ML18151A548

Forwards Annual Rept to Securities & Exchange Commission on Form 10-K for 1992,comparative Statement of Income for Three Months Ended 921231 & 1991,internal Cash Flow Projection 1993 & Statement Ensuring Availability of Funds

ML18151A548
Person / Time
Site:	Surry, North Anna
Issue date:	12/31/1992
From:	Stewart W VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
93-152, NUDOCS 9304020286
Download: ML18151A548 (67)

Text

e VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 March 29, 1993 Director, Nuclear Reactor Regulation Serial No.93-152 United States Nuclear Regulatory Commission NURBP Washington, D. C. 20555 Docket Nos. 50-280 50-281 50-338 50-339 License Nos. DPR-32 DPR-37 NPF-4 NPF-7 Gentlemen:

VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 NORTH ANNA POWER STATION UNITS 1 AND 2 PRICE-ANDERSON ACT Pursuant to 10 CFR 140.21 (e) regarding guarantees of payment of deferred premiums, we are providing the following information:

1. Annual Report to Securities and Exchange Commission on Form 10-K for 1992.

2. Comparative Statement of Income for the three months ended December 31, 1992 and 1991.

3. Internal cash flow projection for calendar year 1993 with certification by officer of the Company.

4. Statement ensuring availability of funds for payment of retrospective premiums without curtailment of required nuclear construction expenditures.

In accordance with 10 CFR 140.7, we submitted a check to the NRC for $1,000 on December 1, 1992 , which is the minimum required premium for the period November 15, 1992, through November 14, 1993.

Very truly yours,

/l.~~

iv1 L>CeJ,;7<)

W. L. Stewart Senior Vice President - Nuclear Enclosures 020058

,,,--- 9304020286. 921231 .. * . I ! ~

, . PDR ADOCK 05000280 i

. I PDR 1

e cc: U. S. Nuclear Regulatory Commission Region II 101 Marietta Street, N. W.

Suite 2900 Atlanta, Georgia 30323 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D. C. 20555 Mr. M. W. Branch NRC Senior Resident Inspector Surry Power Station Mr. M. S. Lesser NRC Senior Resident Inspector North Anna Power Station

VIRGINIA ELECTRIC AND POWER COMPANY CERTIFICATE I, the undersigned B. D. Johnson, do herby certify, pursuant to the guarantee requirements set forth in the Commission's letter dated June 15, 1977, that the cash flow projection for 1993, provided herewith, is based on the best available information known at this time and is a reasonably accurate projection of the Company's 1993 cash flow.

B. o./Johnson Senior Vice /'resident-Finance, Controller, Treasurer and Corporate Secretary Commonwealth of Virginia City of Richmond Sworn to and subscribed before me this '""'day of P'l'°'4,1993.

~yttblic~

My commission expires: January 31, 1994 NOTARIAL SEAL

e Virginia Electric & Power Company 1993 Estimated Internal Cash Flow (Millions of Dollars)

Jan Apr Jul Oct Estimated thru thru thru thru 1993 Mar Jun Sep Dec Total Cash Receipts $1,101.2 $943.6 $1,131.5 $994.3 $4,170.6 Less:

Cash for Operations 596.0 587.2 586.2 603.3 2,372.7 Taxes 31.9 164.7 135.7 143.2 475.5 Interest 93.4 64.3 95.5 69.7 322.9 Dividends

- Preferred Stock 10.2 11.1 10.7 11.4 43.4

- Common Stock 94.6 93.8 93.3 95.6 377.3 Decommissioning Trust 6.1 6.1 6.1 6.0 24.3 Changes in Working Capital 183.1 (0.3) (0.3) (4.9) 177.6 Other .{12) .{12) .{12) .(12) (4.8)

Total Cash Flow (1) $87.1 $17.9 $205.5 $71.2 $381.7 (1) Before Financing and Construction Requirements.

e e VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF INCOME (Unaudited)

Three Months Ended December 31 1992 1991 Millions Operating revenues: $ 840.9 $ 885.7 Operating expenses:

Operation

- fuel used in current generation 120.5 126.6

- purchased power expenses-fuel 77 .1 76.2

-capacity 147.3 70.0

- deferred expenses-fuel 18.8 26.0

-capaci t.y (102. 7)

- other 114 .0 127.8 Maintenance 43.3 88.9 Depreciation and amortization 103.0 97.0 Amortization of terminated construction project costs 9.2 9.5 Taxes - Income 60.8 39.6

- Other 59.7 56.5 Total 651. 0 718.1 Operating income 189.9 167.6 Other income:

Allowance for other funds used during construction 1.3 0.9 Miscellaneous, net ( 5. 2) 7.4 Income taxes associated with miscellaneous, net 3.9 C2. 4)

Total 0.0 5.9 Income before interest charges 189.9 173.5 Interest charges:

Interest on long-term debt 73.1 79.9 Other ( 0. 2) 7.7 Allowance for borrowed funds used during construction (3.3) CO .4)

Total 69.6 87.2 Net income 120.3 86.3 Preferred dividends 11. 0 12.5 Balance available for Common Sto~k $ 109 .3 $ 73.8

e e VIRGINIA ELECTRIC AND POWER COMPANY STATEMENT The Company currently estimates 1993 construction and nuclear fuel expenditures (exclusive of Allowance for Funds Used During Construction) to be $844 million. Of this amount, it is expected that approximately $384 million will be obtained from internal sources. The remaining $460 million of construction requirements, as well as the $1 53 million of debt and preferred stock maturities and sinking fund requirements, will be obtained through a combination of sales of securities and short-term borrowings. The Company is reasonably assured that, based on the best available cash flow projections which are provided herewith, curtailment of capital expenditures for required nuclear programs would not be required to cover the Price-Anderson maximum retrospective premium assessment for a single incident of $264.6 million ($66.15 million for each of the four reactors owned by the Company with assessments not to exceed $10 million per reactor per year) currently in force.

SECUlJITls AND. EXCHANGE CO~ISSION WASHINGTON, D.C. 20549 Form 10-K (Mark One)

~ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year erided December 31, 1992 or 0

• TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

. SECURITIES EXC~NGE ACT OF 1934 For the transition period from _ _ _ _ _ _ to _ _ _ _ __

Commission file number 1-2255 VIRGINIA ELECTRIC AND. POWER COMPANY (Exact name of registrant as specified in its charter)

VIRGINIA 54-0418825 (State or other jurisdiction of (l.R.S. Employer incorporation or organization) identification no.)

One James River Plaza Richmond, Virginia 23261-6666 (Address of principal executive offices)

(Zip Code).

(804) 771-3000 (Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange Title of each class on which registered Preferred Stock (cumulative) New York Stock Exchange

$100 liquidation value:

$5.00 dividend

$7. 72 dividend

$7.45 dividend

$7 .20 dividend

$7.72 dividend (1972 Series)

Securities registered pursuant to Section 12(g) of the Act:

None (Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes V' No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best ofregistrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [,....]

• The aggregate market value of the voting stock held by non-affiliates of the registrant as of January 31, 1993 was zero.

As of January 31, 1993, there were issued and outstanding 166,109 shares of the registrant's common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc.

DOCUMENTS INCORPORATED BY REFERENCE.

None

e e VIRGINIA ELECTRIC AND POWER COMPANY Item Page Number Number PART I

1. Business . . . . . . .. _. . . . . . . . . . . . . . . . * * * * * * * * * * *

• The Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Capital Requirements and Financing Program . . 2 Construction and Nuclear Fuel Expenditures . . . . . . . . . . . . . . 2 Financing Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Rates. . . . . . . . . ..... 2 Virginia . . . . . . . 3 North Carolina .. . 4 County and Municipal Customers . . . 4 Governmental-Commonwealth of Virginia. 4 Federal Energy Regulatory Commission .. . 4 Governmental-Federal .......... . 5 Regulation. . . . . . . . . 5 General . . . . . . . 5 Environmental . 5 Nuclear . . . . . . . 6 Sources of Power . . 6 Company Generating Units 6 Utility Purchases . . . . . . 7 Non-Utility Generation ... 7 New Company Generation. 7 Sources of Energy Used and Fuel Costs . . 8 Nuclear Operations and Fuel Supply. 8 Fossil Fuel Supply . . . . . . . 8 Purchases and Sales of Power. . . . . . . . 8 Interconnections . . . . . . . . . . . . . . . . . . 9 Future Sources of Power . . . . 9 Company Owned Generation . . 10

. Non-Utility Generation . . . . . . 10 Competition. . . . . . . . . . . . . . 11 Conservation and Load Management . . 11

2. Properties . . . . . . . . . -. . . . . . . . . . . . . . . . . . . . . 11

3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . 11

4. Submission of Matters to a Vote of Security Holders. 12 PART II

5. Market for the Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . 12

6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . 13

7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . *. 13

8. Financial Statements and Supplementary Data. . . . . . . . . . . . . 21

9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . 48 PART III

10. Directors and Executive Officers of the Registrant. .. 48

11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . 51

12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . . 55

13. Certain Relationships and Related Transactions .. 55 PARTIV

14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

e PARTI 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-ownecl 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 Carolin.a Power in North Carolina. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives and municipal-ities. The Virginia service area comprises about 65 percent of Virginia's-total land area; butaccounts for over 80 percent ofits 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 pr~ctices and in confc;,rmity with applicable statutes, rules and regulations. Like other electric utilities, the Company's generating facilities are subject to unanticipated or extended oµtages for repairs, replacements or modifi.Gations 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 urider SOURCES OF ENERGY USED AND FUEL COSTS. . .

• . The Company had 12,034 full-time employees on December 31, 1992. 4,244 of the Company's employees are represented by the International Brotherhood of Electrical Workers under a contract extending to March 31, 1993. The Company considers its relations with its union and nonunion employees to be good. *

• 1

e e 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 1993-1995, total $2.4 billion. It has adopted a 1993 budget for construction and nuclear fuel expenditures as set forth below:

Estimated 1993 Expenditures (millions)

New Generating Facilities: ./

Clover Unit 1 and Unit 2 *.......................... . $115 Other Production .................................. . 312 General Support Facilities ............................ . 52 Transmission ..................................... . 62 Distribution ...................................... . 236 Nuclear Fuel ..................................... . 67 Total Construction Requirements and Nuclear Fuel, ...... . 844 AFC ....... -.................................... . 11 Total Expenditures ............................... . $855.

Financing Program In 1992, Virginia Power obtained $1.6 billion from the sale of securities. Its long-term financings included $1.1 billion of First and Refunding Mortgage Bonds, $60 million of unsecured Medium-Term Notes, $56 million of Pollution Control Revenue Bonds, $240 million of preferred stock, and $75 million of Common Stock sold to Dominion Resources. From the proceeds of the 1992 securities sales, the Company retired* $82.3 million of securities through mandatory debt maturities and sinking fund requirements and retired an additional $1.2 billion of debt through optional redemptions and sinking fund payments. 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 1993 construction requirements, exclusive of AFC and refundings, are estimated to be $844 million, as detailed above. Of this amount, it is expected that approximately $384 million will be obtained from internal sources. The remaining $460 million of construction requirements, as well as the $153 million of debt and preferred stock maturities and sinking fund requirements, 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 1992 as follows:

1992 Percent Percent of of Revenues Kwh Sales Virginia retail:

Non-Governmental customers ....... . Virginia Commission 79% 75%

Governmental customers.* .......... . Not regulated (negotiated agreements) 11 13 North Carolina retail .............. *.. North Carolina Commission. 5 4 Wholesale ....................... . Federal Energy Regulatory Commission (FERC) 5 8 100% 100%

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e e . .

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 1992 are described below by jurisdiction. Rate relief obtained by the Company is frequently less than requested.

Virginia As a result of the reversal by the Virginia Supreme Court of the Virginia Commission's Final. Order in the Company's 1990 rate proceeding, which approved a rate increase of $79.8 million, the Company refunded $26 million to Virginia retail customers prior to September 1, 1992.

In the Company's 1991 expedited rate proceeding, which ultimately sought an increase in annual revenues of $158.6 million, the Virginia Commission approved an increase of $45.2 million on December 29, 1992. It denied current recovery of $67 .6 million of projected capacity charges associated with power purchases in that case, but it authorized deferral accounting for such charges with future dollar for dollar recovery of capacity purchases found to have been reasonably incurred. Refunds of

$188.9 million will be completed during the first quarter of 1993.

On May 29, 1992, the Company filed with the Virginia Commission an Application for a general rate increase of $165.9 million over the revenues that were then in effect, subject to refund, in the 1991 rate case. On October 9, 1992, at the Company's request, the Commission directed that consideration of proposed revisions to the Company's line extension policy and certain other tariff provisions, for which-the Company had filed an application on February 14, 1992, be transferred to this rate proceeding. On October 26, 1992, the Hearing Examiner denied a consumer advocate's Motion that the Company's application be found to be incomplete, and the increase took effect, subject to refund, on October 27, 1992.

The Commission's December 29, 1992 Final Order in the 1991 rate case necessitated certain changes in the 1992 case, and supplemental testimony reflecting those changes was filed by the Company .on January 15, 1993. Those changes did not alter either the total revenues or the specific rates sought in the 1992 Application, but they caused the increased revenues sought in that Application-which were $165.9 million above the interim rates in the 1991 rate case-to be $331.6 million above the rates finally approved by the Commission in that case. Testimony of other parties is to be filed in February, and the case is scheduled for an evidentiary hearing beginning March 22, 1993.

On August 19, 1992, the Company instituted a proceeding before the Virginia Commission seeking a review and modification of certain provisions of the rate schedule that governs payments to cogenerators and small power producers providing 3,000 Kw or less of dependable capacity, and it subsequently requested that the schedule be limited to projects of 100 Kw or less. The Company believes that the rate schedule provides substantial overcompensation to such cogenerators and small power producers if they operate for only a limited number of hours each year, and it has proposed contractual terms to ameliorate the consequences of such limited operations. On February 17, 1993, the Virginia Commission issued its Final Order in which it agreed with the Company and found that new contracts with small power producers or cogenerators must include a refund formula that will assure that the. Company avoids excessive payments under the rate schedule. The Company was further directed to limit the applicability of the rate schedule to facilities with a maximum design capacity of 100 Kw until further. consideration of that issue in the next proceeding to be filed on March 31, 1993; provided, however, that the small power producers and cogenerators that had submitted offers to the Company on or before October 30, 1992 may obtain contracts for facilities with a design capacity of up to 3,000 Kw.

3

e e On September 15, 1992, the Company filed with the Virginia Commission an application to revise its fuel factor to effect an annual reduction of $78 .1 million from the previously approved level of fuel cost recovery. On October 23, 1992, the Commission approved the application and the reduction went into effect on October 27, 1992.

Rules On December 13, 1991, the Virginia Commission instituted a proceeding to consider new rules governing rate case filings. If adopted as proposed, these rules would, among other things, eliminate the distinction between expedited and general rate cases, fix the suspension period for all rate cases at 60 days, and allow ratemaking adjustments based on projections of revenues, expenses and rate base during the first year the rates would be in effect. Comments on the proposed rules were filed on April 6, 1992. Most utilities filed comments strongly supporting the proposed rules, while consumer advocates strongly opposed them.

