ML18151A559

Forwards Annual Rept to Securities & Exchange Commission on Form 10-K for 1991 & Company Current Rept on Form 8-K, Comparative Statement of Income for Three Months Ended Dec 1991 & 1990 & Internal Cash Flow Projection for CY92

ML18151A559
Person / Time
Site:	Surry, North Anna
Issue date:	03/27/1992
From:	Stewart W VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:	Office of Nuclear Reactor Regulation
References
92-213, NUDOCS 9204010312
Download: ML18151A559 (66)

Text

• '

e VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 10 CFR 140.21 (e)

March 27, 1992 Director, Nuclear Reactor Regulation United States Nuclear Regulatory Commission Washington, D. C. 20555 Gentlemen:

VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 NORTH ANNA POWER STATION UNITS 1 AND 2 PRICE-ANDERSON ACT Serial No.

NURBP Docket Nos.

License Nos.92-213 50-280 50-281 50-338 50-339 DPR-32 DPR-37 NPF-4 NPF-7 Pursuant to 1 O CFR 140.21 (e) regarding guarantees of payment of deferred premiums, we are providing the following information:

1.

Annual Report to Securities and Exchange Commission on Form 10-K for 1991 and the Company's current report on Form 8-K.

2.

Comparative Statement of Income for the three months ended December 31, 1991 and 1990.

3.

Internal cash flow projection for calendar year 1992 with certification by officer of the Company.

4.

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

In accordance with 1 O CFR 140.7, we submitted a check to the NRC for $1,000 on November 6, 1991, which is the minimum required premium for the period November 15, 1991, through November 14, 1992.

Very truly yours, J.1?~

W. L':-stewart Senior Vice President - Nuclear Enclosures

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9204010312 920327

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

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

PAGE 1 e

SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C.

20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934 Date of Report (Date of earliest event reported) ______ F_..e....

br.... u-a....

ry~28_, __

l....,99.. 2...._ __

Virginia Electric and Power Company (Exact name of registrant as specified in its charter)

Virginh (State of other juris-diction of Incorporation) 1-2255 (Corrmhsion File Number)

One James River Plaza, Richmond, Virginia (Address of principal executive offices) 54-0418825 (IRS Employer Identification No.)

23261-6666

{Zip Code)

Registrant's telephone number, including area code ____ ___.C..._80 __ 4...,.l..... 7.... 7_1 __

-3_.0..._0....

0_* __ __

(Fonner name or former address, if changed since last report.)

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e PAGE 2 ITEM 5.

OTHER EVENTS On February 28, 1992, the Supreme Court of Virginia entered an order on appeal reversing the Final Order of the Virginia State Corporation Conmission (the Virginia Conmission) in the Company's 1990 rate case, which authorized a rate increase of $79.8 million per year.

The Court held that the Virginia Conmission erred by permitting Virginia Power to proceed with an application for rate relief on an expedited basis and stated that it will remand the case to the Virginia Conmission with instructions to order appropriate refunds to ratepayers and to dismiss Virginia Power's application.

The Company is evaluating its options. The ultimate outcome cannot be determined at the present time but the effects may be greater than previously anticipated and could prove to be significant.

PAGE 3 SIGNATURES Pursuant to the requirements 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.

Date:

February 28, 1992

e e

VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF INCOME (UNAUDITED)

Operating Revenues Operating Expenses:

Operation - Fuel used in electric generation

- Purchased and interchanged power

- Other Maintenance Depreciation Amortization of abandoned project costs Taxes - Income

- Other Total Operating Income Other Income:

Allowance for other funds used during construction Miscellaneous, net Income taxes associated with miscellaneous, Total Income Before Interest Charges Interest Charges:

Interest on long-term debt Other Allowance for borrowed funds used during construction Total Net Income Preferred Dividends

• Balance Available for Common Stock net Three Months Ended December 31, 1991 1990 (OOO's)

$885,656

$819,803 126,627 139,101 146,261 131,116 153,869 121,151 88,940 85,425 96,924 93,782 9,556 12,454 39,582 22,692 56,458 47,678 718,217 653,399 167,439 166,404 918 985 7,491 6,693 (2,486)

(2,867) 5,923 4,811 173,362 171,215 79,888 88,276 7,707 1,133 (404)

(484) 87,191 88,925 86,171 82,290 12,378 14,301

$ 73,793

$ 67,989

e VIRGINIA ELECTRIC AND POWER COMPANY 1992 ESTIMATED INTERNAL CASH FLOW (Millions of Dollars)

January April July through through through March June September Cash Receipts

$1,020.9 $878.1

$1,037.1 Less:

Cash for Operations 554.4 543.7 565.5 Taxes 42.9 158.4 144.9 Interest 73.4 88.6 91.4 Dividends

- Preferred Stock 12.2 14.6 14.2

- Common Stock 92.2 91.0 89.9 Decommissioning Trust 6.0 5.9 5.9 Changes in working capital (11.4) 27.6 6.8 Internal cash flow 251. 2

( 51. 7) 118.5 Pl us:

Proceeds from sale of 11.6% of North Anna to Old Dominion Electric Co-op

1. 2 1.2 1.2 Total Cash Flow (1)

$ 252.4

$(50.5)

$ 119. 7 (1)

Before financing and construction requirements.

October Estimated through 1992 December Total

$972. 4

$3,908.5 548.2 2,211.8 153.2 499.4 96.1 349.5 15.0 56.0 91.8 364.9 6.0 23.8 (13.2) 9.8 75.3 393.3

1. 2 4.8

$ 76.5

$ 398.1

VIRGINIA ELECTRIC AND POWER COMPANY CERTIFICATE I, the undersigned B. D. Johnson, 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 1992, provided herewith, is based on the best available information known at this time and is a reasonably accurate projection of the Company's 1992 cash flow.

However, this cash flow projection does not reflect the effects nor any act i ans necessary to compensate for the event described in the Company's current report on Form 8-K, attached.

Commonwealth of Virginia City of Richmond Sworn to and subscribed ~efore me this

/9 day of~l992.

My commission expires:~/~ /99.;?

NOTARIAL SEAL

/ B.,. Johnson Senior Vic President-Finance and Controller

e VIRGINIA ELECTRIC AND POWER COMPANY STATEMENT The Company currently estimates 1992 construction and nuclear fuel expenditures (exclusive of Allowance for Funds Used During Construction) to be

$834 million.

Of this amount, it is expected that approximately $400 million will be obtained from internal sources.

The remaining $434 million of construction requirements, as well as the $90 million of debt and preferred stock maturities and sinking fund requirements, will be obtained by a combination of sales of securities and borrowings under the Inter-Company Credit Agreement with Dominion Resources.

The Company is reasonably assured that, based on the best available cash flow projections which are provided herewith, curtailment of capital expenditures for required nuclear programs would not be required to cover the Price-Anderson maximum retrospective premium assessment for a single incident of $264.6 million ($66.15 million for each of the four reactors owned by the Company with assessments not to exceed $10 mill ion per reactor per year) currently in force.

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

~

ANNUAL REPORT PURSUANT TO SECTION 13 OR lS(d) OF THE SECURITIES EXCHANGEACT OF 1934 For the fiscal year ended December 31, 1991

• or 0

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

( State or other jurisdiction of incorporation or organization)

One James *River Plaza Richmond, Virginia (Address of principal executive offices)

(804) 771-3000 54-0418825 (l.R.S. Employer identification. no.)

23261-6666 (Zip Code)

(Registrant's telephone number, including area code)

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

Title of each class Preferred Stock (cumulative)

• $100 liquidation value:

$5.00 'dividend

$7. 72 dividend

$7.45 dividend

$7.20 dividend

$7.72 dividend (1972 Series)

$8.60 dividend Name of each exchange on which registered New York Stock Exchange Securities registered pursuant tci Section 12(g) of the Act:

None (Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section.

13 or 15(d) of the Securities Exchange Act of 1934 during the *preceding 12 months (or for such shorter.

period that th~ 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 of Regulation S-K is not contained herein, and will not be contained, to the best ofregistrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this F9rm 10-K. [

]

The aggregate market value of the voting stock held by non-affiliates of the registrant as of January 31, 1992 was zero.

As of January 31, 1992, there were issued and outstanding 162,741 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

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THIS PAGE INTENTIONALLY LEFT BLANK

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 23261-6666, telephone (804) 771-3000. It is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion Resources), a Virginia corporation.

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

The Company has nonexclusive franchises or permits for electric operations in substantially all cities and towns now served. It also has certificates of convenience and necessity from the Virginia State Corporation Commission (the Virginia Commission) for service in all territory served at retail in that State. The North Carolina Utilities Comm~ssion (the North Carolina Commission) has assigned territory to the Company for substantially all of its retail service outside certain municipalities in that State.

A wholly-owned subsidiary of the Company, Virginia Power Fuel Corporation (VP Fuel), owns and finances nuclear fuel and related materials for the Company's Surry nuclear units, and sells the heat from such fuel to the Company. VP Fuel finances its operations through the sale of commercial paper, which is guaranteed by the Company.

The Company strives to operate its generating facilities in accordance with prudent utility industry practices and in conformity with applicable statutes, rules and regulations. Like other electric utilities, the Company's generating facilities are subject to unanticipated or extended outages for repairs, replacements or modifications of equipment or otherwise to comply with regulatory requirements. Such outages may involve significant expenditures not previously budgeted, including replacement energy costs. See Nuclear Regulation under REGULATION.below and Nuclear Operations and ]fuel. Supply under SOURCES OF ENERGY USED AND FUEL COSTS.

The Company had 12,573 full-time employees on December 31, 1991. Approximately 4,600 of the Company's employees are represented by the International Brotherhood of Electrical Workers under a contract extending to March 31, 1992. The Company considers its relations with its union and nonunion employees to be good.

e e*

VIRGINIA ELECTRIC AND POWER COMPANY Item Number I. Business......... *...............

The Company....................

Capital Requirements and Financing Program.

Construction and N~clear Fuel Expenditures.

Financing Program Rates........

Virginia.......

North Carolina...

County and Municipal Customers Governmental-Commonwealth of Virginia.

Federal Energy Regulatory Commission.

Governmental-Federal........

Regulation......

General......

Environmental..

Nuclear.......

Sources of Power.

Company Generating Units Utility Purchases......

Non-Utility Generation...

Sources of Energy Used and Fuel Costs.

Nuclear Operations and Fuel Supply.

Coal Supply...........

Natural Gas Supply.......

Purchases and Sales of Power.

Interconnections.........

Future Sources of Power....

Company Owned Generation Non-Utility Generation....

Competition. :..........

Conservation and Load Management.

2. Properties..................

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

4. Submission of Matters to a Vote of Security Holders.

PART I PART II

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

6. Selected Financial Data.........'...............

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

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

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

PART III

10. Directors and Executive Officers of the Registrant.

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

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

13. Certain Relationships and Related Transactions..

PART IV

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

Page Number I

2 2

2 2

3 3

3 3

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• . 10 10 10 11 II 11 12 17 43 43 46 51 51 51

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 1992-1994, total $2.6 billion. It has adopted a 1992 budget for construction and nuclear fuel expenditures as set forth below:

New Generating Facilities:

Estimated 1992 Expenditures (millions)

Chesterfield Unit 8................................

$ 18 Clover Unit 1 and Unit 2...................... :....

184 Other Production....................................

210 General Support Facilities............................

58 Transmission. :............ *. *.......................

61 Distribution................... ;...................

250 Nuclear Fuel......................................

53 Total Construction Requirements and Nuclear Fuel........

834 AFC.................... *........................

13 Total Expenditures...... :.........................

$847 Financing Program In 1991, Virginia Power obtained $449 million from the sale of securities. Its long-term financings included $100 million of First and Refunding Mortgage Bonds, $199 million of unsecured Medium-Term Notes and $150 million of Common Stock sold to Dominion Resources. From the proceeds of the 1991 securities sales, the Company retired $144.9 million of securities through mandatory debt maturities and sinking fund requirements and retired an additional $265.5 million of debt through optional redemptions and sinking fund payments. See Liquidity and Capital Resources under MANAGEMENT'S DISCUS-SION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Virginia Power's 1992 construction requirements, exclusive of AFC and refundings, are estimated to be $834 million, as detailed above. Of this amount, it is expected that approximately $400 million will be obtained from internal sources. The remaining $434 million of construction requirements, as well as the $90 million of debt and preferred stock maturities and sinking fund requirements, will be obtained by a combination of sales of securities and borrowings under the Inter-Company Credit Agreement with Dominion Resources. See Liquidity and Capital Resources under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

RATES The Company was subject to rate regulation in 1991 as follows:

Virginia retail:

Non-Governmental customers........

Governmental customers............

North Carolina retail................

Wholesale........................

Virginia Commission Not regulated (negotiated agreements)

North Carolina Commission Federal Energy Regulatory Commission (FERC) 2 Percent of Revenues 81%

11 4

4 1991 Percent of

• Kwh Sales 77%

13 4

6 100%

100%

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

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

The principal rate proceedings in which the Company was involved in 1991 are described below by jurisdiction. Rate relief obtained by the Company is frequently less than requested.

Virginia On April 22, 1991 the Virginia Commission entered its Final Order in the 1990 rate proceeding authorizing a rate increase of $79.8 million based on a 1989 test year. The Order approved an adjustment to offset attrition in earnings by allowing rate base to be updated to a point seven months beyond the end of the test year. An interim rate increase of $136.9 million had been in effect since May 1, 1990, and approximately $58 million of the amount recovered under interim rates was refunded to customers. The Final Order was appealed to the Virginia Supreme Court by parties challenging the attrition adjustment.

If the Commission's order is reversed it could, depending upon the grounds for reversal, result in either (i) a refund of approximately $27 million or (ii) a prospective rate reduction of approximately $17.3 million, together with a refund of that annual amount retroactive to May 1, 1990. The Virginia Supreme Court heard oral argument on January 8, 1992.

On August 1, 1991, the Company filed with the Virginia Commission an application for an increase in base rates of $183.9 million. The Virginia Commission allowed the proposed increase in base rates effective September I, 1991, subject to refund, pending a final Order. Parties opposing the increase have suggested reductions that in the aggregate would result in an *increase of only $36.9 million. The Commission Staff has recommended an increase of $83.9 million. In rebuttal testimony Virginia Power reduced its requested increase to $148.5 million. A hearing to receive comments from the public was held on January 15, 1992, and the hearing to receive the evidence of the parties was held on January 29 through February 4, 1992. The Company is recognizing revenues at a level management believes is appropriate in view of the facts in this case, pending a final Commission Order.

North Carolina On September 13, 1991, the Company filed with the North Carolina Commission an application for a rate increase of $4.6 million based solely on the cost of fuel. On December 18, 1991, the North Carolina Commission issued an Order approving a $4.2 million increase effective on and after January 1, 1992.

County and Municipal Customers On December 31, 1991, Virginia Power reached agreement on the terms of a three-year contract governing rates for county and municipal customers in Virginia, which will continue through June 30, 1994. Pursuant to this contract an increase of $5.9 million became effective July 1, 1991. Additional increases of $9.7 million and $6.8 million will become effective on July 1, 1992 and July 1, 1993, respectively.

Governmental-Commonwealth of Virginia Governmental base rates for the Commonwealth of Virginia are unregulated but follow the methodology approved by the Virginia Commission for jurisdictional base rates. On September 1, 1991, an increase of $3.0 million was placed into effect, subject to refund, based upon the ratemaking methodology filed in Virginia on August I, 1991.

