ML18151A560
| ML18151A560 | |
| Person / Time | |
|---|---|
| Site: | Surry, North Anna  |
| Issue date: | 03/24/1994 |
| From: | Stewart W VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.) |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| 94-192, NUDOCS 9403290234 | |
| Download: ML18151A560 (65) | |
Text
l e e VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 March 24, 1994 Director, Nuclear Reactor Regulation Serial No.94-192 United States Nuclear Regulatory Commission NURPC Washington, D. C. 20555 Docket Nos. 50-280 50-281 50-338 50-339
. License Nos. DPR-32 DPR-37 NPF-4 NPF-7 Gentlemen:
VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS l AND 2 NORTH ANNA POWER STATION UNITS 1 AND 2 PRICE-ANDERSON ACT Pursuant to 10 CFR 140.21 (e) regarding guarantees of payment of deferred premiums, we are providing the following information:
- 1. Annual Report to Securities and Exchange Commission on Form 10-K for 1993.
- 2. Comparative Statement of Income for the three months ended December 31, 1993 and 1992.
- 3. Internal cash flow projection for calendar year 1994 with certification by an officer of the Company.
- 4. Statement ensuring availability of funds for payment of retrospective premiums without curtailment of required nuclear construction expenditures.
In accordance with 10 CFR 140. 7, we submitted a check to the NRC for $1,000 on November 18, 1993, which is the minimum required premium for the period November 15, 1993, through November 14, 1994.
Very truly yours, Jz~
W. L. ?te~
Senior Vice President - Nuclear Enclosures
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- * .t cc: U. S. Nuclear Regulatory Commission Region II 101 Marietta Street, N. W.
Suite 2900 Atlanta, Georgia 30323 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D. C. 20555 Mr. M. W. Branch NRC Senior Resident Inspector Surry Power Station Mr. R. D. McWhorter NRC Senior Resident Inspector North Anna Power Station
VIRGINIA ELECTRIC AND POWER COMPANY Page Item Number Number PART I
- 1. Business........................................................................................................................................................................................ 1 The Company.............................................................................................................................................................................. 1 Capital Requirements and Financing Program........................................................................................................................... 1 Construction and Nuclear Fuel Expenditures......................................................................................................................... 1 Financing Program ................................... :................ :............................................................................................................. 2 Rates............................................................................................................................................................................................. 2 Virginia .................................................................................................................................................................................... 2 North Carolina......................................................................................................................................................................... 3 Regulation .............................................................................................. *..................................................................................... 3 General..................................................................................................................................................................................... 3 Environmental.......................................................................................................................................................................... 4 Nuclear..................................................................................................................................................................................... 4 Winter Peak............................................................................................................................................................................. 4 Sources of Power .............................................................................................................. ;......................................................... 5 Company Generating Units..................................................................................................................................................... 5 Net Utility Purchases .............................................................................................................................................................. 5 Non-Utility Generation............................................................................................................................................................ 5 Sources of Energy Used and Fuel Costs.................................................................................................................................... 5 Nuclear Operations and Fuel Supply ..................................................................................................................................... 5 Fossil Fuel Supply................................................................................................................................................................... 6 Purchases and Sales of Power................................................................................................................................................ 6 Interconnections........................................................................................................................................................................... 6 Future Sources of Power............................................................................................................................................................. 7 Company Owned Generation.................................................................................................................................................. 7 Non-Utility Generation............................................................................................................................................................. 7 Competition.................................................................................................................................................................................. 7 Conservation and Load Management......................................................................................................................................... 8
- 2. Properties ........................................................... *............................................................................................................................ 8
- 3. Legal Proceedings .......................................................................................................................................................................... 8
- 4. Submission of Matters to a Vote of Security Holders................................................................................................................... 10 PART II
- 5. Market for the Registrant's Common Equity and Related Stockholder Matters.................................................................................................................................................................... 10
- 6. Selected Financial Data.................................................................................................................................................................. 10
- 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................................................................................................................... 10
- 8. Financial Statements and Supplementary Data............................................................................................................................. 18
- 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure............................................................................................................................................................. 47 PART III
- 10. Directors and Executive Officers of the Registrant.................................................................................................................... 47
- 11. Executive Compensation.............................................................................................................................................................. 49
- 12. Security Ownership of Certain Beneficial Owners and Management................................................................................................................................................................................. 52
- 13. Certain Relationships and Related Transactions......................................................................................................................... 52 PART IV
- 14. Exhibits, Financial Statement. Schedules, and Reports on Form 8-K .................................................................................................................................................... *............................... 53
- ' e SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
- Form*tO-K (Mark One) 181 ANNUAL REPORT PURSUANT TO SECTION-13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1993 or 0 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition periQd f r o m - - - - - - t o - - - - - -
Commission file number 1-2255 VIRGINIA ELECTRIC AND POWER COMPANY (Exact name of registrant as specified in its charter)
VIRGINIA 54-0418825 (State or other jurisdiction of , *(I.R.S. Employer incorporation or organization) identification no.)
One James River Plaza Richmond, Virginia 23261-6666 (Address of principal executive offices) (Zip Code)
(804) 771-3000 (Registrant's telephone number, including are~ code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class _ Name of each exchange on which registered Preferred Stock (cumulative) New York Stock Exchange
$100 liquidation value:
$5.00 dividend *
$7.45 dividend
$7 .20 diviclend Securities registered pursuant to Section 12(g) of the Act:
None -
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Sectjon 13 or 15(d) of the, Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter.period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days .. Yes 1"' 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 of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [Y']
The aggregate market value of the voting stock held by non-affiliates of the registrant as of January 31, 1994 was zero.
As of January 31, 1994, there were issued and outstanding 168,277 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
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 munic-ipalities. The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population. As used herein, the terms "Virginia Power" and the "Company" shall refer to the entirety of Virginia Electric and Power Company, including, without limitation, its Virginia and North Carolina operations.
The Company has nonexclusive franchises or permits for electric operations in substantially all cities and towns now served. It also has certificates of convenience and necessity from the Virginia State Corporation Commission (the Virginia Commission) for service in all territory served at retail in Virginia. The North Carolina Utilities Commission (the North Carolina Commission) has assigned territory to the Company for substantially all of its retail service outside certain munici-palities in North Carolina.
The Company strives to operate its generating facilities in accordance with prudent utility industry practices and in conformity with applicable statutes, rules and regulations. Like other electric utilities, the Company's generating facilities are subject to unanticipated or extended outages for repairs, replacements or modifications of equipment or otherwise to comply with regulatory requirements. Such outages may involve significant expenditures not previously budgeted, including replace-ment 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 11,861 full-time employees on December 31, 1993. 4,163 of the Company's employees are repre-sented by the International Brotherhood of Electrical Workers under a contract extending to March 31, 1995. The Company considers its relations with its union and nonunion employees to be good.
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 1994-1996, total $2.1 billion. It has adopted a .1994 budget for construction and nuclear fuel expenditures as set forth below:
Estimated 1994 Expenditures (millions)
New Generating Facilities:
Clover Unit 1 and *unit 2 .......................................................................................... $ 80 Other Production:
Clean Air Act............................................................................................................. 59 North Anna Unit 2 steam generator replacement..................................................... 24 Other........................................................................................................................... 96 General Support Facilities.............................................................................................. 46 Transmission................................................................................................................... 51 Distribution..................................................................................................................... 241 Nuclear Fuel ... ....................... ........... ................................ ......... ................ ..................... 94 Total Construction Requirements and Nuclear Fuel................................................. 691 AFC................................................................................................................................. 11 Total Expenditures...................................................................................................... $702 1
Financing Program In 1993, Virginia Power obtained $1.2 billion from the sale of securities. With a portion of the proceeds of the 1993 securities sales, the Company retired $153 million of securities through mandatory debt maturities and sinking fund require-ments and retired an additional $919 million of securities through optional redemptions and sinking fund payments. Its long-term financings included $1 billion of First and Refunding Mortgage Bonds, $150 million of preferred stock, and $50 million of Common Stock sold to Dominion Resources. See Liquidity and Capital Resources under MANAGEMENT'S DISCUS-SION AND ANALYSIS OF FINANCIAL CONDITION AND. RESULTS OF OPERATIONS for, among other things, a discussion of the Company's commercial paper program.
Virginia Power's 1994 construction requirements, exclusive of AFC, are estimated to be $691 million, as detailed above.
Of this amount, it is expected that approximately $325 million will be obtained from cash flow from operations. The remain-ing $366 million of construction requirements, as well as the $167 million of debt and preferred stock maturities and sinking fund requirements, will be obtained by a combination of sales of securities and short-term borrowings. See Liquidity and Capital Resources under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. .
RATES The Company was subject to rate regulation in 1993 asfollows:
1993 Percent Percent of of Revenues Kwh Sales Virginia retail:
Non-Governmental customers ........ ,.............. . Virginia Commission 78% 73%
Governmental customers .............................. . Negotiated Agreements 11 12 North Carolina retafl ........................................ . ,North Carolina Commission 4 4 Wholesale:
Requirements - Sales for Resale ................ . Federal Energy Regulatory 5 8 Commission (FERC)
Non-Requirements - Sales for Resale ....... . FERC 2 3 100% 100%
All of the Company's electric sales are subject to recovery of changes in fuel costs either through fuel adjustment factors or periodic adjustments to base rates, each of which requires prior regulatory approval.
Each of these jurisdictions has the authority to disallow recovery of costs it determines to be excessive or imprudently incurred. Various cost items may be reviewed on occasion, including costs of constructing or modifying facilities, on-going purchases of capacity .or providing replacement power during generating unit outages.
The principal rate proceedings in which the Company was involved in 1993 are described below by jurisdiction. Rate relief obtained by the Company is frequently less than requested.
Virginia As a result of the reversal by the Virginia Supreme Court of the Virginia Commission's Final Order in the Company's 1990 rate proceeding, which approved a rate increase of $79.8 million, the Company refunded $26 million, including interest, to Virginia retail customers in 1992.
In the Company's 1991 expedited rate proceeding, which ultimately sought an increase in annual revenues of $158.6 million, the Virginia Commission approved an increase of $45.2 million on December 29, 1992. Refunds of $188.9 million were completed in .1993.
In all material respects, the Company had adequately reserved for these refunds in the appropriate periods.
Virginia Power's 1992 rate case before the Virginia Commission, which was consolidated with a separate proceeding for approval of proposed revisions to the Company's line extension policy and an increase in the differential between summer and winter rates, was heard before a Hearing Examiner during 1993. The increase requested at the hearing was approximately 2
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$314.6 million, and the Hearing Examiner recommended an increase of $234.8 million. In the comments it submitted on the Hearing Examiner's recommendations, Virginia Power reduced its request to $289 million. On February 3, 1994, the Virginia Commission entered its Final Order in which it approved an increase of $241.9 million. In all material respects, the Company has adequately reserved for the difference. Refunds will be made in 1994. The Commission also approved continuation of deferral accounting to recover purchased power capacity costs, allowed inclusion of salary incentive pay in the cost of ser-vice, accepted the Company's calculation of postretirement benefits other than pensions, allowed rate base to be updated to November 30, 1992, and recommended a return on equity in the range of 10.5% to 11.5% with rates to be based on 11.4% to reflect superior operating performance of .the Company's generating units. The Commission disapproved the proposed changes in the line extension policy and the proposed increase in the summer/winter rate differential, and it disallowed from recovery through rates the gross receipts tax component of capacity payments under certain previously executed power pur-chase contracts. The Commission directed the Company, the Commission's Staff, and other interested parties to explore the concept of expanding the generating unit performance program to include purchases of capacity and to present testimony on it in the Company's next rate case ..
Virginia Power filed an application with the Virginia Commission on June 4, 1993 requesting approval of Schedule DEF -Dispersed Energy Facility rate that would allow the Company, on an experimental basis, to respond to the request of an -industrial or commercial customer to build and operate a generating facility at its business location and to sell to that a
customer all of the electricity and associated steam from that facility under long-term contract. Prepared testimony and pre-hearing briefs have been filed. A hearing before a Hearing Examiner was held on January 31, 1994 and briefs are due March 7, 1994.
Virginia Power's application to revise its Schedule 19 (rates to be paid to small qualifying facilities), which seeks approval of (a) limiting the schedule's applicability to facilities of 100 Kw* or less and (b) postponing the commencement of capacity payments until the capacity is needed by the Company, was considered at a hearing before a Hearing Examiner on January 10, 1994 and briefs are due February 28_, 1994.
Rules The Virginia Commission has initiated a proceeding to consider new rules governing rate case filings. For additional information, see Utility Rate Regulation under MANAGEMENT'S I)ISCUSSION AND ANALYSIS OF FINANCIAL CONDIDON AND RESULTS OF OPERATIONS.
North Carolina In Virginia Power's 1992 rate case before the North Carolina Commission, which included an increase in base rates and a decrease in fuel rate~, the Company sought a net increase in annual revenues of $13.9 million. The *commission issued its Order approving an increase of $10.6 million on February 26, 1993. The Company appealed the Commission's Order as it relates to the recovery of two expense items: the capacity costs paid to a cogenerator and a portion of the compensation of certain Company officers. The Appeal has been briefed and argued before the Supreme Court of North Carolina, and a decision is pending.
REGULATION General In a wide variety of matters in addition to rates, Virginia Power'is presently subject to regulation by the Virginia Com-mission and the North Carolina Commission, the Environmental Protection Agency (EPA), Department of Energy (DOE),
Nuclear Regulatory Commission (NRC), FERC, the Army Corps of Engineers, and other federal, state and local authorities.
Compliance with numerous laws and regulations increases the Company's operating and capital costs by requiring, among other things, changes in the design and operation of existing facilities and changes or delays in the location, design, construc-tion 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 facili-ties or large capacity transmission lines without the prior approval of state and federal governmental agencies having jurisdic-tion over various aspects of its business. Such approvals relate to, among other things, the environmental impact of such activities, the relationship of such activities to the need for providing adequate utility service and the design and operation of proposed facilities.
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- e Various provisions of the Energy Policy Act of 1992 (Energy Act) that could affect the Company include those encour-aging the development of non-utility generation, giving FERC authority to order transmission access for wholesale transac-tions, requiring higher energy efficiency and alternative fuels use, restructuring of nuclear plant licensing procedures, and requiring state regulatory authorities to give full rate treatment for the effects of conservation and demand management programs, including the effects of reduced sales. Many provisions of the Energy Act must be implemented by regulations that have not yet been adopted but that may affect electric utilities. Therefore, while the full impact of the Energy Act on the Company cannot at this time be quantified it may, over time, be significant. See Competition under BUSINESS and Competi-tion under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Environmental From time to time, the Company may be identified as a potentially responsible party with respect to a Superfund site.
EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation and feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs, but the parties can then bring contribution actions against each other and seek reimbursement from their insurance companies. As a result of the Superfund Act or other laws or regulations regarding the remediation of waste, the Company may be required to expend amounts on remedial investigations and actions. Although the Company is not currently aware of any sites or events including those sites currently identified likely to result in significant liabilities, such amounts, in the future,. could be significant.
Permits under the Clean Water Act and state laws have been issued for all of the Company's steam generating stations now in operation. Such permits are subject to reissuance and continuing review.
The Company is subject to the Clean Air Act (Air Act), which provides the statutory basis for ambient air quality standards. In order to maintain compliance with such standards and reduce the impact of emissions on ambient air quality, the Company may be required to incur 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 particular, the Company is installing a scrubber at its Mt. Storm Power Station to be operational by January l, 1995. The scrubber is expected to cost approxi-mately $140 million. The Company may install two additional scrubbers to meet standards that must be achieved no later than January 1, 2000. The total capital cost for compliance assuming the installation of three scrubbers, nitrogen oxide controls and emission monitoring instrumentation, is estimated at $481 million (1992 dollars). Annual incremental compli-ance costs for operation, maintenance and fuel costs are estimated to be $128 million.
The Company is engaged in discussions with the West Virginia Office of Air Quality (OAQ) concerning opacity require-ments applicabie to the Mt. Storm Power Station. The Company has submitted a draft consent order to OAQ and is presently uncertain as to what will constitute appropriate remedial action and is continuing to investigate the alternatives that may be available.
For additional information on Environmental Matters, see Note M to FINANCIAL STATEMENTS.
Nuclear All aspects of the operation and maintenance of the Company's nuclear power stations are regulated by the NRC.
Operating licenses issued by the NRC are subject to revocation, suspension or modification, and operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantal increases in the cost of operating and maintaining the Company's nuclear generating units.
Winter Peak Due to record cold weather on January 19, 1994, the Company reached a record winter peak of 14,877 MW, which exceeded the prior record of 13,478 MW that had been established one day earlier. Demand on the Company's system resulted in short periods of rolling blackouts. Similar conditions were experienced by utilities within the Pennsylvania-New Jersey-Maryland Power Pool. As a result of these extreme conditions, fact-finding inquiries by the Staff of the Virginia Commission, the FERC and a committee of the U.S. Congress have commenced.
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'f e e SOURCES OF POWER Company Generating Units Type Summer Years of Capability Name of Station, Units and Location Installed Fuel Mw Nuclear:
Surry Units_ 1 & 2, Surry, Va ....................................................... :................ :.... .. 1972-73 Nuclear 1,562
_North Anna U~its 1 & 2, Mineral, Va ................................................................ . 1978-80 Nudear l,787(a)
Total nuclear stations ........................................................................................ . . 3,349 Fossil Fuel:
Steam:
Bremo Units 3 & 4, Bremo Bluff, Va ......................._.'..................................... . 1950-58 Coal 227 Chesterfield Units 3-6, Chester, Va ................................................................. . 1952-69 Coal -1,250 Mt. Storm Units 1-3, Mt. Storm, W. Va ......................................................... . 1965-73 Coal 1,596 Chesapeake Units 1-4, Chesapeake, Va ....... ,................................................. .. 1953-62 Coal* 595 Possum Point Units 3 & 4, Dumfries, Va ....................................................... . 1955-62 Coal 322 Yorktown Units 1* & 2, Yorktown, Va .................. :..................................... :.. .. 1957~59 Coal 326 Possum Point Units 1, 2, & 5, Dumfries, Va ..............*.................. '. .. ;; ........... . 1948-75 Oil 929 ..
Yorktown Unit 3, Yorktown, Va ................................. .-................................... .. 1974 Oil & Gas 818 .
Combustion Turbines:
35 units (8 locations) ..................................................... ,..................................... . .1967-90 Oil & Gas 1,019 Combined Cycle:
- Chesterfield. Units 7 & 8, Chester, Va ........................................................... ;.;.. . 1990~92 Oil & Gas 397 Total fossil stations .. :............... :.............................. ;.... ;.................................... . *7,479 Hydroelectric:
Gaston Units 1-4, Roanoke Rapids, N.C .......... ;......... :............................. :.: ...... .. 1963 Conventional 225 Roanoke Rapids Units 1-4, Roanoke Rapids, N.C ............................................. . 1955 Conventional* 96 Other ..................................................................................................................... . 1930-87 Conventional 3 Bath County Units 1-6, Warm Springs, Va ................................._....................... .. 1985 Pumped Storage 1,260(b)
To.ta! hydro stations_; ........................................................................................... . _ 1,584
. Total Company generating unit capability'.'.._.. ~ ........................ '. ...... ~ ................ . 12,412 Net Utility Purchases .............................................................................................. . 930 Non-Utility Generation '
. 2,867 Total Capability ............................ :.........*., ................................................... ;.... . 16,209 (a) Includes an undivided interest of 11.6 percent (207 Mw) owned by Old Dominion Electric Cooperative (ODEC).
(b) Reflects the Company's 60 percent undivided ownership interest in the 2,100 Mw station. A 40 percent undivided i~ter-est 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 W!!S 13,366 Mw on July 29, 1993, and the highest one-hour integrated winter peak demand was 14,877 Mw on January 19, 1994. See Winter Peak under REGULATION. . , . .
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 fuef cost of energy supply, see Results of Operations under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Nuclear Operations and Fuel Supply In 1993, the Company's four nuclear units achieved a combined capacity factor of 77.1 percent. _
The North Anna Unit 2 steam generator replacement project is scheduled to begin in 1996 at an estimated cost of $134 million.
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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 genera-tion requirements. The Company continually evaluates worldwide market conditions in order to obtain adequate nuclear fuel supply. Current agreements, inventories and market conditions will support planned fuel cycles throughout the remainder of the 1990s.
On-site spent nuclear fuel storage at the Surry Power Station is adequate for the Company's needs through 1998 when, in accordance with the Nuclear Waste Policy Act, the DOE is to begin acceptance of spent fuel for disposal. Should accept-ance be delayed, incremental dry storage facilities will be added under the existing storage license. North Anna Power Station will require an interim spent fuel storage facility in the late 1990's.
For details regarding nuclear insurance and certain related contingent liabilities as well as a NRC rule that requires proceeds from certain insurance policies to be used first to pay stabilization and decontamination expenses, see Note C to FINANCIAL STATEMENTS.
Fossil Fuel Supply The Company's fossil fuel mix consists of coal, oil and natural gas. In 1993, Virginia Power consumed approximately 10.7 million tons of coal. As with nuclear fuel, the Company utilizes both long-term contracts and spot purchases to support its needs. The Company presently anticipates that sufficient coal supplies at reasonable prices will be available for the remainder of the 1990s. Current projections for the adequate supply of oil remain favorable, barring unusual international events or extreme weather conditions which could affect both price and supply.
The Company uses natural gas as needed throughout the year for two combined cycle units and at several combustion turbine units. For winter usage at the combined cycle sites, gas is purchased and stored during the summer and fall and consumed during the colder months when gas supplies are not available at favorable prices. The Company has firm transpor-tation contracts for the delivery of gas to the combined cycle units. Current projections for gas indicate supplies will be available for the next several years.
Purchases and Sales of Power Virginia Power relies on purchases of power to meet a portion of its capacity requirements. The Company also makes economy purchases of power from other utility systems when it is available at a cost lower than the Company's own genera-tion costs.
Under contracts effective January 1, 1985, Virginia Power agreed to purchase 400 Mw of electricity annually through 1999 from Hoosier Energy Rural Electric Cooperative, Inc., and agreed to purchase 500 Mw of electricity annually during 1987-99 from certain operating subsidiaries of American Electric Power Company, Inc. (AEP).
On September 9, 1991, the Company and South Carolina Public Service Authority (SCPSA) signed an agreement whereby the Company will sell limited-term power to SCPSA during nine months in 1993 and nine months in 1994. The capacity purchased by SCPSA ranged from 50 Mw to 75 Mw in 1993 and will range 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 April 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 April 1996) or December 31, 1996, whichever occurs first.
The Company has a diversity exchange agreement with APS under which APS delivers 200 Mw to Virginia Power in the summer and Virginia Power delivers 200 Mw to APS in the winter.
Virginia Power also has 77 non-utility power purchase contracts with a combined dependable summer capacity of 3,561 Mw. Of this amount, 2,867 Mw were operational at the end of 1993 with the balance scheduled to come on-line through 1997 (see Non-Utility Generation under FUTURE SOURCES OF POWER and Note M to FINANCIAL STATEMENTS).
INTERCONNECTIONS The Company maintains major interconnections with CP&L, AEP, APS and the utilities in the Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission network, the Company has arrangements with these utilities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy.
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e On March 23, 1990, the Company and Appalachian Power Company (Apco) (an operating unit of AEP) announced an agreement to increase the ability to exchange electricity between the two companies through the construction of major transmis-sion facilities. The proposed construction will consist of 212 miles of new transmission lines and related substation improve-ments. The transmission additions will include 116 miles of 765 K v line to be constructed by Apco and 102 miles of 500 Kv line to be constructed by the Company. Completion of the project will ta1ce three to four years after all final regulatory approvals have been obtained. A Hearing Examiner of the Virginia Commission has issued reports dated December 2, 1993 and January 24, 1994 recommending Commission approval of the Apco and Company lines, respectively, and both applications are before the Commission for final decision. About 79 miles of the Apco line would be located in West Virginia where regulatory approval must also be obtained. The Company has stated that it would not build its 500 Kv line unless Apco is authorized to build its 765 Kv line and unless certain other regional transmission facilities are constructed or the Company's contractual rights to use the regional transmission network are amended.
FUT~ESOURCESOFPOWER The Company presently anticipates that system load growth will require approximately 1,618 Mw of additional capacity during the 1990s. The Company has and will pursue capacity acquisition plans to provide that capacity and maintain a high degree of service reliability. This capacity. may be built, owned and operated by others and sold to the Company under a competitive bid process pursuant to Commission rules or may be built by the Company if it determines it can build capacity at a lower overall cost. The Company also pursues conservation and demand-side management (see CONSERVATION AND LOAD MANAGEMENT below).
In May 1990, the Company entered into an agreement with ODEC, under which the Company purchased a 50 percent undivided ownership interest in a 782 Mw coal-fired power station to be constructed near Clover, Virginia in Halifax County.
The Company will operate the Clover Power Station after it is completed. The cost of the Company's 50 percent ownership interest is expected to be approximately $533 million. The project is on schedule and the Company's share of costs incurred through December 31, 1993 amounted to $377 million. Construction on Unit 1 is presently 69% complete and construction on Unit 2 is 33% complete.
In Virginia Power's proceeding seeking approval of the Virginia Commission for a 75 mile 500 Kv transmission line from the Clover Power Station to the Carson Substation in Dinwiddie County, Virginia, hearings were held before a Hearing Examiner on September 30, 1993. The Hearing Examiner issued a report recommending Commission approval of the line.
The matter is now before the Commission for approval.
The Company's continuing program to meet future capacity requirements is summarized in the following table:
Company Owned Generation Summer Capability Expected Name of Units Mw In-Service Date Clover Power Station:
Unit 1 391* April 1995 Unit 2 391* April 1996
- Includes the 50 percent undivided ownership interest of ODEC. See Note E to FINANCIAL STATEMENTS.
Non-Utility Generation Number of Projects Mw Projects Operational 61 2,867 Projects Financed 8 475 Unfinanced Projects 8 219 Total Contracts 77 3,561 COMPETITION Competition is playing an increasingly important role in the Company's business both in terms of source of power supply available to the Company and alternative choices for customers meeting their energy needs. Both forms of competition have 7
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- increased as a ftlSUlt of changing federal and state governmental regulations, technological developments, rising costs of con-structing generating facilities and availability of alternative energy sources (see Competition under MANAGEMENT'S DIS-CUSSION AND ANALYSIS OF FINANCIAL CONDIDON AND RESULTS OF OPERATIONS). The creation of exempt wholesale generators by the Energy Act and their existence in the market for electric sales may have an impact on the Com-pany's plans for the construction or purchase of electric capacity and energy. In addition, the Energy Act gives FERC broad power to require utilities to provide transmission access to others. Exempt wholesale generators an.d other power suppliers may seek, and- FERC may require, access to the transmission systems of investor~owned utilities, including the Company.
Several of the Company's industrial customers are seeking means of reducing their expenses for power through self-
. generation and other alternatives .. The Company is h.aving discu~.sion~ with these customers and has propqsed a regulatory initiative in Virginia that would enable it to provide on-site generation for such customers (see Virginia under RATES);
CON~ERVATION AND LOAD MANAGEMENT
_The Comp&ny is committed to. leas.t-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. Demand-side programs are selected annually at Virginia Power through a least-cost integrated resource planning pro-cess which -directly compares the stream of costs and benefits from supply-side and demand-side options. This process ensures the ultimate selection of a demand-side package which .reduces th.e need for additional capacity while efficiently using the Company's existing generation facilities.
- On June 28,, 1993, the Virginia Commissionissued its Finai Order iil a proceeding to consider the appropriate bene-fit/cost tests to be conducted in evaluating conservation and load management programs. The rules adopted by the-Virginia Commission are generally consistent with the position taken by the Company in that proceeding.,
The Company's least-cost planrµ~g pro~ess was the subject of a North* C~olina Commission hearing that concluded on December s; 1992. Prior to the hearing; the Company entered into a stipulation with the North Carolina Public Staff that defines the objectives of least-cost planning and activities necessary to accomplish those objectives. On June 29, 1993, the North Carolina Commission issued its Final Order approving the Company's latest least-cost integrated resources planning process; The Commission concluded that the Company's least-cost integrated resources planning process is in compliance
. with Commission rules. The Commission also approved a stipulation between the Company and the North* Carolina Public Staff regarding conservation and load management cost recovery (including recovery of deferred conservation and load man-agement costs) and incentives for demonstrated,consezy\ition and lmid management acc.omplishments.
ITEM 2. PROPERTIES The Company owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that a
do not interfere materially with their use. Substantially all of its property is subject to the lien of mortgage securing its First and Refunding Mortgage Bonds. Right-of-way grants from the apparent owners of real estate have been obtained for most electric lines, but underlying titles have not been examined except for transmission lines of 69 Kv or more. Where rights of way have not been obtained, they could be acquired from private owners by condemnation if necessary. Many electric lines are on publicly owned property as to which permission for use is generally revocable. Portions of the Company's transmis-
. sion lines cross national parks 'and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line if any exists.
The Company leases certain buildings and. equipment. See Note 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 aggi;egate liability for fmes or penalties will not exceed $100,000. There are no material agency enforcement actions ordtizen suits pending or, to the Company's present knowledge, threatened against the Company.
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e ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of the Company's Common Stock is owned by Dominion Resources.
