ITEM 1. BUSINESS THE COMPANY Virginia Electric and Power Company was incorporated in Virginia in 1909 and has its principal office at One James River Plaza, Richmond, Virginia 23261-6666, telephone (804) 771-3000. It is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion Resources), a Virginia corporation. 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. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives and municipalities. The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. As used herein, 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. The Company has nonexclusive franchises or permits for electric operations in substantially all cities and towns now served. It also has certificates of convenience and necessity from the Virginia State Corporation Commission (the Virginia Commission) for service in all territory served at retail in Virginia. The North Carolina Utilities Commission (the North Carolina Commission) has assigned territory to the Company for substantially all of its retail service outside certain municipalities in North Carolina. The Company strives to operate its generating facilities in accordance with prudent utility industry practices and in conformity with applicable statutes, rules and regulations. Like other electric utilities, the Company's generating facilities are subject to unanticipated or extended outages for repairs, replacements or modifications of equipment or otherwise to comply with regulatory requirements. Such outages may involve significant expenditures not previously budgeted, including replacement energy costs. See NUCLEAR REGULATION under REGULATION below and NUCLEAR OPERATIONS AND FUEL SUPPLY under SOURCES OF ENERGY USED AND FUEL COSTS. The Company had 10,585 full-time employees on December 31, 1994. 3,794 of the Company's employees are represented by the International Brotherhood of Electrical Workers under a contract extending to March 31, 1995. Negotiations are presently underway to extend the contract. For additional information on significant corporate governance issues relating to the nonutility business see Item 3. LEGAL PROCEEDINGS. CAPITAL REQUIREMENTS AND FINANCING PROGRAM CONSTRUCTION AND NUCLEAR FUEL EXPENDITURES Virginia Power's estimated construction and nuclear fuel expenditures, including Allowance for Funds Used During Construction (AFC), for the three-year period 1995-1997, total $1.9 billion. It has adopted a 1995 budget for construction and nuclear fuel expenditures as set forth below:
FINANCING PROGRAM In 1994, Virginia Power obtained $539 million from the sale of securities. With a portion of the proceeds of the 1994 securities sales, the Company retired $166.5 million of securities through mandatory debt maturities and sinking fund requirements and retired an additional $167.8 million of securities through optional redemptions. Its long-term financings included $325.0 million of First and Refunding Mortgage Bonds, $100 million of unsecured Medium-Term Notes, $39.0 million of Pollution Control Revenue Bonds, and $75.0 million of Common Stock sold to Dominion Resources. See LIQUIDITY AND CAPITAL RESOURCES under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for, among other things, a discussion of the Company's commercial paper program. Virginia Power's 1995 construction and nuclear fuel requirements, exclusive of AFC, are estimated to be $673.2 million. Of this amount, it is expected that approximately $552 million will be obtained from cash flow from operations. The remaining $121.2 million of construction and nuclear fuel requirements, as well as the $312.2 million of debt maturities, will be obtained by a combination of sales of securities and short-term borrowings. See LIQUIDITY AND CAPITAL RESOURCES under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. RATES The Company was subject to rate regulation in 1994 as follows:
Substantially all of the Company's electric 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.
The principal rate proceedings in which the Company was involved in 1994 are described below by jurisdiction. Rate relief obtained by the Company is frequently less than requested. VIRGINIA On February 3, 1994, the Virginia Commission entered its Final Order in Virginia Power's 1992 rate case, approving an increase in annual revenues of $241.9 million. Refunds of $129.2 million (representing the amount recovered under interim rates in excess of the rates finally approved, with interest) were completed by the end of April. The Commission also approved continuation of deferral accounting to recover purchased power capacity costs, allowed inclusion of salary incentive pay in the cost of service, accepted the Company's calculation of postretirement benefits other than pensions, allowed rate base to be updated to November 30, 1992, and recommended a return on equity in the range of 10.5% to 11.5% with rates to be based on 11.4% to reflect superior operating performance of the Company's generating units. The Commission disapproved proposed changes in the Company's line extension policy and a proposed increase in its summer/winter rate differential, and it disallowed from recovery through rates the gross receipts tax component of capacity payments under certain previously executed power purchase contracts. The Commission directed the Company, the Commission's Staff and other interested parties to explore the concept of expanding the generating unit performance program to include purchases of capacity and to present testimony on that issue in the Company's next rate case. The Company and several non-utility generators that will be adversely affected by the ruling that disallowed rate recovery of the gross receipts tax component of purchased power costs appealed that ruling to the Virginia Supreme Court. On January 13, 1995, the Court issued its Opinion affirming the Virginia Commission's decision. On January 23, 1995, the Company and the other appellants filed Motions of Intent to Seek Rehearing. On January 31, 1994, a hearing before a Hearing Examiner was held on Virginia Power's application requesting approval of Schedule DEF -- Dispersed Energy Facility, a rate schedule that would allow the Company to respond to the request of an industrial or commercial customer to build and operate a generating facility at its business location and to sell to that customer all of the electricity and associated steam from that facility under a long-term contract. On June 23, 1994, the Hearing Examiner recommended approval on an experimental basis (see COMPETITION below). On January 10, 1994, a hearing was held before a Hearing Examiner on Virginia Power's application to revise its Schedule 19 (rates to be paid to small qualifying facilities), which sought, among other things, approval of (a) limiting the schedule's applicability to facilities of 100 Kw or less and (b) postponing the commencement of capacity payments until the capacity is needed by the Company. On April 25, 1994, the Hearing Examiner issued his Report recommending approval of these and other features of the Company's application, and on July 1, 1994, the Commission entered its Final Order accepting the Examiner's recommendation as to these and most other issues. On September 19, 1994, Virginia Power filed with the Virginia Commission an application for a $25 million increase in the fuel factor. A hearing was held on October 28, 1994, and the Commission approved an increase of $9.9 million effective November 1, 1994. Virginia Power filed an application with the Virginia Commission on December 21, 1994, seeking approval, on an experimental basis, to implement a real time pricing (RTP) option for its industrial customers with loads in excess of 10 Mw. Under this option, all or a portion of an industrial customer's load growth would be supplied at projected incremental hourly production costs, adjusted for line losses and taxes, plus a margin of 0.6 cents per Kwh, and a marginal cost-based Generation Capacity Adder and a Transmission Capacity Adder would be applicable during those hours when the Virginia Power system is approaching its forecasted annual peak demand. Up to 20% of an industrial customer's existing load could be served on an RTP basis if the customer executes a five-year contract for such service. COUNTY AND MUNICIPAL On January 30, 1995, Virginia Power reached agreement on the terms of a three-year contract governing rates for county and municipal customers in Virginia, which will continue through June 30, 1997. This contract resulted in a decrease of $25.5 million in annual base revenue from the previous contract and became effective July 1, 1994, with base rates remaining constant through the term of the new contract. NORTH CAROLINA In Virginia Power's 1992 rate case before the North Carolina Commission, the Commission disallowed recovery of certain capacity costs paid to a cogenerator and a portion of the compensation of certain Company officers. The Company
appealed the Commission's Order on those issues, and on December 9, 1994, the North Carolina Supreme Court affirmed the disallowance of each by the Commission. The Company filed a Motion for Rehearing on January 13, 1995. Virginia Power filed an application with the North Carolina Commission on September 9, 1994 for a $1.5 million increase in fuel rates. A hearing was held on November 8, 1994, and the increase was approved on December 19, 1994. On December 22, 1994, Virginia Power filed an application with the North Carolina Commission for approval of Self-Generation Deferral Rates that are a part of an Energy Agreement between North Carolina Power and Weyerhaeuser. The Energy Agreement involves the use of a negotiated pricing structure which will result in the deferral of the installation of additional self-generation facilities by Weyerhaeuser. 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), FERC, the Army Corps of Engineers, and other federal, state and local authorities. Compliance with numerous laws and regulations increases the Company'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 the Company'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 state and federal governmental agencies having jurisdiction over various aspects of its business. 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. Various provisions of the Energy Policy Act of 1992 (Energy Act) that could affect the Company include those provisions encouraging the development of non-utility generation, giving FERC authority to order transmission access for wholesale transactions, requiring higher energy efficiency and alternative fuels use, restructuring of nuclear plant licensing procedures, and requiring state regulatory authorities to give full rate treatment for the effects of conservation and demand management programs, including the effects of reduced sales. While the full impact of the Energy Act on the Company cannot at this time be quantified, it is likely, over time, to be significant. See COMPETITION under BUSINESS and COMPETITION under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. ENVIRONMENTAL From time to time, the Company 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 and 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, the Company may be required to expend amounts on remedial investigations and actions. Although the Company is not currently aware of any sites or events including those sites currently identified likely to result in significant liabilities, such amounts, in the future, could be significant. Permits under the Clean Water Act and state laws have been issued for all of the Company's steam generating stations now in operation. Such permits are subject to reissuance and continuing review. The Company is subject to the Clean Air Act (Air Act), which provides the statutory basis for ambient air quality standards. In order to maintain compliance with such standards and reduce the impact of emissions on ambient air quality, the Company may be required to incur significant additional expenditures in constructing new facilities or in modifying existing facilities. The Company has installed a scrubber at its Mt. Storm Unit 3 Power Station. The scrubber began operation on October 31, 1994. The cost of this scrubber and related equipment was $147 million. The Company is presently conducting studies leading to the compliance plan for Phase II of the Clean Air Act, which may involve the installation of two additional scrubbers, the addition of nitrogen oxide (NOx) controls and other methods for compliance. The present estimate for the total
capital cost for compliance, assuming the installation of three scrubbers, nitrogen oxide controls and emission monitoring instrumentation, is $481 million (1992 dollars). Annual incremental compliance costs for operation, maintenance and fuel costs are estimated to be $128 million. These cost estimates may change upon completion of the study effort now underway. See CLEAN AIR ACT COMPLIANCE under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The Company continues to work with the West Virginia Office of Air Quality concerning opacity requirements applicable to the Mt. Storm Power Station. For additional information on ENVIRONMENTAL MATTERS, see Note O to FINANCIAL STATEMENTS. NUCLEAR All aspects of the operation and maintenance of the Company'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 the Company's nuclear generating units. WINTER PEAK Due to record cold weather on January 19, 1994, the Company reached a record winter peak of 14,877 Mw, which exceeded the prior record of 13,478 Mw that had been established one day earlier. Similar conditions were experienced by utilities within the Pennsylvania-New Jersey-Maryland Power Pool.