Federal Energy Regulatory Commission On August 7, 1990, the Company filed with FERC an application for a rate increase of $8.5 million from the Company's wholesale customers, which was combined by FERC with an investigation concerning the Company's existing wholesale rates. The proposed rates became effe~tive, subject to 3

refund, on March 16, 1991. By letter order dated September 16, 1991, FERC formally approved a settlement between the Company and its wholesale customers providing for an annual rate increase of

$3.5 million, effective March 16, 1991.

On July 31, 1991, the Company filed with FERC an application for a rate increase of $17.4 million, proposed to be effective on October 1, 1991, from the Company's wholesale customers. FERC suspended the rate increase for the five-month statutory period until March 1, 1992. On February 7, 1992, the Company reached a tentative settlement in principle with all parties to the case. The settlement in principle has not been filed with FERC.

Governmental-Federal Rates for federal governmental customers are unregulated but follow the ratemaking methodology approved by FERC for the Company's resale service to municipalities. Based on the $3.5 million settlement with FERC customers, the equivalent increase for federal government customers is $6.3 million, effective March 16, 1991.

Based on the July 31, 1991 FERC filing the proposed increase for federal government customers is

$12.0 million. This increase is scheduled to become effective March 1, 1992, subject to refund.

REGULATION General In a wide variety of matters in addition to rates, the Company is presently subject to regulation by the Virginia Commission and the North Carolina Commission, the Environmental Protection Agency (EPA), Department of Energy (DOE), Nuclear Regulatory Commission (NRC), FERC, the Army Corps of Engineers, and other federal, state and local authoritie.s. Compliance with numerous laws and regulations increases the Company's operating and capital costs by requiring, among other things, changes in the design and operation of existing facilities and changes or delays in the location, design, construction and operation of new facilities. The commissions regulating the Company's rates have historically permitted recovery of such costs.

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

Environmental From time to time, the Company may be identified as a potentially responsible party with respect to a Superfund site. EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation and feasibility study and remedial action or (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, which amounts cannot be determined at the present time but could ultimately prove to 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 continuin~ review.

The Company is subject to the Clean Air Act (Air Act), which provides the statutory basis for ambient air quality standards. In order to maintain compliance with such standards and reduce the 4

impact of em1ss1pns on ambient air quality, the Company may be required to incur additional expenditures, the amount of which is not presently determinable but which could be significant, in constructing new facilities or in modifying existing facilities.

In November 1990, the President signed Air Act amendments. These amendments will require the Company to reduce sulfur dioxide and nitrogen oxides emissions in two phases. The Company's emissions of sulfur dioxide and nitrogen oxides are relatively low in comparison to many other electric utilities. Nevertheless, the cost impact on the Company to comply with the amendments will be significant. The Company anticipates having to install emission monitoring equipment and has entered into an agreement for the installation of a scrubber at its Mt. Storm Power Station to be operational by January 1, 1995. The scrubber is expected to cost approximately $140 million. The Company will probably need to install two additional scrubbers to meet standards for the second phase. Full.

compliance with both phases must be achieved no later than January 1, 2000. The capital cost for compliance with both phases, assuming the installation of three scrubbers, is estimated at $470 million (1990 dollars). Annual incremental compliance costs for operation, maintenance and fuel costs are estimated to be $140 million (1990 dollars).

Nuclear Regulation 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 exrsting nuclear reactors. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining the Company's nuclear generating units.

SOURCES OF POWER Company Generating Units Name of Station, Units and Location Nuclear:

Surry Units 1 & 2, Surry, Va................

North Anna Units 1 & 2, Mineral, Va.........

Total nuclear stations...................

Fossil Fuel:

Steam:

Bremo Units 3 & 4, Bremo Bluff, Va........

Chesterfield Units 3-6, Chester, Va..........

Mt. Storm Units 1-3, Mt. Storm, W. Va......

Chesapeake Units 1-4, Chesapeake, Va.......

Possum Point Units 3 & 4, Dumfries, Va.....

Yorktown Units 1 & 2, Yorktown, Va.......

Possum Point Units 1, 2, & 5, Dumfries, Va...

Yorktown Unit 3, Yorktown, Va...........

Combustion Turbines:

35 units (8 locations).....................

5 Years Installed 1972-73 1978-80 1950-58 1952-69 1965-73 1953-62 1955-62 1957-59 1948-75 1974 1967-90 Type of Fuel Nuclear Nuclear Coal Coal Coal Coal Coal Coal Oil Oil & Gas Oil & Gas Summer Capability Mw 1,562 l,820(a) 3,382 227 1,250 1,596 595 322 321 929 818 1,019

Name of Station, Units and Location Combined Cycle:

Chesterfield Unit 7, Chester, Va............

Total fossil stations....................

Hydroelectric:

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

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

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

Bath County Units 1-6.....................

Total hydro stations....................

Total Company generating unit capability....

Utility Purchases............................

Non-Utility Generation.......................

Total Capability.......................

Years Installed 1990 1963 1955 1930-87 1985 Type of Fuel Oil & Gas.

Conventional Conventional Conventional Pumped Storage Summer Capability Mw 195 7,272 225 104 3

l,260(b) 1,592 12,246 1,030 1,312 14,588 (a) Includes an undivided interest of 11.6 percent (211 Mw) owned by Old Dominion Electric Cooperative (ODEC).

• (b) Includes only the Company's 60 percent undivided interest in the 2,100 Mw station. A 40 percent undivided interest in the facility is owned by Allegheny Generating Company, a subsidiary of Allegheny Power System, Inc. (APS).

The Company's highest one-hour integrated service area summer peak demand was 12,939 Mw established on July 23, 1991, and the highest one-hour integrated winter peak demand was 12,697Mw established on December 22, 1989. At the time of these peaks, the Company had a total summer capability of 14,863 Mw and a total winter capability of 13,838 Mw.

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

SOURCES OF ENERGY USED AND FUEL COSTS For information as to energy supply mix and the average fuel cost of energy supply, see Results of Operations under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDI-TION AND RESULTS OF OPERATIONS.

Nuclear Operations and Fuel Supply In 1991, the Company's four nuclear units achieved a combined capacity factor of 80.6 percent, a new Company record. In addition, the nuclear program received an improved Systematic Appraisal of Licensee Performance (SALP) rating from the NRC for both its Surry and North Anna Power Stations.

On December 23, 1991, North Anna Unit 1 was shut down for a mid-cycle steam generator inspection and maintenance outage. Current plans call for the unit to be restarted in late March 1992, although the outage duration and conditions under which it may return to service are subject to the results of the inspection and NRC approval. The Company had planned to replace the steam generators at North Anna Unit 1 in the second half of 1995. As a result of the information obtained during the refueling outage in early 1991, the Company decided to advance the steam generators replacement to January 1993. The replacement of the steam generators is estimated to cost approximately $166 million and to take approximately 150 days to complete.

6

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e e

The Company utilizes both long-term contracts and spot purchases to support its needs for nuclear fuel. Virginia Power's nuclear fuel supply and related services are expected to be adequate to support current and planned nuclear generation requirements. The Company continually evaluates market conditions in order to obtain adequate nuclear fuel supply. Current agreements, inventories and market conditions will support planned fuel cycles into the mid-1990s.

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

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

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

Coal Supply In 1991, Virginia Power consumed approximately 10.0 million tons of coal. As with nuclear fuel, the Company utilizes both long-term contracts and spot purchases to support its needs. The central Appalachian coal market, from which the Company purchases most of its coal, continues to produce coal supplies sufficient for the Company's needs. The Company presently anticipates that sufficient coal supplies at reasonable prices will be available at least into the mid-1990s.

Natural Gas Supply On May 21, 1991, the Virginia Commission approved the Company's application to construct a 16-mile pipeline lateral to bring gas from the Virginia Natural Gas, Inc. pipeline to the Chesterfield Power Station, and a certificate of public convenience and necessity was issued by the Virginia Commission on June 18, 1991. Construction began on the pipeline in September 1991 and it is expected to be placed in service in late February 1992.

Purchases and Sales of Power Virginia Power reduces fossil fuel costs by purchasing power from other utility systems when it is available at a cost lower than the Company's own generation costs. It also relies upon purchases of power to meet an increasing amount of its capacity requirements.

• 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., and agreed to purchase 500 Mw of electricity annually during 1987-99 from certain operating subsidiaries of American Electric Power Company, Inc. (AEP). The Company also contracted with Carolina Power and Light Company (CP&L) to purchase 100 Mw for January and February 1991 and 300 Mw from June through August 1991.

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

On November 26, 1991, the Company and ODEC signed an agreement whereby the Company will provide ODEC 300 Mw of firm capacity and associated energy from January 1, 1993, until the commercial operation of Clover Unit 1 (currently scheduled for June 1995) or December 31, 1995, whichever occurs first. The Company will also provide 100 Mw of firm capacity and associated energy from the commercial operation of Clover Unit 1 until the commercial operation of Clover Unit 2 (currently scheduled for June 1996) or December 31, 1996, whichever occurs first.

Virginia Power also has 74 non-utility power purchase contracts with a combined dependable summer capacity of 3,455 Mw. Of this amount, 1,312 Mw were operational at the end of 1991 with the 7

e balance scheduled to come on-line through 1997 (see Non-Utility Generation under FUTURE SOURCES OF POWER and Note M to FINANCIAL STATEMENTS).

INTERCONNECTIONS The Company maintains major interconnections with CP&L, AEP, APS and the utilities in the Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission network, the Company has arrangements with these utilities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy.

On March 23, 1990, the Company and Appalachian Power Company (an operating unit of AEP) announced an agreement to increase the ability to exchange electricity between the two companies through the construction of major Jransmission facilities. J'he proposed construction will consist of 212 miles of new transmission lines and related substation improvements. The transmission additions will include 110 miles of 765 Kv and 102 miles of 500 Kv lines. Completion of the project will take three to four years after all final regulatory approvals have been obtained. The Company filed an application with the Virginia Commission on July 19, 1991 for approval of the 102 mile 500 Kv portion of the project, and the application has been set for a local hearing on April 23, 1992, followed by the principal hearing beginning April 27, 1992.

FUTURE SOURCES OF POWER The Company presently anticipates that system load growth will require approximately 5,200 Mw of additional capacity during the 1990s. The Company has and will pursue capacity acquisition plans to provide that capacity and maintain a high degree of service reliability. This capacity may be built, owned and operated by others and sold to the Company under a competitive bid process or may be built by the Company if it determines it can build capacity at a lower overall cost. _The Company also pursues conservation and demand~side management (see CONSERVATION AND LOAD MANAGEMENT below).

On May 1, 1990, the Commission adopted a Hearing Examiner's findings criticizing the Company's capacity planning and acquisition process and directed its Staff to increase its administrative review of that process and to expand its review of the Company's long-range forecasts. On June 14, 1991 the Staff filed a report of its review in which it indicated that changes in the Company's capacity planning and acquisition process had significantly enhanced that process, and that the process now is comprehensive and fundamentally sound. On November 28, 1990, the Commission adopted rules governing electric and capacity bidding programs. The Company supported those mies, which did not require any material change in the Company's existing program of competitive bidding. The rules preclude arbitration proceedings for capacity offered to the. Company outside. of the competitive bidding process. Two arbitration proceedings that were initiated prior to November 28, 1990 are ongoing. These two proceedings relate to units that aggregate 524 Mw.

In 1987, the Company signed agreements for the purchase of approximately 1,300 M w of additional capacity from six non-utility power producers substantially all of which are either operati~nal or under construction. In 1988, as a result of a competitive bidding solicitation, the Company entered into 19 contracts for approximately 2,000 Mw of additional capacity for initial delivery at various dates through 1994. Seven of these contracts totalling 746 Mw have subsequently been terminated. The Company also issued a Request for Proposals in August 1989 for competitive bids for up to an additional 1,100 Mw of power to come on-line during 1995-1997. Bids were received in January 1990 from 38 developers for 78 projects aggregating 11,600 Mw of capacity. Contracts were executed with three developers in July 1990 for capacity totalling 448 Mw. One project of 210 Mw was later terminated for failure to post financial security according to schedule. The contracts from all three solicitations are generally for a duration of 25 years after the commencement of commercial operation. The projects cover a variety of technolo-gies, fuel supplies, pricing mechanisms, and in-service dates. Each agreement for the purchase of power contains liquidated damage provisions that may be exercised if the electricity is not available as scheduled. The Company has also developed a contingency plan to meet the demand for power in the 8

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event that the growth in demand exceeds present forecasts or in the event of a failure of any of these power purchase agreements. See Note M to FINANCIAL STATEMENTS.

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

In May 1990, the Company entered into an agreement with ODEC, under which the Company purchased a 50 percent undivided ownership interest in a 782 Mw coal-fired power station to be constructed near Clover, Virginia in Halifax County. The Company will operate the power station after it is completed. The cost of the Company's 50 percent ownership interest is expected to be approximately $568.4 million. At the time the Company executed the agreement with ODEC, on-site construction of the first unit was expected to begin in September 1990 and on-site construction of the second unit was expected to begin one year later. On April 29, 1991, the Virginia Air Pollution Control Board issued the environmental permit regulating emissions into the air for the facility. The issuance of that permit was, however, appealed to the EPA by the Southern Environmental Law Center (the Center). On January 29, 1992, the EPA denied the appeal by the Center. The Center has 60 days from the date the denial is published in the Federal Register to appeal the decision of the EPA to the U.S.

Fourth Circuit Court of Appeals. At year end, the Company's share of costs related to the project were approximately $149 million. On January 31, 1992, the Company and ODEC directed the construction contractor to begin permanent on-site construction of the facility. See Note E to FINANCIAL STATEMENTS.

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

Company Owned Generation Name of Units Chesterfield 8 Clover Project:

Unit 1 Unit 2 Summer Capability Mw 205 391*

391*

Expected In-Service Date June 1992 June 1995 June 1996

• Includes the 50 percent undivided ownership interest of ODEC. Under certain conditions, the Company's ownership interest could increase above 50%. See Note E to FINANCIAL STATE-MENTS.

Non-Utility Generation Projects Operational Projects Financed Unfinanced Projects Total Contracts Number of Projects 42 12 20 74 COMPETITION Mw 1,312 1,598 545 3,455 Competition is playing an important role in the Company's business. Public utilities such as the Company have been granted franchises to serve all classes of retail customers within designated service areas in return for a commitment to provide adequate service on a fair and reasonable basis. This 9

e traditional arrangement is being altered due to changing federal and state governmental regulations, technological developments, rising costs of constructing generating facilities and alternative energy sources. As a result of these factors, industrial, municipal and cooperative customers of the Company are presented with a variety of power supply options. Technological developments have given some retail customers opportunities to obtain power through self-generation. Competition for retail customers would require fundamental changes in law and regulatory policies that are no_t currently under consideration. The Company is committed to maintaining high standards of service at competitive rates for all classes of customers.

The Company now has, and in the future will have, increased opportunities to obtain power from sources other than its own generating facilities (see Future Sources of Power under BUSINESS). In particular, the Public Utility Regulatory Policies Act of1978 (PURPA) has encouraged non-utilities to enter the business of producing electricity. The Company supports a competitive system for utilities to buy capacity as an option to meet future demand..

CONSERVATION AND LOAD MANAGEMENT The Company is committed to least-cost planning and has developed a detailed analysis procedure in which effective demand-side and supply-side options are both considered in order to determine the least cost method to satisfy the customers' needs.

