK electricity industry has changed significantly since 1994, as the UK government has privatized and deregulated the industry. As a result, East Midlands' distribution and supply businesses are subject to varying degrees of competition.
On the distribution side of the business, East Midlands' network distribution division is currently a regulated monopoly that does not face direct competition. This division contributes 80% of the distribution business' profits, but could face indirect competition from alternative energy sources such as gas. In addition, the distribution business' metering division faces full competition by the year 2000 and the construction division's work is open to competition from a number of firms.
East Midlands' supply business has Franchise and Non-Franchise markets. East Midlands' exclusive right to supply electricity to its Franchise customers is currently scheduled to end over a 6-month phase-in period beginning December 1, 1998. At that time, East Midlands will compete directly with electricity generators and other suppliers of electricity, primarily other PES license holders. The Non-Franchise portion of the business currently competes with those generators and suppliers.
Beginning March 27, 1998, the residential gas market will be open to competition in the East Midlands franchise region.
Environmental Regulation
East Midlands' businesses are subject to numerous regulatory requirements with respect to the protection of the environment. The Electricity Act of 1989 obligates the UK Secretary of State for Trade and Industry to take into account the effect of electricity generation, transmission and supply activities upon the environment in approving applications for the construction of generating facilities and the location of overhead power lines. The Electricity Act requires East Midlands to adhere to such guidelines when it formulates proposals for development. East Midlands is required to mitigate any effect its proposals may have on the environment and may be required to carry out an environmental assessment when it intends to construct overhead lines. East Midlands also has produced an Environmental Policy Statement which sets out the manner in which it intends to comply with its obligations under the Electricity Act.
The Environmental Protection Act 1990 addresses waste management issues and imposes certain obligations and duties on companies which handle and dispose of waste. Some of East Midlands' distribution activities produce waste, but Dominion Resources believes East Midlands is in compliance with applicable standards.
Virginia Power
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 transacts business under the name Virginia Power in Virginia and under the name North Carolina Power in North Carolina. Virginia Power has retail customers (including governmental agencies) and wholesale customers such as rural electric cooperatives, power marketers and municipalities and serves more than 80% of Virginia's population. Virginia Power has certificates of convenience and necessity from the State Corporation Commission of Virginia (the Virginia Commission) for service in all territories served at retail in Virginia. The North Carolina Utilities Commission (the North Carolina Commission) has assigned territory to Virginia Power for substantially all of its retail service outside certain municipalities in North Carolina.
The electric utility industry in the United States is undergoing an evolutionary change toward less regulation and more competition. To meet the challenges of this new competitive environment, Virginia Power has developed a broad array of "non-traditional" product and service offerings from its operating business units and subsidiaries:
o Energy Services -- offering electric energy and capacity in the emerging wholesale market as well as natural gas and other energy-related products and services;
o Fossil & Hydro -- targeting process type industries, such as chemical, paper, plastics and petroleum to become a service provider of instrumentation equipment;
o Nuclear Services -- offering management and operations services to other electric utilities;
o Commercial Operations -- providing power distribution related services, including transmission and distribution, engineering and metering services to other gas, water and electric utilities; and
o Telecommunications -- offering telecommunications services through the Company's existing fiber-optic network.
Competition and Strategic Initiatives
A number of developments in the United States are causing a trend toward less regulation and more competition in the electric utility industry. This is evidenced by legislative and regulatory action at both the federal and state levels. To the extent that competition is either authorized or mandated and regulation is eliminated or relaxed, electric utilities may no
longer be guaranteed an opportunity to recover all of their prudently incurred costs, and utilities with costs that exceed the market prices established by the competitive market will run the risk of suffering losses, which may be substantial.
Virginia Power has responded to these trends by undertaking cost-cutting measures, engaging in re-engineering efforts, restructuring its core business processes, and pursuing a strategic planning initiative to encourage innovative approaches to serving traditional markets. Virginia Power has established separate business units, as discussed above, to fully execute these strategies.
