ML18151A505

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Forwards Comparative Statement of Income for Three Months Ended 951231 & 1994,internal Cash Flow Projection for CY96 & Statement Ensuring Availability of Funds for Payment of Retrospective Premiums,Per 10CFR142.21(e)
ML18151A505
Person / Time
Site: Surry, North Anna  Dominion icon.png
Issue date: 04/01/1996
From: Ohanlon J
VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:
NRC (Affiliation Not Assigned)
References
96-149, NUDOCS 9604040109
Download: ML18151A505 (64)
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Text

e e VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 April 1, 1996 Director, Nuclear Reactor Regulation Serial No.96-149 United States Nuclear Regulatory Commission NURPC Washington, D. C. 20555 Docket Nos. 50-280 50-281 50-338 50-339 License Nos. DPR-32 DPR-37 NPF-4 NPF-7 Gentlemen:

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

1. Comparative Statement of Income for the three months ended December 31 , 1995 and 1994.
2. Internal cash flow projection for calendar year 1996 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 1995.

In accordance with 10 CFR 140.7, we submitted a check to the NRG for $1,000 on November 13, 1995, which is the minimum required premium for the period November 15, 1995, through November 14, 1996.

  • Very truly yours,

~?~

James P. O'Hanlon Senior Vice President - Nuclear 040021 Enclosures

( 9604040109 960401 PDR ADOCK 05000280 I PDR

l e

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

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

VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF INCOME (Unaudited)

Three Months Ended December 31, 1995 . 1994 (Millions)

Operating revenues $1,026.3 $ 927 .3 Operating expenses:

Operation:

Fuel, net 237.1 229.5 Purchased power capacity, net 170.2 162.4 Other 144.2 174.0 Maintenance 57.8 59.9 Depreciation and amortization 120.0 111.4 Restructuring 82.0 Amortization of terminated construction project costs 8.6 8.6 Taxes - Income 25.0 18.7

- Other 62.5 54.6 Total 907.4 819.1 Operating income 118.9 108.2 Other income (0.9) 4 5 Income before interest charges 118.0 112 .7 Interest charges:

Interest on long-term debt 74.9 74.9 Other 4.2 (6.3)

Allowance for borrowed funds used during construction (0.9) ( 1. 6)

Total 78.2 67.0 Distribution - preferred securities of subsidiary trust, net 1.8

. Net income 38.0 45.7 Preferred dividends 9.2 11. 2 Balance available for Common Stock $ 28.8 $ 34.5

e 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 1996, provided herewith, is based on the best available information known at this time and is a reasonably accurate projection of the Company's 1996 cash flow.

Controller Commonwealth of Virginia City of Richmond Sworn t._fl and subscribed ~efore me q

this J aay of {'()OR.CH- 1996.

Notary Public NOTARIAL SEAL

e Virginia Electric & Power Company 1996 Estimated Internal Cash Flow (Millions of Dollars)

Jan Apr Jul Oct Estimated thru thru thru thru 1996 Mar Jun fum Dec Total Cash Receipts $1,127.9 $955.6 $1,163.8 $1,011.2 $4,258.5 Less:

Cash for Operations 600.0 568.6 589.6 565.4 2,323.6 Taxes 21.9 156.9 96.0 191.7 466.5 Interest 84.1 71.1 83.3 64.6 303.l Dividends

- Preferred Affiliates 2.7 2.7 2.7 2.7 10.8

- Preferred Stock 9.5 9.5 9.5 9.5 38.0

- Common Stock 99.7 99.7 99.7 99.7 398.8 Decommissioning Trust 9.1 9.1 9.1 9.1 36.4 Changes in Working Capital 29.8 (2.4) 51.1 1.9 80.5 Other 0.0 0.0 0.0 0.0 0.0 Total Cash Flow (1) $21.Ll $.40...4 $222..8. $66..6.. $_6illL8_

(1) Before Financing and Construction Requirements.

H:\FPB\PLANNING\1996\BUDGET\DATA\6CASH\PRICEFNL.WK4 03/11/96

VIRGINIA ELECTRIC AND POWER COMPANY STATEMENT The Company currently estimates 1996 construction and nuclear fuel expenditures (exclusive of Allowance for Funds Used During Construction) to be $569 million. Debt maturities in 1996 will total $259.6 million. It is expected that approximately $601 million will be obtained from internal sources. The remaining $227.6 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.

e SECURITIES-AND EXCHANGE COMMISSION WASIDNGTON, D.C. 20549 Form 10-K (Mark One)

.,,* ~ . ANNUAL REPORT PURSUANT TO SECTION .13..0R 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the*fiscal year ended December 31,-1995 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 charter)

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

One James River Plaza Richmond; Virginia 23219-3932'. ..

(Address of principal .executive offices) (Zip Code)

(804) 771-3000 ...

(Registrant's*telephone number, including area code)

- Securities registered pursuant to Sectior.i l~(b) of. the Act:

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

$ roo liquidation value:

$5.00 dividend Trust Preferred Securities *New York Siock Exchange

$25 *liquidation value:

8.05% dividend Securities registered pursuant to Section l2(g) of the Act:

None *

. (Title. of Class) ..

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes Y' No Indicate by check mark if disclosure of delinquent filers pursuant to Item ,405 c:>f Regulation S-K is not coptained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporate~ by reference* in Part III of this Form 10-K or any amendment to this Form 10-K.. Y' The aggregate market value of the voting stock held by non-affiliates of the registrant as of February 29, 1996 was zero.

As of February 29, 1996, there 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

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

1. Business .......................................................................................................................................................................................... . 1 The Company ......................................*.......... ;..................................................................................... **************:************************* 1 Regulation ..................................................................... _............................................................................................................. . 1 General ....................................................................................................* ............................................................................... . 1 FERC ...................................................................................................................... *...... *...... :...................... :........................... . 2 Environmental ................................... ,..................................................................................................................................... . 2 Nuclear .......................................... *............................................ : ........ *.: ...................... *........................ : ............................... . 3 Capital Requirements and Financing Program..... :... :.......... :: .......... :......... :: ............. :.: ................ :.. :.............. :: ...::.... :................ . 4 Construction and Nuclear Fuel Expenditures; ............ :............*......... :::.O'....::.: .*................. :: ................... .'.: ...... ;....................... . 4 Financing Program ..................................... .'......: ............. ;.. ;.............. ;............. :... :.................................................................. . 4 Rates .................................... *.* ........................... *.. *..... *......... :....... *................ *........ *.............................................. , ................... .. 4 Virginia ............................................................ *............... : ...................................................... : ............................................ .. 5 North Carolina ...................... .'.................................................. :................................................. :................. :.......................... . 5 Sources of Power .......................................................................... :.... :........................'..... :..... :....*................ :.:.: .......................... . 6 Company Generating Units ...................................................................................................................................... :............. . 6 Net Utility Purchases ........... :............................. ,..................... :........ ;...... ,................ ,.................... ,., .... ,..., ..:********.**,********,*********** 6 Non-Utility Generation ........................... :...... :: .................. .':................. ,.... :...... :.......... :................. :........ :...........*.................... . 6 Sources of Energy Used and Fuel Costs .........: ..........., ..... ,.............. :... ,......... :.; ...... :.............. ,...:: ... ,:.... :.:.:.,:.: .......... :... :.........: ... . 7 Nuclear Operations and Fuel Supply ....... :... :........................ ;.. :... :............... :............... ;................. ;....... ,.. ,.............. ;....... :.... .. 7 Fossil Operations and Fuel Supply ........... ;..*.; ........................................................................ ,., .............. , .......... ;....., ........... ,... . 7 Purchases and Sales of Power ........................................................................................................................ ,*...................... . 7 Interconnections ................................................................................. :........................................................................................ . 8 Future Sources of Power.: ............................. ,.......................... ;..................... ,........ ,; ......... ,............ ,................... ,.... ,.................... . 8 8

~~:~Tlt~.~~~~r~fi;~~~~~.~::;:::::::::::::::::::::::;::::::::::::::::::;:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::,::::::::::::::::::::::::::::::: 9 Competition and, Strategic Imtiat1ves ............................................................ :.................... :.: .......................... :...... :.... :............. . 9 Wholesale Competition ............ :.:................... .'....... :..................... :.......: ..... ;.................... ;........ :.,.: ....... :: .. ,.............. :: ............. . 9 Retail Competition...... .'..................................................................................................................................................... ;..... . 9 Corporate Re-engineering ... :......................................................................................................, ......................................... ,.. . 10 Regulatory/Legislative Strategy ............... :.................................. ;... :.: ......... :... :: ......... :............... ,....................... :................ :... . 10 Conservation and Load Management ..., ..................... ,.................................. :.. : ....... :............ :............. ,.:.. ;.:: ........ :.................... . 10

2. Properties ........................................................................................................................................................................................ . 10
3. Legal Proceedings ......... :............ :........... ;.: ...:...... :................. :................... ;........... :.......... :.. :... :.:, ................. ,....... :...................... :... . 11
4. Submission of Matters to a Vote of Security Holders: ...........................................................................: ..... :..... :: ...... ;................ . 11

. PART 11*.

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 .................................................... . 13 Liquidity and Capital Resources ....................................... :...................... :................................................................................. . 13 Capital Requirements ................................................................................................................................................................. . 14 Results of Operations ................................................................................................................................................................. . 14 Future Issues ................................. ,.. ,....,. ................................... ,......,.., ..... *********:*.*****,********:*:*****************:,,**.:*************,*,**,*************** 17
8. Financial Statements and Supplementary Data........................... ,... :'........ : ...... :., .... T ........ : .. : ... : ...... : ......... : .................................. .. 21
  • 9. Changes in and Disagreement~ With Accountants on Accounting and Financial Dis'c!osure ............ '..! ..';.:.: ...... :.:: ....... :........ :.. . 44 PART III
10. Directors and Executive Officers of the Registrant ........................................................................................_............................. . 45
11. Executive Compensation .............................................................. :........................................................ :....................................... 47
12. Security Ownership of Certain Beneficial Owners and Management.. ................ :...... , ............. :.:.. ,...... : .......... :.. :.'.. :... :............... 51
13. Certain Relation.ships and Related Transactions ........ ,............. ,., ........................., ........ ,............... :.... ,.,., .., .. ,...... ,........ ,................
  • 51 PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..................................................................................................................................................................................... 52
  • PART*I,,,
  • ITEM 1. BUSINESS THE COMPANY Virginia Electric and Power Company was incorporated in Virginia in 1909 and has its principal office- at One James River Plaza, Richmond, Virginia 23219-3932, telephone (804) 771-3000. It is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion Resources); a Virginia corporation.

Virginia Electric and Power Company is a regulated public utility engaged in the generation, transmission; distribution and sale of electric energy within a 30,000 square mile area in Virginia and northeastern North Carolina. It transacts business under the nam~ Virginia Power in Virginia and underthe name North Carolfna Power in North.Carolina. It sell~ electricity to retail customers (including governmental agencies) and.to wholesale customers such as rural electric cooperatives and munic-ipalities. The Virginia service area co.mprises about 65 percent of Virginia',s total land area, but accounts for over 80 percent of its population. As used herein, the terms "Virginia Power" and the "Company" shall refer to the entirety' of Virginia Electric and Power Company, including; without limitation, its Virginia and North Carolina operations, and all of its subsidiaries. ** * * *

  • The Company has franchises or permits for electric operations in substantially all cities and towns now serv~d. It als*o has certificates of convenience and necessity from the Virginia State Coq,oratioil Commissfon. (the Virginia 'Commission) for service in all territory served at retail in Virginia. The North Carolina Utilities Commission (the North Carolina Commission) has assigned territory to the Company for substantially all of its retail service outside certain municipalities in North Carolina.*

The Company strives to operate its generating facilities- in accordance with prudent utility industry* practices and in conformity with applicable statutes, rules and regulati9ns. Like other electric utilities, the Company's*generating facilities are subject to unanticipated or extended outages for repairs, replacements oi: modifications of equipnwnt or otherwise to _comply with regulatory requirements. Such outages inay invoive.sigruficant expenditures not previously budgeted, including replace-ment energy costs.

The Company had 10,344 full-time employees ori December 31, 1995. A total of 3,746 of .the corn:pany's employees are represented by the International Brotherhood of Electrical Workers under a contract extending to March 31; 1998 ..

. J": '

  • For additional. information on significant corporate issues relating to the utility business, see _COMPETITION AND STRATEGIC INITIATIVES below.

Except for the historical information contained herein, the matters discussed in this annual report on Form lO~K are forward-looking statements which involve risks and uncertainties; including but not limited to regulatory, economic, compet-itive, governmental and technological factors affecting the Company's operations, rates, markets, products, services and prices, and other factors discussed herein and in the Company's other filings with the Securities and Ex~hange Commission.

REGULATION General

. In a wide variety of matters in addition to rates, Virginia Power is presently subject to ~egulation by the Virg1nia Cpm-mission and the North CaroHna Commission, the Environmental Protection ,Agency (EP~). pep~ment: of Energy (I>OE),

Nuclear Regulatory Commission (NRC), the Federal Energy Regulatory Commission (FERC), the Army Corps of Engineers, and other federal, state and local authorities. Compliance witµ 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 state and :federal governmental agencies having jurisdic-tion over various aspects of its business. Such approvals relate to, among other things, the environmental impact of such activities, the relationship of such activities to .the need for: providing adequate utility service and the design and operation of proposed facilities.

e e On January 11, 1996, the Virginia Commission granted interim approval for limited affiliate services between Virginia Power and a subsidiary, A&C Enercom, Inc., in connection with the purchase by the subsidiary of certain assets of two energy services businesses. On March 12, 1996, Virginia Power filed an amendment to its application seeking approval of additional services and asset transfers between it and the subsidiary.

The* City of Falls Church, Virginia has indicated that it intends to pursue the establishment of a. municipal electric system, and it sent the Company a formal Request for Transmission Service pursuant to Sections 211 and 213 of the Federal Power Act'on January 11, 1995. Virginia Power has approximately 4,100 customers in the City. Mwh sales by custom.er class in Falls Church are: Residential - 36,000; Commercial - 67,000; Industrial - O; and Other - 5,000. The Company denied the request and filed a Petition for Declaratory Judgment against the City with the Virginia Commission. The Commission has ruled that Falls Church rr:n.ist seek approval from the Commission prior to implementing plans to condemn Company facilities within the City. Revenues from retail sales within the City of Falls Church account for less than .2% of the company's total revenues. As a result, Virginia Power will not experience a material loss of revenues or net income should a municipal electric system be created. No other municipality has communicated to Virginia* Power any interest in forming a municipal electric system.

  • On September 18, 1995, the Virginia Commission established a proceeding to review and consider its policy regarding restructuring of, and competition in, the electric utility industry. The Commission directed its Staff to investigate *the emerg-ing issues in the industry and prepare a report of its findings and recommendations on or before March 29, 1996. All inter-ested parties may file written comments and requests for oral argument in response to the Staff Report on or before May 30, 1996.
Various provisions of the Energy Policy Act of 1992 (Energy Act) that could affect the Company include those provi-sions encouraging the development of non-utility generation, giving FERC authority to .order transmission access for whole-sale* transactions, requiring higher energy efficiency and alternative fuels use; restructuring of nuclear plant licensing proce-dures and requiring state regulatory authorities to give full rate treatment for the effects of conservation and demand management programs, including the effects of reduced sales. While the full impact of the Energy Act on the Company cannot at this time be quantified, it is likely," over time, to be significant.

FERC On March 29, 1995, FERC issued a Notice of Proposed Rulemaking that would require all FERC jurisdictional utilities to provide open access to the interstate transmission system. Crucial elements of the Commission's proposal included the followhtg: all jurisdictional utilities must file non-discriminatory open access transmission tariffs; utilities must take service under the open access tariffs for their own wholesale sales and purchases of electric energy; and utilities will be allowed the opportunity to recover stranded costs. The Company filed its comments on August 7, 1995 and supported the Commission's objective of promoting comparable open-access transmission service. However, the Company urged the Commission to reconsidet'its proposal to draft generic tariffs for the electric industry. The Company also challenged FERC's authority to impose tariffs of general applicability and urged the adoption of principles of comparability that it will apply to evaluate terms and conditions of tariffs filed by utilities. The Company urged .that any pro forma tariffs included in the final rule should provide for comparable service at rates that permit the utility to recover all its costs of service.

See COMPETITION AND STRATEGIC INITIATIVES under BUSINESS and Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Environmental From time to time, the Company may be identified as a potentially responsible party (PRP) with respect to a Superfund site. EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs, but the parties can then bring contribution actions against each other and seek reimbursement from their insurance companies. As a result of the Superfund Act or other laws or regulations regarding the remediation of waste, the Company may be required to expend amounts on remedial investigations and actions. Although the Company is not currently aware of any sites or events, including those sites currently identified likely to result in significant liabilities, such amounts, in the futm,:e, could be significant.

Permits under the Clean Water Act and state laws have been issued for all of the Company's steam generating stations now in operation. Such permits are subject to reissuance and continuing review.

2

e The Company is subject to the Clean Air Act (Air Act),* which provides the statutory basis for ambient air quality standards. In order to maintain compliance with such standards and reduce the impact of emissions on ambient air quality, the Company may be required to incur significant additional expenditures in constructing new facilities or in modifying existing facilities. The* Company has completed its compliance plan for Phase II of the Clean Air Act, with the exception of some

_additional studies concerning Phase II nitrogen oxide (NOx) controls. The plan will involve switching to lower sulfur coal, purchase of emission allowances and additional NOx and sulfur dioxide (SO) controls. Maximum flexibility and least-cost compliance _will be maintained through annual studies. Capital expenditures on Clean Air Act compliance over the next 5 years are projected to be approximately $61 million. Changes in the regulatory environment, availability of allowances, and emission control technology could substantially impact the timing and magnitude of compliance expenditures.

The Company continues to work with the West Virginia Office of Air Quality concerning opacity requirements applica-ble to the Mt. Storm Power Station.

For additional information on Environmental Matters, see Note Q to CONSOLIDA1ED FINANCIAL STAIBMENTS and I1EM 3. LEGAL PROCEEDINGS below.

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

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

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

On July 18, 1995, the Virginia Commission instituted an investigation regarding spent nuclear fuel disposal. It directed interested parties to provide comments on legal and public policy issues related to spent nuclear fuel storage and disposal, including, but* not limited to, whether to allow utilities to recover from ratepayers some or all money paid to the Nuclear Waste Fund established by the Nuclear Policy Act of 1982, whether to establish an escrow account for spent nuclear fuel storage and/or disposal, and whether utilities should develop their. own plans for storage and disposal of spent nuclear fuel.

The Commission's Order Establishing Investigation recites that Virginia Power has paid $343.6 million to the Nuclear Waste Fund through 1994, mcluding $44.8 million in 1994, and that future payments could exceed $400 million assuming its North Anna and Surry reactors continue to operate through the end of their existing operating licenses. Virginia Power and others filed comments on October 31, 1995. On February 27, 1996, the Commission Staff filed its Report recommending that adoption of a definitive policy on the spent nuclear fuel disposal fee be delayed until (1) a ruling is forthcoming on pending litigation which seeks to impose an obligation on the federal government to begin acceptance of spent nuclear fuel no later than January 31, 1998, (2) the outcome of proposed legislation which would amend the Nuclear Waste Policy Act to require the development of a centralized interim storage facility has been determined, and (3) a vision of the likely outcome of the electric utility industry's restructuring efforts has been more fully conceptualized.

