ML18151A244

Forwards Comparative Statements of Income for Three Months Ended 971231 & 1996,internal Cash Flow Projection for CY98 W/Certification by Officer of Company & Annual Rept to Sec on Form 10-K for 1997

ML18151A244
Person / Time
Site:	Surry, North Anna
Issue date:	03/30/1998
From:	Ohanlon J VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:	NRC (Affiliation Not Assigned)
References
98-045, 98-45, NUDOCS 9804080248
Download: ML18151A244 (131)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 March 30, 1998 e

Director of Nuclear Reactor Regulation Serial No.: 98-045 United States Nuclear Regulatory Commission NLOS/MM Washington, DC 20555 Docket Nos.: 50-280/281 50-338/339 License Nos.: DPR-32/37 NPF-4/7 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. Comparative Statements of Income for the three months ended December 31, 1997 and 1996.

2. Internal cash flow projection for calendar year 1998 with certification by an officer of the Company.

3. Statement ensuring availability of funds for payment of

_retrospective premiums without curtailment . of required nuclear construction expenditures.

4. A copy of the Annual Report to Securities and Exchange Commission on Form 10-K for 1997.

In accordance with 10 CFR 140.7, we submitted a check to the NRC for $1,000 on November 7, 1997, which is the minimum required premium for the period November 15, 1997 through November 14, 1998.

Very truly yours,

~9@~

James P. O'Hanlon Senior Vice President - Nuclear Enclosures _ ,,, .~

9804080248 980330 ,__________{~~

PDR ADOCK 05000280 \

I p~ . .*

cc:

U.S. Nuclear Regulatory Commission

• Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, GA 30303 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555 Mr. R. A. Musser NRC Senior Resident Inspector Surry Power Station Mr. M. J. Morgan NRC Senior Resident Inspector North Anna Power Station

PRICE-ANDERSON ACT

• REC'D W?LTR DTD 03/30/98 .... 9804080248

-NOTICE-THE ATTACHED FILES ARE OFFICAL RECORDS OF THE**

OCIO/INFORMATION MANAGEMENT DIVISION. THEY HAVE BEEN CHARGED TO YOU FOR A LIMITED TIME PERIOD AND MUST BE RETURNED TO THE RECORDS AND ARCHIVES SERVICES SECTION, T-5C3. PLEASE DO NOT SEND DOCUMENTS CHARGED OUT THROUGH THE MAIL. REMOVAL OF ANY PAGE(S)

FROM DOCUMENTS FOR REPRODUCTION MUST BE REFERRED TO FILE PERSONNEL.

-NOTICE-

VIRGINIA ELECTRIC & POWER COMPANY STATEMENTS OF INCOME (Unaudited)

Three Months Ended December 31, 1997 1996 (Millions)

Revenues:

Electric service $ 1,000.9 $ 964.4 Other 351.9 73.9 Total 1,352.8 1,038.3 Expenses:

Fuel, net 515.0 261.2 Purchased power capacity, net 175.4 161.5 Operations and maintenance 208.0 209.6 Depreciation and amortization 157.6 126.0 Restructuring 7.3 0.0 Accelerated cost recovery 10.6 62.4 Amortization of terminated construction project costs 8.6 8.6 Taxes other than income 65.1 60.0 Total 1,147.6 889.3 Income from operations 205.2 149.0 Other income 1.9 (2.1)

Income before interest and income taxes 207.1 146.9 Interest and related charges:

Interest expense, net 77.1 75.7 Distribution - preferred securities of subsidiary trust 2.7 2.7 Total 79.8 78.4 Income before income taxes 127.3 68.5 Income taxes 41.9 22.7 Net income 85.4 45.8 Preferred dividends 9.0 8.9 Balance available for Common Stock $ 76.4 $ 36.9

Virginia Electric & Power Company 1998 Estimated Internal Cash Flow (Millions of Dollars)

Jan Apr Jul Oct Estimated thru thru thru thru 1998 Mar Jun .fum Dec Total Cash Receipts $1,472.8 $1,247.8 $1,517.7 $1,416.5 $5,654.8 Less:

Cash for Operations 889.0 812.1 918.7 946.6 3,566.4 Taxes 34.5 191.0 126.1 181.6 533.2 Interest 78.0 66.0 82.6 58.0 284.6 Dividends 111.8 111.6 111.6 111.4 446.4 Deconunissioning Trust 11.9 11.9 11.9 11.9 47.6 Changes in Working Capital 30.6 Q,l 30.2 20.2 80.9 Total Cash Flow (1) $317.0 ~ $236.6 $86 8 $695.7 (1) Before Financing and Construction Requirements.

H:\FPB\PLANNING\1998\BUDGET\DATA\8CASH\Pricefnl.xls 2/25/98

VIRGINIA ELECTRIC AND POWER COMPANY STATEMENT The Company currently estimates 1998 construction and nuclear fuel expenditures (exclusive of Allowance for Funds Used During Construction) to be $588.1 million. Debt maturities in 1997 will total $333.5 million. It is expected that approximately $695. 7 million will be obtained from internal sources. The remaining $225.9 of capital requirements will be obtained by 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 $326.8 million ($81.7 million, including a 3 percent insurance premium tax for Virginia, for each of the four reactors owned by the Company with assessments not to exceed $10.3 million per reactor per year) currently in force.

VIRGINIA ELECTRIC AND POWER COMPANY CERTIFICATE I, the undersigned M. S. Bolton, Jr., do hereby certify, pursuant to the guarantee requirements set forth in the Commission's letter dated June 15, 1977, that the cash flow projection

, for 1998, provided herewith, is based on the best available information known at this time and is a reasonably accurate projection of the Company's 1998 cash flow.

M. S. Bolton, Jr.

Controller Commonwealth of Virginia City of Richmond Sworn to and subscribed before me this :15 day of h\accJA,,, 1998.

Notary Public My commission expires: Cu - 30 ~ C\°'

NOTARIAL SEAL j

SECURITlES AND EXCHANGE COMl\1ISSION

. WASHINGTON, D.C. 20549

Form 10--K (Mark One)

~ .ANNUAL REPORT PURSlJAN°T TO SECTION 13 OR 15(D). OF THE

. SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1997

. or D . . TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(1)) OF THE

• SECURITIES EXCHANGE ACT OF 1934* .

For the transition period from to Commission me 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 (I.R.S. Employer "I

.\ . incorporation or organization) identiffr.ation no.)*

• 701 East Cary Street

. : ,23219-3932 Richmond, Virginia (Zip Code)

(Address. of principal executive offices)

• .. (804) 771-3000 (Regist,:ant's telephone number; including area code)

.~ecurit_ies ~gistered pursua,nt 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, ....

Trust Preferred Securities . N~w York, Stock Exchange

$25 *liquidation valiie:

8.05% dividend

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

~ . None

.'.II\,:,

(Title.of.Class)

• :Indicate by. c.heck n;;ii-k whether fueregistrant (1) h~~ ifii~d all repo~s requireq to be fil~d by, Sectio~ 13. or 15(d) of the .

Securities Exchange A.ct of 19~4 during the preceding 12 .month~ (or for such shorter period that th~ regi~trant was required to.file such reports), and .

(2) has been subject to su9h . filing requirements for.the past-90 days. .

Yes~ No.D

. . 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 of registrant's knowledge, in definitive proxy odriformatioq statements incorporated by reference in Part 111 of this Form 10-K or any am_endment to this Form 10-K 0

. The aggregate market value of the voting stock heid by ~~n-affiliates of the registrant as of .Fej,ruary .

28, 1998, was zero. . .~

.* .As of February 28, 1998, _tQere wer~ issued and-~ut~Janding 171,484 sharea:ot. the registranf s coiiimon stock, without ar value,. all of whi~h were. held., beneficially and. of retqrd, .by Dominion* Resou1ces, Inc: . :,;

• DOCUMENTS INCORPORATED BY REFERENCE. *

• ,,:*None :*

--1

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

1. Business .................................................. **********:*****************.*****.:****************************************************** 1 The Company **************:**************: .......... :............................ :....................................................... . 1 Company Management.................................................................................................................... . 1 Competition and Strategic Initiatives ....... , .... , ..............,.., ....... ; ................ , ..................., ................... . 1' 2

Re!:i:! :: : : : : : : : : : ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::.:::::L::::::::i:::::::::::::::::::::::::::::::

FERC ......................................................................................................................*...............

2 2

3 Environmental ...........................................................

. . . ... ................ :.i.::.:

.,** . .................. :................. . 3 Nuclear ................................... , ................... ;*...... *...................... *., ............................................ . 3 Rates ................ :............... , ..... , ..... *.. *; ................................*....... ,.,*; ........*...................................... . 4

• FERC .................................................................................................................................... . 4 5

~~:~;;~ii~~**:::::::::::::*:::::::*:,::,::*::::::::*:::::::::::::::::::::::::::*::::'.:::::::::::::::::::::::::::::::::::::::'.::::::::::::::::: 6 Capital Requirements and Financing Program ............... *..... :..................... : ....................................... . 6 Construction and Nuclear Fuel Expenditures ................................................. .': .... ,: .. : .................... . 6

. Financing Program **********************,****************************************************:******************-'***********:*:******** 6 '

Sources of Power ....................................................................................'. ................................ ; .... . 7 Company Generating Units .................................................................. : .............. ,.:**:.: ....*...*...... : 7 Net Purchases :............................................................................. *............................. , ..... :... ;... . 7 Non-Utility Generation '. .................. : .............................. , ..............*............................................ 7 Sources of Energy Used and Fuel Costs .............................................. *........................................... . 8 Nuclear Operations and Fuel Supply **********************************************************************************:********* 8 Fossil Operations and Fuel Supply ........................ , ..... :.................................. , ........... : ............... . 8 Purchases and Sales of Energy ..................... ; ........ :......... ;*, ........... :............................................... . 8 Future Sources of Power ............................................................................................. ; ................. . 9 Conservation and Load Management .... : ..................................... .'...... *........... ; .................................. . 9 Interconnections ........................... , ............................................................................................... . 9

2. Properties ......................................................................................... ,., ...*...................................... 10

3. Legal Proceedings ......................... :...................................................... !......................................... . 11

4. Submission of Matters to a Vote of Security Holders ............................ ::.*'.*:**:*:************'. ....................... . 11 PART II

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

6. Selected Financial Data .................................. ,.... *.... , ......................* , ...................*............................. 12

7. Management's Discussion and Analysis of Financial Condition and Results of Operations ......................... . 12 "t/

Liquidity and Capital Resources ............................ , ........ , ... , ........................................................... . 13 ,*'

Capital Requirements .................................................... .' ............................................................... . 14 Results of Operations ... ,.: .......... ;................ *: ............... ,; .. ; ... : .................. ::\ .. ::* ........................ ; ........ *. 15

• Future Issues, ........ , ........................:......... .'................*............ : ........ .,; ......... ;..... :.......... c:.. :... :........ . 17 Market Risk Sensitive Instruments and Risk Management.: ...... :.; ....... : ..............*....... ; ............ ,*.: .......... . 22

8. Financial Statements and Supplementary Data ...................... ;; ... :.................... ;*.......... : ........................ . 24

9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure ......................... . 47*.*

PARTID

10. Directors and Executive Officers of the Registrant ........................ : ....... : ..*.. :........... '. ........... : ....: ... ~ ...... . 48

11. Executive Compensation ................................................................................................................. . 51 12; Security Ownership ,of Certain Be~f1cial: Owners and Management .. ::.,.:*;: ........... :..\ ................... :........ . 55

13. Certain Relationships and Related"Transactions *.. , ............ ;.. i.... :.... :, ...... :................ :; ........... :........ ;..... . 55 PART.JV.

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

PART I

.ITEM* 1. BUSINESS.

THE COMPANY

• Vi~gini~ Ele~tric ,and Power Company is a Virginia Corporation. Our prindpal office is at 701 East Cary Street, Rich-a mond, Virgi~ia 23219~3932, 'telephone (804) 771-3000. We are wholly owned. subsidiary *of Dominion Resources; Inc:

(Dominion Resources), a Virginia corporation. -Dominion .Resources owns..all of our common stock.

• Virginia Electric_ and* Power. Company is a regulated public utility engaged in the generation, transmission, clistribution and sale of electric energy within a 30,000 square-mile area in Virginia *and northeastern North Carolina. It transacts busi-ness under the name Virginia Power in Virginia and under the name North Carolina Power in North Carolina. We have retail customers (including governmental agencies) and wholesale .customers such as rural electric cooperatives, power marketers arid municipalities. We serve more than 80 percent of Virginia's population. The Company has certificates of convenience and necessity from the State Corporation Commission of Virginia (the Vrrginia Commission) for service in all territories served at retail in Virginia. The North_ Carolina Utilities Conirnissioff (the,North Carolina Commission) has assigned terri-tory to the Company for substantially alJ.ofits retail service outside certain municipalities in North Carolina;

' The electric utility industry in th~ UnitecfStal:e~ is undergoingan -*evblutionary change toward less regulation and more competition. To meet ihe challeriges of this new* corripetittve en,v.iroilment, Virginia Power has developed a broad array of "non:traditional" product anq service offerings from its operating business units and subsidiaries: ' '

. . . ~ . . ' . .. *'. . .

• Energy Services - offering electric energy and capacity in the emerging wholesale market as well as natural gas and

()ther energy-related products and services; *

• Fossil & Hydro - targeting process type industries, such as chemkal, paper, plastics and petroleum to become a ser-vice provider of instrumentation equipment;

• Nuclear .Services - offering management and operations services to other ~lectric utilities;

• Comm~n;:ial Operatio~s C providing power distribution related services, including transmission and distribution, engi-neering and metering services to other gas, water arid electric utilities; and '

• Telecommunications - offering telecommunications services through the Company's existing fiber-optic network.

The Company and its subsidiaries had 9,043 full-time employees on December 31, 1997. A total of 3,452 of our employees are represented by the International Brotherhood of.Electrical Workers under a *contract extending to March 31, 1998. The Company and the uniori have tentatively agreed, subject to* ratification by the union membership, to a two year extension of the contract. -

• For a more th~rough review of the changing utility i~dustry and theCmnpany's strategy see COMPETITION AND STRATEGIC INITIATIVES below and Future Issues - Competition under MANAGEMENT'S DISCUSSION AND ANALY-

.. SIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A). .

l '

,.:_. COMP~*MANAGEMENT In April, Dr. .JamesT. Rhodes, President and Chief Executive Officer since 1989, announced his retirement effective August 1, 1997. The Board of Directors .. subsequently *elected Mr. Norman Askew as the new President and Chief Execu-tive Officer, effective*August l, 1997. Mr. Askew was previously the .Chief Executive.of East Midlands Electricity plc, a United Kingdom regional electricity company acquired by Dominion Resources during the first quarter of 1997.

Mr. Askew also replaced Dr. Rhod~s on the Board of Directors effective* August 1, 1997. *.

b * ' * * ' **

• COMPETITIQN.AND STRATEGIC .INITIATIVES.

A number of developments in the United States are causin*g*a trend toward less regpl~tion and more competition in the

_electric utility industry: This is evi~enced by legislative and 'regulatory action at.20th the federal and state levels. To the.

xtent that competition is either authorized or mandated and regulation is eliminated or relaxed, electric utilities may no nge_r be guaranteed an opportunity to reco:ver. all of their prudently incurred costs, and utilities with costs that exceed the arket prices established by the competitive mru;ket wiJI run the risk of suffering losses, which may be. substantial.

1

Virginia Power has responded to these trends by undertaking cost-cutting measures, engaging in re-engineering effort restructuring its core business processes, and pursuing a strategic planning initiative to encourage inn9vative approaches t serving traditional markets. The Company has establi~hed separate business units, as discussed above, to fully execute these strategies. ** * *  :, ,, * * * *

• The.Company .also is vigorously participating in the state and federal legislative actions. c:urrel}tly underw~y to bring about competitioµ in the ~lectric' utility

' ' ',. .. . . ~

industry, in:: ' an effort to .ensure ~ orderly . transition. from a regulated

' ,. . ' *. ' '\

environment.

The Company's non-traditional businesses face competition from a variety of utility and non-utility entities ..

For a .full discussion of the regulatory and legislative issues related to competition;. carefully read the Future Issues sec-tion of MD&A. **

REGULATION General In, a wide variety of matters in addition:to rates, Virginia Power is presently subject to regulation by the Virginia.Come mission and the North Carolina Commission, the Environmental Protection Agency (EPA), Department of Energy (POE),

Nuclear Regulatory Commission (NRC), the Feder~! Energy Regulatory Commission (FERC), the Army Corps of Engineers, and '9th~r federal, statf and iocal authorities. Compliance with numerous laws and regulations increases the Company's operating and *capital costs. by requiring, among other thing~. changes in the design and ..operation of existing faciiities and changes or d~lays in the location, design, coristruction and operation of new facilities. The commissions regulating the Coin-pany' s rates have historically permitted recovery of such costs.

• Virginia Power may not construct, or incur financial commitments for construction of, any* substantial generating facili-ties or large capacity transmission lines without the prior approval of various* state .and federal governmental agencies. Such approvals relate to, among other things, the environmental impact of such activities, the relationship of such activities to the need for providing adequate utility service and the design and operation of proposed. facilities.

• Both federal and state legislative bodies have been studying competition and, restructuring in the electric utility indus try. Please carefully read. the. full discussion of this matter' found in the Future Issues ..::..:_ Competition - Legislative initia tives section of MD&A. . . .. . . .

Virginia

.In 1995, the Virginia Commission instituted an ongoing generic investigatio.n on electric industry restructuring, result-ing in a number ofreports by its Staff covering such issues as,:etaH wheeling experiments and the status of wholesale power markets. The Staff also submitted a report to the General Assembly calling for a cautious, two-phase, five-year period to adclress restructuring issues. The report acknowledged the need for direction from the Virginia legislature concerning policy issues surrounding cm:npetition in the electric' industry. ' ' '

In November 1996, the Virginia Commission instituted a proceeding concerning Virginia Power's cost .of service and ,.

possible restructuring of the electric utility industry as it might relate to Virginia Power. On March 24, 1997, Virginia Power /

filed in that proceeding a calculation of its cost of s~rvice for 1,99.6 and a proposed Alternative Regulatory Plan (ARP). Sub.:::;*

sequently, the Commission consolidated this proceeding with the proceeding concerning the Company's 1995 Annual Infor-mational Filing, in which the Company\s base rates were made interim and subject to refund as of March 1, 1997. Please carefully read the Future Issues - Competition -.Legislative and Regulatory Initiatives sections of MD&A and RATES-Virginia; below for details concerning the ARP, its current status and related legislative developments.

In Dece~ber l 995,* Virginia Power applied to the Virginia Commission for app~oval of arrangements with Chesapeake Paper Products Company (CPPC), urider which Virginia* Power vvould facilitate the design, construction and financing of a cogeneration plant to meet CPPC's energy requirements for its industrial processes at its plant in West Point, Virginia. On August 13, 1997, the Virginia Coinmission approved, in *substantial part; the proposed transactions between Virginia Power an.d CPP(:'s.,successor in ownersjlip, St. Laure.n.t Paper Products Co. St. Laurent later determinecl that the current design of the facili~y was. no longer compatibie.with its long-term busine~s strategies and terminated its contractual arrangement with Y~rginia .Power,

. The.Virginia

. .. . Commissi'8iCdismissed '*

the proce!'.,ding on January 15, 1998.. .. . . . *. .

In June* 1997, the Virginia Commission granted the Company's request to implement a monitoring program that requir certain non-utility generators to provide certain 'information sufficient to determine continued compliance with the "Qual fying Facility" (QF) requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

2

On August 8, 1997, the Virginia Commission granted the Company's request to provide interchange telecommunica-

• ons services and approved the proposed affiliate agreements between Virginia Power and our wholly-owned subsidiary, S Co"mmunications, Inc. (VPSC). Under the authority granted, VPSC will provide a range of telecommunications ser-es, including private line and special access services and high-capacity fiberoptic services.

On September 3, 1997, the Virginia Commission granted the Company's request to provide services to our wholly-owned subsidiary, Virginia Power Services, Inc. (VPS), which would enable Virginia Power Nuclear Services Company (VPN), *a VPS subsidiary, to furnish nuclear management and operation services to electric utilities seeking assistance in the management and operation of their nuclear generating facilities. VPN currently provides such services to Nortneast Utilities at its Millstone Unit 2 nuclear plant.

FERC In April 1996, FERC issued final rules in Order Nos. 888 and 889 addressing open access transmission service, stranded costs, standards of conduct and open access same-time information systems (OASIS). In July 1996, Virginia Power filed an open access transmission service tariff in compliance with FERC's Order No. 888. In compliance with FERC's directive, Virginia Power's OASIS became operational on January 3, 1997. Also, on that date the standards of conduct requiring sepa-ration of transmission operations/reliability functions from wholesale merchant/marketing functions became effective. The Company also made filings to comply with FERC's directive that, effective January 1, 1997, utilities could no longer make bundled sales of transmission and generation services in economy energy transactions. In certain of those filings, Virginia Power canceled or committed not to use the economy energy rate schedules contained in interconnection agreements with neighboring utilities. On March 4, 1997, FERC issued Order Nos. 888-A and 889-A, which addressed requests for rehear-ing of Order Nos. 888 and 889. Orders No. 888-A and 889-A essentially reaffirm the basic principles of 888 and 889 and clarify and make limited modifications to those orders. On December 17, 1997, FERC issued Order Nos. 888-B and 889-B.

FERC rejected all requests for rehearing filed with respect to Order Nos. 888-A and 889-A and clarified and made limited

• modifications to those orders. Several parties have appealed the 888 orders to the United States Court of Appeals for the District of Columbia Circuit.

For a discussion of the status of the Company's Open Access Transmission Tariff filing, see RATES - FERC below.

For additional discussion of open access issues see Future Issues - Competition under MD&A.

LG&E Westmoreland Southampton owns a cogeneration facility in Franklin, Virginia, and sells its output to Virginia Power. Southampton has sought a waiver of FERC operating requirements for Qualifying Facilities (QF's) under PURPA, however FERC refused to grant such a waiver. On March 31, 1997, the United States Court of Appeals for the District of Columbia Circuit granted FERC's motion to dismiss Southampton's Petition for Review.

Environmental From time to time, Virginia Power may be designated by the EPA as a potentially responsible party (PRP) with respect to a Superfund site. As a result of that designation or other regulations regarding the remediation of waste, we may become

' obligated to fund remedial investigations or actions. We do not believe that any currently identified sites will result in sig-nificant liabilities. For a discussion of the Company's site remediation efforts, see Note Q to the CONSOLIDATED FINAN-CIAL STATEMENTS.

Permits under the Clean Water Act and state laws have been issued for all of the Company's steam generating stations now in operation. These permits are subject to reissuance and continuing review. The Clean Air Act, as amended in 1990, requires the Company to reduce its emissions of sulfur dioxide (S0 2 ) and nitrogen oxides (NOx)- Beginning in 1995, the S0 2 reduction program is based on the issuance of a limited number of S0 2 emission allowances, each of which may be used as a permit to emit one ton of S0 2 into the atmosphere or may be sold to someone else. The program is administered by the EPA.

For additional information on Environmental Matters, Clean Air Act compliance and related issues see the Future Issues section of MD&A.

Nuclear All aspects of the operation and maintenance of the Company's nuclear power station"s are regulated by the NRC.

erating licenses issued by the NRC are subject to revocation, suspension or modification, and operation of a nuclear unit y be suspended if the NRC determines that the public interest, health or safety so requires.

3

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In man*y cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintain-ing the Company's nuclear generating units.

In July 1995, the Virginia Commission instituted an investigation regarding spent nuclear fuel disposal. As directed, Virginia Power and others filed comments on legal and public policy issues related to spent nuclear fuel storage and dis-posal. In February 1996, the Commission Staff filed its Report recommending that adoption of a definitive policy on spent nuclear fuel disposal issues be delayed pending the outcome of litigation against the Department of Energy concerning spent nuclear fuel acceptance, the outcome of proposed federal legislation concerning development of an interim storage facility, and development of a vision of the likely outcome of the electric utility industry's restructuring efforts. The Virginia Com-mission consolidated the proceeding with Virginia Power's pending fuel cost recovery proceeding in October 1996. On March 20, 1997, the Virginia Commission returned the spent nuclear fuel disposal issue to a separate proceeding.

On January 31, 1997, Virginia Power joined thirty-five other electric utilities in filing a petition in the United States Court of Appeals for the District of Columbia Circuit, seeking to compel DOE to comply with .its obligation to begin accept-ing the utilities' spent nuclear fuel for disposal by January 31, 1998, the date imposed by the Nuclear Waste Policy Act.

Additional utilities have joined since the original filing. On November 14, 1997, the Court issued an Order finding that DOE's obligation to begin accepting spent nuclear fuel by the deadline is unconditional, and that DOE may not excuse its delay on the grounds that it has not prepared a permanent repository or *interim storage facility. The Court found that DOE's spent fuel disposal contracts with the utilities offer a potentially adequate remedy for DOE's failure to meet its obligation.

DOE filed a petition for rehearing on December 29, 1997.

RATES The Company's electric services sales were subject to rate regulation in 1997 as follows:

1997 Percent Percent of or Revenues Kwh Sales Virginia retail:

Non-Governmental customers ................... . Virginia Commission 81% 76%

Governmental customers .......................... . Negotiated Agreements 10 12 North Carolina retail .................................. . North Carolina Commission 5 5 Wholesale -Sales for Resale* ...... ! ............. . FERC 4 7 100% 100%

• Excludes wholesale power marketing sales subject to FERC regulation.

Substantially all of the Company's electric service sales are subject to recovery of changes in fuel costs either through fuel adjustment factors or periodic adjustments to base rates, each of which requires prior regulatory approval.

Each of these jurisdictions has the authority to disallow recovery of costs it determines to be excessive or imprudently incurred. Various cost items may be reviewed on occasion, including costs of constructing or modifying facilities, on-going purchases of capacity or providing replacement power during generating unit outages.

FERC In compliance with FERC's Order No. 888, Virginia Power filed an open access transm1ss1on service tariff, which became effective on July 9, 1996. In October 1996, FERC issued a procedural order, scheduling a hearing for April 28, 1997.

The Company and all parties reached a settlement of issues raised in the proceeding, and on March 20, 1997, those parties jointly filed with FERC the Settlement Agreement and Motion to Certify the Settlement Agreement. On April 23, 1997 the presiding Administrative Law Judge certified the Settlement Agreement to the FERC and on June 11, 1997, the FERC approved the settlement.

In compliance with FERC's Order No. 889, on January 3, 1997, the Company filed its Procedures For Standards of Conduct for Unbundled Transmissions and Wholesale Merchant Function (Standards of Conduct) effective on that date. On July I, 1997, the Company filed an amendment to the Standards of Conduct in Compliance with FERC's Order No. 889-A.

4

n July 16, 1997, the Company filed another amendment in response to a FERC Staff request. The Company is awaiting

• RC action on the f,iling.

• On September 11, 1997, FERC authorized the Company to sell power at market-based rates but set for hearing the issue of the impact of ariy transmissi~ri constraints on Virginia Power's ability to exercise generation market power in localized areas within its service territory. If FERC finds:that transmission constraints give Virginia Power generation dominance, ir could either revoke or limit the scope of the market~based rate authority. The hearing is sched.uled to commence June 2, 1998; . . .

On October 31, 1997,'Virginia Pow~r filed at FERC three agreement~ with Old Dominion Electric Cooperative (ODEC) to amend the parties' Interconnection and Operating Agreement (I&O Agreement) and to unbundle transmission services provided to ODEC under the I&O Agreement. On December 22, 1997, FERC issued a deficiency letter with respect to the filing directing the Company to provide additional inforniation. On January 21, 1998; the Company provided the requested information. FERC accepted the agreements on March 12, 1998.

Virginia In March 1997, the Virginia Commission issued an order that Virginia Power's base rates be made interim and subject to refund as. of March 1, 1997 . This order was .the*-result cif the Commission Staff's report on its review of Virginia Pow-er's 1995 Annual Informational Filing, which concluded that Virgjnia Power's present rates would c.ause Virginia Power to earn in excess of its authorized return on equity. The Staff found that,.for* purposes of establishing rates prospectively, a rate reduction of $95.6 million (including a one-time adjustment of $29.7 million to Virginia Power's deferred capacity balance

, at December 31, 1996) may be necessary in order to realign rates to the authorized level. Virginia Power filed its Alterna-tive Regulatory Plan in March 1997, based on 1996 financial information. Subsequently, the Commission consolidated the proceeding concerned with the 1995 Annual Informational Filing with the proceeding that includes the ARP pr~posed by the Company.

In December 1997, Virginia Power sought to withdraw its ARP, having concluded that resolution of the cost recovery issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that the Company may withdraw its support of the ARP but has reserved the right to continue consideration of the ARP .as well as other regulatory alternatives. In addition, the Commission will continue to consider the issues arising out of the 1995 Annual Informational Filing. The Commission's Staff is scheduled to file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A public hearing is scheduled to.commence on May 19, 1998. . .

Virginia Power's previous filings in this proceeding support maintaining the Company's rates at current levels; how-ever, opposing parties have made filings recommending rate reductions in excess of $200 million. At this time, management cannot predict the ultimate outcome of the proceeding and its impact on the Company's results of operations, cash flows or financial position.

In July 1996, Virginia Power .proposed to substantially reduce the rates paid under Schedule 19 to cogenerators and small power producers of 100 kW or iess.' The rates became effective on 'an interim basis on January 1; 1997. On Janu-ary 2J, l998, the Virginia Commission approved revised Schedule 19 rates. The. approved rates do not differ in any signifi-cant way from the rates originally proposed by the Company.

In October 1996, Virginia Power filed an application with the Virginia Commission to increase its fuel factor from 1.299 cents per kWh to 1.322 cents per kWh, reflecting a fuel factor annual revenue increase of approximately $48.2 mil-lion. The increase became effective on an interim basis on December 1, 1996. On June 11, 1997, the Commission entered an Order Establishing Fuel Factor approving the requested increase.

On October 31, 1997, Virginia Power filed with the Virginia Commission its application for a reduction of $45.6 mil-lion in its fuel cost recovery factor for the period December 1, 1997 through November 30, 1998. The reduction became effective on an interim basis on December 1, 1997. Subsequently, as a result of amendments to two non-utility power pur-chase contracts, the Company proposed two additional reductions of approximately $30.2 million and $18 million for the same period, bringing the total proposed fuel factor reduction to $93.8 million. Both atlditionai reductions were approved on an interim basis, effective March 1, 1998. A hearing is scheduled for April 9, 1998.

' 5

North Carolina On November 4, 1996, the Company filed for approval of a new Schedule 19 which governs purchages from cogenerators and small power producers. The Company proposed rates substantially lower than those previously specified.' It also pro-posed to reduce the applicability threshold to 100 kW.and shorten the maximum term-of contracts under Schedule 19 to five years. On June 19,. 1997, the North Carolina Commission issued an Order requiring the Company to offer long-term (5-,10-and 15-year) levelized capacity payments to* hydroelectric and certain landfill and waste facilities contracting for up to 5 MW; a 5-year levelized rate option to other QFs contracting for up to 100 kW; and optional long-term levelized energy payments for QFs rated at 100 kW or less capacity.

On October 10, 1997 the Company fil~d an application with the North Carolina Cqmmission for a $728,000 increase in fuel revenues. On December 29, 1997, the North Carolina Commission entereq an Order Approving Fuel Charge Adjust-ment. The Order.approved an approximate $600,000 increase in the annual rates and *charges paid by the retail customers of North Carolina Power effective on January 1, 1998.

CAPITAL REQUIREMENTS AND FINANCING PROGRAM Construction and Nuclear Fuel Expenditures Virginia Power's estimated construction and nucl.ear fuel expendifores for the three-year p~riod 1998-2000, total $1.5 bil-lion'. It has adopted a 1998 budget for construction and nuclear fuel expenditures as set forth below:

Estimated 1998 Expenditures (millions)

Pro.duction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 60 Technology ................. '. ...... :.... *................................ .'. .' ........... .'.:...................... 150 General Support Facilities .... ,........... .. .................. .. .................... ...... ....... ........ 19 Transmission ............................................................................................... :. 37 Distribution .............................. , ............................................ , . . . . . . . . . . *. . . . . . . . .. . 213 Nuclear Fuel -....................... .-,,.-..... , ......... :................................. : ................ ,... 86 Total Construction Requirements *and Nuclear Fuel Expenditures ......... .-. . . . . . . . . . . . . $565 In *addition; the Company expects to incur approximately $23 million of expenditures in 1998 in connection with the development of energy management projects for customers. Contracts with such customers provide for the recovery of these costs in future years.

Financing Program The Company currently has three shelf registrations on file with the Securities Exchange Commission (SEC) provid-ing the Company with $915 million of debt capital r~sources. The Company also has a Preferred Stock shelf registered with the SEC for $100 million in aggregate.principal amount, which has not been utilized. -

The Company intends to issue securities from time to time to meet its capital requirements, which include $333.5 mil-lion of long-term debt maturities in 1998 ..

Please see the Liquidity and Capital Resources section of MD&A for details about our Financing Program.

6

SOURCES OF POWER.

Company venerating 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 1,602 North Anna Units 1 & 2, Mineral, Va ...... : ........................ . 1978-80 . Nu.clear 1,790(a)

Total nuclear stations ................................................. . 3,392 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 Clover Units l .& 2, Clover, Va.................................. . 1995-96.

• Coal 882(b)

Mt~ Storm Units 1-3, Mt. Storm, W. Va.; ....................... . 1965-73 Coal 1,587 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 929 Yorktown Unit 3, Yorktown, Va ........ : ....*..................... . 1974

• Oil& Gas 818 North Branch Unit 1, Bayard, W. Va. . ......................... . 1994 Waste Coal 74(c)

Combustion Turbines:

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

Bellmeade, Richmond, Va. . ... :............ , .......................... . 1991 Oil & Gas 230 Chesterfield Units 7 & 8, Chester, Va. . ........................... . 1990-92 . Oil & Gas 397

' Total fossil stations ...... : ............. '. ............................... .

Hydroelectric:

Gaston Units 1-4, Roanoke Rapids, N.C ......*...... :............. .

Roanoke Rapids Units 1-4, Roanoke Rapids, N.C. ............ .

Other .......................................................................... .

Bath County Units 1-6, Warm Springs, Va....................... .

1963 1955 1930-87

.l985 Conventional.

Conve,ntional Conventional Pumped Storage 8,656 225 99 3

l,260(d)

Total hydro stations ................................................... . 1,587 Total Company generating unit capability ..................... . 13,635 Net Purchases ................................................................ . 1,480 Non-Utility Generation ................ ;........... *.. , .................... . 3,277 Total Capability .. ; ................ :.... .".. , ............................ . 18,392 (a) Includes an undivided interest of 11.6 percent (208 MW) owned by ODEC.

(b) Includes an undivided interest of 50 percent (441 MW) owned by ODEC.

(c) Effective January 25, 1996, this unit was placed in a cold reserve status.

(d) Reflects the Company's 60 percent undivided ownership interest iri the 2,100 MW station. A 40 percent undivided interest in the facility is owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc (AE).

The Company's highest one-hour integrated service area summer peak demand was 14,537 MW on July 28, 1997, and an all-time high one-hour integrated winter peak demand of 14,910 MW was reached on February 5, 1996.

' 7

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 MD&A. . .

Nuclear Operations and Fuel Supply In 1997, the Company's four nuclear units achieved a combined capacity factor of 91.1 percent.

. The Company utilizes both long-term contracts and spot purchases to support its needs for nuclear fuel. The Company continually evaluates worldwide market conditions in order to ensure a range of supply options at reasonable prices. Cur-rent agreements, inventories and spot market availability will support the Company's current and planned fuel supply needs for fuel cycles throughout the remainder of the 1990's and into the early 2000's. Beyond that period, addition'al fuelwill be purchased as required to ~nsure optimum cost and inventory levels .

. The DOE is not expected to begin the acceptance of spent fuel in 1998 as specified in the Company's contract with the DOE. However, on-site spent nuclear fuel storage at the Surry Power Station (spent fuel pool and dry cask storage) is expected to be ~dequate for the Company's needs until the DOE begins accepting spent fuel. The North Anna Power Sta-tion will require additional spent fuel storage capacity in 1998. The Company submitted a license application to the NRC in May 1995 for a dry cask facility at North Anna. The Co.mpany anticipates that this' application' will *be approved in mid-1998.

. For details on the issues. of decommissioning and nuclear insurance, see Note C to the CONSOLIDATED FINANCIAL STATEMENTS.

Fossil Operations and Fuel Supply The Company's fossil fuel mix consists of coal, oil and natural gas. In 1997, Virginia Power consumed approximately 13 million tons of coal. As* with nuclear fuel, the Company utilizes both long-term contracts and spot purchases to support its needs. The Company presently anticipates that sufficient coal supplies at reasonable prices will be available for the remainder of the 1990's. Current projections for an adequate supply of oil remain favorable, barring unusual international events or extreme weather conditions which could affect both price and supply.

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 con-sumed during the colder months when gas supplies are not available at favorable prices. The Company has firm transporta-tion contracts for the delivery of gas to the combined cycle units. Current projections indicate gas supplies will be available for the next several years.

Purchases and Sales of Energy Virginia Power relies on purchases of power to meet a portion of its capacity requirements. The Company also makes economy purchases of power from other utility systems when it is available at a cost lower than the Comp11ny's own gen-

• eration costs.

Under contracts effective January 1, 1985, Virginia Power agreed to purchase 400 MW of electricity annually through 1999 from Hoosier Energy Rural Electric Cooperative, Inc. (Hoosier), and agreed to purchase 500 MW of electricity annu-ally during 1987-99 from certain operating units of American Electric Power Company, Inc, (AEP).

The Company has a diversity exchange agreement with AE under which AE delivers 200 MW to Virginia Power in the summer and Virginia Power delivers 200 MW to AE in the winter..

0 Virginia Power also h as 57 non-utility power purchase ccintracts with a combined dependable summer capacity of 3,277 MW (for information on the financial obligations under these agreen1ents see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS). In. a continuing effort to mitigate its exposure to above-market long-term purchased power contracts, the Company is evaluating its long-term purchased power contracts and negotiating modifications to their terms, including can-cellations, where it is determined to 'be economically advantageous to do so.

The Company's wholesale power groµp actively participates in the purchase and sale of wholesale electric power and natural gas in the open market. The wholesale power group has expanded the Company's trading range beyond the geo-graphic limits of the Virginia Power service territory, and has developed trading relationships with energy buyers and sell-ers on a nationwide basis.

8

- J In July 1997,)he,c;ompany ~xecuted three. agreements Vl'.ith oid.Dominfoµ Electric Cooperativ~ (ODEC). which ,pro~*

. :vide* for the amendment of the. partielinter'corp;iectiori ,.and Operating J\greemen,t (I&O Agreement). ;The first agr:eement .

provides for,the transition from cost-based rates for capacity and energy purchases by ODEC to market-based rates by *2002.

The sec<?nd two agreements are* the Service and Operating 'A,greements' for Net~ork Integratfon Transmission Service, which .

iinbuhdled the 'transmiss1oii services provided to' ODEC uridei:the I&b Agreement. . . . ,: . .. . . . * '.

,, * .* , 1* ,. j > ,'. *; _ ,<, i , ' ,: , .. ' ,*. ' , . . .: '*:  : ;, . , .:.,,_' . .-*: I,*./: ' '. , ~. \ *' '

JrtJTUI_IB SOURCES. of PO~R Afreported earlier, both the Ho'osier 400MW long-tehn purchase'and the AEP 500 *MW Iong~tenn purchase will expjre

. on* December 31'; 1999. The Company prese,ntly anticipates adding peaking :capacity- beginning in 'the. year 2000' to meet its

• anticipated load growth~ The Company has**iuid will pursue capacity acquisition 'plans to provide 'that capacity and maintain a high 'degr~e-' of ,service reliability.* This 6apacity may be owned .and operated by others *and soid to the, Company* or may

.. be built'.by the Corilpariy if it aeterinines it can build capacity*at a loweroVerall cost.'The Company ltlso pursues conserva-

• tiofr and demand7side *management. (see CONSERVATION AND*LO.AD MANAGEMENT below). No Company~owned

.': generation is currently in. the planning br construction 'stages/ ' ',.* ' ' '

' 'For,a,dditional: illformation, see Not,e

• "* ,.J:, I ", * * " 0

• _.' *,

Q to. the CONSO~IDATE~ FIN~CiAL STATEMENTS.'.

CONSERVATION *.* ,. -

AND .LOAD MANAGEMENT

• . - . ._. . ~;*. r .,. .. *, , : 1 ,. *

• . * . The Company is cpmm:itted to *evaluating and selecting demand-side and. supply-side options on a .cmisistentbasis in

• order to provide reliable,. Iow~c*osf.'service ,to ;its customers. Cons~rvatioii and load: management programs' are evah,iated

'annually at Virginia Power thro'ugh a resource:planning process that. directly compares the stream of costs and benefits from supply-side and demanci~side. options. This process supports a. conservation and load management portfolio 'which contrib-

. utes 'both to the selection oflow-cost resources to m~et the future electricity needs of the Company's customers, as well as the efficient use of current'resoutces. ' .

Events in _the evolving electric power m~ketplace and its regulatory and legisl~tive environment continue to imp~ct utility~sponsored conservation* and.load management.programs: in th~ future,' *the Company anticipates a *greater reliance on

• . the use* of price signals to convey -information* fo. our customers* regarding energy,-related c(_)sts,. resulting in .more efficient purchase decisions; ,: - '

IN~J<

RCONNECTIONS_.

The Comp~riy maintains major interconnections with Carolina)?o.wer ancl Ligqt Company; AEP, AE and the: utilities in the Pennsylvania-New Jersey-Marylancl Power Pool. Through .this major transmission network, t\}e Company 11,as ~ange-ments with these utilities for coordinated planning, operation, elD:ergency assistance and' exchangf;!S of .cap::icity and energy.

In December 1996, _the C~mpany joined with-Allegheny Po*wer Service Corporation, Cleveland Electric *Illuminating C(?mpany, Toledo Edison Company, Ohio Edison Company,. Pennsylvania Power Company and Southern Company Services, Inc.* (the Transmission Alliance) to 'file -~ contract. with .the FERC entitled. the GAPP Experiment Participation Agreement

'(GAPP Agreement). The Tran~missi6n. Alliance and the GAPP Agr6ement 'Jere established',to promote fair and equ,ita~.le, .

use ()f the. transm{ssion systeinr h3:sed on the ,General Agreement ori Parallel Paths. (G;APP) model .f9r co'on;Iii1atiiig the flow of bulk supplies of electricity among utilities. GAPI' principles allow eiectric companies to. determine. where electricity actu-ally flows in bulk'power tra~sac:tion's,.'as opposed to the, .contract" path{that are 6ased .oh power purchase and transmission

!greernents am:orig 'buying,' selling' and tra~sn'iitting utilities: . ' , . ' . ' ' '. . ' ' '

. . .' .. *' '.  : .-* .' . . ' . . .~ . .. . . ' ; . . ... ,'  :., ; - .