Virginia Power also is vigorously participating in the state and federal legislative actions currently underway to bring about competition in the electric utility industry, in an effort to ensure an orderly transition from a regulated environment.
Virginia Power's non-traditional businesses face competition from a variety of utility and non-utility entities.
For a full discussion of the regulatory and legislative issues related to competition, read the Future Issues section of MANAGEMENT DISCUSSION AND ANALYSIS OF OPERATIONS (MD&A) on pages 26 through 30 of the 1997 Annual Report to Shareholders.
Regulation
General
In a wide variety of matters in addition to rates, Virginia Power is presently subject to regulation by the Virginia Commission and the North Carolina Commission, the Environmental Protection Agency (EPA), Department of Energy (DOE), Nuclear Regulatory Commission (NRC), the Federal Energy Regulatory Commission (FERC), the Army Corps of Engineers, and other federal, state and local authorities. Compliance with numerous laws and regulations increases Virginia Power's operating and capital costs by requiring, among other things, changes in the design and operation of existing facilities and changes or delays in the location, design, construction and operation of new facilities. The commissions regulating Virginia Power's rates have historically permitted recovery of such costs.
Virginia Power 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. Such approvals relate to, among other things, the environmental impact of such activities, the relationship of such activities to the need for providing adequate utility service and the design and operation of proposed facilities.
Both federal and state legislative bodies have been studying competition and restructuring in the electric utility industry. See Future Issues -- Competition -- Legislative Initiatives section of MD&A on page 27 of the 1997 Annual Report to Shareholders.
Virginia
In 1995, the Virginia Commission instituted an ongoing generic investigation on electric industry restructuring, resulting in a number of reports by its Staff covering such issues as retail wheeling experiments and the status of wholesale power markets. The Staff also submitted a report to the General Assembly calling for a cautious, two-phase, five-year period to address restructuring issues. The report acknowledged the need for direction from the Virginia legislature concerning policy issues surrounding competition in the electric industry.
In November 1996, the Virginia Commission instituted a proceeding concerning Virginia Power's cost of service and possible restructuring of the electric utility industry as it might relate to Virginia Power. On March 24, 1997, Virginia Power filed in that proceeding a calculation of its cost of service for 1996 and a proposed Alternative Regulatory Plan (ARP). Subsequently, the Commission consolidated this proceeding with the proceeding concerning Virginia Power's 1995 Annual Informational Filing, in which Virginia Power's base rates were made interim and subject to refund as of March 1, 1997. Please carefully read the Future Issues -- Competition -- Legislative Initiatives and Regulatory Initiatives sections of MD&A on page 27 of the 1997 Annual Report to Shareholders and Rates--Virginia, below for details concerning the ARP, its current status and related legislative developments.
In December 1995, Virginia Power applied to the Virginia Commission for approval of arrangements with Chesapeake Paper Products Company (CPPC), under which Virginia Power would facilitate the design, construction and financing of a cogeneration plant to meet CPPC's energy requirements for its industrial processes at its plant in West Point, Virginia. On August 13, 1997, the Virginia Commission approved, in substantial part, the proposed transactions
between Virginia Power and CPPC's successor in ownership, St. Laurent Paper Products Co. St. Laurent later determined that the current design of the facility was no longer compatible with its long-term business strategies and terminated its contractual arrangement with Virginia Power. The Virginia Commission dismissed the proceeding on January 15, 1998.
In June 1997, the Virginia Commission granted Virginia Power's request to implement a monitoring program that requires certain non-utility generators to provide certain information sufficient to determine continued compliance with the "Qualifying Facility" (QF) requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).
On August 8, 1997, the Virginia Commission granted Virginia Power's request to provide interchange telecommunications services and approved the proposed affiliate agreements between Virginia Power and our wholly-owned subsidiary, VPS Communications, Inc. (VPSC). Under the authority granted, VPSC will provide a range of telecommunications services, including private line and special access services and high-capacity fiberoptic services.