On January 7, 1991, the Virginia Commission established a proceeding to consider rules and Commission policy regarding conservation and* load* management programs of electric utilities, including the appropriateness of payments, subsidies and allowances to influence the installation or use of certain appliances or equipment. The Company participated in the proceeding and filed comments.

The Staff filed a report recommending rules governing these matters with which the Company is* in substantial agreement. On October 29, 1991, oral arguments were held.

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 ofreal estate have been obtained for most electric lines, but underlying titles have not been examined except for transmission lines of 69 K v or more. Where rights. of way have not been obtained, they could be acquired from private owners by condemnation if necessary. Many electric lines are on publicly owned property as to which permission for use is generally revocable.

Portions of a 500 Kv transmission line from the Company's coal-fired station at Mt. Storm, West Virginia, cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus electricity in the line if any exists.

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

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

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

In 1986, Virginia Power began a project to expand the capacity of two existing ash disposal ponds at its Possum Point Power Station. As a condition of the environmental permitting process, on April 14, 10

1987, the Company accepted a special order, issued by the Virginia Water Control Board (VWCB),

requiring it to perform a six-month evaluation of groundwater quality in the vicinity of the two ponds.

The study, which has been completed and submitted to the VWCB, concluded that the quality of groundwater near existing domestic wells adjacent to the site was good and met all health-based EPA primary drinking water standards. However, some groundwater contamination associated with the disposal of certain fossil fuel by-products at the facilities was identified. In order to remedy this impact, the Company proposed and is implementing a course of action that includes removal and relocation of certain wastes, back-fitting impermeable liners and additionai monitoring to measure improvement in site groundwater. The action that the Company is implementing is estimated to cost up to $3.5 million.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 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 1991 and 1990; the Company paid qu~rterly cash dividends on its Common Stock as follows:

1991. :...................

1990.......................

1st

$85.2

$79.1 2nd 3rd (Millions)

$85.6 *

$86.2

$80.6

$81.6 ITEM 6. SELECTED FINANCIAL DATA 1991 1990 1989 1988 4th

$89.9

$85.6 1987 Operating revenues...............

(Millions*, except percentages)

Operating income... ;............

Net income.....................

Balance available for Common Stock......... ;.............

Total assets.....................

Total net utility plant.............

Long-term debt, noncurrent capital lease obligations and preferred stock subject to mandatory redemption...................

Utility plant expenditures (including nuclear fuel)..................

Capitalization ratios (percent):

Debt......... *...... ~.........

Preferred stock................

Common equity '..... ;..........

Embedded cost (percent):

Long-term debt.................

Preferred stock...,....... '.....

Weighted average...............

$ 3,688.1

$ 3,461.5 816.8 805.8 487.4 450.3 435.9 392.2 10,205.0 10,105.4 9,064.6 8,830.8 4,119.9 4,146.8 727.8' 803.4 47.4 49.1 9.0 9.4 43.6 41.5 8.43 8.80 6.54 7.40 8.11 8.57 11

$ 3,458.9

$3,097.6

$3,078.2 759.0 736.9 737.4 435.5 460.1 455.9 375.2 407.0 406.7 10,085.5 9,495.2 9,256.1 8,497.9 7,997.7 7,639.0 4,331.0 4,088.6 4,051.8 904.8 806.7 835.7 51.1 50.6 51.9 9.9 9.9 9.5 39.0 39.5

• 38.6 8.86 8.69*

8.42 7.75 7.57 7.77 8.67 8.50 832

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, '63 percent of the Company's cash requirements over the pa.st three years. _As detailed in the Statements o:i' Cash Flows, cash flow from operating activities was affected by a number of factors resulting from nor?Ial operations.

Net ~ash provided by operating activities decreased $6.4 million in 1991 as compared to 1990.

Among other factors, cash flow was affected by the sale of acco~nts wceivable' (see Note D' to FINANCIAL STATEMENTS) and the change in the balance of materials and *supplies.

Net cash provided by operating activities in 1990 increased $282.6 million from 1989. This was primarily attributable to cash inflows resulting from the sale of.$150 million accounts receivable and higher 'than normal accounts receivable balance at the end of 1989 res1..1lting from the unusually cold weather.

__ Cash froin (to) financing activities was as follows:

1991 1990 1989 (l\\'lillions)

Common Stock. _.............,..............

$ 150.0.

$ 200.0

$ 100.0

. Preferred stock............................

75.0

'Mortgage bonds............................

Medium-term notes.........................

100.0 200.0 250.0 199.4

--322.0 Repayment of long-term debt and preferred stock...

(410.4)

(224.5)

(350.5)

Dividends.... *.... :. :................. ;...

Other.-........ ':--... :........ -..... -... *.. :*..

(397.1)

(385.8)

(362.9) 6:6 (101.1) 69.9 Total.... _..... -..... *.....

$(35L5)

. $(311.4) -_

$ 103.5, Financing activities in 1991 resulted in a net cash outflow of $351.5 miliion. The proceeds from external financings in addition to cash flows from operations were used for utility construction

-expenditures and the retirement of $144.9 million of securities through refunding and mandatory cash sinking fund payments on securities. The Company also redeemed -an. *additional $265.5 million of high-cost debt. These transactions, among other factors, had the effect of lowering the Company's embedded cost of debt from 8.80 percent to 8.43 percent in 1991.

• The Inter-Company Credit Agreement with Dominion Resources is used on an ongoing basis to

. pr~)Vide flexibility in the Company's financing program. The Company utiHzed the Inter-Company Credit Agreement as needed throughout 199i and ended the year with a balance of $32.5 million due Domfnion Resources.

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

Utility plant expenditures.....................

Nuclear fuel............._. :................

Nuclear decommissioning trust funds............

Other-.... -.........................-......

Total......... *............'.. _-.;..... *...

1991

$(663.7)

(64.1)

• .(18.5) 11.3

$(735.0) 1990 (Millions)

$(728.8)

(74.6)

(21.0) 42.4

$(782:0)

"1989,

$(870.2)

(34.6)

(21.3) 17.9

$(908.2)

Investing activities in 1991 resulted in a net cash outflow of$735.0 million primarily due to $663.7 million of construction expenditures and $64.1 million of nuclear fuel expenditures. Of the construction expenditures, approximately $137.2 million was spent on new generating facilities, $176.9 millio.n on production projects, and $299.1 million on transmission and distribution projects. Construction 12

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expenditures were lower in 1991

• due to the economic recession and the cost-cutting measures implemented in 1990 and 1991. The Company expects to continue to benefit from these cost-cutting measures in the future.

Capital Requirements The Company presently anticipates that kilowatt-hour sales will grow about 2.9 percent per year and peak de!Dand _will grow approximately 2.6 percent a year during the 1990's. Capacity needed to support this growth will be provided through a combination of Company-constructed generating units and purchases from non-utility generators. Each of these options plays an important role in the Company's overall plan to meet capacity needs.

The Company's construction and nuclear fuel expenditures (excluding AFC), during 1992, 1993 and 1994 are expected to aggregate $834 million, $921 million and $797 million, respectively. Construction has begun on the 78.2 Mw coal-fired power station near Clover, Virginia, of which the Company presently has a 50 percent undivided ownership interest (For additional infonpation, see Future Sources of Power under Item I. BUSINESS and Note E to FINANCIAL STATEMENTS.) The Company's share of the cost of the c.onstruction is approximately $568 million. The expected in-service dates for Clover Units 1 and 2 a:re June 1995 and June 1996, respectively. From 1996 until 2000, the Company will need to add only peaking units to meet demand.

The Company will require $49 million to meet long-term debt maturities and $41 million for sinking funds payments in 1992. The Company presently estimates that, for 1992, 48 percent of its construction expenditures, including nuclear fuel expenditures, will be met through cash flow from operations and the balance, including other capital requirements, will be. obtained through a combination of sales of securities and borrowings under its Inter-Company Credit Agreement.

• The timing of future issuances and redemptions and the mix of debt and equity securities will depend not only on market conditions and the Company's needs but also on maintenance of adequate earnings and the Company's ability to maintain its credit ratings. In light of the current interest rates, management is presently evaluating refinancing a substantial portion of its high-cost, long-term debt with lower interest rate debt.

Results of Operations The following is a discussion of results of operations for the years ended 1991 as compared to 1990, and 1990 as compared to 1989.

1991 Compared to 1990 Operating revenues changed principally due to the following:

Increase (Decrease) From Prior Year Kwh sales................................

Change in base rates........................

Fuel cost recovery..........................

Other, net............................... *.

Total..................................

1991

$195.7

., 74.7 (46.9) 3.1

$226.6 1990 (Millions)

$(80.3) 92.0 (11.5) 2.4

$ 2.6 1989

$161.3 94.5 102.4 3.1

$361.3 Operating revenues were $226.6 million higher in 1991 as a result of the increase in unit sales attributable primarily to warmer weather in 1991. Base revenues wer*e higher due to an increase in base rates effective May 1, 1990 and a base rate increase effective September I, 1991, subject to refund. Fuel cost recovery decreased as a result of the reduction in the fuel factor effective November I, 1990 and another reduction effective September 15, 1991.

During 1991, the Company,had 40,643 new connections to its system compared to 52,961 and 60;201 in 1990 and 1989, respectively. The decline in new connections is primarily due to the economic recession and its effect on the Company's service territory.

13

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

Increase (Decrease) From Prior Year Residential...............................

Commercial..............................

Industrial................................

Public authorities..........................

Total retail sales...........................

Resale...................................

Total sales...............................

1991 6.7%

4.3 2.7 3.6 4.8 45.6 6.8 1990 (5.2)%

1.4 (0.8) 0.4 (1.6)

(9.5)

(2.0) 1989 3.6%

6.7 4.0 6.5 5.0 6.0 5.1 The upturn in sales reflects the warmer weather in 1991 as compared to the very mild weather in 1990. The economy remained weak as evideµced by the lower level of new connections in 1991. Sales for resale increased in 1991 due to the issuance of FERC Order No. 529, which requires the Company to record the sale of power to other utilities as revenues. Prior to this order, the Company recorded such sales as a credit to purchased and interchanged power.

.Fuel used in current generation increased in 1991 primarily due to increased sales resulting in a more expensive energy supply mix.

The average fuel cost of energy supply is shown below (a):

Mills Per Kilowatt-hour 1991 1990 1989 Nuclear.................................

5.69 5.08 4.30 Coal-Mt. Storm (mine-mouth).... '............

13.96 14.44 13.47

-Other..............................

15.78 15.95 15.59 Oil......................................

31.20 35.51 29.21 Purchased and interchanged..................

26.68 26.40 26.15 Gas.....................................

17.04 27.99 25.33 Combustion turbines........................

38.27 47.20 62.01 Combined cycle...........................

12.73 17.52 Average fuel costs..........................

14.05 13.66 16.04 Energy supply mix is shown below:

Actual Estimated 1992 1991 1990 1989 Nuclear(a)..........................

29%(b) 36%

38%

22%

Coal...............................

42 42 40 47 Oil...............................

5 3

2 7

Purchased and interchanged............

20 17 18 23 Other.............................

4 2

2 1

100%

100%

100%

100%

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

(b) Decrease reflects three nuclear outages planned in 1992.

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

14

e Purchased power capacity expenses increased as compared to 1990 primarily as a result of an increase in non-utility generation purchases.

Other operation expenses increased as compared to 1990 primarily as a result of increased advertising, fees associated with the sale of accounts receivable, an increase in the pension accrual, increased benefit plan costs and increased Nuclear Regulatory Commission licensing fees.

Income taxes-operating increased primarily as a result of increased pretax book income.

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

Interest on long-term debt decreased as compared to 1990 primarily as a result of an early redemption of high-cost debt and lower interest rates on pollution control notes.

1990 Compared to 1989 Operating revenues were $2.6 million higher in 1990 primarily as a result of the rate increase of

$64.4 million effective May l, 1989 and an increase in base rates effective May 1, 1990, but offset, in part, by decreased unit sales due to the mild weather in 1990 and a weakening economy and a decrease in fuel rates effective November 1, 1990.

Fuel used in current generation decreased in 1990 due to the unavailability of the Company's nuclear units in 1989 which resulted in a more expensive energy supply mix for that year.

Purchased and interchanged power, net decreased due to the increased availability of company-owned nuclear generation capacity during 1990.

Deferred fuel expenses, net increased primarily as a result of the increased ability of the current fuel factors to recover fuel expenses. In addition, fuel expenses subject to deferral accounting were lower in 1990 due to a more economical energy supply mix resulting from the increased availability of the Company's nuclear units.

Other operation expenses decreased primarily as a result of a decrease of $10.8 million in industry association dues in 1990 and the establishment of a $11.2 million regulatory liability in 1989 associated with the rate treatment of a gain resulting from the 1988 settlement of a portion of the projected benefit obligation under the Dominion Resources' Retirement Plan.

Future Issues Accounting Standards In December 1987, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SPAS) No. 96, "Accounting for Income Taxes." In June 1991, FASB issued an Exposure Draft of a pn;>posed statement on accounting for income taxes which would supersede SPAS No. 96. A final statement is expected to be issued in the first quarter of 1992. As a result of subsequent amendments, the related provisions must be adopted by the Company no later than 1993.

The Company expects to reflect the cumulative effect of an accounting change in the year of implementation. Based on the provisions of the existing standard, the Company has preliminarily determined that the adoption of the standard will increase net income in the year of adoption by approximately $13 million.

For information on SPAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" issued by FASB in December 1990, see Note L to FINANCIAL STATEMENTS.

Utility Rate Regulation Rate relief, especially in Virginia, continues to be of great importance to the Company, and it is a major variable that can materially affect its financial results. The Virginia Commission generally fixes rates based on a past test year, with certain modifications. In a period of increasing costs, such 15

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ratemaking methodology causes attrition in earnings, especially if the utility is engaged in a large construction p*rogram. The Virginia Commission in its most re~ently completed rate proceeding approved a plant update to ratebase beyond the end of the test year that mitigated some of this problem.

On December 13, 1991, the Virginia Commission issued an Order regarding proposed changes to its rules governing utility applications for increases in rates. The most significant change would modify the current test period methodology to allow ratemaking adjustments to reflect. the expected conditions

• throughout the entire period during which rates will be in effect. Therefore, the proposed rules, if adopted, would reduce regulatory lag and help mitigate attrition in the Company's earnings.

For more information on the current rate proceedings, see Rates under Item 1. BUSINESS.

Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment.. These laws and regulations affect future planning and existing operations. In response, the Company has undertaken specific compliance efforts.

On January 28, 1992, the VWCB adopted water quality standards for toxic pollutants pursuant to the Clean Water Act. The emergency regulations will be effective for up to 12 months and will be

• replaced by permanent regulations. The Company cannot presentty determine whether or to what extent changes to facilities or operating procedures might ultimately be required, but incremental compliance costs could be significant.

In addition, several Superfund sites have been identified where the Company has been or may be identified.as a potentially responsible party. As a result, the Company may be required to expend amounts on remedial investigations and actions, which costs cannot be determined at the present time but which could ultimately prove to be significant. These costs have been historically recovered through the ratemaking process; however, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely 1mpacted.

For information on the Air Act and other environmental matters, see Regulation under Item. 1.

BUSINESS.

Nuclear Operations In 1991, the Company's four nuclear units operated at a combined capacity factor of 80.6 percent, reflecting scheduled refueling outages at North Anna Unit 1 and Surry Unit 2. Refueling outages, usually for sixty days, typically occur every eighteen months. Two refueling outages are planned for 1992, as well as mid-cycle steam generator inspection and maintenance outage. In addition, three outages are currently scheduled for both 1993 and 1994.