-. Compensation for* transmission services has *historically *been based ~~ contract p,aths. The GAPP Agreement was designed to deternrine the physic~} path electricity actually ta)<:es thrmigh the system and allocate open access transmission revenues an1ong .~he parties. The. GAPP Agreement 'was. designed as an experiment to .test the GAPP methods* a,nd proce-dures for' a period of two years. The FER'C accepted the contract on.March 2'5; i997. The Company and*the Transmission Alliance implemented the GAPP Agreement on April2, 1.997. * * * * *

• On November 14, 1997, in accordanc:e \vith' the FE.RC' brder a~cepting the 'GAPP Agr~emerit, the Transmission Alli-ance issued a report detailing the results of the first six months of the experiment. The preliminary results of the experiment*

indicate that it is technically possible to monitor and predi'ct the physical flow o{ electricity over multiple ~ystems and that transmission revenues reallocated according to actual use of the system*differ .significantly from collections under*a contract l

path approach. In*October 1997, Virginia Power gave notice to the Transmission Alliance that, effective January 1, 1998, i was exercising its. option under the GAPP Agreement to terminate its involvement in the experiment.,

On Dece~ber 9, 1997, the Company, the Traiismis~ion Alliance and other utilities ~greed to ~tudy the ~re~tio11 of an independent regional transmission entity. The memorandum of understanding to initiate this study was s1gned by elyven investor-owned electric companies, including Virginia Power, Consumers Energy, Detroit Edison, Duquesne Light Company, The Illuminating Company, Ohio Edison Company, Pennsylva!}ia Power Company, Toledo Edison Company, and the Allegheny Energy Companies (Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company). This group is an outgrowth of the GAPP Agreement and its key goals are to maintain the long-term reliability and security of the utilities' interconnected transmission systems; ensure the most efficient use of resources; eliminate pancaking of rates within

. and.between transm.ission entities; avoid duplication of costs .and.achieve tr.an~mission cost savings; and, strike an appropri-ate balance among the diverse interests of energy suppliers, customers, and shareholders .. The group will also explore coop-erative agreem1::nts designeq to*achieve these goals while ensuring nondiscriminatory and comparable access to all users of

, the group's transmission system. The companies intend to be responsive to industry c:hanges, especially with the introduc-tion of retail competition in some of the areas served by the signatories and as some other industry participants consider creation of independent transmission operating companies or separate transmission companies. Further, the companies will have the flexibility to continue to investigate and pursue other opportunities and arrangements that could develop regarding independent system operators or independent transmission companies.

• Virginia Power and Appalachian Power Company* (AEP-Virginia), an operating unit of AEP, each sought approval from the SCC in 1991 to construct certain interconnecting transmission facilities. These applications resulted from a joint plan-ning effort of Virginia Power and AEP to meet the i;equirements of their customers. At. the time of Virginia Power's .appli-cation, particularly during the summer of 1992, constraints were being experienced on. transfers of power_ into the Virginia '

Power service territory from the west On November 7, 1997, the SCC issued an Order directing the Company to report to the Commission on the continued need for certain new interconnected transmission facilities, on the ,i;elationship between the Company's application to build the new facilities and certain other pending proceedings, and on the Company's con-

• struction plans, if the SCC grants the ~ompany's application.

On December 15, 1997, the Company filed a report in compliance with the SCC.Qrder stating that since the filing of the* Company's application, the constraints .have been less frequent, due in part to less severe summer weather, and actual power requirements have been less than originally forecasted. In addition, generating resources within the Virginia Powf!r service area have been increased by the higher performance level of the nuclear units, as well as the completion of the Clo-ver Station. Completion of the AEP project is a prerequisite for the Virginia Power project to go forward. The proposed Vir-ginia Power project would not fulfill its intended purpose without the AEP line being built. AEP has withdrawn its odginal

• application and has instituted a new proceeding before the Commission in which different routing is proposed. Virginia Power continues to monitor closely the progress of AEP in this proceeding with .respect-to its new proposal, but until more is known about these proceedings, Virginia' Power cannot predict *what its* construction' plans will be.

ITEM 2. PROPERTIES The Company owns its principal properties.in fee (except as indicated below), subject to defects arid encumbrances that do not interfere materially with th~ir use. Substantially all of its property is subject to the lien of a mortgage securing its First and Refunding Mortg~ge Bonds. Right-of-way grai;its from the apparent owners of real estate have been obtained for most electric lines, but underlying titles have not been examined except for transmission lines of 69 Kv or more.. Where rights* of way have not been obtained, they could be acquired from private owner_s by condemnation if necessary. Many electric lines are on publicly owned property, as to which permission for use is generally revocable. Portions of the Com-pany'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 the CONSOLIDATED FINANCIAL STATE-MENTS. *-

See Company. Generating Unjts under SOURCES OF POWER under Item l- BUSINESS.

t IO

i-ITEM 3. LEGAL PROCEEDINGS From time to time, the Comp'any is alleged to b~* iri violation or in default under orders, statutes, rules or regulations relating to 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. From time to time, there may be administra-tive proceedings on these matters pending. In_adc:lition, in the. normal course of business, the Company is. involved in vari-ous legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the Company's financial position, liquidity or results *of operations.

In December 1995, two civil actions were filed in the Virginia Circuit Court of the City of Norfolk against the City of Norfolk and Virginia.Power, one for $15 million and one for $3 million, by property owners who each alleged contamina-tion of their respective properties by hazardous substances originating on nearby property now owned by the city and for-merly owned by the Company. In reference to the $15 million_action, th(? parties reached a settlement prior to the scheduled August 18, 1997, trial date. The related action by the other property owner seeking $3 million is still pending, but has not yet been scheduled for trial.

On April 2, 1997, Doswell Limited Partnership (Doswell) filed a motion for judgment against Virginia Power in the Circuit Court.ofthe City of Richmond. Doswell is an independent power producer that has entered into two power purchase agreements with Virginia Power and claims the Company breached one of those agreements. On the same date, Doswell

• also *filed a complaint against Virginia Power in the United States District Court for the Eastern District of Virgiriia alleg-

. ing certain claims relating to the two power purchase agreements. In March 1998, the parties agreed that both proceedings should be stayed. in* order**to give the parties an opportunity to negotiate amendments to the power purchase agreements. .:

. ITEM 4. SUBMISSION OF MATTERS 10 A VOTE OF SECURITY HOLDERS On October 17, 1997, by Consent of the Sole Shareholder, Dominion Resources, Inc., the number of Virginia Power Directors was expanded to a maximum of eighteen (18) and the following Directors were. elected to serve for terms expir-ing at the annual shareholder meetings for the years in'dicated below: * *

• John B. Bernhardt 2000

• John W. Harris 1998 Kenneth A. Randall 1999 Frank S. Royal 1998 Judith B. Sack 1999 S. Dallas Simmons 2000 David A. Wollard 1999 11

ITE~ 5. MAR~T,FOR, T~E ~GIS'.f~T:s ~o~p~E9UITY,, i;'

' . .AND RELATEO..STOCKHOLOER MATTERS,***

. *  : . t . '-. * ,.. ,-,* ( *- .,* .* ',, ,,v .,., ' ' .

... . *.:*'J::

r,  :'r(_**

All of the Company's Common Stock is*owi:J.ed'b'.fDoririiiion.Resoui-6es,

~~. . its: t~mmo*d:

' { ' -~ ,, '*

The Company paid quarterly cash divid~~d!/ ~ : . ' .. ~ .

~~~cI ,*

as follo~s.:

~ . .. .

,*,1st.*. *c'2nd. *,3.rd' ,.'4th. :", .: '

'*: * (Millioris)( . . :* *: i,:; >.,*,>;

1997 ........... *................... *.'....... *....... ; ....... : ......... , .... , ...... *., ;..... J; :*i '$95.9 ', $93.4 . $94.i ;($95.9 : ..

.- 1996 i; :. : :.1.;:. :'...... ::.. ,..... : .. , .. .. :;. '.: ;';.: .:. -:: ..... .'.:.:. ;:,.:. !.. , : .'... -::: ... :: .*.:i..* $95;3;, ! $96:5 ' $96. l >: *,;$'97.9 ' '

ITEM 6. SELECTED FINANCIAL DATA '

1997 , 1996 1995 , * .1993 (Millions, except percentages), '

, .. . .) , . .-. , . , ~- . . , : , . , -. . , . . . . . /.T,: . . , .**: *.

Re~enues

.  :.::.. *: .........':.'..... . $ 5,0,79.0 ..;. $ 4,420.9. $. 4,35L9 .. , $ .4;170.8 . $, 4,1$7.3

. Income from *operations ........... .'.......................... .'...... *" *

• i'.019.f.* * . 1.010,.0 *. , 911,(. :*: : js1.1 * .::

• 1.o-zq,6

\.

N~t i~come.. :..:.:,**************... :.', ... '. ... , .....:.'., ... :,.:.:*.. :: .. ::.,: * *;,}!59.1 . ~57)' .432.8. ',. ':.;447)'.. ,509.0 Balance available for Common Stock ................ : ... :... : .

• 433.4 421.8 ' 388.7:

• 404.9 466.9 Total assets .......................... : ....... '.,.*................ , .. , .. , .. *.. Jl,953;4, . 11;828.0 11,827.7, 11,647,9, *

• 11;520:5 Total net utility plant ...................... .'.: .... , .. : ............ '. .. * 9;219.2 : 9,43:fis' 9,573.1 ' ' 9,623.4 9,459.7

. Long-term debt, noncurrent-,capital lease ob)igations;-  ;. *; ~ */.

preferred stock subject to mandatory redemption a11d . . I ' ' ~, *

• I* *

• preferred securities of subsidiary trust ......... ; ........... . 3,854.4 ' 3,916.2 4,228.0 4,'157.5 4,151,1 Utility plant expenditures (including nuclear fuel) ........ . '481'.8 '484.0' 577'.5'* 660'.9 712.8.

Capitalization ratios (percent):

Debt ...................................... , ........ ;;:*:................ . 45.:4. ';, 46.4 47.2 46:7 46.4 Preferred stock ......... :.... :............ :.... ::....,:............... . . ' *~

7,6 7.5 7.'5 9~0 9.2 Preferred securities .................. :........*:, ..... :............ . '1.5 1.5 1.5 Common equity .......................... : ... ,,.,*; ......... , .... ,. .4~.5 44.6 43.8 44.3 44.4 Embedded cost (percent):

• Long-term debt .: .... : ................,. ......... :****........... .' .. . .* 7.60*., 7.68 7.73 .7.65 7.67 Preferred stock ............... :............................. : ....... . 5.25 5.14 5.29 5.47 4.88

• Pref~rred securities ..... ,,. .... '. .................... *....... ,., .... . 8.72 8:72. 8.72 Weighted average ................................................. . 7.29 7.34 7.41, 7.29 7.18

. JTEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This Management's Discu~sion and Analysis of Financial Condition and Res1:1lts of Operatioriitc~ntains \~for~ard-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including (without.limitation) dis-cussions as to expectations, beliefs, plans,' objectives and:future financial performance, or assumptions underlying or con-cerning matters discussed in this *documerit. These discussions, and any other discussi~ns, including* _certain contin'gehcy

. matters (and their respective cautionary statements) discussed elsewhere in this. report; that are not historical* facts, are

• forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions and uncertainties that could cause actual results or outcomes to differ materially from thos~ expressed in the forward-looking state~ents. .

Some important factors that could cause actual res.ults or outcomes to differ m~terially from 'those discussed in the forward-looking statements include.current governmental policies and regulatory actioris (including those ofFERC, the EPA, the DOE, the NRC, the Virginia Commission and the North Carolina* Commission), industry and rate structure, operation of nuclear power facilities, acquisition and qisposal of assets and facilities, operation.and storage facilities, recovery of the cost

. 12

purchased power, nuclear decommissioning costs, and present or prospective wholesale and retail competition. The busi 0 ess and profitability of Virginia Power also are influenced by economic and geographic factors including political and eco-nomic ,risks,. changes' in and _<::ompliance with environmental laws and policies, weather conditions and catastrophic weather-related damage, competition for retail and. wholesale customers, pricing and transportatim1 of commodities, market demand for energy,. inflation, capital'market conditions, unanticipated changes *in operating expenses and capital'expenditures, com-petition for new energy development opportunities and legal and administrative proceedings. All such.factors are*difficult to predict, contain uncertainties that.may materially affect actual results, and may be beyond the control of Virginia Power.

New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of each suchfactor on the business ofthe Company.

. . Any forward-looking statement speaks only as of the .date on which such statement is made, and Virginia Power under-takes *no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such s_tatement is made.

Liq11idity_ and. Capital Resources Operati,;g _activities cqntinue to be a,stroll,g source of cash flow, providing $1,091 miliion in 19?7 c<>mp~ed to $1,115 mil-lion in 1996. The decrease of $24 million (or 2,percent) from the previous ye_ar is attributable. to normal business fluctua-tions, . .Over th~ past three years, cash.f)ow from operating activit.ies.has,,qn av.erage, covered 134 percent of.our to,tal co.n-struction requirements and provided 8i percent of our total.cash requirements. Our remaining cash needs are met generally with proceeds from the sale of securities and short-term borrowings .

. *Financing activities have represented a µet outflov.r of casq, in. recent years as strong cash. flow from operations _and the absence of major construction programs have ,reduced the Company's _:reliance *on debt finan'cing.

Cash from (used iri) financing activities was as follows: '

1997 1996 1995 (Millions)

Issuance of long-term debt ................................................................................. . $ 270.0 $ 24.5 $ 240.0 Issuance* of preferred securities of subsidiary trust .......: ............ '. ............... : ............ . 135.0 Issuance (Repayment) of short-term debt .............................................................. . (86.2) 143.4 169.0 Repayment of long-terni. dc::bt and preferred stock* .... ,., ....... ~:******************: ................ . (311.3) .(284.1) (439.0)

Dividend payments ....................................................................... .'...... ; ............ . (415.6) (421.4) (438.6)

• other .......... :............... *..................................................*............................... : .. . {13.5) {13.2) _____(UJ) rotal ;.*............ ;-......................... ;.: ............................ : ....... , ............................ . ${556.6) : ,${550.8) ${347.3)

We have ~en advantage of declining interest.rates by issuing new d~bt at lowe~ rates a~ higher-rat~ debt has matured.

For example, in 1997, $311.3 million of the Company's long-term debt securities matured with an average effective rate of 8.08 percent. As a partial replacement for this maturing debt, we issued $270.million of long~term debt securities during the year with .an average effective rate ?f 6.84 percent,*

• We currently have- three shelf registration statements* effective with the Securities and Exchange' Commission from which we can obtain additional debt capital: $400 million of Junior Subordinated Debentures; $375 million of Debt Secu-rities, including _First and Refunding Mortgage Bonds, Senior Notes and Senior Subordinated. Notes filed in February 1998; and $200 million of Medium-Term Notes, Series F. The remaining principal amount of debt that can be issued under these registrations totals $915 million. An additional capital resource of $100 million in preferred stock also is registered with the Securities and Exchange Commission.

• The Company has a commercial paper program that is supported by two credit facilities totaling $500 million. Pro-ceeds from the sale of commercial paper are primarily used to provide working capital. Net borrowings under the program were $226.2 million at December 31, 1997.

Investing activities in 1997 resulted in a net cash outflow of $546.1 million, pri1!1arily due to $397 .0 million of con-struction expenditures and $84.8 million of nuclear fuel expenditures. The construction expenditures included approximately

$252.4 million for transmission and distribution projects, $52.1 mil\ion for production projects, $49. 7 million for informa-tion technology projects and $42.8 million for other projects.

• 13

Cash used in investing activities was as follows:

1997.

• 1996 .. 1995 (Millio.ns> ,,

Utility plant expenditures (excluding AFC,-- other funds) ...................................... ; .. $(397.0) . $(393.8) . $(519.9)

Nuclear fuel (excluding AFC- other funds) ........ , ........................ , ........ : .. , .......... . *'(84,8}, (90.2):. * ,, (57.6)

Nuclear decommissioning contributions ................................. :...... ;............,, .... ,., ..... * (39.2):. (36.2) (28.5)

Sale of accounts. receivable, net ..................................*.......... , ......... , ... , ................... , (160.0)

Purchase of assets ..............................................................,. . . . . . . . . . . . ... . . . . . . . . . . . ... . . ... . . , (19.8) (13:7)

Other .............................. :...... :................................. , ..................... i................. . (8.3) (12.5) (11.1)

Total ........... , .............................................. , ....... ,, ............... ,, ................... ,.-*:*,* $(546.1~ $(546.4)' ":$(777.1)

Capital Requirements Capacity - The Company anticipates, that kilowatt-hour sales will grow approximately 2.36 percent a year thro~gh 2000. We will contirilie to.pursue capacity *acquisition plans to meet the anticipated load growth arid maintain a:high degree of service reliability; The additional capacity may be purchased from others or* built by the. Company if we c'an build capacity at a lower overall cost. We have *1ong~term purchase agreements with Hoosier (400 MW) *and AEP (500 MW) which will expire on December 31, 1999. We presently anticipate adding peaking: capacity' beginning in the year* 2000 to meet future load growth. * * * **

• Fixed Assets*-The Company's construction and nuclear fuel expenditures (excluding AFC), during 1998, 199~i.and 2000 are expected to total $588.l million, $476.2 million and $395.1 million; respectively. The *company presently'esti-mates that all of its 1998 construction and nuclear fuel expenditures will be met throug~ cash flow from operatio!1s.

Long-term Debt- The Company will require $333.5 million to meet maturities of long-term debt in 1998, which we expect to meet with cash flow from operations and issuance bf replacement debt securities. Other capital requirements will be met through a combination of sales of securities and short-term borrowings.

Customer Service - The Company has adopted a plan to improve customer service, requiring .a'n investment .in ,excess of $100 million. Our plan includes: * * ** ** * *

• installing automated electric meters* in metropolitan and inaccessible rural _and urban locations;'.

• installing a new work management system,

• making technological changes to enhance the Company's ability to handle customer calls during power outages,

• installing mobile data dispatch technology in the Companfs service fleet, accompanied by digiti~ed mapping of our service territory, a:nd '

• initiating both local. and regional distribution line improveme.nt projects.

Expenditures in 1997 for these projects were approximately $23 million; future expenditures 'are expected to' be approxi-mately $68 million .in 1998 and $15 million in 1999. We anticipate funding these projects with. cash :f'low from operations.

14

a Results of Operations

• The following is a discussion of results of operations for the years ended 1997 as compared to 1996, and 1996 as com-pared to 1995.

1997 Compared to 1996 Revenue changed from the prior year primarily due to the following:

1997 1996 (Millions)

Revenue - Electric Service Customer growth ......................... :................................................................................. . $ 55.8 $ 45.1 Weather ........................*....................................................................... , ....................... . (111.1) 4.4 Base rate variance ........ : .................. :.................................................................. *.. *......... . (18.7) (35.5)

Fuel rate variance ............................................................................................................ . 44.1 (89.6)

-Other retail, net ...... , ................................................ ,'. ................................................. , ..... : 47.7 41.5 Total retail ..... : ..... : .. '. ............................................... : ..... *...................... : ......... : ....... :/.. . 17.8 (34.1)

Other electric service :.............................................. , ......................... :........................... . 11.0 ~

Total electric service .... : ........ -'* .......... , ........ , ..... , ........................................................... . 28.8 ~

Revenue - Other*

. :Wholesal,e - power mark,eting .. : ............................................... *: ... ................. *: .... :: ........... . 363.4 96.6 Natural gas ................................................................................................................... . 232.6. 33.2 Other, net ....................................................................................................... *.............. . 33.3 23.1 Total ~e~enue::....,..*other .......... :: ..... '. ...... :...................: *... : ...................................... *.......... . 629.3 152.9 Total revenue ........ :................................................................................................... . $ 658.1 $ 69.0 El~ctric service revenue consists of sales to* retail customers in our service territory at rates authorized by the Virginia and*.North Carolina Commissions and sales to cooperatives and municipalities at wholesale rates authorized by FERC._ The primary factors affecting this revenue in 1997 were customer growth, weather, and fuel rates.

Customer growth - There were 50,899 new customer connections to our system in 1997, the largest number of new

_*_ connections in any year since 1990. This had the effect of increasing our sales by $55.8 million in 1997 over 1996.

Weather -The mild weather in 1997 caused customers to use less electricity for heating and cooling, which reduced revenue by approximately $111.1 million from the previous year. Heating and cooling degree days were as follows:

1997 1996 Normal

• Cooling degr~e.days ..... ~ ... ." ....................... , ..... , ................ . 1,349 1,365 1,530 Percentage change compared to prior.* year .......................... . (1.2)% (18.1)%

• Heating degree days .............. : ... : . ."., ........................*......... . 3,787 4,131 3,726 Percentage change compared to prior year .......................... . (8.3)% 9.0%

Fuel rates - The increase in fuel rate revenues is primarily attributable to higher fuel rates which went into effect December 1, 1996, increasing recovery of fuel costs by approximately $48.2 million. The regulatory commissions hav-ing jurisdiction over the Company allow us to charge customers for the cost of fuel used in generating electricity.

Other revenue includes s;iles of electricity beyond our service territory, natural gas, .nuclear consulting services, energy management services and 9ther revenue. The growth in power marketing and natural gas sales revenue is primarily due to our success at n1arketing electrieity and natural gas beyond our service territory. The Company began pursuing these new ,

Jines of business in 1996; We expect that revenue from such non-traditional business activities will continue to grow in th6 near future.

' 15

Kilowatt-hour sales changed as follows:

Increase .

(Decrease) From Prior Year 1997 1996 Residential ............................................... . (1.8)% 2.3%

• Commercial .................. :.: ... ;'. .. .'... :.: .. *...*:;.: .. 0.6 2.3 Industrial .................................................. . 2.1 2.3 Public authorities ...................................... . (4.7) 2.6 Total retail sales :................ : ..................... . (0.5) 2.4 Wholesale ~ system ............ : .................... . 2.5 (24.3)

Wholesale - power marketing .................... . 196.0 200.3 Total sales ................................................ . .17.2 6.3 The decrease in retail kilowatt-hour sales in 1997 as compared to 1996 reflects the impact of weather on our traditional electricity service business, despite continued customer growth. The increase in wholesale kilowatt-hour sales was primarily due to the Company's power marketing. efforts. .

Fuel, net increased as compared to 1996, primarily due to the cost of the power marketing and natural gas sales which reflects increased purchases of energy from other wholesale power suppliers and purchases of natural gas.

System energy output by energy source and the average fuel cost for each are shown below: Fuel cost is presented in mills (one tenth of one cent) per kilowatt hour.

1997 1996 1995

• Source Cost Source Cost *'Source Cost Nuclear (*) .................................. . 34% 4.52 32% 4.48 32% 4.92 Coal(**) ..................................... . 40 13.54 38 14.32 39 14.44 Oil .......*............ : ............ :* ............ . 1" *26.32 *1 27.75 1* 25.11

. . Purchased power, net ...... :............. .'. 23 . 21.54 27 21.99 25 22.50

• Other ........................................ ::.* 2 **30.65

• 2 26.98 3* 23;82

.Total ....... .-.-.. : ............. :................ . 100%

• 100% 100%

• Average fuel cost ...................... .

• 12.67

• 13.47 13.73

(*) Excludes ODEC's 11.6 percent ownersllip interest in the North Anna Power Station.

(**) Excludes ODEC's 50 percent ownership interest in the Clover Power Station.

Other operations an,d maintenance Increased as compared to 1996 as a result of costs associated with the.growth in sales by the Company's energy services business unit. These higher costs were offset partially by a reductfon in expenses attributable to the Company's strategic initiatives. Expenses in 1996 inclilde high stomi damage costs resulting from destruc-tive summer storms, including Hurrican~ Fran. *

• Depreciation and amortization increased as compared to 1996 due to the recognition of additional depreciation and nuclear decommissioning expense to reflect adjustments in the Company's filing currentiy*pending before the Virginia* Com-mission and higher depreciation expense related to Clover Unit 2,* which began operations in March 1996. See Future Issues - Utility Rate Regulation for additional information- on current rate proceedings. *

• Restructuring expenses decreased as compared* to 1996 as the Company ,nears completion of its Vision 2000 strategic initiative.* Charges forrestructuririg primarily include employee *severance* costs, costs to restructure agreements to purchase power from third parties and, when *necessary, to negotiate settlement and termination of these contracts, and other costs.

The Company estimates that staffing reductions will result in annual savings,* in* the range *of $80 *million to $90 million.

• However, these savings are being offset by salary increases, outsourcing costs and increased payroll costs associated with staffing for growth opportunities. See also Note O tci the CONSOLIDATED FINANCIAL STATEMENTS.

Accelerated cost recovery represents a reserve for potential adjustments to regulatory assets. In this increasingly com-petitive environment, the Company has concluded that it is appropriate to utilize available cost reductions, such as those generated by the Vision 2000 program, to accelerate the write-off of unamortized regulatory assets and potentially stranded costs (see Future Issues - Competition).

16

1996 Compared to 1995 Electric service revenues decreased as compared to 1995 due to the effect of mild weather on the Company's summer to retail rates, 'which are designed reflect nonnal weather conditions. These revenues also were affected by reduced sales to Old Dominion Electric Cooperative (ODEC) due.to the completion of Clover Units 1 and _2, of which ODEC. owns a fifty percent interest.

Other revenues increased as compared to 1995 due to growth in *our* power marketing and energy services business, which was organized as a distinct business unit in 1996 ..

Fuel, net increased as co!llpared to 1995, primarily as a result of increased energy purchases associated with our power marketing sales, offset in part by a higher recovery of fuel expenses subject to deferral accounting in 1995.

C

• Operations and maintenance decre.ased slightly as compared to 1995, primarily as a result of a reduction in expenses attributable to the Cotiipany's strategic init1atives, offset partly by the high storm damage costs incurred in 1996 from destructive summer storms, including Hurricane Fran ..:

Depreciation and amortization increased. as c;ompared.to 1995, primarily as _a result of greater nuclear decommission-ing expense and depreciation related to Clover Units l .and 2, which were placed in service in October 1995 and March 1996, respectively.

Restructuring decreased as compared to 1995 as thejmplementation phase of the Vision 2000 initiative continued.

Restructuring charges in 1996 included sev.erance costs, costs to restructure Ol' settle certain contracts to purchase power and other costs. In addition, 1995 restructuring costs included one,tim~ charges to cancel specific capital projects and adjust-ments to inventory and certain real estate to reflect adoption* of changes in business strategies and processes.

. Accelerated cost recovery represents a provision for managemeni'(estimate of a reserve that may ultimately be used to accelerate the write-off of unamortized regulatory assets and potentially stranded costs (see Future Issues - Competition).

Future Issues Competition f_n the Electric Industry - General.*

For most of this century; the. structure of the electric industry in Virginia and throughout the United States has been relatively stable. We have recently seen, however, federal and state developments toward increased competition. Electric utilities have been required to open up their transmission systems for use by potential wholesale competitors. In addition, non-utility power producers. now compete with electric utilities in the wholesale generation market. At the federal level, retail competition is unqer consideration. Some.states have enacted legislation requiring retail competition.

Today, Virginia Power faces competition in the wholesale market. Currently, there is no general retail competition in Virginia Power's principal service area. To the extent that competition is permitted, Virginia Power's ability to sell power at .prices. that allow it to recover its prudently incurred costs may. be an issue. See. Future Issues___, Competition-Exposure to Potentially Stranded Costs. * **

• In response to competition, Virginia Power has successfullytenegotiated long term contracts with wholesale and large federal government customers. In addition, the Company *has obtained regulatory approval of innovative pricing proposals for large industrial customers. Rate concessions resulting from these contract negotiations arid innovative pricing proposals are expected to reduce the Company's 1998 revenue by approximately $40 million. To date, the Company has riot experi-enced any material loss of load.

Virginia Power is actively participating. in the iegislative and regulatory processes relating to industry restructuring. The Company has *also responded to these trends* toward competition by c;utting its costs, re-engineering its core business pro-cesses, and pursuing innovative approaches to serving traditional markets and future markets. In addition, a significant part of the Company's.strategy relies on developing "non-traditional" businesses within the Company's business units and sub-s_idiaries designed to provide .growth in future earnings, including:

• Energy Services-:-- offering electric energy and capacity in the emerging wholesa}e market as well as natural gas, and

. other energy related products and services;

• Fossil & Hydro-:-- targeting process type industries, stich as chemical, paper, plastics and petroleum to become* a ser-vice provider* of instrumentation equipment;

• Nuclear Services - offering management and_ operations services t9 other electric utilities; 17

• Commercial Operations - providing power distribution related services, including transmission and distribution; engi-neering and metering services to other gas, water and electric utilities; and

• Telecommunications - offering telecommunications services through the Company's existing fiber-optic' network The Company's non-traditional" businesses face competition from a variety of utility and non-utility entities. In addi-tion, Virginia Power may from time to time identify and investigate opportunities to expand its markets through strategic alliances with partners whose strengths, market position and strategies complement those of the Company.

Competition - Wholesale During 1997, sales to wholesale customers represented approximately 17 percent of the Company's total revenues from electric sales. Approximately 73 percent of wholesale revenues resulted from the Company's power marketing efforts.

In July 1997, Virginia Power filed amendments to its existing rate tariffs with FERC so it could make .wholesale sales at market-based rates. Under a FERC order conditionally accepting the Company ra,tes for filing, Virginia Power began making market-based sales in 1997. FERC set for hearing in June 1998 the issue of whether transmission constraints limit-ing the transfer of power into the Company's service territory provide Virginia Power with generation dominance in local-ized markets. If FERC finds transmission constraints give Virginia Power generation dominance, it could revoke or limit the scope of the Company's market-based rate authority.

Virginia Power has successfully negotiated a: n:ew power supply arrangement with its .largest wholesale customer. The new arrangement provides for a transition from cost-based rates to market-based rates, subject to FERC approval. Virginia Power estimates the reduced rates, offset in part by other revenues which may be earned under the agreement, will decrease income before taxes by approximately $38 million through 2005. Virginia Power anticipates that additional contract nego-tiations with other wholesale customers will take place in the future.

Competition - Retail Currently, Virginia Power has the exclusive right to provide electricity at retail within its assigned service territories in Virginia and North Carolina. As a result, Virginia Power now only faces competition for retail sales if certain of its busi-ness customers move into another utility service territory, use other energy sources instead of electric power, or generate their own electricity. However, both Virginia and North Carolina are considering implementing retail competition.

Competition - Legislative Initiatives*

Virginia: In the 1998 Session, the Virginia General Assembly passed House Bill No. 1172 (HB 1172) to establish a schedule for Virginia's transition to retail competition in the electric utility industry.* The Company actively supported HB 1172, which passed both houses of the General Assembly in amended form and now awaits action by the Governor.

HB 1172 requires the following:

• establishment of one or mote independent system operators (ISO) and one or more regional power exchanges (RPX) for Virginia by January 1, 2001;

• deregulation of generating facilities beginning January 1, 2002;

• transition .to retail competition to begin on January l, 2002, with retail competition to begin on January 1, 2004;

• **recovery of just and reasonable net stranded costs; and

• appropriate consumer safeguards related to stranded costs and consideration of stranded benefits.

If HB 1172 becomes law, it will become effective July 1, 1998. While the bill establishes a timt!line for the transiti9n to competition in Virginia, a detailed plan to implement that transition must be developed through future legislative and regulatory action. The Company is unable at this time to predict its timing or details.

Federal: The U.S. Congress is expected to consider federal legislation in the near future authorizing or requiring retail

.competition. Virginia Power cannot predict what, if any, definitive actions the Congress may take.

North Carolina: The 1997 Session of the North Carolina General Assembly created a Study Commission on the Future of Electric Service:in North Carolina. A~ interim report is expected in 1998 with final recommendations made to the 1999 session of the North Carolina General Assembly.

18

'Competition - Regulatory Initiatives The Virginia Commission also has been actively interested in industry restructuring and competition, as shown in the following generic and utility~specific proceedings.

In 1995; the Commission i~stituted an ongoing generic investigation on restructuring, resulting in a number of reports by its Staff covering such issues as retail wheel1ng experiments and the status of wholesale power markets.

In November 1996, the Commission ordered Virginia Power to file studies and reports on possible restructuring of the electric industry in Virginia. The Commission also invited Virginia Power to submit a proposed alternative regulation plan with its filing. A two-phase alternative regulatory plan (ARP) was filed March 1.997. During Phase I (1997 to December 2002), Virginia Power proposed implementing a freeze of its current base rates and devoting a portion of earnings above a 11.5% return-on-equity to accelerate the write-off of generation-related regulatory assets and to mitigate the costs associated with payments under power purchase contracts with non-utility generators that may be above market if competition is autho-rized in Virginia. During Phase II (beyond December 31, 2002), Virginia Power would seek Commission approval of stranded cost recovery if retail competition is implemented in Virginia and a transition cost charge mechanism by which stranded costs would be recovered. Virginia l;'ow*er presented illustrative estimates of stranded costs based on hypothetical market prices as part of its Phase II filing. When the Company filed its ARP, the Commission consolidated its consideration of the ARP with its consideration of the Company's 1995 Annual Information Filing. For a discussion of the 1995 Annual Information Filing, See Future Issues - Utility Rate Regulation.

In November 1997, the Commission Staff issued its report to the General Assembly calling for a cautious, two-phase, five-year period to address restructuring issues. The report acknowledged the need for direction from the Virginia legisla-ture concerning policy issues surrounding competition in the electric industry. Virginia Power sought to withdraw its ARP in December 1997, having concluded that resolution of the cost recovery,issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that the Company may withdraw its support of the ARP, but has reserved the right to continue consider.ation of the ARP as well as other regulatory alternatives. In addition, the Commission will continue to consider the issues arising out of the 1995 Annual Informational Filing (See Future Issues - Utility Rate Regulation).

Competition - SFAS 71 Vi~ginia Po~er's reg~lated rates are designed to recover its prudently inc~rred cos~s of providing service, including the

~pportunity to earn a reasonable return on its shareholder's investment: The Company's financial statements reflect assets and costs under this cost-based rate regulation in accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation." SFAS 71 provides that certain expenses normally reflected in income are. deferred on the balance sheet as regulatory assets and are recognized as the related amounts are included in rates and recovered from customers. Continued accounting .under SFAS 71 requires that rates designed to recover the utility's specific costs of providing service, are, and will continue to be, established by regulators. The presence of increasing competition that limits the utility's ability to charge rates that recover its costs, or a change in the method of regulation with the same effect, could result in the discontinued applicability of SPAS 71.

• Rate-regulated companies are required to write off regulatory assets against earnings whenever those assets no longer meet the criteria for recognition as defiqed by SFAS 71. In addition, SFAS 121, "Accounting for the Impairment of Long~

Lived Assets and for Long-Lived Assets to Be Disposed Of," .requires a review of long lived assets for impairment when-0 ever events or changes in circumstanc:es indicate that the c.arrying amount. of an asset may not be recoverable. Thus, events or changes in c.ircumstances.that cause the discontinuance of SPAS 71, and write. off of regulatory assets, may also require a review of utility plant assets for possible impairment. If such review indicates utility plant assets are impaired, the carry-ing amount' of the* affected assets would be written down. This would result in a loss being charged to earnings, unless recovery of the loss is provided through operations that remain regulated; **

• Virginia Power's regulated operations currently satisfy the SFAS 71 criteria. However, if eyents or circumstances should

• change so that those criteria are no longer satisfied, management believes that a material ad.verse effect on the Coµipany's results of operations and financial position may result. *The form of cost-based rate regulation under which Virginia Power operates is likely to evolve as a result of various legislative or regulatory initiatives. At this time, management can predict neither the ultimate outcome of regulatory reform in the electric utility industry nor tlie impact such changes would have on Virginia Power.

19

Competition - Exposure to Potentially Stranded Costs Under traditional. cost-based regulation, utilities have generally had w obligation to serve supported by an implicit promise of the opportunity to recover prudently incurred costs. The most *significant potential adverse effect of competition .

is "stranded c.osts." Stranded costs are* those costs incurred or commitments made by utilities under. cost-based regulation that may not be reasonably expected to be recovered in a competitive market.

The Company's potential exposure to stranded costs is comprised of the following:

• long-term purchased power contracts that may be above market (see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS); .

a

• costs pertaining to certain generating plants that may become uneconomic in deregulated environment;

• regulatory assets for items such as income tax benefits previously flowed-.through to customers, deferred losses on reacquired debt and other costs; (see Note F to the CONSOLIDATED FINANCIAL STATEMENTS); and

• unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the finan-ciaLstatements (see Notes C and N to. the CONSOLIDATED FINANCIAL STATEMENTS).

Any forecast of potentially stranded costs is extremely sensitive to the various assumptions made. Such' assumptions include: *

• the timing and extent of customer choice in the market* for electric .service;*

• estimates of future competitive market prices;

• sales and load growth forecasts;

• power stations' future operating performance;

• rate revenues permitted during the transition;

• .estimated costs of utility operations over time;

• mitigation opportunities;

• stranded cost recovery mechanisms and other factors.

• Certain combinations of these assumptions as applied to Virginia Power would produce little to n~ stranded costs; under other scenarios Virginia Power's .exposure to potentially stranded costs could be substantial.

Virginia Power has assessed the reasonableness of various possible assumptions, but has not been able to settle on any particular combination thereof. Thus, the Company's maximum exposure to potentially stranded costs is uncertain. Manage-ment believes that recovery of any potentially s.tranded costs is appropriate and will vigorously pursue such recovery with the regulatory commissions having jurisdiction over its operations. However, Virginia Power cannot predict the extent to which such costs, if any, will be recoverable from customers. Also, in an effort to mitigate the amount at risk, the Company will continue to implement cost. reduction measures.

Utility Rate Regulation In March 1997, the Virginia Commission issued an orde~ that Virginia Power's base rates be made..interim and subject to refund as of March 1, 1997. This order was the result o.f the Commission S~ff's report on its review of Virginia Pow-er's 1995 Annual Informational Filing, which concluded that Virginia Power's present rates would cause Virginia Power* to a

earn in excess bf its authorized return on equity. The Staff found that, for purposes *of establishing rates prospectively, rate reduction of $95.6 million (including a *one-time adjustment of $29.7 million to Virginia Power's deferred capacity balance at December 31, 1996) may be necessary in order to realign rates _to the authorized level. Virginia Power filed its ARP in March 1997, based on 1996 financial information. Subsequently, the Commission consolidated the*proceeding concerned with the 1995 Annual Informational Filing with the proceeding that includes the ARP proposed by the Company.

in December 1997, Virginia Po'o/er. sought to withdraVI'. its ARP, having concluded that resolution of the cost recovery issues raised by the ARP was unlikely without General Assembly action. The Co~mission has agreed that the Company may withdraw its support of the ARP but has reserved the right to c:ontinue consideration of the ARP as well as other regulatory alternatives. Iri addition, the* Commission will continue to consider the issues arising out of the 1995 Annual Informational Filing. The Commission's Staff is scheduled to file its testimony on March 24, 1998; Virginia Power's rebuttal is to be .filed by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A public hearing is scheduled*to commence on May 19, 1998. .

Virginia Power's previous filings in* this proceeding support maintaining the Company's rates at current levels; how-ever, opposing parties have made filings recommending rate reductions in excess of $200 million. At this time, management cannot predict the ultimate outcome of the proceeding and its impact on the Company's results of operations, cash flows or financial position.

20

Utility Operations The Company strives to operate its generating facilities in accordance with prudent utility industry practices and in conformity with applicable statutes, rules and regulations .. Like other electric utilities, the Coinpany.'s generating facilities are subject to unanticipated or extended outages for repairs, replacements or modification of equipment or otherwise to comply with regulatory requirements. Such outages may involve significant expenditures not previously budgeted, includ-ing replacement energy costs. * * **

On September 10, 1997, the NRC published a proposed rule for financial assuranc~ requirements related to nuclear decommissioning. If the NRC's proposed rule were implemented without further clarification or *mooification, the Company may have to either pre-fund or provide acceptable security for a portion of its nuclear decommissioning obligation. See Note C to the CONSOLIDATED FINANCIAL STATEMENTS.

Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations of the Company. These costs* have been historically recovered from customers through utility rates. However, to the extent that the regulatory environment departs froin cost-based rates, the Company's results of operations and financial condition could be adversely impacted.

Environmental Protection and Monitoring Expenditurrs The Company incurred $70.4 million, $71.1 million and $68.3 million (including depreciation) during 1997, 1996 and 1995, respectively, in connection with the use of environmental protection facilities and expects these expenses to be approxi-mately $69.1 million in 1998. In addition, capital expenditures to limit or monitor hazardous substances were $24.6 million,

$22.4 million and $23.4 million for 1997, 1996 and 1995, respectively. The amount estimated for 1998 for these expendi-tures is $10.0 million.

Clean Air Act Compliance The Clean Air Act, as amended in 1990, requires the Company to reduce its emissions of sulfur dioxide (S02 ) and nitrogen oxides (NOx). The Clean Air Act also requires the Company to obtain operating permits for all major eniissions-emitting facilities. Permit applications have been submitted for the Company's power stations located in.North Carolina and West Vrrginia. Applications for the Company's power stations located in Vrrginia will be filed in 1998.

The Clean Air Act's S02 reduction progr~ is based on.the issua~ce of a limited number of S02 emission allowances, each of which may be used as a permit to emit one ton of S02 into the atmosphere or may be sold to someone else. The program is administered by the EPA. The Company's compliance plans may include switching) to lower sulfur coal, pur~

chase of emission allowances and installation of S02 control equipment. Maximum flexibility and least-cost compliance will be maintained through annual studies. * * *

• The Company began complying with Clean Air Act Phase {NOx limits at eight of it~ units in Vrrginia in 1997, three years earlier than otherwise required. As a result, the units will not be subJect to more stringent Phase II limits until 2008.

Furthermore, in order to avoid the necessity of more stringent regulations, the Company made voluntary commitments in 1996 to cap NOx emissions at its Chesterfield and Yorktown Power Stations and the Chesapeake Energy Center during the ozone season beginning in 2000.

From 1994 through 1997, the Company, invested more than $160 million to install and upgrade S02 and NOx emission control equipment at its Mt. Storm and Possum Point power stations. Capital expenditures related to Clean Air Act compli-ance over the next five years are projected to be approximately $40 million .. Changes in the regulatory environment, avail-ability of allowances, and emissions control technology could, substantially impact the timing and magnitude of compliance expenditures.

In November 1997, the EPA proposed new requirements for 22 states, including Nort:}1 Carolina, Virginia and West Vir-ginia, to reduce and cap emissions of NOx. The EPA will issue.a final rule by September 1998. Altho~gh the proposal allows each* state to determine how to achieve the required reduction in emissions, the caps were calculated based on emission lim-its for utility boilers. If the states in which Virginia Power operates choose to imp~se thi.s limit, major additional emission control equipment, with attendant significant capital and operating costs, could be required.

21

i Global Climate Change In 1993, the United Nation's Global Wanning Treaty became:effective. The objective of the treatx is the stabilization of greenhouse gas concentrations at a level that would prevent man-made emissions from interfering with the Climate sys-tem.

As a c~ntinuation of the effort to liin'tt man-made greenhouse emissions, an international Protocol was formula~ed on December 10, 1997, in Kyoto, Japan. This Protocol calls for the United States to reduce greenhouse emissions by 7 percent from 1990 baseline levels by. the period 2008-2012. The Protocol will not.constitute a binding commitment unless submit-ted to and approved by the United States Senate. Emission reductions of the magnitude included in the Protocol, if adopted, would likely result in a substantial financial impact on companies that consume or produce fossil fuel-derived electric power, including Virginia Power.

Recently Issued Accounting Standards During 1997, the Financial Accounting ~tandards Board (FASB) issued Statement of Financial Accounting Standards

_(SFAS) No. 130, "Reporting ComprehensiveJncome, and SFAS-No. 131, "Disclosures about Segments of an Enterprise and *Related Information." Each of these statements is. effective for fiscal years beginning after December 15, 1997. At this time, the Company..does *not expect the implementation of these standards to have a matedal impact on its results of opera-tions or financial positio_n.

Year 2000 Coinpliance Virginia Power is taking an aggressive approach regarding* computer issues associated with the onset of the new millenium---,- specifically, the impact qf-the possible. failure of comput1rr systems and computer-driven equipment due to the rollover to the year 2000. Th.e year 2000 problem is pervasive and complex as virtually evefy computer operation could be affected in some way by the .rollover of-the two-digit year value from 99 to 00. The issue is whether computer systems will properly recognize date'-sensitive information when the year changes to 2000. Systems that do not properly recognize such information could generate erroneous data or fail.

If not properly addressed, the year 2000 computer problem could result in failures in computer systems in the Com-pany and the computer systems of third parties with which the Company transacts business. Such failures of the Company's or third parties' coinput~i: systems could have a material 1mpact.

on the Company's ability to conduct business.

.a Since January 1997, the Company has -organized formal year 2000. project team to identify, correct or reprogram and test its systems for year,2000 compliance. A_t this time, the. project team has completed its preliminary assessment. Based on the team's evaluation, the costs of testing and conversion of system appiications are projected to be within the range of

$30 million to $50 milli_on. The range* is a function of our ong9ing evaluation as to wheth~r certain systems and equipment will be corrected or replaced, wNch is ciependent on information yet to be obtained from suppliers and other external sources.

Maintenance cir modification *costs 'Yill be expensed as incurred, while the costs of new software and hardware will be capi-talized and amortized over the assef s useful life. . . '

At. this time, Virginia Power is actively pursuing solutions to its year 2000-r~lated computer *problems in order to ensure that foreseeable situations related* to Company computer systems are effectively addressed. The Company* cannot estimate or predict the poten'tial ad~erse*consequences, if any, that c~~ld result from a third party's failure to effectively address this issue.*

Market Rate Sensitive Instruments and Risk Management Virginia Power 'is subject to market risk as a result of its use of various financial instrurnents and derivative commod-ity instruments. Interest rate risk generally is associated with the Company's outstanding debt, preferred stock and trust-issued securities. The Company also is exposed to, irit_erest rate risk as well as equity price -risk as a result of its nuclear decommissioning trust investments in debt and equity securities. . .

The Company's wholesale power group is involved in trading activities which use derivative commodity instruments.

However, the fair value of such instruments at December 31, 1997, is not material to the Company's financial position. Also, the potential near term losses in future earnings, fair values, or cash flows, resulting from reasonably possible near term changes in market prices for* such instruments are not anticipated to be material to the Company's results of operations, financial position or cash flows. *

• 22

The following analysis does not include the price risks associated with the nonfinancial assets and liabilities of utility operations, including underlying fuel requirements.

Interest-rate risk Virginia Power uses both fixed rate and variable rate debt and preferred securities as sources of capital. The following table presents the financial instruments that are held or issued by the Company at December 31, 1997, and are sensitive to interest rate changes in some way. Weighted average variable rates are based on implied fof\Vard rates derived from appro-priate annual spot rate observations as of December 31, 1997. *

• Expected Maturi!I Date Fair 1998

• 1999 2000 2001 2002* ' Thereafter Total Value (Millions of Dollars, Except Percentages)

ASSETS Nuclear decommissioning trust investments .............. : : ....... : $ 17.7 $ 5.3 $ 2.1 $ 7.1 *: $ '. 3.i $ 165.0 $ 200.3 $ 190.7 Average interest rate (1) ............ . 5.5% 5.5% 5.5% 5.5% 5.5% 5.5%

LIABILITIES - Fixed rate Mortgage bonds .......................... . 225.0 100.0 135.0 100.0 255.0 2,009.5 2,824.5 2,937.7 Average interest rate ............. , ... . 6.7% 8.9% 5.9% 6.0% 4.5% 7.6%

Medium term notes ...................... . 108.5 221.0 60.5 60.6 60.0 40.5 551.1 573.7 Average interest rate ................. . 7.6% 8.5% 9.7% 8.4% 7.6% 9.0%

Tax-exempt financing ................... . . 10.0 10.0 10.4 Average interest rate ................. . 5.2%

Short-term debt ........................... . 226.2 226.2 226.2 Average interest rate .................. . 5.9%

Preferred stock, subject to .

mandatory redemption ................... . 180.0 180.0 186.6 Average dividend rate ............... . 6.2%

Mandatorily redeemable trust-issued preferred securities .................................... . 135.0 135.0 137.7 Average dividend rate ............... . 8.1%

LIABILITIES - Variable rate Tax-exempt financing (2) .............. . 488.6 488.6 488.6 Average interest rate ................. . 4.1%

(1) Rates are based on average yield for entire portfolio at December 31, 1997.

(2) Interest rates on the tax-exempt bonds are based on short-term, tax-exempt market rates and are rese.t for periods of one to 270 days in length. The Company has the option to convert these bonds to fixed rate securities upon 40 days writ~

ten notice. See Note H to the CONSOLIDATED FINANCIAL STATEMENTS.

Equity price risk The following table presents a description of marketable equity securities held by the Company at December 31, 1997.

As prescribed by Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities," these securities are reported on the balance sheet at fair value.

Fair Cost Value (Millions of Dollars)

I

~

Nuclear decommissioning trust investments $ 219.4 $ 360.4

. 23

ITEM 8. F~ANCIAL STATEMENTS~ SUPPLEMENTARY.DATA INDEX Page No.

Report.of Management ....... ,, ......... , .... : .. :...::* ....-.... ,_... ~ .. : ...-.: ... : ..... :.,'.:, ..... , .. : .... ::........ :.: .. :....... .' ..*.... : ..... :... '. . 25 Report of Independent Auditors,' .....................*: ...... *................ : ... :-...-..... *.......... : .............. ,:*.:'.: .................... * *26 Consolidated Statem:ents of'Inc~me for' the years ended _. *- "' ' . . '. . . . ' .. . . . .

December 31, 1997, 1996 and 1995 .. : ............... .- .... :.: ..... :*;*.' ......... :... :.... :............ _... .'... -..*... : ........ .-.... :.......

• 27

• Consolidated Balan'ce Sheets at December 31, 1997 and 1996 * ........ ; ......... : ....... '. .. : ... *..... :.. :........................ _ 28

. Consolidated Statements of Earnings Reiriv~sted ii:t 'Btisiness for the years, ended . ..

December 31, 1997, ,1996 and 1995 ....... :~.:: .......... .- ..... -............ .-...... .-..... .'.......... : ......... :........................ 30 Consolidated Statements of Cash Flows* for the y~ars ended . . * *

• December 31, 1997; 1996 arid 1995 .........................-........ , ........................................ .-.: ......................

• 31 Notes to Consolidated, Financial. Statements .......................... _. ....................................................._....... , .. _.. . 32

't,

.24

i REPORT OF MANAGEMENT.

The Company'.s*managenient is responsible for all in{ormation and.representations c;ontained in th~ Consolidated Finan-cial ~tatements and. other sections of the Company's annual report on Form 10-K.. The Consolidated FiIIanci~l Statements,.

wpich* include a:inounts based' oh estimates and judgments of management, have been prepared in conformity with generally ac_cepted accountlni{ principles. Oth~r 'financial information in the Form' 10-K is consistent 'with that iri *the Consolidat.ed Fimincial Stat~ipents. . . - ., . . . . . . . . . , . . . . . *,,.

. ,., :I,,!,__ *.

Management maintains a system.:of internal ~cc01,mting controls. designed to proviqe reasonable assurance,. at a reason-able cost, i:hat the Company's ass~t~ are safeguarded* againstloss from unauthodzed use or disposition and that transactions are executed and recorded in accordance with e'stablished procedure's: Managetnent recognizes the inherent limitations of any; system of internal accou_ht1ng control. and, 'therefore, cannot prbvide \ibsolute**assuran'ce tiiat 'the *objectives of the estab2 lished *internal accou'ntlftg controls will" be ;met. Thls system 'inchides Written P.Olicies, an 6rganfaatiorial *structure designed to ensi:ire appropriate segrega,tion Of responsibilities, careful selediori anci'training'of q\.ialified personnel anci internal audits:

Management believes.*that"duri.ng j997 thksystem of internal c6rttrol was adequate to *accompl1sh the intended objective.'

' I '

. The Consolidated Financi~l Statements. have been audited by*peloitte.& Touchi:: LLP, independent auditors, wh~ have been engaged by the Board of Directors: 'Their audits: wei:-~ conducted in accor.darice with generally accepted* auditing stan° datds and. included a review. of the 'company's .accounting. systems, procedures and foterrial controls; and the performance of tests and other auditing prpceciuies'sufficient'.frrprovide reasonable assuranc~ thai: the Consolidated Financial Statements

. are not materially misleading and 'do riot contain materi~l errors. . .

The Audjt Committee of the Board of Directors, composed entirely of directors who are not offic~rs .or employees of the Company, meets periodically with the independent auditors, the internal auditors and manage~ent to di~cuss auditing, internal accounting control and finaO:cial reporting matters and to* ensure* that each is properly dis'charging its, responsibili-ties. Both the independent auditors and the internal auqitors periodically meet. alone with, the Audit Committee and have free access to the Committee at any time. . . .

Management recognizes its responsibi,ity*fo~ fostering a strop.g ethical ~lilhate so that the Company's affairs- are con-ducted ,according to the highest startdards of personal an.d 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 communiqiition 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 Norman Askew M. S. Bolton, 'Jr. *

.President and

• Controller and

• • . '. Chief Executive Principal Accounting Offic_er . *.* Officer t

25

REPORT OF INDEPENDENT'AUDJTORS To the Board of Directors of Virginia Electric and ..Power Company:

. We have a~dited the acc~mpanying.9o~solidated balance sheets. of Virginia Electric and Powe~ Co,mpany (a wh~lly qwned subsidiary of D(?rninio*n Re.sources, Inc.) and subsidiaries (the Company) as or'becember 3I; 1.991 and 19?6, and the related consolidated statements of income, earnings reinvested in business, and cash flows for each of tlle thr!!¢ y,ears iii. .the period ended December 31, 1997. These financial statements are the responsibility of the Company's in~nagement. Our responsibility is to express an opinion oil these financial statements based on our audits/ * *

• We conducted our audits in acq,rdance wit,h generaliy accepted auditing standard~. Those standards require that*~~ plan and perform the au4fr to obtain reasonable assurance 'about whether th~ financial statements are free of material misstate-ment. An audit includes exaniining, on a test. basis, evidence .supporting:the a~ounts ~nd disclosures in the financial ~tate-ments. An audit also incl~des .assessing the, ~ccountj.ng, principies used. and signittcant estimates ~ade :l?y management, as w~ll as* !=;Valuating. the overaitfi~ancial statetiient 'presentation. We believe that our audi~ provide a reas9nable *basis for our opinion .

. .. . In our opinion, such con~olidated financial statements presentfair~y, in all mat(!riaLrespects, the financial positiqn of the Company at Deceml:>er 31, 1997 .and i996, and the resuhs of their operations and their cash flows for.each .of the three.

years. in the period encied. ri¢ceµiber .31, 1997, i~. conforovty with generally

. . acc~pi~d ilc:~ounting

' - . .. . . ~

pri~~iples. *.

• DELOITTE & TOUCHE LLP

';_ ,,l*;,

Richmond; Virginia February 9; 1998 I

26

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1997 1996 1995 (Millions)

Revenues:

Electric service ............................................................................................. . $4,239.0 $4,210.2 $4,294.1 Other .... :...................................................................................................... . 840.0. 210.7 57.8 Total ........................................................................................................ . 5,079.0 4,420.9 4,351.9 Expenses: ... ;:................ ; ............... ; ............................................... :................... *

. Fuel, net .................. *.................................................................................... . 1,620.7 1,016.6 1,009.7 Purchased power capacity, net ........................ .'................................................ . 717.5 700.6 688.4 Operations and maintenance .......................................................... :......... :....... . 812.7 803.l 805.6 Depreciation and amortization ......................................................... :............... . 549.9 502.0 469.1

.Restructuring ...................................................................................... *. .'........ . 18.4 64.9 117.9 Accelerated cost recovery ............................................................................... . 38.4 26.7 Amortization of terminated construction project costs ......................................... . 34.4 34.4 34.4 Taxes other than income .............................-.................................................... . 267.7 262.6 254.9

• Total ..................... *..... :............... *................................ *............................ :.. 4,059.7 3,410:9 3,380.0 Income from operations .................................................................. : .................. . 1,019.3 1,010.0 971.9 Other income .'. ......................................................... .- .................. *..................... . 14.2 6.8 10.0 Income before interest and income taxes 1,033.5 1,016.8 981.9 Interest and related charges:

Interest expense, net .....................................................................................*.. 304.2 308.4 317.9 Distributions:...._ preferred securities of subsidiary trust ....................................... .. 10.9 10.9 3.7 Total .............................. *.......... :............................................................... . 315.1 319.3 321.6 Income before income taxes ............................................................................... . 718.4 697.5 660.3 Income taxes : ................................................................................................... . 249.3 240.2 227.5

.Net income ......................................... : ............ *............... :................................. . 469.1 457.3 432.8 Preferred dividends ........................................................................................... . 35.7 35.5 44.1 Balance available for Common Stock .................................................................. . $ 433.4 $ 421.8 $ 388.7 The accompanying notes are an integral part of the financial statements.

27

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Assets At December 31, 1997 1996 (Millions of Dollars)

CURRENT ASSETS:

Cash and cash equivalents ........................................................................................... . $ 36.0 $ 47.9 Accounts receivable:

Customers (less allowance for doubtful accounts of $2.4 in 1997 and 1996) ..................... . 462.4 354.8 Other ........................................................................ '. ........................................... . 108.0 80.4 Accrued unbilled revenues ................ .'.......................................................................... . 245,2 i80.3 Materials and supplies at average cost or less:

Plant and general .................................................. .'................................................. . 145.2 148.7

.Fossil fuel ................................. ; .................................................................. ~ ......... . 67.4 76.8 Other ................................................................................... *..................................... . 134.7 107.0 Total current assets . .'............................................................................................ . 1,198.9. .995.9 INVESTMENTS:

Nuclear decommissioning trust funds .......................................................................*... ~ ... . 569.1 443.3 Other ........................................................................................................................ . 38.3 34.5 Total net investments ........................... ,. .................................................................... , 607.4 477.8 DEFERRED DEBITS AND OTHER ASSETS:

Regulatory assets: .

Deferred capacity expenses ....................................................................................... . 47.3 6.1 Other ........................................................................................................ : ............ . 729.3 767.8 Unamortized debt issuance costs .................................. :........ :..... : ............. '. .................... . 24.2 24.7 Other ............................................ :.............................. : ...................... : ...................... . 127.1 121.9 Total deferred debits and other assets ................ :........................................................ . 927.9 . :920.5 UTILITY PLANT:

Plant (includes plant under construction of $240.9 in 1997 and $180.1 in 1996) ................... . 14,794.2 14,506.8 Less accumulated depreciation ............................. : ... :***************************************************** 5,724.3 5,218.3 9,069.9 9,288.5 Nuclear fuel (less accumulated amortization of $705.0 in 1997 and $698.5 in 1996) ............. . 149.3 145.3 Total net utility plant ......................................... ;............................... :.......... : ... :..... ; . 9,219:2 9,433.8 Total assets ............................................................................................... :............. . $11,953.4 $11,828.0 The accompanying notes are an integral part of the financial statements .

.28

.VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Liabilities and Shareholders' Equity At December 31, 1997 1996 (Millions of Dollars)

CURRENT LIABILITIES:

Securities due within one year ............................*......................................................... . $ 333.5 $ 311.3 Short-term debt .................. :.................. : ................................................................... . 226.2 312.4 Accounts payable, trade :**********************.-******: ......... :................. .' ..... *.............................. . 452.0 368.5

• customer deposits .... '. .................... .- .... :: ............................ :*...... *........... : .................... : .. 44.6 50.0 Payrolls accrued .......... *................... : .. :.............................. : ........................................ . 77.5 73.2 Severance costs accrued ........ , ..................... ,,.* .................. : ............................................. . 29.7 50.2 Interest accrued .......*...................................................................................................

• 95.1 95.3 Other ...... ,.. , .....;......................... '.***********.************************,********************************************* 161.6 126.1 Total current. liabilities ...... :..................................................................................... . 1,420.2 1,387.0 LONG-TERM DEBT .......................................... :... : ....... :.. : ............ .c * .-, **.********* , ****** : *****. 3,514.6 3,579.4 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred income taxes ............................................................................. . 1,607.0 1,565.2 Deferred investment tax credits ................................................................................... . 238.4 255.3 Deferred fuel expenses ............................................................................................... . 12.8 3.3 Other ....................................................................................................................... .

• 220.3 151.1 Total deferred credits and other liabilities ............................................................... . 2,078.5 1,974.9 COMMITMENTS AND CONTINGENCIES (See Note Q)

COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST* .................................................................... . 135.0 135.0 PREFERRED STOCK:

Preferred stock subject to mandatory redemption ............................................................ . 180.0 180.0 Preferred stock not subject to mandatory redemption ...................................................... . 509.0 509.0 COMMON STOCKHOLDER'S EQUITY:

Common Stock, no par, 300,000 shares authorized, 171,484 shares outstanding at December 31, 1997 and 1996 .............................................................. . 2,737.4 2,737.4 Other paid-in capital .................................................................................................. . 16.9 16.9 Earnings reinvested in business .................................. :................................................ . 1,361.8 1,308.4 Total common stockholder's equity ........................................................................... . 4,116.1 4,062.7 Total liabilities and shareholders' equity ................................ *,* .................................. . $11,953.4 $11,828.0

(*) As described in Note I to CONSOLIDATED FINANCIAL STATEMENTS, the 8.05% Junior Subordinated Notes total-ling $139.2 million principal amount constitute 100% of the Trust's assets.

The accompanying notes are an integral part of the financial statements.

t 29

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF EARNINGS REINVESTED IN BUSINESS For the Years Ended December 31, 1997 1996 1995 (Millions)

Balance at beginning of year ............................................................................ . $1,308.4 $1,272.5 $1,277.8 Net income ............................................*....... :.. : .......... :.... '. .. :......................... . 469.1 457.3 432.8 Total ......................................................................................................... . 1,777.5 1,729.8 1,710.6 Cash dividends:

Preferred stock subject to mandatory redemption .... :................................... , ... :.. 11.1 11.1 13.5 Preferred stock not subject to mandatory redemption ...................... :... ::: ........... . 24.7 24.5 30.8 Common Stock ...............*................................................................ :.: ........ . 379.9 385.8 394.3 Total dividends ....._............................ , ................................................_...... . 415.7 421.4 . 438.6 Other additions (deductions), net ...... ; ................................................................ . 0.5 Balance at end of year ....................................................................... .*.: ....... :... . $1,361.8 $1,308.4 $1,272.5 The accompanying notes are an integral part of the financial statements.

I

~

30

VIRGINIA'ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1997 1996 1995 (Millions)

'Cash Flow Frail\ Operating Activities: . * .

• Net income .... : ............... *..................... : .....'............... .-..................... , ................ . $ 469.1 $ 457.3 $ 432.8

• Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization ....... :.......... ; ... :............ '. ............ : .......................... . 664.7 616.0 585.1 Deferred income taxes ...... , ............................................................................. . 36.1 69.1 11.8 Deferred investment tax credits ..... :................................................................... ; (16.9) (16.9) (16.9)

Noncash return on temtinated construction project costs - pretax .......................... :.... . (4.2) (6.4) (8.4)

Deferred. fuel expenses, net .............................. ,. ....................-..... :..................... . 9.6 (54.4) 6.2 Deferred capacity expenses ..................... *: ........................................................ . (41.2) (9.2) 6.4 Restructuring ............................................................................................... . 12.5 29.6 96.2 Accelerated cost recovery .......................... , .. : .................................................. :. 38.4

• 26.7 Changes in:

Accounts* receivable ... *........................................................................... *........ . (135.2) (11.3) (54.3)

Accrued unbilled revenues ..............,........................................................... *.... . (64.9) 17.6 (27.7)

Materials and supplies ............................................................ : .................... . 12.9 6.0 61.1 Accounts payable, trade ............................................................................... . 82.8 57.8 (8.9)

Accrued expenses .................................................................. , .................... . (13.9) (62.6) 44.7 Other .......................... .' .............................................................................. . 41.0 (4.0) (2.7)

Net Cash Flow From Operating Activities . : ................................................................ . 1,090.8 1,115.3 1,125.4 Cash Flow From (To) Financing Activities:

Issuance of long-term debt .................................................................................. . 270.0 24.5 240.0 Issuance of preferred securities of subsidiary trust ......................... :........................... . 135.0 Issuance (Repayment) of short-term debt ............................. :................................... . (86.2) 143.4 169.0 Repayment of long-term deb_t and preferred stock ........................ , .... , ... , .................... . (311.3) (284.1) (439.0)

Common Stock dividend payments ...................................................................... , .. (379.9) (385.8) (394.3)

Preferred stock dividend payments ........................................................................ . (35.7) (35.6) (44.3)

Distribution-preferred securities of subsidiary trust ..................... , ............ .-.................. . (10.9) (10.9) (3.7)

Other ... : ............................................................ : .............. .-............................. * (2.6) __ (2.3) (10.0)

Net Cash Flow To. Financing .

Activities ....................

. (556.6) (550.8) (347.3)

Cash Flow Used In Investing Activities:

Utility plant expenditures (excluding AFC - other funds) ...... : ..................................... . (397.0) (393.8) (519'.9)

Nuclear fuel (excluding AFC- other funds) ............................................................ . (84.8) (90.2) (57.6)

Nuclear decommissioning contributions ................................................................. , . (36.2) (36.2) (28.5)

. Sa,Je of accounts receivable, net ............................................................................ . (160.0)

Purchase of assets ................... *......_......... ,............ , ................................. : .... ,,. ..... . (19.8) (13.7)

Other ................................... ,. ............................................... , ......................... . (8.3) (12.5) (11.1)

Net Cash Flow Used In Investing Activities ... " ........................................................... . (546.1) (546.4) (777,.1)

Increase in cash and cash equivalents ........................................................................ . (11.9) 18.1 1.0 Cash and cash equivalents at beginning of year*********************************.**************************** 47.9 29.8 28.8 Cash and cash_ equivalents at end of year ..................... : ............. . :.. :.... :...................... . $ 36.0 $ 47.9 $ 29.8 Cash paid during the year for:

Interest (reduced for the cost of borrowed funds capitalized as AFC) ............................... . $ 277.1 $ 295.4 $ 314.5 Income taxes ................................................................................................... . 230.0 216.1 215.8 The accompanyip.g notes are an integral part of.the financial statements.

t 31

VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A. Significant Accounting J>olicies:

General Virginia Electric and Power Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives, munici-palities, power marketers and other utilities. The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. The Company has organized a wholesale power group to engage in off-system wholesale purchases and sales of electricity and purchases and sales of natural gas; and that group is devel-oping trading relationships beyond the geographic limits of Virginia Power's retail service territory. Within this document, the terms "Virginia Power" and the "Company" shall refer to the entirety of Virginia Electric and Power Company, includ-ing, without limitation, its Virginia and North Carolina operations, and all of its subsidiaries.

• The Company's accounting practices are generally prescribed by the Uniform System of Accounts promulgated by the regulatory commissions having jurisdiction and are in accordance with generally accepted accounting principles applicable to regulated enterprises. The financial statements include the accounts of the Company and its subsidiaries, with all signifi-cant intercompany transactions and accounts being eliminated on consolidation.

The Company is a wholly-owned subsidiary of Dominion Resources, Inc., a Virginia corporation.

The preparation of financial statements in conformity with generally accepted accounting principles requires manage-ment to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenues Revenues are recorded on the basis of services rendered, commodities delivered or contracts settled.

Property, Plant and Equipment Utility plant is recorded at original cost, which includes labor, materials, services, AFC, where permitted by regulators, and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense and clearing accounts. The cost of additions and replacements is charged to the appropriate utility plant account, except that the cost of minor additions and replacements, as provided in the Uniform System of Accounts, is charged to maintenance expense.

Depreciation and Amortization .

Depreciation of utility plant (other than nuclear fuel) is computed on the straight-line method based on projected use-ful service lives. The cost of depreciable utility plant retired and the cost of removal, less salvage, are charged to accumu-lated depreciation. The provision for depreciation provides for the recovery of the cost of assets including the estimated cost of removal, net of salvage, and is based on the weighted average depreciable plant using a rate of 3.2 percent for 1997, 1996 and 1995.

• Operating expenses include amortization of nuclear fuel, which is provided on .a unit of production basis s~fficien~ to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal .costs.

Federal Income Taxes The Company files aconsolidated federal income tax return with Dominion Resources. 0 Deferred investment tax credits are being amortized o~er the service *lives of the property giving rise to such credits.

32

llowance for Funds Used During Construction The applicable r~gulatory Uniform System of Accounts defines AFC as the cost during the construction period of bor-rowed funds' used for construction purposes and a reasonable rate on other funds when so used.

The pretax AFC rates for 1997, 1996 and 1995 were 6.6 percent, 8.i percent and 8.9 percent, respectively. No AFC is accrued for approximately 83 percent of the Company's construction work in progress, which is instead included in rate base. A cash return is currently collected on the portion of construction work in progress included in rate base._

Deferred Capacity and Defei:red Fuel Expense Approximately 80 percent of capacity expenses and _90 percent of fuel expenses incurred as part of providing regulated electric service are subject to deferral accounting. The difference between reasonably incurred actual expenses and the level of,expenses included in current rates is deferred and matched against future revenues.

Amortization of Debt Issuance Costs The Company defers and amortizes any expenses incurred in the issuance of long-term debt, including premiums and discounts associated with such debt, over the lives of the respective issues. Any gains or losses resulting from the refinanc-ing of debt are also deferred and amortized over the lives of the new issues of long-term debt as permitted by the appro-ptjate regulatory jurisdictions. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.

• Cash and_ Cash Equivalents Current banking arrang.ements generally do not require checks to be funded until actually presented fo~ payment. At December 31, 1997 and 1996, the Company's accounts payable included the net effect of checks outstanding but not yet presented for-payment of $55.8 million and $64.8 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand and temporary investments purchased with an initial maturity of three months or less.

Commodity Contracts The trading activities of Virginia Power's wholesale power group include fixed-price forward contracts and the pur-chase and sale of over-the-counter options that require physical delivery of the underlying commodity. Furthermore, in order to manage price risk associated with natural gas sales and fuel requirements for the utility operations, the Company uses exchange-for-physical contracts, basis swaps, NYMEX natural gas futures contracts, *as well as options on natural gas futures contracts.

_ . Options, exchange-for-physical contracts, basis swaps and futures contracts are marked to market with resulting gains and losses reported in earnings, unless such instruments are designated as hedges for accounting purposes. Fixed price for-ward contracts, initiated for trading purposes, also are marked to market with resulting gains and losses reported in earnings.

For exchange-for-physical contracts, basis swaps, fixed price forward contracts and options which require physical delivery of the underlying commodity, market value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Futures contracts and options on futures contracts are marked to market based.on closing exchange prices. No contracts were designated as hedges during 1997.

Purchased options and options sold are reported in Deferred Debits and Other Assets - Other and in Deferred Credits and Other Liabilities - Other, respectively, until exercise or expiration. Gains and losses resulting from marking positions to market are reported in Other Income. Net gains and losses resulting from futures contracts and options on futures con-tracts and settlement of basis swaps are included in Fuel, Net. Amortization of option premiums associated* with sales and purchases are included in Revenues - Other and Fuel, Net, respectively. Cash flows from trading activities are reported in Net Cash Flow from Operating Activities. _

Reclassification Certain amounts in the 1996 and 1995 financial statements have been reclassified.to conform to the 1997 presentaiion.

33

B. Income Taxes:

Details of income tax expense ai:e as follows:

• Years 1997 1996 1995 (Millions)

Current expense:

Federal .................................................................................... . $222.1 $185.6 $230.6 State ......................................... : .............................................. . 8.6 2.4 2.1 230.7 188.0. 232.7 Deferred expense:

Utility plant differences .............................................................. . 41.3 65.4 48.9 Deferred fuel and capacity .......................................................... . 11.0 22.3 (6.0)

Debt issuance costs .................................................................... . (2.1) (2.8) 1.3 Terminated construction project costs ........... , ............................... . (5.8) (5.1) (4.4)

Other ........................................................................................ . ~ ..J!Ql.)*. __.@l),

35.5 _§2.J 11.7 Net deferred investment tax credits-amortization .................... : ....... '. ... . ~ ~) __.ill_:2)

Total income tax expense ............................................................... . $249.3 $240.2 $227.5 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 1997 1996 1995 (Millions)

Federal income tax expense at statutory rate of 35 percent .............. :... . $251.4 $244.1 $231.1 Increases (decreases) resulting from:

Utility plant differences .............................................................. : 7-7 5.7 3.2 Ratable amortization of investment tax credits ......................... *...... . . _(16.9) (16.9) (16.9)

Terminated construction project cqsts **:***************************************** 5.0 5.0 5.0 State income tax, net of federal tax benefit...................................... . 4.9 2.4 2.2 Other, net ................................................................................. . ~ ___@1) 2.9

• ____Ql) ~) ~

Total income tax expense *,****************************************:***********:*****.-.,:*. $249.3. $240.2 $227.5 Effective tax rate .......... *........................ , .. , ..................................... . ,34.7% 34.4% 34.5%

The Company's net accumulated deferred income taxes consist of the following:

.Years 1997 1996 (Millions)

Deferred income tax assets:

Investment tax credits .... :...... :.........*.......... '.: ......... :................... :............. . $ 84.4 $ 90.3 Deferred income tax \iabilities: .

Utility plant differences., ......... : ............................................................... . 1,479.8 1,440.5 Terminated construction project costs .. : ................. :... :....... :...................... . 8.6 14.4 Income taxes recoverable through future rates ............................................ . 169.5 168.8 Other ................................................................................................... . 33.5 31.8 Total deferred income tax liabilities**********::*:****:*******************************************, 1,691.4 1,655.5 Total net accumulated deferred income taxes ................................................. . $1,607.0 $1,565.2 34

C. Nuclear Operations:

Decommiss~oiiing ,

When the Company's nuclear units cease operations, we are obligated to decontaminate or remove radioactive contami-nants so that the property will not require NRC oversight. This phase of a nuclear power plant's life cycle is termed decom-missioning. While the units are operating, we are collecting from ratepayers amounts that, when combined with investment earnings, will be used to fund this future obligation.

• The amount being accrued for decommissioning is equal to the amount being collected from ratepayers and is included in Depreciation and Amortization Expense. The decommissioning collections were $45.8 million, $36.2 million and $28.5 mil-lion in 1997, 1996 and 1995, respectively. These dollars. are deposited into external trusts. through which the funds are invested.

Net earnings of the trusts' investments are included in Other Income in* the Company's Consolidated Statements of Income. In 1997, 1996 and 1995, respectively, net earnings were $20.5 miliion, $16.0 million and $15.9 million. The accre-tion of the decommissioning obligation is equal to the trusts' net earnings and also is recorded in Other Income. Thus, the net impact of the trusts on Other Income is zero.

The accumulated provision for decommissioning, which is included in Utility Plant Accumulated. Depreciation in the Company's Consolidated Balance Sheets, includes the accrued expense and accretion described above and any unrealized gains and losses on the trusts' investments. At December 31, 1997, the net unrealized gains were $149.5 million, which is an increase of $69.0 over the December 31, 1996, amount of $80.5 million. The total accumulated provision for decommis-sioning at December 31, 1997, was $578.7 million, including $9.6 million accrued in 1997 and deposited to the trusts in January 1998. The provision was $443.3 million at December 31, 1996.

The total estimated cost to decommission the Company's four nuclear units is $1 billion based upon a site-specific study that was completed in 1994. We plan to update this*estimate in 1998. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. This method assumes that dismantlement and other decom-missioning activities will begin shortly after cessation of operations, which under current operating licenses will begin in 2012 as detailed in the table below.

Surry North Anna Total Unit 1 Unit 2 Unit 1 . Unit 2 All Units NRC license expirat~on year ................................................. :..... . 2012 2013 2018 2020 (Millions)

Current cost estimate (1994 dollars) ............................................. . $272.4 $274.0 $241.0* $253.6 $1,047.0 Funds in external trusts at 12/31/97 ............................................. . 156.5 151.8 134.2 126.6 569.1 1997 contribution to external trusts .............................................. . 10.6 10.8 7.6 7.2 36.2 The Financial Accounting Standards Board (FASB) is reviewing the accounting for nuclear plant decommissioning. In 1996, the FASB tentatively determined that the estimated cost of decommissioning should be reported as a liability rather than as accumulated depreciation and that a substantial portion of the decommissioning obligation should be recognized ear-lier in the operating life of the nuclear unit. If the industry's accounting were changed to reflect FASB's tentative proposal, then the annual provisions for nuclear decommissioning would increase. During its deliberations, the FASB expanded the scope* of the project to include similar unavoidable obligations to perform closure and post-closure activities for non-nuclear power plants. Therefore, any forthcoming standard also may change industry plant depreciation practices. Any impact related to other Company assets cannot be determined at this time.

Insurance The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $8.9 billion for a single nuclear incident. The Price-Anderson Amendments Act of 1988 allows for an inflationary provision adjustment every five years. The Company has purchased $200 million of coverage from the commercial insurance pools with the remainder pro-vided through a mandatory industry risk sharing program. In the event of a nuclear incident at any licensed nuclear reactor t in the United States, the Company could be assessed up to $81.7 million (including a 3 percent insurance premium tax for Virginia) for each of its four licensed reactors not to exceed ~10.3 million (includirig a 3 percent insurance premium tax for Virginia) per year per reactor. There is no limit to the number of incidents for which this retrospective premiu*m can be assessed.

35

Nuclear liability coverage for claims made by nuclear workers first hired on or after January l, 1988, except those aris--

ing 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 cov-erage for the industry is $400 million ($200 million policy limit with automatic reinstatements of an additional $200 mil-lion). The Company's maximum retrospective assessment is approximately $12.3 million (including a 3 percent insurance premium _tax for Virginia).

The Company's current level of property insurance coverage ($2.55 billion for North Anna and $2.40 billion for Surry) exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The Company's nuclear property insurance is provided by Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL), two mutual insurance companies, and is subject to retrospective premium assessments, in any poiicy year in wh.ich losses exceed the funds available to these insur-ance companies. The maximum assessment for the current policy period is $37 .0 million. Based on the severity of the inci-dent, the Boards of Directors of the Company's nuclear insurers have the discretion to lower the maximum retrospective premium assessment or eliminate either or both completely. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination, the Company has the finan-cial responsibility for these losses.

The Company purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Virginia Power is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period's maxi-mum assessment is $8.7 million.

As part owner of the North Anna Power Station, ODEC is responsible for its share of the nuclear decommissioning obligation and insurance premiums applicable to that station, including any retrospective premium assessments and any losses not covered by insurance.

D. Utility Plant:

Utility plant consisted of the following:

At December 31, 1997 1996 (Millions)

• Production $ 7,684.2 $ 7,691.9 Transmission .......................................................... , .............................. :..... 0 ******* 1,415.7 1,386.5 Distribution ...................................................................................................... . 4,559.2 4,385.4 Other .......................................................................................................... : ... . . 894.2 862.9 14,553.3 14,326.7 Construction work in progress ............... *............................................................. . 240.9 180.1 Total ........................................................... *.......................................... . $14,794.2 $14,506.8 36

E. Jointly Owned Plants: . . .

The following i'nforination relates to the Com:pany's-prbp_ortionate share of jointly own~d piants a(December 31, 1997:

'

• p. * ' **

North Bath County Anna Clover Pumped Storage Power Power Station Station Station

• Ownership interest ................................................................ . 60.Q% 88.4% 50.0%

(Millions)

Utility plant in service ............... .'........................................... . $1,072.9 $1,819.4 $533.3 Accumulated depreciation .. :................................................... . 229.1 819.2 26.3 Nuclear fuel ......................................................................... . 403.6 Accumulated amortization of nuclear fuel ........................... *..... .. . 383.4 Construction work in progress .......................... , .....*................ . '.1 61.2 1.1 The co-owners are obligated to pay their share of all future construction expenditures and operating costs* of the jointly owned facilities in the same proportion as their respective ownership. interest. The Company's share of operating costs is classified in the appropriate operating expense (fuel, operations and maintenance, depreciation, taxes, etc.) in the Consoli-dated Statements of Income.

F. Regulatory Assets-Other Certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets and are recognized in income as the related _amounts are included in rates and recovered from customers. The Company's regulatory assets included the following: * * * *

• At December 31, 1997

• 1996 (Millions)

Income taxes recoverable through future rates ........................................................... . . $478.9 $477.0 Cost of decommissioning DOE uranium enrichment facilities ......................... :........... .. 67.6 73.5 Deferred losses on reacquired debt, net ..................................................................... . 85.4 91.5 North Anna Unit 3 project termination costs ............................................................. . 42.3 73.1 Other .............. .- ............................................. *........ , ... , ......................................... . 55.1 52.7 To_tal ........................*...................................................... .-: ............................... *.... . $729.3 $767.8 Income taxes recoverable through future rates represent principally the tax effect of depreciation differences not nor-malized in earlier years for ratemaking purposes. These amounts are amortized as the *related temporary differences*reverse.

The costs of decommissioning the Department of Energy's (DOE) uranium enrichment facilities have *been °deferred and I represent the unamortized portion of-Virginia Power's required contributions to a fund for decommissioning and decontami-nating the DOE's. uranium enrichment facilities. Virginia Power is making such contributions over a 15-year period with escalation for inflation. These costs are being recovered infuel rates.

• 1 * * ' * *

• Losses or gains on reacquired debt are deferred and amortized over the lives of the n*ew issues oflong-term debt. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.

The construction of North Anna Unit 3 was terminated in November 1982. All retail jurisdictions have permitted recov-ery of the incurred costs. For Virginia and FERC jurisdictional customers, the amounts deferred are being amortized from the date termination costs were first includible in rates.

• The incurred costs underlying these regulatory assets may represent expenditures by the Company or may represent the recognition of liabilities that ultimately will be settled at some time in the future. For ~ome of those regulatory assets rep-resenting past expenditures that are not included in the Company's rate base or used to adjust the Company's capital struc-ture, the Company is not ailowed to earn a return on the unrecovered balance. Of the $729.3 million of regulatory assets at December 31, 1997, approximately $57.7 million represent past expenditures that are effectively excluded from rate base by the Virginia State Corporation _Commission which has primary jurisdiction over the Company's rates. However, of that amount $42.3 million represent the present value of amounts to be recovered through future rates for North Anna Unit 3 37

project termination costs, and thus reflect a redµction in the actual dollars to be recovered through future rates for the time value of money. The C9mpany does not earn a retm:n on the. remain_ing $15.4 million of regulatory assets, effectively excluded from rate base, to be recovered over various recovery periods up to 21 years; depending on the nature of the deferred costs.

G. Leases:

. Plant and property under capital leases included the following:

At December 31,

• 1997 1996 (Millions)

Office buildings (*) .................................................................. :................ *. :..... *. :: ... * $34.4 $34.4 Data *processing equipment ........................................... :....................... :............ :.. :.. 13.3 2.5 Total plant and property under capital leases ............................ :. .".................... . 47.7 36.9 Less accumulated amortization .................................... *.* ... , : ......................................... . 17.8 13.3 Net plant and property under capital leases . .- .......................................... ~ .................. . $29.9* $23.6

(*) The Company leases its principal office building from its parent, Dominion Resources. The capitalized cost of the prop-erty under that lease, net of accumulated amortization, represented $22 million and $23 million at December 31, 1997 and 1996, respectively. Rental payments for such lease were $3 million for each of the three years ended December 31, 1997, 1996 and 1995.

• The Company is responsible for expenses in conn.ection with the leases noted above, incl;;din*g ip.aintenance.

Future minimum lease payments under noncancellable capital leases and for operating leases that have initial or remain-

• ing lease terms in excess of one year as of December 31, 1997, are as follows:

Capital Operating Leases Leases (Millions) 1998 ***********************************************.***.************************.***************************************'**** $ 7.1 $11.4 1999 ............................................................*........................................... ;'..i .. ; *..*..*. 6.4 9.9 2000 ********************************************************************************.*******************.*********.**.****** 4) 7.1 2001 .................... *................................................................................................. . 3.2 3.9 2002 .................................................................................. :...............:.. :... :.: .... :... : 3.0 3.2 After 2002 *********************************************************:**.*********************************:*****:****.:*** 16.7 22.9 Total future minimum le~se payments ............ , ........ ::: ........* ,:***********'*****,:**: ..:... ::.'..:: .... ,. $40.7 $58.4 Less interest element included above .......................................................................

.* ' '1. *

.. 10.8 Present value of future ~inimum lease payi;nents ............. : . .'................. , ...... : ... , .... : *..... $29.9 Rents on leases, which have been charged to operations expense, were $17.6 million, $16.5 iniliion and $13.6 million for 1997, 1996 and 1995, respectively..

38

. Long-term Debt:

Long-term debt included the.following:

At December 31, 1997 1996

• (Millions)

First and Refunding Mortgage Bonds (1):

Series U, 5.125%, due 1997 .... :.: ..................................... : .......... : ................... .. $ 49.3 1992 Series B, 7.25%, due 1991 ...... :....*: .... :: ........ :.: ....... :: .................. ;............. . 250.0 1988 Series A, 9.375%, due 1998 ...................................,. ... , ...................... : ...... . $ 150.0 150.0 1992 Series F, 6.25%, due 1998 ....................................................................... . 75.0 75.0 1989 Series B, 8.875%, due 1999 ...... : ............................................................. . 100.0 100.0 1993 Series C, 5.875%, due 2000 ...................... : ............................... .; ............ . 135.0 135.0 Various series, 6.0-8%, due 2001-2004 ..... , ....................................................... . 805.0 805.0 Various series 6.75%-7.625%, due 2007 ... , .. , ..................................................... . 415.0 215.0 Various series, 5.45%-8.75%, due 2021°2025 ......... , ........................................... . 1,144.5 1,144.5 Total First and Refunding Mortgage Bonds ................................................. . 2,824.5 2,923.8 Other long-term debt:

Tenn notes:

Fixed interest rate, 6.15%-10.00%, due 1997-2003 .......................................... . 551.i 503.1 Tax exempt financings (2):

Money M_arket Municipl:lls, due 2.007-2027(3) .................................. , ............. . 488.6 488.6 Convertible interest rate,. due 2022 / ............ :... '. ...................... .':. :.................. . 10.0 Total other long-term debt_ ...................... , ...... _............................................ . 1,049.7 991.7 3,874.2 3,915.5 Less amounts due within o_ne year:

First and Refunding Mortgage Bonds ............................................................... . 225.0 299.3 Tenn notes .......... : .................................................... .-., ................ .- ................ . 108.5 12.0 Total amount due within one year ....... :*........................... : ......................... . 333.5 -- 311.3 Less unamortized*discount, net of premium ....................... :: ................................. . 26.1 24.8 Total long-term debt ......... : ...... : .........*~*-****************,*.***********:*******-*************:. $3,514.6 $3,579.4 (1) Th~ First and Refunding Mortgage Bonds ~e secured by a mortgage lien on subst~ntially all of the Company'_s property.

(2) Certain pollution control facilities at the Company's generating facilities have been pledged or conveyed to secure the financings. *

(3) Interest rates vary based on shoit-temi, tax-exempt market rates. Fcir 1997 and 1996, the weighted average daily interest rates were 3.74 percent anci' 3.57 percent, respectively. Although these bonds are re-marketed within a one year period, they are classified as long-term debt because the Company intends to maintain the debt and they are supported by long-term bank commitments.

The following amounts of debt will mature during the next five years (in millions): 1998 - $333.5; 1999 ~ $321.0; 2000-$195.5; 2001 ___.: ._ $160.7; and ':2002 ~ $315.o: * * . * . . ,.. * *.. . * ..

I. Company Obligated Mandatorily Redeemable rrererred Securities of Subsidiary Trust:

Virginia Power Capital Trust I (VP Capital Trust) was established as a subsidiary of the Company for the sole purpose of selling $135 million of Preferred Securities (5.4 million shares at $25 par) in 1995. The Company concurrently issued t

$139.2 million of its 1995 Series A, 8.05% Junior Subordinated Notes (the Notes) in exchange for the $135 million realized from the sale of the Preferred Securities. and $4.2 million of common securities of VP Capital T~st. The Preferred Securi-ties and the common securities represent the total beneficial ownership interest in the assets held by VP Capital Trust. The Notes are the sole assets of VP Capital Trust.

39

The Preferred Securities are subject to mandatory redemption upon repayment of the Notes at a liquidation amount 0

$25 plus accrued and unpaid distributions, including interest. The Notes are due September 30, 2025. However, that date may be extended up to an additional ten years if certain conditions are satisfied.

J. Preferred Stock Subject to Mandatory Redemption:

The total number of authorized shares for' all preferred stock (whether or not subject to mandatory redemption) is

• 10,000,000 shares. Upon involuntary liquidation, dissolution or winding-up of the Company, all presently outstanding pre-ferred stock is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.

There are two series of preferred stock subject to mandatory re,ciemption outstanding as of December 31, 1997:

Issued and Outstanding Dividend Shares

$5.58 400,000 . Shares are non-callable prior to redemption at 3/1/2000

$6.35 1,400,000 Shares are non-callable prior to redemption at 9/1/2000 Total .............. . 1,800,000 There were no redemptions of preferred stock during 1997 or 1996. In 1995, the Company redeemed 417,319 shares of its $7.30 dividend preferred .stock subject to mandatory redemption.

K. Preferred Stock Not Subject to Mandatory Redemption:

Shown below are the series of preferred stock not subject to mandatory redemption that were outstanding as of Decem-ber 31, 1997.

Entitled per Share upon Liquidation Issued and And Thereafter to Outstanding Amounts Declining in.

Dividend Shares Amount Through Steps to

$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

• 7.05 ***************************************************************************** 500,000 105.00 7/31/03 $100.00 after 7/31/13 6.98 ........... ;................................................................ . 600,000 105.00 8/31/03 $100. 00 after 8/31 /13 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 9/92, Series A (*) .... .'.............................................. . 500,000 100.00

. MMP 9/92, Series B (*) .................................................. . 500,000 100.00 Total ......................................................................... ,, ... , 5,090,140

(*) Money Market Prefeired (MMP) dividend rates are variable and are set every 49 days via an auction process . .The com-bined weighted average rates for these series in 1997, 1996 and 1995, includi~g fees for broker/dealer agreements, were 4.71 percent, 4.48 percent and 4.93 percent, respectively.

In 1995, the Company redeemed 400,000 shares of its $7.45 dividend preferred stock not subject to mandatory redemp-tion and450,000 shares of its $7.20 dividend preferred stock not subject to mandatory redemption.

L. Common Stock:

There were no changes in the number of authorized and outstanding shares of the Company's Common Stock during the three* years en_ded December 31, 1997.

40

M. Short-term Debt:

The Company's commercial paper program has a maximum borrowing capacity of $500 million. It is supported by two credit facilities. One is a $300 million, five-year credit facility that was effective on June 7, 1996, and expires on June 7, 2001. The other is a $200 million credit facility that originated on June 7, 1996, with an initial term of 364 days and pro-visions for subsequent 364-day extensions. It was renewed on June 6, 1997, for 364 days.

The total amount of commercial paper outstanding as of December 31, 1997, was $226.2 million with a weighted aver-age interest rate of 5.88 percent. This represents a decrease of $86.2 million from the December 31, 1996, balance of $312.4 million and a weighted average interest rate of 5.51 percent.

N. Retirement Plan, Postretirement Benefits and Other Benefits:

Under the terms of its benefit plans, the Company reserves the right to change, rnodify or terminate the*plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Retirement Plan The Company participates in the Dominion Resources, Inc. Retirement Plan (the Retirement Plan), a defined benefit.

pension plan. The benefits are based on years of service and average base compensation over the consecutive 60-month period in which pay is highest.

The Company's pension plan expenses were $20.6 million, $24.8 million and $20.3 million for 1997, 1996 and 1995, respectively, and the amounts funded by the Company were $27.0 million, $28.4 million and $42.7 million in 1997, 1996 and 1995, respectively.

Postretirement Benefits 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 cpmpleted at least 10 years of service after attaining age 45. These and similar benefits for active employees are provided through insurance companies.

Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Net periodic postretirement be.nefit expense was as follows:

Year Ended December 31, 1997 1996 (Millions)

Service cost $12.3 $ 12.1 Interest cost 25.1 23.9 Return on plan assets ......................................................... ~ .............................. . (25.3) . (16.6)

Amortization of transition obligation .................................................................... . 12.1 12.1 Net amortization and deferral *......... : ................................................................... . 13.4 7.1 Net periodic postretirement benefit expense........................................................... . $ 37.6 $ 38.6 41

The following table sets forth the funded status of the plan:

At De,cember 31, 1997 199'6 (Millions)

Fair value of plan assets ................................................ ; ............................... . $ 176.6 $ 133.0 Accumulated postretirement benefit obligation: .

Retirees ........................................... :....................................................... . $ 224.5 $ 201.7 Active plan participants ..................................... :.. ...................................... . 136.3 -122.2 --

Accumulated postretirement benefit obligation ............................................ . 360.8 323.9 Accumulated postretirement benefit obligation in excess of plan assets ..... , ..... . (184.2) (190.9)

Unrecognized transition obligation .................................................................... . 180.8 192.8 Unrecognized net experience (gain)/loss ........................................................... . {1.8) . {3.6)

Accrued postretirement benefit cost ................................................................. . $ {5.2) $ {1.7)

A one percent increase in the health care cost .trend rate would result in an increase of $5.0 million in the service and interest cost components and a $39.5 million increase in the accumulated postretirement benefit obligation.

Significant assumptions used in determining the postretirement benefit obligation were:

1997 1996 Discount rates ........................ '. .......................... :.: .. 7.75% 8%

Assumed return on plan assets ................................ . 9% 9%

Medical cost trend rate .......................................... . 6% for 1st year 7% for 1st year 5% for 2nd year 6% for 2nd year Scaling down to 4.75% Scaling down to 4.75%

beginning in the year beginning in the year

. 2000 2000 The Company is recovering these costs in rates on an accrual basis in all material respects, in all jurisdictions. The funds being collected for Other Postretirement Benefits (OPEB) in rates, in excess of OPEB benefits actually paid during the year, are contributed to external benefit trusts under the Company's current funding policy (see Future Issues -

Competition - Exposure to Potentially Stranded Costs under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINAN~

CIAL CONDITION AND RESULTS OF OPERATIONS).

0. Restructuring:

The Company announced the implementation phase of its Vision 2000 program in March 1995. During this phase, the Company began i:eviewing operations with the objective of outsourcing services where economical and appropriate and re-engineering the remaining functions to streamline operations. The re-engineering process has resulted in outsourcing, decentralization, reorganization and downsizing for portions of the Company's operations. As part of this process, the Com-pany has reevaluated. its utilization of capital resources in the operations of the Company to identify further opportunities for operational efficiencies through outsourcing or re-engineering of its processes.

• Restructuring charges of $18.4 million, $64.9 million, and $117.9 million in 1997, 1996 and 1995, respectively, included severance costs, purchased power contract restructuring and negotiated settlement costs, capital project cancellation costs, and other costs incurred directly as a result of the Vision 2000 initiatives. While the Company may incur additional charges for severance in 1998, the amounts are not expected to be significant.

Employee Severance In 1995, the Company established a comprehensive involuntary severance package for salaried employees who may no longer be employed as a result of these initiatives. The Company is recognizing the cost associated with employee termi-nations in accordance with Emerging _Issues Task Force Consensus No. 94-3 as management identifies the positions to be eliminated. Severance payments will be made over a period not to exceed twenty months. Through December 31, 1997, management had identified 1,977 positions to be eliminated. The recognition of severance costs resulted in charges to opera-tions in 1997, 1996 and 1995 of $12.5 millfon, $49.2 million and $51.2 million, respectively. At December 31, 1997, 1,619 employees had been terminated and severance payments totaling $74 million had been paid. The Company estimates that 42

ese staffing reductions will result in annu.al savings, in the range of $80 million. to $90 million. However, such savings are nities.

eing offset by salary increases, outsourcing costs and increased payroll costs as$ociated with .staffing for growth opportu-Purchased Power Contracts In .an effort to minimize its exposure t~ potential stranded investment, the Company is evaluating its long-term pur-chased power contracts and negotiating modifications to their terms, including cancellations, where it is determined to be economically advantageous to do so. The Company has also negotiated settlements with several other parties to terminate their rights to sell power to the Company. The cost of contract modifications, contract cancellations and negotiated settle-ments was $3.8 million, $7.8 million and $8.1 million in 1997, 1996 and 1995, respectively. Using contract terms, estimated quantities of power that would have otherwise been delivered and other relevant factors atthe time of each transaction, the Company estimated that its ann*ual future purchased power costs; including energy payments, would *be .reduced by up to

$0.8 million, $5.8 million and $147.0 million for the 1997, 1996 and 1995 transactions, respectively.The cost. of alternative sources of power that might ultimately be required as a result of these settlements is expected to be significantly less than the estimated reduction in purchased power costs.

Construction Project Restructuring charges reported in 1995 included $37.3 million for the cancellation of a project to construct a facility to handle low level radioactive waste at the Company's North Anna Power Station. As a result of reevaluating the handling of low level radioactive waste, the Company concluded that the facility should not be completed due to the additional capital investment required, decreased Company. volumes of low level radioactive waste resulting from irriprovements in station procedures and the availability of more economical offsite processing.

• P. Accelerated Cost Recovery:

In this increasingly competitive environment, the Company also has concluded that it is appropriate to .utilize available cost reductions, such as those generated by the Vision 2000 program (see Note Oto the CONSOLIDATED FINANCIAL STATEMENTS), to accelerate the write-off of existing unamortized regulatory assets. Not only will this strategically posi-tion the Company in anticipation of competition, but it also reflects the Company's commitment to mitigate its exposure to potentially stranded costs (see Competition in MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CON-.

DffiON AND RESULTS OF 'OPERATIONS). The Company identified savings of $38.4 million in 1997 and $26.7 million in 1996 which were used to establish a reserve for expected adjustments to regulatory assets.

Q. Commitments and Contingencies:

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory. commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. 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.

Utility Rate Regulation In March 1997, the Virginia Commission issued an order that Virginia Power's base rates be made interim and subject

. to refund as of March 1~ 1997. This order was the result of the Commission Staff's report on its review of Virginia Pow-er's 1995 Annual Informational Filing, which concluded that Virginia Power's present rates would cause Virginia Power to earn in excess of its authorized return on equity. The Staff found that, for'purp*oses of establishing rates prospectively, a rate reduction of $95.6 million (including a one-ti:ine adjustment of $29.7 million to Virginia Power's deferred capacity balance at December 31, 1996) may be necessary in order to realign rates to the authorized level. In March 1997, Virginia Power filed its Alternative Regulatory. Plan (ARP) based on 1996 financial information. Subsequently, the Commission consoli-dated the proceeding concerned with the 1.995 Annual Informational Filing with the proceeding that includes the ARP pro- .*

posed by the Company. ** * * *

• 1 In December 1997, Virginia: Power sought to withdraw its ARP, having concluded that resolution of the cost recovery t issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that the Company may withdraw its support of the ARP but has reserved the right to continue consideratio~ of the ARP as well as other regulatory alternatives. In addition, the Commission will continue to consider the issues arising out of the 1995 Annual Informational 43

Fjling. The Commissi~n's Staff is scheduled to *me its testimony on March 24, 1998; Virginia Power's rebuttal is to be file by April 27, 1998; and the reply testimony is to be filed by May 11,

• 1998. A public hearing is schedpled to commence on May 19, 1998.

Virginia Power's previous filings in this proceeding support m~intaining the Company's rat~s* at current levels; how-ever, opposing parties have made filings recommending rate reductions in excess of $200 million. At this time, management cannot predict the ultimate outcome of the p~oceeding* and its impact on the Company's results of operations, cash *flows or financial position. *

• Retrospective Premium Assessments Under several of the Company's nuclear insurance policies, the Company is subject to retrospective premium assess-ments in any policy year in which losses exceed the funds available to these insurance companies. For a<;Iditional informa-tion, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.. '

Construction Program The Company has made substantial commitments in connection with its construction program and nuclear fuel expen-ditures. Those expenditures are estimated to total $588.1 million (excluding AFC) for 1998. The Company presently esti-mates that all of its 1998 construction expenditures, including nuclear fuel, will be.met through cash flow from operations.

Purchased Power Contracts ..

Since 1984, the Company has entered into contracts for*. the long-term .purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. The Company has 57 non-utility purchase contracts with a combined dependable summer capacity of 3,277 MW.

The table below reflects the Company's minimum commitments as of December 31, 1997, for power purchases from, utility and non-utility suppliers.

Commitment Year Capacity Other (Millions) 1998 ...................................... , ........................................ . $ 813.5 $154.9 1999 ................................................................. , .............. . 816.7 156.7 2000 ................................ : .............................................. : 723.8. 92.0 2001 ............................................................................... . 716.0 83.7 2002 ********************************************************************************* 721.1 81.5 Later years .; ..... *............................... *........ :........ .'..*............ . 9,069.6 388.2 Total ........... :................................................ : .............. . $12,860.7 $957.0 Present value of the total ................................................... . $ 5,878.0, $553.3 Payments made by Virginia Power in satisfaction of the minimum purchase commitments shown in the above table are subject to reduction or partial refund if (1) the non-utility suppJiers fail to meet performance requirements or (2) changes in federal or.. state law or administrative actions disallow or have the effect of disallowing Virginia Power's recovery .of suc.h costs from its customers. The amount of such payment reductions or refunds, if any,. will be .determined and administered as provided in individual supply contracts, although (1) the deferral of refund obligations, (2) disputes over the applicabil-ity of such payment reductions or refund obligations and (3) the ability of some non-utility suppliers to make refunds co.uid limit Virginia Power's ability to benefit from these contract provisions, * -

• 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, emer-gency, limited term, short-term and other purchases for utility operations, as well as for trading purposes) for the years 1997, 1996 and 1995 were $1,381 mil!ion, $1,183 mil,lion and $1,093 million, respe_ctively. For.a discussion of the Company's efforts to restructure certain purchased power contracts, see Note O to CONSQLIDATED FINANCIAL STATEMENTS..

Fuel Purchase Commitments The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (mil-lions): 1998 - $293; 1999-$233; 2000- $144; 2001 -$144; and 2002-$127.

t 44

• Sale of Power .

The Company en,ters into agreements with other utilities and with other parties to purchase and sell capacity and energy.

These agreements may cover c_urrent and future periods ("forward positions"). The volume of these transactions varies from day to day based on the market conditions, our current and anticipated load, and other factors. The combined amounts of sales and purchases range from 500 MW to 7,000 MW at various times during a given year. These operations are closely monitored from a risk management perspective.

Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal; state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. These laws and regulations can result in increased capital, operating and other costs as a result of com-pliance, remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemaking process; however, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely impacted.

Site Remediation The EPA has identified the Company and several oth,er entities as Potentiapy Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania: The estimated future remediation costs for the sites are in the range of $61.5 mil-.

lion i:o $72.5 million. The Company's proportionate share of the cost is expected to be in the range of $1.7 million to

$2.5 million, based upon allocation formulas and the volume of waste* shipped .to the sites. The Company has accrued a

. reserve of $1.7 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at*

these sites, the Company has determined that it is probable that the PRPs will fully pay the costs apportjoned to them.

The Company and Dominion Resources have remedial .action responsibilities remaining at two coal tar sites. The Com-pany accrued a $2 million reserve to meet its estimated liability _based on site stµ_dies and investigations perfo,rmed at th~se sites. In addition, two civil actions have been instituted against the City of Norfolk and Virginia Power by property owners*

who allege that their property has been contanunated by toxic pollutants originating from one of the coal tar sites now owned by the City of Norfolk and formerly owned by the Company. The first civil action reached settlement without trial in September 1997. The remaining plaintiff is seeking compensatory ,damages of $2 million and punitive damages of $1 million. It is too early in this case for the Company .to predict the .outcome. The Company has filed ariswers denying liabil-ity. No trial date has been set.

The Company generally seeks to recover its costs ass,aci~ted with envir.onmental remediation from third party insurers .

. At December 31, 1997, any pending or possible claims were not recognized as ari asset or offset against recorded obliga-tions of the Company.

R. Fair Value of Financial Instruments:

The Company used available market information and appropriat~ vaiuation methodologies to estimate the fair ~alue -of each class of fin.ancial instrument for which it is practicable to estimate fair value. These estimates are not necessarily indica-tive of the amounts the Company could realize in a market exchange. Iri addition, the use of different market assumptions may have a material effect on the estimated fair value amounts.

45

(

December 31, 1997 1996 Carrying Fair ,Carrying *Fair Amount Value Amount* Value (Millions)

Assets:

Cash and cash equivalents .............................................................. . $. 36.0 $ .36.0 $ 47.9 $ 47.9 Nuclear decommissioning trust funds ................................................ . 569.1 569.1 443.3 443.3 Liabilities and capitalization:

Short-term debt ............................................................................ _. .. 226.2 226.2

• 312.4 312.4 Long-term debt:

First and Refunding Mortgage Bonds ....................*........................ 2,824.5 2,937.7 2,923.8 2,95i4:

Medium-term notes .................................................................... . 551.l 573.7 503.1 531.3 Money Market Municipal tax-exempt securities .........._. .................... . 488.6 488.~ 488.6 488.6 Convertible interest rate tax-exempt bonds .................................... .. 10.0 10.4 Preferred stock subject to mandatory redemption ................................ . 180.0 186.6 180.0 185.8 Preferred securities of subsidiary trust .............................................. . 135.0 137.7 135.0 135.0 Cash and cash equivalents and short-term debt: The carrying amount'ofthese Items approximates fair value because of their short maturity. * * *

• Nuclear decommissioning trust funds: The fair value is based on available_ market information and generally is the average of bid and asked price.

First and Refunding Mortgage Bonds: Fair value is based on market quotations.

Medium-term notes: These notes were valued by discounting the remaining cash flows at a rate estimated for each issu_e. A yield curve rate was estimated to relate Treasury.Bond rates for specific issues to the corresponding maturities.

Money Market Municipal tax-exempt securities: The interest rates for these _notes vary so that fair value approximates carrying value.

Convertible interest rate tax-exempt bonds and.preferred stock subject to mandatory redemption: The fair value is based on inarket quotations or is estimated by discounting the dividend and principal payments for a represen'tative issue of each series over the average remaining life of the series. * *

• Preferred securities of subsidiary trust: Fair value is *based on market quotations.

S. Quarterly Financial Data (unaudited):

The following amounts reflect all adjustments, consisting of only normal recurring accruals.(except as discusseq. below),

necessary in the opinion of the management for a fair statement of the results for the interim periods.