On September 3, 1997, the Virginia Commission granted Virginia Power's request to provide services to our wholly-owned subsidiary, Virginia Power Services, Inc. (VPS), which would enable Virginia Power Nuclear Services Company (VPN), a VPS subsidiary, to furnish nuclear management and operation services to electric utilities seeking assistance in the management and operation of their nuclear generating facilities. VPN currently provides such services to Northeast Utilities at its Millstone Unit 2 nuclear plant.
FERC
In April 1996, FERC issued final rules in Order Nos. 888 and 889 addressing open access transmission service, stranded costs, standards of conduct and open access same-time information systems (OASIS). In July 1996, Virginia Power filed an open access transmission service tariff in compliance with FERC's Order No. 888. In compliance with FERC's directive, Virginia Power's OASIS became operational on January 3, 1997. Also, on that date the standards of conduct requiring separation of transmission operations/reliability functions from wholesale merchant/marketing functions became effective. Virginia Power also made filings to comply with FERC's directive that, effective January 1, 1997, utilities could no longer make bundled sales of transmission and generation services in economy energy transactions. In certain of those filings, Virginia Power canceled or committed not to use the economy energy rate schedules contained in interconnection agreements with neighboring utilities. On March 4, 1997, FERC issued Order Nos. 888-A and 889-A, which addressed requests for rehearing of Order Nos. 888 and 889. Orders No. 888-A and 889-A essentially reaffirm the basic principles of 888 and 889 and clarify and make limited modifications to those orders. On December 17, 1997, FERC issued Order Nos. 888-B and 889-B. FERC rejected all requests for rehearing filed with respect to Order Nos. 888-A and 889-A and clarified and made limited modifications to those orders. Several parties have appealed the 888 orders to the United States Court of Appeals for the District of Columbia Circuit.
For a discussion of the status of Virginia Power's Open Access Transmission Tariff filing, see Rates -- FERC below.
For additional discussion of open access issues see Future Issues -- Competition under MD&A on pages 26 through 28 of the 1997 Annual Report to Shareholders.
LG&E Westmoreland Southampton owns a cogeneration facility in Franklin, Virginia, and sells its output to Virginia Power. Southampton has sought a waiver of FERC operating requirements for Qualifying Facilities (QF's) under PURPA, however FERC refused to grant such a waiver. On March 31, 1997, the United States Court of Appeals for the District of Columbia Circuit granted FERC's motion to dismiss Southampton's Petition for Review.
Environmental
From time to time, Virginia Power may be designated by the EPA as a potentially responsible party (PRP) with respect to a Superfund site. As a result of that designation or other regulations regarding the remediation of waste, we may become obligated to fund remedial investigations or actions. We do not believe that any currently identified sites will result in significant liabilities. For a discussion of Virginia Power's site remediation efforts, see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS on page 53 of the 1997 Annual Report to Shareholders.
Permits under the Clean Water Act and state laws have been issued for all of Virginia Power's steam generating stations now in operation. These permits are subject to reissuance and continuing review. The Clean Air Act, as amended in 1990, requires Virginia Power to reduce its emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx). Beginning in 1995, the 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 program is administered by the EPA.
For additional information on Environmental Matters and related issues see Future Issues -- Environmental Matters section of MD&A on pages 28 and 29 of the 1997 Annual Report to Shareholders.
Nuclear
All aspects of the operation and maintenance of Virginia Power's 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 Virginia Power's nuclear generating units.
In July 1995, the Virginia Commission instituted an investigation regarding spent nuclear fuel 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 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 spent nuclear fuel disposal issue to a separate proceeding.