Stress corrosion cracking has occured in steam generators of a certain design, including those at the Surry and North Anna Power Stations. The steam generators at Surry were replaced in 1979 and the Company's current plans are to replace the steam generators at North Anna Unit 1 in 1993. The Company presently estimates the cost of replacing the steam generators to be $166 million. Costs associated with the steam generators replacement at Surry are being recovered through rates. The Company is studying and preparing for the possibility of steam generator replacements 'at its North Anna Unit 2.

For information on nuclear insurance,.~ee Note C to FINANCIAL STATEMENTS.

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

16

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Conservation and Load Management In addition to complying with environmental laws and regulations, the Company is promoting the efficient use of energy sources through cost-effective conservation and energy management programs, such as Energy Saver Homes, controls to cut the use of electric water heaters and air conditioners during periods of high demand and summer rate differentials. The Company plans to enlarge the role of demand management and conservation in its strategy to meet increasing energy demands.

Securities Ratings During the fourth quarter of 1991, Moody's Investors Service and Standard and Poor's Corporation lowered.their ratings on the Company's debt and preferred stock to A2/A and A3/A-, respectively. The agencies cited the effect of construction expenditures to comply with the Air Act and increased purchased power commitments from non-utility generators as the primary reasons for the downgrades.

Competition For information, see Competition, under Item 1. BUSINESS.

Commitments and Contingencies For information on commitments and contingencies, see Note M to FINANCIAL STATEMENTS.

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

Report of Management............................. *.....................

18 Report of Independent Auditors.................... :......................

19 Statements of Income for the years ended December 31, 1991, 1990 and 1989.........

20 Balance Sheets at December 31, 1991 and 1990.... :...........................

21 Statements of Earnings Reinvested in Business for the years ended December 31, 1991, 1990 and 1989..................................................

23 Statements of Cash Flows for the years ended December 31, 1991, 1990 and 1989.....

24 N ates to Financial Statements............................................

25 Financial Statement Schedules:

IV-Indebtedness of and to Related Parties Not Current for the years ended December 31, 1991, 1990 and 1_989....................................

36 V-Property, Plant and Equipment for the years ended December 31, 1991, 1990 and 1989...................................................

37 VI-Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment for the years ended December 31, 1991, 1990 and 1989.........

40 IX-Short-term Borrowings for the years ended December 31, 1991, 1990 and 1989............................... *...........................

41 X-Supplementary Income Statement information for the years ended December 31, 1991,* 1990 and 1989...............................................

42 Schedules other than those listed above have been omitted since they are not required, are inapplicable or are unnecessary due to the presentation of the required information in the.financial statements or notes thereto.

17

e REPORT.OF MANAGEMENT The Company's management is responsible for all information and representations contained in the Financial Statements and other sections of the Company's annual report on Form 10-K. The Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the Form 10-K is consistent with that in the Financial Statements.

Management maintains a system of internal* accouhting contro_ls designed to provide reasonable assurance, at a reasonable cost, that the Company's assets are safeguarded against loss from*

unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control and, therefore cannot provide absolute assurance that the objettives of the established internal accounting controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Management believes that during 1991 the system of internal control was adequate to accomplish the int<;!nded objective.

The Financial.Statements have been audited by Deloitte & Touche, independent auditors, whose designation was approved by the Board of Directors. Their audits were conducted in accordance with generally accepted auditing standards and included a review of the Company's accounting systems, procedures and internal controls, and the performance of.tests and other auditing procedures sufficient to provide reasonable assurance that the Financial Statements ar.e not materially misleading and do not contain material errors.

• The Audit Committee of the Board of Directors, composed entirely of directors who are not officers or employees of the Company, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. Both the independent auditors and the internal auditors periodically meet alone with the Audit Committee and have* free access to

• the Committee at any time.

Management recognizes its responsibility for fostering a strong ethical climate so that the Company's affairs are conducted according to the highest standards of personal and corporate conduct.

This responsibility is characterized and reflected in the Company's Code of Ethics, which is distributed throughout the Company. The Code of Ethics addresses, among other things, the importance of ensuring open communication within the Company; potential conflicts of interest; compliance with all domestic and foreign laws, including those relating to financial disclosure; the confidentiality of proprietary information; and full disclosure of public information.

VIRGINIA ELECTRIC AND POWER COMPANY J. T. Rhodes President 18 B: D. Johnson Senior Vice President-Finance and Controller

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

We have audited the accompanying financial statements of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) as of December 31, 1991 and 1990 and for each of the three years in the period ended December 31, 1991 listed in the index on page 17. Our audits also included the financial statement schedules listed in the index on page 17. These financial statements and the financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company at December 31, 1991 and 1990 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1991 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information shown therein.

DELOITTE & TOUCHE Richmond, Virginia February 7, 1992 19

VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF INCOME For The Years Ended December 31, 1991 Operating revenues...............................

$3,688.1 Operating expenses:

Operation:

Fuel used in current generation...................

584.8 Purchased and interchanged power, net............

281.1 Deferred fuel expenses, net.....................

61.1 Purchased power capacity expenses...............

266.1 Other......................................

482.9 Maintenance..................................

304.7 Depreciation and amortization.....................

395.5 Amortization of terminated construction project costs...

45.8 Taxes-Income................... *.............

222.3

-Other.................................

227.0 Total......................................

2,871.3 Operating income.................................

816.8 Other income:

Allowance for other funds used during construction.....

8.2 Miscellaneous, net.......................... :...

33.2 Income taxes associated with miscellaneous, net........

(11.0)

Total......................................

30.4 Income before interest charges......................

847.2 Interest charges:

Interest on long-term debt........................

335.6 Other.......................................

27.8 Allowance for borrowed funds used during construction..

(3.6)

Total......................................

359.8 Net income.....................................

487.4 Preferred dividends...............................

51.5 Balance available for Common Stock..................

$ 435.9 The accompanying notes are an integral part of the financial statements.

20 1990 (Millions)

$3,461.5 526.4 270.0 126.0 184.9 440.7 281.2 373.6 49.8 200.2 202.9 2,655.7 805.8 3.3 34.9 (13.3) 24.9 830.7 356.3 25.9 (1.8) 380.4 450.3 58.1

$ 392.2 1989

$3,458.9 595.4 360.6 (7.0) 176.2 485.7 295.4 347.7 53.1 188.0 204.8 2,699.9 759.0 3.7 36.0 (5.0) 34.7 793.7 344.5 16.2 (2.5) 358.2 435.5 60.3

$ 375.2

VIRGINIA ELECTRIC AND POWER COMPANY BALANCE SHEETS Assets At December 31, UTILITY PLANT:

Plant (includes plant under construction of $736.1 in 1991 and

$691. 7 in 1990).....................................

Less accumulated depreciation...........................

Nuclear fuel (less accumulated amortization of $758. 7 in 1991 and

$661.6 in 1990).....................................

Total net utility plant.............................

PLANT AND PROPERTY UNDER CAPITAL LEASES (less accumulated amortization of $12.5 in 1991 and

$48.6 in 1990)......................................

INVESTMENTS:

Nuclear decommissioning trust funds......................

Non-utility property, net...............................

Notes receivable.....................................

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

Total net investments.............................

CURRENT ASSETS:

Cash.................. *............................

Customer accounts receivable (less allowance for doubtful accounts of $1.7 in 1991 and $1.1 in 1990).................

Other accounts receivable..............................

Accrued unbilled revenues..............................

Materials and supplies at average cost or less:

Plant and general...................................

Fossil fuel.........................................

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

Total current assets..............................

DEFERRED DEBITS AND OTHER ASSETS:

Terminated construction project costs (less accumulated amortization of $506.3 in 1991 and $460.5 in 1990)...........

Deferred fuel expenses................................

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

Total deferred debits and other assets.................

Total assets....................................

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

21 1991

$12,385.9 3,520.9 8,865.0 199.6 9,064.6 34.0 152.4 8.0 16.3 6.1 182.8 21.1 147.0 26.3 90.2 166.2 130.4 43.2 624.4 190.5 108.7 299.2

$10,205.0 (Millions) 1990

$11,769.9 3,171.4 8,598.5 232.3 8,830.8 38.6 125.4 10.3 21.1 7.0 163.8 19.3 173.8 34.2 90.2 184.2 160.4 52.0 714.1 218.2 16.1 123.8 358.1

$10,105.4

e VIRGINIA ELECTRIC AND POWER COMPANY BALANCE SHEETS Capitalization and Liabilities At December 31, CAPITALIZATION:

Long-term debt.....................................

Preferred stock subject to mandatory redemption...........

Preferred stock not subject to mandatory redemption Common stockholder's equity:

Common Stock, no par 300,000 shares authorized, 162,741 shares outstanding at December 31, 1991 and 156,049 at December 31, 1990.......................

Other paid-in capital...............................

Earnings reinvested in business.......................

Total common stockholder's equity..................

Total capitalization...............................

OBLIGATIONS UNDER CAPITAL LEASES...............

CURRENT LIABILITIES:

Securities due within one year.........................

Short-term debt....................................

Accounts payable, trade.............................

Customer deposits..................................

Payrolls accrued....................................

Taxes accrued.....................................

Interest accrued....................................

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

Total current liabilities............................

DEFERRED CREDITS AND OTHER LIABILITIES:

Deferred fuel expenses...............................

Accumulated deferred income taxes:

Liberalized depreciation............................

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

Deferred investment tax credits........ *................

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

Total deferred credits and other liabilities..............

COMMITMENTS AND CONTINGENCIES Total capitalization and liabilities.....................

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

22 1991

$ 3,818.1 270.1 469.0 2,549.1 16.4 1,132.9 3,698.4 8,255.6 31.7 90.2 104.9 199.6 49.8 57.8 22.3 101.7 66.3 692.6 45.0 745.6 73.4 344.9 16.2 1,225.1

$10,205.0 (Millions) 1990

$ 3,817.4 296.7 469.0 2,398.3 17.2 1,043.8 3,459.3 8,042.4 32.7 145.7 118.6 242.8 46.3 46.5 17.9 107.6 84.6 810.0 713.8 111.4 363.7 31.4 1,220.3

$10,105.4

e VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF EARNINGS REINVESTED IN BUSINESS For the Years Ended December 31, Balance at beginning of year.................

Net income.............................

Total.............................

Cash dividends:

Preferred stock subject to mandatory redemption..........................

Preferred stock not subject to mandatory redemption..........................

Common Stock................... :.....

Total dividends.....................

Other deductions, net......................

Balance at end of year.....................

1991

$1,043.8 487.4 1,531.2 24.2 26.0 346.9 397.1 1.2

$1,132.9 The accompanying notes are an integral part of the financial statements.

23 1990 (Millions)

$ 980.6 450.3 1,430.9 26.4 32.5 326.9 385.8 1.3

$1,043.8 1989

$ 910.3 435.5 1,345.8 28.7 31.2 303.0 362.9 2.3

$ 980.6

e e

VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1991 1990.

1989 (Millions)

Cash Flow From Operating Activities:

Net income................. '......................

$ 487.4

$ 450.3

$ 435.5 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization.....................

544.3 515.2 458.4 Allowance for other funds used during construction.....

(8.2)

(3.3)

(3.7)

Deferred income taxes...........................

(1.6).

(35.8) 35.3 Deferred investment tax credits....................

(18.8)

(21.7)

(24.3)

Partial settlement-pension plan....................

11.2 Noncash return of terminated construction project costs-pretax.................................

(19.2)

(22.1)

(25.0)

Deferred fuel expenses................... ;.......

61.1 126.0 (6.2)

Changes in:

Sale of accounts receivable......................

50.0 150.0 Accounts receivable...........................

(0.8) 51.3 (40.6)

Accrued unbilled revenues......................

(14.4) 31.6 (42.9)

Materials and supplies..........................

48.0 (71. 7)

(24.5)

Accounts payable, trade........................

(43.2)

(3.9)

(4.9)

Accrued expenses.............................

9.8 (72.9) 66.3 Other............................ *............

(6.1) 1.7 (22.5)

Net Cash Flow From Operating Activities.................

1,088.3 1,094.7 812.1 Cash Flow From (To) Financing Activities:

Issuance of Common Stock...........................

150.0 200.0 100.0 Issuance of preferred stock........ _...................

75.0 Issuance of long-term debt............................

299.4 200.0 592.6 Short-term debt...................................

(13.7)

(7.2) 3.7 Inter-company credit agreement.......................

32.5 (84.0) 55.5 Repayment of long-term debt and preferred stock..........

(410.4)

(224.5)

(350.5)

Common Stock dividend payments.....................

(346.9)

(326.9)

(303.0)

Preferred stock dividend payments.....................

(50.2)

(58.9)

(59.9)

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

(12.2)

(9.9)

(9.9)

Net Cash Flow From (To) Financing Activities..............

(351.5)

(311.4) 103.5 Cash Flow From (Used in) Investing Activities:

Utility plant expenditures (excluding AFC-other funds)......

(663.7)

(728.8)

(870.2)

Nuclear fuel (excluding AFC-other funds)...............

(64.1)

(74.6)

(34.6)

Pollution control project funds........................

1.0 34.5 46.9 Nuclear decommissioning trust funds...................

(18.5)

(21.0)

(21.3)

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

10.3 7.9 (29.0)

Net Cash Flow (Used in) Investing Activities...............

(735.0)

(782.0)

(908.2)

Increase in cash and cash equivalents.....................

1.8 1.3 7.4 Cash and cash equivalents at beginning of year..............

19.3 18.0 10.6 Cash and cash equivalents at end of year..................

21.1 19.3

$ 18.0 Cash paid during the year for:

Interest (reduced for the cost of borrowed funds capitalized as AFC)...............................

$ 376.8

$ 388.3

$ 350.0 Income taxes.....................................

255.8 339.6 145.4 The accompanying notes are an integral part of the financial statements.

24

e e

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

General The Company's accounting practices are prescribed by the Uniform System of Accounts promul-gated by the regulatory commissions having jurisdiction and are in* accordance with generally accepted accounting principles applicable to regulated enterprises.

The Company is a wholly-owned subsidiary of Dominion Resources, a Virginia corporation. The financial statements include the accounts of the Company and VP Fuel, with all significant inter-company transactions and accounts being eliminated in consolidation.

• 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 and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense and clearing accounts. The cost of additions and replacements is charged to the appropriate utility plant account, except that the cost of minor additions and replacements is charged to maintenance expense.

Depreciation and Amortization Depreciation of utility plant (other than nuclear fuel) is computed on the straight-line method based on projected useful service lives. The cost of depreciable utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation. The provision for depreciation is based on weighted average depreciable plant using a rate of 3.2 percent for 1991, 1990 and 1989.

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 income taxes are recorded based on differences between book income and federal taxable income to the

. extent permitted by the regulatory commissions for ratemaking purposes. The Company's only significant non-normalized timing difference pertains primarily to accelerated tax depreciation of plant placed in service prior to 1974. Cumulative timing differences for which deferred federal income taxes were not provided were approximately $620 million at December 31, 1991. The tax effect of this amo1,mt is not recorded currently, but such costs are expected to be reflected in rates when the timing differences reverse. Deferred investment tax credits are being amortized over the service lives of the properties giving rise to such credits.

Allowance for Funds Used During Construction The applicable regulatory Uniform System of Accounts defines AFC as the net cost during the construction period of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.

The Company separately determines rates and reports amounts applicable to borrowed funds; calculated on a net-of-tax basis, and to equity funds. Aggregate AFC rates of9.l percent, 9.0 percent and 8.95 percent were 25

e e

used for 1991, 1990 and 1989, respectively. Approximately 88 percent of the Company's construction work in progress is now included in rate base, and a cash return is collected currently thereon.