Income from Net Balance Available Revenues O~erations Income for Common Stock (Millions) 1997 1st .......................................... . $1,174.8 $248.6 $110.3 $101.5 2nd ........................................ .-. 1,051.5 184.6 72.3 63.3 3rd ......................................... . 1,499.9 381.0 201.1 192.1 4th ****************************************** 1,352.8 205.1 85.4 76.5 1996 1st ............................. ..... :....... . $1,169.7 $311.l $152.8 $143.8 2nd ......................................... . 1,032.1 224.0 96.6 87.8 3rd.*****************************************~ 1,180.8 325.8 162.2 153.3 4th ****************************************** 1,038.3 149.1 45.7 36.9 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.

46

Certain accruals were recorded in 1997 and 1996.that are not ordinary,*recurring adjustments, consisting of restructur-ing (see Note O to CONSOLIDATED FINANCIAL STATEMENTS) and accelerated cost recovery (see Note p to CON-SOLIDATED FINANCIAL s:r:ATE:t\:1ENTS).. . .

• . Restructuring---;-Th~ Company expensed $~.3 million, $1.4 million *a114 $10.7 million during .the ~er::ond, third and fourth. q1,1arter:s of 1997, respectively, arid $5.4 million, $i ~.3 million, $4:6:million and)35.6. million .duripg' the first, ,sec-ond, third.and fourth quarters of i996. . , . . . . . . ... , , ' .

-ci.:.-.. :.!.1,,!

Accelerated cost recove,ry - Amounts reserved for acceler~ted cost ,recovery .werp $2.8. µiillio.n,. $~8.'.,., _million *and

$7 .3 million during the second, third and fourth 'q~arters **of 1997, respectively, and $26.7 million during 'tlie fourth quarter of*1996. *' * * * * * *

• • . -Charges for restructuring and accelerated cost recovery reduced Balance Available for Common Sto~k by.$5.8 million,

$19.3 million, and $11.7 million forlthe second, third,.and fourth quarters of 1997,respectively, and $3.5 million;*$12.5 mil-lion, $3.0 million and $40.6* million for: first, second; third and fourth' quarters *of J996. *

. . _1: ' ' ', ' ..

. '". ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

. None

)',.:*.

- . t",:+

• . ':*i,;

• ,',.1

/~.- *, ... '

.:, l, 1','

t  : ., ~

'{,

47

• • . .PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT On September 12, 1997,tlie Board of Directors elected Thos. E. Capps as *chairman, succeeding Jcihn B. Adams, Jr.,

who had held the position since 1994: Mr. Capps also*is Chairman of the Board 6fDirec(ors of Dominion Resources, ,Irie.,

the parent company of Virginia Power. * ** ** * '*

'(a) Information ccincerning d.irec.tors ofV1rgirtia Electric 'and Powet'Company is as follows:

. ", .. . .~ 1.; . . '. ' .

Year First Principal Occupation for Last 5 Years, Elected a Term Name and Age Directorships in Public Corporations. Director Expires Thos. E. Capps (62): Chairman of .the Board of Directors of Virginia Electric and 1986 2000 Power ,Company frQm September 12, ., 997 to date and*.

Chairman, President and Chief Executive Officer of Dominion Resources from September l, 1995 to date

• (from August 15, 1994 to September 1, 1995; Chairman 1

.andChief Executive Officer;.prior to August 15, 1994, *,

Chairman, President and Chief Executive Officer). He is a Director of Bassett Furniture Industries, Inc. and NationsBank Corporation.

Norman Askew (55) President and Chief Executive Officer of Virginia Electric 1997 1998 and Power Company and Executive Vice President of Dominion Resources from August 1, 1997 to date; Executive Vice President of Dominion Resources and Chief Executive.of East Midlands from February 21, 1997

. to August 1, 1997; Chief Executive of East Midlands from April 1, 1994 to February 21, 1997; Managing Director prior to April 1, 1994.

John B. Adams, Jr. {53) President and Chief Executive Officer of The Bowman 1987 1998 Companies, Fredericksburg, Virginia, a manufacturer and bottler of alcohol beverages and he is a Director of Dominion Resources.

John B. Bernhardt (68) Managing Director, Bernhardt/Gibson Financial 1986 2000 Opportunities, financial services, Newport News, Virginia.

He is a Director of Resource Bank and Dominion Resources.

James F. Betts (65) Former Chairman of the Board and President, The Life 1978 2000 Insurance Company of Virginia, Richmond, Virginia. He is a Director of Wachovia Corporation.

Jean E. Clary (53) President. and owner of Century 21. Clary and Associates, 1996 2000 Inc., South Hill, Virginia.

• John W. Harris (50) President, The Harris Group, a real estate consulting firm, 1997 1998.

Charlotte, North Carolina. He is a Director of Piedmont Natural Gas Company, Inc. and US Airways Group, Inc.

Benjamin J. Lambert, III (61) Optometrist, Richmond, Virginia. He is a Director of 1992 1998 Consolidated Bank and Trust Company, Student Loan Marketing Association (SallieMae) and Dominion Resources.

• Richard L. Leatherwood (58) Retired, Baltimore, Maryland .. Former President and Chief 1994 1998 Executive Officer, CSX Equipment, an operating unit of CSX Transportation, Inc.). He is a Director of Dominion Resources and CACI International, Inc.

Harvey L. Lindsay, Jr. (68) Chairman and Chief Executive Officer of Harvey Lindsay 1986 1999 Commercial Real Estate, Norfolk, Virginia, a commercial real estate firm. He is a Director of Dominion Resources ..

Kenneth A. Randall (70) Corporate Director for various companies, Williamsburg, 1971 1999 Virginia. He is a Director of Oppenheimer Funds, .Inc.,

Kemper Insurance Companies and Prime Retail, Inc. He is

• a Director of Dominion Resources.

48

illiam T. Roos (69) Retired, Hampton, Virginia (prior to December 31, 1993, 1975 .1999 President of Penn Luggage, Inc., retail specialty stores).

He is a Director of Dominion Resources. .

Frank S. Royal (58) Physician, Richmond, Virginia. He is a Director of 1997 1998 Columbia/BCA Healthcare Corporation, Crestar Financial Corporation, Chesapeake Corporation, CSX Corporation and Dominion Resources.

• Judith B. Sack (49) Senior Advisor, Morgan Stanley & Co., Inc., an investment 1997 ,1999 banking firm, New York, New York, as of September 1, 1995 (prior to September 1, 1995, Advisor); She is a Director of Dominion Resources. . .. .* .

S. Dallas Simmons (58) President of Virginia Union University, Richmond, Virginia. 1997 2000 He is a* Director of Dominion Resources.

Robert .R. Spilman (70) President, Spilman Properties, Basset, Virginia and Chairman 1994 2000 of the Board and a Director of Jefferson-Pilot Corp.,

. Greensboro, North Carolina. Retired Chairman and Chief Executive Officer of Bassett Furniture Industries, Inc. He a

. is Director of International Home, Ftiinishing Center, The Pittston Company and Dominion Resources.

William G. Thomas (58) President of Hazel & Thomas, Alexandria, Vfrginia, a law .. 1987 1999 firm.

• David A. Wollard (60) Retired President, Bank One Colorado, N.A;* Denver, .1997 1999 Colorado.

The Directors are divided into three classes, with staggered terms. Each class consists, as nearly as possible, .of one-third of the total number of Directors. Each Director holds office until the annual meeting for the year in whi~h his class term expires, or until his successor is duly qualified and elected as provided in the .Company's Articles of Incorporation.

Mr. Thomas has entered into a Consent Decree with the Office of Thrift Supervision in connection.. with the l~11ding a

and credit granting activities of Perpetual Savings Bank, FSB, which Mr..Thomas formerly serveci' as director., The Con-

. sent Decree requires that Mr. Thomas obtain approval from the appropriate federal banking agency before accepting certain positions involving lending or credit activities with an insured depository* institution.

(b) Information concerning the executive officers of Virginia Electric and Power Company is as follo~s:

Name and Age Business Experience. past Five Years Norman Askew (55) President and Chief Executive Officer,of Virginia Electric and Power Company and E~ecutjve Vice President of Dominion Resourc.es from August l, 1997 to date; Executive Vice President .of Dominion .Resources and Chief Executive of East Midlands from February 21,.1997 to August 1, 1997; Chief Executive of East Midlands from April 1, 1994 to February 21, 1997; Managing Direc.tor prior to April 1, 1994. . * ,. . .

• Thomas F. Farrell, II (43) Executive Vice President of Virginia Electric and Power Company and Senior Vice President-Corporate Affairs of Dominion Resources, September 1, 1997 to date; Senior Vice President-Corporate & General Counsel of Dominion Resources, January 1, 1997 to September 1, 1997; Vice President and Generaf Counsel of Dominion Resources, July 1; 1995 to January 1, 1997; Partner in the law .firm of McGuire, Woods, Battle, & Boothe LLP prior to July 1, 1995.

• Robert E. Rigsby (48) Executlve Vice President, January 1, 1996 to date; Senior Vice President-Finance and Controller, January 1, 1995 to January 1, 1996;. Vice President-Human Resources prior to January 1, 1995. * * * * "

• William R. Cartwright (55)

• Senior Vice President-Fossil and Hydro, July 1, 1995 to date; Vice President Fossil and Hydro prior to July 1, 1995. * . .

Lawrence E. D; Simone (50) Senior Vice President-Energy Services, July 15, 1996 to date; vice pres1dent-strategic planning for Central & South West Corp., a Dallas-based electric utility holding company, prior to July 15, 1996. * * ..

Larry M. Girvin (54) Senior Vice President-Commercial Operatl~ns, January 1, 1996 to *d~te;'Vice t James P. O'Hanlon (54)

• President-Human Resources, January. 1, 1995 to January 1, 1996; Vice President-Nuclear Services prior to January 1, 1995.

Senior Vice President-Nuclear, June 1, 1994 to.-date; Vice President-Nuclear Operations prior to June 1, 1994.

49

• John A. Shaw (49) Senior Vice President-Finance, March 16, 1998 to date; Vice President Financial' * /

Service for ARCO Chemical Company; Philadelphia, Pennsylvania, prior to March 16, 1998. During the past 5 years, he has also served a~ Treasur.er and Controller of ARCO Chemical.' *

• Eva S. Teig (53) Senior Vice President-External Affairs'& Corporate Communications, September 1,

,

• 1997 tci date; Vice President-External A_ffairs & Corporate Communications, June l, 1997 to September 1; 1997; Vice President-Public Affairs prior to June 1, 1997.

Said Ziai (44) Senior Vice President-Corporate *stra:tegy, October 1, 1997 to date; Corporate Planning Director, Ea~t Midlands* Electricity plc, Nottingham, England prior to October 1,

. 1997. .

Thomas L. Caviness, Jr. (52) Vice President-Retail E~ergy s*ervices, July 1, 1995 to date;Vice President-Eastern

• Division prior to July 1, 1995.' * * ,* * *

. David A. Christian (43) Site Vice :President-Surry; March 1; 1998 to date; Station Manager-Surry Power Station, September l, 1994 to March 1,* 1998;Assistant Station Manager-Surry;

• prior to September), 1994. ** * *

,J. Kennerly Davis, Jr. (52) Vice Pr~sident-Finance and.Admini~tratiye* s*ervices, Treasurer and Corporate Secretary, January 1, 1996 to date; Vi~e President, Treasurer and Corporate Secretary, October l, 1994 to January 1, 1996; Vice President and Corporate

• Secretary of Dominion Resources prior to October 1, 1994. .

James T. Earwood, Jr. (54) . Vic*e President-Bulk Power Delivery, January 1, 1997 to date;Vice President-Energy*.

Efficiency and Division Services, January 1, 1996 to January 1, 1997; Vice

• President Division Services prior to January 1, 1996.

0

• E. Paul Hilton (54) Vice President-Regulation, October 1;' 1997 to date; Manager, Rates and Regulation, February 20, 1996 to October 1, 1997; Manager, Rates prior to February 20, 1996.

Thomas A. Hyman, Jr. (46) Vice President-Distribution Operations and North Carolin~ *Power; June 1, 1997 to date;Vice President-Eastern Division and North Carolina Power, July l, 1995 to*

• June 1, 1997;. Vice President-Southern Division, June J, J994 to July 1, 1995; Station Manager-Bremo Power Station prior to June 1, 1994. .

Michael R. Kansler (43) Vice Pr~sident~Nuclear Operations, January 1, 1997 to dite;Vice Ptes1dent-Nuclear Engineering and Services, October I, 1995 to January 1, 1997; Vice President- * *.

Nuclear Services, January l, 1995 to October 1, 1995 ; Manager-Nu,clear Operations Support, September 1, 1994 to January 1, 1995; S_tation Manager7 S.urry. Nuclear Power Station prior to September 1, 1994.

• William R. Matthew.s (51) Site Vice President~Norlh Anna, Marbh 1, 1998 to date; Station Manager-North Anna

.Power Station, May 1, 1996 to March 1, 1998; Assistant Statio.n Manager-North Anna Power Station, December 1, 1993 to May 1, 1996; Superintendent-

. Maintenance, prior to December' 1, 1993.

Mark F. McGettr:ick (40) Vice President-Customer Servic~, January 1, 1997 to date; Corporate Restructuring Project Manager, February 1, 1995 to January 1, 1997; Assistant Controller prior to

. February. 1, I995. * .

wmiam:*s: Mistr (50) Vice President~Info~ation Technology; January 1, 1996 to date and Vice President of Dominion Resources, February 20, 1997 to'date; Vice President and Treasurer, ..

Dominion En~rgy, Inc., October 1, 1994 to January 1, 1996; Assistant Treasurer,.

• Dominion Resources prior to October l; 1994.

Thomas J. O'Neil. (55) Vice President-Human :Resources, January 1, 1996 to date; Vice President-Energy Efficiency prior to January 1, 1996. . * . .

Edward J. Rivas (53) Vice President-Fossil & Hydro Operations, January 1, 1998 to date; Manager-Clover Power Station, March 16, 1994 t9,January 1, 1998; Manager-Fossil & Hydro.

• Training prior to March 16, 1994: ,. ** *

• Robert F. S~unders (54) Vice Presiderit-N~dear Engineering. and Services, January 1, 1997 to date; Vice President~Nuclear Operations, June 1, 1994 to January l,.1997; As.sistant Vice President-Nuclear Operations, prior to June 1; 1994. * *

• John~y V.

Shena!

. . . (52) Vice President-Distribution Construction, June 1, 1997 to date;Vice President-Northern and Western Divisions, June. l', 1994 to June 1, 1997; Vice President-Western.. .

Division, prior to.June 1,)994.

• Richard T. Thatc!i~r (48) Vice President-Whoiesale.Power Group, September 1, 1997 to date; Managing Director, Wholesale Power, April 10, 1997 to September 1, 1997; Manager, '

Whole~ale Power Group, July ~. 1995 to April 10, 1997; Project Manager,

, Ja!1uary 1, 1995 to July 1, 1995; Director-Generation and Interconnection Planning pnor to January l,' 1995. . * * *. * . * *

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

50

Section 16(a) Beneficial Ownership Reporting Compliance Our Directors and Executive Officers report their ownership of our preferred* stock pursuant to Section 16(a) of the Exchange Act. Through administrative oversight, the following individuals failed to file their initial statements of beneficial ownership on Form 3 on a timely basis: Thos. E. Capps, Norman Askew, John B. Bernhardt, John W. Harris, Kenneth A.

Randall, Frank S. Royal, Judith B. Sack, S. Dallas Simmons, David A. Wollard, Thomas F. Farrell, II, Said Ziai, E. Paul Hilton, Richard T. Thatcher, David A. Christian and William R. Matthews.

None of the individuals owned any of our preferred stock at the time their initial reports should have been filed nor have they or any other Director or Executive Officer have any reportable transactions in* the preferred stock which have not been reported. The required filings have now been made.

ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The Summary Table below includes compensation paid by the Company for ~ervices rendered in 1997, 1996 and 1995 for the Chief Executive Officer and the four. other most highly compensated executive officers (as of December 31, 1997) as determined by total salary and incentive payments for 1997. . . .

Summary Compensation Table Long Tenn Compensation Awards Annual Compensation Securities Payouts Restricted Underlying Other Annual .Stock Options/ LTIP All Other Name & Principal Position Year ~ Incentive(!) Com:eensation(2) Awards SAR Grants Pay out Com2!:nsation(3)

James* T. Rhodes 1997 $244,800 $159,250(4) $ 0 $ b $0 $803,429(5) $7,977,039(6)

President and CEO 1996 $410,575 $247,606 $ 0 $ 0 $0 $ 75,684 $ 4,500 (retired August 1, 1997) 1995 $406,075 $273,000 $ 0 $ 0 $0 $ 77,970 $ 4,500 Norman Askew 1997 $177,084 $ 85,833 $14,560 $ 0(7) $0 $ 18,791(8) $ 120,000(9)

President and CEO (effective August 1, 1997)

Robert E. Rigsby 1997 $254,850 $129,920 $ 0 $ 0(10) $0 $ 83,171(11) $ 4,800 Executive Vice President 1996 $226,469 $143,892 $ 0 $ 0 $0 $ 43,157 $ 4,500 1995 $171,456. $105,000 $ O* $ 0 $0 $ 34,569 $ . 4,500 James P. O'Hanlon

• 1997 $270,250 $110,240 $ 0 $ 0(12) $0 .* $ 80,140(13) $ 4,800 Senior Vice President - 1996 $220,815 $128,511 $ 0 $ 0 $0 $ 56,152 $ 4,500 Nuclear 1995 $207,555 $136,400 $ 0 $ 0 $0 $ 45,109 $ 4,500 Lawrence E. DeSimone 1997 $212,751 $ 85,520 $ 0 $ 0(14). $0 $ 0 ,$ 3,180

• Senior Vice President - 1996 $ 94,419 $ 50,441 $ 0 $ 0 $0 $ 0 $ 0 Energy Services Larry M. Girvin 1997 $187,050 $ 85,520 $ 0 $ 0(15) $0 $ 52,935(16) $ 4,800 Se.ni?r Vice. President - 1996 $164,600 $ 89,200 $ 0 $ 0 $0 $ 30,717 $ 4,500 Commercial Operations 1995 $139,650 $ 66,606 $ 0 $ 0 $0 $ 24,685 $ 4,500 (1) The Company does not maintain "bonus" plans which are used by some companies to supplement salaries based on the success of the company without regard to individual performance. However, the Company has in place various incentive plans that compensate officers and employees for achieving specified performance goals.

(2) Unless noted, none of the executive officers above received perquisites or other personal benefits in excess of either

$50,000 or 10% of total salary and incentive payment.

(3) Employer matching contribution of $4,800 on Employee Savings Plan contributions, unless otherwise noted.

(4) Amount represents a lump sum settlement of his rights under the 1997 Annual Incentive Plari.

(5) $158,025 was paid under the 1995-1997 Performance Achievement Plan. 7,326 shares of Dominion Resources, Inc.

Common Stock (worth $269,231 @ $36.75 per share) were issued under the 1996-1998 Long Tenn Incentive Plan.

10,326 shares of Dominion Resources, Inc. Common Stock (worth $376,173 @ $36.75 per share) were issued under the 1997-1999 Long Tenn Incentive Plan.

51

• (6) Upon his retirement, Dr. Rhodes received the following payments* from the Company: $51,078 for- unused vacatiolf;

.,. , *. , $1,023,271 .as provjded by his. employment contract;. $4,184,220 lump sum settlement of pension benefits not ,payable I* >: frotil 'the q~alified ;~tireme~t plan; $2,715,,926 ,as a lump sum settl~ment of his benefit under the Execut~ve Supple-

men~al Retirement, P,lan, and ~2,544 in employer match on Employee Savings Plan contributions.

• • (7) Mr. Askew held rio restricted stock as of 12/31/97.

(8) Amount represents incentive plan pay outs from Virginia Power, on a prorated basis, for performance cycles that ended

• .ih 1997: $7-,550:.in. li~u, of dividends on restricted stock for partial participation in the 1996-1998 and the 1997-1999 performance cycles; and, $11;241,for the 1995-1997 performance cycle.

(9) A one time payment related to his_ international transfer frorri the UK to the US.

(10) Aggregate number of shares ofrestricted stock on December 31, 1997: 13,763 with an aggregate value of $585,788 (based on a closing price on December 31, 1997 of $42.5625 per share). *

(11) 2,085 shares of stock; with 50% of the value awarded in cash ($41,133) and the remaining 1,042 shares being issued

{valued at $42,038' or $40.3437 per share as of 2/20/98).

0 (12) Aggregate riumber of shares of re~tricted stock on Dece~ber 31, 1997: 9,773 with aggregate value of $415;963 (clos-ing price on December 31, 1997 of $42.5625 per share).*

(13) 2,009 shares of stock, with 5,0% of the value a\\'arded in cash ($39,635) and the remaining 1,004 shares being issued (valued at $40,505 or $40.3437 per share as of 2/20/98).

(14) Mr. DeSimone held. no restricted.stock as of 12/31/97.

(15) Aggregate number of shares of restricted stock on December 31, 1997: 7,5i8 with aggregate value of $320,411 (clos-

. * . ing' price .on December 31, 1997 of $42.5625 per share).

.(16} 1,327 share(of sfock,. with 50%. of the value awarded in cash ($26,187) and the remaining 663 shares being issued (valued at $26,748 or $40.3437 per share as of 2/20/98).

Long:term I~ce~tiv~ Compensation '

Long-term' incentive awards made during 1997 are shown in the following table.

Long-term Incentive Plans - Awards in the Last Fiscal Year 1997-1999 Long-term Incentive Plan Performance or Estimated Future Payouts Number of Other Period under Non-stock Price Based Plans Shares, Units until Maturation Threshold Target Name or Other Rights(#) or Payout ($ or #) ($ or #)

J,T: Rhodes ...... :......... ;; ......... :.................. ; .... . $259,448. 3 years $129,724 $259,448 N. Askew ...... ,. .................. , ... ~ .............. :......... . $261,250 3 years $130,625 $26i,25o' J.P. O'H_anlon ......... ,., ................ -........ .' ............ . $112,843 3 years $ 56,422 $112,843 R.E. Rigsby ... :.:.. *.*:;., ............................ , .. , ...... . $163,714 3 years $ 81,857 $163?714 L.E.:. DeS(mone .............................................. . $ 87,750 3 years* $ 43,875 $ 87,750.

L.M. Girvin.*........._... , ........ :... : ............ _........... . $ 87,750 3 years $ 43,875 $ 87,750

.. ' .. ' . .... ~ . ,.,

52

Retirement Plans The tabl~ below 'sets forth the *estimated annual straight life benefit that would be paid fol:Iowing retirement under the benefit formula of the Dominion Resources, Inc. Retirement Plan (the Retirement Plan).

Estimated Annual Benefits Payable upon Retirement

• Credited Years of Service Final Average Earnings 15 20 25 30

$185,000 $51,501 $68,668 $85,836 $103,003

. 200;000 56;069 74,758 93,448 112,138 225,000

• 63,681 84,908 106,136 127,363 250;000 7i,294 95,058 118,823 142,588 300,000 86,519 115,358 144,198 173,038 350,000 101,744 135,658 f69,573

• 203,488 400,000 116,969

• 155,958 194,948 233,938 450,000 132,194 176,258 220,323 264,388 500,000 147,419 196,558 245,698 294,838 550,000 162,644 216,858 271,073 325,288 600,000 177,869 237,158 296,448 355,738 650,000 193,094 257,458 321,823 ,386,188 750,000 223,544 298,058 372,573 447,088 Benefits under the Retirement Plan are based on (i) average base compensation over the consecutive 60-month period in which pay is highest, (ii) years of credited service, (iii) age at retirement, and (iv) the offset of Social Security Benefits.

Certain officers have entered into retirement agreements that give additional credited years of service for retirement and retirement life insurance purposes, and retirement medical benefit purposes contingent upon the officer reaching a specified age and remaining in the employ of the Company or an affiliate.

For purposes of the above table, based on 1997 compensation, credited years of service (including any additional years earned in connection with the retirement agreements) for _yach of the individuals named in the cash compensation table.

would be as follows: ' . . .. ' .

• James T. Rhodes: 30; Norman Askew: O; Robert E. Rigsby: 26; James P. O'Hanlon: 8; Lawrence E. De Simone: O; Larry M. Girvin: 31.

Virginia Power's executive compensation program has placed increased emphasis on incentive compensation opportu-nities linked to financial and operating performance. Base salaries have been held below the mean for comparable positions at comparable companies. The Retirement Plan benefit formula recognizes base salary, but not incentive compensation pay-ments. Therefore, each year the Organization *and Compensation Committee approves a market-based adjustment to execu-tive base salaries for use in calculating the retirement benefit under the Dominion Resources, Inc. Benefit Restoration Plan (the Restoration Plan). In 1997, this adjustment was 11 percent. Also, the Internal Revenue Code limits the annual retire-ment 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 limita-tions 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 offic-ers 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 ben-efit is monthly installments for 120 months to a participant with 60 months of service, who (i) retires at or after age 55 from the employ of the Company, (ii) has become permanently disabled, or (iii) dies. The accrued benefit vests proportionately between the time an officer is elected and when he or she reaches age 55 when the benefit is fully vested If a participant dies while employed, the normal form of benefit will be paid to a designated beneficiary. If a participant dies while retii:ed, t but before recei_ving all benefit payments, the remaining installments will be paid to a designated beneficiary. A lump sum payment is available under certain conditions.

Based on 1997 compensation, the estimated annual retirement benefit for each of the executive officers under the Supplemental Plan would be as follows: N. Askew: $167,406; R.E. Rigsby: $104,345; J.P. O'Hanlon: $113,228; L.E. De Simone: $79,139; L.M. Girvin: $73,764.

• 53

Retirement Benefit Funding Plan The Company maintains a Retirement ~enefit Funding Plan to provide a means to 1>ecure obligati,ons under the Supple-mental Plan, the Restoration Plan, and retirement agreements. The Retirement Benefit Funding Plan does not provide any additional benefits; it simply helps secure the funding for these benefit obligations. The amount payable by Virginia Power under the Supplemental Plan, the Restoratio11 Plan and retirement agreements is reduced, on a dollar-for-dollar basis, by the funds available under the Retirement Benefit Funding Plan.

Employment Agreements The Company has entered into empl()yment continuity agreements (the Agreements) with its key management execu-tives, including, Norman Askew, Robert E. Rigsby, James P. O'Hanlon, Lawrence E. De Simone, and Larry M. Girvin, which provide benefits in the event of a change in control. Each Agreement has a three-year term and thereafter is auto-matically extended on its anniversary date for an additional year unless notified that the Agreement will not be extended by the Company. If, following a change 'in ,control (as defined in the Agreements) of Dominion Resources or the Company, an executive's employment is terminated by the Company without cause, or voluntarily*by the executive within sixty days after a material reduction in the executive's compensation, benefits or responsibilities, the Company will be obligated to pay to the executive continued compensation equaling the average base salary and cash incentive bonuses for the thirty-six full month period of employment preceding the change in control or employment termination. In addition, the terminated execu-tive will continue to be entitled to any ,benefits due under any stock or benefit plans. The Agreements do not alter the com-pensation 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 com-pensation earned by the executive from comparable employment by another employer during the thirty-six months follow- -

ing termination of employment with the Company. An executive shall not be entitled to the above benefits in the event ter-mination is for cause.

Compensation of Directors The non-employee members of the Board receive an annual retainer of $19,000 and a fee of $900 for each Board or committee meeting attended. Committee chairmen receive an additional annual retainer of. $3,000,., Consistent with the Com-pany's philosophy concerning equity-based compensation for o'fficers, effective in 1998 non-employee directors will also receive an annual retainer in Dominion Resources common stock valued at $19,000. These Directors may elect to defer their annual retainer and/or their meeting fees under the Deferred Compensation Plan until they retire from the Board or other-wise direct. The .deferred fees are credited, for bookkeeping purposes, with earnings and losses as if they were invested in either an interest bearing account or Dominion Resources Common Stock, depending on the Director's election.

Directors. CIIaritable Contribution PrQgram Dominion Resources administers a Directors' Charitable Contribution Program (the Program) that covers Directors of the Company, as part of its overall program of charitable giving. Beginning at the death of a Director a donation in an aggregate amount of $50,000 per year for 10 years will be made to one or more qualifying charitable organizations recom-mended by the individual Director. Life insµrance policies have been purchased on the lives of the Directors in connection with the I>rogram. These policies are owned by Dominion Resources, which is also the beneficiary. The Directors derive no financiai or ~al\ benefits from the Program, t

54

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The tabl~ below sets forth as of February 20, 1998, except as noted, the number of shares of Common Stock of Domin-ion Resources owned by Directors and four other more highly compensated executive officers of Virginia Electric and Power Company.

Shares of Common Stock Director Plan Name Beneficially Owned Accounts(l)

John B. Adams, Jr............................................. . 3,891 9,091 John B. Bernhardt. ............................................. . 1,500 9,091 James F. Betts ...................... : ............................ . 7,500 .9,091 Thos. E. Capps .................................................. . 44,914(2)

Jean-E. Clary ..................................................... . 116 9,162 John W. Harris ............... , .......... : ....................... .'

• 500 9,091 Benjamin J. Lambert, III ..................................... . 90 10,212 Richard L. Leatherwood ..................................... . 1,000

• 17,616 Harvey L. Lindsay ............................................. . 400 9,091 Kenneth A. Randall ............................................ . 3,027 9,091 William T. Roos .............................. ~ ................. . 14,603(3) 9,091 Frank S. Royal ... *.. : ..................... .-.....*....... ;......... . 10,430 Judith B. Sack ................................................... . 1,000 14,575

- S. Dallas Simmons ............................................. . 650 13,370 Robert H. Spilman.............................................. . '1,187 9,091 William G. Thomas ............. .' .............................. . 1,000 13,257 David A. Wollard ............................................... . 9,879 Norman Askew .................................................. . 1,290(2)

Lawrence E. De Simone ..................................... . *. 92.

Larry M. Girvin ................................................. . 7,654.

James P. O'Hanlon ............................................ *.. 11,100 Robert E. Rigsby ............................................... . 22,079 All Directors and Executive Officers as a group-41 persons (4) .... : ............................. :. 397 ,599(2)(5)

(1) Amounts in this column represent share equivalents accumulated under the non-employee director Stock Accumulation Plan. Balances of 9,091 shares are the amounts accumulated thus far under the plan. Because of the plan's vesting pro-visions, these amounts will not necessarily be distributed to a director. Any balance in *excess of 9,091 is an amount of shares accumulated-at the director's. election-under the Deferred Cash Compensation plan. That excess amount will be distributed in actual shares to the director.

(2) Amounts include restricted stock as follows: Mr. Capps - 23,984 shares; Mr. Askew - 1,290; and all directors and executive officers as a group- 89,859.

(3) Mr. Roos disclaims beneficial ownership of 4,387 shares that are held in trusts for family members.

(4) All current directors and executive officers as a group own less than one percent of the number of shares outstanding as of February 20, 1998.

(5) Beneficial ownership is disclaimed for a total of 4,786 shares.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED ~NSACTIONS Hazel & Thomas, a professional corporation, from time to time acts as counsel to the Company. Mr. Thomas, a Direc-t tor of the Company, is a shareholder of Hazel & Thomas.

55

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. Exhibits 3.1 Restated Articles of Incorporation, as amended,.as in effect on September 12, 1994 (Exhibit 3(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference).

3.2 Bylaws, as amended, as in effect on October 17, 1997 (Exhibit 3(ii), Form 10-Q for the period ended September 30, 1997, File No. 1-2255, incorporated by reference).

4.1 See Exhibit 3 (i) above.

4.2 Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures (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), Form 10-Q for the quarter ended September 30, 1986, File No. 1-2255, incorporated by reference); Sixty-First Supplemental Indenture (Exhibit 4(ii), Form 8-K, dated June 2, 1987, File No. 1-2255, incorporated by reference);

Sixty-Second Supplemental Indenture (Exhibit 4(i), 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 Supplemental 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, gated August 6,. 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth Supplemental Iilclenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth .

Supplemental Indenture (Exhibit 4(i), Form. 8-K, dated April 6, 1993, File No. 1-2255, incorporated by reference); *seventy-Sixth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture (ExhibitA(i), Form .8-K, dated June 8, 1993, File No.

1-2255, incorporated by reference); Seventy~Eighth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August 10, 1993; File No: 1.:.2255, incorporated by reference);

Seventy-Ninth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1-2255, incorporated by reference);

Eighty-First Supplemental Indenture (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No.1-2255,incorporated by reference); Eighty-Second Supplemental Indenture (Exhibit 4(i), Forni 8-K, dated January 18, 1994, File No.

1-2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i), I t

~ Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference);

Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 22, 1995, Fik_No. 1-2255, incorporated by reference; and Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference).

56

Indenture, dated April 1, 1985, between Virginia Electric and Power Company and .

Crestar Bank (formerly United Virginia Bank) (Exhibit 4(iv), Forni 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

4.4 Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company,:..

and The Chase Manhattan Bank (formerly Chem,ic;al Bank) (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, l993, File No. 1-2255, incorporated by reference). .* . . . * . . * .

4.5 Indenture, dated April 1, 1988, between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank), as supplemented and;modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the.

fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

4.6 Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and The Ch.ase Manhattan Bank (formerly Chemical Bank); as Trustee, as supplemented (Exhibit 4(a), Form S-3 Registration Statement File No.

333-20561 as filed on January 28, 1997, incQrpo,rated by reference).

4.7 Virginia Electric. and Power Company agrees to fu~jsh to the Commission upon request any other instrument w.ith respect to long-term debt as to which the total ..

amount of securiti.es. authorized thereunder does not' exceed 10 percent of Virginia

• Electric and.Power Company's total assets.

10.1 Operating Agreement, dated June 17, 1981, betwee~ 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. 1-8489, incorporated by reference).

10.2 Purchase, Construction and Ownership Agree~ent, dated as of December 28, 1982.but amended and restated on October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(viii), Form 10-K f9r the, fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference);

10.3 Amended and Restated Interconnection and Operating Agreement, dated as of July i9,.

1997 between Virginia Electric and Powt:f Company and Old Dominion Electric

• Cooperative (filed herewith).

10.4 Nuclear Fuel 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 IO(x), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference).

10.5 Credit Agreements.dated June 7, 1996, between The Chase Manhattan Bank (formerly Chemical Bank) and Virginia Electric and ,Power, Company (Exhibits 1O(i) and 1O(ii),

• Form 10-Q for the period ended June 30, 1996, File No. 1-2255, incorporated by reference).

10.6 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 31; 1985, File No. 1-8489, incorporated by reference).

10.7 Agreement for Northern Virginia Services, dated as of November 1,' 1985, between Potomac Electric Power Company and Virginia Electric and Power Company *(Exhibit IO(xxi), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-8489; incorporated by reference).

• 10.8 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).

10.9 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).

10.10 Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and the 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 specifi-cations) (Exhibit IO(xiii), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).

• 10.11

• Description of arrangements with certain officern regarding additional credited years of service for retirement purposes (Exhibit lO(xii), Form 10-K for the fiscal year ended December 31, 1992, File No. 1-2255, incorporated by reference).

57

I .

10.12*

• Dominion Resources, Inc. Directors' Deferred Compensation Plan effective July 1, 1986, as amended and restated on January 1, 1996 (Exhibit lO(xii), Form 10-K for the

. fiscal year ended D~cember 31, 1996, File No. 1-2255, incorporatM by reference).

10.13* Dominion Resources, Inc. Performance Achievement Plan, effective January 1, 1986, as amended artd restated effective February 19, 1988 (Exhibit lO(xxiii), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).

10.14* Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective

• January :1, 1981 as amended and restated September 1, 1996 with first amendment dated June 20, 1997 and second.amendment dated March 3, 1998 (filed herewith).

10.15* Dominion Resources, Inc.'s Cash Incentive Plan as adopted December 20, 1991 (Exhibit lO(xxv); Form 10-K for the fiscal year ended December 31, 1994, File

, No. 1-2255, incorporated by reference).

10.16* Dominion Resources, Irie. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September'!, 1996 (filed herewith).

10.17* * ,. Dominion Resources, Inc. Retirement Benefit Restoration Plan *as adopted effective

• January 1, 1991_ as amended and restated September 1, 1996 (filed herewith).

10.18* Dominion Resources, Inc. Executives' Deferred *compensation Plan, effective January 1, 1994, as amended and restated on January 1, 1997 (Exhibit lO(xix), Form 10-K for the J;iscal year ended December 31, 1996, File No. 1-2255, incorporated by reference). * * * . .

10.19* Form of an Employment Agreement dated June 23, 1994 between Virginia Power and certain.executive officers (Exhibit lO(xxi), Form 10-K for the fiscal year ended December*31, 1996, File No. 1-2255, incorporated by reference).

10.20* Employment Agreement dated September 15, 1995 between Virginia Power and Robei;t E: Rigsby (Exhibit IO(xxii), Form 10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference).

10.21* Employment Agreement dated February 21, 1997 between Dominion Resources and Norman A~kew (filed herewith).

• 10.22* Dominion* Resources, Inc. Stock Accumulation* Plan for Outside Directors, effective

. Aprii 23, 1996 (Exhibit IO(xxiy), Form 10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference).

10.23~ Dominio~ R~sources, Inc. incentive Compensation Plan, effective April 22, 1997 (filed herewith).

23.1 Consent of.Hunton & Williams (filed herewith).

23.2

• Consent of*Jackson & Kelly (filed herewith).

23.3 Conserit of Deloitte & Touche LLP (filed herewith).

27 Financial Data Schedule (filed herewith).

• Indicates management contract or compensatory plan or arrangement (b) Reports on Form 8:_ K None 58

SIGNATURES Pursuant to the i.equirements of Section 13 or 15(d) of the Securities Exchange Act of i934, the registrant has duly caused this report to be signed on its behalf by. the undersigned, thereunto duly authorized.

VIRGINIA ELECTRIC AND POWER COMPANY Date: March 20, 1998 By THOS. E. CAPPS (Thos. E. Capps., Chairman of the Board. of D4"ectors)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 20, 1998.

• Signature Title THOS E. CAPPS Chairman *of the Board of Directors and Thos E. Capps Director .

JoHN B. ADAMS, JR. Director John B. Adams, Jr.,.

• NORMAN ASKEW President (Chief Executive Officer) and Norman Askew Director JciHN B. BERNHARDT Director John B. Bernhardt JAMES F. BETIS Director James F. Betts JEAN E. CLARY Director Jean E. Clary JOHN W. HARRIS Director John W. Harris BENJAMIN J. LAMBERT, III Director Benjamin J. Lambert, ill RICHARD L. LEATHERWOOD Director Richard L. Leatherwood t HARVEY L. LINDSAY, JR.

Harvey L. Lindsay, Jr.

Director 59

Signature Title Director

• Ke'nneth A. Randall WILLIAM T. Roos Director William T. Roos

' '*"FRANKS. ROYAL Director Fran.k ~-* Royal

• Director Judith B. Sack S. DALLAS SIMMONS Director

. S. Dallas Simmons ROBERT H. SPILMAN Director Robert H. Spilman WILLIAM G. THOMAS Director William G. Thomas Director David A. Wollard M. s. BOLTON, JR. Controller (Principal Accounting M. S. Bolton, Jr. Officer) 60

SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Form 10-K (Mark One)

[8l ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE

• SECURITIES EXCHANGE ACT OF 1934

• For the fiscal year ended December 31, 1997

• or D .. TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE

• SECURITIES EXCHANGE 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.chaner)

.VIRGINIA .

• 54-0418825 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification no.)

• 101 East Cary Street

.* 23219-3932

• * **Richmond, Virginia * * (Zip Code)

. (Address of principal executive offices)

. (804) 771-3000

.(Registrant's.telephone number, including area code)

.. Securities registered pursuant to S~ction 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: * * * * .. * ..

lf . . . $5.00 dividend ..

Trust Preferred Securities . New York Stock Exchange

... ~....... . . . . . . $25' "IiQuidatioii *vruue:

8.05% dividend Securities registered pursuant to Section 12(g) of the Act:

"}.~ ,*_ ,*

None P*

(Title ofClass)

. -~ .

. 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 ~ No D

.-: 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 of registrant'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. O The aggregate market value of the voting stock held by non-affiliates of the registrant as of February 28, 1998, was zero.

As of February 28, 1998, ti)ere were. issued and outstanding 171,484 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

VIRGINIA ELECTRIC AND POWER COMPANY Page Item Number Number PART I

1. Business ....................................................................................................................................... .

The Company ............................................................................................................................. .

Company Management. ................................................................................................................. .

Competition and Strategic Initiatives . ......... .. .. .......... ....... .. . . .. .......... ..... ....... ................... .. .. ............. 1 Regulation ............................................................................ :....................... '............................... 2 General ....................................................................................... :........................................... 2 Virginia ***********************************:*********************************************************************************************** 2 FERC ..................................................................................................................................... 3 Environmental .......................................................................................................................... 3 Nuclear ................................................................................................................................... 3 Rates ................................ ,........................................................................................................ 4 FERC ..................................................................................................................................... 4 Virginia .................................. ,. .................................. :............................................. :................ 5 North Carolina ................. *... ~ ... :................................................................................................... 6 Capital Requirement<; and Financing Program ...... .......... .. ... . .......... ... .......... .. .......... ......... ...... ..... .. .... 6 Construction and Nuclear Fuel Expenditures ................................................. :...... :........................ 6 Financing Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Sources of Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Company Generating Units ......... .. . ........................ ....... ............ ..... ............... ......... ................. ... 7 Net Purchases : ............................................................................................................. ,........... 7 Non-Utility Generation ................................ :............................. ..... ............ .......... .................. ... 7 Sources of Energy Used and Fuel Costs . .. . . . . . .. .. . . . . . ... . . . . . . .. . . . . . . . ...... .. . .. . . . . .. . . . . . .. . . . ... . . . . . . . . . . . . .. . .. . . . . . . .. 8 Nuclear Operations and Fuel Supply . . . .. . . . . . . . ... . . . . . .. .. . . . . . . ... . . .. .. .. . . .. .. . . . . . . .. . .. . . . .. .. .. . . .. . . . . . . . . ..... .. . . . . . . 8 Fossil Operations and Fuel Supply ....................... ,: ........................................ ,............................ 8 Purchases and Sales of Energy ... ; .. ; .............. .-.. :..... *............................ :.; .... ;.................................. 8 Future Sources of Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Conservation and Load Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . 9 Interconnections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . 9

2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

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

4. Submission of Matters to a Vote of Security Holders .. .. ... . . . . . . ... . . .. .. .. . . . ... . . . .. . . .. . .. . . . . . . .. . .. . . . . . .. . .. .... .. .. . . . . . 11 PART II

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

6. Selected Financial Data ..................................................._.... .. . ... . .. .. . ... . .. .. . . . . . .. .. . .. . . .. . . . . . . . . . . . . ... . . . . .. . ... 12

7. Management's Discussion and Analysis of Financial Condition and Results of Operations .......................... 12 Liquidity and Capital Resources ................................................................................................. ; . . . 13 Capital Requirements . . . . . . . . . . . . .. .. . . . . . . . . .. . . .. . . .. . . . . . . . . . .. . . .. . .. . . . . .. . . .. . . .. . . . .. . . . . . . .. . . . . . .. . .. .. . . . . . . . . . . . .. . ........ .. . 14 Results of Operations ................................................................................................................... 15 Future Issues ........................ :...................................................................................................... 17 Market Risk Sensitive Instruments and Risk Management................................................................... 22

8. Financial Statements and Supplementary Data .................................................... ................................. 24

9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure ... ...................... 47 PART ID l 0. 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 PART IV

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

PART I

'i,.:. -

. ITEM. 1. BUSINESS THE COMPANY

• : Vi~girii~ Ele~tri*c ~n9 Power Company is a Virginia Corporation. Our principal office is at 701 East Cary Street, Rich-mori'd, Virgi~ia 232.19-3932, *t~lephone (804) 771-3000. We are wholly owned subsidiary' of Dominion Resources, Inc.a (Dominion Resources), a Virginia corporation. Dominion Resources owns all of our common stock .

. *. 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 busi-ness under the name Virginia Power in Virginia and under the name North Carolina Power in North Carolina. We have retail customers (including governmental agencies) and wholesale _customers such as rural electric cooperatives, power marketers and municipalities. We serve more than 80 percent of Virginia's population. The Company has certificates of convenience and necessity from the State Corporation Commission of Virginia (the Virginia Commission) for service in all territories served.at retail in Virginia. The North.Carolina Utilities*Commission (the,North Carolina Commission) has assigned terri-tory to the Company for substantially all of its retail service outside certain municipalities in North Carolina.

0

*, Toe'°e!ectric utility industry in the United..Stat~~ is ~nde~goiiig"°a~ e~~lution~ change toward less regulation and more co~petition. To meet the challenges of this n~w co.mpetitive environment, Virginia Power has developed a broad array of "non~.traditional"

. . **. . . ~ - '

product' . . 'and

'.' service offerings from .

its .operating business

.. . . . ~' units and subsidiaries:

• Energy Services - offering electric energy and capacity in the emerging wholesale market as well as natural gas and

.. ,: c 9ther _ene~gy-~elat~ pro.ducts and services; .. ,. . . ,. ,:, ...

• • Fossil & Hydro - targeting process type industries, such*as chemical, paper, plastics and petroleum to become a ser-vice provider of instrumentation equipment;:.,,;

• Nuclear .Services - offering man~g~~~nt a~-d *6pe~atic:i~s' serv.ices to other electric utilities;

' :.: Co~in~r~'ial Operations*~ providirig power distributi~n relat~d servi~es, includini trans~i~sion and distributi,~n: engi-

,., *"*' iie~r.tng and metering services to other 'gas, wate~ and electric utilities; and ., .. ' ' . ' :

• Telecommunications - offering telecommunications services through the Company's existing fiber-optic network.

The Company and its subsidiaries had 9,043 full-time employees on December 31, 1997. A total of 3,452 o( our employees. are represented* by the International Brotherhood of Electrical Workers under a contract extending to March 31, 1998. The *company,:and the union have* tentatively-agreed; subject to ratification by the union membership, to a two year extension'i:,f'thecontract.**,*: *'.*":*' *<;: ,, .... , : *,* .

'**/{)rf :-~.;,*:*~  : *' 1 ',/ .;** , :::_ .. .* *.,' , ** ~*1; J. ' *' ', * * * , ......,..

• For a more thorough* review of the changing utility industry and the Company's strategy see COMPETITION AND STRATEGIC INITIATIVES below and Future Issues - Competition under MANAGEMENT'S DISCUSSION AND ANALY-

,, SIS OF FINANCIAL CONDIDON AND RESULTS OF, OPERATIONS (MD&A).

..: ..,.: . ~,. .

COMPANY MANAGEMENT In April,. Dr. James T. Rhodes, President and Chief Executive Officer since 1989, announced his retirement effective.

August .1, 1997. The Board of Directors .subsequently elected Mr. Norman Askew as the new President and Chief Execu-tive Officer, effective August I, 1997. Mr. Askew was previously the .Chief Executive.of. East Midlands Electricity pie, a United Kingdom regional electricity company acquired by Dominion Resources during the first quarter of 1997.

Mr. Askew also replaced Dr. Rhodes on the Board of Directors effective August I, 1997.

• COMPETITION AND STRATEGIC INITIATIVES

• A number of developments in the United States are causing a trend toward less regulation and more competition in the electric *utility industry. This is evi~enced by legislative and regulatory action at both the federal and state levels. To the extent that competition is either authorized or mandated and regulation is eliminated or relaxed, electric utilities may no l<;>nger.-be guaranteed an opportunity to recover all of their prudently incurred cqsts, and utilities with costs that exceed the rket prices established by the competitive market will run the risk of suffering losses, which may be substantial.

Virginia Power has responded to these trends by undertaking cost-cutting measures, engaging in re-engineering efforts, restructuring its core business processes, and pursuing a strategic planning initiative to encourage inn9vative approaches to serving traditional markets. The Company has established separate business units, as discussed above, to fully execute these strategies.

The Company also is vigorously participating in the state and federal legislative actions currently underway to bring about competition in the electric utility industry, in: an effort to ensure an orderly transition from a regulated environment.

The Company's non-traditional businesses face competition from a variety of utility and non-utility entities.

For a full discussion of the regulatory and legislative issues related to competition, carefully read the Future Issues sec-tion of MD&A.

REGULATION General In a wide variety of matters in addition to rates, Virginia Power is presently subject to regulation by the Virginia Com-mission and the North Carolina Commission, the Environmental Protection Agency (EPA), Department of Energy :(DOE),

Nuclear Regulatory Commission (NRC), the Federal Energy Regulatory Commission (FERC), the Army Corps of Engineers, and other federal, state and local authorities. Compliance _with numerous laws and regulations increases 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 Com-pany's rates have historically permitted recovery of such costs.

Virginia Power may not construct, or incur financial commitments for construction of, any substantial generating facili-ties or large capacity .transmission lines without the prior approval of various state and federal governmental agencies. Such approvals relate to, among other things, the environmental impact of such activities, the relationship of such activities to the need for providing adequate utility service and the design and operation of proposed facilities.

Both federal and state legislative bodies have been studying competition and restructuring in the electric utility indus-try. Please carefully read* the full discussion of this matter found in the Future Issues - Competition - Legislative Initia-tives section of MD&A. *

• Virginia In _1995, the Virginia Commission instituted an ongoing generic investigation on electric industry restructuring, result-ing.in a number of reports by its Staff covering such issues as.retail wheeling experiments and the status of wholesale power markets. The Staff also submitted a report to the General Assembly calling for a cautious, two-phase, five-year period to address restructuring issues. The report acknowledged the need for direction from the Virginia legislature concerning policy issues *surrounding com.petition in the electric industry. . . .

In November 1996, the Virginia Commission instituted a proceeding concerning Virginia Power's cost of service and

• possible restructuring of the electric utility industry as it might relate to Virginia Power. On March 24, 1997, Virginia Power filed in that proceeding a calculation of its_ cost of service for 1996 and a proposed Alternative Regulatory Plan (ARP). Sub,* '

sequently, the Commission consolidated this proceeding with the proceeding concerning the Company's 1995 Annual Infor-mational Filing, in which the Company's base rates were made interim and subject to refund as of March I, 1997. Please carefully read the Future Issues - Competition - Legislative and Regulatory Initiatives sections of MD&A and RATES-Virginia, below for details concerning the ARP, its current status and related legislative developments.

In December 1995, Virginia Power applied to the Virginia Commission for approval of arrangements with Chesapeake Paper Products Company (CPPC), under which Virginia Power would facilitate the design, construction and financing of a cogeneration plant to meet CPPC's energy requirements for its industrial processes at its plant in West Point, Virginia. On August 13, 1997, the Virginia Commission approved, in substantial part, the proposed transactions between Virginia Power and CPPCs _successor in ownership, St. Laurent Paper Products Co. St. Laurent later determined that the current design of the facility was no longer compatible with its long-term business strategies and terminated its contractual arrangement with Virginia Power. The Virginia Commission dismissed the proceeding on January 15, 1998.

In June 1997, the Virginia Commission granted the Company's request to implement a monitoring program that requires certain non-utility generators to provide certain information sufficient to determine continued compliance with the "Quali-fying Facility" (QF) requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA).

2

On August 8, 1997, the Virginia Commission granted the Company's request to provide interchange telecommunica-tions services and approved the proposed affiliate agreements between Virginia. Po:wer and our wholly-owned subsidiary, VPS Communications, Inc. (VPSC) .. Under the, authority granted, VPSC will provide a range of telecommunications ser-vices, including private line and special access services and high-capacity fiberoptic services.

• On September 3, 1997, the Virginia Commission granted the Company's request to provide services to our wholly-owned :subsidiary, Virginia* Power Services, Inc. (VPS), which would enable Virginia Power Nuclear Services Company (VPN), :a VPS subsidiary, to furnish nuclear managemei:it and operation services to .electric utilities seeking assistance in the management and operation of their nuclear generating.facilities. VPN currently provides such services to Northeast Utilities at its Millstone* Unit 2 .nuclear plant.

FERC In April 1996, FERC issued final rules in Order Nos. 888 and 889 addressing open access transmission service, stranded costs, standards of conduct and open access same-time.information systems (OASIS). In July 1996, Virginia Power filed an open access transmission service tariff in compliance with FERC's Order No ... 888. In compliance with FERC's directive, Virginia Power's OASIS became operational on January 3, 1997. Also, on that date the standards of conduct requiring sepa-ration of transmission operations/reliability functions from wholesale merchant/marketing functions became effective. The.

Company also made filings to comply with FERC's directive that, effective January 1, 1997, utilities could no longer make*

bundled sales of transmiss.ion and generation services in economy energy transactions. In. certain of those filings, Virginia Power canceled or committed not to use the economy energy rate schedules contained in interconnection agreements with n~ighboring utilities. On March 4, 1997, FERC issued Order Nos. 888-A and 889-A, which addressed requests for rehearc

~ ing of Order Nos. 888 and 889. Orders No. 888-A and 889-A essentially reaffirm the basic principles of 888 'and 889 and clarify and make limited modifications to those orders. On December 17; 1997, FERC issued Order Nos. 888-~ and 889-B.

FERC rejected all requests for rehearing filed with respect to Order Nos. 888-A and 889-A and clarified and made limited

' modifications to those orders. Several parties have appealed the 888 orders to the Unitl;!~ States Court of Appeals for the District of Columbia Circuit.

• For a discussi~n of the status of the Company's Open Access Transmission Tariff filing, see RATES - FERC below.

For additional discussion of open access issues see Future Issues - Competition under MD&A.

LG&E Westmoreland Southampton owns a cogeneration facility in Franklin, Virginia, and sells its output to Virginia Power. Southampton has sought a waiver of FERC operating requirements for Qualifying Facilities (QF's) under PURPA, however FERC refused to grant such a waiver. On March 31, 1997, the United States Court of Appeals for the District of Columbia Circuit granted FERC's motion to dismiss Southampton's Petition for Review.

Environmental From time to time, Virginia Power may be designated by the EPA as a potentially responsible party (PRP) with respect to a Superfund site. As a result.of that designation or other regulations regarding the*remediation of waste, we may become

• obligated to fund remedial investigations or actions. We do not believe that any currently identified sites will result in sig-nificant liabilities. For a discussion of the Company's site remediation efforts, see Note Q to the CONSOLIDATED FINAN-CIAL STATEMENTS.

, PermJ.ts under the Clean Water Act arid state laws have been issued for all of th.e Company's. steam generating stations now in operation. These permits are subject to reis*suance and continuing review. The Clean Air Act, as amended in J990, requires the Company to reduce its emissions of sulfur dioxide (S02 ) and nitrogen oxides (NOx). Beginni~g in 1995, the S02 reduction program is based on the issuance of a limited number of S02 emission allowances, each of which may be used as a permit to emit one ton of S02 into the atmosphere or may be sold to someone else. The program is. administered by the EPA. .

• For additional information.on Environmental Matters, Clean Air Act compliance and related.issues see the Future Issues section of MD&A. *

• Nuclear All aspects of the operation and !Jlaintenance of the Company's nuclear power stations are regulated by the NRC.

Operating licens.es issued by the NRC are .subject to revocation, suspension or modification, and operatioµ of a n.uclear unit may. be suspended* if the NRC determin_es that. the public interest, health or s~fety so requfres,.;

3

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 nui;.:lear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating ahd maintain-ing the Company's nuclear generating units.

In July 1995, the Virginia Commission instituted an investigation regarding spent nuclear fuel disposal. As directed, Virginia Power and others filed comments on legal and public policy issues related to spent nuclear fuel storage and dis- .

posal. In February 1996, the Commission Staff filed its Report recommending that adoption of a definitive policy on spent nuclear fuel disposal issues be delayed pending the outcome of litigation against the Department of Energy concerning spent nuclear fuel acceptance, the outcome of proposed federal legislation concerning development of an interim storage facility, and development of a vision of the likely outcome of the electric utility industry's restructuring efforts. The Virginia Com-mission consolidated the proceeding with Virginia Power's pending fuel cost recovery proceeding in October 1996. On March 20, 1997, the Virginia Commission returned the spent nuclear fuel disposal issue to a separate proceeding.