On January 21, 1992, the Virginia Commission instituted a proceeding to consider rules concerning the proper ratemaking treatment to be accorded postretirement benefits other than pensions in light of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (OPEB), which requires such benefits to be accounted for on an accrual basis. On December 30, 1992, the Virginia Commission entered its Final Order in which it approved the accrual of expenses for postretirement benefits other than pensions for rate making purposes. The Order permits recovery of OPEB cost accruals in rates if those accruals are fully funded. The Commission required that the transition obligation for such expenses that are not capitalized be amortized over a 40-year period. On January 21, 1993, the Commission entered an Order denying reconsideration of the 40-year amortization which had been requested by other parties. The effect of the Order is not expected to have a significant impact on the Company's financial statements or results of operations.

North Carolina On July 31, 1992, the Company filed with the North Carolina Commission an application for a base rate increase. On September 11, 1992, the Company filed an application for a fuel rate decrease. At the hearing on the combined applications, the Company requested a base rate increase of $17.4 million and a fuel rate decrease of $3.4 million. The hearing concluded on January 20, 1993. New rates will go into effect on March 1, 1993 and an order is expected by that date.

County and Municipal Customers On December 31, 1991, Virginia Power reached agreement on the terms of a three-year contract governing retail rates for county and municipal customers in Virginia, which will continue through June 30, 1994. Pursuant to this contract an increase of $9.7 million became effective July 1, 1992. An additional increase of $6.8 million will become effective on July 1, 1993.

Governmental-Commonwealth of Virginia Governmental base rates for the Commonwealth of Virginia are unregulated but follow the methodology approved by the Virginia Commission for jurisdictional base rates. Based upon the June 2, 1992 Order in the remand proceeding, approximately $0.3 million was refunded. On October 27, 1992, an increase of$3.0 million was placed into effect based upon the ratemaking methodology in the general rate case filed in Virginia on May 29, 1992.

Federal Energy Regulatory Commission On July 31, 1991, the Company filed with FERC an application for a rate increase of $17.4 million, proposed to be effective on October 1, 1991, from the Company's wholesale customers. FERC suspended the rate increase for the five-month statutory period until March 1, 1992. On June 22, 1992, FERC issued a Letter Order approving an annual rate increase of $8.75 million, effective March 1, 1992, and an additional $0.6 million annual increase, effective January 1, 1993 to reflect other postretirement benefits (OPEB) in rates.

4 L

e e Governmental-Federal Rates for federal governmental customers are unregulated but follow the ratemaking methodology approved by FERC for the Company's resale service to municipalities. Based on the approved settlement, the annual increase to federal governmental customers was $6.3 million, effective March l, 1992, with an additional $0.4 million becoming effective January 1, 1993 to reflect OPEB in rates.

REGULATION General In a wide variety of matters in addition to rates, the Company 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.

The Energy Policy Act of 1992 (Energy Act) is the first comprehensive federal energy legislation enacted in over a decade and will have far reaching impacts on all electric utilities, including the Company. In particular, the Energy Act will encourage the development of a new category of "exempt wholesale generators" certified as such by FERC that will be exempt from the provisions of the Public Utility Holding Company Act(PUHCA). It also gives FERC extensive new authority to order utilities to provide other parties with access to their transmission systems.

The Energy Act also requires domestic utilities with nuclear facilities to fund the clean-up of the DOE's gaseous diffusion plants which have provided nuclear enrichment services to the industry. In December 1992, the Company recorded a liability and corresponding regulatory asset of $90 million for its portion of the clean-up. As mandated in the Energy Act, the Company anticipates that it will recover these costs through rates.

Various other provisions of the Energy Act that could affect the Company include those 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. Many provisions of the Energy Act must be implemented by regulations that have not yet been enacted. These regulations may affect electric utilities. Therefore, while the full impact of the Energy Act on the Company cannot at this time be quantified it may, over time, 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 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 (ti) 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 5

e e 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 additional expenditures, the amount of which is not presently determinable but which could be significant, in constructing new facilities or in modifying existing facilities.

In November 1990, the President signed Air Act amendments. These amendments will require the Company to reduce sulfur dioxide and nitrogen oxides emissions in two phases. The Company's emissions of sulfur dioxide and nitrogen oxides are relatively low in comparison to many other electric utilities. Nevertheless, the cost impact on the Company to comply with the amendments will be significant. The Company anticipates having to install emission monitoring equipment and has entered into an agreement for the installation of a scrubber at its Mt. Storm Power Station to be operational by January 1, 1995. The scrubber is expected to cost approximately $140 million. The Company will probably need to install two additional scrubbers to meet standards for the second phase. Full compliance with both phases must be achieved no later than January 1, 2000. The capital cost for compliance with both phases, assuming the installation of three scrubbers, nitrogen oxide controls and emission monitoring instrumentation, is estimated at $481 million (1992 dollars). Annual incremental compliance costs for operation, maintenance and fuel costs are estimated to be $128 million.

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 substantal increases in the cost of operating and maintaining the Company's nuclear generating units.

SOURCES OF POWER Company Generating Units Type Summer Years of Capability Name of Station, Units and Location Installed Fuel Mw Nuclear:

Surry Units 1 & 2, Surry, Va ................. . 1972-73 Nuclear 1,562 North Anna Units 1 & 2, Mineral, Va ........... . 1978-80 Nuclear l,757(a)

Total nuclear stations ..................... . 3,319 Fossil Fuel:

Steam:

Bremo Units 3 & 4, Bremo Bluff, Va ......... . 1950-58 Coal 227 Chesterfield Units 3-6, Chester, Va ........... . 1952-69 Coal 1,250 Mt. Storm Units 1-3, Mt. Storm, W. Va ....... . 1965-73 Coal 1,596 6

e Type Summer Years of Capability Name of Station, Units and Location Installed Fuel Mw Chesapeake Units 1-4, Chesapeake, Va ........ . 1953-62 Coal 595 Possum Point Units 3 & 4, Dumfries, Va ....... . 1955-62 Coal 322 Yorktown Units 1 & 2, Yorktown, Va ......... . 1957-59 Coal 326 Possum Point Units 1, 2, & 5, Dumfries, Va .... . 1948-75 Oil & Gas 929 Yorktown Unit 3, Yorktown, Va ............. . 1974 Oil & Gas 818 Combustion Turbines:

35 units (8 locations) ...................... . 1967-90 Oil & Gas 1,019 Combined Cycle:

Chesterfield Units 7 & 8, Chester, Va ......... . 1990-92 Oil & Gas 397 Total fossil stations ..................... . 7,479 Hydroelectric:

Gaston Units 1-4, Roanoke Rapids, N.C ....... . 1963 Conventional 225 Roanoke Rapids Units 1-4, Roanoke Rapids, N.C .. 1955 Conventional 104 Other ................................. . 1930-87 Conventional 3 Bath County Units 1-6 .................... . 1985 Pumped Storage l,260(b)

Total hydro stations ..................... . 1,592 Total Company generating unit capability ..... . 12,390 Utility Purchases. . . . . . . . . . . . . . ............... . 1,030 Non-Utility Generation . . . . . . . . . . . . . . . . . . . . . . . . . 2,833 Total Capability ........................ . 16,253 (a) Includes an undivided interest of 11.6 percent (204 Mw) owned by Old Dominion Electric Cooperative (ODEC) and a temporary reduction of 63 Mw for Unit 1 resulting from increased steam generator tube plugging. Unit 1 will be re-rated upon completion of steam generator replacement.

(b) Includes only the Company's 60 percent undivided 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 12,942 Mw established on July 14, 1992, and the highest one-hour integrated winter peak demand was 12,697 Mw established on December 22, 1989.

New Company Generation On May 31, 1992, the Company's second combined-cycle unit, Chesterfield Unit 8, was placed in commercial operation. This unit will provide 200 Mw of summer capability and 235 Mw of winter capability.

For financial data as to the property, plant and equipment of the Company, see Schedule V to FINANCIAL STATEMENTS.

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e e 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 CONDI-TION AND RESULTS OF OPERATIONS.

Nuclear Operations and Fuel Supply In 1992, the Company's four nuclear units achieved a combined capacity factor of 79.7 percent.

On December 23, 1991, North Anna Unit 1 was shut down for a mid-cycle steam generator inspection and maintenance outage. Following an extensive examination of the steam generators and plugging of defective tubes, the unit was restarted with NRC approval, on March 5, 1992. The unit operated continuously through the remainder of the cycle, with maximum power limited to 95%, due to the increased tube plugging levels. The Company had planned to replace the steam generators at North Anna Unit 1 in the second half of 1995. As a result of the information.obtained during the refueling outage in early 1991, the Company decided to advance the steam generators replacement to January 1993. On January 4, 1993, the replacement of the steam generators commenced and is estimated to cost approx:imately $126 million and take approximately 150 days to complete.

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 market conditions in order to obtain adequate nuclear fuel supply. Current agreements, inventories and market conditions will support planned fuel cycles into the mid-1990s.

On-site spent nuclear fuel storage is adequate for the Company's needs through 1998, when as required by law, spent nudear fuel storage is to be provided for nuclear reactor licensees by the DOE.

If DOE is unable to accept spent fuel by 1998, an interim storage facility may be required for the Company's North Anna Power Station in the late 1990s.

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 1992, Virginia Power consumed**approximately 10.2 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 at least into the mid-1990s. Current projections for th~ 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 for gas indicate supplies will be available for the next several years.

Purchases and Sales of Power Virginia Power relies on purchases of power to meet an increasing amount 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 annua:lly through 1999 from Hoosier Energy Rural Electric Cooperative, Inc., and agreed to purchase 8

e e 500 Mw of electricity annually during 1987-99 from certain operating subsidiaries of American Electric Power Company, Inc. (AEP).

On September 9, 1991, the Company and South Carolina Public Service Authority (SCPSA) signed an agreement whereby the Company will sell limited-term power to SCPSA during nine months in 1993 and nine months in 1994. The capacity to be purchased by SCPSA ranges from 50 Mw to 75 Mw in 1993 and from 100 Mw to 200 Mw in 1994.

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 June 1995) or December 31, 1995, whichever occurs first. The Company will also 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 June 1996) or December 31, 1996, whichever occurs first.

In 1991, the Company activated a diversity exchange agreement with APS to realize seasonal system operating efficiencies between the companies tvvo systems. Beginning in June 1993. and continuing until August 1993, APS will deliver 200 Mw to Virginia Power. Beginning in December 1993 and continuing until February 1994, the Company will deliver 200 Mw to APS. The Company anticipates this diversity transaction will continue on a seasonal basis for a number of years.

In June 1992, Virginia Power and C~rolina Power and Light Company (CP&L) completed a limited term power sales agreement. Under the terms of the agreement, the Company provided 200 Mw of peaking capacity for the months of July and August 1992.

• Virginia Power also has 87 non-utility power purchase contracts with a combined dependable summer capacity of 3,634 Mw. Of this amount, 2,833 Mw were operational at the end of 1992 with the balance scheduled to come on-line through 1997 (see Non-Utility Generation under FUTURE SOURCES OF POWER and Note M to FINANCIAL STATEMENTS).

INTERCONNECTIONS The Company maintains major interconnections with CP&L, 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 (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 110 miles of 765 Kv and 102 miles of 500 Kv lines. Completion of the project will take three to four years after all final regulatory approvals have been obtained. On July 16, 1992, the Commission completed its hearing on the Company's portion of the project but no decision has been entered.

FUTURE SOURCES OF POWER The Company presently anticipates that system load growth will require approximately 2,064 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 CONSER-VATION AND LOAD MANAGEMENT below).

In 1987, the Company signed agreements for the purchase of approximately 1,300 Mw of additional capacity from six non-utility power producers all of which are operational except one 14 Mw project that was terminated in February 1992. In 1988, as a result of a competitive bidding solicitation, the Company 9

e e entered into 19 contracts for approximately 2,000 Mw of additional capacity for initial delivery at various dates through 1994. Seven of these contracts totalling 746 Mw have subsequently been terminated. The Company also issued a Request for Proposals in August 1989 for competitive bids for up to an additional 1,100 Mw of power to come on-line during 1995-1997. Contracts were executed with three developers in July 1990 for capacity totalling 448 Mw. One 210 Mw project was later terminated.

The contracts from all three solicitations are generally for a duration of 25 years after the commence-ment of commercial operation. The projects cover a variety of technologies, fuel supplies, pricing mechanisms, and in-service dates. Each agreement for the purchase of power contains liquidated damage provisions that may be exercised if the electricity is not available as scheduled. The Company has also developed a contingency plan to meet the demand for pow~r in the event that the growth in demand exceeds present forecasts or in the event of a failure of any of these power purchase agreements. See Note M to FINANCIAL STATEMENTS.

Several non-utility power producers with whom the Company has executed power purchase agreements have not obtained air permits necessary for the construction of the generating facilities. Any delay in obtaining the necessary air permits may cause delays in the in-service dates of this additional capacity. The Company anticipates that there will be alternative energy sources in the event that any of these generating facilities are significanHy delayed.

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 th~ Clover Power Station after it is completed. The cost of the Company's 50 percent ownership interest is expected to be approximately $554 million. At the time the Company executed the agreement with ODEC, on-site construction of the first unit was expected to begin in September 1990 and on-site construction of the second unit was expected to begin one year later. On April 29, 1991, the Virginia Air Pollution Control Board issued the environmental permit regulating emissions into the air for the facility. The issuance of that permit was, however, appealed to the EPA by certain interest groups and denied on January 29, 1992. On January 31, 1992, the Company and ODEC directed the construction contractor to begin permanent on-site construction of the facility. At year end the project is on schedule and the Company's share of costs amount to $289 million. Construction on Unit 1 is presently 32% complete and construction on Unit 2 is 9% complete. See Note E to FINANCIAL STATEMENTS.

The Company's continuing program to meet future capacity requirements is summarized in the following table:

Company Owned Generation Summer Capability Expected Name of Units Mw In-Service Date Clover Power Station:

Unit 1 391* June 1995 Unit 2 391* June 1996

• Includes the 50 percent undivided ownership interest of ODEC. See Note E to FINANCIAL STATEMENTS.

Non-Utility Generation Number of Projects Mw Projects Operational 52 2,833 Projects Financed 7 221 U nfinanced Projects 28 580 Total Contracts 87 3,634 10

e e 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 (see Competition under MANAGEMENT'S DISCUS-SION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS). 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.

CONSERVATION AND LOAD MANAGEMENT The Company is committed to least-cost 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.

On March 27, 1992, the Virginia Commission entered its Final Order in a proceeding to consider rules and Commission policy regarding conservation and load management programs of electric utilities.

The rules adopted by the Virginia Commission are generally consistent with the position taken by the Company in that proceeding.

The Company's least-cost planning process was the subject of a North Carolina Commission hearing that concluded on December 8, 1992. Prior to the hearirig, the Company entered into a stipulation with the North Carolina Public Staff that defines the objectives of least-cost planning and activities necessary to accomplish those objectives. A decision is pending.

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 K v 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 G to FINANCIAL STATE-MENTS.

See Company Generating Units under Sources of Power under BUSINESS and Schedule V of the FINANCIAL STATEMENTS.