Deferred Fuel Approximately 90 percent of fuel expenses are subject to a deferral method of accounting. Under thi~ method, the difference between actual fuel expenses and the level of fuel expenses included in current rates is deferred and matched against anticipated future fuel-related rate increases.

Cash Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 1991 and 1990, the Company had recorded in accounts payable, checks outstanding but not yet presented for payment of $43.3 million and $49.9 million, respectively. *

• Statement of Cash Flows For purposes of the Statement of Cash Flows, the Company considers cash and cash equivalents to include cash on hand and temporary investments purchased with an initial maturity of three months or less.

Reclassification Certain amounts in the 1990 and 1989 financial statements have been reclassified to conform to the 1991 presentation.

B. Income Taxes:

Details of income tax expense are as follows:

Years 1991 1990 1989 Current expense:

Federal.......................................

(Millions)

$244.1

$248.4

$168.0 State........................................,

4.2 4.3 2.9 248.3 252.7 170.9 Deferred expense-federal:

Plant related items:

Liberalized depreciation........................

44.4 50.1 69.7 Indirect construction costs........................

(13.4)

(20.5)

(20.9)

Cost of removal-property retirements...........,..

8.8 4.7

?,5 Other......................................

3.1 (1.9) 3.0 Deferred fuel..................................

(20.8)

(42.8) 2.3 Unbilled revenues...............................

(4.1)

(4.1)

(4.1)

Terminated construction project costs................

(10.1)

(10.6)

(13: 1)

Other................................ :......

(15.1)

(5.4)

(1.0)

(7.2)

(30.5) 41.4 Net deferred investment tax credits-amortization........

(18.8)

(22.0)

(24.3)

Income tax expense-operating income..................

222.3 200.2 188.0 Income tax expense associated with nonoperating income:

Current expense:

Federal......................................

5.2 18.0 10.9 State.........................................

0.2 0.2 0.2 5.4 18.2 11.1 Deferred expense-federal...........................

5.6 (5.2)

(6.1)

Net deferred investment tax credits-amortization.........

0.3 Income tax expense nonoperating income.. *. *............

11.0 13.3 5.0 Total income tax expense...........................

$233.3

$213.5

$193.0 26

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 1991 1990 1989 Amount Amount Amount (Millions, except percentages)

Federal income tax expense at statutory rate of 34%.......

$243.5

$224.2

$212.6 Increases (decreases) resulting from:

Utility plant differences(*).........................

11.3 (0.8) 6.9 Ratable amortization of investment tax credits.........

(16.5)

(17.4)

(18.6)

Terminated construction project costs(*)..............

8.2 9.4 8.3 Other, net.....................................

(17.6)

(6.4)

(19.3)

(14.6)

(15.2)

(22.7)

Total federal income tax expense.....................

$228.9

$209.0

$189.9 Effective tax rate.. *..............................

31.9%

31.7%

30.4%

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

In December 1987, the FASB issued SPAS No. 96, "Accounting for Income Taxes." As a result of subsequent amendments, the related provisions must be adopted by the Company no later than 1993.

However, in June 1991, FASB issued an Exposure Draft of a proposed statement on accounting for income taxes which would supersede SPAS No. 96. A final statement is expected to be issued in the first quarter of 1992. The objective of SPAS No. 96 is to recognize the amount of current and deferred taxes payable and refundable for all events that have been recognized in the financial statements based on enacted tax laws at the date of the financial statements.

The Company has preliminarily determined that the net effect resulting from the adoption of the standard will be the recording of additional deferred income tax liabilities on the Company's balance sheet. At the time the Company records these additional deferred income taxes, a regulatory receivable will also be recorded. The Company will recognize the tax effects in future customer rates when such differences reverse. The Company expects to reflect the cumulative effect of an accounting change in the year of implementation. Based on the provisions of the existing standard, the Company has preliminary determined that the adoption of the standard will increase net income in the year of adoption by approximately $13 million.

C. Nuclear Operations:

Nuclear Decommissioning The Company's nuclear plant depreciation rates include a provision for future decommissioning

• costs that are recoverable through rates charged to customers. Amounts collected from customers are being placed in trusts by the Company. These amounts and the accumulated earnings thereon will be utilized solely to fund future decommissioning obligations. Total future decommissioning costs, including reclamation costs, are estimated to be $854 million in 1990 dollars. The accumulated provision for decommissioning of $152.4 million and $125.4 million is included in Utility Plant Accumulated Depreciation at December 31, 1991 and 1990, respectively. Provisions for decommissioning of $18.5 million, $21.0 million and $21.3 million applicable to 1991, 1990 and 1989, respectively, are included in Depreciation Expense.

27

e Insurance The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $7.8 billion for a single nuclear incident. The Company has purchased $200 million of coverage from the commercial insurance pools with the remainder provided through a mandatory industry risk sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $66.15 million for each of its four licensed reactors not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

Nuclear liability coverage for claims made by nuclear workers first hired on or after January 1, 1988, except those arising out of an extraordinary nuclear occurrence, is provided under the Master Worker insurance program. (Those first hired into the nuclear industry prior to January 1, 1988 are covered by the policy discussed above.) The aggregate limit of coverage for the industry is $400 million

($200 million policy limit with automatic reinstatements of an additional $200 million). The Company's maximum retrospective assessment is approximately $12.6 million.

The Company's current level of property insurance coverage, ($2.15 billion for North Anna and

$2.12 billion for Surry) exceeds the NRC's minimum requirement for nuclear power plant licensees of

$1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition, and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The property insurance coverage is provided through several different policies. Under two of these policies, the Company is subject to retrospective premium assessments, in any policy year in which losses exceed the funds available to these insurance companies. The maximum assessment for the current policy period is $38.9 million. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and deco.ntamination, the Company has the financial responsibility for these losses.

The Company purchases insurance from Nuclear Electric Insurance Limited (NEIL) to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Virginia Power is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period's maximum assessment is $14.7 million.

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

D. Sale of Receivables:

In December 1990, the Company entered into agreements to sell, with limited recourse, certain accounts receivable including unbilled amounts, up to a maximum of $300 million. The agreements expired in December 1991. Upon expiration of those agreements, the Company entered into new agreements to sell, with limited recourse, certain accounts receivable including unbilled amounts, up to a maximum of $200 million. These agreements expire in December 1992 and may be terminated at any time. Additional receivables are continually sold, at the Company's discretion, to replace those collected up to the $200 million limit. At December 31, 1991 and 1990, $200 million and $150 million, respectively, of such receivables had been sold under these agreements. The limited recourse is provided by the Company's assignment of an additional undivided interest in accounts receivable to cover any potential losses to the purchaser due to uncollectible accounts. The Company has provided for the estimated amount of such losses in its accounts.

28

L e

e E. Jointly Owned Plants:

The following information relates to the Company's proportionate share of jointly owned plants at December 31, 1991:

Ownership interest............................

Utility plant in service.........................

Accumulated depreciation......................

Construction work in progress...................

Bath County Pumped Storage Station 60.0%

$1,070.7 121.1 4.1 North Anna Power Station 88.4%

(Millions)

$2,242.5 1,084.0 158.7 Clover Power Station 50.0%*

$149.3

• In August 1991, the Company and ODEC entered into an agreement whereby the Company, under

• certain conditions, would assume the liability for certain commitments and make payments that ODEC is unable to make. The project ownership interests would be adjusted based on cash contributions of the parties, with ODEC, under certain conditions, having the option to reacquire the additional ownership interest acquired by the Company. The Company's ownership interest at any time cannot exceed 60 percent under this agreement.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interests. The Company's share of operating costs is classified in the appropriate* operating expense (fuel,* mainte-nance, depreciation, taxes, etc.) in the Statements of Income.

F. Terminated Construction Project Costs:

The construction of North Anna Unit 3 was terminated in November 1982. All retail jurisdictions have permitted recovery of the incurred costs. The amounts deferred are being amortized over a 15-year period for Virginia and FERCjurisdictional customers and over a IO-year period in the North Carolina jurisdiction. The net cost incurred was $387.6 million. At December 31, 1991, the net unamortized balance was $167.5 million.

• G. Leases:

Plant and property under capital leases included the following:

Combustion turbines (1)................................

Office buildings (2)....................................

Data processing equipment.......... -....................

Total plant and property under capital leases.............

Less accumulated amortization...........................

Net plan*t and property under capital leases.................

1991

$40.8 5.7 46.5 12.5

$34.0 (Millions) 1990

$42.1 40.8 4.3 87.2 48.6

$38.6 (1) At the expiration of the lease in August 1991, the combustion turbines became the property of the *company.

(2) The Company leases its principal office building from its parent, Dominion Resources. The capitalized cost of the property under that lease, net of accumulated amortization, represented $27.7 million and $28.5 million at December 31, 1991 and 1990, respectively. Rental payments for such lease were $3.0 million for each of the three years ended December 31, 1991, 1990 and 1989.

29

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

Future minimum lease payments under noncancellable capital leases and for operating leases that have initial or remaining lease terms in excess of one year as of December 31, 1991, are as follows:

1992...............................................

1993...............................................

1994...............................................

1995...............................................

1996...............................................

After 1996..........................................

Total future minimum lease payments......................

Less interest element included above......................

Present value of future minimum lease payments.............

Capital Leases

$ 5.0 5.1 5.1 4.1 3.2 34.7 57.2 23.2

$34.0 (Millions)

Operating Leases

$ 4.3 3.5 2.4 2.0 1.8

• 19.5

$33.5 Rents on leases, which have been charged to other operation expenses, were $12.8 million, $17.0 million and $18.1 million, for 1991, 1990 and 1989, respectively.

H. Long-term Debt:

Long-term debt included the following:

At December 31, 1991 1990 (Millions)

First and refunding mortgage bonds (1):

Series Q, 4.875%; due 1991............................

Series R, 4.375%, due 1993...........................

30.0 30.0 30.0 Series S, 4.5%, due 1993.............................

30.0 30.0 1984 Series A, 13.3%, due 1994........................

66.0 1984 Series B, 13.25%, due 1994.......................

75.0 1987 Series B, 9.375%, due 1994.......................

100.0 100.0 Series T, 4.5%, due 1995.............................

56.6 56.6 1981 Series B, 15.75% due 1996........................

8.0 8.0 1981 Series C, 15.75% due 1996........................

18.0 Various series, 5.125%-9.375%, due 1997-2001.............

844.2 849.7 Various series, 6.75%-10%, due 2002-2006................

407.8 514.5 Various series, 6.75%-10.25%, due 2007-2011..............

342.0 352.0 Various series, 8.5%-9.875%, due 2012-2016...............

250.0 250.0 Various series, 8.75%-9.875%, due 2017-2021..............

550.0 450.0 Total first and refunding mortgage bonds................

2,618.6 2,829.8 Other long-term debt:

Bank loans, notes and term loans:

Fixed interest rate, 7.4%-10.8%, due 1991-2003...........

836.5 717.7 Pollution control financings (2):

Fixed interest rate, 5.625%, due 2002..................

20.5 21.0 Money Market Municipals, due 2008-2017(3).............

388.6 388.6 Inter-company credit agreement (4).....................

32.5 Total other long-term debt 1,278.1 1,127.3 3,896.7 3,957.1

( continued) 30

At December 31, 1991 1990 (Millions)

Less amounts due within one year:

First and Refunding Mortgage Bonds...................

30.0 Bank loans, notes and term loans.....................

49.4 80.6 Sinking fund obligations (5)..........................

14.2 17.0

• Total amount due within one year...................

63.6 127.6 Less unamortized discount, net of premium...............

15.0 12.1 Total long-term debt..... *........................

$3,818.1

$3,817.4 (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. Pollution control bonds subject to remarkeHng within one year are classified as long-term debt to the extent that the Company's intention to maintai.n the debt is supported by long-term bank commitments.

(4) Under the terms of the Inter-Company Credit Agreement, the Company may borrow funds from Dominion Resour~es on a daily basis and repay all or any part of the loan at any time during the term of the agreement, presently due to expire on July 1, 1993. Borrowings under the agreement are limited to $300 million outstanding at one time. The weighted average interest rate for 1991 and 1990 was 5.81 percent and 8.12 percent, respectively.

(5) $7.8 million of the annual sinking fund requirements. on the First and Refunding Mortgage Bonds may be satisfied by waiving the privilege to issue an equal amount of bonds and by substituting property therefor. The Company intends to exercise such waiver in 1992.

Maturities* through 1996 are as follows (millions): 1992-$63.6; 1993-$150.2; 1994-,--$179.3; 1995-$146.8; and 1996-$191.8.

I. Preferred Stock Subject to Mandatory Redemption:

Preferred stock subject to mandatory redemption, $100 liquidation preference, at December 31, 1991, was as follows:

Entitled Per Share*

Upon Voluntary Liquidation Redemption Issued and And Thereafter to Outstanding Amounts Declining Dividend Shares Amount Through In Steps To

$7.30 500,000

$107.30 4/14/93

$100.00 after 4/14/02 7.325 428,419 101.00

• 7.58

. 600,000 107.58 6/19/92 100.00 after 6/19/93 8.20 330,000 102.46 9/20/92

• 100.41 after 9/20/96 8.40 512,000 103.64 3/31/92 100.00 after 3/31/04

.8.60 228,764 105.00 12/19/92 100.00. after 12/19/97 8.625 203,500 103.96 6/20/92 100.00 after 6/20/02

.8.925 164,500 105.36 9/20/92 100.00 after 9/20/09 2,967,183 Less shares due within one year 265,834 Total 2,701,349 Maturities are $26.6 million for each year through 1996.

31 Annual Sinking Fund Requirements

. at $100 Per Share Shares 15,000 28,000 120,000 30,000 32,000 11,834 18,500 10,500

e e

In 1989, 1990 and 1991, 50,000 shares, 150,000 shares and 50,000 shares, respectively, of the $10.25 Dividend Preferred Stock were redeemed.

In 1989 and 1990, 10,500 shares of the $8.925 Dividend Preferred Stock were redeemed each year through optional sinking funds.

In 1989, 47,581 shares of the $7.325 Dividend Preferred Stock were redeemed through an optional sinking fund.

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

J. Preferred Stock Not Subject to Mandatory Redemption:

Preferred stock not subject to mandatory redemption, $100 liquidation preference, at December 31, 1991, was as follows:

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

$5.00 106,677

$112.50 4.04 12,926 102.27 4.20 14,797 102.50 4.12 32,534 103.73 4.80 73,206 101.00 7.72 350,000 101.50 7.45 400,000 101.00.

7.20 450,000 101.00 7.72 (1972 Series) 500,000 101.00 MMP 1/87(*)

500,000 100.00 MMP 6/87(*)

750,000 100.00 MMP 10/88(*)

750,000 100.00 MMP 6/89(*)

750,000 100.00 Total 4,690,140

(*) Money Market Preferred (MMP) dividend rates are variable and are set every 49 days via an*

auction process. The combined weighted average rates for these series in 1991; 1990 and 1989, including fees for broker/dealer agreements, were 5.22 percent, 6.95 percent and 7.45 percent, respectively..

32

e e

K. Common Stock:

During the years 1989 through 1991 the following changes in Common Stock occurred:

Balance at January 1.....

Transfer from Other Paid-in Capital........

Issuance to Dominion Resources...........