During 1993 and 1992, the Company paid quarterly cash dividends on its Common Stock as follows:
1st 2nd 3rd 4th (Millions) 1993 ................................................ $93.3 $93.9 $94.5 $97.2 1992 ................................................ $90.5 $91.5 $92.2 $95.6 ITEM 6. SELECTED FINANCIAL DATA 1993 1992 1991 1990 1989 (Millions, except percentages)
Operating revenues ................................. .. $4,187.3 $3,679.6 $3,688.1 $3,461.5 $3,458.9 Operating income ................................... .. 813.4 761.6 816.8 805.8 759.0 Income before cumulative effect of a change in accounting principle ........... . 509.0 455.2 487.4 450.3 435.5 Cumulative effect of a change in accounting principle 14.3 Net income ............................................... . 509.0 469.5 487.4 450.3 435.5 Balance available for Common Stock .... . 466.9 423.8 435.9 392.2 375.2 Total assets ............................................... . 11,520.5 11,316.7 10,205.0 10,105.4 10,085.5 Total net utility plant.. ............................. . 9,459.0 9,254.7 9,064.6 8,830.8 8,497.9 Long-term debt, noncurrent capital lease obligations and preferred stock subject to mandatory redemption ......................... . 4,151.1 4,089.5 4,119.9 4,146.8 4,331.0 Utility plant expenditures (including nuclear fuel) ...................... .. 712.8 716.5 727.8 803.4 904.8 Capitalization ratios (percent):
Debt ...................................................... . 46.4 46.3 47.4 49.1 51.1 Preferred stock ..................................... . 9.2 9.7 9.0 9.4 9.9 Common equity .................................. .. 44.4 44.0 43.6 41:~ 39.0 Embedded cost (percent):
Long-term debt ................................... .. 7.67 7.86 8.43 8.80 8.86 Preferred stock .................................... .. 4.88 5.38 6.54 7.40 7.75 Weighted average ................................ . 7.18 7.42 8.11 8.57 8.67 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Liquidity and Capital Resources Cash flow from operating activities has accounted for, on average, 73 percent of the Company's cash requirements over the past three years.
Net cash provided by operating activities decreased by $152.1 million in 1993 as compared to 1992, primarily as a result of the rate refund of $188.9 million in 1993 offset in part by the recovery of previously deferred capacity expenses. Cash flow from operating activities was affected by a number of factors resulting from normal operations.
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Virginia Power is involved in an arbitration with Smith Cogeneration of Virginia, Inc. (SCV) before the Virginia Commis-sion concerning the terms of the purchase of power from two 158 megawatt generating units to be developed by SCV. Pursuant to directions from the Arbitrator, the parties have filed a list of unresolved issues, the separate draft contracts that each party proposes, and a memorandum stating that party's position with respect to each unresolved issue.
Virginia Power and Doswell Limited Partnership (Doswell) have been unable to agree on the calculation of a Fixed Fuel Transportation Charge to be paid to Doswell under a purchase power contract. Dosweli filed suit in the Circuit Court of the City of Richmond alleging breach of contract and actual and constructive fraud and seeking damages of not less than $75 million. The case has been set for trial beginning April 25, 1994. If this proceeding results in increased costs, the Company expects to treat such costs in a manner consistent with other fixed costs relating to purchased power contracts.
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e e Net cash provided by operating activities increased $146.4 million in 1992 as compared to 1991. Among other factors, cash flow was affected by an increase in the pro~ision. for *rate refunds* offset in part by the impact of capacity expense deferrals. .
Cash from (to) financing activities was as follows:
I 1993 1992 1991.
I (Millions)
- common Stock ... :............ :.............. :............... :...... ;..... :....... :.. ** $ 50.0 $ 75.0 $
- 1so.o
- Preferred stock ..... *............................. :......... :...............*.'......... . 150.0 240.0 Mortgage bonds ................ ~ ................. ;............ :............... :.... . 1,035.0 1,125.0 100.0 Medium-term notes ............................. ,................................. . 60.0 199.4 Tax-exempt securities ..... :.............................. :........: ............. . 56.0 Repayment of long-term ,debt and preferred stock .......... ;.; .. ' (1,072.1) * '(1,315.0) (410.4)
Dividends ..*.. :..............................*........ :;: .*. :: ... :.;: .... '.;.*........... (421.1) * (416.1) (397,1)
Other ....................... :........................ ,.:..... :... :....................... :.; (89.8) ,,(154.3) * (0.6)
Total ... :............ '. ............. :.......... ,.......... :............... :'..'.,.. :... : $ (348.0) $- '(329.4) $ (358.7)
As a result of favorable market conditions during 1993, the Company sold $ LO billion of First and Refunding Mortgage Bonds. With a portion of the proceeds, the Company redeemed $725 million of its higher-cost debt. The remainder of the .
proceeds was useq to meet a portion. of the Company's capital requirements. These .transactions, among oth~r factors, had the effect of lowering the Company's embedded cost of debt from 7.86 perce~t in 1992 to 7.67 percent in1993.
In 1993, the Company also issued $150 million of preferred stock with annual dividend rates ranging from $5.58 fo
$7.05 per share. With the proceeds from these sales, the Company redeemed $143.4 million of higher-cost preferred stock having annual dividend rates ranging from $7.325 to $7.72 per share.
In 1993, the *company issued to Dominion Resources $So' million of Comm.on Stock.
- During the year, the Company retired $153.0 million of securities through mandatory debt maturities and sinking fund requirements and $16.3 million through optional sinking fund requirements: In addition, the Company repurchas~d $34.4 miilion of its securities. * *
- Proceeds from the sale of commercial paper are primarily used to finance working capital for operations. Borrowings under the Company's commercial paper program are limited to $200 million outstanding at any one time of which $43.0 million were outstanding at December 31, 1993.
In January 1994, the Company issued $19.5 million of Pollution Control Revenue Bonds, Town of Louisa, with an interest rate of 5.45 percent, the proceeds of which were used to refund all of the outstanding 1976 Pollution Control R~venue.
Bonds, Town of Louisa. The Company also sold $125 million of First and Refunding Mortgage Bonds, 7 percent, the pro-ceeds of which were used to redeem $119 million of 1989 Series A, 9.75 percent, First' and Refunding Mortgage Bonds.
These bonds were not reclassified as securities due within one year at December 31, 1993, as the Company received the proceeds from refinancings in January 1994.
- Cash from (used in) investing activities was as follows:
1993 1992 1991 (Millions)
Utiiity *plant* expenditures.:; ..............: .................. :.... :.. :.. :..... . $ (644.9) $ (662.2) $ (663.7)
Nuclear fuel ........ :................................................................. . (67.9) . (54.3) (64.1)
Nuclear decommissioning contributions .............................. . (24.4) . (24.3) (18.5)
Pollution control project funds .......................... :................. ; 32.7 (55.3) 1.0 Sale of .accounts receivable ......................................... ,......... . 50.0 Other*...... :.: ............................................ *.... **.: .. *.................. .. . - , (13.9) (5.5) . 27.2 Total ...... ; *........... *...... *.... *.......... *............................ -..., .. -.... . $ (718.4) . $ (801.6) . $ (668.1)
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e Investing activities in 1993 resulted in a net cash outflow of $718.4 million primarily due to $644.9 million of construc-tion expenditures and $67.9 million of nuclear fuel expenditures. Of the construction expenditures, approximately $75.4 million was spent on new generating facilities, $244.0 million on other production projects, and $273.9 million on transmis-sion and distribution projects.
Capital Requirements The Company presently anticipates that kilowatt-hour sales will grow approximately 2.0 percent a year through 2012.
Capacity needed to support this growth will be provided through a combination of Company-constructed generating units and purchases from non-utility generators. Each of these options plays an important role in the Company's overall plan to meet capacity needs.
The Company's construction and nuclear fuel expenditures (excluding AFC), during 1994, 1995 and 1996 are expected to aggregate $691 million, $684 million and $686 million, respectively. Construction continues on the 782 Mw coal-fired power station near Clover, Virginia, of which the Company has a 50 percent undivided ownership interest. The Company's share of the cost of the construction is approximately $533 million of which $377 million had been incurred as of Decem-ber 31, 1993. The expected in-service dates for Clover Units 1 and 2 are April 1995 and April 1996, respectively. After 1996, no base load generation is expected to be needed until the middle of the next decade. From 1999 until 2003, the Company will need to add only peaking units to meet anticipated demand.
The Company will require $165.0 million to meet long-term debt maturities and $2.3 million for sinking fund payments in 1994. The Company presently estimates that, for 1994, 47 percent of its construction expenditures, including nuclear fuel expenditures, will be met through cash flow from operations and the balance, including other capital requirements, will be obtained through a combination of sales of securities and short-term borrowings.
Results of Operations The following is a discussion of results of operations for the years ended 1993 as compared to 1992, and 1992 as compared to 1991.
1993 Compared to 1992 Operating revenues changed principally due to the following:
Increase (Decrease) From Prior Year 1993 1992 (Millions)
Kwh sales ...................................... . $333.5 $ 53.5 Change in base rates ..................... . 230.7 (37.8)
Fuel cost recovery .............. :......... .. (55.2) (20.4)
Other, net ....................................... . ___Q_l) _QJ)
Total ........................................... . $507.7 $ (8.5)
As detailed in the chart above, the increase in revenues is primarily due to increased kilowatt-hour sales and an increase in base rates.
Base revenues were higher in 1993 primarily as a result of an increase in base rates, net of reserves for revenue subject to refund, effective October 27, 1992, and the refund in 1992 of $22.7 million in the Virginia 1990 rate case resulting from the Virginia Supreme Court ruling.
Fuel cost recovery decreased due to reductions in fuel revenues effective October 1992.
During 1993, the Company had 43,014 new connections to its system compared to 39,807 and 40,643 in 1992 and 1991, respectively. The increase in new connections in 1993 reflects the recovery from the economic recession of the past few years in the Company's service territory.
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e e Customer kilowatt-hour sales changed as follows:
Increase (Decrease) From Prior Year 1993 1992 Residential ..................................... . 9.3% (1.8)%
Commercial. ................................... . 4.7 1.1 Industrial ........................................ . 4.5 1.5 Public authorities ... :....................... . 5.3 0.6 Total retail sales ............................ . 6.4 0.1 Resale ............................................. . 47.3 20.5 Total sales ...................................... . 9.6 1.0 The increase in kilowatt-hour sales reflects the warmer than nonnal summer weather in 1993 as compared to the moder-ate weather in 1992. The number of actual cooling degree days in 1993 was 10.0 percent above the number of normal cooling degree days and the number of actual heating degree days was 1.2 percent above the number of normal heating degree days.
The decrease in residential sales in 1992 as compared to 1991 reflects the moderate weather in 1992. The summer of 1992 was the coolest in the last twenty years. The number of actual cooling degree days in 1992 was 19 percent below the number of normal cooling degree days and the actual number of heating degree days was 1.8 percent above the number of normal heating degree days.
The increase in sales for resale in 1993 as compared to 1992 was primarily due to the sale of firm capacity and associ-ated energy to ODEC. Under the tenns of the agreement signed November 26, 1992, the Company is committed to sell up to 300 Mw of capacity to ODEC through the commercial operation date of Clover Power Station. Additional capacity became available during 1992 due to lower than anticipated retail sales resulting from moderate weather. The Company was able to sell a portion of this capacity which resulted in increased sales for resale as compared to 1991.
The average fuel cost of system energy output is shown below:
Mills Per Kilowatt-hour 1993 1992 1991 Nuclear ............................................
- 4.60 4.67 5.69 Coal ................................................ . 14.69 14.87 15.00 Oil .................................................. . 26.55 26.61 31.20 Purchased power, net .................... . 24.54 25.94 25.38 Other .............................................. . 24.35 24.45 16.46 Average fuel cost........................... . 14.42 13.84 13.93 System energy output is shown below:
Estimated Actual 1994 1993 1992 1991 Nuclear(*) ....................................... . 29% 31% 35% 36%
Coal. ................................................ . 42 39 41 41 Oil ................................................... . 2 3 2 3 Purchased power, net.. .................. .. 24 23 19 18 Other ............................................... . 3 4 3 2 100% 100% 100% 100%
(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power Station (see Note E to FINANCIAL STATEMENTS).
Fuel used in current generation, purchased power expenses-fuel and purchased power expenses-capacity increased as compared to 1992 as a result of higher sales in 1993 and a decrease in nuclear generation due to the scheduled outages in 1993. The increased sales together with the reduced generation from the nuclear units increased the use of purchased power and resulted in higher overall fuel costs.
Deferred expenses-fuel decreased primarily as a result of refunds of previously over-collected fuel expenses.
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- Deferred expenses-capacity resulted in an increase in 1993. In 1992, the Company implemented deferral accounting for certain capacity expenses. The increase in expense reflects the recovery of previously deferred capacity expenses.
Operation expenses-other increased as compared to 1992 primarily as a result of the increased expenses associated with other postretirement benefits due to the implementation of Statement of Financial Accounting Standards (SPAS) No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions" effective January l, 1993.
Income taxes-operating increased as compared to 1992 primarily as a result of increased pretax book income and an increase in the federal income tax rate from 34 percent to 35 percent.
Miscellaneous, net and other interest charges decreased as compared to 1992 primarily as a result of a reclassification for the imputed interest on the nuclear decommissioning obligation recognized to date which was previously included in Other Interest Charges ($14.8 million) and is now included in Miscellaneous, net, as approved by FERC. This increase is
.offset in part by a $3.1 million decrease in expenses associated with the sale of accounts receivable.
Cumulative Effect of a Change in Accounting Principle In 1992, the Company adopted the provisions of SPAS No. 109, "Accounting for Income Taxes." The Company reported the implementation of the standard as a change in accounting principle with the cumulative effect on prior years of
$14.3 million reported in 1992 earnings. The adoption of SPAS No. 109 in 1992 increased deferred income tax liabilities by
$459 million and resulted in the establishment of a net regulatory asset of $459 million. For additional information, see Note A to FINANCIAL STATEMENTS.
1992 Compared to 1991 Operating revenues were $8.4 million lower as compared to 1991 primarily as a result of the refund of $22.7 million in 1992 in the Virginia 1990 rate case resulting from the Virginia Supreme Court ruling and reductions in fuel revenues effective .
September 1991 and October 1992. These decreases were partially offset by an increase in unit sales.
Purchased power expenses-fuel and purchased power expenses-capacity increased as compared to 1991 primarily due to an increase in NUG purchases. Fifty-two projects, with a summer capability of 2,833 Mw were operational at Decem-ber 31, 1992 as compared to forty-two projects, with a summer capability of 1,312 Mw, operational as of December 31, 1991.
Deferred expenses-fuel decreased as compared to 1991 primarily as a result of a lower recovery of fuel expenses subject to deferral accounting in 1992 as compared to 1991.