On January 31, 1997, Virginia Power joined thirty-five other electric utilities in filing a petition in the United States Court of Appeals for the District of Columbia Circuit, seeking to compel DOE to comply with its obligation to begin accepting the utilities' spent nuclear fuel for disposal by January 31, 1998, the date imposed by the Nuclear Waste Policy Act. Additional utilities have joined since the original filing. On November 14, 1997, the Court issued an Order finding that DOE's obligation to begin accepting spent nuclear fuel by the deadline is unconditional, and that DOE may not excuse its delay on the grounds that it has not prepared a permanent repository or interim storage facility. The Court found that DOE's spent fuel disposal contracts with the utilities offer a potentially adequate remedy for DOE's failure to meet its obligation. DOE filed a petition for rehearing on December 29, 1997.
Rates
Virginia Power electric service sales were subject to rate regulation in 1997 as follows:
- --------- * Excludes wholesale power marketing sales subject to FERC regulation.
Substantially all of Virginia Power's electric service sales are 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.
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
In compliance with FERC's Order No. 888, Virginia Power filed an open access transmission service tariff, which became effective on July 9, 1996. In October 1996, FERC issued a procedural order, scheduling a hearing for April 28, 1997. Virginia Power and all parties reached a settlement of issues raised in the proceeding, and on March 20, 1997, those parties jointly filed with FERC the Settlement Agreement and Motion to Certify the Settlement Agreement. On April 23, 1997 the presiding Administrative Law Judge certified the Settlement Agreement to the FERC and on June 11, 1997, the FERC approved the settlement.
In compliance with FERC's Order No. 889, on January 3, 1997, Virginia Power filed its Procedures For Standards of Conduct for Unbundled Transmissions and Wholesale Merchant Function (Standards of Conduct) effective on that date. On July 1, 1997, Virginia Power filed an amendment to the Standards of Conduct in Compliance with FERC's Order No. 889-A. On July 16, 1997, Virginia Power filed another amendment in response to a FERC Staff request. Virginia Power is awaiting FERC action on the filing.
On September 11, 1997, FERC authorized Virginia Power to sell power at market-based rates but set for hearing the issue of the impact of any transmission constraints on Virginia Power's ability to exercise generation market power in localized areas within its service territory. If FERC finds that transmission constraints give Virginia Power generation dominance, it could either revoke or limit the scope of the market-based rate authority. The hearing is scheduled to commence June 2, 1998.
On October 31, 1997, Virginia Power filed at FERC three agreements with Old Dominion Electric Cooperative (ODEC) to amend the parties' Interconnection and Operating Agreement (I&O Agreement) and to unbundle transmission services provided to ODEC under the I&O Agreement. On December 22, 1997, FERC issued a deficiency letter with respect to the filing directing Virginia Power to provide additional information. On January 21, 1998, Virginia Power provided the requested information. FERC accepted the agreements on March 12, 1998.
Virginia
In March 1997, the Virginia Commission issued an order that Virginia Power's base rates be made interim and subject to refund as of March 1, 1997. This order was the result of the Commission Staff's report on its review of Virginia Power's 1995 Annual Informational Filing, which concluded that Virginia Power's present rates would cause Virginia Power to earn in excess of its authorized return on equity. The Staff found that, for purposes of establishing rates prospectively, a rate reduction of $95.6 million (including a one-time adjustment of $29.7 million to Virginia Power's deferred capacity balance at December 31, 1996) may be necessary in order to realign rates to the authorized level. Virginia Power filed its Alternative Regulatory Plan (ARP) in March 1997, based on 1996 financial information. Subsequently, the Commission consolidated the proceeding concerned with the 1995 Annual Informational Filing with the proceeding that includes the ARP proposed by Virginia Power.
In December 1997, Virginia Power sought to withdraw its ARP, having concluded that resolution of the cost recovery issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that Virginia Power may withdraw its support of the ARP but has reserved the right to continue consideration of the ARP as well as other regulatory alternatives. In addition, the Commission will continue to consider the issues arising out of the 1995 Annual Informational Filing. The Commission's Staff is scheduled to file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A public hearing is scheduled to commence on May 19, 1998.