  • 3

e e CAPITAL REQUIREMENTS AND FINANCING PROGRAM.

Construction and Nuclear Fuel Expenditures Virginia Power's estimated construction and nuclear fuel expenditures,.including. Allowance for Funds Used During Construction (AFC), for the three-year period 1996-1998, total $1.6 billion.. It has adopted a 1996 hu~get for construction and nuclear fuel expenditures as set forth below:

Estimated 1996 Expenditures (millions)

New Generating Facilities:

Clover*unit 2 .................................. ;;; ............... :.*. :....*... '..:.: ......... ;.. ,... :.. :.... :.. :....... ,.. :.. $* 14

, Other Production:

Clean Air Act ............................................................................................................ . 19 60 ..

Other ..................... :*:**:***********************************,***;*....... .':':.:.......... :..... :.*.. :.'..:.. :......... ::.:..... .

General Support Fac1hties .................................. ,.: ....... :.;: .. ::.,.: .. ,*.... :......... :... :., ............. . 88 Transmission.,.; .................................. :.... ,......'............. ,.! ..... ::......... : .... .'.. :....... :., ............. . 42 Distribution ........... ;.............. :........................... ;: ....... :................. .:.. '.. *-'*-'**: ........ :-.... :.:.::..... . 262 Nuclear Fuel .......................... ;......*......... :.: ... ,............... ;... ,............: .... :.. ,;.,.; .. ,,., ................ . 84 Total Construction Requirements and Nuclear Fuel...:: .. ,.;.: ... :.:: ........................ :.,., ..

  • 569 AFC ........................................................ *............................ :....... ,:... :..*. :...................
  • 5 Total Expenditures .. ,................... ,.... ,..... ::.* ........... :... :::: ..... ,: .. .': .......-.... :.: ... ;..... .': .... /... :.. ,* $574

' ., ( . *-.

  • Financing* Program . .

. In 1995, Virginia Power obtained $375 million from the sale of sechrities. With tlie proceeds of the 1995 securities sales, suppiemented by internally generated f~nds, the Company retired $312:3' iriilliort ofsecurities throllgh mandatory debt matu-rities and retired an additional $126.7 million of securities through optional redem.ptiorts. The Company's long-term financ-ings included $2b0 million of First and Refunding Mortgage Bonds, $40 Iiiillion of unsecured Medium-Term Notes, and $135 million of Preferred Securities issued by a subsidiary trust. * ** * * * * '

. Effective September 1, 1995, a $300 million revolving credit facility was.established to support the Company's com-mercial paper program, replacing the Inter-Company Credit Agreement with Dominion Resources. At December 31, 1995,

$169 million of commercial paper was outstan~ing. "

Virginia Power's 1996 construction and nuclear fuel requirements, exclusive of AFC, ate estimated to be $569 million.

Debt maturities in 1996 will total $259.6 million. It is expected that approximately .$601 million will be obtained from cash flow from operations. The remaining $227 .6 million of capital requirements will be obtained by a combination of sales of securities and short-term borrowings.

RATES.

The Company was subject to *rate regulation in *1995 as* follows:

1995 Percent Percent

. of of

. Non-Governmental customers ....................... . Virginia Commission 78% 73%

dovenvnental customer~ .............................. . Negotiated ,Agreement~ 10 12 North Carolina.retail ......................................... . *North Carolina ColllIIlissfon .. .5 4 Wholesale:

R:equirements ~ Sales for *.Resale .. :............. . FERC 5. 7 Non-Require~ents - Sales for Resale ....... . FERC 2 4 10,0% 100%

Substantially all of the Company's electric sales are subject to re~oveiy of ch'anges in fuel :costs either 'through fuel adjustment factors or periodic adjustments to base rates, each of which requires prior regulatory approval.

.4

e

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

The principal rate proceedings in which the Company was involved in 1995 are described below by jurisdiction. Rate relief obtained by the Company is frequently less than requested.

  • Virginia On January 13, 1995, the Supreme Court pf Virginia affirmed a decision of the Virginia Commission in Virginia Power's 1992 rate case that disallowed rate recovery of the gross receipts tax component of certain purchased power costs. On March 3, 1995, the Court denied the motions of Virginia Power and certain industrial cogenerators for a rehearing, and on October 2, 1995, the United States Supreme Court denied the Writ of Certiorari sought by those cogenerators.

On April 20, 1995, the Virginia Commission declined to approve Virginia Power's proposed Schedule DEF- Dis-persed Energy Facility, a rate schedule that would have allowed the Company to respond to the request of an industrial or commercial customer to build and operate a generating facility at its business location and to sell to that customer all of the ele~tricity and associated steam from that facility under a long-term contract. The Commission stated that the scope of the proposal was not an appropriate experiment under Virginia law, and that, without a specific construction proposal before it, the Commission could not approve the concept. The Commission stated, however, that upon a proper record it would con-sider the public interest of allowing a DEFstype facility to be constructed. Virginia Power subsequently negotiated a specific DEF arrangement with Chesapeake Paper Products.Company, and on December 18, 1995, it applied to the Virginia Commis-sion for the approvals required for that arrangement. (See COMPETITION AND STRATEGIC INITIATIVES below).

The Staff of the Virginia Commission has, in Virginia Power's Annual Informational Filing proceeding for 1994, recom-mended .that there be imputed to Virginia Power for rat.emaking purposes income r:eflecting (a) the estimated value of credit support.that Dominion Resources' nonu~ility subsidiaries allegedly receive from Virginia Power and (b) the income earned by Dominion Resources on. the invested proceeds of its unallocated equity for which Virginia Power provides the funds for payment of dividends. Virginia Pqwer filed a.respon'se opposing these l'.ecommendations. The Staff's reply agreed with Vir-ginia Power that no decision on these issues is required in the pending proceeding. On February 23, 1996, the Commission issued its Order, finding that the Company did not earn outside of its authorized range for the calendar year 1994, and indicating that it will investigate the described issues further in a subsequent proceeding. The Commission Order also approved higher collection levels for decommissioning of nuclear plants.

On April 20, 1995, the Virginia Commission authorized Virginia Power to implement a pilot program providing a real time pricing (RTP) option for its industrial customers with lo.ads in excess of 10 MW. Unde:r; this.option, all or a portion of an industrial customer's load growth would be supplied at projected incremental hourly production costs, adjusted for line losses and taxes, plus a margin of 0.6 cents per Kwh. Additionally, a marginal cost-based Generation Capacity Adder and a Trans-mission Capacity Adder would be applicable during those hours when the Virginia Power system is approaching its fore-casted annual peak demand. Up to 20% of an industrial customer's existing load could be served on an RTP basis if the customer executes a five-year contract for such service.

On September 19, 1995, Virginia Power filed an application to revise its annual fuel factor. The Company proposed that the present fuel factor be decreased by $97.1 million. The Staff of the Virginia Commission proposed certain adjustments, which Virginia Power did not oppose, resulting in a recommended reduction of $107.3 million. On October 31, 1995, the Virginia Commission app.roved the reduction of $107.3 million, effective November 1, 1995.

North Carolina On February 13, 1995, the Supreme Court of North Carolina denied Virginia Power's motion for rehearing of the appeal of its 1992 North Carolina rate case, which disallowed recovery of certain capacity costs paid to a cogenerator and a portion of the compensation of certain Company officers. On May 15, 1995, Virginia Power filed with the United States Supreme Court a Petition for a Writ of Certiorari asking the Court to reverse the North Carolina Court's decision as to the recovery of capacity costs. On January 22, 1996, the United States Supreme Court denied the Writ of Certiorari sought by the Company.

On June 27, 1995, the North Carolina Commission approved a Self-Generation Deferral Rate that is a part of an Energy Agreement between the Company and Weyerhaeuser. The agreement involves the use of a negotiated pricing structure which will resuH in the deferral of the installation of additional self-generation facilities by Weyerhaeuser. The rate to be charged 5

e e must be prefiled each year, and the Company is prohibited from recovering from other customers the difference between the new rate and the rate that Weyerhaeuser would otherwise have been charged.

On September 15, 1995, Virginia Power filed an application with the North Carolina Commission for approval of a $1.3 million annual increase in fuel rates. On December 8, 1995, the Commission approved an increase of $.8 million reflecting a disallowance of $.5 million by reason of resolution of issues surrounding the renegotiati,on of a coal transportation contract with CSX Transportation, Inc.

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

  • Surry Units 1 & 2, Surry, Va .............................................................................. . 1972-73 Nuclear . 1;602 North Anna.Units 1 & 2, Mineral, Va ................................................................ . 1978-80 Nuclear l,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 Unit" 1; Clover, Va.................................................. '. ........-......... :......... .. 1995 Coal 416(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 Yorkto_wn 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:

Chesterfield Units 7 & 8, Chester, Va......................_. ..... :*********************************** 1990-92 . Oil & Gas 397 Total fossil stations ............................. ,.............. ,._ ....... ;..................................... . 7,960 Hydroelectric:

Gaston Units 1-4, Roanoke Rapids, N.C ....................... :... ;; .................. :'.. ........ .-.. _* 1'963 Conventional 225 Roanoke Rapids Units 1-4, Roanoke Rapids, N.C. ............................................ 1955 Conventional 96 Other ......................................................... ;............................ , .....*. ;... ;....... :........... 1930-87 Conventional

  • 3 Bath County Units 1-6, Warm Springs, Va.***:**********************-******************************. 1985 . Pumped Storage _ 1,260(d)

Total hydro stations .................................................... ,.._.............. ,............_........ . 1,584 Total Company generating unit capability ...................................................... . 12,936 Net Utility Purchases .............. '. ................................................ ,. ............. :.................

  • 1,030 Non-Utility Generation .......................................................................................... . 3,295 Total Capability ................................................................................................ . 17;261 (a) Includes an undivided interest of 11.6 percent (208 Mw) owned by Old Dominion Electric Cooperative (OD~<:;).

(b) Includes an undivided interest of 50 percent (208 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 inter-est in the facility is owned by Allegheny Generating Company, a* subsidiary of Allegheny Power System, Inc. (A_PS).

  • The Company's highest one-hour integrated service area summer peak demand was 14,003 Mw on August 2, 1995, and a new all-time high one-hour integrated winter peak demand of 14,910 Mw was* reached on February 5, 1996.

6

e e

,'"t SOURCES OF ENERGY USED AND FUEL COSTS

  • * ' *
  • L * * ' * ' '

For information as to energy supply mix and the average fuel cost of energy supply, see Results of Operations under MANAGEMENT'S DiSCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Nuclear Operations and Fuel Supply In 1995, the Company's four nuclear units achieved a combined capacity factor of 85.4 percent.

The North Anna Unit 2 steam generator replacement.projectwas completed in 1995 at a total Company cost of$96 million.

The Company utilizes both long-term contracts and spot purchases to support its needs for nuclear fuel. Virginia Power's nuclear fuel supply and related services are expected to be adequate to support current and planned nuclear genera-tion requirements. The Company continually evaluates worlqwide market conditions in order to obtain an adequate nuclear fuel supply. Current agreements, inventories and markef availability should support planned fuel cycles throughout the.

remainder of the 1990s. * * * *

  • On-site spent nuclear fuel storage at the Surry .Pow~r Station is adequate for the Company's needs through 1998 when, in accordance with the Nuclear Waste Policy Act, the DOE is to begin acceptance of spent fuel for disposal. Should accept-ance be delayed, incremental dry storage facilities will be added under the existing storage license. North Ann~ Power Station will require an interim spent fuel storage facility in the late 1990's. The Company submitted a license application to the NRC in May 1995 for such a facility at North Anna. . . . . .

For details regarding nuclear insurance and certain related contingent liabilities as well as a NRC rule that requires proceeds from certain insurance policies to be used first to pay stabilization and decontamination expenses, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.

Fossil Operations and Fuel Suppl)'. .

The commercial operationof Clover Power Station Unit 1 commen,ced on October 7, 1995. The summer capability of Unit l .has beeri determined to be 416 Mw.

The Company's fossil fuel mix consists of coal, oil and natural gas. In 1995, Virginia Power consumed approximately 11.0 million toris of coal. As with nuclear fuel, the Company utilizes both long-term contracts and spot purchases to support its needs. The Company presently anticipates that sufficient coal supplies at reasonable prices will be available for the remainder of the 1990s. Current projections for an* adequate supply of oil remain favorable, barring unusual international events or extreme weather conditiO!lS 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 tur~ine units. For winter usage at the combined cycle sites, gas is purchased and stored during the summer and fall and consumed during the colder months when gas supplies are not available at favorable prices. The Company has firm transpor-tation contracts for the delivery of gas to the combined cycle units. Current projections indiciite gas supplies will be available for the next several years.

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

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

. . . i .

On November 26, 1991, the Company and ODEC signed an agreement whereby the Company will provide 100 Mw of firm capacity and associated energy until the commercial operation of Clover Unit 2 (currently scheduled for April 1996) or December 31, 1996, whichever occurs first.

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

7

e e Virginia Power also has 67 non-utility power purchase co~tratts with a ~oinbined dependable summer capacity of3,4~3 Mw. Of this amount, 3,295 Mw were operational at the end of 1995 with the balance scheduled to come on-line through 1998 (see Non:Utility Generation under FUTURE SOURCES OF POWER a,nd Note Q to CONSOLIDATED FINANCIAL STATEMENTS). . . . . .* .

Early in 1995, a wholesale power group was formed within the Company. Its .sole foc4s ts the purchase and sale of wholesale electric power in the open market. The wholesale power gro.up has expanded the Company's trading range beyond the geographic limits of the Virginia Power service territory, and has recently developed trading relatfonships with utilities in Illinois, Missouri, Indiana, Kentucky, Ohio, Vermont, Michigan, and Tennessee in addition to most states in the*Mid~Atlantic area.

INTERCONNECTIONS*

The Company maintains major interconnections with *c!h-o-lina Power ~nd Light Company; AEP, A.PS and th~ utilities in the Pennsylvania-New Jersey-Maryland Power Pbol. Thrmigh this major transmisiion network; th~ Company has*arrange-'

nients with these utilities for coordinated planning, . operation,**emergency assistaQce and exchange~'of cap~city

' . and energy; .

The Company and .Appalachian Power Company (Apco) (an operating' timt* ofAEP) have each '.sought approv~I fr~m the Virginia Commission to construct interconnecting transmission :facilities. Apco proposes to construct 116 miles of 765 Kv line to connect with Virginia Power's proposed 102 miles of 500 KV line. Virginia Power does J:!.Ot intend to build its facility uriless the Apco facility, which requires approval iri West Virginia as well as Virginia,. is, also approved and built. Appro'-;al of

, both facilities has been recommended by a Virginia Commission Hearing Examiner. On Pecember 13, 1995, .the Virginia Commission issued an Interim Order in the Apco c~se,in which it found that additional transmission capacity is needed but

  • directed Apco to provide further information* as. to routing, mitigation of visual impact, and uses of th.e line, .

FUTURE SOURCES OF PO,WER As reported earlier, both the Hoo~iei: 400 MW long-termpurchase'and the AEP 500 MW loiig-term pur~hase wili expir~

.on'December 31, 1999. With the sched~led termination of 900 MW.of long-temipurchases*and continued' system load growth, the Company presently anticipates addinf 1,400 Nj:W of short-term (three~year) purchases*throligh the ye~'*2000.

The Company has and will pursue capacity acquisition plans to provide tllat capacity and. maintain l:thigh degree of service reliability. This capacity may be owned and operated by others and sold to the Company or may be'builtby the Com:pariy if it determines it can build capacity at a lower overall cost. The Company- also pursu~s conservation 'and demand-side manage-ment (see CONSERVATION AND LOAD .MANAGEMENT below and Capital Requirements under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONPffiON ANP RESULTS OF OPERATIONS),* ' . * '* ,

In May 1990, *the"Company entf,red into an agreement with ODEC, unde; ~hi~h the Company pu~chase'd a 50,perc;ent undivided ownership interest in a 832 Mw c.oal-fired power station to be constructed Ilflat" Glover, Virginia in.Halifax County.*

Construction of Unit 1 is complete and it achieved commercial operation on Oct.ober 7; .1995. The CoQipany's 50 percent share of costs incurred ,through December 31, 1995 amounted to $500.7 .million. 'Constnictfon of Unit 2 is on schedule for completion in April 1996. The Company expects that completion costs for Unit 2 will t~tal $14 milliori. *, *

  • In March 1995, the Virginia Supreme. Court upheld the May \994* approval by the Virgiltja b,mniission ior a 75 mil,e 500 Kv tr~smission line from the Clo,ver Power Station to the. Carson Substation in Dinwiddi~_(:ounty,,Virginia. The trani-mission* iine is now under construction and is scheduled for. compl~tioil 4i*Aprif .l~Q.6'. . . , . . . . . . ., *. . ' .

The CompaI1f s ~ontinuing prog;am t~ meet future capacity requir~mtmts .is :s~~ariied'in the following table: .

Company Own~d Generation ..

Summer

.Capi!,bility * *. Expected **.' .

Name of Units. Mw *

  • In-Service Date Clover Power Station: ".
  • un1(2 - *
  • 416* *Aprir 1996

~.  : ..

  • Includes the 50 percent undivided ownership interest of O:DEC..
  • 8

Ntin-Utility Generation Number of Projects Mw Projects Operational 66 3,295 Projects Financed 1 198 Unfinanced Projects (j 0 Total Contracts . . . 67 3,493 For additional information, se~ Note Q to CONSOLIDATED FINANCIAL STATEMENTS.

COMPETITION A~D STRATEGIC. INITIATIVES In light of exis_ting and potential thre;i.ts and oppc;>rtunities brought about by increased competition in the wholesale and retail markets for electricity, the Company has µndert~en cosi~cutd.ng measures to maintain its position as a low-cost pro-ducer ofelectricity, engaged in re-engineering efforti qfjts core bllsiness processes, and pursued a strategi~ pfanning initia-tive, called Vision 2000, to encourage innovative approaches to serving traditional markets and to prepare appropriate meth-ods by which to service future markets. In furtherance of these initiatives, the Company has established separate business units for its nuclear operations, fossil -and hydroelectric operations, commercial operations as well as its energy services business. It has gained regulatory approval of innovative pricing proposals for industrial loads in Virginia and North Carolina, entered into an energy partnership with a key industrial customer, executed long term contracts with wholesale customers, increased its presence in a broader geographic market for wholesale sales of electricity, and acquired an existing energy services business to enhance its* national participation in that market. (See Note P to CONSOLIDATED FINANCIAL STATE:rvt;ENTS)

Wholesale Competition The Company has established long-term contrl;lctual seryice arrangements with all of its major wholesale cooperatives and municipalities. These contr11cts ,c_oritain multijea,r notice provisions. To date, the Company has not experienced any a

material loss of l_oad revenue .or net incoine,c:lue to comp~titionfor its traditional wholesale customers. In l995 ~holesale power group was formed within the Company to erig4ge in .the purcl;iase and sale of wholesale electric power. The group has*

expanded the Company's trading range ~eyoAd .the geographic limits of the Company's service territory and h~s developed trading relationships . with.

utilities thr~ughout ':~~ eastern

United States. .. . .