Balance at December 31 1991 Shares Outstanding 156,049 6,692 162,741 Amount

$2,398.3

• 0.8 150.0

$2,549.1 L. Retirement Plan and Postretirement Benefits:

Years 1990 (Millions, except shares)

Shares Outstanding Amount 147,077 8,972 156,049

$2,197.5 0.8 200.0

$2,398.3 1989 Shares Outstanding 142,433 4,644 147,077 Amount

$2,096.7 0.8 100.0

$2,197.5 The Company participates in the Dominion Resources Retirement Plan (the Retirement Plan), a defined benefit pension plan. The Retirement Plan covers virtually all employees of Dominion Resources and its subsidiaries, including the Company. The benefits are based on years of service and the employee's final average compensation.*

Pension plan expenses were $10.8 million, $5.1 million and $6.7 million for 1991, 1990 and 1989, respectively and the amounts funded were $12.2 million, $6.8 million and $6.7 million in 1991, 1990 and 1989, respectively.

In addition to providing pension benefits, Dominion Resources and the Company provide certain health care and life insurance benefits for retired employees. Health care benefits are provided to retirees who have completed at least teri years of service after obtaining age 45. These and similar benefits for active employees are provided through insurance companies with annual premiums based on benefits paid during the year. Un:der the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

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

Years 1991 1990 1989 Health care premiums paid (millions)........ *.. -. *.... *...

$ 8.0

$ 6.8

$ 6.3 Retirees cov~red under health care,.................

2,800 2,500

_2,400 Life insurance premiums paid (millions)..............

$ 0.5

$ 0.4

$ 0.4 Retirees covered under life insurance...............

2,300 2,200 2,000 SPAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" was issued by FASB in December 1990. Based on the current terms of its benefit plans, the Company presently estimates that the required application of this standard in 1993 will result in an increase of approximately $32 million over the pay-as-you-go amount. A transition obligation of approximately $230 million would result from the application of this standard as of January 1, 1993. These amounts reflect plan amendments that occurred in 1991, which among other things, require salaried retirees to pay a portion of the cost of these benefits if they have not completed 30 years of service and retire after 1992.

The Company plans to amortize the transition obligation over a twenty-year period. To the extent that the new standard results in accruals for other postretirement benefits in excess of amounts collected through rates and the collectibility of such excess in future rates is deemed probable, the Company will 33

'

• I

e e

record a receivable representing that amount to be collected through future rates. On January 21, 1992, the Virginia Commission issued an order inviting comments on the appropriate accounting and ratemaking treatment for postretirement benefits other than pensions. The Company has received approval for recovery of expenses associated with the implementation of SFAS No. 106 for the North Carolina jurisdiction and county and municipal customers. Similar recovery has been preliminarily agreed upon for FERC customers.

M. Commitments and Contingencies:

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or the financial position of the Company.

Rate Matters 1991 For information on the principal rate proceedings in which the Company was involved in 1991, including those currently in progress, see Rates under Item l. BUSINESS.

For information on the effect of rate increases see Results of Operations under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERA-TIONS.

1990 In April 1991, the Virginia Commission issued its Final Order in the 1990 rate proceeding, That Order authorized a rate increase of $79.8 million based on a 1989 test year, and approved an adjustment to offset attrition in earnings by allowing rate base to be updated to a point seven months beyond the end of the test year. Refunds of approximately $58 million, representing amounts collected in excess of the amount approved, were made in May 1991. The Final Order has been appealed to the Virginia Supreme Court by parties opposing a portion of the increase.

For more information, see Rates under Item 1. BUSINESS.

Construction Program The Company has made substantial commitments in connectioh with its construction program and nuclear fuel expenditures. Those expenditures are estimated to total $834 million (excluding AFC) for 1992. Additional financing is contemplated in connection with this program. For more information see Capital Requirements under MANAGEMENT'S DISCUSSION AND ANALYSIS AND RESULTS OF OPERATIONS.

Purchased Power Contracts Since 1984, the Company has entered into contracts for the long-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. The Company has 74 non-utility purchase contracts with a combined dependable summer capacity of 3,455 M w. Of these, 42 projects (aggregating 1,312 Mw) were operational as of the end of 1991 with the balance to become operational at various dates before 1998.

The table below reflects the Company's minimum commitments as of December 31, 1991, for power purchases from utility and non-utility suppliers that are currently operating or have obtained construc-tion financing. The table includes those contracts where necessary financing for the generating facility has been obtained.

34

Year 1992..........................

1993...........................

1994...........................

1995...........................

1996...........................

Later years............... _......

Total........................

Present value of the total...........

e Commitment Capacity 460.7 564.5 611.9 644.8 657.8 11,830.8 *

$14,770.5

$ 5,719.2 (Millions)

Other

$ 202.2 209.2 196.8 217.0 226.5 4,077.5

$5,129.2

$1,821.8 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 and interchange received) for the years 1991, 1990 and 1989 were $547.2 million, $473.6 million and

$559.1 million, respectively.

Fuel -Purchase Commitments The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (millions): 1992-$321; 1993-$229; 1994-$187; 1995-$72 and 1996-$38.

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

N. Quarterly Financial Data (Unaudited):

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

Quarter 1991 1st...................-..

2nd................... *..

3rd................ *.....

4th.....................

1990 1st.....................

2nd.....................

3rd.....................

4th.....................

Operating Revenues

$ 884.2 875.6 1,042.6 885.7 *

$ 846.0 813.6 982.1 819.8 Operating Income (Millions)

$196.3 178.5 274.4 167.6

$202.2 181.0 256.2 166.4 Balance Available for Common Stock

$101.2 81.9 179.0 73.8

$ 98.4 77.2 148.6 68.0 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.

In December 1991, the Company established a reserve of $20 million for obsolete material and supplies which had the effect of decreasing Operating Income and Balance Available for Common Stock by $13.2 million.

35

Col. A e

VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE IV INDEBTEDNESS OF AND TO RELATED PARTIES NOT CURRENT For the years ended December 31, 1991, 1990 and 1989 Col. B Col. C Col. D Col. E Col. F Col. G SCHEDULE IV Col. H Col. I Indebtedness of Indebtedness to Name of person Balance at Beginning Dominion Resources:

1991...........

1990............

1989............

Balance Balance at Balance Additions Deductions at End Beginning Additions Deductions at End (Millions)

$84.0

$28.5

$ 709.0

$ 746.9

$1,344.2

$ 676.5

$ 830.9

$1,288.7

$32.5

$84.0 See Note (4) of Note H to FINANCIAL STATEMENTS.

36

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

. (Deduct) of Period (Millions)

Utility plant:

Electric plant:

. In service:

Intangible............

64.5

$ 9.7

$ 2.3 71.9 Production...........

6,132.7 226.8 24.2

$ 41.6(a) 6,376.9 Transmission.........

1,060.0 73.7 4.7 (0.2) 1,128.8 Distribution..........

3,190.6 255.8 44.9 0.2 3,401.7 General.............

576.6 29.4 20.1 0.8 586.7 Total electric plant in service..........

11,024.4 595.4 96.2 42.4 11,566.0 Construction work in progress............

691.7 44.4(b) 736.1 Held for future use......

11.0 28.2 0.1 1.9 41.0 Electric plant acquisition adjustment...........

42.8 42.8 Total electric plant...

11,769.9 668.0 96.3 44.3 12,385.9 Nuclear fuel...............

893.9 64.4 958.3 Total utility plant....

$12,663.8

$732.4

$96.3

$ 44.3

$13,344.2 Non-utility property.........

10.8

$ (2.3) 8.5 Capital leases..............

87.2

$ 0.1

$(40.6) (a) 46.5 (a) At the expiration of the lease in August 1991, the combustion turbines became the property of the Company.

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

37

\\.

,1

).

SCHEDULE V VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE V PROPERTY, PLANT AND EQUIPMENT For the year ended December 31,*1990 Col. A*

Col. B Col. C Col. D Col. E Other Balance at Changes Beginning*

Additions Retirements Add Classification of Peri9d

• at C9st or Sales (Deduct)

(Millions)

Utility plant:

Electric plant:

In service:

Intangible.............

49.0

$ 19.9

$ 4.4 Production.......... *.*

• 5,787.5' 374.5 27.4

'$(1.9)

Transmission... :.... ;

1,010.0 53.8 4.4 0.6' Distribution....,... :.

2,963.9 271.0 44.7

.0.4

• General...............

532.7 54.0 ll.4 1.3 Total electric plant in service..........

10,343.1 773.2 92.3 0.4 Construction work in progress.............

. 745.4 (53.7)(*)

. Held for future use......

4.5 6.6 (0.1).

Electric plant acquisition adjustment.... :......

42.8

. Total electric plant.....

11,135.8 726~1

• 92.3 03

• Nuclear fuel.... *...........

819.1 74.8

'Total utility plant..... *

$11,954,9.

$800.9

$92.3

• $ 0*.3 No~~utHity property.........

5.8

$ 0.2

$ 5.2 Capital leases............ ;.

83.4

$ 0.5

$ 4.3 Col. F Balance at End of Period 64.5 6,132.7 1,060.0

'3,190.6 576.6 11,024.4 691.7 11.0 42.8 11,769.9 893.9

$12,663.8

• 10.8 87.2

(*) Includes additions of $719.5 million net of $773.2 million fransf~rred to plant ih service..

38

SCHEDULE V VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE V PROPERJ'Y, PLANT AND EQU,IPMENT For the year en.ded.December 31, 1989 Col. A Col. B Col. C Col. D Col. E Col. F Other Balance at Changes Balance Beginning Additions Retirements Add at End Classification of Period at Cost.

or Sales (Deduct) of Period (Millions)

Utility plant:

Electric plant:

In service:

Intangible............

43.2

$ 13.5

$ 7.7 49.0 Production...........

5,504.4 314.0 31.7

$ 0.8 5,787.5 Transmission.........

972.5 42.8 5.1 (0.2) 1,010.0 Distribution..........

2,675.8 326.5 38.6 0.2 2,963.9 General.............

469.1 72.5 8.8 (0.1) 532.7 Total electric plant in service..........

9,665.0 769.3 91.9 0.7 10,343.1 Construction work in progress.............

641.5 103.9(*)

745.4 Held for future use......

4.5 4.5 Electric plant acquisition adjustment...........

42.8 42.8 Total electric plant...

10,353.8 873.2 91.9 0.7 11,135.8 Nuclear fuel.............

784.5 34.6 819.1 Total utility plant....

$11,138.3

$907.8

$91.9

$ 0.7

$11,954.9 Non-utility property.........

5.9

$(0.1) 5.8 Capital leases..............

88.0

$ 4.6 83.4

(*)Includes additions of$873.2 million net of $769.3 million transferred to plant in service.

39

SCHEDULE VI VIRGINIA ELECTRIC AND.POWER COMPANY SCHEDULE VI ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT For the years ended December 31, 1991, 1990 and 1989 Col. A Col. B Col. C Col. D Col. E Col. F Additions Other Balance.at Charged to Changes Balance Beginning Costs &

Add at End Classification of Period Expenses Retirements (Dedu_ct) of Period (Millions) 1991 Accumulated depreciation and amortization of electric plant

$3,171.4

$376.3

$102.1

$ 75.3 (*)

$3,520.9 Accumulated amortization of capital leases..............

48.6

$ 6.0

$(42.1)(:f:)

12.5 Accumulated amortization of nuclear fuel...............

$ 661.6

$ 97.1

$ 758.7 1990 Accumulated depreciation and amortization of electric plant

$2,880.1

$353.0

$ 92.2

$ 30.5

$3,171.4 Accumulated amortization of capital leases..............

41.9

$ 7.1

$ 0.5 0.1 48.6 Accumulated amortization of nuclear fuel................

$ 576.8

$ 84.8

-$ 661.6 1989 Accumulated depreciation and amortization of electric plant

$2,615.0

$319.1

$ 84.2

$ 30.2.

$2,880.1 Accumulated amortization of capital leases..............

40.0

$ 6.4

$ 4.5 41.9 Accumulated amortization of nuclear fuel...............

$ 525.6

$ 51.2

$ 576.8 Provision for depreciation of automobiles and trucks is charged to transportation expense clearing

• account and redistributed to operation expense, utility plant and other accounts.

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

40

e SCHEDULE IX VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE IX SHORT -TERM BORROWINGS For the years ended December 31, 1991, 1990 and 1989 Col. A Col. B Col. C Col. D Col. E Weighted Maximum Average Weighted Amount Amount Category of Balance Average Outstanding Outstanding Aggregate Short-at end of Interest During the During the Term Borrowings Period Rate Period Period (a) 1991 (Millions, Except Percentages)

Nuclear fuel financing (b).....

$104.9 4.93%

1990 Nuclear fuel financing (b)

$118.6 7.90%

1989 Nuclear fuel financing (b)

$ 39.3 8.42%

Real estate notes...........

Total..................

$ 39.3 (a) Average computed on a daily weighted basis (b) Maximum 270 days (c)

(c)

(c)

(c)

(c)

. (c)

$0.8

$0.5 Col. F Weighted Average Interest Rate During the Period (a) 6.46%

8.30%

9.46%

10.00%

(c) The total amount of commercial paper outstanding under this arrangement at December 31, 1991, 1990 and 1989 was $104.9 million, $118.6 million and $125.8 million (includes $86.5 million classified as long-term debt), respectively. The standby revolving credit agreement which supports the related commercial paper (a maximum of $200 million) expired in October 1991 and was extended for 364 days; therefore, the total outstanding amount has been classified as short-term debt.

41

SCHEDULEX VIRGINIA ELECTRIC AND POWER COMPANY

.SCHEDULE X SUPPLEMENTARY INCOME STATEMENT INFORMATION For the years ended December 31, 1991, 1990 and 1989 Col.A.

Item Taxes other than income.taxes:

Real estate and property................

Local gross receipts... *..... ; -..........

Payroll related.......................

. West Virginia business and occupation. ;...

Other... :... *.".......... :.....- ; :...

Total......................

42 1991

$ 71.6 91.7 28.7 28.2 6.8

$227.0 Col. B Charged to Expenses Years Ended December 31, 1990

. (Millions)

$ 66.4 86.6 27.7 21.8 0.4

$202.9

. 1989

$ 60.8 84.4 27.7 21.9 10.0

$204.8 J

e

• . ITEM 9. CHANGES IN AND. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (a) Information concerning directors of Virginia Electric and Power Copipany is as follows:

Name and Age William W. Berry. (59)..

Thos. E. Capps (56)

James T. Rhodes (50)

John R Adams, Jr. (47)

Anna Ruth Inskeep (66)

Benjamin J. Lambert, III (55)

Harvey L. Lindsay, Jr. (62)

Shirley S. Pierce (68)

Principal Occupation for Last 5 Years, Directorships in Public Corporations Chairman of the Board of Directors of Virginia Electric.

and Power Company and Dominion Resources (prior to May' 1, 1990, Chairman of the Board of Directors _.

• and Chief Executive Officer of Dominion Resources}.

He is a Director of Dominion,Resources, Nations-Bank Corporation, Ethy}Corporation and Universal

• Corporation.

Vice. Chairman of the Board of Directors of Virginia Electric and Power Company and President and Chief Executive Officer of Dominion Resources (from April l, 1989 to May 1,.1990, President and Chief Operating Officer of Dominion Resources, prior to April 1, 1989, President of Dominion Resources).

He is a pirector of Dominion Resources, Signet Banking Corporation and. Bassett Furniture Indus-

. tries, Incorporated.