Virginia Power's previous filings in this proceeding support maintaining Virginia Power's rates at current levels; however, opposing parties have made filings recommending rate reductions in excess of $200 million. At this time, management cannot predict the ultimate outcome of the proceeding and its impact on Virginia Power's results of operations, cash flows or financial position.
In July 1996, Virginia Power proposed to substantially reduce the rates paid under Schedule 19 to cogenerators and small power producers of 100 kW or less. The rates became effective on an interim basis on January 1, 1997. On January 21, 1998, the Virginia Commission approved revised Schedule 19 rates. The approved rates do not differ in any significant way from the rates originally proposed by Virginia Power.
In October 1996, Virginia Power filed an application with the Virginia Commission to increase its fuel factor from 1.299 cents per kWh to 1.322 cents per kWh, reflecting a fuel factor annual revenue increase of approximately $48.2 million. The increase became effective on an interim basis on December 1, 1996. On June 11, 1997, the Commission entered an Order Establishing Fuel Factor approving the requested increase.
On October 31, 1997, Virginia Power filed with the Virginia Commission its application for a reduction of $45.6 million in its 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, the Company 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. A hearing is scheduled for April 9, 1998.
North Carolina
On November 4, 1996, Virginia Power filed for approval of a new Schedule 19 which governs purchases from cogenerators and small power producers. Virginia Power proposed rates substantially lower than those previously specified. It also proposed to reduce the applicability threshold to 100 kW and shorten the maximum term of contracts under Schedule 19 to five years. On June 19, 1997, the North Carolina Commission issued an Order requiring Virginia Power to offer long-term (5-, 10- and 15-year) levelized capacity payments to hydroelectric and certain landfill and waste facilities contracting for up to 5 MW; a 5-year levelized rate option to other QFs contracting for up to 100 kW; and optional long-term levelized energy payments for QFs rated at 100 kW or less capacity.
Sources Of Power
Virginia Power Generating Units
--------- (a) Includes an undivided interest of 11.6 percent (208 MW) owned by ODEC. (b) Includes an undivided interest of 50 percent (441 MW) owned by ODEC. (c) Effective January 25, 1996, this unit was placed in a cold reserve status. (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 14,537 MW on July 28, 1997, and an all-time high one-hour integrated winter peak demand of 14,910 MW was reached on February 5, 1996.
Energy Used And Fuel Costs
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.
Nuclear Operations and Fuel Supply
In 1997, Virginia Power's four nuclear units achieved a combined capacity factor of 91.1 percent.
Virginia Power utilizes both long-term contracts and spot purchases to support its needs for nuclear fuel. Virginia Power continually evaluates worldwide market conditions in order to ensure a range of supply options at reasonable prices. Current agreements, inventories and spot market availability will support Virginia Power's current and planned fuel supply needs for fuel cycles throughout the remainder of the 1990's and into the early 2000's. Beyond that period, additional fuel will be purchased as required to ensure optimum cost and inventory levels.
The DOE is not expected to begin the acceptance of spent fuel in 1998 as specified in Virginia Power's contract with the DOE. However, on-site spent nuclear fuel storage at the Surry Power Station (spent fuel pool and dry cask storage) is expected to be adequate for Virginia Power's needs until the DOE begins accepting spent fuel. The North Anna Power Station will require additional spent fuel storage capacity in 1998. Virginia Power submitted a license application to the NRC in May 1995 for a dry cask facility at North Anna. Virginia Power anticipates that this application will be approved in mid-1998.
For details on the issues of decommissioning and nuclear insurance, see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS on page 54 of the 1997 Annual Report to Shareholders.
Fossil Operations and Fuel Supply
Virginia Power's fossil fuel mix consists of coal, oil and natural gas. In 1997, Virginia Power consumed approximately 13 million tons of coal. As with nuclear fuel, Virginia Power utilizes both long-term contracts and spot purchases to support its needs. Virginia Power presently anticipates that sufficient coal supplies at reasonable prices will be available for the remainder of the 1990's. Current projections for an adequate supply of oil remain favorable, barring unusual international events or extreme weather conditions which could affect both price and supply.