Deferred expenses-capacity resulted in a decrease to expense as a result of the establishment of a regulatory asset of
$102.7 million due to the implementation of deferral accounting for certain capacity expenses.
Miscellaneous-net decreased as compared to 1991 primarily as a result of the reclassification of costs associated with the sale of accounts receivable ($7.6 million) from other operation expense.
Interest on long-term debt decreased as compared to 1991 primarily as a result of the redemption of certain debt, which was replaced by lower cost debt as well as lower interest rates on variable rate debt.
Future Issues Accounting Standards In November 1992, FASB issued SPAS No. 112, "Employers' Accounting for Postemployment Benefits", effective for fiscal years beginning after December 31, 1993. SPAS No. 112 requires employers who provide benefits to former or inactive employees after employment but before retirement to recognize the liability for these benefits on an accrual basis rather than as paid.
In May 1993, FASB issued two pronouncements, SPAS No. 114, "Accounting By Creditors for Impairment of a Loan,"
and SPAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities."
SPAS No. 114 amends SPAS No. 5, "Accounting for Contingencies" to clarify that a creditor should evaluate the collec-tibility of both contractual interest and contractual principal of all receivables when assessing the need for loss accrual. The Statement must be implemented effective January 1, 1995.
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SFAS No. 115 addresses the accounting and reporting for investments in equity securities that have readily determinable fair values and for all investments in debt securities. The Statement is effective for fiscal years beginning after December 31, 1993.
In June 1993, FASB issued SFAS No. 116, "Accounting for Contributions Received and Contributions Made," effective January 1, 1995. The Statement is aimed primarily at not-for-profit organizations; however, it applies to contributions made by all entities. It prescribes the accounting for contributions including: unconditional promises to give; conditional promises to give; and restricted contributions.
At this time, the Company does not expect the implementation of SFAS No. 112, No. 114, No. 115 or No. 116 to have a material impact on its results of operations and financial condition.
Utility Rate Regulation Regulatory policy continues to be of fundamental importance to the Company and to its financial performance.
Recently and in the near-term future, the costs of purchased capacity constitute the largest category of increased costs requiring rate relief. The Virginia Commission has authorized rates providing for the current recovery of the ongoing level of capacity payments. Moreover, the Virginia Commission has established and reaffirmed deferral accounting that is intended to ensure dollar for dollar recovery of reasonably incurred capacity costs. Rates approved in the Company's 1992 rate case will eliminate a previously existing balance of deferred capacity costs.
The Company's earnings continue to be subject to attrition due to ratemaking practices that fix rates based on a past test year, with certain modifications. A proceeding is pending in Virginia that would set new ratemaking procedures. The pro-posed rules would clarify the Virginia Commission's greater flexibility to use forward-looking adjustments and to set suspen-sion periods up to a maximum of 150 days.
For additional information on the current rate proceedings, see Rates under Item 1. BUSINESS.
Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. T,hese laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemaking process; how-ever, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely impacted.
Water Quality Compliance On March 30, 1992, the Virginia Water Control Board adopted water quality standards for toxic pollutants pursuant to the Clean Water Act. The standards became effective on April 20, 1992. The Company is studying the potential impact of the standards and cannot presently determine whether or to what extent changes to facilities or operating procedures might ultimately be required but incremental compliance costs could be significant.
Environmental Protection and Monitoring Expenditures The Company incurred $72.2 million, $65.2 million and $72.0 million, (including depreciation) during 1993, 1992 and 1991, respectively, in connection with the use of environmental protection facilities and expects these expenses to be approx-imately $69.6 million in 1994. In addition, capital expenditures to limit or monitor hazardous substances were $3.6 million,
$6.6 million and $73.1 million for 1993, 1992 and 1991, respectively. The amount estimated for 1994 for these expenditures is $75.1 million. '
Clean Air Act Compliance The Air Act, as amended in 1990, requires the Company to reduce its emissions of sulfur dioxide and nitrogen oxides in two phases, beginning in 1995. The sulfur dioxide reduction program is based on the issuance of a limited number of sulfur
. dioxide emission allowances, each of which may be used as a permit to emit one ton of sulfur dioxide into the atmosphere or may be sold to someone else. The program will be administered by the EPA.
The Company is assessing the economic reasonableness of acquiring additional allowances as a means to maintaining compliance with the Air Act's standards.
For additional information on the Clean Air Act, see Regulation under Item 1. BUSINESS.
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1J; Electromagnetic Fields The possibility that exposure to electromagnetic fields emanating from power lines, household appliances and other electric sources may result in adverse health effects has been a subject of increased public, governmental and media attention.
A considerable amount of scientific research has been conducted on this topic without definitive results. Research is continu-ing to resolve scientific uncertainties. It is too soon to tell what, if any, impact these actions may have on the Company's financial condition.
Nuclear Operations In 1993, the Company's four nuclear units operated at a combined capacity factor of 77.1 percent, reflecting a 96 day steam generator replacement project at North Anna Unit 1 and scheduled refueling outages at North Anna Units 1 and 2 and Surry Unit 2. Refueling outages typically occur every eighteen months and last for approximately sixty days. The Company's goal is to reduce refueling outages from an average of sixty days to forty-eight days. When nuclear units are refueled, the Company replaces the power from nuclear generation with other more expensive sources. A reduction in the length of the outage should result in increased availability of low-cost nuclear generation, thereby lowering expenses. Three refueling outages are currently scheduled for 1994. The Surry Unit 1 and Unit 2 refuelings will include ten-year, In-Service Inspec-tions, while North Anna Unit 1 will have a normal refueling. See Nuclear Operations and Fuel Supply, Sources of Energy Used and Fuel Costs under Item 1. BUSINESS.
Stress corrosion cracking has occurred in steam generators of a certain design, including those at the Surry and North Anna Power Stations. The steam generators at Surry Units 1 and 2 were replaced in 1981 and 1979, respectively. The replacement of the steam generators at North Anna Unit 1 commenced January 4, 1993 and was completed on April 10, 1993. The cost of replacing the steam generators was $106 million, $20 million under budget. The replacement of the North Anna Unit 2 steam generators is scheduled for 1996 at an estimated cost of $134 million. Costs associated with the steam generator replacements at Surry are being recovered through rates. Costs associated with the steam generator replacements at North Anna Unit 1 are expected to be recovered through rates.
The NRC is currently revising the nuclear power plant license renewal rule it issued in 1991 because it has proved unworkable. The Company has proposed the extension of licenses for five years at a time as opposed to a 20-year renewal.
The Company does not oppose 20-year renewal, but suggests that a five year renewal period may provide a simpler and less costly application and review process. The Company intends to work with industry groups on any life extension endeavor.
For information on nuclear decommissioning, see Note C to FINANCIAL STATEMENTS.
Conservation and Load Management For information, see Conservation and Load Management under Item 1. BUSINESS.
Competition The Company will continue to be affected by the developing competitive market in wholesale power. Under the Energy Policy Act of 1992, any participant in the wholesale market can obtain a FERC order of transmission services, under certain conditions.
FERC has instituted an industry-wide formal inquiry aimed at reforming the pricing of transmission services. The Com-pany is an active participant in that inquiry. FERC is also encouraging the development of regional transmission groups (RTGs) in which transmission-owning utilities and transmission users would jointly coordinate and administer the provision of transmission services. It is too early to determine what effects reformed transmission pricing and the development of RTGs could have on the Company.
At present, competition for retail customers is quite limited. It arises primarily from the ability of certain business customers to relocate among utility service territories, to substitute other energy sources for electric power and to generate their own electricity. The Energy Policy Act bans federal orders of transmission service to retail customers. Thus, broader retail competition that would allow customers to choose among electric suppliers would require drastic changes in traditional state utility law and regulation. If they occur, those complex and difficult changes have the potential to shift costs among customer classes and to create significant transitional costs. Certain state actions to foster retail competition may be pre-empted by federal law.
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Potential competition also exists for the Company's sales to its cooperative and municipal customers. However, nearly all of this service is under contracts with multi-year notice provisions. To date, the Company has not experienced any mate-rial loss of load, revenues or net income due to competition for its customers. The Company believes it has a strong capabil-ity to meet future competition.
Commitments and Contingencies For information on commitments and contingencies, see Note M to FINANCIAL STATEMENTS.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX Page No.
Report of Management...................................................................................................................................... 19 Report of Independent Auditors ........................................................................................................... :...... ;:... 20 Statements of Income for the years ended December 31, 1993,- 1992 and 1991 ....... *........................... ;....... 21 Balance Sheets at December 31, 1993 and 1992 ............................................................................................ 22 Statements of Earnings Reinvested in Business for the years ended December 31, 1993, 1992 and 1991.. ....... _ 24 Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991................................... 25 Notes to Financial Statements .......................................................................................................................... 26 Financial Statement Schedules:
IV - Indebtedness of and to Related Parties Not Current for the years ended December 31, 1993, 1992 and 1991..................................................................................................................................... 40 V -Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991 ............ 41 VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991....................................................................... 44 IX-Short-term Borrowings for the years ended December 31, 1993, 1992 and 1991.......................... 45 X- Supplementary Income Statement Information for the years ended December 31, 1993, 1992 and 1991.* ........................................... *.............................................-.................................................. 46 Schedules other than those listed above have been omitted since they are not required, are inapplicable or are unneces-sary due to the presentation of the required information in the financial statements or notes thereto.
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e e REPORT OF MANAGEMENT The Company's management is responsible for all information and representations contained in the Financial State-ments and other sections of the Company's annual report on Form 10-K. The Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the Form 10-K is consistent with that in the Financial Statements.
Management maintains a system of internal accounting controls designed to provide reasonable assurance, at a reason-able cost, that the Company's assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control and, therefore cannot provide absolute assurance that the objectives of the 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. Manage-ment believes that during 1993 the system of internal control was adequate to accomplish the intended objective.
The Financial Statements have been midited 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 are not materially misleading and do not contain material errors.
The Audit Committee of the Board of Directors, composed entirely of directors who are not officers or employees of the Company, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, inter-nal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. Both the independent auditors and the internal auditors periodically* meet alone with the Audit Committee and have free access to the Committee at any time.
Management recognizes its responsibility for fostering a strong ethical climate so that the Company's affairs are con-ducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Company's Code of Ethics, which is distributed throughout the Company. The Code of Ethics addresses, among other things, the importance of ensuring open communication within the Company; potential conflicts of interest; compliance with all domestic and foreign laws, including those relating to financial disclosure; the confidentiality of proprietary information; and full disclosure of public information.
VIRGINIA ELECTRIC AND POWER COMPANY J. T. Rhodes B. D. Johnson President and Senior Vice President-Finance, Chief Executive Controller, Treasurer and Officer Corporate Secretary 19
- 1 e 'i REPORT OFINDEPENDENT AUDITORS To the Board of Directors of Virgini& 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, 1993 and 1992 and for each of the three years in the period ended December 31, 1993 listed in the index on page 18. Our audits also included the financial statement schedules listed in the index on page 18. These financial statements and the financial statement schedules are the responsibility of the Com-pany's management. Our responsibility is to express an opinion on these financial statements and financial statement sched-ules 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 evalu-ating 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 Elec-tric and Power Company at December 31, 1993 and 1992 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 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 showh therein.
The Company changed its methods of accounting for postretirement benefits other than pensions in 1993 (see Note L) and for accounting for income taxes in 1992 (see Note B) in order to conform with recently issued accounting standards.
DELOITTE & TOUCHE Richmond, Virginia February 7, 1994 20
1*
- *.t:.
VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF INCOME For the Years Ended December 31, 1993, 1992 1991 (Millions)
Operating revenues;, *.';.*,;.,, .* .- ... :.... .-............................................... ;._._.... , $4,187.3 $3,679.6 $3,688.1 Operating expenses:
Operation:
Fuel used in cui;-rent generation ................ _..................-:*: ..... ;.."... :.. 610.9 558.2 584.8 Purchased power expenses - fuel. ................................. ::........ .. 384.7 314.5 281.1
_;_:__'capacity ......... :...... :............... :..... . 573.3 451.5 266.1 Deferred expenses - fuel: .. :............. :.......................... :*: ......... '. .. (36.1) 45.2 61.1
- capacity ........ .-................... :.................-..... . 72.8 (102.7)
Other ............................................................... *...... *.... *............ -.. . 525.7 477.7 482.9 Maintenance ..... :...................... :... *............._....*................ .- ..... .-........... .-; 2795 - -280.6
- 304.7 Depreciation and amortization ..................... :.............................*... .. 426.8 399.9 39,?.5 Amortization of terminated construction project costs .................; 36.1 37.7 45.8 Taxes - Income ...................... ~ .............................. :...................... .. 253.5 222.2 222.3
- Other ........................ *........................................*................ _* 246.7 233.2 227.0 Total ....._._ ......................... _........-............. _........... _.................. .. 3,37~.9 2,918.0 2,871.3 Operating income-............... .'............. :.......... ;....................-..'................ . 813.4 ,761.6 816.8 Other income:-
- Allowance for other funds used during construction: .._.... ,... ~ ..... 1.~ .... . 5.,1. 4,8 8.2 Miscellaneous, net ................................. _.........................._: ..:...... :.. :... _ 10.0 17.9 33.2 Income taxes -as_sociated with miscellaneous, net ........ :.: ..... ;....... .. (3.7) .{3.4) ,(11.0)
Total ......... ;................................................................................. .. 1L4 19.3 30.4
. Income before interest charges'.:: ....... ;.......................................*.... . 824.8 780.9 847.2 Interest charges:
Interest on long-term debt ... .-...................................._...................... . 300.2 . 300.9 335.6 Other ............... -* ....................... -............................. *........................ . 19.1 29.5 27.8 Allowance for borrowe_d funds used during construction ............ . ,' (3.5) (4.7) (3.6)
Total ...... .- ............ :................................................................... . 315.8 325.7 359.8 lnco~e. before cumulative effe~t of a change in accounting _
pnnc1ple ..................................................... *.................... -....... _....... _ . 509.0 455.2 487.4 Cumulative effect on prior years of changing method of ,
- accounting for income taxes ............................. ."........................... .. 14.3 Net income ............................... .-.. .-;.-.. _.......................... ;....................... .. 509.0 . 469.5 487.4 Preferred dividends ...... _.._. .......... ,....................... .-................................. . 42.1 45.7 51.5 Balance available for Common Stock .............................................. .. $ 466.9 .$ 423.8 $ 435.9 The accompanying notes are an integral part of the financial statements.
21
'a/
1,
/.