On January 31, 1997, Virginia Power joined thirty-five other electric utilities in filing a petition in the United States Court of Appeals for the District of Columbia Circuit, seeking to compel DOE to comply with .its obligation to begin accept-ing the utilities' spent nuclear fuel for disposal by January 3i, 1998, the date imposed by the Nuclear Waste Policy Act.

Additional utilities have joined since the original filing. On November 14, 1997, the Court issued an Order finding that DOE's obligation to begin accepting spent nuclear fuel by the deadline is unconditional; and that DOE may not excuse its delay on the grounds that it has not prepared* a permanent repository or interim storage facility. The Court found that DOE's spent fuel disposal contracts with the utilities offer a 'potentially adequate remedy for DOE's failure to rrieet its obligation.

DOE filed a petition for rehearing on December 29, 1997.

RATES The Company's electric services sales were *subject to rate regulation in 1997 as follows:

1997 Percent Percent of of Revenues Kwh Sales Virginia retail:

Non-Governmental customers ................... : Virginia Commission 81% 76%

Governmental customers .......................... . Negotiated Agreements 10 12 North Carolina retail .................................. . North Carolina Commission 5 5 Wholesale -Sales for Resale* .................... . FERC 4 7 100% 100%

• Excludes wholesale power marketing sales subject to FERC regulation.

Substantially all of the Company's electric service sales are subject to recovery of changes in fuel costs either through fuel adjustment factors or periodic adjustments to base rates: each of which requires prior regulatory approval.

Each of these jurisdictions has the authority to disallow recovery of costs it determines to be excessive or imprudently incurred. Various cost items may be reviewed on occasion, including costs of constructing or modifying facilities, on-going purchases of capacity or providing replacement power during generatin& unit outages.

• FERC In compliance with FERC's Order No. 888, Virginia Power filed an open access transmission service tariff, which became effective on July 9, 1996. In October 1996, FERC issued a procedural order, scheduling a hearing for April 28, 1997.

The Company and all parties reached a settlement of issues raised iri the proceeding, and on March 20, 1997, those parties jointly filed with FERC the Settlement Agreement and Motion to Certify the Settlement Agreement. On April 23, 1997 the presiding Administrative Law Judge certified the Settlement Agreement to the FERC and on June 11, 1997, the FERC approved the settlement.

In compliance with FERC's Order No. 889, on January 3, 1997, the Company filed its Procedures For Standards of Conduct for Unbundled Transmissions and Wholesale Merchant Functio.n (Standards of Conduct) effective on that date. On July 1, 1997, the Company filed an amendment to the Standards of Conduct in Compiiance with FERC's Order No. 889-A.

4

On July 16, 1997, the Company filed another amendment in response to a FERC Staff request. The Company is awaiting FERC action on the filing.

On September 11, 1997, FERC authorized the Company to sell power at market-based rates but set for hearing the issue f the impact of any transmission constraints on Virginia Power's ability to exercise generation market power in localized areas within its service territory. If FERC finds that transmission constraints give Virginia Power generation dominance, it could either revoke or limit the scope of the market-based rate authority. The hearing is scheduled to commence June 2, 1998.

On October 31, 1997, Virginia Power filed at FERC three agreements with Old Dominion Electric Cooperative (ODEC) to amend the parties' Interconnection and Operating Agreement (I&O Agreement) and to unbundle transmission services provided to ODEC under the I&O Agreement. On December 22, 1997, FERC issued a deficiency letter with respect to the filing directing the Company to provide additional information. On January 21, 1998, the Company provided the requested information. FERC accepted the agreements on March 12, 1998.

Virginia In March 1997, the Virginia Commission issued an order that Virginia Power's base rates be made interim and subject to refund as of March 1, 1997. This order was the -result of the Commission Staff's report on its review of Virginia Pow-er's 1995 Annual Informational Filing, which concluded that Virginia Power's present rates would cause Virginia Power to earn in excess of its authorized return on equity. The Staff found that, for purposes of establishing rates prospectively, a rate reduction of $95.6 million (including a one-time adjustment of $29.7 million to Virginia Power's deferred capacity balance at December 31, 1996) may be necessary in order to realign rates to the authorized level. Virginia Power filed its Altema-ti ve Regulatory Plan in March 1997, based on 1996 financial information. Subsequently, the Commission consolidated the proceeding concerned with the 1995 Annual Informational Filing with the proceeding that includes the ARP proposed by the Company.

In December 1997, Virginia Power sought to withdraw its ARP, having concluded that resolution of the cost recovery issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that the Company may withdraw its support of the ARP but has reserved the right to continue consideration of the ARP .as well as other regulatory lternatives. In addition, the Commission will continue to consider the issues arising out of the 1995 Annual Informational iling. The Commission's Staff is scheduled to file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed y April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A public hearing is scheduled to commence on May 19, 1998.

Virginia Power's previous filings in this proceeding support maintaining the Company's rates at current levels; how-ever, opposing parties have made filings recommending rate reductions in excess of $200 million. At this time, man.agement cannot predict the ultimate outcome of the proceeding and its impact on the Company's results of operations, cash flows or financial position.

In July 1996, Virginia Power *proposed to substantially reduce the rates paid under Schedule 19 to cogenerators and small power producers of 100 kW or less. The rates became effective on an interim basis on January 1, 1997. On Janu-ary 21, 1998, the Virginia Commission approved revised Schedule 19 rates. The approved rates do not differ in any signifi-cant way from the rates originally proposed by the Company.

In October 1996, Virginia Power filed an application with the Virginia Commission to increase its fuel factor from 1.299 cents per kWh to 1.322 cents per kWh, reflecting a fuel factor annual revenue increase of approximately $48.2 mil-lion. The increase became effective on an interim basis on December 1, 1996. On June 11, 1997, the Commission entered an Order Establishing Fuel Factor approving the requested increase.

On October 31, 1997, Virginia Power filed with the Virginia Commission its application for a reduction of $45.6 mil-lion in its fuel cost recovery factor for the period December 1, 1997 through November 30, 1998. The reduction became effective on an interim basis on December 1, 1997. Subsequently, as a result of amendments to two non-utility powe~ pur-chase contracts, the Company proposed two additional reductions of approximately $30.2 million and $18 mi.Ilion for the same period, bringing the total proposed fuel factor reduction to $93.8 million. Both additional reductions were approved on an interim basis, effective March 1, 1998. A hearing is scheduled for April 9, 1998.

5

North Carolina On November 4, 1996, the Company filed for approval of a new Schedule 19 which governs purchases from cogenerators and small power producers. The Company proposed rates substantially lower than those previously specified.' It also pro-posed to reduce the applicability threshold to 100 kW and shorten the maximum tenn of contracts under Schedule 19 to five years. On June 19, 1997, the North Carolina Commission issued an Order requiring the Company to offer long-term (5-, 10-and 15-year) levelized capacity payments to hydroelectric and certain landfill and waste facilities contracting for up to 5 MW; a 5-year levelized rate option to other QFs contracting for up to 100 kW; and optional long-term levelized energy payments for QFs rated at 100 kW or less capacity.

On October 10, 1997 the Company filed an application with the North Carolina Commission for a $728,000 increase in fuel revenues. On December 29, 1997, the North Carolina Commission entered an Order Approving Fuel Charge Adjust-ment. The Order approved an approximate $600,000 increase in the annual rates and charges paid by the retail customers of North Carolina Power effective on January I, 1998.

CAPITAL REQUIREMENTS AND FINANCING PROGRAM Construction and Nuclear Fuel Expenditures Virginia Power's estimated construction and nuclear fuel expenditures for the three-year period 1998-2000, total $1.5 bil-lion*. It has adopted a 1998 budget for construction and nuclear fuel expenditures as set forth below: .

&timated 1998 E:1.1>enditures (millions)

Production . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .. . . . . .. . . . . . . . . $ 60 Technology ................. '. ....................................................... *...... :.................... 150 General Support Facilities ............................................................................... 19 Transmission . . . . ... . . . . . . . . . . . . . . . . . .. . .. . . .. . . . . . . . . . . .. . . .. .. . . . . . . . .. . . . . . . ... . . . . . . .. . . . . .. . . . . .. ........ 37 Distribution . . . . . . . . .. . . . . . . . . . . . . . . . .. . .. . . .. . . . . .. . . . . . . . . . .. . .. . . . ... . .. . .. . . . . . . . . .. . ... . . . . . . . . . . . . . .. .. . 213 Nuclear Fuel . ..... ..... ... .. .................... .... .............. ............. ... . ............... ......... .. 86 Total Construction Requirements and Nuclear Fuel Expenditures . . .. . . . . . . . . . . . . . . . . . . . $565 In addition, the Company expects to incur approximately $23 million of expenditures in 1998 in connection with the development of energy management projects for customers. Contracts with such customers provide for the recovery of these costs in future years.

Financing Program The Company currently has three shelf registrations on file with the Securities Exchange Commission (SEC) provid-ing the Company with $915 million of debt capital resources. The Company also has a Preferred Stock shelf registered with the SEC for $100 million in aggregate principal amount, which has not been utilized.

The Company intends to issue securities from time to time to meet its capital requirements, which include $333.5 mil-lion of long-term debt maturities in 1998.

Please see the Liquidity and Capital Resources section of MD&A for details about our Financing Program.

6 L_

SOURCES OF POWER Company Generating Unite; l)*pc Summer Years of Capability Name of Station, Unit~ and Location Installed Fuel MW Nuclear:

Surry Units 1 & 2, Surry, Va ..................... :: ................... . 1972-73 Nuclear 1,602 North Anna Units 1 & 2, Mineral, Va ............................... . 1978-80 Nuclear 1,790(a)

Total nuclear stations ................................................. . 3,392 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 Clover Units I & 2, Clover, Va. . ................................ . 1995-96 Coal 882(b)

Mt. Storm Units 1-3, Mt. Storm, W. Va . .................. :... . 1965-73 Coal 1,587 Chesapeake Units 1-4, Chesapeake, Va....................... .. 1953-62 Coal 595 Possum Point Units 3 & 4, Dumfries, Va..................... . 1955-62 Coal 322 Yorktown Units I & 2, Yorktown, Va .......................... . 1957-59 Coal 326 Possum Point Units 1, 2, & 5, Dumfries, Va................. . 1948-75 Oil 929 Yorktown Unit 3, Yorktown, Va .............*..................... . 1974 Oil & Gas 818 North Branch Unit I, Bayard, W. Va ........................... . 1994 Waste Coal 74(c)

Combustion Turbines:

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

Bellmeade, Richmond, Va ............................................. . 1991 Oil & Gas 230 Chesterfield Units 7 & 8, Chester, Va ............................. . 1990-92 Oil & Gas 397 Total fossil stations ...... : ............................................ .. 8.656 Hydroelectric:

Gaston Units 1-4, Roanoke Rapids, N.C .......................... . 1963 Conventional 225

. Roanoke Rapids Units 1-4, Roanoke Rapids, N.C ............. . 1955 Conventional 99 Other ........................................................................... . 1930-87 Conventional 3 Bath County Units 1-6, Warm Springs, Va ....................... . 1985 Pumped Storage I ,260(d)

Total hydro stations ................................................... . 1.587 Total Company generating unit capability ..................... . 13,635 Net Purchases ................................................................ . 1,480 Non-Utility Generation ................................................... . 3.277 Total Capability ........................................................ . 18.392 (a) Includes an undivided interest of 11.6 percent.(208 MW) owned by ODEC.

(b) Includes an undivided interest of 50 percent (441 MW) owned by ODEC.

(c) Effective January 25, 1996, this unit was placed in a cold reserve status.

(d) Reflects the Company's 60 percent undivided ownership interest in the 2,100 MW station. A 40 percent undivided interest in the facility is owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc (AE).

The Company's highest one-hour integrated service area summer peak demand was 14,537 MW on July 28, 1997, and an all-time high one-hour integrated winter peak demand of 14,910 MW was reached on February 5, 1996.

7

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 MD&A.

Nuclear Operations and Fuel Supply In 1997, the Company's four nuclear units achieved a combined capacity factor of 91.1 percent.

- The Company utilizes both Jong-term contracts and spot purchases to support its needs for nuclear fuel. The Company continually evaluates worldwide market conditions in order to ensure a range of supply options at reasonable prices. Cur-rent agreements, inventories and spot market availability will support the Company's current and planned fuel supply needs for fuel cycles throughout the remainder of the I990's and into the early 2000's. Beyond that period, additional fuel will be purchased as required to ensure optimum cost and inventory levels.

The DOE is not expected to begin the acceptance of spent fuel in 1998 as specified in the Company's contract with the DOE. However. on-site spent nuclear fuel storage at the Surry Power Station (spent fuel pool and dry cask storage) is expected to be adequate for the Company's needs until the DOE begins accepting spent fuel. The North Anna Power Sta-tion will require additional spent fuel storage capacity in 1998. The Company submitted a license application to the NRC in May 1995 for a dry cask facility at North Anna. The Company anticipates that this application will be approved in mid-1998.

For details on the issues of decommissioning and nuclear insurance, see Note C to the CONSOLIDATED FINANCIAL STATEMENTS.

Fossil Operations and Fuel Supply The Company's fossil fuel mix consists of coal, oil and natural gas. In I 997, Virginia Power consumed approximately 13 million tons of coal. As with nuclear fuel, the Company utilizes both long-term contracts and spot purchases to support its needs. The Company presently anticipates that sufficient coal supplies at reasonable prices will be available for the remainder of the l 990's. Current projections for an adequate supply of oil remain favorable, barring unusual international events or extreme weather conditions. which could affect both price and supply.

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 con-sumed during the colder months when gas supplies are not available at favorable prices. The Company has firm transporta-tion contracts for the delivery of gas to the combined cycle units. Current projections indicate gas supplies will be available for the next several years.

Purchases and Sales of Energy Virginia Power relies on purchases of power to meet a portion of its capacity requirements. 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 gen-eration costs.

Under contracts effective January I, 1985, Virginia Power agreed to purchase 400 MW of electricity annually through 1999 from Hoosier Energy Rural Electric Cooperative, Inc. (Hoosier), and agreed to purchase 500 MW of electricity annu-ally during 1987-99 from certain operating units of American Electric Power Company, Inc. (AEP).

The Company has a diversity exchange agreement with AE under which AE delivers 200 MW to Virginia Power in the summer and Virginia Power delivers 200 MW to AE in the winter.

• Virginia Power also has 57 non-utility power purchase contracts with a combined dependable summer capacity of 3,277 MW (for information on the financial obligations under these agreements see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS). In a continuing effort to mitigate its exposure to above-market Jong-term purchased power contracts, the Company is evaluating its long-term purchased power contracts and negotiating modifications to their terms, including can-cellations, where it is determined to be economically advantageous to do so.

The Company's wholesale power group actively participates in the purchase and sale of wholesale electric power and natural gas in the open market. The wholesale power group has expanded the Company's trading range beyond the geo-graphic limits of the Virginia Power service territory, and has developed trading relationships with energy buyers and sell-ers on a nationwide basis.

8

In July 1997, the Company executed three agreements with Old Dominion Electric Cooperative (ODEC) which pro-vide for the amendment of the parties' Interconnection and Operating Agreement (I&O Agreement). The first agreement rovides for the transition from cost-based rates for capacity and energy purchases by ODEC to market-based rates by 2002.

he second two agreements arc the Service and Operating Agreements for Network Integration Transmission Service, which unbundled the transmission services provided to ODEC under the I&O Agreement.

FUTURE SOURCES OF POWER As reported earlier, both the Hoosier 400 MW long-term purchase and the AEP 500 MW long-term purchase will expire on December 31, 1999. The Company presently anticipates adding peaking capacity beginning in the year 2000 to meet its anticipated load growth. 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 owned and operated by others and sold to the Company or may be built by the Company if it determines it can build capacity at a lower overall cost. The Company also pursues conserva-tion and demand-side management (see CONSERVATION AND LOAD MANAGEMENT below). No Company-owned generation is currently in the planning or construction stages.

For additional information, see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS.

CONSERVATION AND LOAD MANAGEMENT The Company is committed to evaluating and selecting demand-side and supply-side options on a consistent basis in order to provide reliable, low-cost service to its customers. Conservation and load management programs are evaluated annually at Virginia Power through a resource planning process that directly compares the stream of costs and benefit~ from supply-side and demand-side options. This process supports a conservation and load management portfolio which contrib-utes both to the selection of low-cost resources to meet the future electricity needs of the Company's customers, as well as the efficient use of current resources.

Events in the evolving electric power marketplace and its regulatory and legislative environment continue to impact utility-sponsored conservation and load management programs. In the future, the Company anticipates a greater reliance on the use of price signals to convey information to our customers regarding energy-related costs, resulting in more efficient urchase decisions.

INTERCONNECTIONS The Company maintains major interconnections with Carolina Power and Light Company, AEP, AE and the utilities in the Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission network, the Company has arrange-ments with these utilities for coordinated planning, operation, 'emergency assistance and exchanges of capacity and energy.

In December 1996, the Company joined with Allegheny Power Service Corporation, Cleveland Electric Illuminating Company, Toledo Edison Company, Ohio Edison Company, Pennsylvania Power Company and Southern Company Services, Inc. (the Transmission Alliance) to file a contract with the FERC entitled the GAPP Experiment Participation Agreement (GAPP Agreement). The Transmission Alliance and the GAPP Agreement were established to promote fair and equitable use of the transmission systems based on the General Agreement on Parallel Paths (GAPP) model for coordinating the flow of bulk supplies of electricity among utilities. GAPP principles allow electric companies to determine where electricity actu-ally flows in bulk power transactions, as opposed to the "contract" paths that are based on power purchase and transmission agreements among buying, selling and transmitting utilities.

Compensation for transmission services has historically been based on contract paths. The "GAPP Agreement was designed to determine the physical path electricity actually takes through the system and allocate open access transmission revenues among the parties. The GAPP Agreement was designed a~ an experiment to test the GAPP methods and proce-dures for a period of two years. The FERC accepted the contract on March 25, 1997. The Company and the Transmission Alliance implemented the GAPP Agreement on April 2, 1997.

On November 14, 1997, in accordance with the FERC order accepting the GAPP Agreement, the Transmission Alli-ance issued a report detailing the results of the first six months of the experiment. The preliminary results of the experiment indicate that it is technically possible to monitor and predict the physical flow of electricity over multiple systems and that transmission revenues reallocated according to actual use of the system differ significantly from collections under a contract 9

path approach. In October 1997, Virginia Power gave notice to the Transmission Alliance that, effective January 1, 1998, it wa~ exercising its option under the GAPP Agreement to terminate its involvement in the experiment._

On December 9, 1997, the Company, the Transmission Alliance and other utilities agreed to study the creation of an independent regional transmission entity. The memorandum of understanding to initiate this study was signed by eleven investor-owned electric companies, including Virginia Power, Consumers Energy, Detroit Edison, Duquesne Light Company, The Illuminating Company, Ohio Edison Company, Pennsylvania Power Company, Toledo Edison Company, and the Allegheny Energy Companies (Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company). This group is an outgrowth of the GAPP Agreement and its key goals are to maintain the long-term reliability and security of the utilities' interconnected transmission systems; ensure the most efficient use of resources; eliminate pancaking of rates within and between transmission entities; avoid duplication of costs and achieve transmission cost savings; and, strike an appropri-ate balance among the diverse interests of energy suppliers, customers, and shareholders. The group will also explore coop-

.erative agreements designed to achieve these goals while ensuring nondiscriminatory and comparable access to all users of

. the group's transmission system. The companies intend to be responsive to industry changes, especially with the introduc-tion of retail competition in some of the areas served by the signatories and as some other industry participants consider creation of independent transmission operating companies or separate transmission companies. Further, the companies will have the flexibility to continue to investigate and pursue other opportunities and arrangements that could develop regarding independent system operators or independent transmission companies.

Virginia Power and Appalachian Power Company (AEP-Virginia), an operating unit of AEP, each sought approval from the SCC in 1991 to construct certain interconnecting transmission facilities. These applications resulted from a joint plan-ning effort of Virginia Power and AEP to meet the requirements of their customers. At the time of Virginia Power's appli-

• cation, particularly during the summer of 1992, constraints were being experienced on transfers of power into the Virginia Power service territory from the west. On November 7, 1997, the SCC issued an Order directing the Company to report to the Commission on the continued need for certain new interconnected transmission facilities, on the relationship between the Company's application to build the new facilities and certain other pending proceedings, and on the Company's con-

• struction plans, if the SCC grants the Company's application.

On December 15, 1997, the Company filed a report in compliance with the SCC Order stating that since the filing of the Company's application, the constraints have been less frequent, due in part to less severe summer weather, and actual power requirements have been less than originally forecasted. In addition, generating resources within the Virginia Power service area have been increased by the higher performance level of the nuclear units, as well as the completion of the Clo-ver Station. Completion of the AEP project is a prerequisite for the Virginia Power project to go forward. The proposed Vir-ginia Power project would not fulfill its intended purpose without the AEP line being built. AEP has withdrawn its original application and has instituted a new proceeding before the Commission in which different routing is proposed. Virginia I

Power continues to monitor closely the progress of AEP in this proceeding with respect to its new proposal, but until more is known about these proceedings, Virginia Power cannot predict what its construction plans will be.

ITEM 2. PROPERTIES The Company owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of its property is subject to the lien of a mortgage securing its First and Refunding Mortgage Bonds. Right-of-way grants from the apparent owners of real estate have been obtained for most electric lines, but underlying titles have not been examined except for transmission lines of 69 Kv or more. Where rights of way have not been obtained, they could be acquired from private owners by condemnation if necessary. Many electric lines are on publicly owned property, as to which permission for use is generally revocable. Portions of the Com-pany'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 the CONSOLIDATED FINANCIAL STATE-MENTS.

See Company Generating Units under SOURCES OF POWER under Item 1. BUSINESS.

10

ITEM 3. LEGAL PROCEEDINGS From time to time, the Company is alleged to be in violation or in default under orders, statutes, rules or regulations elating to 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. From time to time, there may be administra-tive proceedings on these matters pending. In addition, in the normal course of business, the Company is involved in vari-ous legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the Company's financial position, liquidity or results of operations.

In December 1995, two civil actions were filed in the Virginia Circuit Court of the City of Norfolk against the City of Norfolk and Virginia Power, one for $15 million and one for $3 million, by property owners who each alleged contamina-tion of their respective properties by hazardous substances originating on nearby property now owned by the city and for-merly owned by the Company. In reference to the $15 million action, the parties reached a settlement prior to the scheduled August I 8, 1997, trial date. The related action by the other property owner seeking $3 million is still pending, but has not yet been scheduled for trial.

On April 2, 1997, Doswell Limited Partnership (Doswell) filed a motion for judgment against Virginia Power in the

. Circuit Court of the City of Richmond. Doswell is an independent power producer that has entered into two power purchase agreements with Virginia Power and claims the Company breached one of those agreements. On the same date, Doswell also filed a complaint against Virginia Power in the United States District *Court for the Eastern District of Virginia alleg-ing certain claims relating to the two power purchase agreements. In March 1998, the parties agreed that both proceedings should be stayed in order to give the parties an opportunity to negotiate amendments to the power- purchase agreements.

• ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS On October 17, 1997, by Consent of the Sole Shareholder, Dominion Resources, Inc., the number of Virginia Power Directors was expanded to a maximum of eighteen (18) and the following Directors were elected to serve for terms expir-ing at the annual shareholder meetings for the years indicated below: *

• John B. Bernhardt 2000 John W. Harris 1998 Kenneth A. Randall 1999 Frank S. Royal 1998 Judith B. Sack 1999 S. Dallas Simmons 2000 David A. Wollard 1999 11

. l , ..

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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.

The Company paid quarterly cash dividends on its Common Stock as follows:

1st 2nd 3rd 4th (Millions) 1997 ************************************************************************************ $95.9 $93.4 $94.7 $95.9 1996 ************************************************************************************ $95.3 $96.5 $96.1 $97 .9 ITEM 6. SELECTED FINANCIAL DATA 1997 1996 1995 1994 1993 (Millions, except percentages)

Revenues ............................................................... . $ 5,079.0 $ 4,420.9 $ 4,351.9 $ 4,170.8 $ 4,187.3 Income from operations ........................................... .. 1,019.3_. 1,010.0 971.9 957.1 1,070.6 Net income ........................................................... .. 469.1 457.3 432.8 .447.l 509.0 Balance available for Common Stock ........................ . 433.4 421.8 388.7 404.9 466.9 Total assets ............................................................ . 11,953.4 . 11,828.0 11,827.7 11,647.9 11,520.5 Total net utility plant ............................................... . 9,219.2 9,433.8 9,573.1 * . 9,623.4 9,459.7 Long-term debt, noncurrent capital lease obligations, preferred stock subject to mandatory redemption and preferred securities of subsidiary trust ..................... . 3,854.4 3,916.2 4,228.0 4,157.5 4,151.1 Utility plant expenditures (including nuclear fuel) ........ . 481.8 484.0 577.5 660.9 712.8 Capitalization ratios (percent):

Debt .................................................................. . 45.4 46.4 47.2 46.7 46.4 Preferred stock .................................................... . 7.6 7.5 7.5 9.0 9.2 Preferred securities .............................................. . 1.5 1.5 1.5 Common equity ................................................. .. 45.5 44.6 43.8 44.3 44.4 Embedded cost (percent):

Long-term debt ................................................... . 7.60 7.68 7.73 7.65 7.67 Preferred stock ..................................................... . 5.25 5.14 5.29 5.47 4.88 Preferred securities .............................................. . 8.72 8.72 8.72 Weighted average ................................................ . 7.29 7.34 7.41 7.29 7.18 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This Management's Discussion and Analysis of Financial Condition and Results of Operations contains "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including (without limitation) dis-cussions as to expectations, beliefs, plans, objectives and future financial performance,. or assumptions underlying or con-cerning matters discussed in this document. These discussions, and any other discussions, including certain contingency matters (and their respective cautionary .statements) discussed elsewhere in this report, that are not historical facts, are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

Some important factors that could cause actual results or outcomes to differ materially from those discussed in the .

forward-looking statements include current governmental policies and regulatory actions (including those of FERC, the EPA, the DOE, the NRC, the Virginia Commission and the North Carolina Commission), industry and rate structure, operation of nuclear power facilities, acquisition and disposal of assets and facilities, operation and storage facilities, recovery of the cost 12

of purchased power, nuclear decommissioning costs, and present or prospective wholesale and retail competition. The busi-ness and profitability of Virginia Power also are influenced by economic and geographic factors including political and eco-nomic risks,.changes in and compliance with environmental laws and policies, weather conditions and catastrophic weather-elated damage, competition for retail and wholesale customers, pricing and transportation of commodities, market demand for energy, inflation, capital market conditions, unanticipated changes in operating expenses and capital expenditures, com-petition for new energy development opportunities and legal and administrative proceedings. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond the control of Virginia Power.

New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of each such factor on the business of the Company.

Any forward-looking statement speaks only as of the date on which such statement is made, and Virginia Power under-

. takes-no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

Liquidity and Capital Resources Operating activities continue to be a strong source of cash flow, providing $1,091 million in 1997 compared to $1,115 mil-lion in 1996. The decrease of $24 million (or 2 percent) from the previous year is attributable to normal business fluctua-tions .. Over the past three years, cash flow from operating activities has, on average, covered 134 percent of our total con-struction requirements and provided 81 percent of our total cash requirements. Our remaining cash needs are met generally with proceeds from the sale of securities and short-term borrowings.

Financing activities have represented a net outflow of cash in recent years as strong cash flow from operations and the absence of major construction programs have reduced the Company's reliance on debt finan'cing.

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

1997 1996 1995 (Millions)

Issuance of long-term debt ................................................................................. . $ 270.0 $ 24.5 $ 240.0 ssuance of preferred securities of subsidiary trust ...... .-............. :; ............................ . 135.0 ssuance (Repayment) of short-term debt .............................................................. . (86.2) 143.4 169.0 epayment of long-term debt and preferred stock ................................................. .. (311.3) (284.1) (439.0)

Dividend payments ........................................................................................... . (415.6) (421.4) (438.6)

Other .............................................................................................................. . {13.5) {13.2) (13.7)

Total ........................................................................................................... . ${556.6) . .$(550.8) ${347.3)

We have taken advantage or'cieclining interest rates by. issuing new debt at lower rates as higher-rate debt has matured.

For example, in 1997, $311.3 million of the Company's long-term debt securities matured with an average effective rate of 8.08 percent. As a partial replacement for this maturing debt,. we issued $270 million of long-term debt securities during the year with an average effective rate of 6.84 percent.

We currently have three shelf registration statements effective with the Securities and Exchange 'Commission from which we can obtain additional debt capital: $400 million of Junior Subordinated Debentures; $375 million of Debt Secu-rities, including First and Refunding Mortgage Bonds, Senior Notes and Senior Subordinated Notes filed 1n February 1998; and $200 million of Medium-Term Notes, Series F. The remaining principal amount of debt that can be issued under these registrations totals $915 million. An additional capital resource of $ JOO million in preferred stock also is registered with the Securities and Exchange Commission.

The Company has a commercial paper program that is supported by two credit facilities totaling $500 million. Pro-ceeds from the sale of commercial paper are primarily used to provide working capital. Net borrowings under the program were $226.2 million at December 31, 1997.

Investing activities in 1997 resulted in a net cash outflow of $546.1 million, primarily due to $397 .0 million of con-struction expenditures and $84.8 million of nuclear fuel expenditures. The construction expenditures included approximately

$252.4 million for transmission and disuibution projects, $52.1 million for production projects, $49.7 million for informa-tion technology projects and $42.8 million for other projects.

13

Cash used in investing activities was as follows:

1997 1996 .. 1995 (Millioru;)

Utility plant expenditures (excluding AFC- other funds) ....................................... . $(397.0) $(393.8) $(519.9)

Nuclear fuel (excluding AFC - other funds) ........................................................ . *(84.8) (90.2) (57.6)

Nuclear decommissioning contributions ........................................... : .................... . (36.2) . (36.2) (28.5)

Sale of accounts receivable, net .......................................................................... . (160.0)

Purchase of assets .............................................................................................. . (19.8) (13.7)

Other .............................................................................................................. . {8.3) {12.5) {11.1)

Total ........................................................................................................... . $(546.1) $(546.4) ,'${777.1)

Capital Requirements Capacity- The Company anticipates that kilowatt-hour sales will grow approximately 2.36 percent a year through 2000. We will continue to pursue capacity acquisition plans to meet the anticipated load growth and maintain a*high degree of service reliability. The additional capacity may be purchased from others or built by the Company if we can build capacity at a lower overall cost. We have long-term purchase agreements with Hoosier (400 MW) and AEP (500 MW) which will expire on December 31, 1999. We presently anticipate adding peaking capacity beginning in the year 2000 to meet future load growth. *

• Fixed Assets-The Company's construction and nuclear fuel expenditures (excluding AFC), during 1998,* 1999 and 2000 are expected to total $588.1 million, $476.2 million and $395.1 million, respectively. The Company presently 'esti-mates that all of its 1998 construction and nuclear fuel expenditures will be met through cash flow from operations.

Long-term Debt - The Company will require $333.5 million to meet maturities of long-term debt in 1998, which we expect to meet with cash flow from operations and issuance of replacement debt securities. Other capital requirements will be met through a combination of sales of securities and short-term borrowings.

Customer Service -The Company has adopted a plan to improve customer service, requiring an inves~ent in.excess of $100 million. Our plan includes: -

• installing automated electric meters in metropolitan and inaccessible rural and urban locations,

• installing a new work management system,

• making technological changes to enhance the Company's ability to handle customer calls during power outages,

• installing mobile data dispatch technology in the Company's service fleet, accompanied by digitized mapping of our service territory, and

• initiating both local and regional distribution line improvement projects.

Expenditures in 1997 for these projects were approximately $23 million; future expenditures are expected to be approxi-mately $68 million in 1998 and $15 million in 1999. We anticipate funding these projects with cash flow from operations.

14 L___________ _

Results of Operations The following is a discussion of results of operations for the years ended 1997 as compared to 1996, and 1996 as com-ared to 1995.

1997 Compared to 1996 Revenue changed from the prior year primarily due to the following:

1997 1996 (Millions)

Revenue - Electric Service Customer growth ........................................................................................................... . $ 55.8 $ 45.1 Weather ....................................................................................................................... . (111.1) 4.4 Base rate variance ......................................................................................................... . (18.7) (35.5)

Fuel rate variance .......................................................................................................... . 44.1 (89.6)

-Other retail, net ............................................................................................................. . 47.7 41.5 Total retail .................................................................................................... : ......... *.. . 17.8 (34.1)

Other electric service .................................................................................................... .. 11.0 (49.8)

Total electric service ................................................................................................... . 28.8 ~

Revenue - Other

Wholesal_e-,- power marketing ........................................................................................ . 363.4 96.6 Natural gas ................................................................................................................... . 232.6 33.2 Other, net ...................................................................................................................... . 33.3 23.1 Total revenue - other ................................................ .-................................................ . 629.3 152.9 Total revenue .......................................................................................................... . $ 658.1 $ 69.0

• Electric service revenue consists of sales to retail customers in our service territory at rates authorized by the Virginia and.North Carolina Commissions and sales to cooperatives and municipalities at wholesale rates authorized by FERC: The rimary factors affecting this revenue in 1997 were customer growth, weather, and fuel rates.

Customer growth - There were 50,899 new customer connections to our system in 1997, the largest number of new

• connections in any year since 1990. This had the effect of increasing our sales by $55.8 million in 1997 over 1996.

Weather - The mild weather in 1997 caused customers to use less electricity for heating and cooling, which reduced revenue by approximately $111.1 million from the previous year. Heating and cooling degree days were as follows:

1997 1996 Normal

• Cooling degree days .................................... *.................... . 1,349 1,365 1,530 Percentage change compared to prior year .......................... . (1.2)% (18.1)%

Heating degree days *:* ...................... *......................*......... . 3,787 4,131 3,726 Percentage change compared to prior year .......................... . (8.3)% 9.0%

Fuel rates - The increase in fuel rate revenues is primarily attributable to higher fuel rates which went into effect December 1, I 996, increasing recovery of fuel costs by approximately $48.2 million. The regulatory commissions hav-ing jurisdiction over the Company allow us to charge customers for the cost of fuel used in generating electricity.

Other revenue includes sales of electricity beyond our service territory, natural gas, nuclear consulting services, energy management services and other revenue. The growth in power marketing and natural gas sales revenue is primarily due to our success at marketing electricity and natural gas beyond our service territory. The Company began pursuing these new lines of business in 1996. We expect that revenue from such non-traditional business activities will continue to grow in the near future.

15

Kilowatt-hour sales changed as follows:

Increase (Decrca~e) From Prior Year 1997 1996 Residential ............................................... . (1.8)% 2.3%

Commercial .................................. :.......... . 0.6 2.3 Industrial ................................................ .. 2.1 2.3 Public authorities ................................ , .... .. (4.7) 2.6 Total retail sales ....................................... . (0.5) 2.4 Wholesale - system ................................. . 2.5 (24.3)

Wholesale - power marketing .................... . 196.0 200.3 Total sales ................................................ . 17.2 6.3 The decrease in retail kilowatt-hour sales in 1997 as compared to 1996 reflects the impact of weather on our traditional electricity service business, despite continued customer growth. The increase in wholesale kilowatt-hour sales was primarily due to the Company's power ma_rketing efforts.

Fuel, net increased as compared to 1996, primarily due to the cost of the power marketing and natural gas sales which reflects increased purchases of energy from other wholesale power suppliers and purchases of natural gas.

System energy output by energy source and the average fuel cost for each are shown below. Fuel cost is presented in mills (one tenth of one cent) per kilowatt hour.

1997 1996 1995

• Source Cost Source Cost Source Cost Nuclear(*) *********************************** 34% 4.52 32% 4.48 32% 4.92 Coal (**) ************************************** 40 13.54 38 14.32 39 14.44 Oil ********************************************** 1 26.32 1 27.75 l 25.11

• Purchased power, net ...... .'.-.............. 23 21.54 27 21.99 25 22.50 Other ******************************************* 2 *30.65 2 26.98 3 23.82 Total* ....................... : ................ *.- 100% 100% 100%

• Average fuel cost *********************** 12.67 13.47 13.73

(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power Station.

(**) Excludes ODEC's 50 percent ownership interest in the Clover Power Station.

Other operations and maintenance* increased as compared to 1996 as a result of costs associated with the growth in sales by the Company's energy services business unit. These higher costs were offset partially by a reduction in expenses attributable to the Company's strategic initiatives. Expenses in 1996 include high storm damage costs resulting from destruc-tive summer storms, including Hurricane Fran.

Depreciation and amortization increased as compared to 1996 due to the recognition of additional depreciation and nuclear decommissioning expense to reflect adjustments in the Company's filing currently pending before the Virginia Com-mission and higher depreciation ex~nse related to Clover Unit 2, which began operations in March 1996. See Future Issues - Utility Rate Regulation for additional information on current rate proceedings.

• Restructuring expenses decreased as compared to 1996 as the Company nears completion of its Vision 2000 strategic initiative. Charges for restructuring primarily include employee severance costs, costs to restructure agreements to purchase power from third parties and, when necessary, to negotiate settlement and terrnination of these contracts, and other costs.

The Company estimates that staffing reductions will result in annual savings, in the range of $80 million to $90 million.

However, these savings are being offset by salary increases, outsourcing costs and increased payroll costs associated with staffing for growth opportunities. See also Note O to the CONSOLIDATED FINANCIAL STATEMENTS.

Accelerated cost recovery represents a reserve for potential adjustments to regulatory assets. In this increasingly com-petitive environment, the Company has concluded that it is appropriate to utilize available cost reductions, such as those generated by the Vision 2000 program, to accelerate the write-off of unamortized regulatory assets and potentially stranded costs (see Future Issues - Competition).

16

1996 Compared to 1995 Electric service revenues decreased as compared to 1995 due to the effect of mild weather on the Company's summer retail rates, which are designed to reflect normal weather conditions. These revenues also were affected by reduced sales to Old Dominion Electric Cooperative (ODEC) due to the completion of Clover Units I and 2, of which ODEC owns a fifty percent interest.

Other revenues increased as compared to 1995 due to growth in our power marketing and energy services business, which was organized as a distinct business unit in 1996.

Fuel, net increased as compared to 1995, primarily as a result of increased energy purchases associated with our power marketing sales, offset in part by a higher recovery of fuel expenses subject to deferral accounting in 1995.

Operations and maintenance decreased slightly as compared to 1995, primarily as a result of a reduction in expenses attributable to the Company's strategic initiatives, offset partly by the high storm damage costs incurred in 1996 from destructive summer storms, including Hurricane Fran.*

Depreciation and amortization increased as compared to 1995, primarily as a result of greater nuclear decommission-ing expense and. depreciation related to Clover Units 1 and 2, which were placed in service in October 1995 and March 1996, respectively.

Restructuring decreased as compared to 1995 as the.implementation phase of the Vision 2000 initiative continued.

Restructuring charges in 1996 included severance costs, costs to restructure or settle certain contracts to purchase power and other costs. In addition, 1995 restructuring costs included one-time charges to cancel specific capital projects and adjust-ments to inventory and certain real estate to reflect adoption of changes in business strategies and processes.

Accelerated cost recovery represents a provision for management's estimate of a reserve that may ultimately be used to accelerate the write-off of unamortized regulatory assets and potentially stranded costs (see Future Issues - Competition).

Future Issues Competition in the Electric Industry- General.

For most of this century, the structure of the electric industry in Virginia and throughout the United States has been relatively stable. We have recently seen, however, federal and state developments toward increased competition. Electric utilities have been required to open up their transmission systems for use by potential wholesale competitors. In addition, non-utility power producers now compete with electric utilities in the wholesale generation market. At the federal level, retail competition is under consideration. Some.states have enacted legislation requiring retail competition.

Today, Virginia Power faces competition in the wholesale market. Currently, there is no general retail competition in Virginia Power's principal service area. To the extent that competition is permitted, Virginia Power's ability to seH power at prices. that allow it to recover its prudently incurred costs may be an issue. See Future Issues - Competition -

Exposure to Potentially Stranded Costs.

In response to competition, Virginia Power has successfully renegotiated long term contracts with wholesale and large federal government customers. In addition, the Company has obtained regulatory approval of innovative pricing proposals for large industrial customers. Rate concessions resulting from these contract negotiations and innovative pricing proppsals are expected to reduce the Company's 1998 revenue by approximately $40 million. To date, the Company has not experi-enced any material loss of load.

Virginia Power is actively participating in the legislative and regulatory processes relating to industry restructuring. The Company has also responded to these trends toward competition by cutting its costs, re-engineering its core business pro-cesses, and pursuing innovative approaches to serving traditional markets and future markets. In addition, a significant part of the Company's strategy relies on developing "non-traditional" businesses within the Company's business units and sub-s_idiaries designed to provide growth in future earnings, including:

• Energy Services - offering electric energy and capacity in the emerging wholesale market as well as natural gas, and other energy related products and services;

• Fossil & Hydro - targeting process type industries, such as chemical, paper, plastics and petroleum to become a ser-vice provider of instrumentation equipment;

• Nuclear Services - offering management and operations services to other electric utilities; 17

• Commercial Operations - providing power distribution related services, including transmission and distribution, engi-neering and metering services to other gas, water and electric utilities; and

• Telecommunications - offering telecommunications services through the Company's existing fiber-optic* network.

The Company's non-traditional businesses face competition from a variety of utility and non-utility entities. In addi-tion. Virginia Power may from time to time identify and investigate opportunities to expand its markets through strategic alliances with partners whose strengths, market position and strategies complement those of the Company.

Competition - Wholesale During 1997, sales to wholesale customers represented approximately 17 percent of the Company's total revenues from electric sales. Approximately 73 percent of wholesale revenues resulted from the Company's power marketing efforts.

In July 1997, Virginia Power filed amendments to its existing rate tariffs with FERC so it could make wholesale sales at market-based rates. Under a FERC order conditionally accepting the Company rates for filing, Virginia Power began making markyt-based sales in I 997. FERC set for hearing in June 1998 the issue of whether transmission constraints limit-ing the transfer of power into the Company's service territory provide Virginia Power with generation dominance in local-ized markets. If FERC finds transmission constraints give Virginia Power generation dominance, it could revoke or limit the scope of the Company's market-based rate authority.

Virginia Power has successfully negotiated a new power supply arrangement with its largest wholesale customer. The new arrangement provides for a transition from cost-based rates to market-based rates, subject to FERC approval. Virginia Power estimates the reduced rates, offset in part by other revenues which may be earned under the agreement, will decrease income before taxes by approximately $38 million through 2005. Virginia Power anticipates that additional contract nego-tiations with other wholesale customers will take place in the future.

Competition - Retail Currently, Virginia Power has the exclusive right to provide electricity at retail within its assigned service territories in Virginia and North Carolina. As a result, Virginia Power now only faces competition for retail sales if certain of its busi-ness customers move into another utility service territory, use other energy sources instead of electric power, or generate their own electricity. However, both Virginia and North Carolina are considering implementing retail competition.

Competition - Legislative Initiatives Virginia: In the I 998 Session, the Virginia General Assembly passed House Bill No. 1172 (HB 1172) to establish a schedule for Virginia's transition to retail competition in the electric utility industry. The Company actively supported HBl 172, which passed both houses of the General Assembly in amended form and now awaits action by the Governor.

HB 1172 requires the following:

• establishment of one or more independent system operators (ISO) and one or more regional power exchanges (RPX) for Virginia by January 1, 2001;

• deregulation of generating facilities beginning January 1, 2002;

• transition to retail competition to begin on January l, 2002; with retail competition to begin on January I, 2004;

• recovery of just and reasonable net stranded costs; and

• appropriate consumer safeguards related to stranded costs and consideration of stranded benefits.

If HB 1172 becomes law, it will become effective July 1, 1998. While the bill establishes a timeline for the transition to competition in Virginia, a detailed plan to implement that transition must be developed through future legislative and regulatory action. The Company is unable at this time to predict its timing or details.

Federal: The U.S. Congress is expected to consider federal legislation in the near future authorizing or requiring retail competition. Virginia Power cannot predict what, if any, definitive actions the Congress may take.

North Carolina: The 1997 Session of the North Carolina General Assembly created a Study Commission on the Future of Electric Service in North Carolina. An interim report is expected in 1998 with final recommendations made to the 1999 session of the North Carolina General Assembly.

18

Competition - Regulatory Initiatives The Virginia Commission also has been actively interested in industry restructuring and competition, as shown in the ollowing generic and utility-specific proceedings.

In 1995, the Commission instituted an ongoing generic investigation on restructuring, resulting in a number of reports by its Staff covering such issues as retail wheeling experiments and the status of wholesale power markets.

In November 1996, the Commission ordered Virginia Power to file studies and reports on possible restructuring of the electric industry in Virginia. The Commission also invited Virgini~ Power to submit a proposed alternative regulation plan with its filing. A two-phase alternative regulatory plan (ARP) was filed March 1997. During Phase I (1997 to December 2002), Virginia Power proposed implementing a freeze of its current base rates and devoting a portion of earnings above a 11.5% return-on-equity to accelerate the write-off of generation-related regulatory assets and to mitigate the costs associated with payments under power purchase contracts with non-utility generators that may be above market if competition is autho-rized in Virginia. During Phase II (beyond December 31, 2002), Virginia Power would seek Commission approval of stranded cost recovery if retail competition is implemented in Virginia and a transition cost charge mechanism by which stranded costs would be recovered. Virginia Power presented illustrative estimates of stranded costs based on hypothetical market prices as part of its Phase II filing. When the Company filed its ARP, the Commission consolidated its consideration of the ARP with its consideration of the Company's 1995 Annual Information Filing. For a discussion of the 1995 Annual Information Filing, See Future Issues - Utility Rate Regulation.

In November 1997, the Commission Staff issued its report to the General Assembly calling for a cautious, two-phase, five-year period to address restructuring issues. The report acknowledged the need for direction from the Virginia legisla-

--fore concerning policy issues surrounding competition in the electric industry. Virginia Power sought to withdraw its ARP in December 1997, having concluded that resolution of the cost recovery issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that the Company may withdraw its support of the ARP, but has reserved the right to continue consideration of the ARP as well as other regulatory alternatives. In addition, the Commission will continue to consider the issues arising out of the 1995 Annual Informational Filing (See Future Issues - Utility Rate Regulation).

Competition - SFAS 71 Virginia Po~er's regulated rates are designed to recover its prudently in.curred costs of providing service, including the opportunity to earn a reasonable return on its shareholder's investment. The Company's financial statements reflect assets and cg1,ts under- this -cost-based rate regulation in accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation." SFAS 71 provides that certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets and are recognized as the related amounts are included in rates and recovered from customers. Continued accounting under SFAS 71 requires that rates designed to recover the utility's specific costs of providing service, are, and will continue to be, established by regulators. The presence of increasing competition that limits the utility's ability to charge rates that recover its costs, or a change in the method of regulation with the same effect, could result in the discontinued applicability of SFAS 71.

Rate-regulated companies are required to write off regulatory assets against earnings whenever those assets no longer meet the criteria for recognition as defined by SFAS 71. In addition, SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," requires a review of long-lived assets for impairment when-ever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Thus, events or changes in circumstances that cause the discontinuance of SFAS 71, and write off of regulatory assets, may also require a review of utility plant assets for possible impairment. If such review indicates utility plant assets are impaired, *the carry-ing amount of the affected assets would be written down. This would result in a loss being charged to earnings, unless recovery of the loss is provided through operations that remain regulated.

Virginia Power's regulated operations currently satisfy the SFAS 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company's results of operations and financial position may resuJt.*The form of cost-based rate regulation under*which Virginia Power operat~s is likely to ~volve as a result of various legislative or regulatory initiatives. At this time, management can predict

- - - -- neither the ultimate outcome of regulatory reform in the electric utility industry nor the impact such changes would have on Virginia Power.

19

Competition - Exposure to Potentially Stranded Costs Under traditional* cost-based regulation, utilities have generally had an obligation to serve supported by an implicit promise of the opportunity to recover prudently incurred costs. The most significant potential adverse effect of competition is "stranded costs." Stranded costs are those costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market.

The Company's potential exposure to stranded costs is comprised of the following:

• long-term purchased power contracts that may be above market (see Note Q to the CONSOLIDATED FINANCIAL STATEMENTS);