Virginia Power uses natural gas as needed throughout the year for two 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 are not available at favorable prices. Virginia Power has firm transportation contracts for the delivery of gas to the combined cycle units. Current projections indicate gas supplies will be available for the next several years.
Purchases and Sales of Energy
Virginia Power relies on purchases of power to meet a portion of its capacity requirements. Virginia Power also makes economy purchases of power from other utility systems when it is available at a cost lower than Virginia Power's own generation costs.
Under contracts effective January 1, 1985, Virginia Power agreed to purchase 400 MW of electricity annually through 1999 from Hoosier Energy Rural Electric Cooperative, Inc. (Hoosier), and agreed to purchase 500 MW of electricity annually during 1987-99 from certain operating units of American Electric Power Company, Inc. (AEP).
Virginia Power has a diversity exchange agreement with AE under which AE delivers 200 MW to Virginia Power in the summer and Virginia Power delivers 200 MW to AE in the winter.
Virginia Power also has 57 non-utility power purchase contracts with a combined dependable summer capacity of 3,277 MW (for information on the financial obligations under these agreements see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS on page 53 of the 1997 Annual Report to Shareholders). In a continuing effort to mitigate its exposure to above-market long-term purchased power contracts, Virginia Power is evaluating its long-term purchased power contracts and negotiating modifications to their terms, including cancellations, where it is determined to be economically advantageous to do so.
Virginia Power's wholesale power group actively participates in the purchase and sale of wholesale electric power and natural gas in the open market. The wholesale power group has expanded Virginia Power's trading range beyond the geographic limits of the Virginia Power service territory, and has developed trading relationships with energy buyers and sellers on a nationwide basis.
In July 1997, Virginia Power executed three agreements with Old Dominion Electric Cooperative (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.
As reported above, both the Hoosier 400 MW long-term purchase and the AEP 500 MW long-term purchase will expire on December 31, 1999. Virginia Power presently anticipates adding peaking capacity beginning in the year 2000 to meet its anticipated load growth. Virginia Power has and will pursue capacity acquisition plans to provide that capacity and maintain a high degree of service reliability. This capacity may be owned and operated by others and sold to Virginia Power or may be built by Virginia Power if it determines it can build capacity at a lower overall cost. Virginia Power also pursues conservation and demand-side management. No Virginia Power owned generation is currently in the planning or construction stages.
For additional information, see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS on page 53 of the 1997 Annual Report to Shareholders.
Interconnections
Virginia Power maintains major interconnections with Carolina Power and Light Company, AEP, AE and the utilities in the Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission network, Virginia Power has arrangements with these utilities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy.
In December 1996, Virginia Power joined with Allegheny Power Service Corporation, Cleveland Electric Illuminating Company, Toledo Edison Company, Ohio Edison Company, Pennsylvania Power Company and Southern Company Services, Inc. (the Transmission Alliance) to file a contract with the FERC entitled the GAPP Experiment Participation Agreement (GAPP Agreement). The Transmission Alliance and the GAPP Agreement were established to promote fair and equitable use of the transmission systems based on the General Agreement on Parallel Paths (GAPP) model for coordinating the flow of bulk supplies of electricity among utilities. GAPP principles allow electric companies to determine where electricity actually flows in bulk power transactions, as opposed to the "contract" paths that are based on power purchase and transmission agreements among buying, selling and transmitting utilities.
Compensation for transmission services has historically been based on contract paths. The GAPP Agreement was designed to determine the physical path electricity actually takes through the system and allocate open access transmission revenues among the parties. The GAPP Agreement was designed as an experiment to test the GAPP methods and procedures for a period of two years. The FERC accepted the contract on March 25, 1997. Virginia Power and the Transmission Alliance implemented the GAPP Agreement on April 2, 1997.