SOURCES OF POWER COMPANY GENERATING UNITS
(a) Includes an undivided interest of 11.6 percent (207 Mw) owned by Old Dominion Electric Cooperative (ODEC). (b) On December 30, 1994, the Company acquired the North Branch 80 Mw (nominal rating) waste coal power station located in Bayard, West Virginia in Grant County. (c) Reflects the Company'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 Power System, Inc. (APS). The Company's highest one-hour integrated service area summer peak demand was 13,366 Mw on July 29, 1993, and the highest one-hour integrated winter peak demand was 14,877 Mw on January 19, 1994. SOURCES OF ENERGY USED AND FUEL COSTS For information as to energy supply mix and the average fuel cost of energy supply, see RESULTS OF OPERATIONS under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. NUCLEAR OPERATIONS AND FUEL SUPPLY In 1994, the Company's four nuclear units achieved a combined capacity factor of 86.7 percent. The North Anna Unit 2 steam generator replacement project is scheduled to begin at the end of the first quarter of 1995 at a total estimated Company cost of $110 million.
The Company utilizes both long-term contracts and spot purchases to support its needs for nuclear fuel. Virginia Power's nuclear fuel supply and related services are expected to be adequate to support current and planned nuclear generation requirements. The Company continually evaluates worldwide market conditions in order to obtain an adequate nuclear fuel supply. Current agreements, inventories and market availability should support planned fuel cycles throughout the remainder of the 1990s. On-site spent nuclear fuel storage at the Surry Power Station is adequate for the Company's needs through 1998 when, in accordance with the Nuclear Waste Policy Act, the DOE is to begin acceptance of spent fuel for disposal. Should acceptance be delayed, incremental dry storage facilities will be added under the existing storage license. North Anna Power Station will require an interim spent fuel storage facility in the late 1990's and the Company plans to submit a license application to the NRC in 1995 for such a facility at North Anna. For details regarding nuclear insurance and certain related contingent liabilities as well as a NRC rule that requires proceeds from certain insurance policies to be used first to pay stabilization and decontamination expenses, see Note C to FINANCIAL STATEMENTS. FOSSIL FUEL SUPPLY The Company's fossil fuel mix consists of coal, oil and natural gas. In 1994, Virginia Power consumed approximately 10.0 million tons of coal. As with nuclear fuel, the Company utilizes both long-term contracts and spot purchases to support its needs. The Company presently anticipates that sufficient coal supplies at reasonable prices will be available for the remainder of the 1990s. 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. The Company 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. The Company 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 POWER Virginia Power relies on purchases of power to meet a portion of its capacity requirements. The Company also makes economy purchases of power from other utility systems when it is available at a cost lower than the Company'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 subsidiaries of American Electric Power Company, Inc. (AEP). On November 26, 1991, the Company and ODEC signed an agreement whereby the Company will provide ODEC 300 Mw of firm capacity and associated energy from January 1, 1993, until the commercial operation of Clover Unit 1 (currently scheduled for April 1995) or December 31, 1995, whichever occurs first. The Company will then provide 100 Mw of firm capacity and associated energy from the commercial operation of Clover Unit 1 until the commercial operation of Clover Unit 2 (currently scheduled for April 1996) or December 31, 1996, whichever occurs first. The Company has a diversity exchange agreement with APS under which APS delivers 200 Mw to Virginia Power in the summer and Virginia Power delivers 200 Mw to APS in the winter. On June 28, 1994, FERC accepted a Power Sales Tariff filed by the Company on March 8, 1994 and revised on May 27, 1994. This tariff allows the Company to resell the 400 Mw Hoosier allotment to other eligible purchasers and also allows the Company to sell system and emergency power. Virginia Power also has 75 non-utility power purchase contracts with a combined dependable summer capacity of 3,506 Mw. Of this amount, 3,244 Mw were operational at the end of 1994 with the balance scheduled to come on-line through 1997 (see NON-UTILITY GENERATION under FUTURE SOURCES OF POWER and Note O to FINANCIAL STATEMENTS). INTERCONNECTIONS The Company maintains major interconnections with Carolina Power and Light Company, AEP, APS and the utilities in the Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission network, the Company has arrangements with these utilities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy.
On March 23, 1990, the Company and Appalachian Power Company (Apco) (an operating unit of AEP) announced an agreement to increase the ability to exchange electricity between the two companies through the construction of major transmission facilities. The proposed construction will consist of 212 miles of new transmission lines and related substation improvements. The transmission additions will include 116 miles of 765 Kv line to be constructed by Apco and 102 miles of 500 Kv line to be constructed by the Company. Completion of the project, expected to be in service in the year 2000, will take three to four years after all final regulatory approvals have been obtained. A Hearing Examiner of the Virginia Commission has issued reports dated December 2, 1993 and January 24, 1994, recommending Commission approval of the Apco and Company lines, respectively, and both applications are before the Commission for final decision. About 79 miles of the Apco line would be located in West Virginia where regulatory approval must also be obtained. The Company has stated that it would not build its 500 Kv line unless Apco is authorized to build its 765 Kv line and unless certain other regional transmission facilities are constructed or the Company's contractual rights to use the regional transmission network are amended. FUTURE SOURCES OF POWER The Company presently anticipates that system load growth will require approximately 1,100 Mw of additional capacity during the 1990s. The Company has and will pursue capacity acquisition plans to provide that capacity and maintain a high degree of service reliability. This capacity may be built, owned and operated by others and sold to the Company under a competitive bid process pursuant to Commission rules or may be built by the Company if it determines it can build capacity at a lower overall cost. The Company also pursues conservation and demand-side management (see CONSERVATION AND LOAD MANAGEMENT below and CAPITAL REQUIREMENTS under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS). In May 1990, the Company entered into an agreement with ODEC, under which the Company purchased a 50 percent undivided ownership interest in a 782 Mw coal-fired power station to be constructed near Clover, Virginia in Halifax County. The Company will operate the Clover Power Station after it is completed. The cost of the Company's 50 percent ownership interest is expected to be approximately $533 million. The project is on schedule and the Company's share of costs incurred through December 31, 1994 amounted to $449.8 million. Construction on Unit 1 is presently 98% complete and construction on Unit 2 is 54% complete. In Virginia Power's proceeding seeking approval of the Virginia Commission for a 75 mile 500 Kv transmission line from the Clover Power Station to the Carson Substation in Dinwiddie County, Virginia, the Commission approved the line in its Order Granting Application on May 11, 1994. A protestant group has appealed that Order to the Virginia Supreme Court. Initial briefs of all parties have been filed. Oral argument is expected to be scheduled during the first quarter of 1995 and a decision of the Court is likely before mid-1995. The Company's continuing program to meet future capacity requirements is summarized in the following table: COMPANY OWNED GENERATION
* Includes the 50 percent undivided ownership interest of ODEC. See Note F to FINANCIAL STATEMENTS.