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 11

e e are no material agency enforcement actions or citizen suits pending or, to the Company's present knowledge, threatened against the Company.

On August 3, 1992, Doswell Limited Partnership filed a Petition for Declaratory Order with FERC to resolve a dispute between it and the Company as to the determination of the compensation that the Company is to pay Doswell for capacity purchases under a Power Purchase Agreement between the parties. The dispute centers on what portion of the cost of a gas pipeline constructed by the Company (estimated to be $13.3 million) should be included in the calculation of a Fixed Fuel Transportadon Charge to be paid to Doswell. The Company believes that the proper amount to be included in the calculation is 44% of the cost of the pipeline, while Doswell asserts that 100% of that cost must be included. Subsequent pleadings have been filed by both parties. On November 4, 1992, FERC entered an order in which it disclaimed jurisdiction over Doswell's petition and dismissed its complaint. Both the Company and Doswell have asked FERC to reconsider this order and to take jurisdiction and decide the issue. On February 17, 1993, FERC issued an Order denying the motions for reconsideration.

The Power Company is involved in three arbitration proceedings before the Virginia Commission involving a total of 667 Mw of cogeneration capacity. In two cases developers are seeking to require the Company to purchase an aggregate of 502 Mw, and in the third case the developer is seeking to displace 165 Mw of the Company's sales to ODEC.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None PART II 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 1992 and 1991, the Company paid quarterly cash dividends on its Common Stock as follows:

1st 2nd 3rd 4th (Millions) 1992 $90.5 $91.5 $92.2 $95.6 1991 $85.2 $85.6 $86.2 $89.9 12

e e ITEM 6. SELECTED FINANCIAL DATA 1992 1991 1990 1989 1988 (Millions, except percentages)

Operating revenues .............. . $ 3,679.6 $ 3,688.1 $ 3,461.5 $ 3,458.9 $3,097.6 Operating income ............... . 761.6 816.8 805.8 759.0 736.9 Income before cumulative effect of a change in accounting principle ..... 455.2 487.4 450.3 435.5 460.1 Cumulative effect of a change in accounting principle ............ . 14.3 Net income .................... . 469.5 487.4 450.3 435.5 460.1 Balance available for Common Stock .. 423.8 435.9 392.2 375.2 407.0 Total assets .................... . 11,316.7 10,205.0 10,105.4 10,085.5 9,495.2 Total net utility plant ............ . 9,254.7 9,064.6 8,830.8 8,497.9 7,997.7 Long-term debt, noncurrent capital lease obligations and preferred stock subject to mandatory redemp-tion ........................ . 4,089.5 4,119.9 4,146.8 4,331.0 4,088.6 Utility plant expenditures (including nuclear fuel) ....... : ......... . 716.5 727.8 803.4 904.8 806.7 Capitalization ratios (percent):

Debt ....................... . 46.3 47.4 49.1 51.1 50.6 Preferred stock ............... . 9.7 9.0 9.4 9.9 9.9 Common equity ............... . 44.0 43.6 41.5 39.0 39.5 Embedded cost (percent):

Long-term debt ........ *....... . 7.86 8.43 8.80 8.86 8.69 Preferred stock ............... . 5.38 6.54 7.40 7.75 7.57 Weighted average ............. . 7.42 8.11 8.57 8.67 8.50 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, 73 percent of the Company's cash requirements over the past three years. As detailed in the Statements of Cash Flows, cash flow from operating activities was affected by a number of factors.

Net cash provided by operating activities increased $96.4 million in 1992 as compared to 1991.

Among other factors, cash flow was affected by an increase in the provision for rate refunds offset in part by the impact of capacity expense deferrals.

Net cash provided by operating activities in 1991 decreased $11.1 million as compared to 1990.

Among other factors, cash flow was affected by the change in sale of accounts receivable and the change in the balance of material and supplies.

13

e e Cash from (to) financing activities was as follows:

1992 1991 1990 (Millions)

Common Stock ............................. . $ 75.0 $ 150.0 $ 200.0 Preferred stock ............................. . 240.0 Mortgage bonds ............................ . 1,125.0 100.0 200.0 Medium-term notes .......................... . 60.0 199.4 Tax-exempt securities ........................ . 56.0 Repayment of long-term debt and preferred stock .... . (1,315.0) (410.4) (224.5)

Dividends .................................. . (416.1) (397.1) (385.8)

Other .................................... . (154.3) (0.6) (95.2)

Total .................................. . $ (329.4) $(358.7) $(305.5)

During 1992, the Company took advantage of lower interest rates and sold $1.1 billion of First and Refunding Mortgage Bonds, with interest rates ranging from 6.25 percent to 8 percent. With the proceeds from the sale, the Company redeemed $1.1 billion of its higher-cost debt (which represented more than 40 percent of its outstanding mortgage bond portfolio at the end of 1991) with interest rates ranging from 7.75 percent to 10.25 percent. This refinancing is expected to save about $7.4 million annually beginning in 1993. These transactions, among other factors, had the effect of lowering the Company's embedded cost of debt from 8.43 percent to 7.86 percent in 1992.

In August 1992, the Company issued $140 million of preferred stock with an annual dividend rate of $6.35 per share. With the proceeds from this sale, the Company redeemed $133.7 million of higher-cost preferred stock having annual dividend rates ranging from $8.20 to $8.925 per share. The Company also issued $100 million of adjustable rate preferred stock in September 1992.

The Company established a commercial paper program in 1992, that provides an additional source of borrowing in lieu of borrowing through the Inter-Company Credit Agreement with Dominion Resources. Proceeds from the sale of commercial paper are primarily used to finance working capital for operations. Borrowings under this program are limited to $200 million outstanding at any one time. The Company had $49.5 million outstanding under its commercial paper program at December 31, 1992.

In October 1987, Virginia Power Fuel Corporation, a wholly-owned subsidiary of the Company, entered into a four-year stand-by revolving credit agreement. This agreement, which was extended, supported up to $200 million of commercial paper to finance the purchase of nuclear fuel used at the Company's Surry Power Station. The Agreement was extended to October 9, 1992 and subsequently terminated.

In November 1992, the Company issued $56 million of tax-exempt securities. The proceeds will be used to finance the Company's portion of the acquisition, construction and installation of certain solid waste disposal facilities at the Clover Power Station.

In December 1992, the Company issued to Dominion Resources $75 million of Common Stock and issued $60 million of Medium-Term Notes.

Cash from (used in) investing activities was as follows:

1992 1991 1990 (Millions)

Utility plant expenditures ..................... . $(662.2) $(663.7) $(728.8)

Nuclear fuel ............................... . (54.3) (64.1) (74.6)

Nuclear decommissioning trust funds ............. . (24.3) (18.5) (21.0)

Pollution control project funds .................. . (55.3) 1.0 34.5 Other ........ * ............................ . (5.5) 27.2 7.0 Total .................................. . $(801.6) $(718.1) $(782.9) 14

e e Investing activities in 1992 resulted in a net cash outflow of $801.6 million primarily due to $662.2 million of construction expenditures and $54.3 million of nuclear fuel expenditures. Of the construction expenditures, approximately $155.2 millioH was spent on new generating facilities, $182.3 million on production projects, and $265.3 million on transmission and distribution projects. Construction expenditures continued to decline due to the economic recession and the cost-cutting measures implemented by management. The Company expects to continue to benefit from these cost-cutting measures in the future.

Capital Requirements The Company presently anticipates that kilowatt-hour sales will grow about 2.2 percent per year and peak demand will grow approximately 2.0 percent a year through 2012. Capacity needed to support this growth will be provided through a combination of Company-constructed generating units and purchases from non-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 1993, 1994 and 1995 are expected to aggregate $844 million, $723 million and $761 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 (For additional information, see Future Sources of Power under Item 1. BUSINESS and Note E to FINANCIAL STATEMENTS.) The Company's share of the cost of the construction is approximately $554 million of which $289.3 million had been incurred as of December 31, 1992. The expected in-service dates for Clover Units 1 and 2 are June 1995 and June 1996, respectively. The Company does not foresee the need for additional construction to meet anticipated demand through 1998. From 1999 until 2001, the Company will need to add only peaking units to meet anticipated demand.

The Company will require $136.7 million to meet long-term debt maturities and $16.3 million for sinking fund payments in 1993. The Company presently estimates that, for 1993, 45 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 combina-tion of sales of securities and short-term borrowings .

• The timing of future issuances and redemptions and the mix of debt and equity securities will depend not only on market conditions and the Company's needs but also on maintenance of adequate earnings and the Company's ability to maintain its credit ratings ..

Results of Operations The following is a discussion of results of operations for the years ended 1992 as compared to 1991, and 1991 as compared to 1990.

15

e e 1992 Compared to 1991

• Operating revenues changed principally due to the following:

Increase (Decrease) From Prior Year 1992 1991 1990 (Millions)

Kwh sales ......... *...................... . $ 53.5 $195.7 $(80.3)

Change in base rates ............ : .......... . (37.8) 74.7

• 92.0 Fuel cost recovery ........................ *. (20.4). (46.9) (11.5)

Other, net .................... '. .......... .

(3.7) 3.1 . 2A

• Total '................ *................ . $ (8.4) $226.6 $ 2.6 Operating revenues were $8.4 million lower in 1992 *primarily as .a result of the refund of $22.7 million in the Virginia 1990 rate case resulting from the Virginia Supreme Court ruling and reductions in fuel revenues effective September 1991 and October 1992. These decreases were partially offset by an increase in unit sales.

During 1992, the Company had 39,807 new connections to its system compared to 40,643 and 52,961 in 1991 and 1990, respectively. The decline in new connections is primarily due to the. economic recession and its effect on the Company's service territory,

• Total unit sales increased or decreased by customer class as follows:

Increase (Decrease) From Prior Year i992 1991 1990 Residential ................................

(1.8)% 6.7% (5.2)%

Commercial .................* .- ............

• 1.1 4.3 1.4 Industrial ..... *.......................... . 1.5 2.7 (0.8)

Public authorities * .......................... . 0.6 3.6 0.4 Total retail sales ........................... . 0.1 4.8 (1..6)

Resale .. *.... *............... *............ . 20.5 45.6 (9.5)

. Total sales ... *................ * ............ *.. 1.0 6.8 (2.0) .

The decrease in residential sales reflects the moderate weather in 1992 as compared to the warmer

• weather in 1991. The summer of 1992 was the coolest*in the last twenty years. The number of actual cooling degree days in 1992 was 6 percent below the number of normal cooling degree days and the nu01:ber of actual heating degree days was 2.5 percent below the number of normal heating degre<? days.

Additional capacity became available during 1992 due to the lower than anticipated retail sales a

resulting froni moderate weather. The Company was able to sell portion of this capacity which resulted in increased sales for resale as compared to 1991.

In addition, sales for resale increased in 1991 compared to 1990 due to the issuance of FER~ Order No. 529. The Company implemented the provisions of FERC Order 529 in 1991, which requires the Company to record the sale of power to other utilities as revenues. Prior to' this order, the Company recorded such sales as a credit to purchased power expenses.

16

e e The average fuel cost of system energy output is shown below:

Mills Per Kilowatt-hour 1992 1991 1990 Nuclear ................................ . 4.67 5.69 5.08 Coal .................................... . 14.87 15.00 15.29 Oil .................................... . 26.61 31.20 35.51 Purchased power, net .. *.................... . 25.94 25.38 26.40 Other ................................... . 24.45 16.46 24.93 Average fuel cost .......................... . 13.84 13.93 13.66 System energy output is shown below:

Estimated Actual 1993 1992 1991 1990 Nuclear(*) ......................... . 26% 35% 36% 38%

Coal .... *......................... . 42 41 42 40 Oil .......................... ; ... . 1 2 3 2 Purchased power, net ................ . 26 19 17 18 Other ...................... *...... . 5 3 2 2 100% 100% 100% 100%

(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power Station (see Note E to FINANCIAL STATEMENTS). .

Purchased power expenses-fuel and purchased power expenses-capacity increased as compared to 1991 primarily due to an increase in non-utility generation (NUG) purchases. Thirteen projects, with a summer capability of 1,514 Mw, became operational during 1992.

Deferred expenses-fuel, decreased as a result of a lower recovery of fuel expenses subject to deferral accounting in 1992 as compared to 1991.

Deferred expenses-capacity resulted in a decrease to expense as a result of the establishment of a regulatory asset of $102. 7 million due to the implementation of deferral accounting for certain capacity expenses. For additional information on the deferral of capacity expenses, see Note A to FINANCIAL STATEMENTS.

Miscellaneous net decreased as compared to 1991 primarily as a result of the reclassification of costs associated with the sale .of accounts receivable from other operation expenses.

Interest on long-term debt decreased as compared to 1991 primarily as a result of the redemption of certain debt, which was replaced by the issuance of lower-cost debt and lower interest on variable rate debt..

Change in Accounting Principle In 1992, the Company adopted the provisions of Statement of Financial Accounting Standards (SF AS) No. 109, Accounting for Income Taxes. The Company is reporting 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 million and resulted in the establishment of a net regulatory asset of $459 million. For additional information, see Note A to FINANCIAL STATEMENTS.

SPAS No. 107, "Disclosure about Fair Value of Financial Instrnments" requires disclosures about fair value for all financial instrnments, whether recognized or not recognized in the statement of financial position. These disclosures are included in the Notes to FINANCIAL STATEMENTS.

17

1991 Compared to 1990 Operating revenues were $226.6 million higher as compared to 1990 primarily as a result of the increase in unit sales attributable primarily to warmer weather in 1991. Base revenues were higher due to an increase in base rates effective May 1, 1990 and a base rate increase effective September 1, 1991',

subject to refund. Fuel cost recovery decreased as a result of the reduction in the fuel factor effective November 1, 1990 and another reduction effective September 15, 1991.

Fuel used in current generation increased as compared to 1990 primarily due to increased sales resulting in a more expensive system energy output.

Purchased power expenses-fuel and purchased power expenses-capacity increased as compared to 1990 primarily due to an increase in NUG purchases. Three projects, with a summer capability of 237 Mw became operational during 1991.

Deferred expenses-fuel decreased as compared to 1990 primarily as a result of a lower level of recovery in 1991 of previously deferred fuel expenses as compared to the rates in effect for 1990, offset in part, by an over-recovery in 1991 of current fuel expenses subject to deferral.

Other operation expenses increased primarily as a result of increased advertising, fees associated with the sale of accounts receivable, an increase in the pension accrual, increased benefit plan costs and increased nuclear regulatory commission licensing fees.

Other taxes-operating increased as compared to 1990 primarily due to a change in law which had the effect of increasing the West Virginia Business and Occupation taxes on power generation and increases in the Virginia sales and use tax, gross receipts taxes and property taxes.

Interest on long-term debt decreased as compared to 1990 primarily as a result of the redemption of certain debt, which was replaced by lower cost debt and lower interest rates on pollution control notes.