VIRGINIA ELECTRIC AND POWER COMPANY BALANCE SHEETS Assets At December 31, 1993 1992 (Millions)
UTILITY PLANT:
Plant (includes plant under construction of $913.1 in 1993 and $840.9 in 1992) ................................................................................................. . $13,376.1 $12,930.6 Less accumulated depreciation* ................................................................ . 4,065.9 3,837.6 9,310.2 9,093.0 Nuclear fuel (less accumulated amortization of $665.3 in 1993 *and
$592.9 in 1992) ................................................................... :............... .. 148.8 161.7 Total net utility plant. ........................................................................ . 9,459.0 9,254.7 INVESTMENTS:
Nuclear decommissioning trust funds .............................................. ;...... . 226.4 185.8 Pollution control project funds ................................................................ . 27.2 59.9 Other ........................................................ .'................................................ . 21.5 22.6 Total net investments ............................ ;........................................... . 275.1 268.3 CURRENT ASSETS:
Cash and cash equivalents ....................................................................... . 21.6 65.1 Customer accounts receivable (less allowance for doubtful accounts of $1.7 in 1993 and 1992) ................................................................... . 202.9 181.3 Accrued unbilled revenues ...................... :.: .............................................. . 105.7 87.4 Materials and supplies at average cost or less:
Plant and general ...... :....................... :................................................... . 182.0 180.7 Fossil fuel ............................................................................................. . 121.0 149.8 Other ......................................................................................................... . 112.2 69.1 Total current assets ........................................................................... . 745.4 733.4 DEFERRED DEBITS AND OTHER ASSETS:
Regulatory assets:
Income taxes recoverable through rates .............................................. . 497.7 459.0 Deferred capacity expenses ......................................................... .'........ . 29.8 102.7 Terminated construction project costs (less accumulated amortization of $356.0 in 1993 and $319.9 in 1992) .................... . 153.3 178.6 Other ...............................................................................................*...... 146.1 149.0 Unamortized debt issuance costs ....................................................... :..... . 127.3 86.7 Other ......................................................................................................... . 86.8 84.3 Total deferred debits and other assets ............................................. . 1,041.0 1,060.3 Total assets ........................................................................................ . $11,520.5 $11',316.7 The accompanying notes are an integral part of the financial statements.
22
J '
VIRGINIA ELECTRIC AND POWER COMPANY e
BALANCE SHEETS Capitalization and Liabilities At December 31, 1993 1992
(\\fillions)
LONG-TERM DEBT ................................................................................... . $ 3,899.9 $ 3,800.2 PREFERRED STOCK:
- Preferred stock subject to mandatory redemption ................................. ;. 224.0 260.2 Preferred stock not subject to mandatory redemption ............................ . 594.0 569.0 COMMON STOCKHOLDER'S EQUITY:
Common Stock, no par 300,000 shares authorized, 168,277 shares outstanding at December 31, 1993 and 166,109 at December 31, 1992................................ :...................................................................... . . 2,662.4 2,612.4 Other paid-in capital. ................................................................................ . 20.3 22.0 Earnings reinvested in business ....................................... :................. :..... . 1,269.3 1,182.7 Total common stockholder's equity ................................................. . 3,952.0 3,817.1 CURRENT LIABILITIES:
Securities due within one year ................................................................ . 167.3 153.0 Short-term debt ......................................................................................... . 43.0 49.5 Accounts payable, trade ........................................................................... . 297.2 278.8 Customer deposits .................................................................................... . 53.9 52.3 Payrolls accrued ........................................................................................ . 68.3 57.1 Provision for rate refunds ........................................................................ . 101.7 189.3 Interest accrued ......................................................................................... . 101.7 108.2 Other ......................................................................................................... . 86.0 52.3 Total current liabilities ................ ,.................................................... . 919.1 940.5 DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes ....................................................... .. 1,449.7 1,382.7 Deferred investment tax credits ............................................................... . 306.3 325.5 Deferred fuel expenses ............................................................................. . 54.1 90.2 Other ......................................................................................................... . 121.4 131.3 Total deferred credits and other liabilities ...................................... . 1,931.5 1,929.7 COMMITMENTS AND CONTINGENCIES (See Note M)
Total capitalization and liabilities ................................................... .. $11,520.5 $11,316.7 The accompanying notes are an integral part of the financial statements.
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VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF EARNINGS REINVESTED IN BUSINESS For the Years Ended December 31, 1993 1992 1991 (Millions)
Balance at beginning of year .......................................... . $1,182.7 $1,132.9 $1,043.8 Net income ....................................................................... . 509.0 469.5 487.4 Total ..................................................................... . 1,691.7 1,602.4 1,531.2 Cash dividends:
Preferred stock subject to mandatory redemption ..... . 17.2 . 22.4 24.2 Preferred stock not subject to mandatory redemption ... . 25.0 23.9 26.0 Common Stock .. :......................................................... . 378.9 369.8 346.9 Total dividends .................................................... . 421.1 416.1 397.1 Other deductions, net ...................................................... . 1.3 3.6 1.2 Balance at end of year .................................................... . $1,269.3 $1,182.7 $1,132.9 The accompanying notes are an integral part of the financial statements.
24
J
- VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993 1992 1991 (Millions)
Cash Flow From Operating Activities:
Net income ...................................................................................................................... . $ 509.0 $ 469.5 $ 487.4 Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of change in method of accounting for income taxes ........... . (14.3)
Depreciation and amortization ............................................................................... . 546.6 547.9 544.3 Allowance for other funds used during construction ........................................... . (5.1) (4.8) (8.2)
Deferred income taxes ........................................................................................... . (6.7) 105.1 (1.6)
Deferred investment tax credits .............................................................................. * (19.2) (19.4) (18.8)
Noncash return of terminated construction project costs-pretax .......................... . (11.9) (13.7) (19.2)
Deferred fuel expenses, net. ................................................................................... . (36.1) 45.2 61.1 Deferred capacity expenses .................................................................................... . 72.9 (102.7)
Changes in:
Accounts receivable ............................................................................................ . (33.6) (34.1) (0.8)
Accrued unbilled revenues ................................................................................. . (6.3) 2.8 (14.4)
Materials and supplies ........................................................................................ . 27.5 (33.8) 48.0 Accounts payable, trade ..................................................................................... . 18.4 79.2 (43.2)
Accrued expenses ............................................................................................... . 28.2 (26.7) 9.8 Provision for rate refunds .................................................................................. . (87.6) 161.9 (12.5)
Other ....................................................................................................................... . 26.8 12.9 (3.3)
Net Cash Flow From Operating Activities ...................... _. ................................................ . 1,022.9 1,175.0 1,028.6 Cash Flow From (To) Financing Activities:
Issuance of Common Stock ..................,. ........................................................................ . 50.0 75.0 150.0 Issuance of preferred stock ............................................................................................ . 150.0 240.0 Issuance of long-term debt. .... .'................................... , ................................................... . 1,035.0 1,241.0 299.4 Repayment of short-term debt ....................................................................................... . (6.5) (55.4) (13.7)
Inter-company credit agreement .................................................................................... . (32.5) 32.5 Repayment of long-term debt and preferred stock ....................................................... . (1,072.1) (1,315.0) (410.4)
Common Stock dividend payments ............................................................................... . (378.9) (369.8) (346.9)
Preferred stock dividend payments ................................................................................ . (42.2) (46.3) (50.2)
Other ........................................................................................................~ ...................... . (83.3) (66.4) (19.4)
Net Cash Flow (To) Financing Activities ......................................................................... . (348.0) (329.4) (358.7)
Cash Flow From (Used in) Investing Activities:
Utility plant expenditures (excluding AFC-other funds) .............................................. . (644.9) (662.2) (663.7)
Nuclear fuel (excluding AFC-other funds) ................................................................... . (68.1) (54.3) (64.1)
Pollution control project funds ...................................................................................... . 32.7 (55.3) 1.0 Nuclear decommissioning contributions ........................................................................ . (24.4) (24.3) (18.5)
Sale of accounts receivable ............................................................................................ . 50.0 Other ................................................................. :............................................................. . (13.7) (5.5) 27.2 Net Cash Flow (Used in) Investing Activities .................................................................. . (718.4) (801.6) (668.1)
Increase (Decrease) in cash and cash equivalents ............................................................ . (43.5) 44.0 1.8 Cash and cash equivalents at beginning of year .............................................................. . 65.1 21.1 19.3 Cash and cash equivalents at end of year ......................................................................... . $ 21.6 $ 65.1 $ 21.1 Cash paid during the year for:
Interest (reduced for the cost of borrowed funds capitalized as AFC) ....................... . $ 324.8 $ 325.3 $ 376.8 Income taxes ................................................................................................................... . 268.1 163.8 255.8 The accompanying notes are an integral part of the financial statements.
25
VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO FINANCIAL STATEMENTS A. Significant Accounting Policies:
General The Company's accounting practices are generally prescribed by the Uniform System of Accounts promulgated by the regulatory commissions having jurisdiction and are in accordance with generally accepted accounting principles applicable to regulated enterprises.
The Company is a wholly-owned subsidiary of Dominion Resources, Inc., a Virginia corporation:
Revenues Operating revenues are recorded on the basis of service rendered.
Property, Plant and Equipment Utility plant is recorded at original cost which includes labor, materials, services, AFC, where permitted by regulators, and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense and clearing accounts. The cost of additions and replacements is charged to the appropriate utility plant account, except that the cost of minor additions and replacements, as provided in the Uniform System of Accounts, is charged to maintenance expense.
Depreciation and Amortization Depreciation of utility plant (other than nuclear fuel) is computed on the straight-line method based on projected useful service lives. The cost of depreciable utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation. The provision for depreciation is based on weighted average depreciable plant using a rate of 3.2 percent for 1993, 1992 and 1991.
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.
In 1993, the Company changed the classification of spent nuclear fuel. Prior to 1993, spent nuclear fuel was not retired until transfer of title to a third party. The spent nuclear fuel will be retired after a five-year cooling period. The effect of this reclassification resulted in a decrease of $191.9 million in nuclear fuel and nuclear fuel accumulated amortization as of January 1, 1992. Prior period financial statements have been restated to reflect this change.
Federal Income Taxes The Company adopted SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109) in 1992. This standard requires companies to measure and record deferred tax assets and liabilities for all temporary differences. Temporary differences occur when events and transactions recognized for financial reporting result in taxable or tax-deductible amounts in future periods. The regulatory treatment of temporary differences can differ from the requirements of SFAS No. 109. Accordingly, the Company recognizes a regulatory asset if it is probable that future revenues will be provided for the payment of those deferred tax liabilities. Similarly, in the event a deferred tax liability is reduced to reflect changes in tax rates, a regulatory liability is established if it is probable that a future reduction in revenue will result. Prior to 1992, the Company recorded deferred taxes for timing differences between book income and taxable income to the extent such differences were permitted
_by regulatory commissions for ratemaking purposes.
The Company files a consolidated federal income tax return with Dominion Resources.
Accumulated investment tax credits are being amortized over the service lives of the property giving rise to such credits.
Allowance for Funds Used During Construction The applicable regulatory Uniform System of Accounts defines AFC as the cost during the construction period of bor-rowed funds used for construction purposes and a reasonable rate on other funds when so used.
26
'J e e The pretax AFC rates for 1993 and 1992 were 9.4 and 10.3 percent, respectively. An AFC rate, net-of-tax, of 9.1 percent was used for 1991. Approximately 88 percent of the Company's CWIP is now included in rate base, and a cash return is collected currently thereon.
Deferred Capacity In 1992, the Company began to defer certain capacity expenses based on an order of the Virginia Commission. Approxi-mately 80 percent of capacity expenses are subject to deferral accounting. The difference between reasonably incurred actual expenses and the level of expenses included in current rates is deferred and matched against future revenues.
Deferred Fuel Approximately 90 percent of fuel expenses are subject to deferral accounting. The difference between actual fuel expenses and the level of fuel expenses included in current rates is deferred and matched against future revenues.
Amortization of Debt Issuance Costs The Company defers and amortizes any expenses incurred in the issuance of long-term debt including premiums and discounts associated with such debt over the lives of the respective issues. Any costs resulting from the refinancing of debt
- are also deferred and amortized over the lives of the new issues of long-term debt as permitted by the appropriate regulatory jurisdictions.
Cash and Other Investments Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 1993 and 1992, the Company's accounts payable included the net effect of checks outstanding but not yet presented for payment of $72.5 million and $60.3 million, respectively. For purposes of the Statement of Cash Flows, the Company considers cash and cash equivalents to include cash on hand and temporary investments purchased with an initial maturity of three months or less. **
- Reclassification Certain amounts in the 1992 and 1991 financial statements have been reclassified to conform to the 1993 presentation.
27
e ,*
B. Income Taxes:
Details of income tax expense are as follows:
Years 1993 1992 1991 (Millions)
Current expense:
Federal. ............................................................................................ . $ 283.0 $ 142.9 $ 244.1 State ................................................................................................ .. (0.3) 3.0 4.2 282.7 145.9 248.3 Deferred expense:
Plant related items:
Liberalized depreciation ............................................................ .. 48.3 55.9 44.4 Indirect construction costs ......................................................... . (23.2) (12.6) (13.4)
Cost of removal-property retirements ....................................... .. 9.3 5.4 8.8 Other ........................................................................................... . 10.6 4.6 3.1 Deferred fuel .................................................................................. .. 11.8 (15.4) (20.8)
Deferred capacity ........................................................................... .. (24.7) 34.9 Debt issuance costs ........................................................................ . 8.3 15.4 1.5 Customer accounts reserve ............................................................. . (34.9) 7.5 5.0 Terminated construction project costs ........................................... . (7.7) (7.9) (10.1)
Other ............................................................................................... . (7.8) 7.9 (25.7)
(10.0) 95.7 (7.2)
Net deferred investment tax credits-amortization ............................ .. (19.2) (19.4) (18.8)
Income tax expense-operating income ..................... ,....................... .. 253.5 222.2 222.3 Income tax expense associated with nonoperating income:
Current expense:
Federal. ..... ;........... :......................................................................... .. (0.2) (6.1) 5.2 State ................................................................................................. . 0.1 0.2 (0.2) (6.0) 5.4 Deferred expense ............................................................................... .. 3.9 9.4 5.6 Income tax expense-nonoperating income ....................................... .. 3.7 3.4 11.0 Total income tax expense ................................................................... . $ 257.2 $ 225.6 $ 233.3 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 1993 1992 1991 (Millions, except percentages)
Federal income tax expense at statutory rate of 35%
(34% in 1992 and 1991)(1) ......................................... $ 266.5 $ 230.4 $ 243.5 Increases (decreases) resulting from:
Utility plant differences(2) ........................................... (6.2) 4.6 11.3 Ratable amortization of investment tax credits ........... (16.1) (15.2) (16.5)
Terminated construction project costs(2) .... :................ 5.2 5.0 8.2 Other, net ...................................................................... 3.0 (2.2) (17.6)
(14.1) (7.8) (14.6)
Total federal income tax expense .................................... $ 252.4 $ 222.6 $ 228.9 Effective tax rate .............................................................. 33.1% 32.8% 31.9%
(1) The Omnibus Budget Reconciliation Act of 1993 increased the corporate income tax rate to 35 percent effective January 1, 1993.