NON-UTILITY GENERATION
COMPETITION Competition is playing an increasingly important role in the Company's business both in terms of source of power supply available to the Company and alternative choices for customers meeting their energy needs. Both forms of competition have increased as a result of changing federal and state governmental regulations, technological developments, rising costs of constructing generating facilities and availability of alternative energy sources. The creation of exempt wholesale generators by the Energy Act and their existence in the market for electric sales may have an impact on the Company's plans for the construction or purchase of electric capacity and energy. In addition, the Energy Act gives FERC broad power to require utilities to provide transmission access to others. Exempt wholesale generators and other power suppliers may seek, and FERC may require, access to the transmission systems of investor-owned utilities, including the Company's system. Several of the Company's industrial customers are seeking means of reducing their expenses for power through self-generation and other alternatives. The Company is having discussions with these customers and has proposed a regulatory initiative in Virginia that would enable it to provide on-site generation for such customers (see VIRGINIA under RATES). The Company has undertaken cost-cutting measures to maintain its position as a low-cost producer of electricity and has pursued a strategic planning initiative, called Vision 2000, to encourage innovative approaches to serving traditional markets and to prepare appropriate methods by which to serve future markets. In furtherance of these initiatives, the Company has established its nuclear and fossil and hydroelectric operations as separate business units, has proposed innovative pricing arrangements for incremental industrial loads in Virginia and North Carolina, has executed long term contracts with key wholesale customers and intends to provide an array of energy services to its customers. Potential competition also exists for the Company's sales to its cooperative and municipal customers. Virginia Power entered into discussions in early 1993 with the City of Falls Church, Virginia, where it has approximately 4,100 customers, for the renewal of its franchise that expired on March 26, 1993. Before agreement on a new franchise, the City announced on October 12, 1994, that it would pursue the establishment of a municipal electric system or a municipal purchasing agent and passed an ordinance purporting to extend the Company's franchise until March 26, 1997. The City issued an "Informal Request for Power Supply Proposal" to other electric suppliers on October 13, 1994 to determine the interest in providing power to the City. On January 11, 1995, the City sent to the Company a formal Request for Transmission Service pursuant to Sections 211(a) and 213(a) of the Federal Power Act. The Company, consistent with the State and Federal law, will still attempt to negotiate a new long term franchise with the City while responding as required to the City's request for transmission services. See COMPETITION under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. CONSERVATION AND LOAD MANAGEMENT The Company is committed to integrated resource planning and has developed a detailed analysis procedure in which effective demand-side and supply-side options are both considered in order to determine the least cost method to satisfy the customers' needs. Demand-side programs are selected annually at Virginia Power through an integrated resource planning process which directly compares the stream of costs and benefits from supply-side and demand-side options. This process ensures the ultimate selection of a demand-side package which reduces the need for additional capacity while efficiently using the Company's existing generation facilities. ITEM 2.

ITEM 2. PROPERTIES The Company owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of its property is subject to the lien of a mortgage securing its First
and Refunding Mortgage Bonds. Right-of-way grants from the apparent owners of real estate have been obtained for most electric lines, but underlying titles have not been examined except for transmission lines of 69 Kv or more. Where rights of way have not been obtained, they could be acquired from private owners by condemnation if necessary. Many electric lines are on publicly owned property as to which permission for use is generally revocable. Portions of the Company's 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. The Company leases certain buildings and equipment. See Note H to FINANCIAL STATEMENTS. See COMPANY GENERATING UNITS under SOURCES OF POWER under Item 1. BUSINESS. ITEM 3.

ITEM 3. LEGAL PROCEEDINGS From time to time, the Company may be in violation of or in default under orders, statutes, rules or regulations relating to protection of the environment, compliance plans imposed upon or agreed to by the Company or permits issued by various local, state and federal agencies for the construction or operation of facilities. There may be pending from time to time administrative proceedings involving violations of state or federal environmental regulations that the Company believes are not material with respect to it and for which its aggregate liability for fines or penalties will not exceed $100,000. There are no material agency enforcement actions or citizen suits pending or, to the Company's present knowledge, threatened against the Company. Virginia Power is involved in an arbitration with Smith Cogeneration of Virginia, Inc. (SCV) before the Virginia Commission concerning the terms of the purchase of power from two 158 megawatt generating units to be developed by SCV. The arbitrator has submitted his Report to the Commission recommending that the parties enter into a contract containing terms that would require Virginia Power to pay what it considers to be excessive amounts for the power to be purchased. The parities have been given until March 31, 1995 to file comments on the Arbitrator's Report. Virginia Power and Doswell Limited Partnership (Doswell) have been unable to agree on the calculation of a Fixed Fuel Transportation Charge to be paid to Doswell under a purchased power contract. Doswell filed suit in the Circuit Court of the City of Richmond alleging breach of contract and actual and constructive fraud and seeking damages of not less than $75 million. The issues of actual and constructive fraud were dismissed from the case, with prejudice, leaving only the contract claim, which reduced alleged damages to approximately $19 million. On March 2, 1995, the Court announced its verdict in favor of Virginia Power. On February 23, 1994, Virginia Power filed with the Virginia Commission a Petition for Declaratory Judgment seeking a declaration that an arrangement proposed by E.I. DuPont de Nemours & Company (DuPont) and LG&E Power, Inc. (LG&E) for a partnership between those two companies to furnish energy services to DuPont in Virginia Power's service territory is illegal under Virginia law. DuPont filed a Motion to dismiss for lack of jurisdiction, to which Virginia Power responded. Prior to any action by the Commission, DuPont and LG&E announced that they had terminated their negotiations, and the Commission has directed the parties to comment on whether the proceeding should be dismissed. On January 13, 1995, Virginia Power filed its response stating that the case should not be dismissed in the absence of a clear statement on the record by both DuPont and LG&E that each has abandoned the power partnering concept in Virginia Power's service territory. DuPont renewed its Motion to Dismiss and the Commission entered its dismissal order on January 24, 1995. A dispute over corporate governance issues between Dominion Resources and Virginia Power arose in 1994. On June 17, 1994, Dominion Resources and Virginia Power received an order from the Virginia Commission (the 1994 Order) that, among other things, initiated an investigation into the affiliate relationships and corporate governance issues between Dominion Resources and Virginia Power (the First Proceeding). The text of the 1994 Order was set forth in the Company's Current Report on Form 8-K of June 17, 1994. Between June and August 1994, Dominion Resources and Virginia Power made various filings with the Commission, and the Commission issued several procedural orders, in connection with the First Proceeding. A description of those filings and orders is set forth in the Company's Quarterly Report on Form 10-Q for the period ending June 30, 1994. On August 15, 1994, Dominion Resources, Virginia Power and their respective directors entered into a Settlement Agreement resolving certain of the disputed corporate governance issues. The terms of that settlement are summarized in the Company's Current Report on Form 8-K of August 17, 1994. Pursuant to the Settlement Agreement, Dominion Resources and Virginia Power filed a Joint Motion to Dismiss certain of the corporate governance issues from the First Proceeding. The Commission denied that Motion on August 24, 1994, continued the First Proceeding, and instituted a new proceeding (the Second Proceeding) into the holding company structure and the relationship between Dominion Resources and Virginia
Power. The Commission stated that the Second Proceeding would be an "investigation directed not at averting a crisis or penalizing past conduct, but toward protecting the public interest in the future." The Commission directed its Staff to conduct an investigation and file an interim report on or before December 1, 1994. On December 1, 1994, the Staff of the Virginia Commission and its consultants filed an Interim Report in the Second Proceeding. That Report is included in the Company's Current Report on Form 8-K of December 5, 1994. The Interim Report made numerous recommendations for Commission involvement in matters of corporate governance, corporate structure, affiliate service arrangements, and operating relationships between Dominion Resources and Virginia Power, and suggested certain financial constraints on Dominion Resources and new regulatory authority for the Commission. Many of these suggestions were far-reaching. On December 21, 1994, Dominion Resources and Virginia Power filed a Joint Response to the Interim Report, in which they accepted some of the recommendations and urged that the corporate governance structure established by the Settlement Agreement continue while they considered the other recommendations in the course of a strategic planning effort by Dominion Resources. On January 23, 1995, the Staff of the Virginia Commission issued a report in the Second Proceeding on its investigation of a coal transportation contract between the Company and CSX Transportation. The Staff's report concluded that Dominion Resources improperly pressured Virginia Power to renegotiate the contract, and recommended that approximately $11 million ($8.3 million Virginia jurisdictional) of the coal transportation costs incurred under the contract from 1991 through May 31, 1994 be disallowed in determining Virginia Power's rates. The Staff's report further recommended that any future transportation costs that it identified as excess be disallowed over the remainder of the contract, which expires on May 31, 2000. The Company has recorded a regulatory liability of $10.5 million at December 31, 1994. The Company currently estimates that the total amount called into question by the Virginia Commission Staff report is a net present value of $60 million ($100 million over the life of the contract). On February 1, 1995, without admitting any imprudence, fault or liability, and believing that their relationship with the Commission would be enhanced, Dominion Resources and the Company filed a motion offering to refund to the Company's customers $8.3 million in settlement of these issues regarding transportation rates. During the 1995 session of the Virginia General Assembly, the Virginia Commission caused legislation to be introduced that addressed the Commission's authority to intervene in disputes involving public utilities owned by separate holding companies. That legislation was opposed by Dominion Resources. On February 20, 1995, the proposed legislation was withdrawn and Dominion Resources, Virginia Power and the Virginia Commission Staff consented to an order that is included in Virginia Power's Current Report on Form 8-K of February 21, 1995. Under this order, which will be effective until July 2, 1996, Dominion Resources must obtain the Commission's approval before taking steps such as removing Virginia Power's board members or officers or changing Virginia Power's articles of incorporation or by-laws. Although the order imposes for a period of time significant restrictions on the ability of Dominion Resources to select the Board and management of its subsidiary, Dominion Resources and Virginia Power agreed to the order in the interest of enhancing relations with the Virginia Commission and achieving the purposes of the Settlement Agreement. Disagreements between the companies have arisen from time to time since the Settlement Agreement was executed. On February 28, 1995, upon recommendation of a Joint Committee created under the Settlement Agreement, the Boards of Dominion Resources and Virginia Power took further action to enhance cooperation between the two companies and their relationship with the Virginia Commission. Among other things, the Boards expanded the authority of the Joint Committee to act for the Boards on issues presented to it by the chief executives of the companies. Each Board directed corporate officials and employees of its company to cooperate fully with the Joint Committee in resolution of issues acted on by the Committee and to support actions taken by the Committee. In connection with these initiatives, the chief executive officers of both companies made known their intentions to retire in July 1996 and the Boards directed the development of executive succession plans for each company. Also, the Dominion Resources Board received the resignations of directors Bruce C. Gottwald and John W. Snow and the Virginia Power Board received the resignations of directors William W. Berry and Frank S. Royal, and both Boards voted to reduce their size by two members. At this time, Virginia Power is unable to predict the ultimate resolution of these matters or their effect on the Company.