Future Issues Accounting Standards In December 1990, FASB issued SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," (SFAS No. 106), which requires ac.crual accounting for other postretirement employment benefits (OPEB). With the approval of acGrual accounting for OPEB costs through rates by the Virginia Commission in 1992, the Company has now received approval for accrual accounting for OPEB expenses in all jurisdictions. The Company is recovering OPEB costs in rates as of January 1, 1993, on an accrual basis, in all jurisdictions, except Virginia. On February 22, 1993, the Virginia Commission Staff filed testimony in the Company's pending rate proceeding that would provid_e for the recovery of OPEB on an accrual basis, effective January 1, 1993. The Company expects that rates currently in effect, subject to refund, will ultimately be. determined to provide for recovery of OPEB costs on an accrual basis, consistent with the policy adopted by the Virginia Commission.

For additional information on SFAS No. 106, see Rates under Item 1. BUSINESS and Note L to FINANCIAL STATEMENTS.

In November 1992, FASB issued SFAS No. 112, "Employer's Accounting for Postemployment Benefits," effective for fiscal years beginning after December 15, 1992. SFAS No. 112 requires employers who provide benefits to former or inactive employees after employment but before retirement to recognize the liability for these benefits on an accrual basis rather than as paid. Based on the current benefits offered, the Company has determined that this statement will not have an impact on the Company's financial statements.

18

e e Utility Rate Regulation Rate relief, especially in Virginia, continues to be of great importance to the Company, and it is a major variable that can materially affect its financial results. The Virginia Commission generally fixes rates based on a past test year, with certain modifications. In a period of increasing costs, such ratemaking methodology causes attrition in earnings, especially if the ut1lity is engaged in a large construction program.

For additional information on the current rate proceedings, see Rates under Item L 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. In response, the Company has undertaken specific compliance efforts:

. On March 30, 1992, the VWCB adopted water quality standards for toxic pollutants pursuant to the Cfean Water Act. The standards became effective on April 20, 1992. 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 pe *significant.

• Several. Superfund sites have been identified where the Company has been or may be identifi.ed as a potentially responsible party. :As a result of the Superfund Act or other laws or regulations regarding t1-e remediation of waste, the Company may be required to expend amounts on remedial investigations

• and actions. Other laws oi- regulations can give rise *to a similar liability for nori-superfund sites.

Although* the Company is not currently aware of any sites or events, including those sites currently identified, likely to re~ult in significant liabilities, such amounts, in the future, could b_e significant.

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 information on the Air Act and other en~ironmental matters, see Regulation under Itein 1.

BUSINESS. . . . ..

For information on Electric and Magnetic Fields, See Note M to. FINANCIAL STATEMENTS.

Nuclear Operations In 1992, the Company's four nuclear units operated at a combined capacity factor of 79.7 percent, reflecting a 72-day mid-cycle steam generator inspection and maintenance outage at North Anna Unit 1 and scheduled refueling outages for North Anna Unit 2 and Surry Unit 1. Refueling outages typically occur every eighteen months and last for approximately sixty days. Two refueling outages, as well*as the combination refueling and steam generator replacement outage for North Anna Unit 1, are currently scheduled for 1993. See Nuclear Operations and Fuel Supply, Sources of Energy Used and Fuel.Costs under Item 1. BUSINESS. .

Stress corrosion cracking has occurred in steani 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 repiaced in 1981 and 1979, respectively. The replacement of the steam generators at North Anna Unit "1 commenced January 4, 1993. The Company presently estimates the cost of replacing the steam generators to be $126 million. In 1992, the Company added as a new capital project, the procurement of three steam generators at a cost of $47.2 million for potential replacement in North Anna .Unit 2.

Costs associated with the steam generator replacements at Surry are being recovered through rates.

Other Trends Due to the effects of attrition and a gradual reduction in the authorized rate of return on equity used to set rates, the Company's earned return on average common equity has decreased over the past five

• years from 13.8 percent in 1988 to 11.5 percent in 1992.

19

e e Operation and maintenance expenses are expected to increase in the future due to changing regulations and costs associated with customer growth. The Company's capacity acquisition strategy of meeting the growing demand for electric power should continue to provide a low-cost energy mix.

During 1992, the Company continued its aggressive cost-cutting efforts by consolidating seve~~

district offices and offering an early retirement program to employees. Management is committed *to controlling costs. *

• Conservation and load Management In addition to complying with environmental laws and regulations, the Company is promoting toe*

efficient use of energy sources through cost effective conservation and energy management programs such as Energy Saver Homes, controls to cut the use of electric *water heaters and air conditioners during periods of high demand and summer rate differentials. In 1992, the Company created a department of energy efficiency to explore, promote and assist customers in the more efficient use of electricity.

For additional information see Conservation and Load Ma.nagement under Item 1. BUSINESS.

Competition The Company is increasingly encountering a variety of competitive forces as its customers consider alternative power and energy supplies and the Coinpany looks to generating resources that it does not own (see Competition under Item 1. BUSINESS);

• Industrial, commercial, municipal and cooper~tive cu~tomers of the. Comp~ny are presented. '}'i~h a variety of power supply options, as well as alterpative energy supply sources such as natural gas ..In addition, the Company faces competition . as a .result of the development of equipment by which customers may reduce their energy requirements or generate their own electricity. To date, loss. of customers to such alternatives has not materially reduced the Company's load, revenues or net income.

The access to utility transmission systems made possible by the Energy Act will facilitate increased wholesale competition. That Act bans federal orders of transmission services to retail customers and prohibits sham wholesale energy transactions that are wholesale in form but retail in substance. The Company's customers may be able to overcome these barriers and obtain services from another utility or a nonutility generator. The Company is committed to maintaining high standards of service at competitive rates for all classes of customers.

The Company now has, and in the future will have, increased opportunities to obta_in power from sources other than its own generating facilities (see Future Sources of Power under Item L BUSINESS). The Public Utility Regulatory Policies Act of 1978 (PURPA) and the :energy Act have encouraged non-utilities to enter the business of pr9ducing electricity. The Company supports a competitive system for utilities to buy capacity as an option to meet future demand. **

For additional information on the Energy Act, see Regulation, under Item 1. BUSINESS.

Commitmef/.ts and Contingencies For information on commitments and contingencies, see Ncite M to FINANCIAL STATEMENTS; 20

e e ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX Page No.

Report of Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Report of Independent Auditors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Statements of Income for the years ended December 31, 1992, 1991 and 1990 . . . . . . . . . . 24 Balance Sheets at December 31, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Statements of Earnings Reinvested in Business for the years ended December 31, 1992, 1991 and 1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 27 Statements of Cash Flows for the years ended December 31, 1992, 1991 and 1990 . . . . .. 28 Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 29 Financial Statement Schedules:

IV-Indebtedness of and to Related Parties Not Current for the years ended December 31, 1992, 1991 and 1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 41 V-Property, Plant and Equipment for the years ended December 31, 1992, 1991 and 1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 42 VI-Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment for the years ended December 31, 1992, 1991 and 1990 . . . . . . .. 45 IX-Short-term Borrowings for the years ended December 31, 1992, 1991 and 1990 .. 46 X-Supplementary Income Statement Information for the years ended December 31, 1992, 1991 and 1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 47 Schedules other than those listed above have been omitted since they are not required, are inapplicable or are unnecessary due to the presentation of the required information in the financial statements or notes thereto.

21

e 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 l:!.re 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 1992 the system of internal control was adequate to accomplish the intended objective.

The Financial Statements have been audited by Deloitte & Tonche, 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 J. T. Rhodes B. D. Johnson President and Senior Vice President-Finance, Chief Executive Controller, Treasurer and Officer Corporate Secretary 22

e e REPORT OF INDEPENDENT AUDITORS

• To the, Board of Directors of Virginia Electric and Power Company:

We have audited the accompanying financial statements of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) as of December 31, 1992 and 1991 and for each ofthe three years in the period ended December 31, 1992 listed in the index on page 2L Our audits also included the financial statement schedules listed in the index on page 21. These financial statements and the financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules

• 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

• ev~luatihg the overall financial statement presentation. We believe that oµr 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, 1992 and 1991 and the results of its cip~rations and its cash flows for each of the three years in the period ended December 31, 1992 in ctmfonnity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information shown therein; *

• * . As discussed in Note A to the financial statements, the Company changed its.method of accounting for income taxes in 1992 to conform with Statem~nt of Financial Accounting St~dard.s No. 109.

DELOITTE & TOUCHE Richmond, Virginia February 4, 1993 23

VIRGINIA ELECTRIC AND POWER COMPANY e

_STATEMENTS OF INCOME For The Years Ended December 31, 1992 1991 1990 (Millions)

Operating revenues $3,679.6. $3,688.1 $3,46i.5 Operating expenses:

Operation:

Fuel used in current generation .......... : .. .- ..... . 558.2 584.8 526A Purchased power expenses-fuel ................ . 314.5 281.1 270.0

-capacity ............. . 45i.5 266.1 184.9 Deferred expenses-fuel ..... *.................. . 45.2 61.l 126.0*

.:......capacity ..... *......... *.... *.. . (102.7)

Other ......................... , ..... : ..... .

• 477.7 482.9 440.7 Maintenance ......... : ; .......... *.......... *.. . 280.6 304.7 281.2 Depreciation and amortization . *................... . 399.9 395.5 373.6 Amortization of terminated construction project costs .. . 37.7 45.8 49.8 Taxes-Income ....:...................... *...... . 222.2 222.3 200.2

-Other .................................. . 233.2 227.0 202,9 Total .. ; .................................. _. .. 2,918.0

• 2,871.3 2,655.7*

Operating incom~ ......... .'........... : ......... . 761.6 816.8 . 805.8 Other income:

Allowance for other funds used during construction .... . 4.8 8.2 3.3 Miscellaneous, net ............................. . 17.9 33.2 34.9 IIicome taxes associated with miscellaneous, net ....... . (3.4) . (11.0) (13.3).

Total ................. , .......... : *...... : .. *. 19.3 30.4 24.9 Income before interest charges ..................... . 780.9 847.2 830:7 Interest charges:

Interest on long-term debt ....................... . 300.9 335.6 356.3 Other ...................... *........ *........ . 29.5 27.8 .25.9 Allowance for borrowed funds used during construction .. (4.7) (3.6) (LS)

Total ................ *...*............. *.... . 325.7 359.8 380.4 Income before cumulative effect of a change in accounting .

principle ...................................... 455.2 487.4 450.3 Cumulative effect on prior years of changing method of accounting for income taxes ...................... . 14.3 Net income ..................................... . 469.5 4~7.4 450.3 Preferred dividends .................... <......... . 45.7 51.5 5~.l Balance available for Common Stock ................. . $ 423.8 $ 435;9 $ 392.2 The accompanying notes are an integral part of the financial statements.

24

e e VIRGINIA ELECTRIC AND POWER .COMPANY BALANCE SHEETS Assets At December 31, 1992 1991-(Millions)

UTILITY PLANT:

Plant (includes plant under construction of $840.9 in 1992 and

$736.1 in 1991) .................................. . . $12,930.6 $12,385.9 Less accumulated depreciation ...........................* 3,837.6 3,520.9 9,093.0 8,865.0 Nuclear fuel (less accumulated amortization of $851.2 in 1992 and $758.7 in 1991) .. : ............................. . 161.7 199.6 Total net utility plant ........................... . 9,254.7 9,064.6 PLANT AND PROPERTY UNDER CAPITAL LEASES (less accumulated amortization of $14.9 in 1_992 anct $12.5 _in 1991) .. 31.6 34.0 INVESTMENTS:

.. Nuclear decommissioning tru_st funds .................. ; .. 185.8 . 152.4

_Pollution control project funds ........................ . 59.9 4.6

.. Other .................. *......................... . 22.6 25.8 Total net investments ............................ . 268.3 182.8 CURRENT ASSETS:

Cash and cash equivalents. ; .......................... . 65.1 21.1

• Customer accounts receivable (less allowance for doubtful

• . accounts of $1.7 in 1992 and in 1991) .... *............. . 181.3 147.0

• Accrued unbilled revenues .* .................. ; ........ . 87.4 90.2 Materials and supplies at average co"st or less:

Plant and general ................................. . 180.7 166.2 Fossil fuel ..................................... . 149.8 .130.4 Other ................ ." ................ : ....... _* .. 69.1 69.5 Total current assets ............................. . 733.4 . 624.4 DEFERRED DEBITS AND OTHER ASSETS:

Regulatory assets:

Income taxes recoverable through rates .................... . 459.0 Deferred capacity expenses ......................... . 102.7 Terminated construction project costs (less accumulated amortization of $319.9 in 1992 and $282.4 in 1991) ...... . 178.6. 190.5 Other ..... : ........... ; .......................... . 127.6 7.8 Unamortized debt issuance costs ....................... . 61.7 16.9 Other ................. : ......................... . 99.1 84.0 Total deferred debits and other assets * ...... '. ........ . 1,028.7 299.2 Total assets .................................... . $11,316.7 $10,205.0 The accompanying notes are an integral part of the financial statements.

25

VIRGINIA ELECTRIC AND POWER COMPANY e

. BALANCE SHEETS

. Capitalization and Liabilities At December 31, 1992 1991 (Millions) .

LONG-TERM DEBT $ 3,800.2 $ 3,818.1 PREFERRED STOCK:

Preferred stock subject to mandatory redemption .......... . 260.2 270.1 Preferred stock not subject to mandatory redemption 569.0 '469.0

.COMMON STOCKHOLDER'S EQUITY:

Common Stock, no par 300,000 shares authorized, 166,109 shares outstanding at December 31, 1992 and 162,741 at December 31; 1991 ......... : ................... . 2,612.4 2,549.1

• Other paid-in capital .......... *..................... . '22.0 16.4

_ Earnings reinvested in business ....................... . 1,182.7 1,132.9 Total common stockholder's*eqt1ity ................. . 3,817.1 .**J,69S.4

. 8,446.5 8,255.6

• OBLIGATIONS UNDER CAPITAL LEASES ........ * ...... . 29.1 31.7 CURRENT LIABILITIES:

Securities due within one year ........................ . 153.0 90.2 Short-term debt .................................... . 49.5 104.9 Accounts payable; trade ....... *. *......... ; ...... ; *... . 278.8 199.6 Customer deposits ................................. . 52.3 49.8 Payrolls accrued .. ; ................................ . 57.1 57.8 Provision for rate refunds ............................ . 189.3 27.3 Interest' accrued ................................... . 108.2 101.7 Other ..................... * ....................... . 52.3 61.3

, Total current

. liabilities. ....................... . ; .. . 940.5 692.6 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred income taxes .................... . 1,382.7 819.0 Deferred investment tax credits ....................... . 325.5 344.9 Deferred fuel expenses ......................... * ..... . 90.2 45.0 Other ............................................ . 102.2 16.2 Total deferred credits and other liabilities .............

• 1,900.6 1,225.1 COMMITMENTS AND CONTINGENCIES (See Note M)

Total capitalization and liabilities ................... . $11,316.7 $10,205.0 The accompanying notes are an integral part of the financial statements.