President and Chief Executive Officer of Virginia Elec-tric and Power Company (from January 1, 1988 to April 1, 1989, Senior Vfce President-Finance; prior to January 1, 1988, Senior Vice President-Power Opera-tions). He is a Director of Dominion Resources and

• NationsBank of Virginia, N.A.

President and Chief Executive Officer of A. Smith Bowman Distillery, Inc., Fredericksburg, Virginia, a

• manufacturer arid bottler of alcoholic beverages, De-cember 27, 1989 to date; (prior to December 27, 1989 Vice President and Director).

Battle Park Farms, Rapidan, Virginia, a dairy farm and milk hauling business.

Optometrist, Richmond, Virginia. He is a Director of Consolidated Bank and Trust Company Chairman and Chief Executive Officer of Harvey Lind-

. say Commercial Real Estate, a commercial real es-tate development firm, Norfolk, Virginia.

. Chairman of the Board and President of The Ahoskie Fertilizer Company, Inc., Ahoskie, North Carolina, a manufacturer and distributor of fertilizer and agricul-tural products.

43 Year First Elected a Director

• 198Q 1989 1989 1987 1987 1992 1986 1972

Name and Age William_T. Roos (64) -

William G: Thomas (52)

L Year First Principal Occupation for Last 5 Years, Elected a Directorships in PuJ>Iic Corporations Director.

President of Penn Luggage, inc., retail specialty stores, -

1975 Hampton,- Virginia.

President of Hazel & Thomas, i>.C. Alexandria, Vir-1987 ginia, a law firm.

Each Director holds office uritil the next Annual Meeting of Shareholders or until his or her

• successor is duly elected.

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

Name and Age William W. ':serry (59)

Th~s._ E.. Capps (56)

Jame~ T. Rhodes (50)

John A. Ahladas (49)

• Larry W. Ellis (51)

Robert F. Hill (56)

B. D. Johnson (59)

- Wiiliam L. Stewart (48)

Charles A.. Brown (49)

William R; Cartwright (49)

Business Experience Past Five Years Chairman of the Board of Directors.

Vice Chairman of the Board of Dire~tors, April 1, 1989 to date; President and Chief Operating Officer of Dominion Resources, Inc., prior to. April 1, 1989.

Presideµt arid Chief Executive Officer, April 1, 1989 to date; Senior Vice President-Finance, Jamjary 1, 1988 to April l, 1989; Senior

• . Vice President-Power Operations prior to January 1, 1988.

• Senior Vice President-Corporate Services, January 1, 1990 to date; Senior Vice President-C9rporate Technical Servi<;es, April 1, 1988 to January 1, 1990; Vice President-Engineering prior to April 1; 1988.

Senior Vice President-Power Operations and Planning, January 1, 1990 to da~e;yic~ President-System Planning and Power Supply,

_ March 18, 1988 to January 1, 1990; Manager, System Planning and Power Supply, prior to Ma_rch 18, 1988.*

• Senior Vice President-Commercial Operations.

Senior Vice PresidenhFinai:J.ce and Controller; January, 1, 1990 to.:

date; Vice President and Controller prior to* January 1, 1990.

- Senior Vice Pre~ident-Nuclear, January 1, 1990 to date; Senior Vice -

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

Vice President-Procurement, Septeqiber 1, 1988 to *date; Manager,_

Materials Management, May l, 1988 to September 1, 1988; Man~

ager, Contracts prior fo May 1, 1988.

• Vi~e Preside~t-Fossil and Hydro Operations, January 1, 1990 to date; Vice President-Nuclear Operations, September 1, 1988 to January l, 1990; Vice President-Fossil and Hydro, prior to Sep-

.. *-tember 1; 1988.

Thomas L.'caviness, ~L (46)

• Vice President-Eastern Division, November l, 1989 to date; Execu-tive Project Director, November 1, 1988 to November 1, 1989; Manager, Productivity prior tq November 1, 1988.

44

Naine and Age Thomas N. Chewning (46)

James T. Earwood, Jr. (48)

James R. Frazier, Jr. (50)

Larry M. Girvin (48)

Earl R. Gore (51)

E. Wayne Harrell (45)

F. Kenneth Moore (50)

Irene M. Moszer (48)

James P*. O'Hanlon.(48)

Thomas J. O'Neil (49)

Ro.bert E. Rigsby (42)

Johnny V. Shena! (46)

Eva S. Teig (47)

Business Experience Past Five Years Vice President; Treasurer and Corporate Secretary, October 1, 1991 to date; Vice President and Treasurer, Dominion Energy, Inc.,

January 1, 1990 to October l, 1991; Vice President and Treasurer, Dominion Lands, Inc., June 15, 1987 to October 1, 1991; Vice President-Administration, Dominion Capital, Inc., June 15, 1987 to October 1, 1991; Assistant Treasurer, Dominion Resources, Sep-tember 1, 1988 to March 1, 1990; President, Bethea Consolidated, Inc., Bellevue, Washington, prior to June 15, 1987.

Vice President-Division Services.

Vice President-Southern Division.

Vice President-Central Division, January 1, 1991 to date; District Manager Richmond, September 1, 1989 to January 1, 1991; Dis~

trict Manager East Richmond, prior to September 1, 1989..

Vice President-Northern Division, September 1, 1988 to date; Man-

. ager, Operations and Construction prior to September 1, 1988.

Vice President-Nuclear Services, January 1, 1992 to date; Vice President-Nuclear Operations, January 1, 1990 to January 1, 1992; Vice President-Fossil and Hydro Operations, September 1, 1988 to January 1, 1990; Manager, Fossil and Hydro Operation Support, April 1, 1988 to September l, 1988; Station Manager, Nuclear prior to April 1, 1988.

Vice President-Nuclear Engineering Services, November l, 1989 to date; Vice President-Power Engineering Services, March 18, 1988 to November l, 1989; Manager, Purchasing prior to March 18, 1988:

• Vice President-Information Services, October 1, 1991 to date; Vice

• President, Treasurer and Corporate Secretary, January 1, 1990 to October 1, 1991; Vice President-Administrative Services prior to January 1, 1990.

Vice. President-Nuclear Operations, January 1, 1992 to date; Vice, President-Nuclear Services, June 15, 1989 to January 1, 1992; Vice President, United Energy Services Corporation prior to June 15, 1989.

Vice President-Regulation, August 1, 1988 to date; Vice President-Western Division prior to August 1, 1988.

Vice President-Human Res0,urces, October 1, 1991 to date; Vice President-Information Systems, January l, 1990 to October 1, 1991; Vice President-Western Division, August 1, 1988 to Janu-ary 1, 1990; General Auditor prior to August 1, 1988.

Vice President-Western Division, January 1, 1990 to date; Manager, Transmission and Substation Engineering, August 1, 1988 to Janu-ary 1, 1990; District Manager, Alexandria prior to August 1, 1988.

Vice President-Public Affairs, September 7, 1990 to date; Vice President-Government Affairs, January 1, 1990 to September 7, 1990; Secretary of Health and Human Resources, Commonwealth of Virginia, prior to January 1, 1990.

45 0

t_

e

(,

Name and Age Business Experience Past Five Years Robert F. Saunders (48)

Assistant Vice President-Nuclear, November 1, 1990 to date; Man-.

ager, Nuclear Licensing and Programs, November 1, 1989 to No-vember 1, 1990; Manager, Nuclear Licensing, December 16, 1988 to November 1, 1989; Manager, Nuclear Programs, April 1, 1988 to December 16, 1988; Nuclear Specialist, prior to April 1, 1988.

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

Compliance with Section 16(a) of the Exchange Act Based solely on its review ofth~ forms required by Section 16(a) of the Securities Exchange Act of 1934 that have been received by the Company or written representations from certain reporting persons that no annual statements on Form 5 were required, the Company believes that all filing requirements applicable to its officers, directors and beneficial owners of greater than ten percent of various series of its Cumulative Preferred Stock (registered on the New York Stock Exchange) (the Preferred Stock) have been complied with, except that each of the following persons did not file an Initial Statement on Form 3 stating that they did not own any shares of the Preferred Stock: Messrs. Adams, Lindsay, Thomas, Capps, Ahladas, Ellis, Brown, Cartwright, Caviness, Earwood, Frazier, Girvin, Gore, Harrell, Rigsby, Moore, Chewning, O'Hanlon, O'Neil, Shena! and Saunders and Ms. Inskeep, Moszer and Teig. Each of the above listed individuals has filed a timely Annual Statement on Form 5.

ITEM 11. EXECUTIVE COMPENSATION The following table lists all cash compensation paid by the Company for services rendered in 1991 to each of the five most highly compensated executive officers and to all executive officers as a group.

Name and Capacity in Which Served William W. Berry, Chairman of the Board and Director................

Thos. E. Capps, Vice Chairman of the Board of Directors and Director....

James T. Rhodes, President and Chief Executive Officer and Director......

Robert F. Hill, Senior Vice President..............................

William L. Stewart, Senior Vice President..........................

Executive officers of the Company as a*group 26 persons (including those named above).........................................

Cash Compensation

$ 433,343 405,645 274,600 196,275 192,350 4,046,510 Certain executive officers of the Company are eligible to participate in one of two annual incentive plans. The Virginia Power Management Incentive Plan (the Management Incentive Plan) has been in effect since 1981 and provides incentive compensation for designated employees of the Company. The Dominion Resources, Inc. Cash Incentive Plan (the Dominion Resources Incentive Plan), adopted in 1991 as an amendment and restatement of the Dominion Resources, Inc. Short-Term Incentive Plan, provides incentive compensation for designated executives of the Company who are employees of Dominion Resources or the Company, including Mr. Berry, Mr. Capps and Dr.* Rhodes. The Company's Board of Directors' Organization and Compensation Committee administers and establishes the rules of eligibility, participants' goals and actual awards for the Management Incentive Plan. The Dominion Resources' Board of Directors' Organization and Compensation Committee performs the same administrative function for the Dominion Resources Incentive Plan.

Under both incentive plans, annual awards to participants are based on the achievement of individual and corporate performance goals that are adopted annually. The individual component of each incentive plan is based on the achievement of individual management goals. To the extent that awards paid by the Dominion Resources Incentive Plan are for the achievement of corporate performance goals related to the Company, that portion of the award is paid by the Company.

The 1991 Management Incentive Plan provided for incentive compensation based on (1) individual management goals, (2) achieving a stated contribution to Dominion Resources' earning per share and (3) 46

e a comparison of the annual change in expenses per kilowatt-hour to the annual change in the Consumer Price Index. Amounts earned for the year 1990 under the Management Incentive Plan were paid in March 1991 and were reported in the 1990 Form 10-K and are not included in the above compensation table. Amounts earned for the year 1991 under the program will not be allocated or paid until the end of February 1992.

A Performance Achievement Plan (the Performance Plan) was established effective January 1, 1985, and was approved by the Dominion Resources Stockholders at the 1985 Annual Meeting. The Performance Plan awards shares of Dominion Resources Common Stock for the achievement of specific long-term goals and strategies that are approved by the Organization and Compensation Committee (the Committee) of the Board of Directors of the Company. Distributions of stock under the Performance Plan may not exceed 10,000 shares times the number of participants in the Performance Plan on the relevant date. The duration of each performance period is three years, and a new performance period and set of goals are initiated annually. Participants in the Performance Plans for the periods of 1989-91, 1990-92 and 1991-93 include all Vice Presidents of the Company, but do not include the Chairman or Vice Chairman of the Board of Directors or the President. Subject to the Committee's approval and within certain time periods established in the Performance Plan, each participant may elect to receive up to 50 percent of any award in cash and to defer all or part of any award. To be eligible for an award, an employee must occupy a qualifying position for an entire performance cycle. Individual awards will be determined on the basis of goal achievement, positions held during the performance period, the salary grade mid-points of those positions and the average price of the Common Stock on the last day of September, October and November of the year before the start of the performance cycle. Following the conclusion of each performance period, the Committee determines the level of achievement of the goals for that performance period. The Board of Directors must approve each participant's award, and may approve pro rata awards to participants who retire, die, become disabled, or transfer during a performance cycle; Dominion Resources' Board of Directors must approve any award for any participant who is also an officer or director of Dominion Resources.

Awards for the 1989-91 performance period have not yet been allocated but will be made in the latter part of February 1992 and will be based on (1) the performance of Virginia Power's return on equity over the three-year period as compared to the average for comparable electric utilities, and (2) a comparison between the increase in expenses per kilowatt-hour and the increase in the Consumer Price Index over the three-year period.

No awards can be determined or made under the 1990-92 and the 1991-93 performance periods of the Performance Plans until 1993 and 1994, respectively.

Certain executive officers surrendered outstanding awards under the Management Incentive Plan and the Performance Plan in favor of substantially identical awards under the Dominion Resources

. Incentive Plan and the Dominion Resources, Inc. Long-Term Incentive Plan (the Dominion Resources Long-Term Plan). For example, Messrs. Rhodes, Herrick and Robertson surrendered outstanding awards under the Performance Plan for the 1989-91, 1990-92, and 1991-93 performance cycles.

Dr. Rhodes also relinquished his opportunity to participate in the Management Incentive Plan for 1991.

The substituted awards under the Dominion Resources Incentive Plan and the Dominion Resources Long-Term Plan are governed by the same terms and conditions, and provide an opportunity to earn the same level of incentive compensation, as the surrendered awards.

In 1990, the Company established a Budget Incentive Plan (the Budget Plan) for 1990 and 1991.

Incentive awards are earned by (1) reducing actual 1990 operation and maintenance (O&M) and capital budget expenses to specified target levels, (2) developing budgets for 1991 to meet targets, and (3) keeping actual 1991 expenses and capital expenses at target ievels for 1991. With the exception of the Chairman, Vice Chairman, and the President, officers and managers of the Company participate in the Budget Plan. For 1991, the Plan provides each participant with a maximum award of $7,000 if both targets are met, of which 25% was payable for planning, and 75% is payable for making, the 1991 targets.

47

Awards for 1990 and for planning the 1991 budget were paid in December 1990 and January 1991 and were reported in the 1990 Form 10-K. Awards for making the 1991 targets will be paid in the latter part of February 1992.

In 1990, the Company established an incentive plan (the Nuclear Performance Plan) directed at key personnel in the Company's nuclear operations area. Incentive awards under the Nuclear Incentive Plan are earned by completing scheduled outages at the Company's nuclear power stations within established time schedules. Awards are reduced by 10 percent for each day that the outage continues beyond the scheduled completion date. Awards for the year 1991 are included in the cash compensation table above.

An employee savings plan has been in effect since 1963. Effective January 1, 1989, the employee savings plan was amended by separating it into two plans (the Savings Plans), one for salaried and one for nonsalaried employees. The Savings Plans include a salary reduction provision under Section 401(k) of the Internal Revenue Code of 1986 (the Code) for officers and employees. The two Savings Plans are identical in all material respects. Under the Savings Plan, employees who have attained age 18 and completed six months of service may make contributions of between 2 percent and 6 percent of their base compensation, and the Company contributes an amount equal to 50 percent of such contributions.