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 All of the Company's Common Stock is owned by Dominion Resources. During 1994 and 1993, the Company paid quarterly cash dividends on its Common Stock as follows:
ITEM 6.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES Cash flow from operating activities has accounted for, on average, 74 percent of the Company's cash requirements over the past three years. Net cash provided by operating activities decreased by $4.6 million in 1994 as compared to 1993, primarily as a result of a number of factors resulting from normal operations, partially offset by a rate refund of $129.2 million in 1994.
Net cash provided by operating activities decreased $152.1 million in 1993 as compared to 1992, primarily as a result of the rate refund of $188.9 million in 1993 offset in part by the recovery of previously deferred capacity expenses. Cash from (to) financing activities was as follows:
The Company sold $325.0 million of First and Refunding Mortgage Bonds in 1994. With a portion of the proceeds, the Company refinanced $119.0 million of its higher-cost debt. The remainder of the proceeds was used to meet a portion of the Company's capital requirements. In 1994, the Company also issued $100 million of unsecured Medium-Term Notes with annual interest rates ranging from 6.15% to 7.27%, the proceeds of which were used to meet a portion of the Company's capital requirements. The Company also issued $39 million of variable and fixed rate Pollution Control Securities in 1994 to refinance $39 million of higher-cost Pollution Control Securities. In 1994, the Company issued to Dominion Resources $75 million of Common Stock. During the year, the Company retired $166.5 million of securities through mandatory debt maturities and sinking fund requirements and repurchased $7.5 million of its debt securities and $2.3 million of preferred stock. Proceeds from the sale of commercial paper are primarily used to finance working capital for operations. Borrowings under the Company's commercial paper program are limited to $200 million outstanding at any one time. At December 31, 1994, no amount was outstanding under this program. Cash from (used in) investing activities was as follows:
Investing activities in 1994 resulted in a net cash outflow of $726.8 million primarily due to $580.9 million of construction expenditures and $80 million of nuclear fuel expenditures. Of the construction expenditures, approximately $67.3 million was spent on new generating facilities, $173.8 million on other production projects, and $291.3 million on transmission and distribution projects. CAPITAL REQUIREMENTS The Company presently anticipates that kilowatt-hour sales will grow approximately 2.1 percent a year through 2014. Capacity needed to support this growth will be provided through a combination of Company-constructed generating units, purchases from non-utility generators and other utility generators. Each of these options plays an important role in the Company's overall plan to meet capacity needs. The Company's construction and nuclear fuel expenditures (excluding AFC), during 1995, 1996 and 1997 are expected to aggregate $673.2 million, $600.3 million and $615.2 million, respectively. Construction continues on the 782 Mw coal-
fired power station near Clover, Virginia, of which the Company has a 50 percent undivided ownership interest. The Company's share of the cost of the construction is approximately $533.0 million of which $449.8 million had been incurred as of December 31, 1994. The expected in-service dates for Clover Units 1 and 2 are April 1995 and April 1996, respectively. After 1996, no base load generation is expected to be needed until the middle of the next decade. From 1999 until 2005, the Company will need to add only peaking units to meet anticipated demand. The Company will require $312.2 million to meet long-term debt maturities in 1995. The Company presently estimates that, for 1995, 82 percent of its construction expenditures, including nuclear fuel expenditures, will be met through cash flow from operations and the balance, including other capital requirements, will be obtained 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 1994 as compared to 1993, and 1993 as compared to 1992. 1994 COMPARED TO 1993 OPERATING REVENUES changed principally due to the following:
As detailed in the chart above, the decrease in revenues is primarily due to a decrease in base revenues. Base revenues were lower in 1994 primarily as a result of additional revenue reserves established during the year. During 1994, the Company had 46,741 new connections to its system compared to 43,014 and 39,807 in 1993 and 1992, respectively. Kilowatt-hour sales changed as follows:
The increase in kilowatt-hour sales in 1994 as compared to 1993 reflects the extreme weather experienced in January 1994, partially offset by lower sales during the second half of 1994, due to milder weather. The number of actual cooling degree days in 1994 was 5.7 percent above the normal number of cooling degree days and the number of actual heating degree days was 3.8 percent below the number of normal heating degree days. The increase in kilowatt-hour sales in 1993 as compared to 1992 reflects the warmer than normal summer weather in 1993 as compared to the moderate weather in 1992. The number of actual cooling degree days in 1993 was 10.0 percent above the number of normal cooling degree days and the number of actual heating degree days was 1.2 percent above the number of normal heating degree days. The increase in sales for resale in 1993 as compared to 1992 was primarily due to the sale of firm capacity and associated energy to ODEC. Under the terms of the agreement signed November 26, 1991, the Company is committed to sell up to 300 Mw of capacity to ODEC through the commercial operation date of Clover Power Station.
The average fuel cost of system energy output is shown below:
System energy output is shown below:
(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power Station (see Note F to FINANCIAL STATEMENTS). OPERATION EXPENSES-OTHER increased as compared to 1993 primarily as a result of recognition of costs associated with the Early Retirement and Voluntary Separation Programs offered by the Company in 1994. INCOME TAXES-OPERATING decreased as compared to 1993 primarily as a result of decreased pretax book income. INTEREST CHARGES-OTHER decreased in 1994 primarily as a result of a reduction of $10.6 million in the interest accrued for prior years on certain tax obligations. 1993 COMPARED TO 1992 FUEL, NET increased as compared to 1992 as a result of higher sales in 1993 and a decrease in nuclear generation due to the scheduled outages in 1993. The increased sales together with the reduced generation from the nuclear units increased the use of purchased power and resulted in higher overall fuel costs. PURCHASED POWER CAPACITY, NET resulted in an increase in 1993. In 1992, the Company implemented deferral accounting for certain capacity expenses. The increase in expense in 1993 primarily reflects the recovery of expenses deferred in 1992. OPERATION EXPENSES, OTHER increased as compared to 1992 primarily as a result of the increased expenses associated with accrual of other postretirement benefits due to the implementation of Statement of Financial Accounting Standards (SFAS) No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions" effective January 1, 1993. INCOME TAXES-OPERATING increased as compared to 1992 primarily as a result of increased pretax book income and an increase in the federal income tax rate from 34 percent to 35 percent. OTHER INCOME AND OTHER INTEREST CHARGES decreased as compared to 1992 primarily as a result of a reclassification of the imputed interest on the nuclear decommissioning obligation which was previously included in Other Interest Charges ($14.8 million) and is now included in OTHER INCOME, as approved by FERC. This increase was offset in part by a $3.1 million decrease in expenses associated with the sale of accounts receivable. CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE In 1992, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." The Company reported the implementation of the standard as a change in accounting principle with the cumulative effect on prior years of $14.3 million reported in 1992 earnings. The adoption of SFAS No. 109
in 1992 increased deferred income tax liabilities by $459 million and resulted in the establishment of a net regulatory asset of $459 million. For additional information, see Note A to FINANCIAL STATEMENTS. FUTURE ISSUES UTILITY RATE REGULATION Regulatory policy continues to be of fundamental importance to the Company and to its financial performance. Recently and in the near-term future, the costs of purchased capacity constitute the largest category of increased costs requiring rate relief. The Virginia Commission has authorized rates providing for the current recovery of the ongoing level of capacity payments. Moreover, the Virginia Commission has established and reaffirmed deferral accounting that is intended to ensure dollar for dollar recovery of reasonably incurred capacity costs. For additional information on the current rate proceedings, see RATES under Item 1. BUSINESS. 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. They can result in increased capital, operating and other costs as a result of remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemaking process; however, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely impacted. WATER QUALITY COMPLIANCE On March 30, 1992, the Virginia Water Control Board adopted water quality standards for toxic pollutants pursuant to the Clean Water Act. The standards became effective on April 20, 1992 and will be applicable to the Company as Virginia Pollution Discharge Elimination System Permits are reissued. The Company is studying the potential impact of the standards and cannot presently determine whether or to what extent changes to facilities or operating procedures might ultimately be required but incremental compliance costs could be significant. ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES The Company incurred $67.3 million, $72.2 million and $65.2 million (including depreciation) during 1994, 1993 and 1992, respectively, in connection with the use of environmental protection facilities and expects these expenses to be approximately $64.3 million in 1995. In addition, capital expenditures to limit or monitor hazardous substances were $4.0 million, $3.6 million and $6.6 million for 1994, 1993 and 1992, respectively. The amount estimated for 1995 for these expenditures is $33.1 million. CLEAN AIR ACT COMPLIANCE The Air Act, as amended in 1990, requires the Company to reduce its emissions of sulfur dioxide and nitrogen oxides. Beginning in 1995, the sulfur dioxide reduction program is based on the issuance of a limited number of sulfur dioxide emission allowances, each of which may be used as a permit to emit one ton of sulfur dioxide into the atmosphere or may be sold to someone else. The program is administered by the EPA. The Company is assessing the economic reasonableness of constructing two additional scrubbers at its Mt. Storm Power Station or acquiring allowances as a means of maintaining compliance with the Air Act's standards. For additional information on the Clean Air Act, see REGULATION under Item 1. BUSINESS.