26

e e VIRGINIA ELECTRIC .AND POWER COMPANY STATEMENTS OF EARNINGS REINVESTED IN BUSINESS For the Years Ended December*31, 1992 1991 1990 (Millions)

Balance at beginning of year ............... . $1,132.9 $1,043.8 $ 980.6 Net income ........ ; .... .' .............. . 469.5. 487.4 450.3 Total .............. ; ............. . 1,602.4 1,531.2 1,430.9 Cash dividends:

Preferred stock subject to mandatory redemption .*...................* ..... . 19.4 24.2 26.4

, Preferred stock not subject to mandatory redemption ............... : ......... . 26.9 26.0 32.5 Common Stock .......... *.............. . 369.8

• 346.9 326.9 Total dividends 416.1 397.1 385.8 Other deductions, net 3.6* 1.2 1.3 Balance at end of year .................. . $1,182.7 $1,132.9 $1,043.8 The accompanying notes are an integral part of the financial statements.

27

e e VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1992 1991 1990 (Millions)

Cash Flow From Operating Activities:

Net income_ ....... :-............................. . $ 469.5 $ 487.4 $ 450.3 Adjustments to reconcile net income to net cash provided by operating activities:

Cumulative effect of change in method of accounting for income taxes ............................... . (14.3)

Depreciation and amortization .................... . 547.9 544.3 515.2 Allowance for other funds used during construction .... . (4.8) (8.2) (3.3)

Deferred income taxes ......................... . 105.1 (1.6) * (35.8)

Deferred investment tax credits ................... . (19.4) (18.8) (21.7)

Noncash return of terminated construction project costs-pretax ..................................... . (13.7) (19.2) (22.1)

Deferred fuel expenses, net ...................... . 45.2 61.1 126.0 Deferred capacity expenses ...................... . (102.7)

Changes in:*

Sale of accounts receivable .................... . 50.0 '150.0 Accounts receivable ........1 * * * * * * * * * * * * * * * * * * * (34.1) (0.8) 51.3 Accrued unbilled revenues ..................... . 2.8 (14.4) 31.6 Materials and supplies ........................ . (33.8) 48.0 (71.7)

Accounts payable, trade ...................... . 79.2. (43.2). . (3~9)

Accrued expenses ........................... . (26.7) 9.8 (72.9)

Provision for rate refunds ...................... . 16L9 (12.5) 17.5 Other .....* *............................... *... . 12.9 (3.3) (20.8)

Net Cash Flow From Operating Activities ................ . 1;175.0 1,078.6

• 1,089.7 Cash Flow From (To) Financing Activities:

Issuance of Common Stock ......................... . 75.0 150.0. , 200.0 Issuance of preferred stock .......................... . 240.0 Issuance of long-term debt .......................... . 1,241.0 299.4 200.0 Repayment of short-term debt ....................... . (55.4) (13.7) (7.2)

Inter-company credit agreement ...................... . (32.5) 32.5 (84.0)

Repayment of long-term debt and preferred stock .......... . (1,315.0) (410.4) (224.5)

Common Stock dividend payments ..................... . (369.8) (346.9) (326.9)

Preferred stock dividend payments ..... *............... . (46.3) (50.2) (58.9)

Other ............................... *.......... . (66.4) (19.4) . (4.0)

Net Cash Flow (To) Financing Activities ................. . (329.4) (358.7) (305.5)

Cash Flow From (Used in) Investing Activities:

Utility plant expenditures (excluding AFC-other funds) ...... . (662.2) (663.7) (728.8)

Nuclear fuel (excluding AFC-other funds) .............. . (54.3) (64.1) (74.6)

Pollution control project funds ....................... . (55.3) 1.0 34.5 Nuclear decommissioning trust funds .............. ; ... . (24.3) (18.5) (21.0)

Other .... *......................... ; ............ . (5.5) 27.2 7.0 Net Cash Flow (Used in) Investing Activities ............. . (801.6) (718.1) (782.9)

Increase in cash and cash equivalents ................... . 44.0 1.8 1.3 Cash and cash equivalents at beginning of year ............ . 21.1 19.3 18.0 Cash and cash equivalents at end of year ................. . $ 65.1 $ 21.1 $ 19.3 Cash paid during the year for:

Interest (reduced for the cost of borrowed funds capitalized as AFC) ........................................ . $ 325.3 $ 376.8 $ 388.3 Income taxes .................................... . 163.8 255.8 339.6 The accompanying notes are an integral part of the financial statements.

28

e e VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO FINANCIAL STATEMENTS A. Significant Accounting Policies:

General The Company's accounting practices are prescribed by the Uniform System of Accounts promul-gated 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, 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 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 1992, 1991 and 1990.

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, effective January 1, 1992, SPAS No. 109, "Accounting for Income Taxes" (SPAS No. 109). This standard requires companies to measure and record deferred tax assets and liabilities for all temporary differences. Temporary differences occur when events and transactions recognized for financial reporting result in taxable or tax-deductible amounts in future periods. The regulatory treatment of temporary differences can differ from the requirements of SPAS 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.

During 1991 and 1990, 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 net cost during the construction period of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.

29

e Prior to 1992, the rate and amount of AFC for borrowed funds were determined on a net-of-tax basis. As a result of the Company's adoption of SFAS No. 109, net-of-tax accounting is no longer permitted. Accordingly, construction work in progress (CWIP) at January 1, 1992, has been restated, thereby increasing CWIP and deferred income taxes. Utility plant in service has not been restated since measurement of the adjustments to utility plant in service and accumulated depreciation is not practicable. The* pretax AFC rate for 1992 was 10.3 percent. Aggregate AFC rates, net-of-tax, of approximately 9.0 percent were used for 1991 and 1990. Approximately 88 percent of the Company's CWIP is now included in rate base, and a cash return is collected currently thereon.

Deferred Capacity Beginning in 1992, the Company began to defer certain capacity expenses based on an order of the Virginia Commission. In its Final Order dated December 29, 1992, the Virginia Commission ordered the Company to record the over or under recovery of capacity costs on its balance sheet rather than in an off-balance-sheet memorandum account. Such deferral accounting will allow dollar for dollar.recovery of reasonably incurred capacity costs. *

• Approiimately 80 percent ~f capacity expenses are subject to deferral accounting. The difference between actual expenses and the level of expenses included in current rates is deferred and matched against anticipated future capacity-related rate increases.

• Deferred Fuel Approximately *90 percent of fuel expenses are subject to deferral accounting. The difference between actual fuel expenses and the level of fuel expenses included in current rates is deferred and matched against anticipated future fuel-related rate increases.

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 expenses resulting from the refinancing of debt are also deferred and amortized over the lives of the new issues of long-term debt.

Cash and Other Investments Current banking arrangements generally do not r.equire checks to be funded until actually presented for payment. At December 31, 1992 and_ 1991, the Company's accounts payable included the effect of checks outstanding but not yet presented for payment of $60.3 million and $43.3 million, respectively.

The carrying amount of temporary investments and pollution control project funds approximates fair value because of the short maturity of these investments.

Statement of Cash Flows 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 1991 and 1990 financial statements have been reclassified to conform to the 1992 presentation.

30

e B. Income Taxes: .

Details of income tax expense are as.(ollows:

Years 1992 1991 1990 (Millions)

Current expense:

Federal ,* .................................... ; . $142.9 $244.1 $248.4 State* ....................................... . 3.0 4.2 4.3 145.9 248.3 252.7 Deferred expense:

Plant related items:

Liberalized depreciation . . . . . . . . . . . . . . . . . . . . . . . . . 55.9 44.4 50.1 Indirect construction costs .................... ; . * (12.6) (13.4) (20.5)

Co~t of removal-property retirements ........ *. .' :* . , . 5.4 8.8 4.7 Other ... : .... ,. ........ : . , ................... . 4.6 3.1 (1.9)

Deferred fuel ..................... *...... , ...... . (15.4) (20.8) (42.8)

Unbilled revenues . *............................ . ' (4.1) (4.1) (4.1)

Deferred capacity . , . : .............. : ..........*. 34.9

• Debt issuance costs ....... : ........... *....*..... 15.4 1.5 1.4 Terminated construction project costs .............. . (7.9) (10.1) (10~6)

Other . *.. *... ; ... *.... ; ....................... . 19.5 (16.6) (6.8)

-95.7- . (7.2) (30.5)

Net deferred investment tax credits-2amortizatio~ ....... . (19.4) (18.8) (22.0)

Income tax expense-operating income ................ . . 222.2 222.3 200.2 Income tax expense associated with nonoperating income:

Current expense:

Federal ..................... *................ . (6.1) 5.2 18.0 State* .... \ ..................................  ; 0.1 0.2 0.2 (6.0) 5.4 18.2 Deferred expense ................................ . 9.4 5.6 (5.2)

Net deferred investment tax credits-amortization ........ . 0.3 Income tax expense nonoperating income ............. . 3.4 11.0 13.3 Total income tax expense .......................... . $225.6 * $233.3 $213.5 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: * **

Years 1992 1991 1990 (Millions, except percentages)

Federal income tax expense at statutory rate of 34% $230.4 $243.5 $224.2 Increases (decreases) resulting from:

Utility plant differences(*) ....................... . 4.6 11.3 (0.8)

Ratable amortization of investment tax credits ...... : .. (15.2) (16.5) (17.4)

Terminated construction project costs(*) ............ . 5.0 8.2 9.4 Other, net ................................... . (2.2) (17.6) (6.4)

(7.8) (14.6) (15.2)

Total federal income tax expense ..*................. $222.6 $228.9 $209.0 Effective*tax rate ....... *..... *................... . 32.8% 31.9% 31.7%

(*) Items for which deferred taxes had not been provided in prior years, net of amortization of certain deferred tax provisions recorded at higher levels than the current statutory rate.

31

- e In 1992, the Company adopted the provisions of SFAS No. 109. The Company is reporting 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 million and resulted in th.e establishment of a net regulatory asset of $459 million. For additional information see Federal Income Taxes under Note A to FINANCIAL STATEMENTS.

The Company's net noncurrent deferred tax liability is attributable to: depreciation method and plant basis differences ($856.6 million); income taxes recoverable through future rates ($459.0 million);

and abandoned project costs ($31.7 million); and other, net ($35.4 million).

C. Nuclear Operations:

Nuclear Decommissioning The Company's rates charged to customers include a provision for future decommissioning costs.

Amounts collected from customers are being placed in trusts by the Company. These amounts and the accumulated earnings thereon will be utilized solely to fund future decomissioning obligations. Total future decommissioning costs, including reclamation costs, are estimated to be $854 million in 1990 dollars. The accumulated provision for decommissioning of$185.8 million and $152.4 million is included in Utility Plant Accumulated Depreciation at December 31, 1992 and 1991, respectively. Provisions for decommissioning of $24.3 million, $18.5 million and $21.0 million applicable to 1992, 1991 and 1990, respectively, are included in Depreciation Expense.

The fair value of the Company's nuclear decommissioning trust funds at December 31, 1992 was

$198.2 million. The fair value is based on available market information and generally is the average of bid and ask price.

Insurance The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $7 .8 billion for a single nuclear incident. 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 $66.15 million for each of its four licensed reactors not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

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 $12.5 million.

The Company's current level of property insurance coverage ($2.225 billion for North Anna and

$2.225 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 is provided through several different policies. Under two of these policies, 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 $38.3 million and the maximum assessment at the time of the second incident is an additional $14.8 million. Based on the severity of the incident, the Board of Directors of the Company's nuclear insurers has the discretion t~ lower the maximum retrospective premium assessment or eliminate either or both completely. For 32

e e 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 $12.5 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 agreements 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, 1992 and 1991, $200 million of such receivables had been sold and were outstanding under these agreements. 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. Jointly Owned Plants:

The following information relates to the Company's proportionate share of jointly owned plants at December 31, 1992:

Bath County North Anna Clover Pumped Storage Power Power Station Station Station Ownership interest 60.0% 88.4% 50.0%

(Millions)

Utility plant in service ........................ . $1,070.5 $1,658.0 Accumulated depreciation .................. , .. . 140.9 562.2 Nuclear fuel .................................. . 656.6 Accumulated amortization of nuclear fuel .......... . 608.8 Construction work in progress .................. . 1.8 163.5 $289.3 The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interests. The Company's share of operating costs is classified in the appropriate operating expense (fuel, mainte-nance, depreciation, taxes, etc.) in the Statements of Income.

F. Terminated Construction Project Costs:

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 15-year period for Virginia and FERC jurisdictional customers. The net cost incurred was $387.6 million. At December 31, 1992, the net unamortized balance was $146.9 million.

33

G. Leases:

Plant and property under capital leases included the following:

1992 1991 (Millions)

Office buildings (*) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $40.8 $40.8 Data processing equipment ............................. . 5.7 5.7 Total plant and property under capital leases .......... . 46.5 46.5 Less accumulated amortization .......................... . 14.9 12.5 Net plant and property under capital leases ................ . $31.6 $34.0

(*) 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 $26.9 million and $27.7 million at December 31, 1992 ~nd 1991, respectively. Rental payments for such lease were $3.0 million for each of the three years ended December 31, 1992, 1991 and 1990.

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, 1992, are as follows:

Capital Operating Leases Leases (Millions) 1993 ............................................. . $ 5.1 $ 4.2 1994 .............................................. . 5.1 3.3 1995 ................................. *............. . 4;1 2.3 1996 ............. *.............. .- .................. . 3.2 2.1 1997 ............................................. . 3.2 1.5 After 1997 ......................................... . 31.7 17.7 Total future minimum lease payments .................... . 52.4 $31.1 Less interest element included above ..................... . 23.1 Present value of future minimum lease payments ............ . $29.3 Rents on leases, which have been charged to other operation expenses, were $10.6 million, $12.8 million, $17.0 million for 1992, 1991 and 1990, respectively.

34

H. Lung-term Debt:

e *l Long-term debt included the following:

At December 31, 1992 1991 (Millions)

First and Refunding Mortgage Bonds (1):

Series R, 4.375%, due 1993 ......................... : . $ 30.0 $ 30.0 Series S, 4.5%, due 1993 ............................ . 30.0 30.0 1987 Series B, 9.375%, due 1994 ...................... . 100.0 100.0 1992 Series A, 6.375%, due 1995 ....................... . 180.0 Series T, 4.5%, due 1995 ............................ . 56.6 56.6 1981 Series B, 15.75%, due 1996 ...................... . 8.0 8.0 Series U, 5.125%, due 1997 .......................... . 49.2 49.2 Series V, 6.875%, due 1997 ........................... . 50.0 50.0 1992 Series B, 7.25%, dlie 1997 ........................ . 250.0 Various series, 6.25%-9.375%, due 1998-2002 ............. . 805.0 845:0 Various series, 6.75%-8%, due 2003-2007 ................ . 484.8 457.8 Various series, 9.625%-10.25%, due 2008-2012 ............ . 192.0 Various series, 8.5%, due 2013-2017 ........ , ........... . 150.0 350.0 Various series, 8.75%-9.875%, due 2018-2022 ............. . 445.0 450.0 Total first and refunding mortgage bonds ............... . 2,638.6 2,618.6 Other long-term debt:

Bank loans, notes and term loans:

Fixed interest rate, 5.7%-10.8%, due 1993-2003 .......... . 847.1 836.5 Pollution control financings (2):

Fixed interest rate, 5.625%, due 2002 ................. . 20.0 20.5 Money Market Municipals, due 2008-2017(3) ............ . 444.6 388.6 Inter-company credit agreement (4) .................... . 32.5 Total other long-term debt ......................... . 1,311.7 1,278.1 3,950.3 3,896.7 Less amounts due within one year:

First and Refunding Mortgage Bonds .................. . 60.0 Bank loans, notes and term loans .....................