• costs pertaining to certain generating plants that may become uneconomic in. a deregulated environment;

• regulatory assets for items such as income tax benefits previously flowed-through to customers, deferred losses on reacquired debt and other costs; (see Note F to the CONSOLIDATED FINANCIAL STATEMENTS); and

• unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the finan-cial statements (see Notes C and N to the CONSOLIDATED FINANCIAL STATEMENTS).

Any forecast of potentially stranded costs is extremely sensitive to the various assumptions made. Such assumptions include:

• the timing and extent of customer choice in the market for electric service;

• estimates of future competitive market prices;

• sales and load growth forecasts;

• power stations' future operating performance;

• rate revenues permitted during the transition;

• estimated costs of utility operations over time;

• mitigation opportunities;

• stranded cost recovery mechanisms and other factors.

Certain combinations of these assumptions as applied to Virginia Power would produce little to no stranded costs; under other scenarios Virginia Power's exposure to potentially stranded costs could be substantial.

Virginia Power has assessed the reasonableness of various possible assumptions, but has not been able to settle on any particular combination thereof. Thus, the Company's maximum exposure:: to pmemially stranded costs is uncertain. Manage- _ _I ment believes that recovery of any potentially stranded costs is appropriate and will vigorously pursue such recovery witli~ *

• the regulatory commissions having jurisdiction over its operations. However, Virginia Power cannot predict the extent to which such costs, if any, will be recoverable from customers. Also, in an effort to mitigate the amount at risk, the Company will continue to implement cost reduction measures.

Utility Rate Regulation In March 1997, the Virginia Commission issued an order that Virginia Power's base rates be made interim and subject to refund as of March I, 1997. This order was the result of the Commission Staff's report on its review of Virginia Pow-er's 1995 Annual Informational Filing, which concluded that Virginia Power's present rates would cause Virginia Power to earn in excess of its authorized return on equity. The Staff found that, for purposes of establishing rates prospectively, a rate reduction of $95.6 million (including a one-time adjustment of $29.7 million to Virginia Power's deferred capacity balance at December 31, 1996) may be necessary in order to realign rates to the authorized level. Virginia Power filed its ARP in March 1997, based on I 996 financial information. Subsequently, the Commission consolidated the proceeding concerned with the 1995 Annual Informational Filing with the proceeding that includes the ARP proposed by the Company.

In December 1997, Virginia Power sought to withdraw its ARP, having concluded that resolution of the cost recovery issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that the Company may withdraw its support of the ARP but has reserved the right to continue consideration of the ARP as well as other regulatory alternatives. In addition, the Commission will continue to*consider the issues arising oui uf the ! 995 Annual Informational Filing. The Commission's Staff is scheduled to file its testimony on March 24, 1998; Virginia Power's rebuttal is to be riic::cl by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A public hearing is scheduled to commence on May 19, 1998.

Virginia Power's previous filings in this proceeding support maintaining the Company's rates at current levels; how-ever, opposing parties have made filings rcccmme,nding rate reductions in excess of $200 million. At this time, management cannot predict the ultimate outcome of the proceeding and its impact on the Company's results of operations, cash flows or financial position.

20

Utility Operations The Company strives to operate its generating facilities in accordance with* prudent utility industry practices and in

• onformity with applicable statutes. rules and regulations. Like other electric utilities, the Company's generating facilities re subject to unanticipated or extended outages for repairs, replacements or modification of equipment or otherwise to comply with regulatory requirements. Such outages may involve significant expenditures not previously budgeted, includ-ing replacement energy costs.

On September 10, 1997, the NRC published a proposed rule for financial assurance requirements related to nuclear decommissioning. If t'*e NRC's proposed rule were implemented without further clarification or modification, the Company may have to either pre-fund or provide acceptable security for a portion of its nuclear decommissioning obligation. See Note C to the CONSOLIDATED FINANCIAL STATEMENTS.

Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other -costs as a result of compliance, remediation, containment and monitoring obligations of the Company. These costs have been historically recovered from customers through utility rates. However, to the extent that the regulatory environment departs from cost-based rates, the Company's results of operations and financial condition could be adversely impacted.

Environmental Protection and Monitoring Expenditures The Company incurred $70.4 million, $71.1 million and $68.3 million (including depreciation) during 1997, 1996 and 1995, respectively, in connection with the use of environmental protection facilities and expects these expenses to be approxi-mately $69.1 million in 1998. In addition, capital expenditures to limit or monitor hazardous substances were $24.6 million,

$22.4 million and $23.4 million for 1997, 1996 and 1995, respectively. The amount estimated for 1998 for these expendi-tures is $10.0 million.

Clean Air Act Compliance The Clean Air Act, as amended in 1990, requires the Company to reduce its emissions of sulfur dioxide (S0 2 ) and itrogen oxides (NO,.). The Clean Air Act also requires the Company to obtain operating permits for all major emissions-emitting facilities. Permit applications have been submitted for the .Company's power stations located in North Carolina and West Virginia. Applications for the Company's power stations located in Virginia will be filed in 1998.

The Clean Air Act's S0 2 reduction program is based on the issuance of a limited number of S02 emission allowances, each of which may be used as a permit to emit one ton of S02 into the atmosphere or may be sold to someone else. The program is administered by the EPA. The Company's compliance plans may include switching to lower sulfur coal, pur-chase of emission allowances and installation of S0 2 control equipment. Maximum flexibility and least-cost compliance will be maintained through annual studies.

The Company began complying with Clean Air Act Phase I NO,. limits at eight of its units in Virginia in 1997, three years earlier than otherwise required. As a result, the units will not be subject to more stringent Phase II limits until 2008.

Furthermore, in order to avoid the necessity of more stringent regulations, the Company made voluntary commitments in 1996 to cap NO,. emissions at its Chesterfield and Yorktown Power Stations and the Chesapea.ke Energy Center during the ozone season beginning in 2000.

From 1994 through 1997, the Company invested more than $160 million to install and upgrade S0 2 and NO,. emission control equipment at its Mt. Storm and Possum Point power stations. Capital expenditures related to Clean Air Act compli-ance over the next five years are projected to be approximately $40 million. Changes in the regulatory environment, avail-ability of allowances, and emissions control technology could substantially impact the timing and magnitude of compliance expenditures.

In November 1997, the EPA proposed new requirements for 22 states, including North Carolina, Virginia and West Vir-ginia, to reduce and cap emissions of NO,.. The EPA will issue a final rule by September 1998. Although the proposal allows each state to determine how to achieve the required reduction in emissions, the caps were calculated based on emission lim-its for utility boilers. If the states in which Virginia Power operates choose to impose this limit, major additional emission ontrol equipment, with attendant significant capital and operating costs, could be required.

21

Global Climate Change In 1993, the United Nation's Global Warming Treaty became effective. The objective of the treatx is the stabilization of greenhouse gas concentrations at a level that would prevent man-made emissions from interfering with the climate sys-tem.

As a continuation of the effort to limit man-made greenhouse emissions, an international Protocol was formulated on December JO, 1997, in Kyoto, Japan. This Protocol calls for the United States to reduce greenhouse emissions by 7 percent from 1990 baseline levels by the period 2008-2012. The Protocol will not constitute a binding commitment unless submit-ted to and approved by the United States Senate. Emission reductions of the magnitude included in the Protocol, if adopted, would likely result in a substan_tial financial impact on companies that consume or produce fossil fuel-derived electric power, including Virginia Power.

Recently Issued Accounting Standards During 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income," and SFAS No. 131, "Disclosures about Segments of an Enterprise

• and Related Infonnation." Each of these statements is effective for fiscal years beginning after December 15, i'997. At this time, the Company does not expect the implementation of these standards to have a material impact on its results of opera-tions or financial position.

Year 2000 Compliance Virginia Power is taking an aggressive approach regarding computer issues associated with the onset of the new millenium - specifically, the impact of the*possible failure of computer systems and computer-driven equipment due to the rollover to the year 2000. The year.2000 problem is pervasive and complex as virtually every computer operation could be affected in some way by the rollover of the two-digit year value from 99 to 00. The issue is whether computer systems will properly recognize date-sensitive information when the year changes to 2000. Systems that do not properly recognize such information could generate erroneous data or fail.

If not properly addressed, the year 2000 computer problem could result in failures in computer systems in the Com-pany and the computer systems of third parties with which the Company transacts business. Such failures of the Company's or third parties' computer systems could have a material impact on the Company's ability to conduct business.

a Since January 1997, the Company has organized formal year 2000 project team to identify, correct or reprogram and test its systems for year 2000 compliance. At this time, the project team .has completed its preliminary assessment. Based on the team's evaluation, the costs of testing and conversion of system applications are projected to be within the range of

$30 million to $So** million. The range is a function of our ongoing evaluation as to whether certain systems and equipment will be corrected or replaced, which is dependent on information yet to be obtained from suppliers and other external sources.

Maintenance or modification costs will be expensed as incurred, while the costs of new software and hardware will be capi-talized and amortized 'over the asset's useful life.

At this time, Virginia Power is actively pursuing solutions to its year 2000-related computer problems in order to ensure that foreseeable situations related to Company computer systems are effectively addressed. The Company cannot estimate or predict the potential adverse consequences, if any, that could result from a third party's failure to effectively address this

.issue.

Market Rate Sensitive Instruments and Risk Management Virginia Power is subject to market risk as a result of its use of various financial instruments and derivative commod-ity instruments. Interest rate risk generally is associated with the Company's outstanding debt, preferred stock and trust-issued securities. The Company also is exposed to interest rate risk as well as equity price risk as a result of its nuclear decommissioning trust investmenLc; in debt and equity securities.

The Company's wholesale power group is involved in trading activities which use derivative commodity instruments.

However, the fair value of such instruments at December 31, 1997, is not material to the Company's financial position. Also, the potential near term losses in future earnings. fair values, or cash flows, resulting from reasonably possible near term changes in market prices for such instruments are not anticipated to be material to the Company's results of operations, financial position or cash flows.

22

The following analysis does not include the price risks associated with the nonfinancial assets and liabilities of utility operations, including underlying fuel requirements.

Interest-rate risk Virginia Power uses both fixed rate and variable rate debt and preferred securities as sources of capital. The following table presents the financial instruments that are held or issued by the Company at December .31, 1997., and are sensitive to interest rate changes in some way. Weighted average variable rates are based on implied forward rates derived from appro-priate annual spot rate observations as of December 31, 1997.

Expected Maturity Date Fair 1998 1999 2000 2001 2002 *

• Thereafter Total Value (Millions of Dollars, Except Percentages)

ASSETS Nuclear decommissioning trust investments ............... : ....... . $ 17.7 $ 5.3 $ 2.1 $ 7.(;' $ :'3.1' $ 165.0 $ 200.3 $ 190.7 Average interest rate (]) ............ . 5.5% 5.5% 5.5% 5.5% 5.5% 5.5%

LIABILITIES - Fixed rate Mortgage bonds .......................... . 225.0 100.0 135.0 100.0 255.0 2,009.5 2,824.5 2,937.7 Average interest rate *************:**** 6.7% 8.9% 5.9% 6.0% 4.5% 7.6%

Medium term notes ...................... . 108.5 221.0 60.5 60.6 60.0 40.5 551.1 573.7 Average interest rate ................. . 7.6% 8.5% 9.7% 8.4% 7.6% 9.0%

Tax-exempt financing ................... . 10.0 10.0 10.4 Average interest rate ................. . 5.2%

Short-term debt ........................... . 226.2 226.2 226.2 Average interest rate .................. . 5.9%

Preferred stock, subject to mandatory redemption ................... . 180.0 180.0 186.6 Average dividend rate ............... . 6.2%

Mandatorily redeemable trust-issued preferred securities .................................... . 135.0 135.0 137.7 Average dividend rate ............... . 8.1%

LIABILIDES - Variable rate Tax-exempt financing (2) .............. . 488.6 488.6 488.6 I

Average interest rate ................. . 4.1%

(]) Rates are based on average yield for entire portfolio at December 31, 1997.

(2) Interest rates on the tax-exempt bonds are based on short-term, tax-exempt market rates and are reset for periods of one to 270 days in length. The Company has the option to convert these bonds to fixed rate securities upon 40 days writ-ten notice. See Note H to the CONSOLIDATED FINANCIAL STATEMENTS.

Equity price risk The following table presents a description of marketable equity securities held by the Company at December 31, 1997.

As prescribed by Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities," these securities are reported on the balance sheet at fair value.

Fair Cost Value (Millions of Dollars)

Nuclear decommissioning trust investments $ 219.4 $ .360.4 23

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

Report of Management . . . . . . . . . . . . . . . . . .......................... .. . . . . .. . . . . . .. . . . . . . . . . . . . . . . . . .. . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Report of Independent Auditors .. . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . 26 Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995 ................................................................................................... 27 Consolidated Balance Sheets at December 31, 1997 and 1996 . . . . . . . . . . .. . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . 28 Consolidated Statements of Earnings Reinvested in Business for the years ended December 31, 1997, 1996 and 1995 ................................................................................................... 30 Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995 ................................................................................................... 31 Notes to Consolidated Financial Statements ........................................................................................... 32 24

REPORT OF MANAGEMENT The Company's management is responsible for all information and representations contained in the Consolidated Finan-ial Statements and other sections of the Company's annual report on Form I 0-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.

Management maintains a system of internal accounting controls designed to provide reasonable assurance, at a reason-able cost, that the Company's assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control and, therefore, cannot provide absolute assurance that the objectives of the estab-lished 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 1997 the system of internal control was adequate to accomplish the intended objective.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by the Board of Directors. Their audits were conducted in accordance with generally accepted auditing stan-dards and included a review of the Company's accounting systems, procedures and internal controls, and the performance of tests and other auditing procedures sufficient to *provide reasonable assurance that the Consolidated Financial Statements are not materially misleading and do not contain material errors.

The Audit Committee of the Board of Directors, composed entirely of directors who are not officers or employees of the Company, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters and to ensure that each is properly dis.charging its responsibili-ties. 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 con-ucted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected the Company's Code of Ethics, which is distributed throughout the Company. The Code of Ethics addresses, among other

• ngs, 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 Norman Askew M. S. Bolton, Jr.

President and Controller and Chief Executive Principal Accounting Officer Officer 25

REPORT OF INDEPENDENT AUDITORS To the Board of Directors of Virginia Electric and Power Company:

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the Company) as of December 31, 1997 and 1996, and the related consolidated statements of income, earnings reinvested in business, and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstate-ment. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial state-ments. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP Richmond, Virginia February 9, 1998 26

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1997 1996 1995 (Millions)

Revenues:

Electric service ............................................................................................. . $4,239.0 $4,210.2 $4,294.1 Other ........................................................................................................... . 840.0 210.7 57.8 Total ........................................................................................................ . 5,079.0 4,420.9 4,351.9 Expenses: ........................................................................................................ .

• Fuel, net ...................................................................................................... . 1,620.7 1,016.6 1,009.7 Purchased power capacity, net ......................................................................... . 717.5 700.6 688.4 Operations and maintenance ................................... :........................................ . 812.7 803.1 805.6 Depreciation and amortization ......................................................................... . 549.9 502.0 469.J Restructuring ................................................................................................ . 18.4 64.9 117.9 Accelerated cost recovery ............................................................................... . 38.4 26.7 Amortization of terminated construction project costs ......................................... . 34.4 34.4 34.4 Taxes* other than income .............................. .'.... : ............................................. . 267.7 262.6 254.9 Total ........................................................................................................ . 4,059.7 3.410.9 3,380.0 Income from operations ..................................................................................... . 1,019.3 1,010.0 971.9 Other income ................................................................................................... . 14.2 6.8 10.0 Income before interest and income taxes 1,033.5 1,016.8 981.9 Interest and related charges:

... Interest expense, net ...................................................................................... . 304.2 308.4 317.9 Distributions - preferred securities of subsidiary trust ........................................ . 10.9 10.9 3.7 Total ......... : .............................................................................................. . 315.1 319.3 321.6 Income before income taxes ............................................................................... . 718.4 697.5 660.3 Income* taxes .................................................................................................... . 249.3 240.2 227.5

.Net income ...................................................................................................... . 469.1 457.3 432.8 Preferred dividends ........................................................................................... . 35.7 35.5 44.1 Balance available for Common Stock .................................................................. . $ 433.4 $ 421.8 $ 388.7 The accompanying notes are an integral part of the financial statements.

27

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Assets At December 31, 1997 1996 (Millions of Dollars)

CURRENT ASSETS:

Cash and cash equivalents ........................................................................................... . $ 36.0 $ 47.9 Accounts receivable:

Customers (less allowance for doubtful accounts of $2.4 in 1997 and 1996) ..................... . 462.4 354.8 Other .................................................................................................................... . 108.0 80.4 Accrued unbilled revenues ............................................. : ............................................. . 245.2 180.3 Materials and supplies at average cost or less:

Plant and general .................................................................................................... . 145.2 148.7 Fossil fuel .............................................................................................................. . 67.4 76.8 Other ........................................................................................................................ . 134.7 107.0 Total current assets .... ; ......................................................................................... . 1,198.9 . 995.9 INVESTMENTS:

Nuclear decommissioning trust funds ............................................................................. . 569.1 443.3 Other ........................................................................................................................ . 38.3 34.5 Total net investments ............................................................................................... . 607.4 477.8 DEFERRED DEBITS AND OTHER ASSETS:

Regulatory assets:

Deferred capacity expenses ....................................................................................... . 47.3 6.1 Other .................................................................................................................... . 729.3 767.8 Unamortized debt issuance costs ................................................................................... . 24.2 24.7 Other ......................................................................................................................... . 127.1 121.9 Total deferred debits and other assets ......................................................................... . 927.9 920.5 UTILITY PLANT:

Plant (includes plant under construction of $240.9 in 1997 and $180. 1 in 1996) ................... . 14,794.2 14,506.8 Less accumulated depreciation ........................................................... *.* ......................... . 5.724.3 5,218.3 9,069.9 9,288.5 Nuclear fuel (less accumulated amortization of $705.0 in 1997 and $698.5 in 1996) ............. . 149.3 145.3 Total net utility plant ............................................................................................... . 9,219.2 9,433.8 Total assets ............................................................................................................ . $11,953.4 $11,828.0 The accompanying notes are an integral part of the financial stat.ements.

28

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Liabilities and Shareholders' Equity At December 31, 1997 1996 (Millions of Dollars)

CURRENT LIABILITIES:

Securities due within one year ..................................................................................... . $ 333.5 $ 311.3 Short-tenn debt ................ :................................................. : ...................................... . 226.2 312.4

_Accounts payable, trade .............................................................................................. . 452.0 368.5

• customer deposits ............................... : ..................................................................... . 44.6 50.0 Payrolls accrued ........................................................................................................ . 77.5 73.2 Severance costs accrued .............................................................................................. . 29.7 50.2 Interest accrued ......................................................................................................... . 95.1 95.3 Other ....................................................................................................................... . 161.6 126.1 Total current liabilities ............................................................................................ . 1,420.2 1.387.0 LONG-TERM DEBT .......................................... : .......................................................... . 3,514.6 3,579.4 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred income taxes ............................................................................. . 1,607.0 1,565.2 Deferred investment tax credits ................................................................................... . 238.4 255.3 Deferred fuel expenses ....................................................................... ; ....................... . 12.8 3.3 Other ....................................................................................................................... . 220.3 151.1 Total deferred credits and other liabilities ............................................................... . 2,078.5 1,974.9 COMMITMENTS AND CONTINGENCIES (See Note Q)

COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST* .................................................................... . 135.0 135.0 PREFERRED STOCK:

Preferred stock subject to mandatory redemption ............................................................ . 180.0 180.0 Preferred stock not subject to mandatory redemption ...................................................... . 509.0 509.0

,?

COMMON STOCKHOLDER'S EQUITY:

Common Stock, no par, 300,000 shares authorized, 171,484 shares outstanding at December 31, 1997 and 1996 ............................................................. *.. 2,737.4 2,737.4 Other paid-in capital .................................................................................................. . 16.9 16.9 Earnings reinvested in business ................... : ............................................................... . 1,361.8 1.308.4 Total common stockholder's equity ........................................................................... . 4,116.1 4.062.7 Total liabilities and shareholders' equity .................................................................... . $11.953.4 $11.828.0

(*) As described in Note I to CONSOLIDATED FINANCIAL STATEMENTS, the 8.05% Junior Subordinated Notes total-ling $139.2 million principal amount constitute 100% of the Trust's assets.

The accompanying notes are.an integral part of the financial statements.

I 29

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF EARNINGS REINVESTED IN BUSINESS For the Years Ended December 31, 1997 1996 1995 (Millions)

Balance at beginning of year ..................... :..................................................... .. $1,308.4 $1,272.5 $1,277.8 Net income ................................................................................................... .. 469.1 457.3 432.8 Total ......................................................................................................... . 1,777.5 1,729.8 1,710.6 Cash dividends:

Preferred stock subject to mandatory redemption .............................................. . 11.1 11.1 13.5 Preferred stock not subject to mandatory redemption ........................................ . 24.7 24.5 30.8 Common Stock ........................................................................................... . 379.9 385.8 394.3 Total dividends ........................................................................................ . 415.7 421.4 438.6 Other additions (deductions), net ...................................................................... .. 0.5 Balance at end of year ..................................................................................... . $1,361.8 $1,308.4 $1,272.5 The accompanying notes are ari integral part of the financial statements.

30

VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1997 1996 1995 (Millions)

Cash Flow From Operating Activities:

Net income .............................................. : ...................................................... . $ 469.1 $ 457.3 $ 432.8 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization ........................................................................... . 664.7 616.0 585.1

• Deferred income taxes .................................................................................... . 36.1 69.1 I 1.8 Deferred investment tax credits ......................................................................... . (I 6.9) (I 6.9) (I 6.9)

Non cash return on terminated construction project costs - pretax .............................. .. (4.2) (6.4) (8.4)

Deferred. fuel expenses, net .............................................................................. . 9.6 (54.4) 6.2 Deferred capacity expenses .............................................................................. . (41.2) (9.2) 6.4 Restructuring ............................................................................................... . 12.5 29.6 9*6.2 Accelerated cost recovery ................................................................................ . 38.4 26.7 Changes in:

Accounts receivable .................................................................................... . (135.2) (11.3) (54.3)

Accrued unbilled revenues ............................................................................ . (64.9) 17.6 (27.7)

Materials and supplies ............ *............... *................................................. *..... . 12.9 -6.0 61.1 Accounts payable, trade .............................................................................. .. 82.8 57.8 (8.9)

Accrued expenses ....................................................................................... . (13.9) (62.6) 44.7 Other ......................................................................................................... . 41.0 (4.0) (2.7)

. Net Cash Flow From Operating Activities .............. _. ................................................... . 1,090.8 1,115.3 1,125.4 Cash Flow From (To) Financing Activities:

Issuance of long-term debt .................................................................................. . 270.0 24.5 240.0 Issuance of preferred securities of subsidiary trust ..................................................... . 135.0 Issuance (Repayment) of short-term debt ................................................................. . (86.2) 143.4 169.0 Repayment of long-term debt and preferred stock ...................................................... . (3 l 1.3) (284. l) (439.0)

Common Stock dividend payments ........................................................................ . (379.9) (385.8) (394.3)

Preferred stock dividend payments ........................................................................ . (35.7) (35.6) (44.3)

Distribution-preferred securities of subsidiary trust ..................................................... . (10.9) (I 0.9) (3.7)

Other ............................................................................................................ . (2.6) _ (2.3) (10.0)

Net Cash Flow To Financing Activities . .".................................................................... . (556.6) (550.8) (347.3)

Cash Flow Used In Investing Activities:

Utility plant expenditures (excluding AFC - other funds) ............................................ . (397.0) (393.8) (519.9)

Nuclear fuel (excluding AFC - other funds) ............................................................ . (84.8) (90.2) (57.6)

Nuclear decommissioning contributions .................................................................. . (36.2) (36.2) (28.5)

Sale of accounts receivable, net ............................................................................ . (160.0)

Purchase of assets ............................................................................................ . (19.8) (13.7)

Other ................. .- .......................................................................................... . (8.3) (12.5) ( 11.1)

Net Cash Flow Used In Investing Activities ................................................................ . (546.1) (546.4) (777.1)

Increase in cash and cash equivalents ....................................................................... .. (11.9) 18.1 1.0 Cash and cash equivalents at beginning of year ............................................................ . 47.9 29.8 28.8 Cash and cash equivalents at end of year ................................................................... . $ 36.0 $ 47.9 $ 29.8 Cash paid during the year for:

Interest (reduced for the cost of borrowed funds capitalized as AFC) ............................... . $ 277.1 $ 295.4 $ 314.5 Income taxes ................................................................................................... . 230.0 216.1 215.8 The accompanying notes are an integral part of the financial statements.

31

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

General Virginia Electric and Pqwer Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives, munici-palities, power marketers and other utilities. The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. The Company has organized a wholesale power group to engage in off-system wholesale purchases and sales of electricity and purchases and sales of natural gas, and that group is devel-oping trading relationships beyond the geographic limits of Virginia Power's retail service territory. Within this document, the terms "Virginia Power" and the "Company" shall refer to the entirety of Virginia Electric and Power Company, includ-ing, without limitation, its Virginia and North Carolina operations, and all of its subsidiaries.

The Company's accounting practices are generally prescribed by the Uniform System of Accounts promulgated by the regulatory commissions having jurisdiction and are in accordance with generally accepted accounting principles applicable to regulated enterprises. The financial statements include the accounts of the Company and its subsidiaries, with all signifi-cant intercompany transactions and accounts being eliminated on consolidation.

The Company is a wholly-owned subsidiary of Dominion Resources, Inc., a Virginia corporation.

The preparation of financial statements in conformity with generally accepted accounting principles requires manage-ment to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenues Revenues are recorded on the basis of services rendered, commodities delivered or contracts settled.

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 of1additions and replacements is charged to the appropriate utility plant account, except that the cost of minor additions and replacements, as provided in the Uniform System of Accounts, is charged to maintenance expense.

Depreciation and Amortization Depreciation of utility plant (other than nuclear fuel) is computed on the straight-line method based on projected use-ful service lives. The cost of depreciable utility plant retired and the cost of removal, less salvage, are charged to accumu-lated depreciation. The provision for depreciation provides for the recovery of the cost of assets including the estimated cost of removal, net of salvage, and is based on the weighted average depreciable plant using a rate of3.2 percent for 1997, 1996 and 1995.

• Operating expenses include amortization of nuclear fuel, which is provided on a unit of production basis sufficient to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs ..

Federal Income Taxes The Company files a consolidated federal income tax return with Dominion Resources.

Deferred investment tax credits are being amortized over the service lives of the property giving rise to such credits.

32

Allowance for Funds Used During Construction The applicable regulatory Uniform System of Accounts defines AFC as the cost during the construction period of bor-owed funds used for construction purposes and a reasonable rate on other funds when so used.

The pretax AFC rates for 1997, 1996 and 1995 were 6.6 percent, 8.1 percent and 8.9 percent, respectively. No AFC is accrued for approximately 83 percent of the Company's construction work in progress, which is instead included in rate base. A cash return is currently collected on the portion of construction work in progress included in rate base.

Deferred Capacity and Deferred Fuel Expense Approximately 80 percent of capacity expenses and 90 percent of fuel expenses incurred as part of providing regulated electric service are subject to deferral accounting. The difference between reasonably incurred actual expenses and the level of.expenses included in current rates is deferred and matched against future revenues.

Amortization of Debt Issuance Costs The Company defers and amortizes any expenses incurred in the issuance of long-term debt, including premiums and discounts associated with such debt, over the lives of the respective issues. Any gains or losses resulting from the refinanc-ing of debt are also deferred and amortized over the lives of the new issues of long-term debt as permitted by the appro-priate regulatory jurisdictions. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.

Cash and Cash Equivalents Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 1997 and 1996, the Company's accounts payable included the net effect of checks outstanding but not yet presented for payment of $55.8 million and $64.8 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand and temporary investments purchased with an initial maturity of three months or less.

ommodity Contracts The trading activities of Virginia Power's wholesale power group include fixed-price forward contracts and the pur-chase and sale of over-the-counter options that require physical delivery of the underlying commodity. Furthermore, in order to manage price risk associated with natural gas sales and fuel requirements for the utility operations, the Company uses exchange-for-physical contracts, basis swaps, NYMEX natural gas futures contracts, as well as options on natural gas futures contracts.

\

• . Options, exchange-for-physical contracts, basis swaps and futures contracts are marked to market with resulting gains and losses reported in earnings, unless such instruments are designated as hedges for accounting purposes. Fixed price for-ward contracts, initiated for trading purposes, also are marked to market with resulting gains and losses reported in earnings.

For exchange-for-physical contracts, basis swaps, fixed price forward contracts and options which require physical delivery of the underlying commodity, market value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Futures contracts and options on futures contracts are marked to market based on closing exchange prices. No contracts were designated as hedges during 1997.

Purchased options and options sold are reported in Deferred Debits and Other Assets - Other and in Deferred Credits and Other Liabilities - Other, respectively, until exercise or expiration. Gains and losses resulting from marking positions to market are reported in Other Income. Net gains and losses resulting from futures contracts and options on futures con-tracts and settlement of basis swaps are included in Fuel, Net. Amortization of option premiums associated with sales and purchases are included in Revenues - Other and Fuel, Net, respectively. Cash flows from trading activities are reported in Net Cash Flow from Operating Activities.

Reclassification Certain amounts in the 1996 and 1995 financial statements have been reclassified to conform to the 1997 presentation.

33

B. Income Taxes:

Details of income tax expense are as follows:

Years 1997 1996 1995 (Millions)

Current expense:

Federal .................................................................................... . $222.1 $185.6 $230.6 State ........................................................................................ . 8.6 2.4 2.1 230.7 188.0 232.7 Deferred expense:

Utility plant differences .............................................................. . 41.3 65.4 48.9 Deferred fuel and capacity .......................................................... . 11.0 22.3 (6.0)

Debt issuance costs .................................................................... . (2.1) (2.8) 1.3 Terminated construction project costs ........................................... . (5.8) (5.1) (4.4)

Other ....................................................................................... . ~ (10.7) __@J_)

35.5 _fil 11.7 Net deferred investment tax credits-amortization ................................ . _fil2) ~) ~

Total income tax expense ............................................................... . $249.3 $240.2 * $227.5 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 1997 1996 1995 (Millions)

Federal income tax expense at statutory rate of 35 percent .................. . $251.4 $244.l $231.1 Increases (decreases) resulting from:

Utility plant differences .............................................................. . 7.7 5.7 3.2 Ratable amortization of investment tax credits ............................... . (16.9) (16.9) (16.9)

Terminated construction project costs ..,. ........................................ . 5.0 5.0 5.0 State income tax, net of federal tax benefit. .................................... . 4.9 2.4 2.2 Other, net .................................................. :.............................. . ____.G_!) __fill) 2.9

__QJ) ~) ~

Total income tax expense ................................. :............................. . $249.3 $240.2 $227.5 Effective tax rate ..................................*........................................ 34.7% 34.4% 34.5%

The Company's net accumulated deferred income taxes consist of the following:

Years 1997 1996 (Millions)

Deferred income .tax assets:

Investment tax credits ................................................................. *........... . $ 84.4 $ 90.3 Deferred income tax liabilities:

Utility plant differences ........................................................................... . 1,479.8 1,440.5 Terminated construction project costs ....................................................... . 8.6 14.4 Income taxes recoverable through future rates ................................... , ........ . 169.5 168.8 Other ................................................................................................... . 33.5 31.8 Total deferred income tax liabilities ............................................................. . 1,691.4 1,655.5 Total net accumulated deferred income taxes ................................................. . $1.607.0 $1,565.2 34

C. Nuclear Operations:

ecommissioning When the Company's nuclear units cease operations, we are obligated to decontaminate or remove radioactive contami-nants so that the property will not require NRC oversight. This phase of a nuclear power plant's life cycle is termed decom-missioning. While the units are operating, we are collecting from ratepayers amounts that, when combined with investment earnings, will be used to fund this future obligation.

The amount being accrued for decommissioning is equal to the amount being collected from ratepayers and is included in Depreciation and Amortization Expense. The decommissioning collections were $45.8 million, $36.2 million and $28.5 mil-lion in 1997, 1996 and 1995, respectively. These dollars are deposited into external trusts through which the funds are invested.

Net earnings of the trusts' investments are included in Other Income in the Company's Consolidated Statements of Income. In 1997, 1996 and 1995, respectively, net earnings were $20.5 million, $16.0 million and $15.9 million. The accre-tion of the decommissioning obligation is equal to the trusts' net earnings and also is recorded in Other Income. Thus, the net impact of the trusts on Other Income is zero.

The accumulated provision for decommissioning, which is included in Utility Plant Accumulated Depreciation in the Company's Consolidated Balance Sheets, includes the accrued expense and accretion described above and any unrealized gains and losses on the trusts' investments. At December 31, 1997, the net unrealized gains were $149.5 million, which is an increase of $69.0 over the December 31, 1996, amount of $80.5 million. The total accumulated provision for decommis-sioning at December 31, 1997, was $578.7 million, including $9.6 million accrued in 1997 and deposited to the trusts in January 1998. The provision was $443.3 million at December 31, 1996.

The total estimated cost to decommission the Company's four nuclear units is $1 billion based upon a site-specific study that was completed in 1994. We plan to update this estimate in 1998. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. This method assumes that dismantlement and other decom-missioning activities will begin shortly after cessation of operations, which under current operating licenses will begin in 012 as detailed in the table below.

Surrv North Anna Total Unit I Unit 2 Unit I Unit 2 All Units NRC license expiration year 2012 2013 2018 2020 (Millions)

Current cost estimate (1994 dollars) ............................................. . $272.4 $274.0 $247.0 $253.6 $1,047.0 Funds in external trusts at 12/31 /97 ............................................ .. 156.5 151.8 134.2 126.6 569.1 1997 contribution to external trusts ............................................. .. 10.6 10.8 7.6 7.2 36.2 The Financial Accounting Standards Board (FASB) is reviewing the accounting for nuclear plant decommissioning. In 1996, the FASB tentatively determined that the estimated cost of decommissioning should be reported as a liability rather than as accumulated depreciation and that a substantial portion of the decommissioning obligation should be recognized ear-lier in the operating life of the nuclear unit. If the industry's accounting were changed to reflect FASB's tentative proposal, then the annual provisions for nuclear decommissioning would increa~e. During its deliberations, the FASB expanded the scope of the project to include similar unavoidable obligations to perform closure and post-closure activities for non-nuclear power plants. Therefore, any forthcoming standard also may change industry plant depreciation practices. Any impact related to other Company assets cannot be determined at this time.

Insurance The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $8.9 billion for a single nuclear incident. The Price-Anderson Amendments Act of 1988 allows for an inflationary provision adjustment every five years. The Company has purchased $200 million of coverage from the commercial insurance pools with the remainder pro-vided through a mandatory industry risk sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $81.7 million (including a 3 percent insurance premium tax for Virginia) for each of its four licensed reactors not to exceed $ I 0.3 million (including a 3 percent insurance premium tax for irginia) per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be sessed.

35

Nuclear liability coverage for claims made by nuclear workers first hired on or after January I, 1988, except those aris-ing out of an extraordinary nuclear occurrence. is provided under the Master Worker insurance program. (Those first hired into the nuclear industry prior to January l, 1988, are covered by the policy discussed above.) The aggregate limit of cov-erage for the industry is $400 million ($200 million policy limit with automatic reinstatements of an additional $200 mil-lion). The Company's maximum retrospective assessment is approximately $12.3 million (including a 3 percent insurance premium tax for Virginia).

The Company's current level of property insurance coverage ($2.55 billion for North Anna and $2.40 billion for Surry) exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total Joss. 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 Company's nuclear property insurance is provided by Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL), two mutual insurance companies, and is subject to retrospective premium assessments, in any policy year in which losses exceed the funds available to these insur-ance companies. The maximum assessment for the current policy period is $37 .0 million. Based on the severity of the inci-dent, the Boards of Directors of the Company's nuclear insurers have the discretion to lower the maximum retrospective premium assessment or eliminate either or both completely. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination, the Company has the finan-cial responsibility for these losses.

The Company purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Virginia Power is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period's maxi-mum assessment is $8.7 million.

As part owner of the North Anna Power Station, ODEC is responsible for its share of the nuclear decommissioning obligation and insurance premiums applicable to that station, including any retrospective premium assessments and any losses not covered by insurance.

D. Utility Plant:

Utility plant consisted of the following:

At December 31, 1997 1996 (Millions)

Production ***************************************** J.************************************************************** $ 7,684.2 $ 7,691.9 Transmission .................................................................................................... . 1,415.7 1,386.5 Distribution ..................................................................................................... . 4,559.2 4,385.4 Other .............................................................................................................. . 894.2 862.9 14,553.3 14,326.7 Construction work in progress ........................................................................... .. 240.9 180.1 Total ..................................................................................................... . $14,794.2 $14,506.8 36

E. Jointly Owned Plants:

The following information relates to the Company's proportionate share of jointly owned plants at December 31, 1997:

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

(Millions)

Utility plant in service ........................................................... . $1,072.9 $1,819.4 $533.3 Accumulated depreciation ..................................................... .. 229.1 819.2 26.3 Nuclear fuel ......................................................................... . 403.6 Accumulated amortization of nuclear fuel ................................ .. 383.4 Construction work in progress ............................................... .. .1 61.2 1.1 The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interest. The Company's share of operating costs is classified in the appropriate operating expense (fuel, operations and maintenance, depreciation, taxes, etc.) in the Consoli-dated Statements of Income.

F. Regulatory Assets-Other Certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets and are recognized in income as the related amounts are included in rates and recovered from customers. The Company's regulatory assets included the following:

At December 31, 1997 1996 (Millions) ncome taxes recoverable through future rates ........................................................... . $478.9 $477.0 ost of decommissioning DOE uranium enrichment facilities ..................................... .. 67.6 73.5 Deferred losses on reacquired debt, net ................................................................... .. 85.4 91.5 North Anna Unit 3 project termination costs ............................................................. . 42.3 73.l Other .................................................................................................................. . 55.1 52.7 Total ....................... .' ............................................................................................ * $729.3 $767.8

\

Income taxes recoverable through future rates represent principally the tax effect of depreciation differences not nor-malized in earlier years for ratemaking purposes. These amounts are amortized as the related temporary differences reverse.

The costs of decommissioning the Department of Energy's (DOE) uranium enrichment facilities have been deferred and represent the unamortized portion of Virginia Power's required contributions to a fund for decommissioning and decontami-nating the DOE's uranium enrichment facilities. Virginia Power is making such contributions over a 15-year period with escalation for inflation. These costs are being recovered in fuel rates.

Losses or gains on reacquired debt are deferred and amortized over the lives of the new issues of Jong-term debt. Gains ,

or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.

The construction of North Anna Unit 3 was terminated in November 1982. All retail jurisdictions have permitted recov-ery of the incurred costs. For Virginia and FERC jurisdictional customers, the amounts deferred are being amortized from the date termination costs were first includible in rates.

The incurred costs underlying these regulatory assets may represent expenditures by the Company or may represent the recognition of liabilities that ultimately will be settled at some time in the future. For some of those regulatory assets rep-resenting past expenditures that are not included in the Company's rate base or used to adjust the Company's capital struc-ture, the Company is not allowed to earn a return on the unrecovered balance. Of the $729.3 *million of regulatory assets at ecember 31, 1997, approximately $57.7 million represent past expenditures that are effectively excluded from rate base by e Virginia State Corporation Commission which has primary jurisdiction over the Company's rates. However, of that mount $42.3 million represent the present value of amounts to be recovered through future rates for North Anna Unit 3 37

project termination costs, and thus reflect a reduction in the actual dollars to be recovered through future rates for the. time value of money. The Company does not earn a return on the remaining $15.4 million of regulatcry assets, effectively excluded from rate base, to be recovered over various recovery periods up to 21 years, depending on the nature of the deferred costs.

G. Leases:

Plant and property under capital leases included the following:

At December 31, 1997 1996 (Millions)

Office buildings (*) ............................................................................................... . $34.4 $34.4 Data processing equipment ..................................................................................... . 13.3 2.5 Total plant and property under capital leases ................................................... . 47.7 36.9 Less accumulated amortization ............................................................................... . 17.8 13.3 Net plant and property under capital leases ............................................................... . $29.9 $23.6

(*) The Company leases its principal office building from its parent, Dominion Resources. The capitalized cost of the prop-erty under that lease, net of accumulated amortization, represented $22 million and $23 million at December 31, 1997 and 1996, respectively. Rental payments for such lease were $3 million for each of the three years ended December 31, 1997, 1996 and 1995.

The Company is responsible for expenses in connection with the leases noted above, incl~ding maintenance .

. Future minimum lease payments under noncancellable capital leases and for operating leases that have initial or remain-ing lease terms in excess of one year as of December 31, 1997, are as follows:

Capital Operating Lea~cs Leases (Millions) 1998 ******************************************************************************************************************** $ 7.1 $11.4 1999 ******************************************************************************************************************** 6.4 9.9 2000 ******************************************************************************************************************** 4.3 7.1 2001 ********************************************************************************************************************* 3.2 3.9 2002 ******************************************************************************************************************** 3.0 3.2 After 2002 ........................................................................................................... . 16.7 22.9 Total_ future minimum lease payments ............................................ *.. *********************.**** $40.7 $58.4 Less interest element included above ............................................................... , ....... . 10.8 Present value of future minimum lease payments ....................................................... . $29.9 Rents on leases, which have been charged to operations expense, were $17.6 million, $16.5 million and $13.6 million for 1997, 1996 and 1995, respectively.

38

Long-term debt jncluded the following:

Al December 31, 1997 1996 (Millions)

First and Refunding Mortgage Bonds (1 ):

Series U, 5. l 25o/o, due 1997 ............................................................................ . $ 49.3 1992 Series B, 7 .25%, due 1997 ...................................................................... . 250.0 1988 Series A, 9.375%, due 1998 .................................................................... . $ 150.0 150.0 1992 Series F, 6.25%, due 1998 ....................................................................... . 75.0 75.0 1989 Series B, 8.875%, due 1999 .................................................................... . 100.0 100.0 1993 Series C, 5.875%, due 2000 .................................................................... . 135.0 135.0 Various series, 6.0-8%, due 2001-2004 ............................................................. . 805.0 805.0 Various series 6.75%-7.625%, due 2007 ............................................................ . 415.0 215.0 Various series, 5.45%-8.75%, due 2021-2025 ..................................................... . 1,144.5 1,144.5 Total First and Refunding Mortgage Bonds ................................................. . 2.824.5 2.923.8 Other long-term debt:

Term notes:

Fixed interest rate, 6.15%-10.00%, due 1997-2003 .......................................... . 551.1 503.1 Tax exempt financings (2):

Money Market Municipals, due 2007-2027(3) ................................................ . 488.6 488.6 Convertible interest rate,*due 2022 .:'. ............................................................. . 10.0 Total other long-term debt_ ........................................................................ . 1,049.7 991.7 3,874.2 3,915.5 Less amounts due within one year:

First and Refunding Mortgage Bonds ............................................................... . 225.0 299.3 Term notes ................................................................................................... . 108.5 12.0 Total amount due within one year ........ *..................................................... . 333.5 311.3 Less unamortized discount, net of premium ........................ :................................. . 26.1 24.8 Total long-term debt ............................................................................... :. $3,514.6 $3,579.4 (I) The First and Refunding Mortgage Bonds are secured by a mortgage lien on substantially all of the Company's property.

(2) Certain pollution control facilities at the Company's generating facilities have been pledged or conveyed to secure the financings.

(3) Interest rates vary based on short-term, tax-exempt market rates. For 1997 and 1996, the weighted average daily interest rates were 3.74 percent and 3.57 percent, respectively. Although these bonds are re-marketed within a one year period, they are classified as long-term debt because the Company intends to maintain the debt and they are supported by long-term bank commitments.

The following amounts of debt will mature during the next five years (in millions): 1998 - $333.5; 1999 - $321.0; 2000-$195.5; 2001 - $160.7; and 2002-$315.0 .

. I. Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust:

Virginia Power Capital Trust I (VP Capital Trust) was established as a subsidiary of the Company for the sole purpose of selling $135 million of Preferred Securities (5.4 million shares at $25 par) in 1995. The Company concurrently issued

$139.2 million of its 1995 Series A, 8.05% Junior Subordinated Notes (the Notes) in exchange for the $135 million realized from the sale of the Preferred Securities and $4.2 million of common securities of VP Capital Trust. The Preferred Securi-ties and the common securities represent the total beneficial ownership interest in the assets held by VP Capital Trust. The otes are the sole assets of VP Capital Trust. .