ELECTROMAGNETIC FIELDS The possibility that exposure to electromagnetic fields emanating from power lines, household appliances and other electric sources may result in adverse health effects has been a subject of increased public, governmental and media attention. A considerable amount of scientific research has been conducted on this topic without definitive results. Research is continuing to resolve scientific uncertainties. It is too soon to tell what, if any, impact these actions may have on the Company's financial condition. NUCLEAR OPERATIONS In 1994, the Company's four nuclear units operated at a combined capacity factor of 86.7 percent, reflecting a record 31 day refueling outage at North Anna Unit 1, a 63 day refueling/ten-year in-service inspection outage at Surry Unit 1, and two scheduled steam generator chemical cleaning outages at Surry Units 1 and 2, which took 27 and 21 days respectively. Nuclear refueling outages typically occur every eighteen months and last approximately sixty days. The Company's goal is to reduce refueling outages from an average of sixty days to forty-eight days. When nuclear units are refueled, the Company replaces the power from nuclear generation with other more expensive sources. A reduction in the length of an outage should result in increased availability of low-cost nuclear generation, thereby lowering expenses. Three refueling outages are currently scheduled in 1995. The North Anna Unit 2 outage will include steam generator replacement. The Surry Unit 2 outage will include a ten year in-service inspection while the Surry Unit 1 outage will be for normal refueling. See NUCLEAR OPERATIONS AND FUEL SUPPLY, Sources of Energy Used and Fuel Costs under Item 1. BUSINESS. Stress corrosion cracking has occurred in steam generators of a certain design, including those at the Surry and North Anna Power Stations. The steam generators at Surry Units 1 and 2 were replaced in 1981 and 1979, respectively. The replacement of the North Anna Unit 1 steam generators was completed in 1993 at a cost of $106 million. Replacement of the North Anna Unit 2 steam generators is scheduled for 1995 at a total estimated Company cost of $110 million. Costs associated with the steam generator replacements at Surry are being recovered through rates. Costs associated with the steam generator replacements at North Anna Unit 1 and Unit 2 are expected to be recovered through rates. The NRC has proposed revisions to the nuclear power plant license renewal rules issued in 1991. The Company intends to work with industry groups on life extension programs, and comment on the proposed rulemaking. In addition to improving nuclear unit productivity and efficiency, the Company has completed engineering analyses and evaluations to support uprating the capability of the units. The plant modifications have been completed at the North Anna facility, and the upgraded core improvement has resulted in a 4.2% increase in the gross electrical output for each of the units. A similar project has been initiated to uprate both Surry Units 1 and 2 in 1995. Analyses and evaluations to support the uprate have been completed and a license amendment is pending before the Nuclear Regulatory Commission. For information on nuclear decommissioning, see Note C to FINANCIAL STATEMENTS. CONSERVATION AND LOAD MANAGEMENT For information, see CONSERVATION AND LOAD MANAGEMENT under Item 1. BUSINESS. COMPETITION The Company will continue to be affected by the developing competitive market in wholesale power. Under the Energy Policy Act of 1992, any participant in the wholesale market can obtain a FERC order to provide transmission services, under certain conditions. FERC has completed an industry-wide formal inquiry aimed at reforming the pricing of transmission services. The Company was an active participant in that inquiry. FERC is also encouraging the development of regional transmission groups (RTGs) in which transmission-owning utilities and transmission users would jointly plan facilities and administer the provision of transmission services. It is too early to determine what effects reformed transmission pricing and the development of RTGs could have on the Company. At present, competition for retail customers is limited. It arises primarily from the ability of certain business customers to relocate among utility service territories, to substitute other energy sources for electric power and to generate their own electricity. The Energy Policy Act bans federal orders of transmission service to ultimate customers. Broader retail competition that would allow customers to choose among electric suppliers has been the subject of intense debate in federal and state
forums. If such competition were to develop, it would have the potential to shift costs among customer classes and to create significant transitional costs. Certain state actions that affect retail competition may be preempted by federal law. Potential competition also exists for the Company's sales to its cooperative and municipal customers. However, nearly all of this service is under contracts with multi-year notice provisions. To date, the Company has not experienced any material loss of load, revenues or net income due to competition for its customers. The Company believes it has a strong capability to meet future competition. For additional information on competition, see COMPETITION under Item 1. BUSINESS. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", the Company's financial statements reflect assets and costs based on current cost-based ratemaking regulations. Continued accounting under SFAS 71 requires that the following criteria be met: a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator; b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from customers. This criterion requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs. A utility's operations or portion of operations can cease to meet these criteria for various reasons, including a change in the method of regulation or a change in the competitive environment for regulated services. A utility whose operations or portion of operations cease to meet these criteria should discontinue application of SFAS 71 and write-off any regulatory assets and liabilities for those operations that no longer meet the requirements of SFAS 71. The Company's operations currently satisfy the SFAS 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, Management believes that a material adverse effect on the Company's results of operations and financial position may result. COMMITMENTS AND CONTINGENCIES A dispute over corporate governance issues between Dominion Resources and Virginia Power arose in 1994. In connection with that dispute, the Virginia Commission commenced proceedings investigating these and related issues. A Settlement Agreement was entered into by the two Companies and their respective Boards with respect to these matters in August 1994. The Settlement Agreement is also described in Item 3. LEGAL PROCEEDINGS. During the 1995 session of the Virginia General Assembly, the Virginia Commission caused legislation to be introduced that addressed the Commission's authority to intervene in disputes involving public utilities owned by separate holding companies. That legislation was opposed by Dominion Resources. On February 20, 1995, the proposed legislation was withdrawn and Dominion Resources, Virginia Power and the Virginia Commission Staff consented to an order that is included in Virginia Power's Current Report on Form 8-K of February 21, 1995. Under this order, which will be effective until July 2, 1996, Dominion Resources must obtain the Commission's approval before taking steps such as removing Virginia Power's board members or officers or changing Virginia Power's articles of incorporation or by-laws. Although the order imposes for a period of time significant restrictions on the ability of Dominion Resources to select the Board and management of its subsidiary, Dominion Resources and Virginia Power agreed to the order in the interest of enhancing relations with the Virginia Commission and achieving the purposes of the Settlement Agreement. Disagreements between the companies have arisen from time to time since the Settlement Agreement was executed. On February 28, 1995, upon recommendation of a Joint Committee created under the Settlement Agreement, the Boards of Dominion Resources and Virginia Power took further action to enhance cooperation between the two companies and their relationship with the Virginia Commission. Among other things, the Boards expanded the authority of the Joint Committee to act for the Boards on issues presented to it by the chief executives of the companies. Each Board directed corporate officials and employees of its company to cooperate fully with the Joint Committee in resolution of issues acted on by the Committee and to support actions taken by the Committee. In connection with these initiatives, the chief executive officers of both companies made known their intentions to retire in July 1996 and the Boards directed the development of executive succession plans for each company. Also, the Dominion Resources Board received the resignations of directors Bruce C. Gottwald and John W. Snow and the Virginia Power Board received the resignations of directors William W. Berry and Frank S. Royal, and both Boards voted to reduce their size by two members. At this time, Virginia Power is unable to predict the ultimate resolution of these matters or their effect on the Company.
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 Financial Statements and other sections of the Company's annual report on Form 10-K. The 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 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 1994 the system of internal control was adequate to accomplish the intended objective. The Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, whose designation was approved 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 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 balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) as of December 31, 1994 and 1993 and the related statements of income, earnings reinvested in business, and cash flows for each of the three years in the period ended December 31, 1994. 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 financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company at December 31, 1994 and 1993 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. The Company changed its methods of accounting for postretirement benefits other than pensions in 1993 (see Note M) and for accounting for income taxes in 1992 (see Note B) in order to conform with recently issued accounting standards. DELOITTE & TOUCHE LLP Richmond, Virginia February 6, 1995
VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF INCOME
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY BALANCE SHEETS ASSETS
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF EARNINGS REINVESTED IN BUSINESS
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of the financial statements.
VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO FINANCIAL STATEMENTS A. SIGNIFICANT ACCOUNTING POLICIES: GENERAL The Company's accounting practices are generally prescribed by the Uniform System of Accounts promulgated by the regulatory commissions having jurisdiction and are in accordance with generally accepted accounting principles applicable to regulated enterprises. The Company is a wholly-owned subsidiary of Dominion Resources, Inc., a Virginia corporation. REVENUES Operating revenues are recorded on the basis of service rendered. PROPERTY, PLANT AND EQUIPMENT Utility plant 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, as provided in the Uniform System of Accounts, 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 is based on weighted average depreciable plant using a rate of 3.2 percent for 1994, 1993 and 1992. 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 adopted SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109) in 1992. This standard requires companies to measure and record deferred tax assets and liabilities for all temporary differences. The regulatory treatment of temporary differences can differ from the requirements of SFAS No. 109. Accordingly, the Company recognizes a regulatory asset if it is probable that future revenues will be provided for the payment of those deferred tax liabilities. Similarly, in the event a deferred tax liability is reduced to reflect changes in tax rates, a regulatory liability is established if it is probable that a future reduction in revenue will result. Prior to 1992, the Company recorded deferred taxes for timing differences between book income and taxable income to the extent such differences were permitted by regulatory commissions for ratemaking purposes. The Company files a consolidated federal income tax return with Dominion Resources. Accumulated investment tax credits are being amortized over the service lives of the property giving rise to such credits. 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. The pretax AFC rates for 1994, 1993 and 1992 were 8.9, 9.4 and 10.3 percent, respectively. Approximately 83 percent of the Company's construction work in progress is now included in rate base, and a cash return is collected currently thereon. DEFERRED CAPACITY AND FUEL EXPENSE In 1992, the Company began to defer certain capacity expenses based on an order of the Virginia Commission. Approximately 80 percent of capacity expenses and 90 percent of fuel expenses are subject to deferral accounting. The difference
between reasonably incurred actual expenses and the level of expenses included in current rates is deferred and matched against future revenues. 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 OTHER INVESTMENTS Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 1994 and 1993, the Company's accounts payable included the net effect of checks outstanding but not yet presented for payment of $66.8 million and $72.5 million, respectively. For purposes of the Statement 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. RECLASSIFICATION Certain amounts in the 1993 and 1992 financial statements have been reclassified to conform to the 1994 presentation. 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:
In 1992, the Company adopted the provisions of SFAS No. 109. The Company reported the implementation of the standard as a change in accounting principle with the cumulative effect on prior years of $14.3 million reported in 1992 earnings. The adoption of SFAS No. 109 increased deferred income tax liabilities by $459.0 million and resulted in the establishment of a net regulatory asset of $459.0 million. For additional information see FEDERAL INCOME TAXES under Note A to FINANCIAL STATEMENTS. The Company's net accumulated deferred income taxes consist of the following:
C. NUCLEAR OPERATIONS: DECOMMISSIONING Nuclear plant decommissioning costs are accrued and recovered through rates over the expected service lives of the Company's nuclear generating units. The amounts collected from customers are being placed in trusts, which, with the accumulated earnings thereon, will be utilized solely to fund future decommissioning obligations. Approximately every four years, site-specific studies are prepared to determine the decommissioning cost estimate for the Company's four nuclear units. The current cost estimate is based on the DECON method, which assumes the decontamination or prompt removal of radioactive contaminants so that the property may be released for unrestricted use shortly after cessation of operations. The Company currently estimates that decommissioning will begin at the expiration date of each unit's operating license, which will occur in 2012, 2013, 2018 and 2020 for the Surry Units 1 & 2 and North Anna Units 1 & 2, respectively. Based on the Company's latest decommissioning study completed in 1994, total decommissioning costs, including reclamation costs, are estimated to be $1.0 billion in 1994 dollars. The accumulated provision for decommissioning of $260.9 million and $226.4 million is included in Utility Plant Accumulated Depreciation at December 31, 1994 and 1993, respectively. Provisions for decommissioning of $24.5 million, $24.4 million and $24.3 million applicable to 1994, 1993 and 1992, respectively, are included in Depreciation and Amortization Expense. The balance in the Company's Nuclear Decommissioning trust funds was $260.9 million and $226.4 million at December 31, 1994 and 1993, respectively. The net unrealized loss of $5.2 million at December 31, 1994 is included in the accumulated provision for decommissioning.
Earnings of the trust funds were $15.2 million, $16.3 million and $9.1 million for 1994, 1993 and 1992, respectively, and are included in Other Income in the Company's Statements of Income. In 1994 and 1993, the accretion of the accumulated provision for decommissioning, equal to the earnings of the trust funds, was recorded in Other Income. See MISCELLANEOUS, NET under RESULTS OF OPERATIONS, Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Such amounts in 1992 were recorded in Interest Charges, Other. The Financial Accounting Standards Board (FASB) is reviewing the accounting for nuclear plant decommissioning. If current electric utility industry practices for such decommissioning are changed, annual provisions for decommissioning could increase. FASB may ultimately determine 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 plant. INSURANCE The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $8.9 billion for a single nuclear incident. The Price-Anderson Amendments Act 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 $81.7 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. Nuclear liability coverage for claims made by nuclear workers first hired on or after January 1, 1988, except those arising out of an extraordinary nuclear occurrence, is provided under the Master Worker insurance program. (Those first hired into the nuclear industry prior to January 1, 1988, are covered by the policy discussed above.) The aggregate limit of coverage for the industry is $400 million ($200 million policy limit with automatic reinstatements of an additional $200 million). The Company's maximum retrospective assessment is approximately $12.7 million (including a 3 percent insurance premium tax for Virginia). 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 be 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 property insurance coverage provided to the Company is subject to retrospective premium assessments, in any policy year in which losses exceed the funds available to these insurance companies. The maximum assessment at the first incident of the current policy period is $45.4 million and the maximum assessment related to a second incident is an additional $15.1 million. Based on the severity of the incident, the Board of Directors of the Company's nuclear insurers has the discretion to lower the maximum retrospective premium assessment or eliminate either or both completely. 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 Nuclear Electric Insurance Limited (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 $9.2 million. As part owner of the North Anna Power Station, ODEC is responsible for its proportionate share (11.6 percent) of the insurance premiums applicable to that station, including any retrospective premium assessments and any losses not covered by insurance. D. SALE OF RECEIVABLES: The Company has an agreement to sell, with limited recourse, certain accounts receivable including unbilled amounts, up to a maximum of $200 million. Additional receivables are continually sold, at the Company's discretion, to replace those collected up to the limit. At December 31, 1994 and 1993, $160 million and $200 million, respectively, of receivables had been sold and were outstanding under this agreement. The limited recourse is provided by the Company's assignment of an
additional undivided interest in accounts receivable to cover any potential losses to the purchaser due to uncollectible accounts. The Company has provided for the estimated amount of such losses in its accounts. E. UTILITY PLANT: Utility plant at December 31, consisted of the following:
F. JOINTLY OWNED PLANTS: The following information relates to the Company's proportionate share of jointly owned plants at December 31, 1994:
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, maintenance, depreciation, taxes, etc.) in the Statements of Income. G. REGULATORY ASSETS: Certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets and are recognized in income as the related amounts are included in rates and recovered from customers. The Company's regulatory assets included the following:
Income taxes recoverable through future rates represent principally the tax effect of depreciation differences not normalized. These amounts are amortized as the related temporary differences reverse.
The costs of decommissioning the Department of Energy's (DOE) uranium enrichment facilities have been deferred and represents the unamortized portion of 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 fifteen-year period with escalation for inflation. These costs are being recovered in fuel rates. Deferred 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 construction of North Anna Unit 3 was terminated in November 1982. All retail jurisdictions have permitted recovery of the incurred costs. The amounts deferred are being amortized over a fifteen-year period for Virginia and FERC jurisdictional customers. H. LEASES: Plant and property under capital leases included 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 $25.0 million and $26.0 million at December 31, 1994 and 1993, respectively. Rental payments for such lease were $3.0 million for each of the three years ended December 31, 1994, 1993 and 1992. 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, 1994, are as follows:
Rents on leases, which have been charged to other operation expenses, were $9.6 million, $11.2 million and $10.6 million for 1994, 1993 and 1992, respectively.