Retail Competition At present, competition for retail customers is limited. It arises primarily from the ability of certain business customers to relocate amorig utility service territorids;' to 'substitute' other energy sources for electric power and to generate their own electricity. while the Ene,rgy' .Policy\<\.d bans.'federal order's' of transrrtission service to ultimate clisfomers, 'broader retail

' competition that would allow customer's to choose among electric suppliers is the subject of intense debate in federal and state forums, both legislative and regulatory. ' ' ';. . ' ' ' .

A Retail Energy Services gro~p was formed in July 1995 and has begun developing non-traditional products and ser-vices to offer to customers b:oth inside*and outside' the service territory. These products and services include fuel procurement and risk management servites/electrical 'equipment mafotenance, power quality control, on-site tumk'ey industrial p6;er plant construction, and energy conservation systems. In December 1995, the Company launched the name EVANTAGESM for the retail energy services divisic;m to: establish a national brand identity for the business.

In December 1995, the Company entered into an agreement with a key industrial customer, Chesapeake Paper Products Company, to facilitate the design, construction, and financing of a 38 Mw cogeneration plant, in order to meet Chesapeake's energy requirements for its industrial processes., and appJied fo the Virginia Commission for the necessary approval of these arrangements. To expand the offering of a range of energy services, the Company, in January 1996, acquired two divisions of A&C Enercom of Atlanta, Georgia from Heartland Development Corporation of Madison, Wisconsin. The Company has formed a non-regulated subsidiary, A&C Enercom, Inc., which will provide marketing, program planning and design, cus-tomer engineering and energy services consulting to the utility industry. The new subsidiary has approximately 230 emplgy-ees in 15 offices located in 13 states.

9

e e In September 1995, the Virginia Commission launched an extensive investigation into restructuring of and competition in the electric utility industry. The scope of the investigation includes consideration of reliability, continuity and stability of rates, fairness to all customers, fairness to investors, and whether truly competitive markets that are in the public interest can be developed. The outcome of the investigation could impact the extent to which retail competition will exist within Virginia.

In July 1995, the North Carolina Utilities Commission declined to conduct an adversarial proceeding into the question of whether retail competition should be allowed in North Carolina. Instead, it is conducting an infornial proceeding to gather information.

The Company has initiated new programs aimed at meeting retail customers' needs for increased flexibility and control of their electric costs. The Company has implemented a real time pricing rate experiment for a five year period. The volun-tary rate is available to industrial customers with loads in excess of 10 Mw and allows a customer to move up to 20% of its existing load, plus any load growth, to the hourly pricing rate. In 1995 the Company also implemented a self-generation deferral rate for a North Car91ina industrial customer, Weyerhauser. As a result of the rate being approved, the Company will serve approximately 25-30 Mw of new load through at least May 1, 1999.

  • The Virginia Commission entered its Final Order on November 27, 1995 in the Company's Petition for Declaratory Judgment against the City of Falls Church. The Petition had been filed in light of Falls Church's municipalization proposal and request for transmission service under Sections 211 and 213 of the Federal Power Act. The Commission ruled that it has jurisdiction over the City and that the City must seek approval from the Commission prior to implementing plans to condemn Company facilities within the City. No other city has communicated to the Company any interest in forming a municipal electric system.

Corporate Re-engineering The Vision 2000 strategic planning initiative has generated efforts aimed at improving shareholder value as competitive threats intensify. Re-engineering and remissioning efforts have included reducing the number of operating divisions, consoli-dating district offices and closing business offices as work practices have been re-engineered to reduce costs and promote flexibility.

A review of Corporate Center functions has identified several activities that were not core business functions and which were subsequently outsourced to service providers. The Fossil and Hydroelectric Business Unit completed a redesign effort in*

1995. Re-engineering and restructuring efforts will continue in the Corporate Center, Commercial Operations.Business Unit, and Nuclear Business Unit in an effort to improve the Company's competitive capabilities. * *

  • Regulatory/Legislative Strategy Consistent with implementation of other Vision 2000 efforts, the Company has developed a regulatory/legislative strat-egy intended to establish an orderly transition to a more competitive environment. The regulatory/legislative proposals are aimed at achieving greater flexibility on the part of the Company and the Virginia Commissipn in setting overall rate levels as well as in setting rates for individual customers.

For additional information, see COMPETITION under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

  • CONSERVATION AND LOAD MANAGEMENT The Company is committed to integrated resource planning and has developed a detailed analysis procedure in which effective demand-side and supply-side options are both considered in order to determine the least cost method to satisfy the customers' needs. Demand-side programs are selected annually at Virginia Power through an integrated resource planning process which directly compares the stream of costs and benefits from supply-side and demand-side options. This process ensures the ultimate selection of a demand-side package which reduces the need for additional capacity while efficiently using the Company's existing generation facilities. '

ITEM 2. 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 10 J

el~ctric lines, but underlying titles have not been examined except for transmission lines of 69 K v or more. Where rights of way have not been obtained, they could be acquired from private owners by condemnation if necessary. Many electric lines are on publicly owned propei;ty ,as to which permission for use is generally revocable. Portions of the Company's transmis-sion lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line if any exists. **

The Company leases certain buildings and equipment. See Note H to CONSOLIDATED FINANCIAL STATEMENTS.

See Company Generating Units under SOURCES OF POWER under Item l. BUSINESS.

ITEM 3. LEGAL PROCEEDINGS From time to time, the Company may be in violation of or in default under orders, statutes, rules or regulations relating to protection of the environment, compliance plans imposed upon or agreed to by the Company or permits issued by various local, state and federal agencies for the construction or operation of facilities. There may be pending from time to time administrative proceedings involving violations of state or federal environmental regulations that the Company believes are not material with respect to it and for which its aggregate liability for fines or penalties will not exceed $100,000. There are no material agency enforcement actions or citizen suits pending or, to the Company's present knowledge, threatened against the Company.

Doswell Limited Partnership (Doswell) brought suit against Virginia Power in the Circuit Court of the City of Richmond alleging breach of contract and actual and constructive fraud and seeking damages of not less than $75 million arising* out of a disagreement on the calculation of a Fixed Fuel Transportation Charge to be paid to Doswell under a purchased power contract. The issues of actual and constructive fraud \V~re dismissed with prejudice, and on March 6, 1995, the Court entered its opinion in favor of Virginia Power. Doswell has appealed to the Supreme Court of Virginia, and briefs have peen filed.

Oral argument was held on January ,2, 1996. On March 1, 1996, the Supreme Court of Virginia affirmed the decision of the Circuit Court. On March 8, 1996; Doswell filed notice of its intent to seek a re-hearing. **

On December 13, 1995, a civil *action was instituted in the United States District .Court for the Eastern District of Virginia, Norfolk Division, against the City of Norfolk and Virginia Power by a landowner who alleges that his property has been contaminated by toxic pollutants originating on an adjacent property now owned by the city and formerly owned by the Company. The plaintiff seeks compensatory damages .of $10 million and punitive damages of $5 million from Virginia Power. Virginia Power and prior owners operated a gas manufacturing plant on the property until 1968, when the plant was cl9sed and dismantled. Virginia Power sold the property to the city in 1970. The Company filed its answer denying liabHity on January 10, 1996. * *

  • A dispute over corporate governance issues between Dominion Resources, Inc. and-Virginia Power arose in 1994, and the Virginia Commission instituted a proceeding concerning the holding company structure and the relationship between the two companies. This proceeding was continued generally and has been inactive since August 1994, when a related proceed-ing of broader scope was initiated by the Commission. On February 20, 1995, Dominion Resources, Virginia Power and the Commission Staff consented to an order in this proceeding under which Dominion Resources must obtain the. Commission's approval before taking steps such as acting in the place of Virginia Power's Board of Directors or officers, removing Virginia Power's Board members or officers or changing Virginia Power's articles of incorporation or bylaws. The Order remains effective until July 2, 1996. On April 12, 1995 the Staff of the Commission and its consultants filed a Final Report, which contains a summary of the proceedings and numerous recommendations by the consultants pertaining to the relationship between the two companies, _including recommendations relating to corporate governance issues, opernting relationships, including overhead allocations and financial controls, affiliate service arrangements and transactions, compensation to Vir-ginia Power for credit support perceived by the consultants to flow to Dominion Resources and its other subsidiaries, and possible regulatory tools for the Commission. In September 1995 Dominion Resources and Virginia Power each filed responses to the matters addressed in the Final Report. The Staff is scheduled to file its final response by March 15, 1996.

At this time, Virginia Power is unable to predict the ultimate resolution of these matters or their effect on the Company; ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 11

PARTII.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of the Company's Common Stock is owned by Dominion Resources.

During 1995 and 1994, the Company paid quarterly cash dividends on its Common Stock as follows:

1st 2nd 3rd 4th (Millions) 1995 ................................................ . . $100.3 $96.0 $99.2 $ 98.8 1994 ............................................... . $"97.7 $98.2 $99.0 $100.6 ITEM 6. SELECTED FINANCIAL DATA 1995 1994 1993 1992 1991

  • (Millions, except percentages)

Operating revenues .................................. . . $ 4,350.4 $ 4,170.8 $ 4,187.3 $ 3,679.6 $ 3,688.1 Operating income .................................... . 746.5 731.4 813.4 761.6 816.8 Income before cumulative effect of a change in accounting principle ........... . 432.8 447.1 509.0 455.2 487.4 Cumulative effect of a change in accounting principle ............................ . 14.3 Net income ......................:............. :.......... . $ 432.8 $ 447) $ .509.0 $ 469.5 $ 487.4 Balance available for Common Stock ... ,. . $ 388.7 $ 404.9 $ 466.9 $ 423.8 $ 435.9 Total assets ............................................... . 11,827.7 11,647.9 11,520.5 11,316.7 10,205.0

_Total net utility plant ............................... . 9,573.1 9,623.4 9,459.7 9,254.7 9,064.6 Long-term debt, noncurrent capital lease obligations, preferred stock subject to mandatory redemption and preferred securities of subsidiary trust ............... . 4,228.0 4,157.5 4,151.1 4,089.5 4,119.9 Utility plant expenditures (including nuclear fuel) .......................... ,.............. . . 577.5 660.9 712.8 716.5 727.8 Capitalization ratios (percent): * . . . "' ...

Debt ...................................................... . 47.2

  • 46.7 46.4 46.3 47.4 Preferred s'tock ............ :: .. :....... :.:. ........ :. 7.5 9.0 9.2 9.7 9.0 Preferred securities .. :............... ~ ........... . 1'.5 Common equity ................................... . 43.8 44.3 44.4 44.0 43.6 Emb.edded cost (percent):

Long-term* debt ............................... ;-... ;. 7;73 7.65 7.67 7.86 8:43

. Preferred stock ..................................... , . 5.29 5.47 4.88 5.38 6.54

. Preferred securities .............................. . 8.72 Weighted average_.*********:********:************* 7.41 7.29 7.18 7.42 8.11 12

_I

e e ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Liquidity and Capital Resources --

Cash flow from operating activities has accounted for, on average, 72% of the Company's cash requirements over the past three years.

With the near completion of the 832 Mw coal-fired power station near Clover, Virginia, the Company has entered, in 1995, a period in which internal cash generation will exceed construction expenditures. The internal generation of cash in 1994 and 1993 provided 88% and 84%, respectively, of the funds required for the Company's capital requirements.

Net cash provided by operating activities increased by $107.l million in 1995 as compared to 1994, primarily as a result of increased sales, partially offset by a number of other factors resulting from normal operations.

Net cash provided by operating activities decreased $4.6 million in 1994 as_ compared to 1993, primarily as a result of a rate refund of $129.2 million in 19~4, partially offset by a number of factors resulting from normal operations.

Cash from (to) financing activities was as follows:

1995' 1994 1993 (Millions)

Common stock .................................................................. :... . *$ 75.0* $ 50.0 Preferred stock ............................................................... ,...... . 150.0 Mortgage bonds._..'. ............................................................. :***- $ 200.0. 325.0 1,035.0 Medium-term notes .................................. ;.. ." ........................ . - 40,0 100.0 Pollution controi securities ..........._..........._..................... ;....... . 39.0 Preferred securities of subsidiary trust .................*.: .........-.... .. 135,0 Short-term debt ................................ ,... ,........................._..-.......

  • 169.0 Repayment of long-term debt and preferred stock .. ,......... .. (439.0) (334.3) (1,072.1)

Dividends .............................................................................. . (438.6) (438.2) (421.1)

Preferr~d securities distribution .......................................... .. (3.6)

Other .................................................................. :.......... '. ....... . (10.1) (50.8) (89.8)

Total ................................................ :.:: .............................. . $ (347.3) $ (284.3) $ (348.0)

The Company sold $200 million of First and Refunding Mortgage 'Bonds with an annual stated interest rate of 8.25% in

-March 1995. The proceeds were ~sed primarily to pay a portion of mandatory debt maturities. The Company sold $40 million of Medium-Term Notes with an annual stated interest rate of 6.35% in June 1995, the proceeds of which were used to meet a portion of the Company's capital requirements. During the year the Company retired a total of$312.3 million of debt securi-ties through mandatory maturities.

  • In 1995 the Company issued $135 million of Preferred Securities of a subsidiary trust. The proceeds _were used to redeem 450,000 shares of the Company's $7.20 Dividend Preferred Stock, 417,319 shares of the $7.30 Dividend Preferred Stock, and 400,000 .shares of the $7.45 Dividend Preferred Stock (total principal value of $126.7 million) and for other capital requirements.

In May and June 1995, the Company filed two shelf registration statements with the Securities and Exchange Commis-sion, one for $500 million of First and Refunding Mortgage Bonds and the other for $200 million of Medium-Term Notes, Series F, respectively, which combine to provide the Company with $700 million in unused capital resources. In addition, the Company has a Preferred Stock shelf, registered with the Securities and Exchange Commission, for $100 million in aggre-gate principal amount, which has not been utilized. The Company intends to issue securities from time to time to meet its capital requirements.

The Company has an established commercial paper program. Under the program $300 million of commercial paper may be outstanding at any point in time. This program is supported by a $300 million revolving credit facility which replaced the Inter-Company Credit Agreement with Dominion Resources, Inc .. Proceeds from the sale of commercial paper are primarily used to finance working capital for operations. As of December 31, 1995, net borrowings under the commercial paper pro-gram were $169 million.

13

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

1995 1994 1993 (Millions)

Utility plant expenditures ..................................................... . $ (519.9) $ (580.9) $ (644.9)

Nuclear fuel .......................................................................... . (57.6) (80.0) (67.9)

Nuclear decommissioning contributions .............................. . (28.5) (24.5) (24.4)

Pollution control project funds ............................................ . 8.4 6.9 32.7 Sale of accounts receivable, net .......................................... . (160.0) (40.0)

Other ................................................................... ,................. . (19.5) (8.3) (13.9)

Total ............................ ;............................................. ;.: ..... . $ (777.1) $ (726.8) $ (718.4)

Investing activities in 1995 resulted in a net cash outflow of $777.1 million primarily due to $519.9 million of construc-tion expenditures and $57 .6 million of nuclear fuel expe~ditures. Of the construction. expenditures, approximately

$42.7 million was spent on new generating facilities, $141.7 million on other production projects, and $286.8 million on transmission and distribution projects.

Capital Requirements The Company presently anticipates that kilowatt-hour sales will grow approximately 2 percent a year through 2010.

Capacity needed to support this growth will be provided through a combination of Company-constructed generating units, purchases from non-utility generators and other utility generators. Each of these options plays an important role in the Com-pany's overall plan to meet capacity needs.

  • The Company's construction and nuclear fuel expenditures (excluding AFC), during 1996, 1997 and 1998 are expected to aggregate $569.3 million, $530.3 million and $530.8 million, respectively.
  • Clover Unit 1 that is part of a two-unit facility jointly owned with ODEC, began commercial operation in October 1995.

The Company's fifty percent ownership share was completed at a cost of $289.6 million. The Company's annual depreciation and operations and maintenance expenses, for both units, are estimated to .be $15 million.

Construction continues on Clover Unit ;2 with an expected in-service date of April 1996. The Company's share of the cost of construction is approximately $225.1 million of which $14 million remains to be spent. After 1996, no new base lo.ad generation is expected to be needed until the end of the next decade. From 2000 until 2009, the Company will need to add peaking or intermediate units to meet anticipated demand .

. The Company will require $259.6 million to meet ~ong-term debt maturities in 1996. The Company presently estimates that, for 1996, all of its construction expenditures, including nuclear fuel expenditures, will be met through cash. flow from operations. Other capital requirements will be ~et through a combination of sales of securities and short-term borrowings.

Results of Operations The following is a discussion of results of operations for the years ended 1995 as compared to 1994, and 1994 as compared to 1993.

1995 Compared to 1994 Balance available for Common Stock decreased as compared to 1994, primarily as a result of restructuring costs recog-nized during 1995. Without restructuring costs, balance available for Common Stock in 1995 would have been higher by

$76.6 million.

  • 14

e Operating revenues changed primarily due to the following:*

Increase (Decrease) From Prior Year 1995 1994 (Millions)

Customer growth .......................... .. $ 76.2 $ 22.5 Weather .......................................... . 81.6 (8.8)

Change in base revenues .............. . 6.3 (35.0)

Fuel cost recovery ......................... . (8.9) (7.9)

Other, net ....................................... . ~)

Total retail. ................................. . 149.2 (29.2)

Sales for resale .............................. . 32.8 8.8 Other operating revenues .............. . ~) 3.9 Total revenues ............................ . $179.6 $ (16.5)

As detailed in the chart above, the increase in revenues is primarily due to the weather, i.e., increased heating and cooling degree days, experienced in the last six months of 1995, increased customer growth and increased sales for resale.

During 1995, the Company had 44,955 new connections to its system compared to 46,741 and 43,014 in 1994 and 1993, respectively.

Kilowatt-hour sales changed as follows:

Increase (Decrease) From Prior Year 1995 1994 Residential ..................................... . 4.1% (l.0)%

Commercial. .................................... . 3.6 0.8 Industrial ........................................ . 3.6 5.4 Public authorities ........................... . 4.0 (0.3)

Total retail sales ............................ . 3.8 0.7 Resale ............................................. . 13.4 4.1 Total sales ...................................... . 4.9 1.1 Cooling and heating degree days were as follows:

1995 1994 N~rmal Cooling degree days ...................... . 1,667 1,613 1,534 Percentage change compared to prior year.............. . 3.3% (5.2)%

Heating degree days ...................... . 3,790 3,515 3,662 Percentage change compared to prior year .............. . 7.8% (8.3)%

  • The increase in kilowatt-hour sales in 1995 as compared to 1994 reflects increased customer growth and the weather experienced in the last six months of 1995, partially offset by the milder weather experienced in the first six months of 1995.

The increase in kilowatt-hour sales in 1994 as compared to 1993 reflects the extreme weather experienced in January 1994, partially offset by lower sales during the second half of 1994 due to milder weather.

'./

The increase in sales for resale in 1995, as compared to 1994, was primarily due to weather experienced by other utilities in surrounding regions during the last six months of 1995 and increased marketing efforts by the Company.

15

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

Mills Per Kilowatt-hour 1995 1994 1993 Nuclear .................. :........................ . 4.92 4.89 4.60 Coal ................................................ . 14.44 14.61 14.69 Oil .................................................. . 25.11 23.00

  • 26.55 Purchased power, net .................... . 22.50 23.99 24.54 Other .............................................. . 23.82 25.46 24.35 Average fuel cost.. ......................... . 13.73 14.02 14.42 System energy output is shown below:.