39

The Preferred Securities are subject to mandatory redemption upon repayment of the Notes at a liquidation amount of

$25 plus accrued and unpaid distributions, including interest. The Notes are due September 30, 2025. However, that date may be extended up to an additional ten years if certain conditions are satisfied.

J. Preferred Stock Subject to Mandatory Redemption:

The total number of authorized shares for all preferred stock (whether or not subject to mandatory redemption) is 10,000,000 shares. Upon involuntary liquidation, dissolution or winding-up of the Company, all presently outstanding pre-ferred stock is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.

There are two series of preferred stock subject to mandatory redemption outstanding as of December 31, 1997:

Issued and Outstanding Dhidend Shares

$5.58 400,000 Shares are non-callable prior to redemption at 3/1/2000

$6.35 1,400,000 Shares are non-callable prior to redemption at 9/1/2000 Total .............. . 1,800,000 There were no redemptions of preferred stock during 1997 or 1996. In 1995, the Company redeemed 417,319 shares of its $7 .30 dividend preferred stock subject to mandatory redemption.

K. Preferred Stock Not Subject to Mandatory Redemption:

Shown below are the series of preferred stock not subject to mandatory redemption that were outstanding as of Decem-ber 3 1, 1997.

Entitled per Share upon Liquidation Issued and And Thereafter to Outstanding Amounts Declining in Dividend Shares Amount Through Steps to

$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 7.05 ............................................................................ . 500,000 105.00 7/31/03 $100.00 after 7/31/13 6.98 ............................................................................ . 600,000 105.00 8/31/03 $100.00 after 8/31 /13 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 9/92, Series A (*) ................................................... . 500,000 100.00 MMP 9/92, Series B (*) .................................................. . 500,000 100.00 Total .............................................................................. 5.090,140

(*) Money Market Preferred (MMP) dividend rates are variable and are set every 49 days via an auction process. The com-bined weighted average rates for these series in 1997, 1996 and 1995, including fees for broker/dealer agreements, were 4.7 l percent, 4.48 percent and 4.93 percent, respectively.

In 1995, the Company redeemed 400,000 shares of its $7.45 dividend preferred stock not subject to mandatory redemp-tion and 450,000 shares of its $7 .20 dividend preferred stock not subject to mandatory redemption.

L. Common Stock:

There were no changes in the number of authorized and outstanding shares of the Company's Common Stock during the three years ended December 31, 1997.

40

M. Short-term Debt:

The Company's commercial paper program has a maximum borrowing capacity of $500 million. It is supported by two credit facilities. One is a $300 million, five-year credit facility that was effective on June 7, 1996, and expires on June 7, 2001. The other is a $200 million credit facility that originated on June 7, 1996, with an initial term of 364 days and pro-visions for subsequent 364-day extensions. It was renewed on June 6, 1997, for 364 days.

The total amount of commercial paper outstanding as of December 31, 1997, was $226.2 million with a weighted aver-age interest rate of 5.88 percent. This represents a decrease of $86.2 million from the December 31, 1996, balance of $312.4 million and a weighted average interest rate of 5.51 percent.

N. Retirement Plan, Postretirement Benefits and Other Benefits:

Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Retirement Plan The Company participates in the Dominion Resources, Inc. Retirement Plan (the Retirement Plan), a defined benefit pension plan. The benefits are based on years of service and average base compensation over the consecutive 60-month period in which pay is highest.

The Company's pension plan expenses were $20.6 million, $24.8 million and $20.3 million for 1997, 1996 and 1995, respectively, and the amounts funded by the Company were $27.0 million, $28.4 million and $42.7 million in 1997, 1996 and 1995, respectively.

Postretirement Benefits 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 c.ompleted at least. 10 years of service after attaining age 45. These and similar benefits for active employees are provided through insurance companies.

Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time o time in the past, benefits have changed, and some of these changes have reduced benefits.

Net periodic postretirement benefit expense was as follows:

Year Ended December 31, 1997 1996 (Millions) 1 Service cost ..................................................................................................... . $ 12.3 $ 12.1 Interest cost ..................................................................................................... . 25.1 23.9 Return on plan assets ........................................................................................ . (25.3) . (16.6)

Amortization of transition obligation .................................................................... . 12.1 12.1 Net amortization and deferral ............................................................................. . 13.4 7.1 Net periodic postretirement benefit expense .......................................................... . $ 37.6 $ 38.6 41

The following table sets forth the funded status of the plan:

At December 31, 1997 1996 (Millions)

Fair value of plan assets ................................................................................. $ 176.6 $ 133.0 Accumulated postretirement benefit obligation:

Retirees ................................................................................................... . $ 224.5 $ 201.7 Active plan participants ............................................................................. .. 136.3 122.2 Accumulated postretirement benefit obligation ............................................ . 360.8 323.9 Accumulated postretirement benefit obligation in excess of plan assets .......... .. (184.2) (190.9)

Unrecognized transition obligation ................................................................... . 180.8 192.8 Unrecognized net experience (gain)/loss ........................................................... . (1.8) (3.6)

Accrued postretirement benefit cost ................................................................. . $ (5.2) $ (1.7)

A one percent increase in the health care cost trend rate would result in an increase of $5.0 million in the service and interest cost components and a $39.5 million increase in the accumulated postretirement benefit obligation.

Significant assumptions used in determining the postretirement benefit obligation were:

1997 1996 Discount rates ................................................... : ... . 7.75% 8%

Assumed return on plan assets ................................ . 9% 9%

Medical cost trend rate .......................................... . 6% for 1st year 7% for 1st year 5% for 2nd year 6% for 2nd year Scaling down to 4.75% Scaling down to 4.75%

beginning in the year beginning in the year 2000 2000 The Company is recovering these costs in rates on an accrual basis in all material respects, in all jurisdictions. The funds being collected for Other Postretirement Benefits (OPEB) in rates, in excess of OPEB benefits actually paid during the year, are contributed to external benefit trusts under the Company's current funding policy (see Future Issues -

Competition -Exposure to Potentially Stranded Costs under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINAN-CIAL CONDIDON AND RESULTS OF OPERATIONS).

0. Restructuring:

The Company announced the implementation phase of its Vision 2000 program in March 1995. During this phase, the Company began reviewing operations with the objective of outsourcing services where economical and appropriate and re-engineering the remaining functions to streamline operations. The re-engineering process has resulted in outsourcing, decentralization, reorganization and downsizing for portions of the Company's operations. As part of this process, the Com-pany has reevaluated its utilization of capital resources in the operations of the Company to identify further opportunities for operational efficiencies through outsourcing or re-engineering of its processes.

Restructuring charges of $18.4 million, $64.9 million, and $117 .9 million in 1997, 1996 and 1995, respectively, included severance costs, purchased power contract restructuring and negotiated settlement costs, capital project cancellation costs, and other costs incurred directly as a result of the Vision 2000 initiatives. While the Company may incur additional charges for severance in 1998, the amounts are not expected to be significant.

Employee Severance In 1995, the Company established a comprehensive involuntary severance package for salaried employees who may no longer be employed as a result of these initiatives. The Company is recognizing the cost associated with employee termi-nations in accordance with Emerging Issues Task Force Consensus No. 94-3 as management identifies the positions to be eliminated. Severance payments will be made over a period not to exceed twenty months. Through December 31, 1997, management had identified 1,977 po~itions to be eliminated. The recognition of severance costs resulted in charges to opera-tions in 1997, 1996 and 1995 of $12.5 million, $49.2 million and $51.2 million, respectively. At December 31, 1997, 1,619 employees had been terminated and severance payments totaling $74 million had been paid. The Company estimates that 42

these staffing reductions will result in annual savings, in the range of $80 million to $90 million. However, such savings are eing offset by salary increases, outsourcing costs and increased payroll costs associated with staffing for growth opportu-ties.

Purchased Power Contracts In an effort to minimize its exposure to potential stranded investment, the Company is evaluating its long-term pur-chased power contracts and negotiating modifications to their terms, including cancellations, where it is determined to be economically advantageous to do so. The Company has also negotiated settlements with several other parties to terminate their rights to sell power to the Company. The cost of contract modifications, contract cancellations and negotiated settle-ments was $3.8 million, $7.8 million and $8.1 million in 1997, 1996 and 1995, respectively. Using contract terms, estimated quantities of power that would have otherwise been delivered and other relevant factors at the time of each transaction, the Company estimated that its annual future purchased power costs, including energy payments, would be reduced by up to

$0.8 million, $5.8 million and $147.0 million for the 1997, 1996 and 1995 transactions, respectively. The cost of alternative sources of power that might ultimately be required as a result of these settlements is expected to be significantly less than the estimated reduction in purchased power costs.

Construction Project Restructuring charges reported in 1995 included $37 .3 million for the cancellation of a project to construct a facility to handle low level radioactive waste at the Company's North Anna Power Station. As a result of reevaluating the handling of low level radioactive waste, the Company concluded that the facility should not be completed due to the additional capital investment required, decreased Company volumes of low level radioactive waste resulting from improvements in station procedures and the availability of more economical offsite processing.

P. Accelerated Cost Recovery:

In this increasingly competitive environment, the Co'mpany also has concluded that it is appropriate to utilize available cost reductions, such as those generated by the Vision 2000 program (see Note O to the CON SOLIDATED FINANCIAL TATEMENTS), to accelerate the write-off of existing unamortized regulatory assets. Not only will this strategically posi-on the Company in anticipation of competition, but it also reflects the Company's commitment to mitigate its exposure to otentially stranded costs (see Competition in MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CON-DffiON AND RESULTS OF OPERATIONS). The Company identified savings of $38.4 million in 1997 and $26.7 million in 1996 which were used to establish a reserve for expected adjustments to regulatory assets.

Q. Commitments and Contingencies:

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. 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.

Utility Rate Regulation In March 1997, the Virginia Commission issued an order that Virginia Power's base rates be made interim and subject

• to refund as of March 1, 1997. This order was the result of the Commission Staff's report on its review of Virginia Pow-er's 1995 Annual Informational Filing, which concluded that Virginia Power's present rates would cause Virginia Power to earn in excess of its authorized return on equity. The Staff found that, for purposes of establishing rates prospectively, a rate reduction of $95.6 million (including a one-time adjustment of $29.7 million to Virginia Power's deferred capacity balance at December 31, 1996) may be necessary in order to realign rates to the authorized level. In March 1997, Virginia Power filed its Alternative Regulatory Plan (ARP) based on 1996 financial information. Subsequently, the Commission consoli-dated the proceeding concerned with the 1995 Annual Informational Filing with the proceeding that includes the ARP pro-posed by the Company.

In December 1997, Virginia Power sought to withdraw its ARP, having concluded that resolution of the cost recovery issues raised by the ARP was unlikely without General Assembly action. The Commission has agreed that the Company may withdraw its support of the ARP but has reserved trye right to continue consideration of the ARP as well as other regulatory tematives. In addition, the Commission will continue to consider the issues arising out of the J995 Annual Informational 43

Filing. The Commission's Staff is scheduled to file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A public hearing is scheduled to commence on May 19, 1998.

Virginia Power's previous filings in this proceeding support maintaining the Company's rates at current levels; how-ever, opposing parties have made filings recommending rate reductions in excess of $200 million. At this time, management cannot predict the ultimate outcome of the proceeding and its impact on the Company's results of operations, cash flows or financial position.

Retrospective Premium Assessments Under several of the Company's nuclear insurance policies, the Company is subject to retrospective premium assess-ments in any policy year in which losses exceed the funds available to these insurance companies. For additional informa-tion, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.

Construction Program The Company has made substantial commitments in connection with its construction program and nuclear fuel expen-ditures. Those expenditures are estimated to total $588.1 million (excluding AFC) for 1998. The Company presently esti-mates that all of its 1998 construction expenditures, including nuclear fuel, will be met through cash flow from operations.

Purchased Power Contracts Since 1984, the Company has entered into contracts for the Jong-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. The Company has 57 non-utility purchase contracts with a combined dependable summer capacity of 3,277 MW.

The table below reflects the Company's minimum commitments as of December 31, 1997, for power purchases from utility and non-utility suppliers.

Commitment Year Capacity Other (Millions) 1998 .............................................................................. .. $ 813.5 $154.9 1999 ******************************************************************************** 816.7 156.7 2000 ******************************************************************************** 723.8 92.0 2001 .............................................................................. .. 716.0 83.7 2002 ..................................................... : ......................... . 721.1 \ 81.5 Later years ...................................................................... . 9,069.6 388.2 Total ........................................................................... . $12,860.7 $957.0 Present value of the total .................................................. .. $ 5,878.0. $553.3 Payments made by Virginia Power in satisfaction of the minimum purchase commitments shown in the above table are subject to reduction or partial refund if (1) the non-utility suppliers fail to meet performance requirements or (2) changes in federal or state law or administrative actions disallow or have the effect of disallowing Virginia Power's recovery of such costs from its customers. The amount of such payment reductions or refunds, if any, will be determined and administered as provided in individual supply contracts, although (l) the deferral of refund obligations, (2) disputes over the applicabil-ity of such payment reductions or refund obligations and (3) the ability of some non-utility suppliers to make refunds could limit Virginia Power's ability to benefit from these contract provisions.

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 payment~ for purchased power (including economy, emer-gency, limited term, short-term and other purchases for utility operations, as well as for trading purposes) for the years 1997, 1996 and 1995 were $1,381 million, $1,183 milJion and $1,093 million, respectively. For a discussion of the Company's efforts to restructure certain purchased power contracts, see Note O to CONSOLIDATED FINANCIAL STATEMENTS.

Fuel Purchase Commitments The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (mil-lions): 1998-$293; 1999-$233; 2000-$144; 2001 ~$144; and 2002-$127.

44.

Sale of Power A.a The Company enters into agreements with other utilities and with other parties to purchase and sell capacity and energy.

- e s e agreements may cover current and future periods ("forward positions"). The volume of these transactions varies from day to day based on the market conditions, our current and anticipated load, and other factors. The combined amounts of sales and purchases range from 500 MW to 7,000 MW at various times during a given year. These operations are closely monitored from a risk management perspective.

Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. These laws and regulations can result in increased capital, operating and other costs as a result of com-pliance, remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemaking process; however, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely impacted.

Site Remediation The EPA has identified the Company and several other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. The estimated future remediation costs*for the sites are in the range of $61.5 mil-lion to $72.5 million. The Company's proportionate share of the cost is expected to be in the range of $1.7 million to

$2:5 million; based upon allocation formulas and the volume of waste shipped to the sites. The Company has accrued a reserve of $1.7 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay the costs apportioned to them.

The Company and Dominion Resources have remedial action responsibilities remaining at two coal tar sites. The Com-pany accrued a $2 million reserve to meet its estimated liability based on site studies and investigations performed at these sites. In addition, two civil actions have been instituted against the City of Norfolk and Virginia Power by property owners ho allege that their property has been contaminated by toxic pollutants originating from one of the coal tar sites now ned by the City of Norfolk and formerly owned by the Company. The first civil action reached settlement without trial September 1997. The remaining plaintiff is seeking compensatory damages of $2 million and punitive damages of $1 million. It is too early in this case for the Company to predict the outcome. The Company has filed answers denying liabil-ity. No trial date has been set.

The Company generally seeks to recover its costs associated with environmental remediation from third party insurers.

At December 31, 1997, any pending or possible claims were not reco'gnized as an asset or offset against recorded obliga-tions of the Company.

R. Fair Value of Financial Instruments:

The Company used available market information and appropriate valuation methodologies to estimate the fair value of each class of financial instrument for which it is practicable to estimate fair value. These estimates are not necessarily indica-a tive of the amounts the Company could realize in market exchange. In addition, the use of different market assumptions may have a material effect on the estimated fair value amounts.

45

Dcrcmhcr 31, 199i 1996 Assets:

Cash and cash equivalents .............................................................. .

Nuclear decommissioning trust funds ................................................ .

Liabilities and_ capitalization:

Carrying Amount 36.0 569.1 Fair Value 36.0 569.1

,Carrying Amount*

(Millions) 47.9 443.3 Fair Value 47.9 443.3

" . I Short-term debt ............................................................................ .. 226.2 226.2 312.4 312.4 Long-term debt:

First and Refunding Mortgage Bonds ........................................... ,. 2,824.5 2,937.7 2,923.8 2,957.4.

Medium-term notes .................................................................... . 551.1 573.7 503.1 531.3 Money Market Municipal tax-exempt securities ............................... . 488.6 488.6 488.6 488.6 Convertible interest rate tax-exempt bonds .................................... .. 10.0. 10.4 Preferred stock subject to mandatory redemption ................................ . 180.0 186.6 180.0 185.8 Preferred securities of subsidiary trust .............................................. . 135.0 137.7 135.0 135.0 Cash and cash equivalents and short-term debt: The carrying amount of these items approximates fair value because of their short maturity.

• Nuclear decommissioning trust funds: The fair value is based on available market information and generally is the average of bid and asked price.

• First and Refunding Mortgage Bonds: Fair value is based on market quotations.

Medium-term notes: These notes were valued by discounting the remaining cash flows at a rate estimated for each issue. A yield curve rate was estimated to relate Treasury Bond rates for specific issues to the corresponding maturities.

Money Market Municipal tax-exempt securities: The interest rates for these notes vary so that fair value approximates carrying value.

Convertible interest rate tax-exempt bonds and preferred stock subject to mandatory redemption: The fair *value is based on market quotations or is estimated by discounting the dividend and principal payments for a representative issue of each series over the average remaining life of the series.

Preferred securities of subsidiary trust: Fair value is based on market quotations.

S. Quarterly Financial Data (unaudited):

The following amounts reflect all adjustments, consisting of only normal recurring accruals (except as discussed below),

necessary in the opinion of the management for a fair statement of the results for the interim periods.

Income from Net Balance Available Revenues O~rations Income for Common Stock (Millions) 1997 1st ... , ...................................... . $1,174.8 $248.6 $110.3 $101.5 2nd ........................................ .. 1,051.5 184.6 72.3 63.3 3rd ......................................... . 1,499.9 381.0 201.1 192.1 4th ......................................... . 1.352.8 205.1 85.4 76.5 1996

!st .......................................... . $1,169.7 $311.1 $152.8 $143.8 2nd ......................................... . 1,032.1 224.0 96.6 87.8 3rd 1,180.8 325.8 162.2 153.3 4th 1,038.3 149.1 45.7 36.9 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.

46

/

Certain accruals were recorded in 1997 and 1996 that are not ordinary, recurring adjustments, consisting of restructur-

~ n g (see Note O to CONSOLIDATED FINANCIAL STATEMENTS) and accelerated cost recovery (see Note P to CON-

• OLIDATED FINANCIAL STATEMENTS).

Restructuring-The Company expensed $6.3 million, $1.4 million and $10.7 million during the second, third and fourth quarters of 1997, respectively, and $5.4 million, $19.3 million, $4.6 million and $35.6 million during the first, sec-ond, third and fourth quarters of 1996.

Accelerated cost recovery - Amounts reserved for accelerated cost recovery were $2.8 million, $28.3 million and

$7 .3 million during the second, third and fourth quarters of 1997, respectively, and $26.7 million during the fourth quarter of 1996.

Charges for restructuring and accelerated cost recovery reduced Balance Available for Common Stock by $5.8 million,

$19.3 million, and $11.7 million for the second, third, and fourth quarters of 1997, respectively, and $3.5 million, $12.5 mil-lion, $3.0 million and $40.6 million for first, second, third and fourth quarters of 1996.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 47

PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT On September 12, 1997, the Board of Directors elected Thos. E. Capps as Chairman, succeeding John B. Adams, Jr.,

who had held the position since 1994. Mr. Capps also is Chairman of the Board of Directors of Dominion Resources, Inc.,

the parent company of Virginia Power.

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

Year First Principal Occupation for Last 5 Years, Elected a Term Name and Age Directorships in Public Corporations Director Expires Thos. E. Capps (62) Chairman of the Board of Directors of Virginia Electric and 1986 2000 Power Company from September 12, 1997 to date and Chairman, President and Chief Executive Officer of Dominion Resources from September 1, 1995 to date (from August 15, 1994 to September 1, 1995, Chairman and Chief Executive Officer; prior to August 15, 1994, Chairman, President and Chief Executive Officer). He is a Director of Bassett Furniture Industries, Inc. and NationsBank Corporation.

Norman Askew (55) President and Chief Executive Officer of Virginia Electric 1997 1998 and Power Company and Executive Vice President of Dominion Resources from August 1, 1997 to date; Executive Vice President of Dominion Resources and Chief Executive of East Midlands from February 21, 1997 to August 1, 1997; Chief Executive of East Midlands from April I, I 994 to February 21, 1997; Managing Director prior to April l, 1994.

John B. Adams, Jr. (53)

John B. Bernhardt (68)

President and Chief Executive Officer of The Bowman Companies, Fredericksburg, Virginia, a manufacturer and bottler of alcohol beverages and he is a Director of Dominion Resources.

Managing Director, Bernhardt/Gibson Financial 1987 1986 1998 2000 I

Opportunities, financial services, Newport News, Virginia.

He is a Director of Resource Bank and Dominion Resources.

James F. Betts (65) Former Chairman of the Board and President, The Life 1978 2000 Insurance Company of Virginia, Richmond, Virginia. He is a Director of Wachovia Corporation.

Jean E. Clary (53) President and owner of Century 21 Clary and Associates, 1996 2000 Inc., South Hill, Virginia.

John W. Harris (50) President, The Harris Group, a real estate consulting firm, 1997 1998 Charlotte, North Carolina. He is a Director of Piedmont Natural Gas Company, Inc. and US Airways Group, Inc.

Benjamin J. Lambert, III (61) Optometrist, Richmond, Virginia. He is a Director of 1992 1998 Consolidated Bank and Trust Company, Student Loan Marketing Association (SallieMae) and Dominion Resources.

Richard L. Leatherwood (58) Retired, Baltimore, Maryland. Former President and Chief 1994 1998 Executive Officer, CSX Equipment, an operating unit of CSX Transportation, Inc.). He is a Director of Dominion Resources and CACI International, Inc.

Harvey L. Lindsay, Jr. (68) Chairman and Chief Executive Officer of Harvey Lindsay 1986 1999 Commercial Real Estate, Norfolk, Virginia, a commercial real estate firm. He is a Director of Dominion Resources.

Kenneth A. Randall (70) Corporate Director for various companies, Williamsburg, 1971 1999 Virginia. He is a Director of Oppenheimer Funds, Inc.,

Kemper Insurance Companies and Prime Retail, Inc. He is a Director of Dominion Resources.

48

William T. Roos (69) Retired, Hampton, Virginia (prior to December 31, J 993, 1975 1999 President of Penn Luggage, Inc., retail specialty stores) .

He is a Director of Dominion Resources.

• rank S. Royal (58) Physician, Richmond, Virginia. He is a Director of 1997 1998 Columbia/HCA Healthcare Corporation, Crestar Financial Corporation, Chesapeake Corporation, CSX Corporation and Dominion Resources.

Judith B. Sack (49) Senior Advisor, Morgan Stanley & Co., Inc., an investment 1997 1999 banking firm, New York, New York, as of September J, 1995 (prior to September J, 1995, Advisor). She is a Director of Dominion Resources.

S. DaJlas Simmons (58) President of Virginia Union University, Richmond, Virginia. 1997 2000 He is a Director of Dominion Resources.

Robert H. Spilman (70) President, Spilman Properties, Basset, Virginia and Chairman 1994 2000 of the Board and a Director of Jefferson-Pilot Corp.,

Greensboro, North Carolina. Retired Chairman and Chief Executive Officer of Bassett Furniture Industries, Inc. He is a Director of International Home Furnishing Center, The Pittston Company and Dominion Resources.

William G. Thomas (58) President of Hazel & Thomas, Alexandria, Virginia, a law .1987 1999 firm.

David A. Wollard (60) Retired President, Bank One Colorado, N.A., Denver, 1997 1999 Colorado.

The Directors are divided into three classes, with staggered terms. Each class consists, as nearly as possible, of one-third of the total number of Directors. Each Director holds office until the annual meeting for the year in which his class term expires, or until his successor is duly qualified and elected as provided in the Company's Articles of Incorporation.

Mr. Thomas has entered into a Consent Decree with the Office of Thrift Supervision in connection with the lending a

and credit granting activities of Perpetual Savings Bank, FSB, which Mr. Thomas formerly served as director.. The Con-ent Decree requires that Mr. Thomas obtain approval from the appropriate federal banking agency before accepting certain ositions involving lending or credit activities with an insured depository institution.

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

Name and Age Business Experience past Five Years Norman Askew (55) President and Chief Executive Officer of Virginia Electric and Power Company and Executive Vice President of Dominion Resources from August 1, 1997 to date; Executive Vice President of Dominion .Resources and Chief Executive of East Midlands from February 21, 1997 to August 1, 1997; Chief Executive of East Midlands from April l, 1994 to February 21, 1997; Managing Director prior to April 1, 1994. .

Thomas F. Farrell, II (43) Executive Vice President of Virginia Electric arid Power Company and Senior Vice President-Corporate Affairs of Dominion Resources, September 1, 1997 to date; Senior Vice President-Corporate & General Counsel of Dominion Resources, January 1, 1997 to September 1, 1997; Vice President and General Counsel of Dominion Resources, July 1, 1995 to January I, 1997; Partner in the Jaw firm of McGuire, Woods, Battle, & Boothe LLP prior to July I, 1995.

Robert E. Rigsby (48) Executive Vice President, January 1, 1996 to date; Senior Vice President-Finance and Controller, January 1, 1995 to January 1, 1996; Vice President-Human Resources prior to January I, 1995.

William R. Cartwright (55) Senior Vice President-Fossil and Hydro, July l, 1995 to date; Vice President Fossil and Hydro prior to July 1, 1995.

Lawrence E. De Simone (50) Senior Vice President-Energy Services, July 15, 1996 to date; vice president-strategic planning for Central & South West Corp., a Dallas-based electric utility holding company, prior to July 15, I 996.

Larry M. Girvin (54) Senior Vice President-Commercial Operations, January 1, 1996 to date; Vice President-Human Resources, January 1, 1995 to January 1, 1996; Vice President-Nuclear Services prior to January I, 1995.

ames P. O'Hanlon (54) Senior Vice President-Nuclear, June I, 1994 to date; Vice President-Nuclear Operations prior to June 1, 1994.

49

John A. Shaw (49) Senior Vice President-Finance, March 16, 1998 to date; Vice President Financial Service for ARCO Chemical Company, Philadelphia, Pennsylvania, prior to March 16, 1998. During the past 5 years, he has also served as Treasurer and Controller of ARCO Chemical.

Eva S. Teig (53) Senior Vice President-External Affairs & Corporate Communications, September 1, 1997 to date; Vice President-External Affairs & Corporate Communications, June 1, 1997 to September I, 1997; Vice President-Public Affairs prior to June 1, 1997.

Said Ziai (44) Senior Vice President-Corporate Strategy, October I, 1997 to date; Corporate Planning Director, East Midlands Electricity pie, Nottingham, England prior to October I, 1997.

Thomas L. Caviness, Jr. (52) Vice President-Retail Energy Services, July 1, 1995 to date;Vice President-Eastern Division prior to July 1, 1995.

David A. Christian (43) Site Vice President-Surry, March 1, 1998 to date; Station Manager-Surry Power Station, September 1, 1994 to March I, 1998; Assistant Station Manager-Surry, prior to September 1, 1994.

J. Kennerly Davis, Jr. (52) Vice President-Finance and Administrative Services, Treasurer and Corporate Secretary, January 1, 1996 to date; Vice President, Treasurer and Corporate Secretary, October 1, 1994 to January 1, 1996; Vice President and Corporate Secretary of Dominion Resources prior to October 1, 1994.

James T. Earwood, Jr. (54) Vice President-Bulk Power Delivery, January 1, 1997 to date;Vice President-Energy Efficiency and Division Services, January 1, 1996 to January 1, 1997; Vice President-Division Services prior to January 1, 1996.

E. Paul Hilton (54) Vice President-Regulation, October 1, 1997 to date; Manager, Rates and Regulation, February 20, 1996 to October 1, 1997; Manager, Rates prior to February 20, 1996.

Thomas A. Hyman, Jr. (46) Vice President-Distribution Operations and North Carolina Power, June I, 1997 to date;Vice President-Eastern Division and North Carolina Power, July 1, 1995 to

• June 1, 1997; Vice President-Southern Division, June J, 1994 to July 1, 1995; Station Manager-Bremo Power Station prior to June 1, 1994.

Michael R. Kansler (43) Vice President-Nuclear Operations, January l, 1997 to date;Vice President-Nuclear Engineering and Services, October 1, 1995 to January 1, 1997; Vice President-Nuclear Services, January I, 1995 to October 1, 1995 ; Manager-Nuclear Operations Support, September 1, 1994 to January l, 1995; Station Manager-Surry Nuclear Power Station prior to September 1, 1994.

• William R. Matthews (51) Site Vice President-North Anna, March 1, 1998 to date; Station Manager-North Anna Power Station, May 1, 1996 to March 1, 1998; Assistant Station Manager-North Anna Power Station, December 1, 1993 to May 1, 1996; Superintendent-Maintenance, prior to December l, 1993.

MarkF. McGettrick (40) Vice President-Customer Service, January 1, 1997 to date; Corporate Restructuring Project Manager, February 1, 1995 to January I, 1997; Assistant Controller prior to February 1, 1995.

William S. Mistr (50) Vice President-Information Technology, January 1, 1996 to date and Vice President of Dominion Resources, February 20, 1997 to date; Vice President and Treasurer, Dominion Energy, Inc., October 1, 1994 to January 1, 1996; Assistant Treasurer, Dominion Resources prior to October 1, 1994.

Thomas J. O'Neil (55) Vice President-Human Resources, January 1, 1996 to date; Vice President-Energy Efficiency prior to January I, 1996.

Edward J. Rivas (53) Vice President-Fossil & Hydro Operations, January I. 1998 to date; Manager-Clover Power Station, March 16, 1994 to January 1, 1998; Manager-Fossil & Hydro Training prior to March 16, 1994.

Robert F. Saunders (54) Vice President-Nuclear Engineering and Services, January I, 1997 to date; Vice President-Nuclear Operations, June 1, 1994 to January 1, 1997; Assistant Vice President-Nuclear Operations, prior to June I, 1994.

Johnny V. Shenal (52) Vice President-Distribution Construction, June I, 1997 to date;Vice President-Northern and Western Divisions, June I, 1994 to June I, 1997; Vice President-Western Division, prior to June I, 1994.

Richard T. Thatcher (48) Vice President-Wholesale Power Group, September I, 1997 to date; Managing Director, Wholesale Power, April 10, 1997 to September 1,- 1997; Manager, Wholesale Power Group, July 1, 1995 to April I 0, 1997; Project Manager, January 1, 1995 to July I, 1995; Director-Generation and Interconnection Planning prior to January I, 1995.

There is no family relationship between any of the persons named in response to Item I 0.

50

Section 16(a) Beneficial Ownership Reporting Compliance

• Our Directors and Executive Officers report their ownership of our preferred stock pursuant to Section I6(a) of the Exchange Act. Through administrative oversight, the following individuals failed to file their initial statements of beneficial ownership on Form 3 on a timely basis: Thos. E. Capps, Norman Askew, John B. Bernhardt, John W. Harris, Kenneth A.

Randall, Frank S. Royal, Judith B. Sack, S. Dallas Simmons, David A. Wollard, Thomas F. Farrell, II, Said Ziai, E. Paul Hilton, Richard T. Thatcher, David A. Christian and William R. Matthews.

None of the individuals owned any of our preferred stock at the time their initial reports should have been filed nor have they or any other Director or Executive Officer have any reportable transactions in the preferred stock which have not been reported. The required filings have now been made.

ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The Summary Table below includes compensation paid by the Company for services rendered in 1997, 1996 and 1995 for the Chief Executive Officer and the four other most highly compensated executive officers (as of December 31, 1997) as determined by total salary and incentive payments for 1997.

Summary Compensation Table Long Tenn Compensation Awards Annual Compensation Securities Payouts Restricted Underlying Other Annual Stock Options/ LTIP All Other Name & Principal Position Year ~ lncentive(l) Compensation(2) Awards SAR Grants Pay out Come!:nsation(3)

James* T. Rhodes 1997 $244,800 $159,250(4) $ 0 $ 0 $0 $803,429(5) $7,977,039(6)

President and CEO 1996 $410,575 $247,606 $ 0 $ 0 $0 $ 75,684 $ 4,500 (retired August I, 1997) 1995 $406,075 $273,000 $ 0 $ 0 $0 $ 77,970 $ 4,500 orman Askew 1997 $177,084 $ 85,833 $14,560 $ 0(7} $0 $ 18,791(8) $ 120,000(9) esident and CEO effective August I, 1997)

Robert E. Rigsby 1997 $254.850 $129,920 $ 0 $ 0(10) $0 $ 83,171(11) $ 4,800 Executive Vice President 1996 $226.469 $143,892 $ 0 $ 0 $0 $ 43,157 $ 4,500 1995 $171,456 $105,000 $ 0 $ 0 $0 $ 34,569 $ 4,500 James. P. *O'Hanlon 1997 S270,250 SI 10.240 $ 0 $ 0(12) $0 $ 80, 140(13) $ 4,800 Senicir Vice President I

- 1996 $220,815 $128,511 $ 0 $ 0 so $ 56,152 $ 4,500 Nuclear 1995 $207,555 $136,400 $ 0 $ 0 $0 $ 45,109 $ 4,500 Lawrence E. DeSimone 1997 $212,751 S 85,520 $ 0 $ 0(14) $0 $ 0 $ 3,180 Senior Vice President - 1996 S 94,419 S 50,441 s 0 s 0 $0 $ 0 $ 0 Energy Services Larry M. Girvin 1997 Sl87,050 $ 85.520 s 0 $ 0(15) $0 $ 52,935(16) $ 4,800 Senior Vice President - 1996 Sl64,600 S 89,200 $ 0 s 0 $0 $ 30,717 $ 4,500 Commercial Operations 1995 S 139,650 S 66,606 $ 0 $ 0 $0 $ 24,685 $ 4,500 (1) The Company does not maintain "bonus" plans which are used by some companies to supplement salaries based on the success of the company without regard to individual performance. However, the Company has in place various incentive plans that compensate officers and employees for achieving specified performance goals.

(2) Unless noted, none of the executive officers above received perquisites or other personal benefits in excess of either

$50,000 or 10% of total salary and incentive payment.

(3) Employer matching contribution of $4,800 on Employee Savings Plan contributions, unless otherwise noted.

(4) Amount represents a lump sum settlement of his rights under the 1997 Annual Incentive Plan.

(5) $158,025 was paid under the 1995-1997 Performance Achievement Plan. 7,326 shares. of Dominion Resources, Inc.

Common Stock (worth $269,231 @ $36.75 per share) were issued under the 1996-1998 Long Term Incentive Plan.

10,326 shares of Dominion Resources, Inc. Common Stock (worth $376,173 @ $36.75 per share) were issued under the 1997-1999 Long Term Incentive Plan.

51

(6) Upon his retirement, Dr. Rhodes received the following payments from the Company: $51,078 for unused vacation;

$1,023,271 as provided by his employment contract; $4,184.220 lump sum settlement of pension benefits not payable from the qualified retirement plan; $2,715,926 as a lump sum settlement of his benefit under the Executive Supple-mental Retirement Plan, and $2,544 in employer match on Employee Savings Plan contributions.

(7) Mr. Askew held no restricted stock as of 12/31/97.

(8) Amount represents incentive plan pay outs from Virginia Power, on a prorated basis, for performance cycles that ended in 1997: $7,550 in lieu of dividends on restricted stock for partial participation in the 1996-1998 and the 1997-1999 performance cycles; and $11,241 for the 1995-1997 performance cycle.

(9) A one time payment related to his international transfer from the UK to the US.

( 10) Aggregate number of shares of restricted stock on December 31, 1997: 13,763 with an aggregate value of $585,788 (based on a closing price on December 31, 1997 of $42.5625 per share).

(11) 2,085 shares of stock, with 50% of the value awarded in cash ($41,133) and the remaining 1,042 shares being issued (valued at $42,038 or $40.3437 per share as of 2/20/98).

(12) Aggregate number of shares of restricted stock on December 31, 1997: 9,773 with aggregate value of $415,963 (clos-ing price on December 31, 1997 of $42.5625 per share).

(13) 2,009 shares of stock, with 50% of the value awarded in cash ($39,635) and the remaining 1,004 shares being issued (valued at $40,505 or $40.3437 per share as of 2/20/98).

( 14) Mr. DeSimone held no restricted stock as of 12/31 /97.

(15) Aggregate number of shares of restricted stock on December 31, 1997: 7,528 with aggregate value of $320,411 (clos-ing price on December 31, 1997 of $42.5625 per share).

(16) 1,327 shares of stock, with 50% of the value awarded in cash ($26,187) and the remaining 663 shares being issued (valued at $26,748 or $40.3437 per share as of 2/20/98).

Long-term Incentive Compensation Long-term incentive awards made during 1997 are shown in the following table.

Long-term Incentive Plans - Awards in the Last Fiscal Year 1997-1999 Long-term Incentive Plan Performance or Estimated Future Payouts Number of Other Period under Non-stock Price Based Plans Shares, Unil~ until Maturation Threshold Target

,, Name or Other Rights(#) or l'uvout ($ or #) ($ or #)

J.T. Rhodes .................................................. .. $259,448 3 years $129,724 $259,448 N. Askew .................................................... .. $261,250 3 years $130,625 $261,250 J.P. O'Hanlon ............................................... .. $112,843 3 years $ 56,422 $112,843 R.E. Rigsby .................................................. . $163,714 3 years $ 81,857 $163,714 L.E. DeSimone .............................................. . $ 87,750 3 years $ 43,875 $ 87,750 L.M. Girvin .................................................. . $ 87,750 3 years $ 43,875 $ 87,750 I

52

Retirement Plans

'\

.

• The tabl~ below sets forth the estimated annual straight life benefit that would be paid following retirement under the

• enefit formula of the Dominion Resources, Inc. Retirement Plan (the Retirement Plan).

Estimated Annual Benefits Payable upon Retirement Credited Years of Service Final Average Earnings 15 20 25 30

$185,000 $51,501 $68,668 $85,836 $103,003 200,000 56,069 74,758 93,448 112,138 225,000 63,681 84,908 106,136 127,363 250,000 71,294 95,058 118,823 142,588 300,000 86,519 115,358 144,198 173,038 350,000 101,744 135,658 169,573 203,488 400,000 116,969 155,958 194,948 233,938 450,000 132,194 176,258 220,323 264,388 500,000 147,419 196,558 245,698 294,838 550,000 162,644 216,858 271,073 325,288 600,000 177,869 237,158 296,448 355,738 650,000 193,094 257,458 321,823 386,188 750,000 223,544 298,058 372,573 447,088 Benefits under the Retirement Plan are based on (i) average base compensation over the consecutive 60-month period in which pay is highest, (ii) years of credited service, (iii) age at retirement, and (iv) the offset of Social Security Benefits.

Certain officers have entered into retirement agreements that give additional credited years of service for retirement and retirement life insurance purposes, and retirement medical benefit purposes contingent upon the officer reaching a specified ge and remaining in the employ of the Company or an affiliate.

For purposes of the above table, based on 1997 compensation, credited years of service (including any additional years ned in connection with the retirement agreements) for each of the individuals named_ in the cash compensation table.

would be as follows:

James T. Rhodes: 30; Norman Askew: O; Robert E. Rigsby: 26; James P. O'Hanlon: 8; Lawrence E. De Simone: 0; Larry M. Girvin: 31.

Virginia Power's executive compensation program has placed increased emphasis on incentive compensation opportu-nities linked to financial and operating performance. Base salaries have been held below the mean for comparable positions at comparable companies. The Retirement Plan benefit formula recognizes base salary, but not mcentive compensation pay-ments. Therefore, each year the Organization and Compensation Committee approves a market-based adjustment to execu-tive base salaries for use in calculating the retirement benefit under the Dominion Resources, Inc. Benefit Restoration Plan (the Restoration Plan). In 1997, this adjustment was 11 percent. Also, the Internal Revenue Code limits the annual retire-ment 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 limita-tions 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 offic-ers 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 ben-efit is monthly installments for 120 months to a participant with 60 months of service, who (i) retires at or after age 55 from the employ of the Company, (ii) has become permanently disabled, or (iii) dies. The accrued benefit vests proportionately between the time an officer is elected and when he or she reaches age 55 when the benefit is fully vested If a participant dies while employed, the normal form of benefit will be paid to a designated beneficiary. If a participant dies while retired, but before receiving all benefit payments, the remaining installments will be paid to a designated beneficiary. A lump sum payment is available under certain conditions. .

a Based on 1997 compensation, the estimated annual retirement benefit for each of the executive officers under the plemental Plan would be as follows: N. Askew: $167,406; R.E. Rigsby: $104,345; J.P. O'Hanlon: $113,228;

.E. De Simone: $79,139; L.M. Girvin: $73,764.

53

Retirement Benefit Funding Plan The Company maintains a Retirement Benefit Funding Plan to provide a means to secure obligations under the Supple-mental Plan, the Restoration Plan, and retirement agreements. The Retirement Benefit Funding Plan does not provide any additional benefits; it simply helps secure the funding for these benefit obligations. The amount payable by Virginia Power under the Supplemental Plan, the Restoration Plan and retirement agreements is reduced, on a dollar-for-dollar basis, by the funds available under the Retirement Benefit Funding Plan.

Employment Agreements The Company has entered into employment continuity agreements (the Agreements) with its key management execu-tives, including, Norman Askew, Robert E. Rigsby, James P. O'Hanlon, Lawrence E. De Simone, and Larry M. Girvin, which provide benefits in the event of a change in control. Each Agreement has a three-year term and thereafter is auto-matically extended on its anniversary date for an additional year unless notified that the Agreement will not be extended by the Company. If, following a change in control (as defined in the Agreements) of Dominion Resources or the Company, an executive's employment is terminated by the Company without cause, or voluntarily*by the executive within sixty days after a material reduction in the executive's compensation, benefits or responsibilities, the Company will be obligated to pay to the executive continued compensation equaling the average base salary and cash incentive bonuses for the thirty-six full month period of employment preceding the change in control or employment termination. In addition, the terminated execu-tive will continue to be entitled to any benefits due under any stock or benefit plans. The Agreements do not alter the com-pensation 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 com-pensation earned by the executive from comparable employment by another employer during the thirty-six months follow-ing termination of employment with the Company. An executive shall not be entitled to the above benefits in the event ter-mination is for cause.

Compensation of Directors The non-employee members of the Board receive an annual retainer of $19,000 and a fee of $900 for each Board or committee meeting attended. Committee chairmen receive an additional annual retainer of $3,000. Consistent with the Com-pany's philosophy concerning equity-based compensation for officers, effective in 1998 non-employee directors will also receive an annual retainer in Dominion Resources common stock valued at $19,000. These Directors may elect to defer their annual retainer and/or their meeting fees under the Deferred Compensation Plan until they retire from the Board or other-wise direct. The deferred fees are credited, for bookkeeping purposes, with earnings and losses as if they were invested in either an interest bearing account or Dominion Resources Common Stock, depending on the Director's election.

\

Directors Charitable Contribution Program Dominion Resources administers a Directors' Charitable Contribution Program (the Program) that covers Directors of 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 IO years will be made to one or more qualifying charitable organizations recom-mended 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.

I 54

ITEM 12. SECURITY OWNERSHIP OF CERTAIN

., BENEFICIAL OWNERS AND MANAGEMENT

• The table below sets forth as of February 20, 1998, except as noted, the number of shares of Common Stock of Domin-ion Resources owned by Directors and four other more highly compensated executive officers of Virginia Electric and Power Company.

Shares of Common Stock Director Plan Name Beneficially Owned Accounts(I)

John B. Adams, Jr............................................. . 3,891 9,091 John B. Bernhardt. ............................................. . 1,500 9,091 James F. Betts ................................................... . 7,500 9,091 Thos. E. Capps .................................................. . 44,914(2)

Jean E. Clary .................................................... . 116 9,162 John W. Harris .................................................. . 500 9,091 Benjamin J. Lambert, III ........ , ............................ . 90 10,212 Richard L. Leatherwood ..................................... . 1,000 17,616 Harvey L. Lindsay ............................................. . 400 9,091 Kenneth A. Randall ............................................ . 3,027 9,091 William T. Roos ............................... : ................ . 14,603(3) 9,091 Frank S. Royal .................................................. . 10,430 Judith B. Sack ................................................... . 1,000 14,575 S. Dallas Simmons ............................................. . 650 13,370 Robert H. Spilman ............................................. . 1,187 9,091 William G. Thomas ............................................ . 1,000 13,257 David A. Wollard ............................................... . 9,879 Norman Askew .................................................. . 1,290(2)

Lawrence E. De Simone ............................ *......... . 92 arry M. Girvin ................................................. . 7,654 es P. O'Hanlon ............................................. . 11,100 bert E. Rigsby ............................................... . 22,079 All Directors and Executive Officers as a group - 41 persons (4) ................................... . 397 ,599(2)(5)

(I) Amounts in this column represent share equivalents accumulated under the non-employee director Stock Accumulation Plan. Balances of 9,091 shares are the amounts accumulated thus far under the plan. Because of the plan's vesting pro-visions, these amounts will not necessarily be distributed to a director. Any balance in excess of 9,091 is an amount of shares accumulated-at the director's election-under the Deferred Cash Compensation plan. That excess amount will be distributed in actual shares to the director.

(2) Amounts include restricted stock as follows: Mr. Capps - 23,984 shares; Mr. Askew - 1,290; and all directors and executive officers as a group - 89,859.

(3) Mr. Roos disclaims beneficial ownership of 4,387 shares that are held in trusts for family members.

(4) All current directors and executive officers as a group own less than one percent of the number of shares outstanding as of February 20, 1998.

(5) Beneficial ownership is disclaimed for a total of 4,786 shares.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Hazel & Thomas, a professional corporation, from time to time acts as counsel to the Company. Mr. Thomas, a Direc-tor of the Company, is a shareholder of Hazel & Thomas.

I 55

PART IV ITEM 14. EXHIBITS, FINANCIAL ST ATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this Form I 0-K:

1. Financial Statements See Index on page 21.

2. Exhibits 3.1 Restated Articles of Incorporation, as amended, as in effect on September 12, 1994 (Exhibit 3(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference).

3.2 Bylaws, as amended, as in effect on October 17, 1997 (Exhibit 3(ii), Form 10-Q for the period ended September 30, 1997, File No. 1-2255, incorporated by reference).

4.1 See Exhibit 3 (i) above.

4.2 Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures (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), Form 10-Q for the quarter ended September 30, 1986, File No. 1-2255, incorporated by reference); Sixty-First Supplemental Indenture (Exhibit 4(ii), Form 8-K, dated June 2, 1987, File No. 1-2255. incorporated by reference);

Sixty-Second Supplemental Indenture (Exhibit 4(i), 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 Supplemental 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, I 990, 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, I 992, 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); Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture (Exhibit 4(i). Form 8-K, dated April 6, 1993, File No. 1-2255, incorporated by reference); Seventy-Sixth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 21, I 993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture (Exhibit A(i), Form 8-K, dated June 8, 1993, File No.

1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August JO, 1993, File No. 1-2255, incorporated by reference);

Seventy-Ninth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 12. 1993, File No. 1-2255, incorporated by reference);

Eighty-First Supplemental Indenture (Exhibit 4(iii), Form I 0-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture (Exhibit 4(i), Form 8-K. dated January 18, 1994, File No.

1-2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i),

Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference);

Eighty-Fourth Supplemental Indenture (Exhibit 4(i). Form 8-K, dated March 22, 1995, File No. 1-2255, incorporated by reference; and Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference). I 56

4.3 Indenture, dated April I, 1985, between Virginia Electric and Power Company and Crestar Bank (formerly United Virginia Bank) (Exhibit 4(iv), Fonn I 0-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

• .4 Indenture, dated as of June I, 1986, between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank) (Exhibit 4(v), Fonn 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

4.5 Indenture, dated April I, 1988, between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank), as supplemented and modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

4.6 Subordinated Note Indenture, dated as of August I, 1995 between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank), as Trustee, as supplemented (Exhibit 4(a), Form S-3 Registration Statement File No.

333-20561 as filed on January 28, 1997, incorporated by reference).

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

JO.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 1O(vi), Fann 10-K for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference).

• 10.2 Purchase, Construction and Ownership Agreement, dated as of December 28, 1982 but amended and restated on October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit JO(viii), Fonn 10-K for the_

fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference).

10.3 Amended and Restated Interconnection and Operating Agreement, dated as of July 29, 1997 between Virginia Electric and Power Company and Old Dominion Electric

• Cooperative (filed herewith).

Nuclear Fuel 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 1O(x), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference).

Credit Agreements dated June 7, 1996, between The Chase Manhattan Bank (fonnerly Chemical Bank) and Virginia Electric and Power Company (Exhibits I O(i) and lO(ii),

• Fonn 10-Q for the period ended June 30, 1996, File No. 1-2255, incorporated by reference).

10.6 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 31, 1985, File No. 1-8489, incorporated by reference).

10.7 Agreement for Northern Virginia Services, dated as of November 1, 1985, between Potomac Electric Power Company and Virginia Electric and Power Company *(Exhibit IO(xxi), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-8489, incorporated by reference).

10.8 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 ye~rended December 31, 1990, File No. 1-2255, incorporated by reference).

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

10.10 Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and the Unit 2 Amendment (Volume I); dated May 31, 1990 between Virginia Electric and Power Company and Old Dominion Electric Cooperative, Westinghouse, Black & Veatch,

,.II' Combustion Engineering and H. B. Zachry (Volumes 2-11 contain technical specifi-cations) (Exhibit I O(xiii), Form I 0-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).

Description of arrangements with certain officers regarding additional credited years of service for retirement purposes (Exhibit 1O(xii), Form 10-K for the fiscal year ended December 31, 1992, File No. 1-2255, incorporated by reference).

57

• l*-,,,,,.-..

10.12* Dominion Resources, Inc. Directors' Deferred Compensation Plan effective July 1, I 986, as amended and restated on January 1, 1996 (Exhibit l O(xii), Form l 0-K for the fiscal year ended December 3], 1996, File No. 1-2255, incorporated by reference).

10.13* Dominion Resources, Inc. Performance Achievement Plan, effective January I, 1986, a~ amended and restated effective February 19, 1988 (Exhibit JO(xxiii), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).

10.14* Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 198 I as amended and restated September 1, I 996 with first amendment dated June 20, 1997 and second amendment dated March 3, 1998 (filed herewith).

10.15* Dominion Resources, Inc.'s Cash Incentive Plan as adopted December 20, 1991 (Exhibit lO(xxv), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).

10.16* Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September 1, 1996 (filed herewith).

10.17* Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective January 1, 1991 as amended and restated September 1, 1996 (filed herewith).

10.18* Dominion Resources, Inc. Executives' Deferred Compensation Plan, effective January 1, 1994, as amended and restated on January 1, 1997 (Exhibit IO(xix), Form 10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference).

10.19* Form of an Employment Agreement dated June 23, 1994 between Virginia Power and certain executive officers (Exhibit lO(xxi), Form 10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference).

10.20* Employment Agreement dated September 15, 1995 between Virginia Power and Robert E. Rigsby (Exhibit JO(xxii), Fonn 10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference).

10.21

• Employment Agreement dated February 21, 1997 between Dominion Resources and Nonnan Askew (filed herewith).

10.22* Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, effective April 23, 1996 (Exhibit JO(xxiv), Form I 0-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference).

10.23* Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, I 997 (filed herewith) 23.1 Consent of Hunton & Williams (filed herewith).

23.2 Consent of Jackson & Kelly (filed herewith).

23.3 Consent of Deloitte & Touche LLP (filed herewith).

27 Financial Data Schedule (filed herewith).

• Indicates management contract or compensatory plan or arrangement (b) Reports on Form 8-K None I

58

i I .

SIGNATURES Pursuant to the requirements of Section 13 or JS(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VIRGINIA ELECTRIC AND POWER COMPANY Date: March 20, 1998 By THOS. E. CAPPS (Th os. E. Capps., Chairman of the Board or Directors)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 20, 1998.

Signature Title THOS E. CAPPS Chairman of the Board of Directors and Thos E. Capps Director JOHN B. ADAMS, JR.

• Director John B. Adams, Jr.

NORMAN ASKEW President (Chief Executive Officer) and Nonnan Askew Director JoHN B. BERNHARDT Director John B. Bernhardt JAM ES F. B E'ITS Director James F. Betts JEAN E. CLARY Director Jean E. Clary JOHN W. HARRIS Director John W. Harris BENJAMIN J. LAMBERT. III Director Benjamin J. Lambert, lil RICHARD L LEATHERWOOD Director Richard L. Leatherwood I HARVEY L. LINDSAY. JR.

Harvey L Lindsay, Jr.

Director 59

l Signature Kenneth A. Randall Director Title WILLIAM T. Roos Director William 1: Roos

'"'FRANK. S. ROYAL Director Frank S. Royal JUDITH B. SACK Director Judith JI. Sack S. DALLAS SIMMONS Director S. Dallas Simmons ROBERT H. SPILMAN Director Robert H. Spilman WILLIAM G. THOMAS Director William G. Thomas Director David A. Wollard M. S. BOLTON, JR. Controller (Principal Accounting M. S. Bolton, Jr. Officer)

I 60