On November 14, 1997, in accordance with the FERC order accepting the GAPP Agreement, the Transmission Alliance issued a report detailing the results of the first six months of the experiment. The preliminary results of the experiment indicate that it is technically possible to monitor and predict the physical flow of electricity over multiple systems and that
transmission revenues reallocated according to actual use of the system differ significantly from collections under a contract path approach. In October 1997, Virginia Power gave notice to the Transmission Alliance that, effective January 1, 1998, it was exercising its option under the GAPP Agreement to terminate its involvement in the experiment.
On December 9, 1997, Virginia Power, the Transmission Alliance and other utilities agreed to study the creation of an independent regional transmission entity. The memorandum of understanding to initiate this study was signed by eleven investor-owned electric companies, including Virginia Power, Consumers Energy, Detroit Edison, Duquesne Light Company, The Illuminating Company, Ohio Edison Company, Pennsylvania Power Company, Toledo Edison Company, and the Allegheny Energy Companies (Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company). This group is an outgrowth of the GAPP Agreement and its key goals are to maintain the long-term reliability and security of the utilities' interconnected transmission systems; ensure the most efficient use of resources; eliminate pancaking of rates within and between transmission entities; avoid duplication of costs and achieve transmission cost savings; and, strike an appropriate balance among the diverse interests of energy suppliers, customers, and shareholders. The group will also explore cooperative agreements designed to achieve these goals while ensuring nondiscriminatory and comparable access to all users of the group's transmission system. The companies intend to be responsive to industry changes, especially with the introduction of retail competition in some of the areas served by the signatories and as some other industry participants consider creation of independent transmission operating companies or separate transmission companies. Further, the companies will have the flexibility to continue to investigate and pursue other opportunities and arrangements that could develop regarding independent system operators or independent transmission companies.
Virginia Power and Appalachian Power Company (AEP-Virginia), an operating unit of AEP, each sought approval from the SCC in 1991 to construct certain interconnecting transmission facilities. These applications resulted from a joint planning effort of Virginia Power and AEP to meet the requirements of their customers. At the time of Virginia Power's application, particularly during the summer of 1992, constraints were being experienced on transfers of power into the Virginia Power service territory from the west. On November 7, 1997, the SCC issued an Order directing Virginia Power to report to the Commission on the continued need for certain new interconnected transmission facilities, on the relationship between Virginia Power's application to build the new facilities and certain other pending proceedings, and on Virginia Power's construction plans, if the SCC grants Virginia Power's application.
On December 15, 1997, Virginia Power filed a report in compliance with the SCC Order stating that since the filing of Virginia Power's application, the constraints have been less frequent, due in part to less severe summer weather, and actual power requirements have been less than originally forecasted. In addition, generating resources within the Virginia Power service area have been increased by the higher performance level of the nuclear units, as well as the completion of the Clover Station. Completion of the AEP project is a prerequisite for the Virginia Power project to go forward. The proposed Virginia Power project would not fulfill its intended purpose without the AEP line being built. AEP has withdrawn its original application and has instituted a new proceeding before the Commission in which different routing is proposed. Virginia Power continues to monitor closely the progress of AEP in this proceeding with respect to its new proposal, but until more is known about these proceedings, Virginia Power cannot predict what its construction plans will be.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
See MANAGEMENT'S DISCUSSION AND ANALYSIS OF CASH FLOWS AND FINANCIAL CONDITION on pages 37 through 40 of the 1997 Annual Report to Shareholders.
ITEM 2.
ITEM 2. PROPERTIES
Dominion Resources owns the building at One James River Plaza, Richmond, Virginia, in which Virginia Power has its principal offices. Dominion Resources' other assets consist primarily of its investments in its subsidiaries, which invest various enterprises and assets, as described in THE COMPANY under Item 1. BUSINESS above. See also Virginia Power Generating Units under Item 1. BUSINESS above.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
From time to time, Dominion Resources and its subsidiaries are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by them, or permits issued by various local, state and federal agencies for the construction or operation of facilities. From time to time, there may be administrative proceedings on these matters pending. In addition, in the normal course of business, Dominion Resources and its subsidiaries are in involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the company's financial position, liquidity or results of operations.