Estimated Actual 1996 1995 1994 1993 Nuclear(*) .............................. ~ ........ . 33% 32% 34% 31%

Coal(**) .......................................... . 40 39 36 39 Oil ................................................... . 1 1 3 3 Purchased power, net.. ....................

  • 23 25 23 23
  • other ............................................... . 3 3 4 4 100% 100% 100% 100%

(*) 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 Restructuring - as part of the Vision 2000 program (see Note P to CONSOLIDATED FINANCIAL STATEMENTS), the Company recorded $117 .9 million of restructuring charges in 1995. Restructuring charges included severance costs, purchase power contract cancellation and negotiated settlement costs, capital project cancellation costs and other costs. As of Decem-ber 31, 1995, no material savings have been realized due to recently implemented, 1995 involuntary staffing reductions.

However, the Company estimates that these staffing reductions will result in annual savings, net of outsourcing costs, in the range of $50 milli.on to $60 million. The Company will incur additional restructuring charges in 1996. However, the amount of restructuring charges yet to be incurred is not known at this time. Furthermore, because the Company's review of its operations has not been completed, the amount of savings ultimately to be realized cannot be estimated at this time. When realized, the savings will be reflected in lower construction expenditures as well as lower operation and maintenance expenses.

Operation - other and maintenance decreased as compared to 1994. Expenses during 1994 included payroll and volun-tary separation costs for those employees who elected to terminate service with the Company under the 1994 Early Retire-ment and Voluntary Separation Programs, offset in part by recognition of insurance policyholder distributions. Expenses in 1995 reflected a decrease in payroll costs due to reduced staffing levels and weather-related overtime, offset by 1995 salary increases and the impact of employees being reassigned from capital to operation and maintenance activities. In addition, 1995 expenses include expenses associated with the North Branch Power Station, increased obsolete inventory costs, increased accruals for employee benefits, and increased nuclear outage costs.

Interest Charges - interest on long-term debt increased as compared to 1994 primarily as a result of higher interest rates on First and Refunding Mortgage Bonds and Pollution Control Notes.

Interest Charges - other increased in 1995 primarily as a result of a reduction of $10.6 million in the interest accrued for prior years on certain tax obligations in 1994.

1994 Compared to 1993 Operation expenses-other increased as compared to 1993 primarily as a result of recognition of costs associated with the Early Retirement and Voluntary Separation Programs offered by the Company in 1994.

Income taxes-operating decreased as compared to 1993 primarily as a result of decreased pretax book income.

Interest charges-other decreased in 1994 primarily as a result of a reduction of $10.6 million in the interest accrued for prior years on certain tax obligations.

16

_I

Future Issues Utility Rate Regulation Regulatory policy continues to be of fundamental importance to the Company and to its financial performance.

The cost of purchased capacity constitutes a large category*of cost incurred in the Company's operations. The Virginia Commission has authorized rates providing for the current recovery of the ongoing level of capacity payments. Moreover, the Virginia Commission has established and reaffirmed deferral accounting that is intended to ensure dollar for dollar recovery of reasonably incurred capacity costs.

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 through the ratemak-ing 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.

Environmental Protection and Monitoring Expenditures The Company incurred $68.3 million, $67.3 million and $72.2 million (including depreciation) during 1995, 1994 and 1993, respectively, in connection with the use of environmental protection facilities and expects these expenses to be approx-imately $68.3 million in 1996. In addition, capital expenditures to limit or monitor hazardous substances were $23.4 million,

$47.3 million and $94.4 million for 1995, 1994 and 1993, respectively. The amount estimated for 1996 for these expenditures is $24.5 million.

Clean Air

. Act Compliance. . . ...

The Clean Air Act, as amended in 1990, requires the Company to reduce its emissions of sulfur dioxide (SO) and nitrogen oxides. Beginning in 1995, the S02 reduction program is based on th.e 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 has installed S02 control equipment on Unit 3 at Mt. Storm Power Station. The S02 .control eqU:ipm~nt began operation on October 31, *1.994. The cost of this and related equipment was $147 million. The Company has co.mpleted its compliance plan for Phase II of the Clean Air Act, with the exception of some additional studies concerning Phase II nitrogen oxide NOx controls. The plan will involve switching to lower sulfur coal, purchase of emission allowances and additional NOx and S02 controls. Maximum flexibility and least-cost compliance will be maintained through annual studies.

Capital expenditures on Clean Air Act compliance over the next 5 years are projected to be approximately $61 million.

Changes in the regulatory environment, availability of allowances, and emission control technology could substantially impact the timing and magnitude of compliance expenditures.

  • Electromagnetic Fields The possibility that exposure to electrom~gneiic fields emanating from power lines, household appliances and *either electric sources may result in adverse health effects has been a subject of increased public, governmental and media attention.

A considerable amount of scientific research has been conducted on this topic without definitive results. Research is continu-ing to resolve scientific uncertainties. It is too soon to tell what, if any, impact these actions may have on the Company's financial condition.

  • 17

---i e e Nuclear Operations In 1995, the Company's four nuclear units operated at a combined capacity factor of 85.4%, reflecting a world record 69 day refueling/steam generator replacement outage at North Anna l.Jnit 2, a 46 day refueling/IO-year in-service inspection outage at Surry Unit 2 and a 43 day refueling outage at Surry Unit 1. Nuclear refueling outages typically occur every 18 months and last approximately 48 days. When nuclear units are refueled, the Company replaces the power from nuclear generation with *other more expensive sources. A reduction in the length of an outage should result in increased availability of low-cost nuclear generation, thereby lowering generation expenses: Three normal refueling outages are currently scheduled in 1996. The Company's goal is to reduce future refueling outages from an average of 48 days to 35 days.

The NRC revised the nuclear power plant license renewal rules issued in 1991. The Company intends to work with industry groups on license renewal programs, and apply for renewal of the current 40-year licenses by 1999.

In addition to improving nuclear unit productivity and efficiency, the Company has completed engineering analyses and evaluations to support uprating the capability of the units. The plant modifications have been completed at both North Anna and Surry. The.upgraded core improvement at North Anna Power Station has resulteq in a 4.2% increase in the gross electri-cal output for each. of the. units. A similar project for uprating Surry Units 1 and 2 was completed in 1995 and resulted in a 4.3% increase in the gross electrical output for each of the units.

For information on nuclear decommissioning, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.

Competition In light of existing and potential threats and opportunities brought about by increased competitiori in the wholesale and retail markets for electricity, the Company has undertaken cost-cutting. measures to maintain its position as a low-cost pro-ducer of electricity' eng*aged in re-engineering efforts of its core business processes, and pursued a strategic planning initia-tive, called Vision 2000, to encourage innovative approaches to serving traditional markets and to prepare appropriate meth-ods by which to service future markets. In furtherance of these initiatives, the Company has established separate business units for its nuclear operations, fossil and hydroelectric operations, commercial operations as well as its energy services business. It has gained regulatory approval of innovative* pricing proposals for industrial loads in Virginia and North Carolina, entered into an energy-partnership with a key industrial' customer, and in January 1996, acquired two divisions of A&C Enercom of Atlanta, Georgia from Heartland Development Corporation of Madison, Wisconsin. The Company has formed a non-regulated subsidiary, A&C Enercom, Inc., which will provide marketing, program planning and design,'customer engi-neering and energy consulting services.

As part of the Company's Vision 2000 initiatives, the Company developed a regulatory/legislative strategy intended to establish an orderly transition to a more competitive environine.nt. The Company supported a number of legislative proposals during the 1996 sei;sion of the Virginia General Assembly* that are aimed at achieving greater flexibility for the Virginia Commission and the Company. All the proposals supported by the Company were passed in amended form by both houses of the General Assembly. After passage, the Governor recommended an amendment to one of the proposals, which was then considered and passed by both houses. The remaining proposals await action by the Governor. The legislation will:

  • allow the Virginia Commission to approve 1) alternative forms of regulation (including, but not limited to, price regulation, ranges of authorized returns, categories of services and price indexing) that may serve as a transition to a more market-based electric utility industry and 2) economic development rates and packages of incentive rates and services. customized to meet individual custorner needs; . .
  • facilitate a regulated utility's ability to enter into joint ventures and partnerships;
  • bring federal customer accounts served in Virginia under limited jurisdiction of the Virginia Commission, thus ena-bling the Virginia Commission to address any "stranded investment" issues that may arise due to changes in federal policy;
  • clarify that a local referendum must be held before municipalization of utility services can occur for services previ-ously provided by a utility;
  • allow the Virginia Commission to establish for use in a condemnation proceeding the amount of stranded investment payment, if any, that is appropriate when a corporation possessing the power of eminent domain seeks permission to condemn the property of another corporation possessing the power of eminent domain.

18

- e The Company will continue to be affected by the developing competitive market in wholesale power. Under the Energy Policy Act of 1992, any participant in the wholesale market can obtain a FERC order to provide transmission services, under certain conditions. In 1995 a wholesale power group was formed within the Company to engage in the purchase and sale of wholesale electric power. The group has already developed trading relationships beyond the geographic limits of the Com-pany's retail service territory.

In 1995, FERC issued a Notice of Proposed Rulemaking (NOPR) regarding open-access transmission service and a NOPR regarding real-time information networks and standards of conduct. The real-time information network would provide transmission users data concerning the availability of transmission service on a same-time basis. The Company filed com-ments in both proceedings supporting FERC's objective to promote comparable open-access transmission service, however, the Company urged FERC to rethink its suggestion of functional unbundling to insure the continued reliability of the trans-mission system.

At present, competition for retail customers is limited. It arises primarily from the ability of certain business customers to relocate among utility service territories, to substitute other energy sources for electric power and to generate their own electricity. While the Energy Policy Act bans federal orders of transmission service to ultimate customers, broader retail competition that would allow customers to choose among electric suppliers is the subject of intense debate, both legislative

  • and regulatory. If such competition were to develop, it would have the potential to shift costs among customer classes and to create significant transitional costs ..

Potential competition also exists for the Company's sales to its wholesale cooperative and municipal customers. How-ever, nearly all.of this service is under contracts with multi-year notice provisions. To date, the Company has not experienced any material loss *of load, revenues or net income due to competition for its customers. The Company believes it has a strong capability to meet future competition.

The City of Falls Church, Virginia, has indicated that it intends to pursue the establishment of a municipal electric system. In response to a Company petition, the Commission has ruled that it has jurisdiction over the City and that the City must seek approval from the Commission prior to implementing plans to condemn Company facilities within the City. Reve-nues from retail sales within the City of Falls Church account for less than .2% of the company's total revenues. As a result, Virginia Power will not experience a material loss of revenues or net income should a municipal electric system be created.

No other city has communicated to the Company any interest in forming a municipal electric system.

In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", the Company's financial statements reflect assets and costs based on current cost-based ratemaking regulations. Continued accounting under SPAS 71 requires that the following criteria be met:

a) A utility's rates for regulated services provided to its customers are established by, or are subject to approval by, an independent third-party regulator; b) The regulated rates are designed to recover specific costs of providing the regulated services or products; and c) In view of the demand for the regulated services and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover a utility's costs can be charged to and collected from custom-ers. This criterion requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.

A utility's operations or portion of operations can cease to meet these criteria for various reasons, including a change in the method of regulation or a change in the competitive environment for regulated services. A utility whose operations or portion of operations cease to meet these criteria should discontinue application of SFAS 71 and write-off any regulatory assets and liabilities for those operations that no longer meet the requirements of SFAS 71. The Company's operations currently satisfy the SFAS 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company's results of operations and financial position may result.

Recently Issued Accounting Standards In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS)

No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which must be adopted by the Company by January 1, 1996. This statement requires the Company to review long-lived assets for impair-ment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable and requires rate-regulated companies to write-off regulatory assets against earnings whenever those assets no longer meet the criteria for recognition of a regulatory asset as defined by SFAS 71.

The Company has operated and continues to operate in a regulated environment. Under regulation, the Company's rates are intended to recover its cost of providing service, including the opportunity to earn a return on shareholder's investment.

19

e e In this regulated enviro11111ent, the CoIUpany's long-lived assets are generally included in rate base and the depreciation thereof is included in cost of service. As long as the Company continues to operate within cost-based regulation and the Company's long-lived assets are provided for in the Company's regulated rates, the Company would not experience impair-ment writ~~downs for assets held and used in providing electric service.

If, however, the service potential of an asset used in utility operations is impaired by an adverse event, the Company would evaluate the nature of the event and whether to seek specific rate recovery for that amount. If specific rate recovery is permitted by regulators, the Company would recognize a regulatory asset instead of charging the impairment write-down to operations.

From time to time, the Company may decide to dispose of long-lived utility assets previously used in operations but no longer needed. Under SPAS No. 121, the Company will determine the fair value*less the cost to sell such assets. To the extent such amount is less than the carrying amount for that asset, the Company would recognize a loss. If specific rate recovery is permitted by regulators, the Company would recognize a regulatory asset instead of charging the loss to operations.

Based on the Company's current operating environment, adoption of SPAS 121 is not expected to have a material impact. However, as discussed under Competition, the Virginia Commission has established a proceeding to examine the issue of competition ancl the regulatory framework in Virginia. In addition, FERC has initiated proceedings to address open-access transmission policy. If future regulatory reform should provide for a departure from cost-based regulation, regulators, electric utilities and other parties involved in the restructuring of the electric industry would face significant issues. One such issue is concerned with potential "stranded investment." Stranded investment represents costs incurred or commitments made by utilities under traditional cost-based regulation based on an obligation to serve supported by an implicit promise to recover prudently incurred costs that may not be reasonably expected to be recovered. Regulatory assets recognized under SPAS 71, unrecovered investment in power plants and commitments such as long-term purchased power contracts are items that may become stranded investment if prices for electric services are bas.ed on market rather than the c.ost of providing that service.

The Company expects to continue to operate under regulation and to recover its cost of providing traditional electric service. However, the form of cost-based rate regulation, under which the Company operates, may evolve in the future to accommodate changes in the industry and to address issues such as recovery of potential stranded investment. At this time, Company management can predict neither the ultimate outcome of the regulatory reform initiatives in the electric utility industry nor the impact such changes would have on the Company.

Other Except for the historical information contained herein, the matters discussed in this annual report on Form 10-K are forward-looking statements which involve risks and uncertainties, including but not limited to regulatory, economic, compet-itive, governmental and technological factors affecting the Company's operations, rates, markets, products, services and prices, and other factors discussed herein and in the Company's other filings with the Securities and Exchange Commission.

20

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

Report of Management...................................................................................................................................... 22 Report of Independent Auditors .............................................................................................. ..... .................... 23 Consolidated Statements of Income for the years ended December 31, 1995, 1994 and 1993.................... 24 Consolidated Balance Sheets at December 31, 1995 and 1994...................................................................... 25 Consolidated Statements of Earnings Reinvested in Business for the years ended December 31, 1995, 1994 and 1993......................................................................................................................................................... 27 Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993 ............ 28 Notes to Consolidated Financial Statements.................................................................................................... 29 21

e (This Page Intentionally Left Blank)

e REPORT OF MANAGEMENT.

The Company's management is responsible for all information and representations contained in the Consolidated Finan-cial Statements and other sections of the Company's ~ual report on Form 10-K. The. ,Conso}idat~d Financial Statements, which include amounts based on estimates and judgments of m!lllagem~!1t, have been .prepared in co.nformity with geperally accepted accounting principles. Other financial information hi the Form 10-K is cotu~iste.nt ~tth that*. in ipe

  • Con~qlidated Financial* Statements. * * * '* ** * *
  • 1
  • i ;_ 1**,.: *...

Management maintains a system of-internal accounting controls _designed to provide reasonable a:ssurance,,ata reason-able cost, that the Company's assets are safeguarded agajnst loss-from unauthorized use or disposition and that transactions are executed and recorded in accordance with established _pro~ed~e.s. Management reco~nizes the. inherent limitations. of any system of intei:n,al accounting control and, .therefore cannot provide .aJ>.solgte assurance that.the objectives of the. estab}ished internal accounting controls will be met. This system include.s written policies, an organizati~rial structure designed to;ensure appropriate segregation_ of responsibilities, careful selection aqd traiI,llllg* of qualified, persorihel and iI1ternal audits. Manage-merit believes that du~ng 19.95. the sys~m of int(?m~r 'control w_as adequate to accorµP,,ish tpe _intende,d objective.'. *...*.

  • The Consolidated Financial Statements have been audited by Deloitte & ToucheLLP, iI1dependent auditors, who have been engaged by the. Board. of Directors. Their aud_its were conducted in a,ccordance* with' genetl'llly accepted auditing stan- .

<lards and included a review of the Company's acc6urittng systems, procedures and iriter;nal controls, and tl}.e peifoi"rbance* of

  • tests and other auditing procedures sufficient to provide reasonable a~surance that the Consolidated Finiuicial Statem*ents 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, inter-nal accounting control and financial reporting matters and to ensure that each is properly discharging .its responsibilities. Bqth the independent auditors and the internal auditors periodically meet alone With the Audit Committee and.have*free access to the Committee at any time. .

a

  • Management recognizes its responsibility for fostering strong ethical cHmate so that the Company's *affairs*are con-ducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Company's Code of Ethics, which is distributed throughout the Company. The Code of Ethics addresses, among other things, the importance of ensuring open communication within the Company; potential conflicts of interest; compliance with all domestic and foreign laws, including those relating to financial disclosure; the confidentiality of proprietary information; and full disclosure of public information.

VIRGINIA ELECTRIC AND POWER COMPANY J. T. Rhodes E. M. Roach, Jr.

  • Presiqent and Senior Vice President-Finance, Chief Executive Regulation & General. Counsel Officer 22

e e REPORT OF INDEPENDENT AUDITORS To the Board of Directors *of Virginia Electric and Power Company:

' We have audited the' accompanying consolidated bal~ce she~fs 'of Virginia' ~lectric and' Po:wer (:ompany' (a, wholly.-

owned subsidiary of Dominion Resources, Inc.) and subsidiaries as of December 31, 1995 and 1994 gnd. the .related consoli-dated statements of income, earnings reinvested in business, and cash flows for each of the three yeaisfo.'tlie penod ended December 31, 1995. These financial statements are the responsibility ofthe*Compiui.y's management*Our responsibility is to express an opinion on these financial statements based on-our audits:**.: * * * * *: '. * .

we conducted oux:*a~ciits iri accordance ~ith geI1eritU;, accepted audttirig s~d~cts. Those'stand~cts.~equtie tli~t'Ye pl~n and perform the audit to obtain reasonable assuran.ce abqut:whether the'firiancial stiiterrients are free of material misstl,ltement.

An audit includes examilµng,. on a test basis, evidence. supporting llie amounts arid q.isclosure~ *in The *fin~cial *s.tatements .. An audit also includes assessing _the ac~ounting principles *~sed .and signifi~ant estimates niade,'hy i:p.anagerrient; as .weU as evalu-ating the overall financial statement presentation. We believe that our audits provide a reasonable.basis for our*opinion. *

. . In our opi~ion, such *consolidated finap.c~al .statem~nts' present fairly, .in ,iill ~iiteriai\~sp~cts, \ni fin~p~i~i p~~ition. of the companies* at Decemt;,er. 3J, 1995 and 1994 and the results' of their ()peratfons. and, their. c~s4 tJqws Joi:. ~ac:h of the three years 'in the ' period ended ..December

.31, 1995, .,in conformity with generally accept~d accounting prj.Iicipl~( .