• 76.0 49.4 Sinking fund obligations ........................ '. ... . 0.7 14.2 Total amount due within one year .................. . 136.7 63.6 Less unamortized discount, net of premium .............. . 13.4 15.0 Total long-term debt ............................ . $3,800.2 $3,818.1 (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. 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.

(4) Under the terms of the Inter-Company Credit Agreement, the Company may borrow funds from Dominion Resources on a daily basis and repay all or any part of the loan at any time during the term of the agreement, presently due to expire on December 31, 1994. Borrowings under the agreement are 35

e e limited to $300 million outstanding at one time less amounts outstanding under the commercial paper program. The weighted average interest rate for 1992 and 1991 was 5.06 percent and 5.81 percent, respectively.

Maturities through 1997 are as follows (millions): 1993-$136.7; 199~165.8; 1995-$313.3; 1996--$178.3 and 1997-$362.0.

The fair value of the Company's First and Refunding Mortgage* Bonds and pollution control revenue bonds is based on market quotations. The estimated fair value for these bonds at December 31, 1992 was $2.7 billion.

At December 31, 1992, there were $847.1 million Medium-Term Notes outstanding. These Medium-Term Notes were valued by discounting the remaining cash flows at a rate estimated for each issue. A yield curve was estimated to relate Treasury Bond rates for specific issues to the corresponding maturities. The estimated fair value for the Company's Medium-Term Notes at December 31, 1992 was

$909.9 million.

The Money Market Municipal pollution control notes have variable interest rates which are set so that fair value approximates carrying value.

The Company ui;;ed 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.

In February 1993, the Company sold.$100 million of First and Refunding Mortgage Bonds.

I. Preferred Stock Subject to Mandatory Redemption:

)?referred stock subject to mandatory redemption, $100 liquidation preference, at December 31, 1992, was as follows:

Annual Sinking Fund Entitled Per Share Requirements Upon Voluntary Liquidation Redemption at $100 Per Share Issued and And Thereafter to Outstanding Amounts Declining Dividend Shares Amount Through In Steps To Shares

$6.35 1,400,000 (A) (B) 7.30 485,000 $107.30 4/14/93 $100.00 after 4/14/02 15,000 7.325 400,419 101.00 28,000 7.58 480,000 103.79 . 6/19/93 100.00 after 6/19/93 120,000 2,765,419 Less shares due within one year 163,000 Total 2,602,419 (A) Shares are non-callable prior to, redemption.

(B) All shares to be.redeemed on 9/1/2000.

Maturities are $16.3 million for each Year 1993-1996 and $4.3 million for 1997.

In 1992, the following series were redeemed: $8.20 (330,000 shares), $8.40 (512,000 shares), $8.60 (228,764 shares), $8.625 (203,500 shares)', and $8.925 (164,500 shares).

In 1990 and 1991, 150,000 sl:iares and 50,000 shares, respectively, of the $10.25 Dividend Preferred Stock were redeemed.

36

e e In 1990, 10,500 shares of the $8.925 Dividend Preferred Stock were redeemed through optional sinking funds.

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.

The preferred stock subject to mandatory redemption had a carrying amount of $276.5 million and an estimated fair value of $301.9 million at December 31, 1992. The fair value of the preferred subject to mandatory redemption was estimated by discounting the dividend and principal payments for a representative issue of each series over the average remaining life of the series.

The Company used available market information and appropriate valuation methodologies to estimate the fair value of each class of financial instruments 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.

J. Preferred Stock Not Subject to Mandatory Redemption:

Preferred stock not subject to mandatory redemption, $100 liquidation preference, at December 31, 1992, was as follows:

Entitled Per Share Upon Issued Voluntary and Liquidation Outstanding Redemption Dividend Shares Amount

$5.00

--- 106,677 $112.50 4.04 12,926 102.27 4.20 14,797 102.50 4.12 32,534 103.73 4.80 73,206 101.00 7.72 350,000 101.50 7.45 400,000 101.00 7.20 450,000 101.00 7.72 (1972 Series) 500,000 101.00 MMP 1/87 (*) 500,000 100.00 MMP 6/87 (*) 750,000 100.00 MMP 10/88 (*) 750,000 100.00 MMP 6/89 (*) 750,000 100.00 MMP 9/92A (*) 500,000 100.00 MMP 9/92B (*) 500,000 100.00 Total 5,690,140

(*) 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 1992, 1991 and 1990, including fees for broker/dealer agreements, were 3.43 percent, 5.22 percent and 6.95 percent, respectively.

In February 1993, the Company issued $40 million of Money Market Preferred Stock.

37

K. Common Stock:

During the years 1990 through 1992 the following changes in Common Stock occurred:

Years 1992 1991 1990 (Millions, except shares)

Shares Shares Shares Outstanding Amount Outstanding Amount Outstanding Amount Balance at January 1 ..... 162,741 $2,549.1 156,049 $2,398.3 147,077 $2,197.5 Transfer from (to) Other Paid-in Capital ........ (11.7) 0.8 0.8 Issuance to Dominion Resources ........... 3,368 75.0 6,692 150.0 8,972 200.0 Balance at December 31 .. 166,109 $2,612.4 162,741 $2,549.1 156,049 $2,398.3 L. 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 $13.1 million, $10.8 million and $5.1 million for 1992, 1991 and 1990, respectively and the amounts funded were $12.3 million, $12.2 million and $6.8 million in 1992, 1991 and 1990, respectively.

In addition to providing pension benefits, Dominion Resources and the Company provide certain health care and life insurance benefits for retired employees. Health care benefits are provided to retirees who have completed at least ten years of service after obtaining age 45. These and similar benefits for active employees are provided through insurance companies with annual premiums based on benefits paid during the year. 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.

The following information relates to the retiree health care and life insurance benefits:

Years 1992 1991 1990 Health care premiums paid (millions) ............... . $ 10.0 $ 8.0 $ 6.8 Retirees covered under health care ................ . 2,900 2,800 2,500 Life insurance premiums paid (millions) ............. . $ 0.5 $ 0.5 $ 0.4 Retirees covered under life insurance .............. . 2,300 2,300 2,200 SFAS No. 106 was issued by FASB in December 1990. Based on the current terms of its benefit plans, the Company presently estimates that the required application of this standard in 1993 will result in an increase of approximately $28 million over the pay-as-you-go amount. A transition obligation of approximately $241 million would result from the application of this standard as of January 1, 1993. The Company has received approval for accrual accounting for OPEB expenses for all of the jurisdictions.

The Company is recovering OPEB costs in rates as of January 1, 1993, on an accrual basis, in all jurisdictions, except Virginia. On February 22, 1993, the Virginia Commission Staff filed testimony in the Company's pending rate proceeding that would provide for the recovery of OPEB on an accrual basis, effective January 1, 1993. The Company expects that rates currently in effect, subject to refund, will ultimately be determined to provide for recovery ofOPEB costs on an accrual basis, consistent with the policy adopted by the Virginia Commission. For additional information, see Rates under Item 1.

BUSINESS.

M. 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, 38

e e 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 1991 aqd 1992, including those currently in progress, see Rates under Item 1. BUSINESS.

For information on the effect of rate increases see Results of Operations under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDIDON AND RESULTS OF OPERATIONS.

Retrospective Premium Assessments Under several of the Company's nuclear insurance policies, the Company is subject to retrospec-tive 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 $844 million (excluding AFC) for 1993. Additional financing is contemplated in connection with this program. For more information see Capital Requirements under MANAGEMENT'S DISCUSSION AND ANALYSIS 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 h~s 87 non-utility purchase contracts with a combined dependable summer capacity of 3,634 Mw. Of these, 52 projects (aggregating 2,833 Mw) were operational as of the end of 1992 with the balance to become operational at various dates before 1998.

The table below reflects the Company's minimum commitments as of December 31, 1992, for power purchases from utility and non-utility suppliers that are currently operating or have obtained construction financing.

Commitment Year Capacity Other (Millions) 1993 ......................... . $ 591.1 $ 194.9 1994 ............................ . 637.8 204.7 1995 .......................... . 661.3 204.4 1996 ............ *.............. . 664.8 212.3 1997 .......................... . 666.8 222.7 Later years . . . . . . . . . . . . . . . . . . . . . 10,820.2 3,781.7 Total .................... *... . $14,042.0 $4,820.7 Present value of the total .......... : $ 5,873.7 $1,774.9 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 1992, 1991 and 1990 were $766.0 million, $547.2 million and $473.6 million, respectively.

Fuel Purchase Commitments The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (millions): 1993-$332; 1994-$268; 1995-$155; 1996-$44 and 1997-$23.

Environmental Matters For more information, see Future Issues under Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

39

e e Electric and Magnetic Fields The possibility that exposure to electric and magnetic 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 so.on to tell what, If any, impact these actions may have on the Company's financial condition. . .

N. Quarterly Financial Data (unaudited):

The following amounts reflect all adjustments, consisting of only normal recurring accruals (except as disc1,1ssed below), necessary in the opinion of the management for a fair statement of the results for the interim periods.

Income Before Cumulative EIJect Cumulative EIJect of a Change of a Change Balance Available Operating Operating in Accounting in Accounting for Common Quarter Revenues* Income Principle Principle Stock (Millions) 1992 1st ............. $ 934.6 $194.5 $110.9 $14.3 $113.4 2nd .............

• 851.8 144.7 68.2 56.7 3rd ............. 1,052.3 232.5 155.8 144.4 4th ............. 840.9 189.9 120.3 109.3 1991

• 1st ............. $ 884.2 $1~6.3 $114.8 $101.2 2rid ............. 875.6 178.5 94.7 81.9 3rd .............. 1,042.6 274.4 191.6 179.0 4th ............. 885.7 167.6 86.3 73.8 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.

In 1992, the Company adopted the provisions of SFAS No. 109. The Company is reporting the implementation of the standard as a change in accounting principle. The cumulative effect on prior years increased net income by $14.3 million. Accordingly, first quarter results have been restated to reflect this change.

In the first quarter of 1992, the Company reserved approximately $34 million, in accordance with the Virginia 1990 rate case Virginia Supreme Court ruling, resulting in a decrease to Operating Income and Balance Available for Common Stock of $22. 7 million (net ofassociated taxes of $11.3 million). This reserve was adjusted in the second quarter to reflect actual refunds to customers of $26 million, including $3.3 million of interest.

In accordance with the Virginia Commission's December 1992 Final Order, the Company implemented deferral accounting and established a regulatory asset for certain capacity expenses, which had the impact of increasing operating income and Balance Available for Common Stock by $67.8 million (net of associated taxes of $34.9 million). This increase was offset, in part, by a reduction in revenues for a provision for refunds to pe made in connection with the Virginia Commission's December 1992 Final Order, which had the effect of decreasing operating revenues by $84.0 million, and decreasing operating. income and Balance Available for Common Stock by $60.3 million (net of associated taxes of $31.0 million).

In December 1991, the Company provided $20 million for obsolete material and supplies which had the effect of decreasing Operating Income and Balance Available for Common Stock by $13.2 million (net of associated taxes of $6.8 million).

40

e SCHEDULE IV VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE IV INDEBTEDNESS OF AND TO RELATED PARTIES NOT CURRENT For the years ended December 31, 1992, 1991 and 1990 Col.A Col. B Col. C Col. D Col. E Col. F Col. G Col. H Col. I Indebtedness of Indebtedness to Name of Balance at Balance Balance at Balance person Beginning Additions Deductions at End Beginning Additions Deductions at End (Millions)

Dominion Resources:

1992 . . . . . . . . . . . $32.5 $ 5.0 $ 37.5 1991 . . . . . . . . . . . . $709.0 $676.5 $32.5 1990 . . . . . . . . . . . . $84.0 $746.9 $830.9 See Note (4) of Note H to FINANCIAL STATEMENTS.

41

e SCHEDULE V VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE V PROPERTY, PLANT AND EQUIPMENT For the year ended December 31, 1992 Col. A Col. B Col. C Col. D Col. E Col. F.

Other Balance at Changes Balance Beginning Additions Retirements Add at End Classification of Period at Cost or Sales (Deduct) of Period (Millions)

Utility plant:

Electric Plant:

In service:

Intangible ................. $ 71.9 $ 23.5 $ 9.8 $ 85.6 Production ................. 6,376.9 215.5 33.8 $. 2.6 6,561.2 Transmission .............. 1,128.8 56.2 1.2 0.6 l, 184.4 Distribution ................ 3,401.7 218.9 38.4 (0.2) 3,582.0 General ................... 586.7 38.7 30.6 (0.7) 594.1 Total electric plant in service . 11,566.0 552.8 113.8 2.3 12,007.3 Construction work in progress ... 736.1 104.8(*) 840.9 Held for future use ............ 41.0 (1.4) 39.6 Electric plant acquisition adjust-ment ..................... 42.8 42.8 Total electric plant ......... 12,385.9 657.6 113.8 0.9 12,930.6 Nuclear fuel .................... 958.3 54.1 $11.6 1,024.0 Total utility plant ........ , . $13,344.2 $711.7 $113.8 $12.5 13,954.6 Non-utility property ............... $ 8.5 $ 1.7 $ 10:2 Capital leases . . . . . . . . . . . . . . . . . . . . $ 46.5 $ 46.5

(*) Includes additions of $657.6 million net of $552.8 million transferred to plant in service.

42

SCHEDULE V VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE V PROPERTY, PLANT AND EQUIPMENT For the year ended December 31, 1991 Col. A Col. B Col. C Col. D Col. E Col. F Other Balance at Changes Balance Beginning Additions Retirements Add at End Classification of Period at Cost or Sales (Deduct) of Period (Millions)

Utility plant:

Electric plant:

In service:

Intangible ............ $ 64.5 $ 9.7 $ 2.3 $ 71.9 Production ........... 6,132.7 226.8 24.2 $41.6(a) 6,376.9 Transmission ......... 1,060.0 73.7 4.7 (0.2) 1,128.8 Distribution .......... 3,190.6 255.8 44.9 0.2 3,401.7 General ............. 576.6 29.4 20.1 0.8 586.7 Total electric plant in service .......... 11,024.4 595.4 96.2 42.4 11,566.0 Construction work in progress ............ 691.7 44.4(b) 736.1 Held for future use ...... 11.0 28.2 0.1 1.9 41.0 Electric plant acquisition adjustment. .......... 42.8 42.8 Total electric plant ... 11,769.9 668.0 96.3 44.3 12,385.9 Nuclear fuel ............... 893.9 64.4 958.3 Total utility plant .... $12,663.8 $732.4 $96.3 $ 44.3 $13,344.2 Non-utility property ......... $ 10.8 $ (2.3) $ 8.5 Capital leases .............. $ 87.2 $ 0.1 $(40.6)(a) $ 46.5 (a) At the expiration of the lease in August 1991, the combustion turbines became the property of the Company.