I. LONG-TERM DEBT: Long-term debt included the following:
(1) Substantially all of the Company's property is subject to the lien of its mortgage, securing its First and Refunding Mortgage Bonds. (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. The weighted average daily interest rates were 2.96% and 2.53% for 1994 and 1993, respectively. Pollution control bonds subject to remarketing within one year are classified as long-term debt to the extent that the Company's intention to maintain the debt is supported by long-term bank commitments. Under the terms of an Inter-Company Credit Agreement, the Company may borrow funds from Dominion Resources on a daily basis and repay all or part of the loan at any time. Borrowings under the Agreement are limited to $300 million outstanding at any one time, less amounts outstanding under the commercial paper program. At December 31, 1994, there were no amounts outstanding under the Agreement and no amounts were borrowed during 1994. With a portion of the proceeds from the sale of $200 million First and Refunding Mortgage Bonds of 1993, Series G, the Company in 1993 irrevocably placed $138.2 million in a trust to defease $119.1 million 1990 Series A Bonds. As a result, the
1990 Series A Bonds were considered to be extinguished for financial reporting purposes and were excluded from the balance sheet at December 31, 1994 and 1993. The cost of $19.1 million was deferred and is being amortized over the life of the new issue. Maturities through 1999 are as follows (millions): 1995 -- $312.2; 1996 -- $259.6; 1997 -- $311.3; 1998 -- $293.5; and 1999 -- $261.0. J. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION: Preferred stock subject to mandatory redemption, $100 liquidation preference, at December 31, 1994, was as follows:
(a) Shares are non-callable prior to redemption. (b) All shares to be redeemed on 3/1/2000. (c) All shares to be redeemed on 9/1/2000. (d) The 1995 and a portion of the 1996 sinking fund requirements were satisfied by the 1994 open market purchase. Maturities are $0.7 million for 1996 and $1.5 million for each of the years 1997-1999. During the years 1992 through 1994, the following shares were redeemed:
The total number of authorized shares for all preferred stock is 10,000,000 shares. Upon involuntary liquidation, all presently outstanding preferred stock is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.
K. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION: Preferred stock not subject to mandatory redemption, $100 liquidation preference, at December 31, 1994, was as follows:
(*) 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 1994, 1993 and 1992, including fees for broker/dealer agreements, were 3.75 percent, 3.01 percent and 3.43 percent, respectively. In 1993, 350,000 and 500,000 shares of the $7.72 and the $7.72 (1972 Series) Dividend Preferred Stock, respectively, were redeemed. L. COMMON STOCK: During the years 1992 through 1994 the following changes in Common Stock occurred:
M. RETIREMENT PLAN AND POSTRETIREMENT BENEFITS: The Company participates in the Dominion Resources, Inc. Retirement Plan (the Retirement Plan), a defined benefit pension plan. The Retirement Plan covers virtually all employees of Dominion Resources and its subsidiaries, including the Company. The benefits are based on years of service and average base compensation over the consecutive 60-month period in which pay is highest. Pension plan expenses were $19.3 million, $15.9 million and $13.1 million for 1994, 1993 and 1992, respectively and the amounts funded were $42.7 million, $16.0 million and $12.3 million in 1994, 1993 and 1992, respectively.
The Company adopted the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" effective January 1, 1993. This standard requires the accrual of the cost of providing other postretirement benefits (OPEB), including medical and life insurance coverage, during the active service of the employee. Prior to 1993, the Company recognized expense on a pay-as-you-go basis. The Company recognized as expense $10.5 million for these benefits in 1992. 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. Net periodic postretirement benefit expense for 1994 and 1993 was as follows:
The following table sets forth the funded status of the plan:
A one percent increase in the health care cost trend rate would result in an increase of $4.8 million in the service and interest cost components and a $26.9 million increase in the accumulated postretirement benefit obligation. Significant assumptions used in determining the postretirement benefit obligation were:
The Company is recovering these costs in rates on an accrual basis in all material respects, in all jurisdictions. Current and future recoveries of OPEB accruals are expected to collect sufficient amounts to provide for the unfunded accumulated postretirement obligation over time. The funds being collected for OPEB accruals in rates, in excess of OPEB benefits actually paid during the year, are contributed to external benefit trusts under the Company's current funding policy. N. EARLY RETIREMENT AND VOLUNTARY SEPARATION PROGRAMS: During the first quarter of 1994, the Company offered an early retirement program to employees aged 50 or older and offered a voluntary separation program to all regular full-time employees. The offers under the program expired September 1,
1994. Approximately 1,400 employees accepted offers under these programs. The costs associated with these programs were $90.1 million. The Company capitalized $25.9 million based upon prior regulatory precedent and expensed $64.2 million. O. COMMITMENTS AND CONTINGENCIES: The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or the financial position of the Company. RATE MATTERS For information on the principal rate proceedings in which the Company was involved in 1994, see RATES under Item 1. BUSINESS. For information on the effect of rate changes see Results of Operations under Item 7. MANAGEMENT's DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION 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 to FINANCIAL STATEMENTS. CONSTRUCTION PROGRAM The Company has made substantial commitments in connection with its construction program and nuclear fuel expenditures. Those expenditures are estimated to total $673.2 million (excluding AFC) for 1995. Additional financing is contemplated in connection with this program. For more information see CAPITAL REQUIREMENTS under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. PURCHASED POWER CONTRACTS Since 1984, 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 75 non-utility purchase contracts with a combined dependable summer capacity of 3,506 Mw. Of these, 65 projects (aggregating 3,244 Mw) were operational as of the end of 1994 with the balance to become operational at various dates before 1997. The table below reflects the Company's minimum commitments as of December 31, 1994, for power purchases from utility and non-utility suppliers that are currently operating or have obtained construction financing.
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. Actual payments for purchased power (including economy, emergency, limited term, short-term and long-term purchases) for the years 1994, 1993 and 1992 were $1,025.0 million, $958.0 million and $766.0 million, respectively.
FUEL PURCHASE COMMITMENTS The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (millions): 1995 -- $351; 1996 -- $266; 1997 -- $153; 1998 -- $33; and 1999 -- $32. SALE OF POWER For information on the Company's commitment to sell power, see PURCHASES AND SALES OF POWER under SOURCES OF ENERGY USED AND FUEL COSTS, Item 1. BUSINESS. 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 remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemaking process; however, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely impacted. For additional information on environmental matters, see FUTURE ISSUES under Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. 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 $46.5 million to $134.6 million. The Company's proportionate share of the cost is expected to be in the range of $0.5 million to $6.7 million, based upon allocation formulas and the volume of waste shipped to the sites. As of December 31, 1994, the Company had provided for $1.4 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 and Dominion Resources along with Consolidated Natural Gas have remedial action responsibilities remaining at two coal tar sites. The Company provided a $2 million reserve to meet its estimated liability based on site studies and investigations performed at these sites. The Company generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 1994 any pending or possible claims were not recognized as an asset or offset against recorded obligations of the Company. WEST VIRGINIA AIR ACT For information see REGULATION under Item 1. BUSINESS. LEGAL PROCEEDINGS For information on legal proceedings see Item 3. LEGAL PROCEEDINGS. P. 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, pollution control project funds 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 and pollution control 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 pollution control notes: These notes have variable interest rates which are set so that fair value approximates carrying value. 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. Q. 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 the management for a fair statement of the results for the interim periods.
Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors. During the first quarter of 1994, the Company offered an early retirement program to employees aged 50 or older and offered a voluntary separation program to all regular full-time employees. The offers under the programs expired September 1, 1994. Approximately 1,400 employees accepted offers under these programs. The costs associated with these programs were $90.1 million. The Company capitalized $25.9 million based upon prior regulatory precedent and expensed $2.8 million, $10.4 million and $51 million during the second, third and fourth quarters, respectively. The impact of the write-off was to reduce Balance Available for Common Stock by $1.8 million, $6.7 million and $33.1 million for the second, third and fourth quarters, 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:
Each Director holds office until the next Annual Meeting of Shareholders or until his successor is duly elected.
(b) Information concerning the executive officers of Virginia Electric and Power Company is as follows:
There is no family relationship between any of the persons named in response to Item 10.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The Summary Table below includes compensation paid by the Company for services rendered in 1994, 1993 and 1992 for the Chief Executive Officer and the four other most highly compensated executive officers (as of December 31, 1994) as determined by total salary and incentive payments for 1994. SUMMARY COMPENSATION TABLE
(1) The Company does not maintain "bonus" plans which are used by some companies to supplement salaries based on the success of the company without regard to individual performance. However, the Company has in place various incentive plans that compensate officers and employees for achieving pre-determined specified performance goals. (2) Includes 1,118 shares of Restricted Stock and $51,540 in cash awarded on February 18, 1994 at the end of a three-year performance period. Dividends are paid on Restricted Stock. Restrictions on the shares of stock will lapse six months from the date of grant. As of December 31, 1993 no shares of Restricted Stock were held. (3) Company match on savings plan contribution ($7,075) and insurance premium to Directors Charitable Contribution Program ($10,058). (4) Includes 788 shares of Restricted Stock and $20,254 in cash awarded on February 19, 1993 at the end of a three-year performance period. Dividends are paid on Restricted Stock. Restrictions on the shares of stock lapsed six months from the date of grant. (5) Company match on savings plan contribution ($6,866) and insurance premium for Directors Charitable Contribution Program ($10,058). (6) Company match on savings plan contribution. (7) Retired December 31, 1994. (8) Company match on savings plan contribution ($4,500) and insurance premium to Directors Charitable Contribution Program ($10,058). (9) Company match on savings plan contribution ($4,500) retirement payment as provided by Company's Early Retirement and Voluntary Separation Program ($112,000) and payment at retirement for accrued vacation ($44,860).