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  • DELOI'ITE' & TOUCHE LLP . '

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Richmond, Virginia February 2, 1996 . :1,, . ' .~ r,* ,: * '.* *: j'

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23

e VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1995

  • 1994 1993 (Millions)

Operating revenues ..................................................... :.................. . $4,350.4 $4,170.8 . $4,187.3 Operating expenses:

Operation: . .

Fuel, net .................. :......................................., .............. '. ....... ,. 1,006.9 973~0 959.5 Purchased power capacity, net ............................................... . 688.4 669.4 646.1 Other ................................................................................... ,... . 543.8 577.4 525.7 Maintenance ............................................................................... . 260.5 263.2 2795 Restructuring .............................................................................. . 117.9 . .

Depreciation and amortization ........................... ,...................... . 469.1 446.3 . 426,8 Amortization of terminated construction project costs ............ . 34.4 34.4 36.1 Taxes - Income ........................................................................ . 228.1 223.0 253.5

-Other ........................................................................... . 254.8 252.7 246.7 Total ................................................................................... . 3,603.9 3,439.4 3,373.9

.Operating income .......................................................................... . 746.5 . 731.4 813.4 Other income ................................................................................. . 6.7 10.9 11.4 Income before interest charges ..................................................... . 753.2 742.3 824.8 Interest charges:

Interest on long-term debt. .............................. ;......................... . 302.6 291.9 300.2 Other .......................................................................................... . 20.1 7.5

  • 19.1 Allowance for borrowed funds used during construction ....... . (4.7) (4.2) (3.5)

Total ................................................................................... . 318.0 295.2 315.8 Distributions - preferred securities of subsidiary trust, net ....... . 2.4 Net income ..................................................................................... . 432.8

  • 447.1 509.0 Preferred dividends ........................................................................ . 44.1 42.2 42.1 Balance available for Common Stock ....................................... :.. . $ 388.7 $ 404.9 $ 466.9 The accompanying notes are an integral part of the financial statements.

24

e e VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Assets At December 31, 1995 1994 (Millions of Dollars)

UTILITY PLANT:

Plant (includes plant under construction of $512.1 in 1995 and $828.2 in 1994) ................................................ ,........................................................ . $14,201.6 $13,896.6 Less accumulated depreciation ............ :....................................................... . 4,760.9 4,426.9 9,440.7 9,469.7 Nuclear fuel (less accumulated amortization of $703.6 in 1995 and

$663.5 in 1994) ........................................................................................ . 132.4 153.7 Total net utility plant ........... :................................................................ . 9,573.1 9,623.4 INVESTMENTS:

Nuclear decommissioning trust funds ........................................................ .. 351.4 260.9 Pollution control project funds ................................................................... .. 11.9 20.3 Other ............................................................................................................. . 21.0 21.1 Total net investments ............................................................................ . 384.3 302.3 CURRENT ASSETS:

Cash and cash equivalents ............................................... :........................... . 29.8 28.8 Customer accounts receivable (less allowance for doubtful accounts of

$1.7 in 1995 and 1994) ........................................................................... .. 362.6 202.7 Accrued unbilled revenues ............................................................................. 179.5 97.4

. Materials and supplies at average cost or less:

Plant and general ...................................................................................... . 160.2 186.7 Fossil fuel ............. :............................:....................................................... . 71.2 122.9 Other ............................................................................................................. . 133.5 104.9 Total current as~ets ............................................................................... . 936.8 743.4 DEFERRED DEBITS AND OTHER ASSETS:

Regulatory assets ...........,.............................................................. :............. :.. . 816.4 871.0 Unamortized debt issuance costs ................................................................. . 26.6 22.8 Other ............................................................................................................. . 90.5 85.0 Total deferred debits and other assets ................................................ .. 933.5 978.8 Total assets ............................................................................................ . $11,827.7 $11,647.9 The accompanying notes are an integral part of the financial statements.

25

VffiGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Liabilities and Shareholders' Equity At December 31, 1995 1994 (Millions of Dollars)

LONG-TERM DEBT ....................................................................................... . $ 3,889.4 $ 3,910.4 COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST* ........................ . 135.0 PREFERRED STOCK:

Preferred stock subject to mandatory red.emption ...................................... . 180.0 221.7 Preferred stock not subject to mandatory redemption ................................ . 509.0 594.0 COMMON STOCKHOLDER'S EQUITY:

Common Stock, no par, 300,000 shares authorized, 171,484 shares outstanding at December 31, 1995 and 1994 ........................................ .. 2,737.4 2,737.4 Other paid-in capital. .................................................................................... . 16.9 20.4 Earnings reinvested in business ...................................._. ...,. .......................... . 1,272.5 1,277.8 Total common stockholder's equity ................ :........................................ . 4,026.8 4,035.6 CURRENT LIABILITIES:

Securities due within one year .................................................................... . 259.6 312.2 Short-term debt ............................................................................................. . 169.0 Accounts payable, trade ............................................................................... . 310.7 318.3 Customer deposits ........................................................................................ . 55.4 55.0 Payrolls accrued ............................................................................................ . 77.7 59.5 Severance costs accrued ............................................................................... . 42.5 Interest accrued ............................................................................................. . 101.8 96.2 Other ............................................................................................................. . 99.0 107.9 Total current liabilities ............................................................................. . 1,115.7 949.1 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred income taxes ............................................................ . 1,498.8 1,466.7 Deferred investment tax credits ................................................................... . 272.2 289.2 Deferred fuel expenses ................................................................................. . 57.7 51.5 Other ............................................................................................................. . 143.1 129.7 Total deferred credits and other liabilities .............................................. . 1,971.8 1,937.1 COMMITMENTS AND CONTINGENCIES (See Note Q)

Total liabilities and shareholders' equity ................................................. . $11,827.7 $11,647.9

(*) As described in Note (J) 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.

26

e e VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF EARNINGS REINVESTED IN BUSINESS For the Years Ended December 31, 1995 1994 1993 (Millions)

Balance at beginning of year ........................................................ . $1,277.8 $1,269.3 $1,182.7 Net income ..................................................................................... . 432.8 447.1 509.0 Total ....................................................................................... . 1,710.6 1,716.4 1,691.7

~ash dividends:

Preferred stock subject to mandatory redemption ................... . 13.5 14.4 17.2 Preferred stock not subject to mandatory redemption ............. . 30.8 28.3 25.0 Common Stock .......................................................................... . 394.3 3955 378.9 Total dividends ...................................................................... . 438.6 438.2 421.1 Other additions (deductions), net .................................................. . 0.5 (0.4) (1.3)

  • .Balance.at end of year .................................................................. . $1,272.5 $1,277.8 $1,269.3 The accompanying notes are an integral part of the financial statements.

27

e VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1995 1994 1993 (Millions)

Cash Flow From Operating Activities:

Net income ................................................................................................ . $ 432.8 $ 447.1 $ 509.0 Adjustments to reconcile net income to net cash provided by operatii:ig .activities: . .

Depreciation and amortization .................. :...................................... . 585.1 558.3 546.6 Allowance for other funds used during construction ..................... . (6.7) (6.4) (5.1)

  • Deferred income taxes; .................................................................... . 11.8 56.7 (6.7)

Deferred investment tax credits ....................................................... . (16.9) (17.1) (19.2)

Noncash return on terminated construction project costs - pretax (8.4) (10.3) (11.9)

Deferred fuel expenses, net. .......................... ;.................................. . 6.2 (2.6) (36.1)

Deferred capacity expenses ................ ,................................ ;............ . 6.4 26.5 72.9 Restructuring ..................................................................................... . 96.2 Changes in:

Accounts receh'.able ...................................................................... . (54.3) 36.5 (33.6)

Accrued unbilled revenues ............................................................ . (27.7) 11.9 (6.3)

Materials and supplies .................................................................. . 61.1 (6.5) 27.5 Accounts payable, trade ................................................ *............... . (8.9) 21.1 18.4 Accrued expenses ......................................................................... . 44.7 (29.0) 28.2 Provision for rate refunds ..... :....... ;.... ;..............-........................... . (12.2) (89.5) (87.6)

Other ... ,............................................................................................. . 16.2 21.6 26.8 Net Cash Flow From Operating Activities ................................................. . 1,125.4 1,018.3 1,022.9 Cash Flow From (To) Financing Activities:

Issuance of Common Stock ..................................................................... . 75.0 50.0 Issuance of preferred stock ...................................................................... . 150.0 Issuance of long-term debt. ...................................................................... . 240.0 464.0 1,035.0 Issuance of preferred securities of subsidiary trust ................................ . 135.0 Issuance (Repayment) of short-term debt ............................................... . 169.0 (43.0) (6.5)

Repayment of long-term debt and preferred stock ................................. . (439.0) (334.3) (1,072.1)

Common Stock dividend payments ......................................................... . (394.3) (395.5) (378.9)

Preferred stock dividend payments .......................................................... . (44.3) (42.7) (42.2)

Distribution-preferred securities of subsidiary trust... .............. ,.............. . (3.6)

Other ........... ;..................................................................................... :....... . (10.1) (7.8) ~83.3)

Net Cash Flow From (To) Financing Activities ......................................... . (347.3) (284.3) (348.0)

Cash Flow From (Used In) Investing Activities:

Utility plant expenditures (excluding AFC - other funds) ................... . (519.9) (580.9) (644.9)

Nuclear fuel (excluding AFC - other funds) ......................................... . (57.6) (80.0) (68.1)

Pollution control project funds ................................................ :............... . 8.4 6.9 32.7 Nuclear decommissioning contributions ................................ .-................. . (28.5). (24.5) (24.4)

Sale of accounts receivable, net .............................................................. . (160.0) (40.0)

Other ......................................................................................................... . (19.5) (8.3) (13.7)

Net Cash Flow From (Used In) Investing Activities ................................. . (777.1) (726.8) {718.4)

Increase (Decrease) in cash and cash equivalents ...................................... . 1.0 7.2 (43.5)

Cash and cash equivalents at beginning of year ........................................ . 28.8 21.6 65.1 Cash and cash equivalents at end of year ................................................... . $ 29.8 $ 28.8 $ 21.6 Cash paid during the year for:

Interest (reduced for the cost of borrowed funds capitalized as AFC) $ 314.5 $ 302.9 $ 324.8 Income taxes ............................................................................................. . 215.8 190.5 268.1 Non-cash transactions for financing and investing activities:

Assumption of obligations ....................................................................... . 26.3 Acquisition of utility property ................................................................. . 26.3 The accompanying notes are an integral part of the financial statements.

28

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

General Virginia Electric and Power Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy within a 30,000 square mile area in Virginia and northeastern North Carolina. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives and munic-ipalities. 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'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 significant intercompany transactions and accounts being eliminated on consolidation.

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

The preparation of financial statements in conformity with generally accepted accounting principles requires manage-ment to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent

.liabilities at the date of the financial statements and the reported amounts of revenues and expenses during *the reporting period. Actual results could differ from those estimates.

Revenues Operating revenues are recorded on the basis of service rendered.

Property, Plant and Equipment Utility plant is recorded at original cost which includes labor, materials, services, AFC, where permitted by regulators, and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense and clearing

_accounts. The cost of additions and replacements is charged to the appropriate utility plant account, except that the cost of minor additions and replacements, .as provided in the Uniform System of Accounts, is charged to maintenance expense.

Depreciation and Amortization Depreciation of utility plant (other than nuclear fuel) is computed on the straight-line method based on projected useful service lives. The cost of depreciable utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation. The provision for depreciation is based on weighted average depreciable plant using a rate of 3.2 percent for 1995, 1994 and 1993.

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.

Allowance for Funds Used During Construction The applicable regulatory 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 1995, 1994 and 1993 were 8.9, 8.9 and 9.4 percent, respectively. Approximately 83 percent of the Company's construction work in progress is now included in rate base, and a cash return is collected currently thereon.

29

e Deferred Capacity and Fuel Expense Approximately 80% of capacity expenses and 90% of fuel expenses are subject to deferral accounting. The difference between reasonably incurred actual expenses and the level of expenses included in current rates is deferred and matched against future revenues.

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

Cash and Cash Equivalents Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 1995 and 1994, the Company's accounts payable included the net effect of checks outstanding but not yet presented for payment of $62.7 million and $66.8 million, respectively. For purposes of the Consolidated Statement of Cash Flows, the Company considers cash and cash equivalents to include cash on hand and temporary investments purchased with an initial maturity of three months or less.

Reclassification Certain amounts in the 1994 and 1993 financial statements have been reclassified to conform to the 1995 presentation.

B. Income Taxes:

Details of income tax expense are as follows:

Years 1995 1994 1993 (Millions)

Current expense:

Federal. ............................................................................................ . $ 231.0 $ 185.6 $ 283.0 State ................................................................................................. . 2.1 2.1 (0.3) 233.1 187.7 282.7 Deferred expense:

Plant related items .......................................................................... . 48.9 39.0 45.0 Deferred fuel and capacity ............................................................. . (6.0) (8.2) (12.9)

Debt issuance costs ........................................................................ . 1.3 3.7 8.3 Customer accounts reserve ................................................ ;............ . 36.8 (34.9)

Terminated construction project costs ........................................... . (7.3) (7.3) (7.7)

Other ............................................................................................... . (25.0) (11.6) (7.8) 11.9 52.4 (10.0)

Net deferred investment tax credits-amortization ............................. . (16.9) (17.1) (19.2)

Income tax expense-operating income .............................................. . 228.1 223.0 253.5 Income tax expense associated with nonoperating income:

Current expense:

Federal. ............................................................................................ . 0.8 (1.7) (0.2)

Deferred expense ................................................................................ . (0.1) 4.3 3.9 Income tax expense-nonoperating income ........................................ . 0.7 2.6 3.7 Total income tax expense ................................................................... . $ 228.8 $ 225.6 $ 257.2 30

e e 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 1995 1994 1993 (Millions)

Federal income tax expense at statutory rate of 35% .... $229.9 $234.4 $266.5 Increases (decreases) resulting from:

Utility plant differences .. ,................................. *........... . 3.2 (1.8) (6.2)

Ratable amortization of investment tax credits .......... . (16.9) (17.l) (16.1)

Terminated construction project costs ........................ . 5.0 5.0 5.2 Other, net ..................................................................... . 4.2 2.1 3.0

_Ji:~) __i!_!_&) (14.1)

Total federal income tax expense ................................... . $225.4 $222.6 $252.4 Effective tax rate ............................................................. .

-34.3%

- 33.2% 33.1%

The following chart reconciles total income tax expense as shown on the Consolidated Statements of Income:

Years 1995 1994 1993 (Millions)

Total federal income tax expense ................................... . $225.4 $222.6 $252.4 Less: federal income tax charged other income ............ . 0.7 2.6 3.7 Add: state income tax charged to operating income ..... . 3.4 3.0 4.8 Total income tax expense charged_ to operating income $228.1 $223.0 $253.5 The Company's net accumulated deferred income taxes consist of the following:

Years 1995 1994 (Millions)

Deferred income tax assets:

Investment tax credits .............................................................................. . $ 96.4 $ 102.4 Deferred income tax liabilities:

Plant-method and basis differences ......................................................... . 1,384.4 1,338.2 Terminated construction project costs ..................................................... . 19.5 23.9 Income taxes recoverable through future rates ....................................... . 171.6 172.9 Other ......................................................................................................... . 19.7 34.1 Total deferred income tax liabilities ............................................................ . 1,595.2 1,569.1 Total net accumulated deferred income taxes ............................................. . $1,498.8 $1,466.7 C. Nuclear Operations:

Decommissioning Nuclear plant decommissioning costs are accrued and recovered through rates over the expected service lives of the Company's nuclear generating units. The amounts collected from customers are being placed in trusts, which, with the accu-mulated earnings thereon, will be utilized solely to fund future decommissioning obligations.

North Anna Surry Unit 1 Unit 2 Unit 1 Unit 2 NRC license expiration year ......................................................................... . 2018 2020 2012 2013 Method of decommissioning ........................................................................ . DECON DECON DECON DECON (Millions)

Current cost estimate (1994) dollars ........................................................... . $247.0 $253.6 $272.4 $274.0 External trusts balance at December 31, 1995 ........................................... . $ 84.1 $ 78.9 $ 96.2 $ 92.2 1995 contribution to external trusts ...*.......................................................... $ 6.1 $ 5.7 $ 8.0 $ 8.7 31 J

e

  • - Approximately ev.ery four years, site 0 specific studies are prepared to determine the decommissioning cost estimate for the Company's four nuclear units .. DECON assumes the activities associated with .decontamination or prompt removal of radioactive contaminants will begin shortly after cessation of operations so that the property may*be released for unrestricted use.

The accumulated provision for decommissioning of $351.4 million and $260.9 million is included in Utility Plant Accu-mulated Depreciation at December 31, 1995 and 1994, respectively. Provisions for decommissioning of $28.5 million, $24.5 million and $24.4 million applicable to 1995, 1994 and 1993, respectively, are included in Depreciation and Amortization Expense. The net unrealized gain of $40.7 million and net unrealized loss of $5.2 million associated with securities held by the Company's Nuclear Decommissioning trust at December 31, 1995 and 1994, respectively, are included in the accumu-lated provision for dewmmissioning'.

Earnings of the trust funds were $15;9 million, $15.2 million and $16.3 million for 1995, 1994 and 1993, respectively, and are included in Other Income in the Company's Consolidated Statements of Income. The accretion of the accumulated provision for decommissioning, equal to the earnings of the trust funds, is also recorded in Other Income .

. The Fi~an"ial Accounting stim:dard~ Board (FASB) is reviewing the accounting for nuclear. plant decommissioning. If current electric *utility industry practices for such decommissioning are changed, annual provisions for decommissioning could increase. FASB has 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 recog-nized earlier in the operating life of the nuclear plant.

During its deliberations, FASB has expanded the scope of this project to include similar unavoidable obligations to perform closure and post-closure activities incurred as a condition to operate assets other than nuclear power plants. Whether this position, if adopted, would.impact otjler ~ssets of the. Company cannot be determined at this time. Furthermore, the FASB has tentatively determined that it would be inappropriate to accou11t for cost of removal as negative salvage; thus, any forthcoming standard may also cause. changes in industry plant depreciation practices.

Insurance The Price-Anderson Act limits. the public liability of .an owner of a nuclear power plant t.o $8.9 billion for a single nuclear incident. The Price-Anderson Amendments Act of 1988 allows for fill 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% insurance premium tax for Virginia) for each of its fourJicensed reactors not to exceed $10.3 million (including a 3% insurance premium tax for Virginia) per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

Nuclear li?bility coverage for claimS:made by nuclear workers first hired on or after January 1, 1988, except those arising out of an extramdinary 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 cover-age for the industry ,is $400 million ($200 million policy limit with automatic reinstatements of an additional $200 million).

The Company's maximum retrospective assessment is approximately $12.5 million (including a 3% 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 policy year in which losses exceed the funds available to these insur-ance companies. The maximum assessment at the first incident of the current policy period is $42.7 million and the maxi-mum assessment related to a second incident is an additional $15.4 million. Based on the severity of the incident, 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 financial responsibility for these losses.