(2) 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.
28
Virginia) for each of its four licensed reactors not to exceed $10.3 million (including a 3 percent insurance premium tax for Virginia) per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.
Nuclear liability coverage for claims made by nuclear workers first hired on or after January 1, 1988, except those arising out of an extraordinary nuclear occurrence, is provided under the Master Worker insurance program. (Those first hired into the nuclear industry prior to January 1, 1988 are covered by the policy discussed above.) The aggregate limit of coverage for the industry is $400 million ($200 million policy limit with automatic reinstatements of an additional $200 million). The Company's maximum retrospective assessment is approximately $12.8 million (including a 3 percent insurance premium tax for Virginia).
The Company's current level of property insurance coverage ($2.625 billion for North Anna and $2.58 billion for Surry) exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The property insurance coverage is provided through several different policies. Under two of these policies, the Company is subject to retrospective premium assessments, in any policy year in which losses exceed the funds available to these insurance companies. The maximum assessment at the first incident of the current policy period is $36.3 million and the maximum assessment related to a second incident is an additional $13.4 million. Based on the severity of the incident, the Board of Directors of the Company's nuclear insurers has the discretion to lower the maximum retrospective premium assessment or eliminate either or both completely. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination, the Company has the financial responsibility for these losses.
The Company purchases insurance from Nuclear Electric Insurance Limited (NEIL) to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Virginia Power is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL.
The current policy period's maximum assessment is $9.6 million.
As part owner of the North Anna Power Station, ODEC is responsible for its proportionate share (11.6 percent) of the insurance premiums applicable to that station, including any retrospective premium assessments and any losses not covered by insurance.
D. Sale of Receivables:
The Company has an agreement to sell, with limited recourse, certain accounts receivable including unbilled amounts, up to a maximum of $200 million. Additional receivables are continually sold, at the Company's discretion, to replace those collected up to the limit. At December 31, 1993 and 1992, $200 million of such receivables had been sold and were outstand-ing under this agreement. The limited recourse is provided by the Company's assignment of an additional undivided interest in accounts receivable to cover any potential losses to the purchaser due to uncollectible accounts. The Company has pro-vided for the estimated amount of such losses in its accounts.
E. Jointly Owned Plants:
The following information relates to the Company's proportionate share of jointly owned plants at December 31, 1993:
North Bath County Anna Clover Pumped Storage Power Power Station Station Station Ownership interest .................................................................... . 60.0% 88.4% 50.0%
(Millions)
Utility plant in service ............................................................ .. $1,072.7 $1,754.4 Accumulated depreciation ........................................................ . 153.2 562.5 Nuclear fuel .............................................................................. . 447.5 Accumulated amortization of nuclear fuel ................ ,............ .. 407.0 Construction work in progress* ................................................. . 1.1 101.8 $376.6 30
In 1992, the Company adopted the provisions of SFAS No. 109. The Company reported the implementation of the standard as a change in accounting principle with the cumulative effect on prior years of $14.3 million reported in 1992 earnings. The adoption of SFAS No. 109 increased deferred income tax liabilities by $459 million and resulted in the estab-lishment of a net regulatory asset of $459 million. For additional information see Federal Income Taxes under Note A to FINANCIAL STATEMENTS.
The Company's accumulated deferred income taxes consists of the.following:
Years 1993 1992 (Millions)
Depreciation method and plant basis differences ...................................... .. $ 897.4 $ 856.6 Income taxes recoverable through rates ...................................................... . 497.8 459.0 Terminated construction project costs ........................................................ .. 27.6 31.7 Other ............................................................................................................. . 26.9 35.4 Accumulated deferred income taxes ........... ,................................................ . $1,449.7 $1,382.7 C. Nuclear Operations:
Decommissioning Nuclear plant decommissioning costs are accrued and recovered through rates over the expected service lives of the Company's nuclear generating units. The amounts collected from customers are being placed in trusts, which, with the accu-mulated earnings thereon, will be utilized solely to fund future decommissioning obligations.
Approximately every four years, site-specific studies are prepared to determine the decommissioning cost estimate for the Company's four nuclear units. The current cost estimate is based on the DECON method, which assumes the decontami-nation or prompt removal of radioactive contaminants so that the property may be released for unrestricted use shortly after cessation of operations. The Company currently estimates that decommissioning will begin at the expiration date of each unit's operating license, which will occur in 2012, 2013, 2018 and 2020 for the Surry Units 1 & 2 and North Anna Units 1 &
2, respectively. Based on the Company's latest decommissioning study completed in 1990, total decommissioning costs, including reclamation costs, are estimated to be $1 billion in 1993 dollars.
The accumulated provision for decommissioning of $226.4 million and $185.8 million is included in Utility Plant Accu-mulated Depreciation at December 31, 1993 and 1992, respectively. Provisions for decommissioning of $24.4 million, $24.3 million and $18.5 million applicable to 1993, 1992 and 1991, respectively, are included in Depreciation and Amortization Expense. The balance in the Company's Nuclear Decommissioning Trust Funds was $226.4 million and $185.8 million at December 31, 1993 and 1992, respectively.
Earnings of the trust funds were $16.3 million, $9.1 million and $8.4 million for 1993, 1992 and 1991, respectively, and are included in Other Income, Miscellaneous, Net in the Company's Statements of Income. Beginning in 1993, the accretion of the accumulated provision for decommissioning, equal to the earnings of the trust funds, is recorded in Other Income, Miscellaneous, Net. See Miscellaneous, net under Results of Operations, Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Such amounts in 1992 and 1991 were recorded in Interest Charges, Other.
The Energy Act required domestic utilities with nuclear facilities to fund the clean-up of the DOE's gaseous diffusion plants which have provided nuclear enrichment services to the industry. In December 1992, the Company recorded a liability and corresponding regulatory asset of $90 million for its portion of the clean-up. During 1993, the Company paid $6.3 million of its liability. The Company will pay approximately $13 million in 1994. The Company is presently recovering these costs through fuel rates in all jurisdictions.
Insurance The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $9.4 billion for a single nuclear incident. The Price-Anderson Amendments Act of 1988 allows for an inflationary provision adjustment every five years. The Company has purchased $200 million of coverage from the commercial insurance pools with the remainder pro-vided through a mandatory industry risk sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $81.7 million (including a 3 percent insurance premium tax for 29
(
e 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, maintenance, 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 recov-ery of the incurred costs. The amounts deferred are being amortized over a 15-year period for Virginia and FERC jurisdic-tional customers. The net cost incurred was $387.6 million. At December 31, 1993, the net unamortized balance was $125.7 million.
G. Leases:
Plant and property under capital leases included the following:
1993 1992 I",
(Millions)
Office buildings (*) ...................................................................................... . $35.7 $40.8 Data processing equipment ......................................................................... .. 6.9 5.7 Total plant and property under capital leases ................................ .. 42.6 46.5 Less accumulated amortization .................................................................... . 12.8 14.9 Net plant and property under capital leases ................................................ . $29.8 $31.6
(*) The Company leases its principal office building from its parent, Dominion Resources. The capitalized cost of the prop-erty under that lease, net of accumulated amortization, represented $26.0 million and $26.9 million at December 31, 1993 and, 1992, respectively. Rental payments for such lease were $3.0 million for each of the three years ended December 31, 1993, 1992 and 1991.
The Company is responsible for expenses in connection with the leases noted above, including maintenance.
Future minimum lease payments under noncancellable capital leases and for operating leases that have initial or remain-ing lease terms in excess of one year as of December 31, 1993, are as follows:
Capital Operating Leases Leases (Millions) 1994............................................................................................................... . $ 4.9 $ 5.2 1995 ............................................................................................................... . 4.4 4.2 1996 ............................................................................................................... . 3.5 3.9 1997 ............................................................................................................... . 3.5 3.1 1998 ............................................................................................................... . 3.1 3.0 After 1998 ..................................................................................................... . 28.7 35:0 Total future minimum lease payments .................................... :.................. .. 48.1 $54.4 Less interest element included above .......................................................... .
-18.3 Present value of future minimum lease payments ...................................... . $29.8 Rents on leases, which have been charged to other operation expenses, were $11.2 million, $10.6 million and $12.8 million for 1993, 1992 and 1991, respectively.
t,...,,'
31
e ' .
H. Long-term Debt:
Long-term debt included. the following:
At December 31, 1993 1992 (Millions)
First and Refunding Mortgage Bonds (1):
Series R, 4.375%, due 1993 ..................................... .' ..................................................... . $ 30.0 Series S, 4.5o/o, due 1993 ................................................................................................. . 30.0 1987 Series B, 9.375%, due 1994 ................................................................................... . $ 100.0 100.0 1992 Series A, 6.375%, due 1995 ................................................................................... . 180.0 180.0 Series T, 4.5%; due 1995 ................................................................................................. . 56.6 56.6 1981 Series B, 15.75%, due 1996 ............................................................................. :..... . 8.0 Series* U~ 5.125%, due 1997 .................................................................................... *........ . 49.3 49.3 Series V, 6.875%, due 1997 ............................................................................................ . 50.0 1992 Series B, 7.25%, due 1997 ..................................................................................... . 250.0 250.0 1988 Series A, 9.375%, due 1998 ................................................................................... . 150.0 150.0 1992 Series F, 6.25%, due 1998 ..................................................................................... . 75.0 75.0 Various series, 5.875-8.875%, due 1999-2003 ................................................................ . 790.0 580.0 Various series, 6.75%-8%, due 2004-2008 ........................................ :............................ . 484.5 484.7
. Various series, 8.5%, due 2014-2018 ....................................................................*.......... 150;0 Various series, 6.75%-9.75%, due 2019-2023 ................................................................ . 719.0 445.0 Total first and refunding mortgage bonds ................................ ,.............................. . 2,854.4 2,638.6 Other long-term debt:
Bank loans, notes and term loans:
Fixed interest rate, 7.39%-10.8%, due 1993-2003 ...................................................... . 770.8 847.1 Pollution control financings (2):
Fixed interest rate, 5.625%, due 2002 ............................................................................. . 19.5 20.0 Money Market Municipals, due 2008-2027(3) ............................................................... . 444.6 444.6 Total other long-term debt ................ :...................................................................... . 1,234.9 1,311.7 4,089.3 3,950.3 Less amounts due within one year:
First and Refunding Mortgage Bonds ............................................................................. . 100.0 60.0 Bank loans, notes and term loans .................................................................................... . 65.0 76.0 Sinking fund obligations .................................................................................................. . 0.8 0.7 Total amount due within one year ........................................................................... . 165.8 136.7 Less unamortized discount, net of premium ....................................................................... . 23.6 13.4 Total long-term debt ................................................................................................. . $3,899.9 $3,800.2 (1) Substantially all of the Company's property is subject to the lien of its mortgage, securing its First and Refunding Mortgage Bonds.
(2) Certain pollution control facilities at the Company's generating facilities have been pledged or conveyed to secure the financings.
(3) Interest rates vary based on short-term, tax-exempt market rates. Pollution control bonds subject to remarketing within one year are classified as long-term debt to the extent that the Company's intention to maintain the debt is supported by long-term bank commitments.
In January 1994, the Company issued $19.5 million of Pollution Control Revenue Bonds, Town of Louisa, with an interest rate of 5.45 percent, the proceeds of which were used to refund all of the outstanding 1976 Pollution Control Revenue Bonds, Town of Louisa. The Company also sold $125 million of First and Refunding Mortgage Bonds, 7 percent, the pro-ceeds of which were used to redeem $119 million of 1989 Series A, 9.75 percent, First and Refunding Mortgage Bonds.
32
( JI
- These bonds were not reclassified as securities due within one year at December 31, 1993, as the Company received the proceeds from refinancings in January 1994.
Under the terms of an Inter-Company Credit Agreement, the Company may borrow funds from Dominion Resources on a daily basis and repay all or part of the loan at any time. Borrowings under the Agreement are limited to $300 million outstanding at one time, less amounts outstanding under the commercial paper program. At December 31, 1992, there were no amounts outstanding under the Agreement and no amounts were borrowed during 1993.
With a portion of the proceeds from the sale of $200 million First and Refunding Mortgage Bonds of 1993, Series G, the Company irrevocably placed in a trust $138.2 million to defease $119.1 million 1990 Series A Bonds. As a result, the 1990 Series A Bonds were considered to be extinguished for financial reporting purposes and were excluded from the balance sheet at December 31, 1993. The cost of $19.1 million was deferred consistent with the Company's policy for other refunding costs. The Company will amortize the cost over the life of the new issue.
Maturities through 1998 are as follows (millions): 1994-$165.8; 1995-$313.0; 1996-$170.3; 199:7-$312.0; and 1998-$294.3.
I. Preferred Stock Subject to Mandatory Redemption:
Preferred stock subject to mandatory_redemption, $100 liquidation preference, at December 31, 1993, was as follows:
Annual Sinking Fund Requirements Entitled Per Share Upon Redemption at $100 Per Share Issued and And Thereafter to Outstanding Amounts Declining Dividend Shares Amount In Steps To Shares
$5.58 .................. . 400,000 (a) (b) 6.35 .................. . 1,400,000 (a) (c) 7.30...........*....... . 455,000 $106.57 4/14/94 $100.00 after 4/14/02 15,000 2,255,000 Less shares due within one year ............... .. 15,000 Total .................. . 2,240,000 (a) Shares are non-callable prior to redemption.
(b) All shares to be redeemed on 3/1/2000.
(c) All shares to be redeemed on 9/1/2000.
Maturities. are $1.5 million for each of the years 1994-1998.
During the years 1991 through 1993, the following shares were redeemed:
Year Dividend Shares 1993 .............................................................. . $7.30 30,000 1993 .............................................................. . 7.58 480,000 1993 .............................................................. . 7.325 400,419 1992 .............................................................. . 8.20 330,000 1992 .............................................................. . 8.40 512,000 1992 .............................................................. . 8.60, 228,764 1992 .............................................................. . 8.625 203,500 1992 ............................................................. .. 8.925 164,500 1991 .............................................................. . 10.25 50,000 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.