Employees may also make additional contributions, which are not matched by their employer. (In accordance with Section 401(k) of the Code, the Savings Plans provide participants with the option to reduce their gross income for federal income tax purposes and the Company contributes that amount to the Savings Plan on behalf of the employee.) Participants' contributions and deferrals under Section 401(k) are subject to certain limitations prescribed in the Code. The compensation table above includes amounts deferred pursuant to Section 40l(k). The employees may direct that their contributions be allocated between an interest bearing fund, which invests primarily in U.S. Government securities, and a stock fund, which invests in Dominion Resources Common Stock. All of the Company's matching contributions to the Savings Plans are invested in Dominion Resources Common Stock. The Savings Plans provide for the vesting of the Company's matching contributions at the earlier of(a) the beginning of the third year following the year in which the contribution was made and (b) the date the participant completes five years of service with the Company. However, matching contributions vest immediately for participants aged 55 or older. Amounts shown in the Cash Compensation table above do not include any Company matching contributions. The following Company matching contributions vested under the Savings Plan during 1991: William W, Berry: 138 shares; Thos. E. Capps: 138 shares; James T. Rhodes:

72 shares; Robert F. Hill: 122 shares; William L. Stewart: 80 shares; and 1,978 shares to the 26 executive officers as a group.

A retirement plan (the Retirement Plan) provides retirement benefits for all eligible officers and employees of Virginia Power who have attained age 21 and completed six months of service. The Retirement Plan is a noncontributory defined benefit plan that provides for vesting of retirement benefits upon completion of five years of vesting service or, if earlier, upon attainment of age 50. Employer contributions to the Retirement Plan are determined actuarially. Benefits under the Retirement Plan, as of December 31, 1991, 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. Compensation in excess of $200,000 (indexed for changes in the cost of living) may not be taken into account under the Plan. Benefits under the Retirement Plan are payable as a straight life benefit or a joint and survivor benefit. In May 1990, the Internal Revenue Service issued proposed regulations, subsequently modified, related to pension plan non-discrimination requirements that were included in the Tax Reform Act of 1986. The Company has determined that the Retirement Plan's benefit formula complies with such regulations and that no changes to the benefit formula will

• be necessary.

The table below sets forth the estimated annual straight life benefit that would be paid following retirement under the Retirement Plan's benefit formula. 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. At this time, credited years of service under the Retirement Plan and such retirement agreements (excluding contingent years) for the individuals named in the compensation table are as 48

J follows: William W. Berry: 30; Thos. E. Capps: 21; James T. Rhodes: 20; Robert F. Hill: 27; and William L. Stewart: 21. Estimated annual benefit figures are based on the formulas in effect under the Retirement Plan as of December 31, 1991.

Estimated Annual Benefits Payable Upon Retirement*

Credited Years of Service Final Average Earnings**

15 20 25 30

$ 75,000

$ 18,583

$ 24,778

$ 30,972

$ 37,166 100,000 26,083 34,778 43,472 52,166 125,000 33,583 44,778 55,972

• 67,166 150,000 41,083 54,778 68,472 82,166 175,000 48,583 64,778 80,972 97,166 200,000 56,083 74,778 93,472 112,166 250,000 71,083 94,778 118,472 142,166 300,000.

86,083 114,778 143,472 172,166 350,000 101,083 134,778 168,472 202,166 400,000 116,083 154,778 193,472 232,166 450,000 131,083 174,778 218,472

. 262,166

• Based on normal retirement at age 65.

• • Final Average Earnings is one-fifth of the earnings during the 60 consecutive calendar months during which the individual's earnings are the highest. The table does not reflect the limit on the amount of compensation that may be recognized by the Retirement Plan (i.e., annual compensation in excess of $200,000 (adjusted for changes in the cost of living)).

For purposes of the above table, based on 1991 compensation, final average earnings for each of the individuals named in the cash compensation table would be as follows: William w: Berry: $370,611; Thos. E. Capps: $309,627; James T. Rhodes: $197,775; Robert F. Hill:_ $177,815; and William L.

Stewart: $158,130.

The Internal Revenue Code limits the annual retirement benefit that may be paid from a qualified retirement plan and, as noted above, the amount of compensation that may be recognized by the Retirement Plan. To the extent that benefits determined under the Retirement Plan's benefit formula exceed the limitations imposed by the Internal Revenue Code, they will be paid under the Dominion Resources, Inc. Benefit Restoration Plan (the Benefit Restoration Plan), either from general funds as an operating expense or from a secular trust fund established for such purpose.

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 and Directors' fees). The normal form of benefit is payable in equal monthly installments for 120 months to a participant with 60 months of service, who (i) retires at or after age 55 from the employ of the Company, (ii) has become permanently disabled, or (iii) dies. If a participant dies while employed, the normal form of benefit will be paid to a designated beneficiary. If a participant dies while retired, but before receiving all benefit payments, the remaining installments will.

be paid to a designated beneficiary. In order to be entitled to benefits under the Supplemental Plan, an employee must be employed as an elected officer of the Company until death, disability or retirement.

Based on 1991 compensation, the estimated annual retirement benefit for each of the executive officers under the Supplemental Plan would be as follows: William W. Berry: $173,881; Thos. E. Capps:

$167,881; James T. Rhodes: $106,840; Robert F. Hill: $62,265; and William L. Stewart: $61,365.

The Company has transferred cash, and in its discretion may make future transfers of cash or other property, to an irrevocable trust. The assets of the trust must be used to satisfy employee benefit and similar obligations to employees and former employees of the Company, including the obligations described above for executive employees.

49

e c'

The Board of Directors of Dominion Resources adopted the Dominion Resources, Inc. Retirement Benefit Funding Plan (the Trust) on June 15, 1990. The Trust is intended to allow Dominion Resources and its subsidiaries, including the Company, to fund their obligations under (i) the Supplemental Plan, (ii) the Benefit Restoration Plan and (iii) supplemental retirement benefit agreements with certain key executives. Benefits provided under the Trust reduce, on a dollar-for-dollar basis, the amounts payable under the above plans and agreements. The Company's Board of Directors and the Committee have certain responsibilities under the Trust with respect to participants who are current or former elected officers of Virginia Power (Virginia Power Participants). The Administrative and Investment Benefit Committee and the Administrative Benefit Committee also have responsibilities under the Trust.

Dominion Resources and its subsidiaries, including the Company, may, in their discretion, make contributions to the Trust. In addition, amounts may be transferred to the Trust from the irrevocable trust described above. Contributions and transfers on behalf of Virginia Power Participants are subject to the approval of the Company's Board of Directors.

An individual may become a Virginia Power Participant only upon his selection by the Company's Board of Directors. The Committee is responsible for establishing a funding policy with respect to Virginia Power Participants. The current funding policy adopted by the Committee calls for nominal contributions during an individual's initial years of participation in the Trust and for full funding of his Supplemental Plan, Benefit Restoration Plan, and supplemental retirement agreement benefits between the ages 51 and 55.

The Administrative and Investment Benefit Committee is responsible for establishing an invest-ment policy for the Funding Plan. The Administrative Benefits Committee is responsible for the

. implementation of that investment policy as well as the day-to-day administration of the Trust.

Participants in the Trust are fully vested in their interests therein. Each Trust participant will begin to receive his benefit from the Trust upon separation from service (without regard to the reason for his separation). Benefits are paid under the Trust in the same manner as the Supplemental Plan's benefits.

Dominion Resources has reserved the right to amend or terminate the Trust at any time. No amendment or termination will divest a participant of amounts previously allocated to his Trust account.

Amounts contributed or transferred to the Trust may not revert to Dominion Resources or any of its subsidiaries.

During 1991, a total of $28,400 was contributed to the Trust and allocated to the accounts of the 23 Funding Plan participants, including the executive officers named in the cash compensation table and all executive officers as a group.

The Company has purchased an insurance policy that provides certain managers and all elected officers with accidental death and dismemberment insurance. The policy provides an accidental death benefit to managers and officers ranging from $50,000 to $250,000, with the specific dollar amount of coverage being determined on the basis of the covered employee's position. The policy also provides accidental death and dismemberment insurance to the spouses of all officers who are Vice Presidents or higher in rank, and the accidental death benefit ranges from $100,000 to $200,000 (depending on the officer's position). This insurance coverage is provided at no cost to covered employees.

The Company has entered into employment agreements (the Agreements) with key management executives, including the officers named above. Each Agreement has a three-year term and thereafter is automatically extended on its anniversary date for an additional year unless notified that the Agreement will not be extended by the Company. If, following a change in control of Dominion Resources (as defined in the Agreements), an executive's employment is terminated by the Company without cause, or voluntarily by the executive within sixty days after a material reduction in the executive's compensation, benefits or responsibilities, the Company will be obligated to pay to the executive continued compensation equaling the average base salary and cash incentive bonuses for the thirty-six full month period of employment preceding the change in control or employment termination.

In addition, the terminated executive will continue to be entitled to any benefits due under any stock or 50

benefit plans. The Agreements do not alter the compensation and benefits available to an executive whose employment with the Company continues for the full term of the executive's Agreement. The amount of benefits provided under each executive's Agreement will be reduced by any compensation earned by the executive from comparable employment by another employer during the thirty-six months following termination of employment with the Company. An executive shall not be entitled t9 the above benefits in the event termination is for cause.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below sets forth as of January 31, 1992, except as noted, the number of shares of Common Stock of Dominion Resources owned by directors of Virginia Electric and Power Company.

. Name William W. Berry.................

Thos. E. Capps..................

James T. Rhodes.................

John B. Adams, Jr.................

Anna Ruth Inskeep...............

Benjamin J. Lambert, III...........

Harvey L. Lindsay, Jr.............

Shirley S. Pierce.................

William T. Roos..................

William G. Thomas.............. *.

Shares of Common Stock Beneficially Owned 44,307 (a) 31,202(b) 3,839 155 2,000 0

256 4,236 702(c) 0 (a) Includes 15,420 shares represented by options awarded and exercisable under the Dominion Resources, Inc. Long-Term Incentive Plan.

(b) A member of Mr. Capp' s family is a beneficiary of a trust that owns an additional 1,500 shares of Common Stock. Also includes 10,200 shares represented by options awarded and exercisable under the Dominion Resources, Inc. Long-Term Incentive Plan.

(c) Members of Mr. Roos' family are beneficiaries of trusts that own an additional 2,830 shares of Common Stock for which he disclaimed beneficial ownership.

All current Directors and officers as a group (33 persons) beneficially own, in the aggregate, less than 1 percent of each class of Dominion Resources and the Company's equity securities, respectively.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Hazel & Thomas, P.C., provided legal services to the Company during 1991. Mr. William G.

Thomas, a director of the Company, is President of Hazel & Thomas.

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

1. Financial Statements See Index on page 17.

2. Financial Statement Schedules See Index on page 17.

51

3. Exhibits 3(i)

-Restated Articles of Incorporation, as amended, as in effect on June 16, 1989 (Exhibit 3(i), Form 10-Q for the quarter ended September 30, 1989, File No. 1-2255, incorporated by reference).

3(ii)

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

4(i)

-See Exhibit (3(i)) above.

4(ii)

-Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures, Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference; Fifty-Ninth Supplemental Indenture, Exhibit 4(ii), Form 10-Q for the quarter ended March 31, 1986, File No. 1-2255, incorporated by reference; Sixtieth Supplemental Indenture, Exhibit 4(ii), Form 10-Q for the quarter ended September 30, 1986, File No. 1-2255, incorporated by reference; Sixty-First Supplemental Indenture, Exhibit 4(ii), Form 10-Q for the quarter ended June 30, 1987, File No. 1-2255, incorporated by reference; Sixty-Second Supplemental Indenture, Exhibit 4(ii), Form 8-K, dated November 3, 1987, File No. 1-2255, incorporated by reference; Sixty-Third Supplemental Indenture, Exhibit 4(i), Form 8-K, dated June 8, 1988, File No. 1-2255, incorporated by reference; Sixty-Fourth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated February 8, 1989, File No. 1-2255, incorporated by reference; Sixty-Fifth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated June 22, 1989, File No. 1-2255, incorporated by reference; Sixty-Sixth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated February 27, 1990, File No. 1-2255, incorporated by reference; and Sixty-Seventh Supplemental Indenture, Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference.

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

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

4(v)

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

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

lO(i)

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

lO(ii)

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

lO(iii)

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

52

lO(iv) lO(v) lO(vi) lO(vii) lO(viii) lO(ix) lO(x) lO(xi) lO(xii) lO(xiii) lO(xiv) lO(xv) lO(xvi) 22 24(i) 24(ii) 24(iii)

(b)

-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. 1-2255, incorporated by reference).

-Heat Supply Contract, dated as of October 14, 1987, between Virginia Electric and Power Company and Virginia Power Fuel Corporation (Exhibit lO(v), Form 10-K for the fiscal year ended December 31, 1987, File No. 1-2255, incorporated by reference).

-Heat Supply Contract extension, dated October 11, 1991, between Virginia Electric and Power Company and Virginia Power Fuel Corporation (filed herewith under cover of Form SE).

-Credit Agreement, dated as of October 11, 1991, among Virginia Power Fuel Corporation, ABN AMRO Bank N.V., New York Branch, as Facility Agent, and the Banks.named therein (filed herewith under cover of Form SE).

---Guarantee, dated as of October 11, 1991, by Virginia Electric and Power Company in favor of ABN AMRO Bank N.V., as Facility Agency, and the Banks named therein (filed herewith under cover of Form SE).

-Inter-Company Credit Agreement, dated July 1, 1986, as amended and restated as of September 1, 1987 between Dominion Resources and Virginia Electric and Power Company (Exhibit lO(viii), Form 10-K for the fiscal year ended December 31, 1987, File No. 1-2255, incorporated by reference).

-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. 1-2255, incorporated by reference).

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

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

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

-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 only) (Exhibit lO(xiii), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).

-Receivables Purchase Agreement, dated as of December 11, 1991, between Virginia Electric and Power Company and Dynamic Funding Corporation (filed herewith under cover of Form SE).

.:._Description of arrangements with certain officers regarding additional credited years of service for retirement purposes (filed herewith under cover of Form SE).

-Subsidiaries of Virginia Electric and Power Company (not included because Virginia Electric and Power Company's subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a "significant subsidiary" under Rule 1-02( v) of Regulation S-X as of the end of the year covered by this report).

-Consent of Hunton & Williams (filed herewith under cover of Form SE).

-Consent of Jackson & Kelly (filed herewith under cover of Form SE).

-Consent of Deloitte & Touche (filed herewith under cover of Form SE).

Report on Form 8-K None 53

/'

I

---

~ ----------------------------------------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 COMPANY WILLIAM w. BERRY By----------------~

(William W. Berry, Chairman of the Board of Directors)

Date: February 14, 1992 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons -on behalf of the registrant and in the capacities and on the date

• indicated.

Signature Title WILLIAM W. BERRY Chairman of the Board of Willi am w. Berry Directors and Director THos. E. CAPPS Vice Chairman of the Board of Tho s. E. Capps Dir_ectors and Director J. T. RHODES President (Chief Executive J. T. Rhodes Officer) and Director JoHN B. ADAMS, JR.

John B. Adams, Jr.

ANNA RUTH INSKEEP Anna Ruth Inskeep BENJAMIN J. LAMBERT, III Benjamin J. Lambert, III HARVEY L. LINDSAY, JR.

Harvey L. Lindsay, Jr.

SHIRLEY s. PIERCE Shirley S. Pierce WILLIAM T. Roos William T. Roos w ILLIAM G. THOMAS William G. Thomas Director Director Director Director Director Director Director B. D. JoHNSON Senior Vice President and B. D. Johnson Controller (Principal Accounting Officer)

THOMAS N. CHEWNING Vice President and Treasurer (Chief Thom as N. Chewning Financial Officer)

Date February 14, 1992 February 14, 1992 February 14, 1992 February 14, 1992 February 14, 1992 February 14, 1992 February_ 14, 1992 February 14, 1992 February 14, 1992 February 14, 1992 February 14, 1992 February 14, 1992