32

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 e

premium assessment for any policy year in which losses.exceed funds available to NEIL. The current policy period's maxi-mum assessment is $9 million. *

. As part owner of the North Anna Power Station, ODEC is responsible for its proportionate share (11.6,percent) of the insurance premiums applicable to that station;. including any retrospective premium assessments artd any losses not covered by insurance.

D. Sale of Receivables:

The Company has an agreement to sell, with limited recourse, certain accounts receivable including unbilled amounts, up to a maximum of $200 million. Additional receivables are continually sold, at the Company's _discretion, to replace those collected up to-the limit.At l)ecember 31, 1995 no amount was outstanding; however. at Deqember 31, 1994, .$160 million of rec~ivables had beeri*sold and w.ei:e-o:utstanding.under this agreement The limited recoµrse is provided by rhe Company's assignment of an additional undivided interest in accounts receivabl~ to cover any potential losses to the purchaser due to uncollectible .accounts: The Company has provided. for the estimated amount of such losses in its accounts.

. . . ' ' 'l.

E. u~mty p1~iit: *

. Utility piant consisted of tbe following:

At December 31,

.

  • 1995 1994
    • . *; * . . (Millions) *'
  • Production.:.. *.:; .. :.. :... :-.... .-, .. :.. .-.:-... :.:.: ....*.* ;; ... :...... .':,., ..'.;;'. ..... ,; .... ;........ ,.','. .........*......* .': ..........*...*...... :..... .-..*. *---$ 7;340.0 $* 6,916.6 Trarisniissiori .. ;:: ..... :..': ... :-.: ... ;.... ::.:;':'..: .........:.:.. :..... :.. ,............ :.'..:.........*. ;......:: .... :.. ;..'.:'..: ...... :.: ...... ,.'.'.:.;.:; *.
  • 1,316.1 1,301.2 Distribution ...... *................................. ;....... *.-- .. -.. :... -**.., ..*.* ..'* ................. .- ........ *........ *...... *............. :.*.....
  • 4,215.7. *
  • 3,989.8 Other .... .'...................... .- ........-.......... .'................ -.................................................................................... 817.7 * '860.8 13,689.5 13,068.4 C_onstniclion work in progress:.-......... ,...*.... :.'; .... , ..... :.: ....*:*:... :;::,*.............. .-........ ;.......... '. ...... ;............. ,:.. ;'. .. , 512.1 . 828.2 Total.:;* ...... *....... *.. *...... *... -..... *.. *.. '.*:**.*--... .-*.............................................:.. ;* .. *....... *.... *............ . $14,201.6 $,13,896.6

..~' ' ' '

F. Joi_ntly Owned Plants:

. The *following. inf01mation relates to the Company's proportionate share of jointly owned plants at December 31, 1995: *

  • North Bath Co11nty Anna Clover

\

Pumped Storage Power:*. Power Station. Station Station Ownership interest. ... .-... ;....*...... ;......*..........*.......... ,.. ;.;';.;.... :....... , * *60.0% . *88.4%  : 50.0%

(Millions)

Utility plant i11 service .. ,, ....{.... ,.... ,...... :... :............... ,.: .... ,.'.... .-... . $1,074.8 . $1,798.5 .-$289:6 Accumulated depreqiation ..... :.................. :............................... . 188.6 635.7 1.5 Nuclear fuel ................................. :............................................ . 405.1 Accumulated amortization' of nucleiu" fuel ....  :::u..': ..........;....:;.: 387.3 construction woi:k. in *progress . .

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

. 0.7 110.9 211.1 The co-owners are obligated to pay their share. 0:f 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,Jn~tenance, depreciation, taxes,etc.) in the Consolidated Statements of Income.

33

_I

e

. G. Regulatory Assets:

Certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets and are recognized in income as the *related amounts are included in rates and recovered. from custom.ers. The Company's rygulatory assets included the following: * *

  • At December 31, 1995  : 1994 (Millions)

Income taxes recoverable through future rates ...................................................................*.......................... $484.5 $488.2 Cost of decommis~ioning DOE uranium enrichment facilities .................................................................... . 78.5 83.7 Deferred losses (gains) on reacquired debt, net. ............................. i ............................................................. . 99.3 107.0 North Anna Unit 3 project termination costs ..... :....................... ::.................................... :.:........................ :: 10L8 128.. 5 Other ................................. :............. ,............................................................................................................... . 52.3 63.6 Total ..................... _.................................................................................................................... , ........... . $816.4 . $87LO Income taxes recoverable through future rates represent principally the tax effect of depreciation differences not normal-ized. these amounts are amortized as the related temporary differences reverse; The costs of decommissioning the Department of Energy's (DOE) uranium enrichment facilities have be'en 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 fifteen-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 long-term debt. Gains or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.

The construction of North Anna Unit 3 was terminated in November 1982. All retail jurisdictions have permitted 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 repre-senting past expenditures that are not included in the Company's rate base or used to adjust the Company's capital structure, the Company is not allowed to earn a return on the unrecovered balance. Of the $816.4 million of regulatory assets at December 31, 1995, approximately $123 million represent past expenditures that are effectively excluded from rate base by the Virginia State Corporation Commission that has primary jurisdiction over the Company's rates. However, of that amount

$1QL8 million represent the present value of amounts to be recovered through future rates for North Anna Unit 3 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 $21.2 million of regulatory assets, effectively excluded from rate base, to be recovered over various recovery periods up to 23 years, depending on the nature of the deferred costs.

H. Leases:

Plant and property under capital leases included the following:

At December 31, 1995 1994 (Millions)

Office buildings (*) .......... :........................................................................... . $34.4 $34.4 Data processing equipment._ ......................................................................... . 2.8 5.8 Total plant and property under capital leases ................................ .. 37.2 40.2 Less accumulated amortization .................................................................... . 11.8 12.5 Net plant and property under capital leases ................................................ . $25.4 $27.7

(*) 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 $24 million and $25 million at December 31, 1995 and 34

e e 1994, respectively. Rental payments for such lease were $3 million for each of the three years ended December 31, 1995,-

1994 and 1993.

The Company is responsible for expenses in connection with the leases noted above, including maintenance.

Future minimum lease payments under noncancellable capital leases and for operating leases that have initial or remain-ing lease terms in excess of one year as of December 31, 1995, are as follows:

Capital Operating Leases Leases (Millions) 1996.................................... *........................................................................... . $ 3.7 $ 9.9 i997 ............................................................................................................... . 3.6 8.2 1998 .......... * .................................................................................................... . 3.3 4.1 1999........................................................................................ *...................... . 3.0 3.0 2000 ........... *........................ *.: ....................................................................... . 3.0 2.4 After 2000 ..................................................................................................... . 22.8 26.0 Total future minimum lease payments ................... :................................... .. 39.4 $53.6 Less interest element included. above .......................................................... . 14.0 Present value of future minimum lease payments ..................................... .. $25.4 Rents on leases, which have been charged to other operation expenses, were $9 .8 million, $9 .6 million and $11.2 million for 1995, 1994 and 1993, respectively.

35

1.: Long-term Debt:

Long-term debt included the following:

At December 31, 1995 1994 (Millions)

First and Refunding Mortgage Bonds (1):

  • 1992 Series A, 6.375%, due 1995 ....................................................................................* $ 180.0 Series T, 4.5o/o, due 1995 ................................................................................................. . 56.6 Series U, 5.125%, due 1997 ............................................................................................ . $ 49.3 49.3 1992 Series B, 7.25%, due 1997 ..................................................................................... . 250.0 250.0 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 1992 Series D, 7.625%, due 2007 ..................................................... '. ............................ .. 215.0 215.0 Various series, 5.45-8.75%, due 2020-2025 ...................................................... ;............. . 1,144.5 944.5 Total First and Refunding Mortgage Bonds .................................... :...................... .. 2,923.8. 2,960.4 Other long-term debt:

Bank loans, notes and term loans:

Fixed interest rate, 6.15%-10.8%, due 1995-2003 ........................................... :..'........ . -762.7 798.2 Pollution control financings (2):

Money Market Municipals, due 2008-2027 (3) ......................................................... .. 488.6 488.6 Total other long-term debt ....................................................................................... . 1,251.3 1,286.8 4,175.1 4,247.2 Less amounts due within one year:

First and Refunding Mortgage Bonds ............................................................................. . 236.6 Bank loans, notes and term loans .................................................................................... .. 259.6 75.6 Total amount ciue within one year ........ '. .................................................................. .. 259.6 . 312.2 Less unamortized discount, net of premium ....................................................................... . 26.1 24.6 Total long-term debt ................................................................................... :............. . $3,889.4 $3,910.4 (1) Substantially all of the Company's property is subject to the lien of its mortgage, securing its First and Refunding Mortgage Bonds.

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

(3) Interest rates vary based on short-term, tax-exempt market rates. The weighted average daily interest rates were 3.89% and 2.96% for 1995 and 1994, respectively. Pollution control bonds subject to remarketing within one year are classi-fied as long-term debt to the extent that the Company's intention to maintain the debt is supported by long-term bank commitments.

Maturitiesthrough2000areasfollows(millions): 1996 - $259.6; 1997 - $311.3; 1998 - $333.5; 1999 - $261; and 2000 - $195.5.

J. Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust:

In 1995, the Company established Virginia Power Capital Trust I (VP Capita:! Trust). VP Capital Trust sold 5,400,000 shares of Preferred Securities for $135 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by VP Capital Trust.

The Company 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.

36

e e The common securities represent the remaining 3% beneficial ownership interest in the assets held by VP Capital Trust. The Notes constitute 100% of VP Capital Trust's assets.

The Notes are due September 30, 2025, but may be extended up to an additional ten years, subject to satisfying certain conditions. However, the Company may redeem the Notes on or after September 30, 2000, under certain circumstances. The Preferred Securities are subject to mandatory redemption upon repayment of the Notes at maturity or earlier redemption. At redemption, each Preferred Security shall be entitled to receive a liquidation amount of $25 plus accrued and unpaid distribu-tions, including any interest thereon.

K. Preferred Stock Subject to Mandatory Redemption:

Preferred stock subject to mandatory redemption, $100 liquidation preference, at December 31, 1995, was as follows:

Issued and Outstanding Dividend Shares

$5.58 .............................. :.. 400,000(a)(b) 6.35 .................. :.. :: ......... . 1,400,000(a)(c)

Total ..................... . 1,800,000 (a) Shares are non-callable prior to redemption.

(b) All shares to be redeemed on 3/1/2000.

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

During the ye~s 1993 through 1995, the following shares were redeemed: ,

Year Dividend Shares 1995 ........................ :...... :............................... . $7.30 417,319 1994.:: ........................................................... . 7.30 37,681 1993 .............................................................. . 7.30 30,000 1993 .............................................................. . 7.58 480,000 1993 .............................................................. . 7.325 400,419

. The total number of authorized shares for all preferred sto~k is 10,000,000 shares. Upon inv~luntary liquidation, all presently outstanding preferred stock is entitled to receive $100 per share plus .accrued dividends. Dividends are cumulative.

37

L.* Preferred Stock Not Subject to 'Mandatory Redemption: **

Preferred stock not subject to mandatory redemption, $100 liquidation preference, at December 31, ,1995, was as follows: *

  • E~titled Per. Share* Upon Liquidatio~ .

Issued and

  • And Thereafter to
  • Outstanding *
  • Amounts Dec1j¢ng Dividend Shares Amount In 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 ~/3V13 MMP 1/87 (*) ............................ :............., ......... ;........................ . 500,000 100.00 .

.MMP 6/87 (*) .......................................:....... ~ ........................ :..... . 750,000 100.00'*'

MMP 10/88 (*) ............... '..:; ............... ,........................................ . 750,000 100.00 MMP 6/89 (*) .. :, ....... ;... ,..................... :........................................ . 750,000 100.00 MMP 9/92A (*) .......................................................*.................. .. 500,000 100.00 MMP 9/92B (*) ...................................................*........~ ........:., .... . 500,000 100.00 Total* ..................................................... *....................................... . 5,090,140

,* *1 k

(*) Money Market Preferred (MMP) dividend rates are variable and are set every .49 .days yia an auctipn process. The combined weighted average rates for these series in 1995, 1994 and i993, including fees for broker/dealer agreements, were 4.93%, 3.75% and 3.01 %, respectively.

During the years 1993 through 1995 the following shares were redeemed:

. Year Dividend Shares 1995. * $7.45 400,000 1995 7.20 *. 450,900 ..

1993 7.72 350,000,.

1993 7.72(1972 Series) 500,000

  • M. *common Stock:

During the years 1993 through 1995 the following changes in Common Stoc~ occurred:

Years 1995 1994 1993 Shares .. Shares **. Shares Outstanding Amount Outstanding Amount Outstanding Amount

' . t". - .

.. ,* (Millions, el'cept shares)

Balance at January 1 .............. . 171,484 $'.f/737.,4 168,277  ;$2,.662.4 166,109 ,$2,612.4 Issuance to Dominion ..

Resources ........................... ..

  • 3,207: 75.0 2;168 . 50;0 Balance at December 31 ... ;..... . 171,484 $2,737.4 171,484 $2,737.4 168,277 $2,662.4 N. Short-Terni Debt:

The Company has !ill established cominercial paper program, supported by a credit agree~ent that has an expiration qitte of July 31, 2000. This credit agreement provides for a maximum borrowing of $300 million. At December 31, 1995, $169

  • million of commercial paper was outstanding. No commercial paper was outstanding at December 31, 1994.
  • The weighted average interest rate for commercial paper on.December 31, 1995 was 5.79%

38

e

0. Retirement Plan, Postretirement Benefits and Other Benefits:

Retirement Plan Toe Company participates in the Dominion Resources, Inc. Retirement Plan (the Retirement Plan), a defined benefit pension plan. Toe Retirement Plan covers virtually all employees of Dominion Resources and its subsidiaries, including the Company. Toe benefits are based on years of service and average base compensation over the consecutive 60-month period in which pay is highest.

  • Pension plan expenses were $20.3 million, $19.3 million and $15.9 million for 1995, 1994 and 1993, respectively and the amounts funded were $42.7 million, $42.7 million and $16 million in 1995, i994 and 1993, respectively.

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.

Postretirement Benefits Net periodic postretirement benefit expense was as follows:

Year Ended December 31, 1995 1994 (Millions)

Service cost ........................................ , ......................................................... : $ 8.7 ', $11.0 Interest cost ............................................. *..................................................... . 21.7 21.6 Return on plan assets ................................... '. ..... ,......................................... . (6.2) 0.9 Amortization of* transition obligation ...........: .............................................. . 12.1 12.1 Net amortization and deferral ...................................................................... . 0.1 (4.1)

Net periodic postretirement benefit expense ...........,. ..... :..... ,.. *****:******: ........ . $36.4 $41.5 The following table sets forth the funded status of the plan:

At December 31, 1995 1994 (Millions)

Fair v.alue of plan assets ............................................................................. . $ 96.3 $ 59.7 Accumulated postretirement benefit obligation:

Retirees .................................................................................................... . $210.7 $208.4 Active plan participants .......................................................................... . 96.5 91.7 Accumulated postretirement benefit obligation ................................. . 307.2 300.1 Accumulated postretirement benefit obligation in excess of plan assets ......................................................... :.. ,........ :.......... ,.............. :.'. (210.9). . (240.4)

Unrecognized transition obligation ............................................................. . 204.9 216.9 Unrecognized net experience (gain)/loss .............. ;.............................. :...... . 7.9 16.6 Accrued postretirement benefit cost ............................................ :...... :....... . $ 1.9 $ (6.9)

A one percent increase in the health care cost trend rate would result in an increase of $3.5 million in the service and interest cost components and a $36.9 million increase in the accumulated postretirement benefit obligation.

Significant assumptions used in determining the postretirement benefit obligation were:

1995 1994 Discount rates................................................................................................. 8.0% 8.25%

Assumed return on plan assets ..................................................................... . 9.0% 9.0%

Medical cost trend rate ......................... ,....................................................... . 9% for 1st year 10% for 1st year 8% for 2nd year 9%. for .2nd year

  • Scaling down td Scaling down to 4.75% beginning 4.75% beginning in the year 2001 in the year 2001 Toe Company is recovering these costs in rates on an accrual basis in all material respects, in all jurisdictions. Current and future recoveries of other postretirement benefits (OPEB) accruals are expected to collect sufficient amounts to provide 39

e e for the unfunded accumulated postretirement obligation over time. The funds being collected for OPEB accruals in rates, in excess of OPEB benefits actually paid during the year, are contributed to external benefit trusts under the Company's current funding policy.

Other Benefits In 1994, the Company offered an early retirement program to employees aged 50 or older and offered a voluntary separation program to all regular full-time employees. Approximately 1,400 employees accepted offers under these programs.

The costs associated with these programs were $90.1 million. The Company capitalized $25.9 million based upon regulatory precedent and expensed $64.2 million.

P. Restructuring:

In March 1995, the Company announced the implementation-phase of its Vision 2000 program. 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 is resulting in outsourcing, decen-tralization, reorganization and downsizing for portions of the Company's operations. As part of this process, the Company is reevaluating its utilization of capital resources in the operations of the* Company to identify further opportunities for opera-tional efficiencies through outsourcing or re-engineering of its processes.

  • Restructuring charges of $117.9 million in 1995, included severance costs, purchase power contract cancellation and negotiated settlement costs, capital project cancellation costs, and other costs incurred directly as a result of the Vision 2000 initiatives. The Vision 2000 review of operations is expected to continue through 1996. At this time, Company management cannot estimate the restructuring costs yet to be incurred.

In May 1995, the Company established a comprehensive involuntary severance package for salaried employees who lose their positions as a result of these initiatives. The Company is recognizing the cost associated with employee termina-tions 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, 1995, management had decided to eliminate 1,018 positions. The recognition of severance costs resulted in a charge to operations in 1995 .of $51.2 million. At December 31, 1995, ~07 employees have been terminated and severance payments totaling $8.7 million have been paid. The Company estimates that these staffing reductions will result in annual savings, net of outsourcing costs, in the range of $50 million to $60 million. These savings will be reflected in lower construction expenditures as well as lower operation and maintenance expenses.

In an effort to minimize its exposure to potential stranded investment, the Company is evaluating its long-term pur-chased power contracts and neg-otiating modifications to their terms, including cancellations, where it is determined to be economically advantageous to do so. The Company also negotiated settlements with several other parties to terminate their rights to sell power to the Company. The cost of contract cancellations and negotiated settlements was $8.1 million in 1995.

Based on contract terms and estimated quantities of power that would have otherwise been delivered, the cancellation of these contracts and rights to sell power to the Company has the effect of reducing the Company's future purchased power costs, including energy payments, by up to $214 million annually. The cost of alternative sources of power that might ulti-mately be required as a result of these settlements is expected to be significantly less than $214 million, on an annual basis.

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.

As a regulated utility, Virginia Power provides service to its customers at rates based on its cost of operations and an opportunity to earn a return on its shareholder's investment. From time to time, the Company reviews its cost of providing regulated services and files such information with certain regulatory commissions having jurisdiction. The Company or the regulatory commissions may initiate proceedings to review rates charged to Company jurisdictional customers. The incur-rence of restructuring charges and the savings resulting therefrom in subsequent periods are elements of the Company's cost of operations. Accordingly, Vision 2000 costs and related savings will be considered in any future review of the Company's overall regulatory cost of service.