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J. Preferred Stock Not Subject to Mandatory Redemption:
Preferred stock not subject to mandatory redemption, $100 liquidation preference, at December 31, 1993, was as follows:
Entitled Per Share Upon Liquidation Issued and And Thereafter to Outstanding Amounts Declining Dividend Shares Amount Through In Steps To
$5.00 ............................................................................................ . 106,677 $112.50 4.04............................................................................................ . 12,926 102.27 4.20 ............................................................................................ . 14,797 102.50 4.12 ............................................................................................ . 32,534 103.73 4.80 ............................................................................................ . 73,206 101.00 7.45 ............ :............................................................................... . 400,000 101.00 7.20 ............................................................................................ . 450,000 101.00 7.05 ............................................................................................ . 500,000 105.00 07/31/03 $100.00 after 7/31/13 6.98 ............................................................................................ . 600,000 105.00 08/31/03 $100.00 after 8/31/13 MMP 1/87 (*) ............................................................................. . 500,000 100.00 MMP 6/87 (*) ............................................................................. . 750,000 100.00 MMP 10/88 (*) ........................................................................... . 750,000 100.00 MMP 6/89 (*) ............................................................................. . 750,000 100.00 MMP 9/92A (*) .......................................................................... . 500,000 100.00 MMP 9/92B (*) .......................................................................... . 500,000 100.00 Total............................................................................................. 5,940,140
(*) 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 1993, 1992 and 1991, including fees for broker/ dealer agreements, were 3.01 percent, 3.43 percent and 5.22 percent, respectively.
In 1993, 350,000 and 500,000 shares of the 7.72 and the 7.72(1972 Series) Dividend Preferred Stock, respectively, were redeemed.
K. Common Stock:
During the years 1991 through 1993 the following changes in Common Stock occurred:
Years 1993 1992 1991 Shares Shares Shares Outstanding Amount Outstanding Amount Outstanding Amount (Millions, except shares)
Balance at January 1 .............. . 166,109 $2,612.4 162,741 $2,549.1 156,049 $2,398.3 Transfer from (to) Other Paid-in Capital ............................ . (11.7) 0.8 Issuance to Dominion Resources ............................ . 2,168 50.0 3,368 75.0 6,692 150.0 Balance at December 31 ........ . 168,277 $2,662.4 166,109 $2,612.4 162,741 $2,549.1 L. Retirement Plan and Postretirement Benefits:
The Company participates in the Dominion Resources, Inc. Retirement Plan (the Retirement Plan), a defineci benefit pension plan. The Retirement Plan covers virtually all employees of Dominion Resources and its subsidiaries, including the Company. The benefits are based on years of service and average base compensation over the consecutive 60-month period in which pay is highest.
- Pension plan expenses were $15.9 million, $13.1 million and $10.8 million for 1993, 1992 and 1991, respectively and the amounts funded were $16.0 million, $12.3 million and $12.2 million in 1993, 1992 and 1991, respectively.
34
.. *l' e e In addition to providing pension benefits, Dominion Resources and the Company provide certain health care and life insurance benefits for retired employees. Health care benefits are provided to retirees who have completed at least ten years of service after obtaining age 45. These and similar benefits for active employees are provided through insurance companies.
Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
The Company adopted the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Account-ing for Postretirement Benefits Other Than Pensions" effective January 1, 1993. This standard requires the accrual of the cost of providing other postretirement benefits (OPEB), including medical and life insurance coverage, during the active service of the employee. Prior to 1993, the Company recognized expense on a pay-as-you-go basis. The Company recognized as expense $10.5 million and $8.5 million for these benefits in 1992 and 1991, respectively.
Net periodic postretirement benefit expense for 1993 was as follows:
Year Ending December 31, 1993 (Millions)
Service cost .............................................................................................................. . $ 9.7 Interest cost ...................... :....................................................................................... . 20.6 Return on plan assets ................................................................................ '. .............. . (2.0)
Amortization of transition obligation ...................................................................... . 12.0 Net amortization and deferral .................................................................................. . 0.7 Net periodic postretirement benefit expense ........................................................... . $41.0 The following table sets forth the funded status of the plan:
At December 31, 1993 (Millions)
Fair value of plan assets ..................................................................... . $
- 28.4 Accumulated postretirement benefit obligation:
Retirees ............................................................................................ . $142.4 Active plan participants .................................................................. . 110.0 Accumulated postretirement benefit obligation ......................... . 252.4 Accumulated postretirement benefit obligation in excess of plan assets ................................................................................ . (224.0)
Unrecognized transition obligation ..................................................... . 229.0 Unrecognized net experience (gain)/loss ............................................ . (9.2)
Accrued postretirement benefit cost ................................................... . $ (4.2)
The discount rate used to determine the accumulated postretirement benefit obligation for 1993 was 7.75 percent.
A one percent increase in the health care cost trend rate would result in an 11 percent increase in net periodic postretire-ment benefit costs and the accumulated postretirement benefit obligation as of December 31, 1993.
The assumed return on plan assets is 9 percent. The medical cost trend rate is 11 percent for the first year, 10 percent in the second year, scaling down to an ultimate rate of 4.75 percent, beginning in the year 2001.
As of January 1, 1993, the Company is recovering these costs in rates on an accrual basis in all material respects, in all jurisdictions. Current and future rate recoveries of OPEB accruals are expected to collect sufficient amounts to provide for the unfunded accumulated postretirement obligation over time. The funds being collected for OPEB accruals in rates; in excess of OPEB benefits actually paid during the year, are contributed to external benefit trusts under the Company's current funding policy.
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.
35
Rate Matters For information on the principal rate proceedings in which the Company was involved in 1992 and 1993, see Rates under Item 1. BUSINESS.
For information on the effect of rate increases see Results of Operations under Item 7. MANAGEMENT's DISCUS-SION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Retrospective Premium Assessments Under several of the Company's nuclear insurance policies, the Company is subject to retrospective premium assess-ments in any policy year in which losses exceed the funds available to these insurance companies. For additional information, see Note C to FINANCIAL STATEMENTS.
Construction Program The Company has made substantial commitments in connection with its construction program and nuclear fuel expendi-tures. Those expenditures are estimated to total $691 million (excluding AFC) for 1994. Additional financing is contemplated in connection with this program. For more information see Capital Requirements under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Purchased Power. Contracts Since 1984, the Company has entered into contracts for the long-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. The Company has 77 non-utility purchase contracts with a combined dependable summer capacity of 3,561 Mw. Of these, 61 projects (aggregating 2,867 Mw) were operational as of the end of 1993 with the balance to become operational at various dates before 1997.
The table below reflects the Company's minimum commitments as of December 31, 1993, for power purchases from utility and non-utility suppliers that are currently operating or have obtained construction financing.
Commitment Year Capacity Other (Millions) 1994 ......... :.................................................... . $ 675.5 $ 200.5 1995 .............................................................. . 730.5 201.5 1996 .............................................................. . 742.4 206.4 1997 *************************************************************** 743.2 217.0 1998 *************************************************************** 746.6 216.8 Later years .................................................... . 11,789.7 3,341.0 Total .......................................................... . $15,427.9 $4,383.2 Present value of the total.. ........................... . $ 6,647.9 $1,689.8 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) for the years 1993, 1992 and 1991 were $958.0 million, $766.0 million and
$547.2 million, respectively.
Fuel Purchase Commitments The Company's estimated fuel purchase commitments for the next five years for system generation are as follows (millions): 1994-$344; 1995 -$219; 1996-$114; 1997 -$35 and 1998 - $18.
Sales of Power For information on the Company's commitment to sell power, see Purchases and Sales of Power under SOURCES OF ENERGY USED AND FUEL COSTS, Item 1. BUSINESS.
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<<.. 'l' e e Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. These laws and regulations can result in increased capital, operating and other costs as a result of remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemaking process; however, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely impacted.
For additional information on environmental matters, see Future Issues under Item 7. MANAGEMENT'S DISCUS-SION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Site Remediation The Company is actively involved as a potentially responsible party (PRP) at two sites as discussed below.
From 1972 to 1975, the Company's Surry Power Station generated low-level radiological waste that was sent to the Maxey Flats disposal site in Kentucky. The Company has been named one of approximately 800 PRPs with respect to the Maxey Flats Superfund Site. The estimated future remediation costs for the site are $86 million. Based on the Company's estimated share of the total volume of the waste at the site, the Company's total expenditure is expected to be approximately
$0.6 million.
The EPA has identified the Company and several other utilities as PRPs at a Superfund site in Philadelphia known as the Metal Bank Cottman Avenue site. Oil and PCB 's have leaked from tanks at the site into the ground and the adjacent river.
The utility companies involved have formed a PRP group and Virginia Power's share is 7.06 percent, based on an allocation formula applied to the PRP group. As of December 31, 1993, the remedial investigation and feasibility study had not been completed; therefore, a site-specific estimate of the total costs of the cleanup is not available. The current estimate of the total investigation costs is $1.1 million. The Company's share of the investigation costs would be approximately $80,000.
Based on a financial assessment of the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay the costs apportioned to them.
The Company and Dominion Resources along with Consolidated Natural Gas have remedial action responsibilities remaining at two coal tar sites. The Company has provided a $3.4 million reserve to meet its estimated minimum liability.
Based on site studies and investigations performed at these sites, the Company expects that its contribution will not exceed approximately $5 million.
The Company generally seeks to recover its costs associated with environmental remediation from third party insurers.
At December 31, 1993 any pending or possible claims were not recognized as an asset or offset against recorded obligations of the Company.
West Virginia Air Act For information see Regulation under Item 1. BUSINESS Litigation For information on the legal proceeding with Doswell see Item 3. LEGAL PROCEEDINGS.
N. Fair Value of Financial Instruments:
The Company used available market information and appropriate valuation methodologies to estimate the fair value of each class of financial instrument for which it is practicable to estimate fair value. These estimates are not necessarily indica-tive of the amounts the Company could realize in a market exchange. In addition, the use of different market assumptions may have a material effect on the estimated fair value amounts.
37
December 31, 1993 1992 Carrying Fair Carrying Fair Amount Value Amount Value (Millions)
Assets:
Cash and cash equivalents .................................................. . $ 21.6 $ 21.6 $ 65.1 $ 65.1 Nuclear decommissioning trust funds ................................. . 226.4 243.8 185.8 198.2 Pollution control project funds ........................................... .. 27.2 27.2 59.9 59.9 Liabilities and capitalization:
Short-term debt ....................................... :............................. . 43.0 43.0 49.5 49.5 Long-term debt:
First and refunding mortgage bonds ................................ . 2,854.4 2,996.0 2,638.6 2,726.1 Medium-term notes .......................................................... . 770.8 856.3 847.1 909.9 Pollution control bonds .. ;................................................. . 19.5 18.4 20.0 20.0 Money Market Municipal pollution control notes ......... .. 444.6 444.6 444.6 444.6 Preferred stock subject to mandatory redemption .............. . 225.5 251.8 276.5 301.9 Cash and cash equivalents, pollution control project funds and short-term debt: The carrying amount of these items approximates fair value because of their short maturity.
Nuclear decommissioning trust funds: The fair value is based. on available market information and generally is the average of bid and asked price.
First and refunding mortgage bonds and pollution control bonds: Fair value is based on market quotations.
Medium-term notes: These notes were valued by discounting the remaining cash flows at a rate estimated for each issue.
A yield curve rate was estimated to relate Treasury Bond rates for specific issues to the corresponding maturities.
Money market municipal pollution control notes: These notes have variable interest rates which are set so that fair value approximates carrying value.
Preferred stock subject to mandatory redemption: The. fair value was estimated by discounting the dividend and princi-pal payments for a representative issue of each series over the average remaining life of the series.
- 0. Quarterly Financial Data (unaudit~d):
The following amounts reflect all adjustments, consisting of only normal recurring accruals (except as discussed below),
necessary in the opinion of the management for a fair statement of the results for the interim periods.
Income Before Cumulative Effect Cumulative Effect of a Change of a Change Balance Available Operating Operating in Accounting in Accounting for Common Quarter Revenues Income Principle Principle Stock (Millions) 1993 1st ................................. $1,060.6 $194.4 $119.8 $108.8 2nd ................................ 950.8 175.9 101.4 90.9 3rd ................................ 1,212.1 271.7 193.9 183.3 4th ................................ 963.8 171.4 93.9 83.9 1992 1st ................................. $ 934.6 $194.5 $110.9 $14.3 $113.4 2nd................................ 851.8 144.7 68.2 56.7 3rd ................................ 1,052.3 232.5 155.8 144.4 4th ................................ 840.9 189.9 120.3 109.3 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.
In 1992, the Company adopted the provisions of SFAS No. 109. The Company reported the implementation of the standard as a change in accounting principle. The cumulative effect on prior years increased net income by $14.3 million.
Accordingly, first quarter results were restated to reflect this change.
38
- - *l' In the first quarter of 1992, the Company reserved approximately $34 million, in accordance with the Virginia 1990 rate case Virginia Supreme Court ruling, resulting in a decrease to Operating Income and Balance Available for Common Stock of
$22.7 million (net of associated taxes of $11.3 million). This reserve was adjusted in the second quarter to reflect actual refunds to customers of $26 million, including $3.3 million of interest.
In accordance with the Virginia Commission's December 1992 Final Order, the Company implemented deferral accounting and established a regulatory asset for certain capacity expenses, which had the impact of increasing Operating Income and Balance Available for Common Stock by $67.8 million (net of associated taxes of $34.9 million). This increase was offset, in part, by a reduction in revenues for a provision for refunds to be made in connection with the Virginia Commis-sion's December 1992 Final Order, which had the effect of decreasing operating revenues by $84.0 million, and decreasing operating income and Balance Available for Common Stock by $60.3 million (net of associated taxes of $31.0 million).
39
SCHEDULE IV VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE IV - INDEBTEDNESS OF AND TO RELATED PARTIES NOT CURRENT For the years ended December 31, 1993; 1992 and 1991 Col.A Col. B Col. C Col. D Col. E Col. F Col. G Col.H Col. I Indebtedness of Indebtedness to Balance at Balance at Balance at Balance at Name of Person Beginning Additions Deductions End Beginning Additions Deductions End (Millions)
Dominion Resources:
1993 .............................. .
1992.............................. . $32.5 $ 5.0 $ 37.5 1991 ............................. .. $709.0 $676.5 $32.5 Under the terms of an Inter-Company Credit Agreement, the Company may borrow funds from Dominion Resources on a daily basis and repay all or part of the loan any time. Borrowings under the Agreement are limited to $300 million outstand-ing at one time, less amounts outstanding under the commercial paper program. The weighted average interest rate for 1992 and 1991 was 5.06 percent and 5.81 percent, respectively. At December 31, 1992, there were no amounts outstanding under the Agreement and no amounts were borrowed during 1993.
40
'.t e VIRGINIA ELECTRIC AND POWER COMPANY
- SCHEDULE V SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1993 .