LONG-TERM INCENTIVE COMPENSATION Long-term incentive awards made during 1994 are shown in the following table. LONG-TERM INCENTIVE PLANS -- AWARDS IN THE LAST FISCAL YEAR 1994-1996 PERFORMANCE ACHIEVEMENT PLAN
(1) Performance shares representing Dominion Resources Common Stock to be awarded at the end of Performance period. (2) Except for James T. Rhodes, payout of awards are tied to achieving levels of Virginia Power's return on equity (ROE) (50%) and meeting a cost per kilowatt-hour goal (50%). The threshold award will be earned if 81% of the ROE goal or 75% of the costs per kilowatt-hour goal is achieved. The target awards will be earned if the goals are fully achieved. The maximum award will be earned at 110% or more of the ROE goal and 112% of the cost goal. Targets and goals for James T. Rhodes were approved by the Dominion Resources Organization and Compensation Committee under the Dominion Resources Long-Term Incentive Plan. The award for James T. Rhodes will be paid out in shares of restricted stock based on the achievement of three specified goals over a three-year performance period (1994-1996), weighted as follows: a total return to Dominion Resources Shareholders superior to that of the S&P Utility Index (50%), utility return on equity equal to the average ROE achieved by a group of comparable utilities (25%), and restraint of utility costs to a growth rate less than that of the Consumer Price Index (25%). The target number of shares will be earned if all goals are fully achieved. The threshold amount will be earned if at least 71% of the total return goal, 81% of the ROE goal, and 75% of the cost control goal are achieved. The maximum amount will be earned if at least 114% of the total return goal, 110% of the ROE goal, and 112% of the cost control goal are achieved. RETIREMENT PLANS The table below sets forth the estimated annual straight life benefit that would be paid following retirement under the Dominion Resources, Inc. Retirement Plan's (the Retirement Plan) benefit formula.
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, contingent upon the officer reaching a specified age and remaining in the employ of the Company. For purposes of the above table, based on 1994 compensation, credited years of service (including any additional years earned in connection with the retirement agreements) for each of the individuals named in the cash compensation table would be as follows: James T. Rhodes: 23; John A. Ahladas: 29; Robert F. Hill: 30; Larry W. Ellis: 30 and Bill D. Johnson: 30. 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 Dominion Resources, Inc. Benefit Restoration Plan. The Company also provides an Executive Supplemental Retirement Plan (the Supplemental Plan) to its elected officers designated to participate by the Board of Directors. The Supplemental Plan provides an annual retirement benefit equal to 25 percent of a participant's final compensation (base pay plus annual incentive plan payments). The normal form of benefit is payable in equal 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. 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. In order to be entitled to benefits under the Supplemental Plan, an employee must be employed as an elected officer of the Company until death, disability or retirement. Based on 1994 compensation, the estimated annual retirement benefit for each of the executive officers under the Supplemental Plan would be as follows: James T. Rhodes: $160,290; John A. Ahladas: $72,500; Robert F. Hill: $79,025; Larry W. Ellis: $69,650; and Bill D. Johnson: $77,650. EMPLOYMENT AGREEMENTS The Company has entered into employment agreements (the Agreements) with its key management executives, including James T. Rhodes, John A. Ahladas, Robert F. Hill, Larry W. Ellis and Bill D. Johnson. Each Agreement has a three-year term and thereafter is automatically extended on its anniversary date for an additional year unless notified that the Agreement will not be extended by the Company. 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 voluntarily 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 cash incentive bonuses 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 or 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. James T. Rhodes has an employment agreement with Virginia Power, for a three-year period ending April 21, 1997. During the term of the agreement, if James T. Rhodes' employment as an officer of Virginia Power is terminated for any reason other than cause, James T. Rhodes will receive the amount that he would have otherwise received in base salary and incentive compensation. He will also receive a benefit equal to his then annual base salary or, at his election, the retirement and other benefits that he would have received as a participant in Virginia Power's 1994 early retirement program. Virginia Power's 1994 early retirement program provided five additional years of service and age credit for purposes of retirement benefits, a severance benefit equal to six months' salary, and continuation of certain benefits for a period of time. If James T. Rhodes remains in the employ of Virginia Power through April 21, 1997, he will receive a benefit when he later retires or otherwise terminates employment equal to his then annual base salary or, at his election, the retirement and other benefits that he would have received as a participant in Virginia Power's 1994 early retirement program. The payments under this agreement are provided in addition to any payments under James T. Rhodes' employment continuity agreement. Other officers (including Messrs. Ahladas, Hill, Ellis and Johnson) have similar agreements for a period ending June 21, 1997. In addition to the foregoing agreement, the Settlement Agreement dated as of August 15, 1994, among Dominion Resources, Virginia Power and the members of their Boards of Directors, provides that Virginia Power will make available to James T. Rhodes Virginia Power's 1994 Early Retirement Program for the three-year period beginning on August 24, 1994. Messrs.
Hill and Johnson had available to them agreements which provided for the Early Retirement Program if they continued employment to December 31, 1994. COMPENSATION OF DIRECTORS The non-employee members of the Board receive an annual retainer of $19,000 and a fee of $900 for each Board or committee meeting attended. Committee chairmen receive an additional annual retainer of $3,000. These Directors may elect to defer their annual retainer and/or their meeting fees under the Deferred Compensation Plan until they retire from the Board or otherwise direct. The deferred fees are credited, for bookkeeping purposes, with earnings and losses as if they were invested in either an interest bearing account or Dominion Resources Common Stock, depending on the Director's election. In addition, the Company makes payments to non-employee Directors or their designated beneficiaries upon those Directors' retirement, death or disability. Payments to a retired Director, including one who becomes disabled after retirement, are made for a period of four years, or for a period of years equal to the Director's service on the Board of the Company or one of its subsidiaries, whichever is longer. If a non-employee Director becomes disabled prior to retirement, these payments are made for four years. Each year, these payments equal the annual retainer in effect at the time the payments begin. Upon the death of a non-employee Director, the unpaid portion of these payments, up to a maximum of four times the annual amount due, is paid in a lump sum to the Director's designated beneficiary. DIRECTORS CHARITABLE CONTRIBUTION PROGRAM Dominion Resources administers a Directors' Charitable Contribution Program (the Program) for all its subsidiaries, including the Company, as part of its overall program of charitable giving. Beginning at the death of a Director a donation in an aggregate amount of $50,000 per year for 10 years will be made to one or more qualifying charitable organizations recommended by the individual Director. Life insurance policies have been purchased on the lives of the Directors in connection with the Program. These policies are owned by Dominion Resources, which is also the beneficiary. The Directors derive no financial or tax benefits from the Program. ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below sets forth as of January 31, 1995, except as noted, the number of shares of Common Stock of Dominion Resources owned by Directors and four other more highly compensated executive officers of Virginia Electric and Power Company.
(a) Represents shares the Directors have accumulated under the Deferred Compensation Plan. (b) Members of Mr. Roos' family are beneficiaries of trusts that own 3,818 shares of Common Stock for which he disclaims beneficial ownership. All Directors and executive officers as a group (34 persons) beneficially own, in the aggregate, 171,218 shares of Common Stock of Dominion Resources which includes 3,585 shares represented by options awarded and exercisable under Dominion Resources' Long-Term Incentive Plan. Beneficial ownership of 3,818 shares of the total are disclaimed. No shares of the Company's Preferred Stock are owned by the Directors or executive officers as a group.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS In October 1994, in connection with the Settlement Agreement that is summarized in the Company's Current Report on Form 8-K of August 17, 1994, Dominion Resources and Virginia Power paid $77,646 and $76,530, respectively, to a law firm that represented the following persons in connection with the corporate governance dispute that led to the execution of the Settlement Agreement: William W. Berry, James F. Betts, Bruce C. Gottwald, T. Justin Moore, Jr. and James T. Rhodes. Messrs. Berry and Betts and Dr. Rhodes were directors of Virginia Power at the time the legal expenses were incurred, and all of these persons were directors of Dominion Resources at that time. Dr. Rhodes is also President and Chief Executive Officer of Virginia Power.
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 19. 2. EXHIBITS
*Indicates management contract or compensatory plan or arrangement (b) Reports of Form 8-K Virginia Power filed a report on Form 8-K, dated December 5, 1994, reporting the release by the Staff of the Virginia State Corporation Commission (the Staff) of a report filed December 1, 1994 entitled "Staff Investigation of Corporate Relationships, Affiliate Arrangements, and Financial and Diversification Issues of Dominion Resources, Inc. and Virginia Power." Virginia Power filed a report on Form 8-K dated February 21, 1995, reporting the entry of a Consent Order by the Virginia State Corporation Commission (the Commission) on the joint motion of Dominion Resources, Virginia Power and the Staff and the withdrawal by Delegate Clinton Miller of certain legislation introduced by Delegate Miller in the 1995 Virginia General Assembly at the request of the Commission.
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: March 8, 1995 By JOHN B. ADAMS, JR. (JOHN B. ADAMS, JR., 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 and on March 8, 1995.