40

e Q. Commitments and Contingencies:

The Company is involved in legal, tax artd 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.

Federal Energy Regulatory Commission Audit The FERC has recently conducted a compliance audit of the Company's financial statements for the years 1990 through 1994. The Company has received a preliminary draft of the audit report in which certain compliance exceptions were noted.

The Company has supplied information to the FERC staff relating to these preliminary exceptions, but no final audit report has been issued. Based on information available at this time, the disposition of these issues is not expected to have a signifi-cant effect on the Company's financial position or results of operations.

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 information, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.

Construction Program The Company has made substantial commitments in connection with its construction program and nuclear fuel expendi-tures. Those expenditures are estimated to total $569.3 million (excluding AFC) for 1996. Additional financing is contem-plated in connection with this program.

Purchased Power Contracts Since 1984, the Company has entered into contracts for the long-term purchases of capacity arid energy froni other utilities, qualifying facilities and independent power producers. The Company has 67 non-utility purchase contracts with a combined dependable summer capacity of 3,493 Mw. Of these, 66 projects (aggregating 3,295 Mw) were operational as of the end of 1995 with the remaining project to become operational before 1998.

The table below reflects the Company's minimum commitments as of December 31, 1995, for power purchases from utility and non-utility suppliers.

Commitment Year Other (Millions) 1996 *************************************************************** $ 738.3 $ 207.4 1997 *************************************************************** 784.7 213.2 1998 *************************************************************** 788.8 219.8 1999 *************************************************************** 791.6 224.2 2000 .............................................................. . 707.4 163.6 Later years .................................................... . 11,106.3 1,200.9 Total .......................................................... . $14,917.1 $2,229.1 Present value of the total.. ........................... . $ 6,860.7 $1,243.4 In addition to the minimum purchase commitments in the table above, under some of these contracts the Company may purchase, at its option, additional power as needed. Actual payments for purchased power (including economy, emergency, limited term, short-term and long-term purchases) for the years 1995, 1994 and 1993 were $1,093 million, $1,025 million and

$958 million, respectively.

  • Fuel Purchase Commitments The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (millions): 1996 - $348; 1997 - $319; 1998 - $205; 1999 - $137; and 2000 - $151.

41

Sale of Power On-November 26, 1991, the Company and ODEC signed an agreement whereby the Company will provide 100 Mw of firm capacity and associated energy until the commercial operation of Clover Unit 2 (currently scheduled for April 1996) or December 31, 1996, whichever occurs first. In addition, the Company has a diversity exchange agreement with APS under which APS delivers 200 Mw to Virginia Power in the summer and Virginia Power delivers 200 Mw to APS in the winter.

The Company has entered into agreements to supply wholesale power under various terms on a firm basis during certain upcoming winter and summer months. Under these agreements, the Company has the following commitments:

Years 1996 1997 1998 (Mw of Capacity)

Winter ................................................................................................................._........................ . 200 110 Summer................................................................................................................... :....... ;........... 425 310 200 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 compli-ance, 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

$46.5 million to $134.6 million. The Company's proportionate share of the cost is expected to be in the range of $0.5 million to $6.7 million, based upon allocation formulas and the volume of waste shipped to the sites. As of December 31, 1995, the Company accrued a reserve of $1.4 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay the costs appor-tioned to them.

The Company and Dominion Resources along with Consolidated Natural Gas have remedial action responsibilities remaining at two coal tar sites. The Company accrued a $2 million reserve to meet its estimated liability based on site studies and investigations performed at these sites. In addition, on December 13, 1995, a civil action was instituted against the City of Norfolk and Virginia Power by a landowner who alleges that h1s property has been contaminated by toxic pollutants originating from one of these sites, which is now owned by the City of Norfolk. The plaintiff seeks compensatory damages of

$10 million and punitive damages of $5 million from Virginia Power. The Company filed its answer denying liability on January 10, 1996.

The Company generally seeks to recover its costs associated with environmental remediation from third party insurers.

At December 31, 1995, any pending or possible claims were not recognized as an asset or offset against recorded obligations of the Company.

R. Fair Value of Financial Instruments:

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

42

December 31,.

1995 1994.

Carrying Fair Carrying Fair Amount Value Amount *value (Millions)

Assets:

C)\~h and cas.h. equivalents .............. ,.................................... . $ 29.8 $ 29.8 $ 28.8, $ 28.8 Nuclear gecommissioning t,rust funds ................................. '. 351.4 351.4 260.9 260.9

. Polluti()n .~ontrol proje<;:t funds ............................................ ; 11.9 11.9 20.3 20.3 Liabilitie~ :and. capitalization:.

': *.short,~.(?flll deqt. .. ,. ..... ,..... ,,.****:************.*,*********,*********************** 169.0 . 169.0 Long-term debt:

First and refunding mortgage bonds ................................ . 2,923.8 3,106.3 2,960.4 2,763.2 Medium-term notes., ..... ,........ .' ............... ,........... ,........:....... . 762.7 810.l 798.2 807.2 Money Market Munic1.pal pollutjori control notes* ........... . 488.6 488.6 488.6 488.6 Preferred stock subject to mandatory redemption ..~ ...... :.. :..

  • 180:0 190.9 221.7 201.2 Preferred securities of subsidiary trust ....*........... ~ ........ :.... ;.. 135.0 140.4 Cash and cash equivalents, pollution controt project funds and short-term debt: The carrying .amount of these items approximates fair value because of their short maturity.

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

First and refunding mortgage bonds and pollution control bonds: Fair value is based on market quotations.

Medium-term notes: These notes were valued by discounting the remaining cash flows at a rate estimated for each issue.

A yield.curve rate* was estimated to i:elate Treasury Bond rates for specific issues to the corresponding maturities.

Money market municipal pollution c*ontrol notes: These notes have variable interest rates which are set so that fair value approximates carrying va1ue.

Preferred stock subject to mandatory redemption: The fair value is based on market quotations or is estimated by dis~

counting 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),

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

Balance Available Operating Operating Net for Common Quarter Revenues Income Income Stock (Millions) 1995 1st ................................. $1,076.3 $191.8 $115.0 $103.3 2nd ................................ 971.1 156.7 78.0 66.3 3rd ................................ 1,276.6 279.1 201.8 190.3 4th******************************** 1,026.4 118.9 38.0 28.8 1994 1st ................................. $1,102.1 $207.1 $133.4 $123.4 2nd ................................ 990.2 175.2 102.1 91.7 3rd ................................ 1,151.2 241.0 165.9 155.2 4th ................................ 927.3 108.1 45.7 34.6 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.

As part of the Vision 2000 program (see Note P to CONSOLIDATED FINANCIAL STATEMENTS) the Company recorded $117.9 million of restructuring charges in 1995. Restructuring charges included severance costs, purchase power 43

e contract cancellation and negotiated settlement costs, capital project cancellation costs, and other costs incurred directly as a result of the Vision 2000 initiatives. The Company expensed $3.5 million, $1.8 million, $30.6 million and $82 million during the first, second, third and fourth quarters, respectively; The impact of the write-off reduced Balance Available for Common Stock by $2.3 million, $1.1 million, $19.9 million and $53.3 million for the first, second, third, and fourth quarters, respectively.

In 1994, the Company offered an. early retirement program to employees aged 50 or older and offered a voluntary separation program to all regular full-time employees. Approximately 1,400 employees accepted offers under these programs.

- The costs associated with these programs were $90.1 million. The Company capitalized $25.'9 million based upon regulatory precedent and expensed $2.8 million, $10.4 million and $51 million during the second, third and fourth quarters, respectively.

The impact of the write-off reduced Balance Available for Common Stock by $1.8 million, $6.7 million and $33.1 million for the s~cond, third and fourth quarters, respectively.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON

.ACCOUNTING AND FINANCIAL DISCLOSURE .

None J:.*'.*.

44

e PART III iTEM. 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (a) Information concerning directors of Virginia Electric and Power Company is as follows:

Year First Principal Occupation for Last 5 Years, Elected a Name a~d Age Directorships in Public Corporations

  • Director Jqh,nB. Adams,)r. (51) President and Chief Executive Officer of The Bowman 1987 Companies, Fredericksburg, Vfrginia, a manufacturer.

and bottler of beverages and Chairman of the Board of Directors and a Director* of Virginia Electric

  • and Power Company. He is a Director of Dominion Resources.

James T. Rhodes (54) President anq Chief Executive Officer of Virginia Electric 1989 and Power Company. He is a Director of NationsBank, N.A.

Tyndall L. Baucom (54) Retired, President and Chief Operating Officer of 1994

. Dominion Resources, Inc. from August 16, 1994 to August 29, 1995. Prior to August 16, 1994, he was Senior Vice President of Dominion Resources.

He is a Director of Dominion Resources.

James F. Betts (63) Retired, Richmond, Virginia. He is a Director of Central 1978 Fidelity Bank, Inc.

Benjamin J. Lambert; III (59) Optometrist, Richmond, Virginia. He is a Director of 1992 Consolidated Bank and Trust Company, Student Loan Marketing Association (SallieMae) and Dominion Resources.

Richard L. Leatherwood (56) Retired, Baltimore, Maryland (prior to December 1, 1991, 1994 President and Chief Executive Officer, CSX Equipment, an operating unit of CSX Transportation, Inc.). He is a Director of Dominion Resources.

Harvey L. Lindsay, Jr. (66) Chairman and Chief Executive Officer of Harvey Lindsay 1986 Commercial Real Estate, Norfolk, Virginia, a commercial real estate firm. He is a Director of Dominion Resources.

William T. Roos (68)

  • Retired, Hampton, Virginia (prior to December 31, 1993, 1975 President of Penn Luggage, Inc., retail specialty stores).

He is a Director of Dominion Resources.

Robert H. Spilman (68) Chairman, Chief Executive Officer and a Director of 1994 Bassett Furniture Industries, Inc., Bassett, Virginia. He is Chairman of the Board and a Director of Jefferson-Pilot Corp., Greensboro, North Carolina. He is a Director of NationsBank Corporation, TRINOVA Corporation, The Pittston Company and Dominion Resources.

William G. Thomas (56) President of Hazel & Thomas, Alexandria, Virginia, 1987 a law firm.

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 and credit granting activiti~s. of Perpetual Savings Bank, FSB, which Mr. Thomas formerly served as a director. The Consent Decree requires that Mr. Thomas obtain approval from the appropriate federal banking agency before accepting certain posi-tions involving lending or credit ai::tivities with an insured depository institution.

45

e *

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

Name and Age Business Experience Past Five Years James T. Rhodes (54) President and Chief Executive Officer.

Robert E. Rigsby (46) Executive Vice President, January 1, 1996 to date; Senior Vice President-Finance and Controller, January 1, 1995 to January l, 1996; Vice President-Human Resources, October 1, 1991 to January l, 1995; Vice President-Information Systems prior to October 1, 1991.

- William R. Cartwright (53) Senior Vice President-Fossil and Hydro, July 1, 1995 to date; Vice President Fossil and Hydro prior to July 1, 1995. *,

Larry W. Ellis (55) Senior Vice President-Energy Services, July 1, 1995 to date; Senior Vice President-Power Operations and Planning prior to July 1, 1995.

Larry M. Girvin (52) 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, September 1, 1992 to January 1, 1995; Vice President-Central Division, January 1, 1991 to September 1, 1992.

James P. O'Hanlon (52) Senior Vice President-Nuclear, June 1, 1994 to date; Vice President-Nuclear Operations, January 1, 1992 to June 1, 1994; Vice President-Nuclear. Services prior to January l, 1992.

Edgar. M. Roach, Jr. (47) Senior Vice President-Finance, Regulation and General Counsel, January 1, 1996 to date; Vice President-Regulation and General Counsel, January 1, 1995 to January 1, 1996; Vice President-Regulation, February 1, 1994 to January 1, 1995; Partner in the law firm of Hunton & Williams, Raleigh, North Carolina prior to February 1, 1994.

Charles A. Brown (53) Vice President-Central Division, September l, 1992 to date; Vice President-Procurement prior to September 1, 1992.

Thomas L. .Caviness, Jr. (50) Vice President-Retail Energy Services, July l, 1995 to date; Vice President-Eastern Division prior to July 1, 1995.

J. Kennerly°Davis, Jr. (50)' 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._ (52) Vice President-Energy Efficiency and Division Services, January 1, 1996 to date; Vice President-Division Servic'es prior to January 1, 1996..

Thomas A. Hyman, ir. (44) Vice President-Eastern Division and North Carolina Power, July 1, 1995 to date; Vice President-Southern Division, June 1, 1994 to July 1, 1995; Station Manager-Bremo Power Station, September 1, 1992 to June 1, 1994; Assistant Controller Financial Services, prior to September 1, 1992.

Michael R. Kansler (41) Vice President-Nuclear Engineering and Services, October 1, 1995 to date; Vice President-Nuclear Services, January 1, 1995 to October 1, 1995; Manager-Nuclear Operations Support, September l, 1994 to January 1, 1995; Station Manager-Surry Nuclear Power Station prior to September 1, 1994.

William S. Mistr (48) Vice President-Information Technology, January I, 1996 to date; Vice President-Treasurer of Dominion Energy, Inc., October 1, 1994 to January 1, 1996; Assistant Treasurer, Dominion Resources, December 1, 1992 to October 1, 1994; Assistant Treasurer, May 1, 1991 to December 1, 1992; Manager-Information Systems Client Services prior to May 1, 1991.

F. Kenneth Moore (54) Vice President-Fossil and Hydro Services, July 1, 1995 to date. Vice President-Procurement, September 1, 1992 to July 1, 1995; Vice President-Nuclear Engineering Services prior to September 1, 1992.

Thomas J .. O'Neil (53) Vice President-Human Resources, January 1, 1996 to date; Vice President-Energy *

. Efficiency, September 1, 1992 to January 1, 1996; Vice President-Regulation,

  • prior to September 1, 1992.
  • Robert F. Saunders:(52) Vice President-Nuclear Operations, June 1, 1994 to date; Assistant Vice President-Nuclear Operations, prior to June 1, 1994.

Johnny V. Shena! (50) Vice President-Northern and Western Divisions, June l, 1994 to date; Vice President-Western Division, prior to June l, 1994.

Eva S. Teig (51) Vice President-Public Affairs.

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

46

  • ITEM 11. EXECUTIVE COMPENSATION
  • e Summary Compensation Table The Summary Table below includes compensation paid by the Company for services rendered in 1995, 1994 and 1993 for the Chief Executive Officer and the four other most highly compensated executive officers (as of December 31, 1995) as determined by total salary and incentive payments for 1995*.

Summary Compensation Table Long-Term Compensation All AnnuaJ*:Compensation LTIP Other Name & Principal Position Year Salary Incentives(!) Payouts Compensation James T. Rhodes 1995 $406,075 $273,000 $77,970(9) $ 14,558(6)

President & CEO 1994 $384,575 $193,830 $69,709 $ 14,558(6) 1993 $356,000 $202,202 $97,657(2) $ 17,133(3)

John A. Ahladas (5) 1995 $201,085 $108,150 $55,847(10) $ 51,115(8)

Senior Vice President- 1994 $192,385 $ 86,100 $29,096 $ 4,500(4)

Corporate Services 1993 $183,150 $ 90,954 $44,677 $ 5,495 Robert F. Hill (5) 1995 $226,775 $101,850. $54,041(11) $173,068(7)

Senior Vice President- 1994 $219,526 $ 74,550 $29,096 $ 4,500(4)

Commercial Operations 1993 $210,350 $ 85,086 $44,677 $ 6,311(4)

Larry W. Ellis 1995 $189,360 $102,900 . : $54,041(11) $ 4,500(4)

Senior Vice President- 1994 $181,160 $ 82,950 $29,096 $ 4,500(4)

Power Operations and Planning 1993 $174,000 $ 81,174 $44,667 $ 5;220 James P. O'Hanlon 1995 $207,555 . $136,400 * $45,109(12) $ 4,500(4)

Senior Vice President-Nuclear (1) The Company does not maintain "bonus" plans which are used by ~ollle ~mnpa11ies t~ supplement salaries based on the succes~ of the company without regard to individual performance. Howeyer, the Company has in place. vario~s incentive plans that compensate officers and employees for achieving pre-determined specified performance goals. *

(2) Includes 1,118 shares of Restricted Stock and $51,540 in cash awarded on February 18, 1994 at the end of a three-year performance period. Dividends are paid on Restricted Stock. Restrictions on the shares of stock lapsed six months from the date of grant. As of December 31, 1995 no shares of Restricted Stock were held. * *

(3) Company match on savings plan contributi.on ($7,075) and insura~ce premiumtoDirectors Ch~table Contributio.n Program ($10,058).

(4) Company match on savings plan contribution.

(5) Retired December 31, 1995.

(6) Company match.on savings plan contribution ($4,500) and insurance premium to Directors Charitable Contribution Program ($10,058).

(7) Company match on savings plan contribution ($4,500) retirement payment as provided by Company's Early Retire-ment and Voluntary Separation Prograin ($113,250) and payment at retirement for accrued vacation ($55,318).

(8) Company match on savings plan contribution ($4,500) and payment at retirement for accrued vacation ($46,615).

(9) Represents 1,808 shares of Dominion Resources Common Stock awarded on February 16, 1996 at the end of a three-year performance period.

(10) Represents 1,295 shares of Dominion Resources Common Stock awarded on February 16, 1996 at the end of a three-year performance period.

( 11) Includes $26,096 cash and 648 shares of Dominion Resources Common Stock awarded on February 16, 1996 at the end of a three-year performance period.

(12) Represents 1,046 shares of Dominion Resources Common Stock awarded on February 16, 1996 at the end of a three-year performance period.

47

Lang-Term Incentive Compensation e

Long-term incentive awards n;iade during 1995 are shown in .the following table ..

, Long-Term Incentive Plans :.:._ Awards* in the Last Fiscid Year 1995-1997 PerfQrmance Achievem~nt Pl~n

. Estimated Future* Payouts Performance or *Under Non-Stock Price Based*Plans Number of * * '* :other Period Shares, Units . Until Maturation Threshold Target, Maximum Name ,* or Other Rights(!) or Payout ' . (#) (#) (#)

  • James J'. Rhodes 4,300 ~, yeai;s 1(2) 4,300(2) 6,450(2)

John A: Ahladas 1,478 . 3 years : *,* *, *,1(2) 1,478(2) . *, 2,217(2) ,

Robert F. Hill 1,478 3 years**: , '1(2) 1,478(2) 2,217(2)

Larry: W. Ellis 1,478 3 years****,

  • 1(2) 1,478(2) 2,217(2) lames P. O'Hanlon 1,814 ~ years. , , 1(2) 1,814(2) 2,721(2)

, .. '(1) The performance shares representing Dominion R,esources Common Stock to be awarded at the end ofperformance period. * . . . \

. (2) Except for James T; :Rhodes, payout of awards are tied,to achieving-levels of Virginia Power's return on equity (ROE) (50%) and meeting a cost per kilowatt-hour goal (50%)/The threshold awru;d_will be earned if.81 % of the ROE goal or 75% of the. costs per kilowat~-hour goal is achi~ved. The tru-g~t awards, will)~ earned if the: &cials are fully- achieved. The maximum award will be earned*at 11_0% or more of the, ROE goal and 120% of the cost goat * *

. ' ;  : - . *:. .-~: : .