(b) Includes additions of $639.8 million net of $595.4 million transferred to plant in service.

43

e e SCHEDULE V VIRGINIA ELECTRIC AND -POWER COMPANY SCHEDULE V PROPERTY, PLANT AND EQUIPMENT For the year *ended December 31, 1990 Col. A Col. B. Col. C Col. D Col. E Col. F Other Balance at Changes Balance Beginning Additions Retirements Add at End Classification of Period at Cost or Sales (Deduct) of Period (Millions)

Utility plant:

Electric plant:

In service:

Intangible ............ $ 49.0 $ 19.9 $ 4.4 $ 64.5 Production ........... 5,787.5 374.5 27.4 $(1.9) 6,132.7 Transmission . : ....... 1,010.0 53.8 4.4 0.6 1,060.0 Distribution . . . . . . . . . . 2,963.9 271.0 44.7 0.4 3,190.6 General ............. 532.7 54.0 11.4 1.3 576.6 Total electric plant in service .......... 10,343.1 773.2 92.3 0.4 11,024.4 Construction work in progress ............. 745.4 (53.7)(*) 691.7 Held for future use ...... 4.5 6.6 (0.1) 11.0 Electric plant acquisition .

adjustment. .......... 42.8 42.8 Total electric plant ... 11,135.8 726.1 92.3 0.3 11,769.9 Nuclear fuel ............... 819.1 74.8 893.9 Total utility plant .... $11,954.9 $800.9 $92.3 $ 0.3 $12,663.8 Non-utility property ......... $ 5.8 $ 0.2 $ 5.2 $ 10.8 Capital leases . . . . . . . . . . . . . . $ 83.4 $ 0.5 $ 4.3 $ 87.2.

(*) Includes additions of $719.5 million net of $773.2 million transferred to plant in service.

44

e SCHEDULE VI VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE VI ACCUMULATED DEPRECIATION, .DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT For the years ended December 31, 1992, 1991 and 1990 Col. A Col. B Col. C Col. D Col. E Col. F Additions Other Balance at Charged to Changes Balance Beginning Costs & Add at End Classification of Period Expenses Retirements (Deduct) of Period (Millions) 1992 Accumulated depreciation and amortization of electric plant $3,520.9 $391.4 $116.2 $ 41.5 $3,837.6 Accumulated amortization of .

capital leases ........... *... $ 12.5 $ 2.4 $ 14.9 Accumulated amortization of nuclear fuel ............... $ 758.7 $ 92.5 $ 851.2 1991

- Accumulated depreciation and amortization of electric plant $3,171.4 $376.3 $102.1 $ 75.3 (*) $3,520.9 Accumulated amortization of capital leases .............. $ 48.6 $ 6.0 $(42.1) (*) $ 12.5 Accumulated amortization of nuclear fuel o o o o o o IO o O o O O O o $ 661.6 $ 97.1 $ 758.7 1990 Accumulated depreciation and amortization of electric plant $2,880.1 $353.0 $ 92.2 $ 30.5 $3,171.4 Accumulated amortization of capital leases . . . . . . . . . . . . . . $ 41.9 $ 7.1 $ 0.5 $ 0.1 $ 48.6 Accumulated amortization of nuclear fuel . . . . . . . . . . . . . . . $ 576.8 $ 84.8 $ 661.6 Provision for depreciation of automobiles and trucks is charged to transportation expense clearing account and redistributed to operation expense, utility plant and other accounts.

(*) At the expiration of the lease in August 1991, the combustion turbines became the property of the Company.

45

e SCHEDULE IX VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE IX SHORT-TERM BORROWINGS For the years ended December 31, 1992, 1991 and 1990 Col. A Col. B Col. C Col.D Col. E Col. F Weighted Weighted Maximum Average Average Weighted Amount Amount Interest Category of Balance Average Outstanding Outstanding Rate Aggregate Short- at end of Interest During the During the During the Term Borrowings Period Rate Period Period (a) Period (a) 1992 Commercial paper program (b). $ 49.5 3.43% $134.0 $26.2 3.61%

Nuclear fuel financing (c)(d) ... $ 0.0 4.24%

1991 Nuclear fuel financing (c) $104.9 4.93% (d) (d) 6.46%

1990 Nuclear fuel financing (c) $118.6 7.90% (d) (d) 8.30%

(a) Average computed on a daily weighted basis (b) In 1992, the Company established a commercial paper program that provides an additional source of borrowing in lieu of the Inter-Company Credit Agreement with Dominion Resources.

Borrowings are limited to $200 million outstanding at any one time. Dominion Resources maintains credit agreements with various expiration dates, to support this commercial paper program.

(c) Maximum 270 days (d) The total amount of commercial paper outstanding under this arrangement at December 31, 1991 and 1990 was $104.9 million and $118.6 million, respectively. The standby revolving credit agreement which supports the related commercial paper (a maximum of $200 milliqn) was terminated in October 1992.

46

SCHEDULEX VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE X SUPPLEMENTARY INCOME STATEMENT INFORMATION For the years ended December 31, 1992, 1991 and 1990 Col. A Col. B Charged to Expenses Item Years Ended December 31, 1992 1991 1990 (Millions)

Taxes other than income taxes:

Real estate and property .............. . $ 79.1 $ 71.6 $ 66.4 Local gross receipts .................. . 92.8 91.7 86.6 Payroll related ...................... . 30.1 28.7 27.7 West Virginia business and occupation .... . 28.7 28.2 21.8 Other ............................ . 2.5 6.8 0.4 Total ........................... . $233.2 $227.0 $202.9 47

e ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PAR.Till ITEM 10. DffiECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

(a) Information concerning directors of Virginia Electric and Power Company is as follows:

Year First Principal Occupation for Last S Years, Elected a Name and Age Directorships in Public Corporations Director Thos. E. Capps (57) Chairman of the Board of Directors of Virginia Electric . 1989 and Power Company and Dominion Resources and President and Chief Executive Officer of Dominion Resources (from May l, 1990 to December 30, 1992, Vice Chairman of the Board of Directors of Virginia Electric and Power Company and President and Chief Executive Officer of Dominion Resources;

. from April 1, 1989 to May 1, 1990, President and Chief Operating Officer of Qominion Resources, prior to April 1,-1989, President of Dominion Resources).

He is a Director of Dominion Resources and Bassett Furniture Industries, Incorporated.

James T. Rhodes (51) President and Chief Executive Officer of Virginia Elec- 1989 tric and Power Company (from January 1, 1988 to April 1, 1989, Senior Vice President~Finance; prior to January 1, 1988, Senior Vice President-Power Opera-

. tions). He is a Director of Dominion Resources and

• NationsBank of Virginia, . N .A.

John B. Adams, Jr. (48) President and Chief Executive Officer of A. Smith 1987

. *Bowman Distillery, Inc.; Fredericksburg, Virginia, a manufacturer and bottler of alcohol beverages, De-

. cember 27, 1989 t9 date; (prior to December 27, 1989 Vice President and Director). .

• William W. Berry (60) Retired Chairman of the Boarq of Directors of Virginia 1980 Electric and Power Company and Dominion Re-sources (from May 1, 199.0 to December 30, 1992, Chairm~n of the Board of Directors of Virginia Elec-tric and Power Company and Dominion Resources; prior to May 1, 1990, Chairman of the Board of Di-

. rectors of Virginia Electric arid Power Company and Dominion Resources and Chief Executive Officer of Dominion Resources). He is. a Director of Dominion Resources, NationsBank Corporation, Ethyl Corpo-ration and Universal Corporation.

Anna Ruth Inskeep (67) Battle Park Farms, Rapidan, Virginia, a dairy farm and 1987 milk hauling business.

Benjamin J. Lambert, III (56) Optometrist, Richmond, Virginia. He is a Director of 1992 Consolidated Bank and Trust Company Harvey L. Lindsay, Jr'. (63) Chairman and Chief Executive Officer of Harvey Lind- 1986 say Commercial Real Estate, Norfolk, Virginia, a commercial real estate firm.

48

i Year.First Principal Occupation for Last*S Years, Elected a Name and Age Directorships in Public Corporatio~ Director Shirley S. Pierce (69) Chairman of the Board and President of Ahoskie Fertil- 1972 izer Company, Inc., Ahoskie, North Carolina, a manufacturer and distributor of fertilizer and agricul-

. tural products.

William T. Roos (65)

• President of Penn Luggage, Irie., Hampton, Virginia, 1975

. retail specialty stores .

William G. Thomas (53) . . President of Hazel & Thomas, Alexandria, Virginia, a 1987 law firm.

Each Director holds office* until .the next Annual Meeting of Shareholders or until his or her successor is duly elected ..

(b) Information. concerning the. executive Officers of Virginia Electric and Power Company is as follows:

Name and Age

• Business Experience Past Five Years Thos. E. Capps (57)

• Chairma~ of the B~ard of Directors, December 30, 1992 to date; Vice Chairman of the Board of Directors, Aprill, 1989 to Decem-ber* 30, 1992; President and Chief Operating Officer of Dominion Resources, Inc., prior to April 1,. 1989.

James T. Rhodes (51) . President and Chief Executive Officer, April 1, 1989 to date; Senior Vice President-Finance, prior to April 1, 1989 ..

. John A. Ahladas (50) Senior Vice President-Corporate.Services, January 1, 1990 to date; Senior Vice President-Corporate Technical Services, April 1, 1988 to January 1, 1990; Vice President-Engineering prior to April 1, 1988.

Larry W. Ellis (52) Senior Vice President-PowerOperations and Planning, January 1, 1990,to date; Vice President~System Planning and Power Supply, Match 18, 1988 to January 1, 1990; Manager, System Planning and Power Supply, prior to March; 18, 1988.

Robert F. Hill *(57) Senior Vice President-Commercial Operations.

B. D. Johnson (60) Seni~r Vfoe President-Finance, Controller, Treasurer and Corporate

• secretary, November 15; 1992 to date; Senior Vice President-

• Finance and Controller, January 1, 1990 to November 15; 1992; Vice President and Controller prior to*January 1, 1990.

William L. Stewart (49) Senior Vice :President-Nuclear, January 1, 1990 to date; Senior Vice

,President-Power, April 1, 1988 to January l, 1990; Vice President-Nuclear Operati.ons prior to April 1, 1988.

Paul J. Bonavia (41) Vice President-Regulation, September 1, 1992 to date; Vice Presi-dentand General Counsel, Dominion Resources, June 3, 1991 to September 1, 1992; Partner in the law firm of Steel, Hector and Davis, Miami, Florida, prior to June 3, 1991.

• Charles A. Brown (50) Vice President-Central Division; September 1, 1992 to date; Vice President-Procurement, September 1, 1988 to September 1, 1992; Manager, Materials Management, May l, 1988 to September 1, 1988; Manager, Contracts prior to May 1, 1988:

William R. Cartwright (50). Vice President-Fossil and Hydro, January 1,.1990 to date; Vice Pres~

ident-Nuclear Operations, September 1, 1988 to January 1, 1990; Vice President-Fossil and Hydro, prior to September 1, 1988.

49

Name and Age Business Experience Past Five Years Thomas L. Caviness, Jr. (47) Vice President-Eastern Division, November 1, 1989 to date; Execu-tive Project Director, November 1, 1988 to November 1, 1989; Manager, Productivity prior to November 1, 1988.

James T. Earwood, Jr. (49) Vice President-Division Services.

James R. Frazier, Jr. (51) Vice President-Southern Division.

Larry M. Girvin (49) .Vice President-Nuclear Services, September 1, 1992. to date; Vice President-Central Division, January 1, 1991 to September 1, 1992; District Manager Richmond, September 1, 1989 to January 1, 1991; District Manager East Richmond, prior to September 1, 1989.

Earl R. Gore (52) Vice President-Northern Division, September 1, 1988 to date; Man-ager, _Operations and Construction prior to September 1, 1988.

E. Wayne Harrell (46) Vice President-Nuclear Engineering Services, September 1, 1992 to date; Vice President-Nuclear Services, January 1, 1992 to Septem-ber 1, 1992; Vice President:Nuclear Operations, January 1, 1990 to January 1, 1992; Vice President-Fossil and Hydro Operations, September 1, 1988 to January 1, 1990; Manager, Fossil and Hydro Operation Support, April 1, 1988 to September l, 1988; Station Manager, Nuclear prior to April 1, 1988.

F. Kenneth Moore (51) Vice President-Procurement, September 1, 1992 to date; Vice Presi-dent-Nuclear Engineering Services, November 1, 1989 to Sep-tember 1, 1992; Vice President-Power Engineering Services, March 18, 1988 to November 1, 1989; Manager, Purchasing prior to March 18, 1988.

Irene M. Moszer (49) Vice President-Information Services, October 1, 1991 to date; Vice President, Treasurer and Corporate Secretary, January 1, 1990 to October 1, 1991; Vice President-Administrative Services prior to January 1, 1990.

James P. O'Hanlon (49) Vice President-Nuclear Operations, January 1, 1992 to date; Vice President-Nuclear Services, June 15, 1989 to January 1, 1992; Vice President, United Energy Services Corporation prior to June 15, 1989.

Thomas J. O'Neil (50) Vice President-Energy Efficiency, September 1, 1992 to date; Vice President-Regulation, August 1, 1988 to September 1, 1992; Vice President-Western Division prior to August 1, 1988.

Robert E. Rigsby (43) Vice President-Human Resources, October 1, 1991 to date; Vice President-Information Systems, January 1, 1990 to October 1, 1991; Vice President-Western Division, August 1, 1988 to Jan-uary 1, 1990; General Auditor prior to August 1, 1988.

Johnny V. Shena! (47) Vice President-Western Division, January 1, 1990 to date; Manager, Transmission and Substation Engineering, August 1, 1988 to Janu-ary l, 1990; District Manager, Alexandria prior to August 1, 1988.

Eva S. Teig (48) Vice President-Public Affairs, September 7, 1990 to date; Vice Presi-dent-Government Affairs, January 1, 1990 to September 7, 1990; Secretary of Health and Human Resources, Commonwealth of*

Virginia, prior to January 1, 1990.

50

e Name and Age Business Experience Past Five Years Robert F. Saunders (49) Assistant Vice President-Nuclear Operations, November 1, 1990 to date; Manager, Nuclear LiceQsing and Programs. November 1, 1989 to November 1, 1990; Manager, Nuclear Licensing, Decem-ber 16, 1988 to November 1, 1989; Manager, Nuclear Programs, April l, 1988 to December 16, 1988; Nuclear Specialist, prior to April 1, 1988.

There is no family relationship between any of the persons named in response to Item 10.

ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The Summary Table below includes compensation paid by the Company for services rendered in 1992, 1991 and 1990 for the Chief Executive Officer and the four other most highly compensated executive officers (as of December 31, 1992) as determined by total salary and incentive payments for 1~2. .