In reference to the lawsuit filed by Dominion Energy and Dominion Cogen D.C., Inc. against the District of Columbia and the District's counterclaims to the lawsuit, the parties settled all claims and dismissed the lawsuit and related counterclaims on August 20, 1997.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Dominion Resources common stock is listed on the New York Stock Exchange and at December 31, 1997 there were 215,685 registered common shareholders of record. Quarterly information concerning stock prices and dividends contained on page 56 of the 1997 Annual Report to Shareholders for the fiscal year ended December 31, 1997 in Note U to CONSOLIDATED FINANCIAL STATEMENTS which is filed herein as Exhibit 13, is hereby incorporated herein by reference.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
This information contained under the caption "Selected Consolidated Financial Data" on page 60 of the 1997 Annual Report to Shareholders for the fiscal year ended December 31, 1997 filed herein as Exhibit 13, is hereby incorporated herein by reference.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This information contained under the caption MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATIONS on pages 22 through 33 and MANAGEMENT'S DISCUSSION AND ANALYSIS OF CASH FLOWS AND FINANCIAL CONDITION on pages 37 through 40 of the 1997 Annual Report to Shareholders for the fiscal year ended December 31, 1997, filed herein as Exhibit 13, is hereby incorporated herein by reference.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information contained under the caption MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATIONS on pages 30 through 33 of the 1997 Annual to Shareholders for the fiscal year ended December 31, 1997, filed herein as Exhibit 13, is hereby incorporated herein by reference.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This information contained in the CONSOLIDATED FINANCIAL STATEMENTS on pages 21, 34 through 36, NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on pages 37 through 56 and related report thereon of Deloitte & Touche LLP, independent auditors, appearing on page 57 of the 1997 Annual Report to Shareholders for the fiscal year ended December 31, 1997, filed herein as Exhibit 13, is hereby incorporated herein by reference.
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
Information regarding the Directors of Dominion Resources contained on pages 6 through 8 of the 1998 Proxy Statement, File No. 1-8489, dated March 11, 1998 is hereby incorporated herein by reference. The information concerning the executive officers of Dominion Resources required by this Item is set forth in Part I, under the section EXECUTIVE OFFICERS OF THE REGISTRANT. Information regarding Section 16(a) Beneficial Ownership Reporting Compliance is contained on page 26 of the 1998 Proxy Statement, dated March 11, 1998, which is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive and director compensation contained on pages 6 through 19 of the 1998 Proxy Statement is hereby incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information concerning stock ownership by directors and executive officers contained on page 12 of the 1998 Proxy Statement is hereby incorporated herein by reference. There is no person known by Dominion Resources to be the beneficial owner of more than five percent of Dominion Resources common stock.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
A. Certain documents are filed as part of this Form 10-K and are incorporated herein by reference and found on the pages noted.
1. Financial Statements
2. Exhibits
- --------- * Indicates management contract or compensatory plan or arrangement.
B. Reports on Form 8-K
Dominion Resources filed a report on Form 8-K, dated December 11, 1997, reporting the issuance of 250,000 7.83% Capital Securities (liquidation amount $1,000 per security) through its Dominion Resources Capital Trust I, a Delaware business trust.
Dominion Resources filed a report on Form 8-K, dated January 15, 1998, reporting the issuance of 6,500,000 shares of Common Stock.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION RESOURCES, INC.
By: THOS. E. CAPPS ------------------------------------------------------ (Thos. E. Capps, Chairman of the Board of Directors, President and Chief Executive Officer)
Date: MARCH 20, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on the 20th day of March, 1998.
DOMINION RESOURCES, INC.
PORTIONS OF THE ANNUAL REPORT TO SHAREHOLDERS (Incorporated by Reference)