The award for James T. Rhodes will be paid_ out- in shares of stQCkQl\lill equivalent illl_lount. of cash based, on the a

achievement of three specified :goals civer three-'year performance perfod ;(1995~ 1997), 'weighted as follows: a total r~turn to Dominion Resources Shareholders 'Superior to that *of the S&P Utility Ind~x (50%); utility 'return on equity equal _to the a

average ,ROE achieved by a group ofcoinparable:utilities '(25%); arid 'restraint 6hitility c6;t~*to growth rate less than that of the Consumer Price.Index (25%); , * , .. . .. ' . ' ** .: ,. ,

. The t~g~t 'number of share~ will.be e~ed if all goai~ are fully_'achiev~d. Tiii threshold amount will be earned if at least 71 % of the total retu~ goal; 81 % of the ROE goal, and 75% of the ccisi control'goaJare achievect.'The Iliaxiinuni ainount will be *earned if at least 114% of the total renirn.: goal, 110% of the *RciE. goal, .and 120% of.the cost control goal are achieved.

Prorated amounts will be earned between the threshold and the maximum; * * ,'.

'.I:

48

Retirement Plans The table below sets forth the estimated annual straight life benefit .that would be paid following retirement under the Dominion Resources, Inc. Retirement Plan's (the Retirement Plan) benefit formula.

Estimated Annual Benefits Payable Upon Retirement Credited Years of Service Final Average Earnin~s 15 20 25 30

$150,000 $ 41,182 $ 54,910 $ 68,637 $ 82,364 175,000 48,795 65,060 81,325 97,589 .

200,000 56,407 75,210 94,012 112,814 225,000 64,020 85,360 106,700 128,039 250,000 71,632 95,510 119,387 143,264 300,000 . 86,857 115,810 144,762

  • 173,714 350,000 102,082
  • 136,110 170,137 204,164 400,000
  • 117,307 156,410 195,512 234,614 450,000
  • 132,532 176,710 220,887 265,064 500,000 147,757 197,010 246,262 295,514 550,000 *162,982 217,310 271,637 325,964 600,000' 178,207 237,610 297,012 356,414 650,000 193,432 257,910 322,387 386,864 Benefits un,der the Retirement Plan 'are based on (i) average base compensation over the consecutive 60-month period in which pay is highest, (ii) years of credited service, (iii) age at retirement, and (iv) the offset of Social Security Benefits.

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

  • Fo~ purposes of the above table, based on 1995 compensation, credited years of service (including any additional years earned in connection with' the retirement agreements) for each of the individuals named in the cash compensation table would be as follows:

James T. Rhodes: 30; John: A. Ahladas: 30; Robert F. Hill: 30; Larry W. Ellis: 30 and James P. O'_Hanlon: 6.

Virginia Power's e_xecutive compensation program has placed increased emphasis on incentive compensation opportuni-ties 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-Flan). In i 995,* this adjustment was 11 percent. Also, the Internal Revenue Code limits the annual retirement benefit that may be paid from a qualified retirement plan and the amount of compensation that may be recognized by the Retirement Plan~ TO the extent that benefits* determined under the Retirement Plan's benefit formula exceed the limitations

  • imposed by the Internal Revenue Code, they will be paid under the Dominion Resources, Inc. Benefit Restoration Plan.
  • In 1995, the Company entered into an agreement with Mr. Ahladas which allowed him to retire on December 31, 1995 with Retirement .B~nefhs. approxiip.ately. equal to those he would have received had he remained an employee thro~gh June 21, 1997," * *
  • The Company also provides an Executive Supplemental Retirement Plan (the Supplemental Plan) to its elected officers designated to participate by the Board of Directors. The Supplemental Plan provides an annual retirement benefit equal to 25 percent of a participant's final compensation (base pay plus annual incentive plan payments). The normal form of benefit is payable in equal monthly installments* for 120 months to a participant with 60 months of service, who (i) retires at or after age 55 from the employ of the Compa11y, (ii) has become permanently disabled, or (iii) dies. If a participant dies while employed, the normal-form of )Jenefit wiU be paid to a designated beneficiary. If a participant dies while retired, b~t before receiving all benefit,payments, the remaining fastallments will be paid to a designated beneficiary. In order to be entitled to benefits under the Supplemental Plan, an employee must be employed as an elected officer of the Company until death, disability or retirement.

49

e

~ Based on 1995 compensation, the estimated annual retirement benefit for each of the executive officers under the Sup-plemental Plan would be as follows: James T. Rhodes: $164,790; John A. Ahladas: $74,650; Robert F. Hill: $80,775; Larry W. Ellis: $71,800; and James P. O'Hanlon: $84,747.

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 Plani and retirement agreements: Th~ 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 James T. Rhodes; John A. Ahladas, Robert F. Hill, Larry W. Ellis and James P. O'Hanlon, which provide benefits in the event of a change in control. Each Agreement has a three-year term and thereafter is automatically extended on its anniversary date for an additional year unless notified that the Agreement will not be extended by the C:ompany. 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 l)fter a material

.reduction in the executive's compensation, benefits or responsibilities, the Company will be obligated to pay to the executive contjnued compensation equaling the average base salary and cas4 incentive bonuses for the thirty-six full month period of employment preceding the change in control or employment termination. In addition, the terminated executive will continue to be entitled to any benefits due under any stock or benefit plans. The Agreements do *not alter the- compensation and benefits available to ,an executive whose employment with the Company continues for the fulherm of the executive's Agree-ment. The amount of benefits provided under each executive's Agreement will be reduced by any comp~nsation earned by the executive from comparable employment by another employer during the thirty-six. mont:p.s following termination of employment with the Company. An executive shall not be entitled to the above benefits in the event terininatiqn is for cause.

On April 21, 1995, the Company entered into an employment agreement with Dr. Janies T. Rpodes. This agreement was amended on September 15, 1995. As amended,-the agreement replaces a)Lprevious agreeip.ents between, the Company and Dr. Rhodes, except that his Employment Continuity Agreement, and various retirement, incentive and benefit plans in which Dr. Rhodes participates, remain in effect.

The amended agreement provides that Dr. Rhodes will continue in the employ of the Company, as Chief Executive Officer until July 31, 1999. During this term, Dr. Rhodes' base salary w1ll not be reduced/and he will participate in the compensation and benefit plans provided for senior management. * *** *

  • If Dr. Rhodes' employment is terminated, for any reason, after July 3 l, ~ 996, his retirell!ent bep.efits will be calculated using his final salary and will assume 60 years of age and 30 years of service. In additic;m, any restricted stock held. for Dr. Rhodes will become fully vested, his benefit under the Executive Supplemental Retirement Plan will be_paidJor life, he

. will receive immediate payment for all outstanding awards under the Performance Ach_ievement Plan, '.he will receive a lump sum payment approx:imately. eqm1l to his 1994 salary plus incentive, ari.d he .wiH.re_ceive a cash payment equal to the net present value of base salary and incentives that he would be projei::ted to receive between August.I-, 1996 and April 21,.1997.

Salary and incentive will be calculated at a rate not less than the maximum rate paid during the prior three years. These benefits will also be paid if Dr. Rhodes is terminated by the Company without cause prior to iuly*3 J, I 996: Termination as a result of disability' at any time during the term of employment, Will also result in the above benefits. Irr the case of termina-tion due to death, the above benefits will be paid to the designated beneficiary, but payments under the Executive Supple-mental Retirement Plan will be made for ten years.

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 and the Chairman of the Board receives an additional $25,000 annual retainer. These Directors may elect to defer their annual retainer and/or their meeting fees under the Deferred Compensation Plan until they retire from the 'Board or otherwise direct. The deferred fees are credited, for bookkeeping purposes, with earnings and losses as ifthey were invested in' either an interest bearing account or Dominion Resources Common Stock, depending on the Director's election.

  • 50

e In addition, the Company makes payments to non-employee Directors or their designated beneficiaries upon those a

Directors' retirement, death or disability. Payments to retired Director, including one who becomes disabled after retire-ment, are made for a period of four years, or for a period of years equal to the Director's service on the Board of the Company or one of its subsidiaries, whichever is longer. If a non-employee Director becomes disabled prior to retirement, these payments are made for four years. Each year, these payments equal the annuai retainer in effect at the time the pay-ments begin. Upon the death of a non-employee Director, the unpaid portion of these payments, up to a maximum of four times the annual amount due, is paid in a lump suni to the Director;s designated beneficiary.

Directors Charitable Contribution Program Dominion Resources administers a Directors' Charitable Contribution Program (the Program) for all its subsidiaries, including the Company, as part of its overall prbgram of charitable giving. Beginning at the death ofa Director a donation in an aggregate amount of $50,000 per year for' 10 years will be made to one or more qualifying charitable organizations*

  • recommended by the individual Director. Life insurance policies have _been purchased on the lives of the Directors in connec-tion 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 Prognµn. .

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below sets forth as of February 23, 1996, ~xcept as noted, .the number of shares of C~mmon 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
  • Deferred Compensation Name. Beneficially Owned Plan Account (a)

James T. Rhodes ....... :................. :...................... ,.. . 20,027 John A. Ahladas: ............. :............... ;.... :........ :..... :.

  • 3,851 Robert F. Hill ..... ;........ '.................. :...._.*. : ........ :.*.. :.. : 624 Larry W .. Ellis ........... :............... , .... :..... ;.............. .. 5,220 James P. O'Hanlon ........ :..... ,......................... ,...... .. 2,763, John B. Adams, Jr ....... ,.'. ....... , .............. ,:;: .......... .. 3,280 Tyndall L. Baucom ..... :....... :.; ........ :......................
  • 17,801 James F. Betts ..................................................... .. 7,500 Benjamin J. Lambert, III ........ ;*..... .".. :.:.: ......... ;.: .. .. 981 Richarcl L. Leatherwood .......... ,.....,................ :.... .. 1,000 4,395 Harvey L. Lindsay, Jr ........... :........... :.................... . 400.

William T. Roos .................... :....... ;...... :.'.::.: ......... . 11,496 ,, *2,120 Robert'fl. Spilman ..... ,.: .. :....... :..... .:... :............'. .. :.. :.. 1,088 William G, Thomas ............................... :.......*....... .. 3,058 (a) Represents shares the Directors have accumulated under the Deferred Compensation Plan.

(b) Members of Mr. Roos' family are beneficiaries of trusts that own 4,387 shares of Common Stock for which he disclaims beneficial ownership. * * ** *

  • All Directors and executive officers as a group (30 persons) beneficially own, in the aggr~gate, 176,958 shares of Com-mon Stock of Dominion Resources. Beneficial ownership of4,387 shares of the total are disclaimed, No shares of the Com-pany's Preferred Stock are owned by the Directors or executive officers as a group.

ITEM 13. CERTAIN RELATIONSHIPS AND. RELATED .TRANSACTIONS . . .

Hazel & Thomas, a professional corporation, from time to time acts as counsel to the Company. Mr. Thomas, a Director of the Company, is a shareholder of Hazel & Thomas;;

  • 51

e PART IV e

.ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)

The folfowing dbcuments

~e filed as part of this Form 10-K:

1. Financial Statements .

See Index on page 21.

2. Exhibits 3(i) * *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). . .

)(ii) . Bylaws, as am~nded, as in effect on December 31, 1994 (Exhibit 3(ii), Form 10-K for the fiscal year

.* . ended pecember 31, 1994, File No. 1-2255., incorporated by reference).

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

4(ii) Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental 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 lO"Q for the quarter ended September 30, 1986,

- Form.'10-Q*for the quarter ended June 30, 1987, File No. 1-2255, incorporated by reference); :

Sixty-Second Supplemental Indenture (Exhibit 4(ii), Form 8-K, dated November 3, 1987, File No. l-

'.?255, incorporated by r~ference); Sixty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated

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), Forni 8-K, dated February 27, 1990, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference);

Sixty-Eighth Supplemental Indenture, (Exhibit 4(i)), Sixty-Ninth Supplemental Indenture; (Exhibit .

4(ii)) and Seventieth Supplemental Indenture, (Exhibit 4(iii),.Form"8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture, (Exhibit 4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture, (Exhibit 4(i),

Form 8-K, dated Augus~ 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), Forin 8-K, dated April 6, 1993, File No. 1~2255, incorporated by reference); Seventy-Sixth Supplemental Indenture,

. (Exhibit4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference);,

Seventy-Seventh Supplemental Indenture, (Exhibit 4(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); SeventysNinth 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, I993, File No. 1-2255, incorporated by reference); Eighty-First Supplemental Indenture, (Exhibit 4(iii), Form 10-

...K for: .tll~ _f1scalyear _ended.Decymber 31, 1993, File No. 1-2255, incorporated by reference); Eighty-

.** Secorid'Suppleinerttal 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); and Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 22; 1995, File No. 1-2255, incorporated by reference).

4(iii) Inderit~r~i dated* April* 1,' 198{ between Virginia Electric and Power Company* and Crestar Bank (form.erly United Virginia Bank)*(Exhibit 4(iv), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

4(iv) Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and Chemical Bank (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).

52

4(v)

Indenture, dated April 1, 1988, between Virginia Electlic and Power Company and Chemical Balli\.~

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(vi) Indenture, dated as of August 1, 1995, from Virginia Electric and Power Company to Chemical Bank, Trustee, as supplemented and modified by a First Supplemental Indenture, dated* as of August 1, 1995, pursuant to which the Series A 8.05% Junior Subordinated Notes were issued to fund*the purchase of Virginia Power Capital Trust 1 Common Stock and Preferred Securities proceeds (Exhibits 4(a) and 4(b), respectively, Form S-3 Registration Statement No. 33-61265 as filed on July 24, 1995 and amended on August 21, 1995 and August 22, 1995, incorporated by reference).

4(vii) Virginia Electric and Power Company agrees to furnish to the Commission upon request any other instrument with respect to. long-term debt .as .to which the total amount of _securities authorized thereunder does riot exceed 10 percent of Virginia Electric and Power Company's total assets.

lO(i) Operating Agreement, dated June 17, 1981, between Virginia Ele~tric and J=>ower Company and Monongahela Power Conwany, 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). * . ,

lO(ii) Purchase, Construction and Ownership Agreement, dated as of Decem_ber 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 for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference). . , .

1O(iii) Interconnection and Operating Agreement, dated as of_ December 28, 1982 as amended and restated on October 17, 1983, between Virginia Electric and Power Company ~d Old Dominion Electric Cooperative (Exhibit lO(ix), Form rn.:K for the fiscal year endeq December 31, 1983, File No. 1-8489, incorporated by*reference).

  • lO(iv) Nuclear Fuel Agreement, dated as of December 28, 1982 as amended and restated on October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(x), Form 10-K for the fiscal year ended December 31, 1983,' File No. 1-8489, incorporated by reference).
  • lO(v) Credit Agreement*dated as of September.I, 1995, *between Chemical Bank and Virginia Electric and Power Company (filed herewith).

lO(vi) Credit Agreement, dated December 1, 1985, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xix), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-8489, incorporated by reference).

lO(vii) Agreement for Northern Virginia Services, dated as of November l; 1985, between Potomac Electric Power Company and Virginia Electric and Power Company (Exhibit lO(xxi), Form 10-Kfor the fiscal year ended December 31, 1985, File No. 1-8489, incorporated by reference). .

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

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

lO(x) Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and 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 specifications) (Exhibit lO(xiii), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).

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

.lO(xxi)* Description of arrangements with certain officers 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).

lO(xxii)* Dominion Resources, Inc. Directors' Deferred Compensation Plan effective July 1, 1986 (Exhibit lO(xxii), Form 10-K for the fiscal year *ended December 31, 1994, File No. 1-2255, incorporated by reference).

  • lO(xxiii)* Dominion Resources, Inc. Performance Achievement Plan, effective January 1, 1986, as amended and 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).

53

,.. e e lO("iXxiv )* Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 1981 as amended and restated effective October 22, 1988 and as amended and restated June 15, 1990 (Exhibit lO(xxiv); Form 10-K for the fiscal year ended December 31, 1994, File'No. 1-2255,"1 incorporated by reference).

lO(xxv)* Dominion Resources, Inc.'s Cash Inc~ntive 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).

lO(xxvi)* Dominion Resources, Inc. Long-Term Incentive Plan, effective April 17, 1987 (Exhibit lO(xxvi),

lO(xxvii)*

  • Employment Continuity Agreement for James T. Rhodes of Virginia Power (Exhibit lO(xxvii), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).

lO(xxviii)* Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 (Exhibit lO(xxviii), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).

  • lO(xxix)* Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective January 1, 1991 (Exhibit lO(xxix), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).

lO(xxx)* Dominion Resources, Inc. Executives' Deferred Compensation Plan, effective January 1, 1994 (Exhibit lO(xxx), Form 10-K for the fiscal year ended December 31, 1994, File No. 1°2255, incorporated by reference).

lO(xxxi)* Employment Agreement dated April 21, 1995 between Virginia Power and James J'. Rhodes (Exhibit 10, Form 10-Q for the period ended March 31, 1995, incorporated by reference) and an amendment dated September 15, 1995 (Exhibit 10, Form 10-Q for the period ended September 30, 1995, incorporated by reference).

  • lO(xxxii)* Employment Agreement dated June 23, 1994 between Virginia Power and LW. Ellis (Exhibit lO(xxxiv), Form 10-K for the fiscal year ended December 31, 1994, incorporated by reference).

23(i) Consent of Hunton & Williams (filed herewith).

23(ii) Consent of Jackson & Kelly (filed herewith).

23(iii) Consent of Deloitte & Touche LLP (filed herewith).

27 Financial Data Schedule (filed herewith).

99(i) Consent Order by the Virginia State Corporation Commission (Item 5., Form 8-K dated February 21, 1995, incorporated by reference). ,

  • Indicates management contract or compensatory plan or arrangement (b) Reports on Form 8-K None .

54

~I

  • SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VIRGINIA ELECTRIC AND POWER COMP ANY Date: March 12, 1996 By Isl JOHN B. ADAMS, JR.

_ _ _ _ ____;,..:c......c:....:..:cc.;,____ _ _- ' -_ _ _ _ __

(John B. Adams, Jr., Chairman of the Board of Directors)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 12, 1996.

Signature Title Isl JOHN B. ADAMS, JR. Chairman of the Board of Directors John B: Adams, Jr. and Director Isl TYNDALL BAUCOM Director Tyndall L. Baucom Isl JAMES F. BETIS Director James F. Betts.

Isl BENJAMIN J. LAMBERT, III Director Benjamin J. Lambert, III Isl RICHARD L. LEATHERWOOD Director Richard L. Leatherwood Isl HARVEY L. LINDSAY, JR. Director Harvey L. Lindsay, Jr.

Isl J. T. RHODES President (Chief Executive Officer)

J, T. Rhodes and Director Isl WILLIAM T. Roos Director William T. Roos Director a

Robert H. Spilman Isl WILLIAM G. THOMAS Director William G. Thomas Isl R. E. RIGSBY Executive Vice President R. E. Rigsby Isl E. M. ROACH, JR. Senior Vice President-Finance, E. M. Roach, Jr. Regulation and General Counsel (Chief Financial Officer)

Isl M. S. BOLTON, JR. Controller (Principal Accounting M. Stuart Bolton, Jr. Officer) 55

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