Summary Compensation Table Long Term Compensation Annual Compensation Awards Payouts Restricted All Stock LTIP Other Name & Principal Position Year Salary Incentives(*) Awards Payouts Compensation

-($)- ($) ($) ($) ($)

James T. Rhodes President & CEO 1992 $340,000 $188,752 $32,579 (1) $20,254 $112,933 (2) 1991 $274,600 $155,502 $28,118 (3) $15,401 1990 $228,250 $133,056 $ 0 $33,631 Thos. E. Capps Chairman of the Board 1992 $333,698 $144,828 $ 0 $ 0 $108,537 (4) 1991 $275,141 $130,504 $ 0 $ 0 1990 $236,972 $137,226 $ 0 $ 0 Robert F. Hill Senior Vice President- 1992 $204,900 $ 71,703 $ 0 $24,334 $54,602 (5)

Commercial Operations 1991 $196,275 $ 71,085 $ 0 $21,290 1990 $186,325 $ 63,542 $ 0 $20,036 William L. Stewart Senior Vice President- 1992 $202,575 $ 71,703 $ 0 $24,334 $ 6,915 (6)

Nuclear 1991 $192,350 $ 71,085 $ 0 $21,290 1990 $173,175 $ 69,562 $ 0 $19,426 Bill D. Johnson Senior Vice President- 1992 $199,250 $ 72,474 $ 0 $25,167 $106,406 (7)

Finance, Controller, Treasurer 1991 $187,625 $ 72,339 $ 0 $19,106 and Corporate Secretary 1990 $171,175 $ 63,542 $ 0 $16,335

(*) 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.

(1) 1990-1992 Long-term incentive plan; the 788 shares awarded on February 19, 1993 vest 6 months from the date of grant.

(2) Company match on savings plan contribution ($6,866), insurance premium for Directors Charitable Contribution Program ($10,058) and Company contribution to Retirement Benefit Funding Plan ($96,009).

51

- e (3) 1989-1991 Long-term incentive plan; the 773 shares awarded on February 25, 1992 vested 6 months from the date of grant; aggregate number of shares at December 31, 1992 = 0.

(4) Company match on savings plan contribution ($1,147), insurance. premium for Directors Charitable Contribution Program ($11,629) and Company contribution to Retirement Benefit Funding Plan ($95,761).

(5) Company match on savings plan contribution ($6,147) and Company contribution to Retirement Benefit Funding Plan ($48,455).

(6) Company match on savings plan contribution ($5,915) and Company contribution to Retirement Benefit Funding Plan ($1,000).

(7) Company match on savings plan contribution ($5,978) and Company contribution to Retirement Benefit Funding Plan ($100,428).

• Long-Term Incentive Compensation Long-term incentive awards made during 1992 are shown in the following table.

Long-Term Incentive Plans-Awards in the Last Fiscal Year 1992-1994 Performance Achievement Plan

• Estimated Future Payouts Under Non-Stock Price Based Plans

• Performance or Number of Other Period Shares, Units Until Maturation Threshold Target**_ Maximum Name or Other Rights (1) or Payout (#) (#) (#)

James T. Rhodes l,671 3 years 1. (3) 1,671 (3) 2,507 (3)

Thos. E. Capps . 0 (2)

Robert F. Hill 697

• 3 years 1 (3) 697 (3) 1,046.(3)

William L. Stewart 691 3 years 1 (3) 697 (3) 1,046 (3)

Bill D. Johnson 697 3 years - 1 (3) 697 (3) 1,046(3)

(1) Dominion Resources Common Stock (2) Mr. Capps does not participate in this plan.

(3) 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 amount will be earned if at least 81 % of the ROE goal or 99% of the costs per kilowatt-hour goal is a<ehieved. The target awards will be earned at 100% of the ROE goal and 80% of the cost goal. The maximum award will be earned at 110% or more of the ROE goal and 70% or less of the cost goal. Note: For the cost goal, a lower score indicates better performance. Targets and goals for James T. Rhodes were approved by Dominion Resources Organization and Compensation Committee under the Dominion Resources Long-term incentive plan.

52

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.

Estimated Annual Benefits Payable Upon Retirement Credited Years of Service Final Average Earnings 1~ 20 25 30 35

$125,000 $ 33,439 $ 44,586 $ 55,732 $ 66,878 $ 66,878 150,000 40,939 54,586 68,232 81,878 81,878 175,000 48,439 64,586 80,732 96,878 96,878 200,000 55,939 74,586 93,232 111,878 111,878 225,000 63,439 84,586 105,732 126,878 126,878 250,000 70,939 94,586 118,232 141,878 141,878 300,000 85,939 114,586 143,232 171,878 171,878 350,000 100,939 134,586 168,232 201,878 201,878 400,000 115,939 154,586 193,232 231,878 231,878 450,000 130,939 174,586 218,232 261,878 261,878 500,000 145,939 194,586 243,232 291,878 291,878 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 1992 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:

Credited Years of Service James T. Rhodes 21 Thos. E. Capps 22 Robert F. Hill 28 William L. Stewart 22 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 53

- e 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 1992 compensation, the estimated annual retirement benefit for each of the executive officers under the Supplemental Plan would be as follows: James T. Rhodes: $133,684; Thos. E. Capps:

$173,583; Robert F. Hill: $69,233; William L. Stewart: $61,365; and B. D. Johnson: $68,108.

Employment Agreements The Company has entered into employment agreements (the Agreements) with key management executives, including James T. Rhodes, Thos. E. Capps, Robert F. Hill, William L. Stewart 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 of Dominion Resources (as defined in the Agreements), 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.

The Company has entered into an agreement with Paul J. Bonavia that provides his compensation as Vice President-Regulation will include salary and incentive compensation opportunities that are not less than what would have been afforded him had he remained at Dominion Resources. Prior to being elected Vice President-Regulation effective September l, 1992, Mr. Bonavia served as General Counsel of Dominion Resources. Dominion Resources has agreed to reimburse the Company for the difference between the amounts paid to Mr. Bonavia and the amounts that he would have otherwise received under the Company's salary schedule and incentive compensation policies.

Compensation of Directors The non-employee members of the Board receive an annual retainer of $16,500 and a fee of $800 for each Board or committee meeting attended. 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 iosses 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 54

e e 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.

Compensation Committee Interlocks and Insider Participation One member of the Company's Organization and Compensation Committee, William W. Berry was Chairman of the Boards of Directors of Dominion Resources and the Company prior to his retirement on December 30, 1992. William G. Thomas, another member of the Company's Organization and Compensation Committee, is the President of Hazel & Thomas, which provided legal services to the Company during 1992.

ITEM 12. SECURITY OWNERSIDP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below sets forth as of January 31, 1993, 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.

Shares of Common Stock Name Beneficially Owned James T. Rhodes ................ . 5,462 Thos. E. Capps ................. . 28,152(a)

Robert F. Hill .................. . 4,931 William L. Stewart ............... . 2,438 Bill D. Johnson ................. . 10,084 John B. Adams, Jr. .............. . 2,097 William W. Berry ................ . 20,403 Anna Ruth Inskeep .............. . 3,796 Benjamin J. Lambert, III .......... . 0 Harvey L. Lindsay, Jr. ........... . 171 Shirley S. Pierce ................ . 4,462 William T. Roos ................. . 5,934(b)

William G. Thomas .............. . 0 (a) A member of Mr. Capp's family is a beneficiary of a trust that owns an additional 750 shares of Common Stock for which he disclaimed beneficial ownership.

(b) Members of Mr. Roos' family are beneficiaries of trusts that own an additional 3,618 shares of Common Stock for which he disclaimed beneficial ownership.

All current Directors and executive officers as a group (32 persons) beneficially own, in the aggregate, 166,361 shares of Common Stock of Dominion Resources. No shares of the Company's Preferred Stock are owned by the Directors or executive officers as a group.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Hazel & Thomas, provided legal services to the Company during 1992. Mr. William G. Thomas, a director of the Company, is President of Hazel & Thomas.

55

e PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this Form 10-K:

1. Financial Statements See Index* on page 21. *

2. Financial Statement Schedules See Index on page 21.

3. Exhibits*

3(i) -Restated Articles of Incorporation, as amended, as in effect on February 10, 1993 (filed .

herewith under cover of Form SE).

• 3(ii) -Bylaws, as amended, as in effect on April 1, 1989 (Exhibit 3(i), Form 10-Q for quarter year ended March 31, 1989, File No. 1-2255, incorporated by reference).

4(i) -See Exhibit (3(i)) above. *

• 4(ii) -Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentun:s. Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File.No. 1-2255, incorporated by reference; Fifty-Ninth Supplemental Indenture, Exhibit 4(ii), Form 10-Q for the quarter ended March 31, 1986, File No. 1-2255, incorporated by reference; Sixtieth Supplemental Indenture, Exhibit 4(ii), For~ 10-Q for the quarter ended September 30, 1986, File No. 1-2255, incorporated by reference; Sixty-First Supplemental Indenture, Exhibit 4(ii), Form 10-Q for the quarter ended June 30, 1987, File No: 1-2255, incorporated by reference; Sixty-Second Supplemental Indenture, Exhibit 4(ii), Form 8-K, dated November 3, 1987, File No. 1-2255, incorporated by reference; Sixty-Third Supplemental Indenture, Exhibit 4(i), Form 8-K, dated June 8, 1988, File No. 1-2255, incorporated by reference; Sixty-Fourth Suppfementai Indenture, Exhibit 4(i), Form 8-K; dated February 8, 1989, File No. 1-2255, incorporated by reference; Sixty~Fifth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated June 22, 1989, File No. 1-2255, incorporated by reference; Sixty-Sixth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated February 27, 1990, File No. 1-2255, incorporated by reference; Sixty-Seventh Supplemental Indenture, Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference; Sixty-Eighth Supplemental Indenture, Exhibit 4(i), Sixty-Ninth Supplemental Indenture, Exhibit 4(ii) and Seventieth Supplemental Indenture, Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference; Seventy~First Supplemental Indenture, Exhibit 4(i) and Seventy-Second Supplemental Indenture, Exhibit 4(ii), Form 8-K, dated July 7, 1992; File No. 1-2255, incorporated by reference; Seventy-Third Supplemental Indenture*, Exhibit 4(i), Form 8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference; and Seventy-Fourth Supplemental Indenture, Exhibit 4(i), Form 8-K dated February 10, 1993 File No. 1-2255, incorporated by reference. *

• 4(iii). -Indenture; dated April 1, 1985, between Virginia Electric and Power Company and Crestar. Bank (formerly United Virginia Bank) Exhibit 4(i), File No. 2-96772, .

incorporated by reference). **

4(iv) -Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and Chemical Bank (Exhibit 4(i), File No. 33-5763, incorporated by reference).

56

4(v) e

-Indenture, dated April 1, 1988, between Virginia Electric and Power Company and Chemical Bank (Exhibit 4(i), File No. 33-21319, incorporated by reference) as supplemented and modified by a First Supplemental Indenture,-dated August 1, 1989, (Exhibit 4(ii), File No. 33-30532, incorporated by reference).

4(vi) -Virginia Electric and Power Company agrees to furnish to the Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized thereunder does not exceed 10 percent of Virginia Electric and Power Company's total assets.

lO(i) -Operating Agreement, dated June 17, 1981, between Virginia Electric and Power Company and Monongahela Power Company, The Potomac Edison Company, West Penn Power Company and Allegheny Generating Company (Exhibit lO(vi), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-2255, incorporated by reference).

lO(ii) -Purchase, Construction and Ownership Agreement, dated .as of December 28, 1982 as amended and restated on October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(viii), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-2255, incorporated by reference).

lO(iii) ---:Interconnection and Operating Agreement, dated as of December 28, 1982 as amended and restated on October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(ix), Form 10-K for the fiscal year eride'd December 31, 1983, File No. 1-2255, incorporated by reference).

• lO(iv) -Nuclear Fuel Agreement, dated as of December 28, 1982 as amended and restated on

. October 17, 1983, between Virginia Electric and Powet Company and Old Dominion Electric Cooperative (Exhibit lO(x), Form 10-K f9r the fiscal year e;nded December 31, 1983 1 File No. 1-2255., incorporated by reference). . .

lO(v) -Inter-Company Credit Agreement, dated July 1, 1986, as amended and restate.cl as of December 31, 1992 between Dominion Resources and Virginia Electric and Power Company (filed herewith under cover of Form SE). ,

lO(vi) -Credit Agreement, dated December 1, 1985, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xix), Form 10-K for the fiscal year ended December 3'1, 1985, File No. 1~2255, incorporated by reference).

lO(vii) -Agreement for Northern Virginia Services, dated as of November 1, 1985, between Potomac Electric Power Company and Virginia Electric and Power Company (Exhibit lO(xxi), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference).

lO(viii) -Purchase, Construction and Ownership Agreement, dated May 31, 1990, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xi), .Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).

lO(ix) -Operating Agreement, dated May 31, 1990, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xii), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).

lO(x) -Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and tlie Unit 2 Amendment (Volume 1), dated May 31, 1990, between Virginia Electric and Power Company and Old Dominion Electric Cooperative, Westinghouse, Black & Veatch, Combustion Engineering and H. B. Zachry (Volumes 2-11 contain technical specifications only) (Exhibit lO(xiii), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).

lO(xi) -Receivables Purchase Agreem~nt, dated as of December 11, 1991, between Virginia Electric and Power Company and Dynamic Funding Corporation (Exhibit lO(xv) Form 10-K for the fiscal year ended December 31, 1991, File No. 1-2255, incorporated by reference).

57

23(i) e lO(xii) -Description of arrangements with certain officers regarding additional credited years of service for retirement purposes (filed herewith under cover of Form SE).

-Consent of Hunton & Williams (Exhibit 24(i) per Regulation S-K) (filed herewith under cover of Form SE).

23(ii) -Consent of Jackson & Kelly (Exhibit 24(ii) per Regulation S-K) (filed herewith under

• cover of Form SE).

23(iii) -Consent of Deloitte & Touche (Exhibit 24(iii) per Regulation S-K) (filed herewith under cover of Form SE).

• Exhibit numbers may not correspond to those in Item 601 of Regulation S-K because of special requirements applicable to EDGAR filers.

(b) Report on Form 8-K None 58

• 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 THOS. E. CAPPS By~~~~~~~~~~~~~~~~~-

(Thos .. E. Capps, Chairman of the Board of Directors)

Date: February 24, 1993 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 the date indicated.

• Signature Title Date THos. E. CAPPS Chairman of the Board of February 24, 1993 Thos. E. Capps Directors and Director J. T. RHODES President (Chief Executive February 24, 1993 J. T. Rhodes Officer) and Director JoHN B. ADAMS, JR. Director February 24, 1993 John B. Adams, Jr.

WILLIAM w..BERRY Director February 24, 1993 William W. Berry ANNA RUTH INSKEEP Director February 24, 1993

• Anna Ruth Inskeep BENJAMIN J. LAMBERT, III Director February 24, 1993 Benjamin J. Lambert, III HARVEY L. LINDSAY, JR. Director February 24, 1993 Harvey L. Lindsay, Jr.

SHIRLEY s .. ~IERCE Director February 24, 1993 Shirley S. Pierce WILLIAM T. Roos Director February 24, 1993 William T. Roos WILLIAM G. THOMAS Director February 24, 1993 William G. Thomas B. D. JoHNSON Senior Vice President, February 24, 1993 B. D. Johnson Controller and Treasurer (Principal Accounting Officer and Chief Financial Officer) 59