Col.A Col. B Col. C Col.D Col. E Col. F Other Balance at Changes Balance at Beginning Additions Retirements Add End of Classification of Period at Cost or Sales (Deduct) Period (Millions)
Utility plant:
In service:
Intangible ......................................................................... . $ 85.6 $ 14.9 $ 17.8 $ 82.7 Production .......................................................... :............. . 6,561.2 215.7 122.9 $5.0 6,659.0 Transmission .................................................................... . 1,184.4 74.1 10.2 0.1 1,248.4 Distribution ..................................................................... .. 3,582.0 222.3 43.3 3,761.0 General ............................................................................. . 594.1 49.3 17.4 (1.4) 624.6 Total plant in service ....................................................... . 12,007.3 576.3 211.6 3.7 12,375.7 Construction work in progress ........................................... .. 840.9 72.2(a) 913.1 Held for future use ............................................................. .. 39.6 1.7 0.6 3.8 44.5 Plant acquisition adjustment .............................................. .. 4i8 42.8 Total plant ........................................................................ . 12,930.6 650.2 212.2 7.5 13,376.1 Nuclear fuel ................................................................................. . 754.6 68.4 __!2(b) 814.1 Total utility plant ............................................................. . $13,685.2 $718.6 $221.1 $7.5 $14,190.2 Non-utility property ..................................................................... . $ 10.2 $0.1 $ 10.3 Capital leases ............................................................................... . $ 46.5 $ 5.8 $1.9 $ 42.6 (a) Includes additions of $648.5 million net of $576.3 million transferred to plant in service.
(b) For information on the re~ement of spent nuclear fuel, see Depreciation and Amortization under Note A to FINANCIAL STATEMENTS. .. .
41
e SCHEDULE V VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE V - PROPERTY, PLANT EQUIPMENT For the Year Ended December 31, 1992 Col. A Col. B Col. C. Col. D Col.E Col. F Other Balance at Changes Balance at Beginning Additions Retirements Add End of Classification of Period at Cost or Sales (Deduct) Period (Millions)
Utility plant:
In service:
Intangible ......................................................................... . $ 71.9 $ 23.5 $ 9.8 $ 85.6 Production ........................................................................ . 6,376.9 215.5 33.8 $ 2.6 6,561.2 Transmission .................................................................... . 1,128.8 56.2 1.2 0.6 1,184.4 Distribution ...................................................................... . 3,401.7 218.9 38.4 (0.2) 3,582.0 General ..................................... :....................................... . 586.7 38.7 30.6 (0.7) 594.1 Total plant in service ................................................... . 11,566.0 552.8 113.8 2.3 12,007.3 Construction work in progress ............................................ . 736.1 I04.8(a) 840.9 Held for future use .............................................................. . 41.0 (1.4) 39.6 Plant acquisition adjustment ............................................... . 42.8 42.8 Total plant ................................................ :....................... . 12,385.9 657.6 113.8 0.9 12,930.6 Nuclear fuel ................................................................................. . 766.4 54.6 66.4(b) 754.6 Total utility plant ............................................................. . $13,152.3 $712.2 $180.2 $ 0.9 $13,685.2 Non-utility property ..................................................................... . $ 8.5 $ 1.7 $ 10.2 Capital leases ............................................................................... . $ 46.5 $ 46.5 (a) Includes additions of $657.6 million net of $552.8 million transferred to plant in service.
(b) For information on the retirement of spent nucl~ar fuel, see Depreciation and Amortization under Note A to FINANCIAL STATEMENTS.
42
..... *.i'
- 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 at Beginning Additions Retirements Add End of Classification of Period at Cost or Sales (Deduct) Period (Millions)
Utility 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 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 Plant acquisition adjustment ............................................... . 42.8 42.8 Total plant ........................................................................ . 11,769.9 668.0 96.3 44.3 12,385.9 Nuclear fuel ................................................................................ .. 732.9 64.4 30.9(c) 766.4 Total utility plant ............................................................. . $12,502.8 $732.4 $127.2 $ 44.3 $13,152.3 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.
(c) For information on the retirement of spent nuclear fuel, see Depreciation and Amortization, under Note A to FINAN-CIAL STATEMENTS.
43
- 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, 1993, 1992 AND 1991 Col. A Col. B Col. C Col. D Col.E Col. F Additions Charged Other Balance at to Costs Changes Balance Beginning & Add at End of Classification of Period Expenses Retirements (Deduct)
- Period
- (Millions) 1993
.Accumulated depreciation and amortization of plant ............*..... , $3,837.6 $401.T $219.2 $45.8 $4,065.9 Accumulated amortization of capital leases ..... :............ '. ... ,......... $ 14.9 $ 2.7 $ 4.8 $ 12.8 Accumulated amortization of nuclear fuel .................................. $ 592.9 $ 81.3 $ 8.9(a) $ 665.3 1992
. Accumulated ~depreciation and amortization of plant .. '. ........ ,..... $3,520.9 $391.4 $116.2 $ 41.5 $3,837;6 Accumulated amortization of capital leases ....................... ,........ $ 12.5 $ 2.4 $, 14.9 Accumulated amortization of nuclear fuel ... :.............................. $ 566,8 . $ 92.5 . $ _66.4(a) * '*$ 592.9 1991
- Accumulated depreciation .!l!ld amortization of plant ................. $3,171.4, - $376.3 $102.1 *.* $ 75.3(b) $3,520.9
=*
Accumulated amortization of capital leases .......... ;..................... $* 48.6 * $ 6.0 *$(42.l)(b)$
- 12.5 Accumulated amortization of nuclear fuel .................................. $ 500.6 $ 97.1 $ 30.9(a) $ 566.8
-~----- .
Pro~ision for dep~eciation. of automobiles and* trucks is charged to .transportation expense clearing account and redis-tributed to operation expense, utility plant and other accounts. * * *
(a) For information on the retirementof spent nuclear fuel, see Depreciation .and Amortization under Note A to FINAN-CIAL STATEMENTS. .
(b) At the expiration of the lease in August 1991, the combustion turbines became the property of the Company ..
44
- SCHEDULE IX VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE IX- SHORT-TERM BORROWINGS For the Years Ended December 31, 1993, 1992 and 1991 Col.A Col. B Col.C Col.D Col.E Col. F Weighted Maximum Average Weighted Amount Amount Weighted Average Balance at Average Outstanding Outstanding Interest Rate end of Interest During the During the During the Category of Aggregate Short-Term Borrowings Period Rate Period Period (a) Period (a)
(M111ions) 1993 Commercial paper program (b) ................................ .. $ 43.0 3.40% $110.2 $35.2 3.21%
1992 Commercial paper program (b) ................................ .. $ 49.5 3.43% $134.0 $26.2 3.61%
Nuclear fuel financing (c) .......................................... . $ 0.0 (d) (d) 4.24%
1991 Nuclear fuel financing (c) .......................................... . $104.9 4.93% (d) (d) 6.46%
(a) Average computed on a daily weighted basis (b) In 1992, the Company established a commercial paper program that provides an additional source of borrowing in lieu of the Inter-Company Credit Agreement with Dominion Resources. Borrowings are limited to $200 million outstanding at any one time. Dominion Resources maintains credit agreements with various expiration dates, to support this commercial paper program.
(c) Maximum 270 days (d) The total amount of commercial paper outstanding under this arrangement at December 31, 1991 was $104.9 million.
The standby revolving credit agreement which supported the related commercial paper (a maximum of $200 million) was terminated in October 1992.
45
- SCHEDULEX "I ..
VIRGINIA ELECTRIC AND POWER COMPANY SCHEDULE X *sUPPLEMENTARY. INCOME STATEMENT*INFORMATION For the Years Ended December 31,' i993, 1992 and 1991 Col. B
_Item ...
Col.A Charged to Expenses Years Ended December 31, 1993 1992 1991
.. , (M~lions)
Truces other than mcome taxes:
- Real estate and property ....................................:.. :.................................................................... *.. $ 84.5 $ 79.1 $ 71.6 Local gross receipts ..'-..... ,............,.. :.......................................... ;.................................................... . J00.8 . 92.8 91.7 Payroll related ............ ::............. ::: ....................................... :...:..............*.. '. ......: ............ :...............
- 30.6' 30.1 28.7 West Virginia business. and occµpation *********.********************************************************************'.******** 27.2 28.7 28.2 Other .... : .............**.* .... :.............' ................. *........ *....................................... ; ... *......... ;*:....... *..... . 3.6.
- 2.5
- 6.8
- Total ................... *..................... *..* .............................. ,.: .. *...... *....... *.... *.* ...... *.... *.:.. * *.......... ******* ' $246.7* $233.2 $227.0
. * .. r ,.,*
46
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 Company is as follows:
Year First Principal Occupation for Last 5 Years, Elected a Name and Age Directorships in Public Corporations Director T110s. E. Capps (58) Chairman of the Board of Directors of Virginia Electric 1989 and Power Company and Dominion Resources and President and Chief Executive Officer of Dominion Resources (from May 1, 1990 to December 30, 1992, Vice Chairman of the Board of Directors of Virginia Electric and Power Company and President and Chief Executive Officer of Dominion Resources; from April 1, 1989 to May 1, 1990, President and Chief Operating .
Officer of Dominion Resources prior to April 1, 1989, President of Dominion Resources). He is a Director of Dominion Resources, NationsBank Corporation and Bassett Furniture Industries, Inc.
James T. Rhodes (52) President and Chief Executive Officer of Virginia Electric 1989 and Power Company (prior to April 1, 1989, Senior Vice President-Finance). He is a Director of Dominion Resources and NationsBank of Virginia, N.A.
John B. Adams, Jr. (49) President and Chief Executive Officer of A. Smith 1987 Bowman Distillery, Inc., Fredericksburg, Virginia, a manufacturer and bottler of *alcohol beverages, December 27, 1989 to date; (prior to December 27, 1989 Vice President and Director).
William W. Berry (61) Retired Chairman of the Board of Directors of Virginia 1980 Electric and Power Company and Dominion Resources (from May 1, 1990 to December 30, 1992, 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 of Virginia Electric and Power Company and Dominion Resources and Chief Executive Qfficer of Dominion Resources).
He is a Director of Dominion Resources, Ethyl Corporation, Scott & Stringfellow Financial, Inc. and Universal Corporation.
- Anna Ruth Inskeep (68) Battle Park Farms, Rapidan, Virginia, a dairy farm and 1987 milk hauling business.
Benjamin J. Lambert, III (57) Optometrist, Richmond, Virginia. He is a Director of 1992 Consolidated Bank and Trust Company Harvey L. Lindsay, Jr. (64) Chairman and Chief Executive Officer of Harvey Lindsay 1986 Commercial Real Estate, Norfolk, Virginia, a commercial real estate firm.*
William T. Roos (66) Retired President of Penn Luggage, Inc., Hampton, 1975 Virginia, retail specialty stores.
William G. Thomas (54) President of Hazel & Thomas, Alexandria, Virginia, a law 1987 firm.
Each Director holds office until the next Annual Meeting of Shareholders or until his or her successor is duly elected.
47
- ~.. r (b) Information concerning the executive officers of Virginia Electric and Power Company is as follows:
Name and Age Business Experience Past Five Years Thos. E. Capps (58) Chairman of the Board of Directors, December 30, 1992 to date; Vice Chairman of the Board of Directors April 1, 1989 to December 30, 1992; President and Chief Operating Officer of Dominion Resources, Inc., prior to April 1, 1989.
James T. Rhodes (52) President and Chief Executive Officer, April 1, 1989 to date; Senior Vice President-Finance prior to April 1, 1989.
John A. Ahladas (51) Senior Vice President-Corporate Services, January 1, 1990 to date; Senior Vice President-Corporate Technical Services prior to January 1, 1990.
Larry W. Ellis (53) Senior Vice President-Power Operations and Planning, January 1, 1990 to date; Vice President-System Planning and Power Supply prior to January 1, 1990.
Robert F. Hill (58) Senior Vice President-Commercial Operations. .
B.D. Johnson (61) Senior Vice President-Finance, Controller, Treasurer and Corporate Secretary, November 15, 1992 to date; Senior Vice President-Finance and Controller, January l, 1990 to November 15, 1992; Vice President and Controller prior to January 1, 1990.
William L. Stewart (50) Senior Vice President-Nuclear, January 1, 1990 to date; Senior Vice President-Power prior to January 1, 1990.
Charles A. Brown (51) Vice President-Central Division, September 1, 1992 to date; Vice President-Procurement prior to September 1, 1992.
William R. Cartwright (51) Vice President-Fossil and Hydro, January 1, 1990 to date; Vice President-Nuclear Operations prior to January 1, 1990.
Thomas L. Caviness, Jr. (48) Vice President-Eastern Division, November l, 1989 to date; Executive Project Director prior to November 1, 1989.
James T. Earwood, Jr. (50) Vice President-Division Services.
James R. Frazier, Jr. (52) Vice President-Southern Division.
Larry M. Girvin (50) Vice .President-Nuclear Services, September 1, 1992 to date; Vice President~Central Division, January 1, 1991 to September 1, 1992; District Manager Richmond, September 1, 1989 to January 1, 1991; District Manager East Richmond prior to September 1, 1989.
Earl R. Gore (53) Vice President-Northern Division.
E. Wayne Harrell (47) Vice President-Nuclear Engineering Services, September 1, 1992 to date; Vice President-Nuclear Services, January 1, 1992 to September 1, 1992; Vice President-Nuclear Operations, January 1, 1990 to January 1, 1992; Vice President-Fossil and Hydro Operations prior to January 1, 1990.
F. Kenneth Moore (52) Vice President-Procurement, September 1, 1992 to date; Vice President-Nuclear Engineering Services, November 1, 1989 to September 1, 1992; Vice President-Power Engineering Services prior to November 1, 1989.
Irene M. Moszer (50) Vice President-Information Services, October 1, 1991 to date; Vice President, Treasurer and Corporate Secretary, January 1, 1990 to October 1, 1991; Vice President-Administrative Services prior to January 1, 1990.
James P. O'Hanlon (50) Vice President-Nuclear Operations, January 1, 1992 to date; Vice President-Nuclear Services, June 15, 1989 to January l, 1992; Vice President-United Energy Services Corporation prior to June 15, 19.89.
- Thomas J. O'Neil (51) Vice President-Energy Efficiency, September 1, 1992 to date; Vice President-Regulation, prior to September 1, 1992.
Robert E. Rigsby (44) Vice President-Human Resources, October 1, 1991 to date; Vice President-Information Systems, January 1, 1990 to October 1, 1991; Vice President-Western Division prior to January 1, 1990.
Edgar M. Roach, Jr. (45) Vice President-Regulation, February 1, 1994 to date; Partner in.the law firm of Hunton & Williams, Raleigh, North Carolina prior to February 1, 1994.
Johnny V. Shenal (48) Vice President-Western Division, January 1, 1990 to date; Manager, Transmission and Substation Engineering prior to January 1, 1990.
48
Eva S. Teig (49)
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.
Robert F. Saunders (50) Assistant Vice President-Nuclear Operations, November 1, 1990 to date; Manager, Nuclear Licensing and Programs, November 1, 1989 to November 1, 1990; Manager, Nuclear Licensing prior to November 1, 1989.
There is no family relationship between any of the persons named in response to Item 10.
ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The Summary Table below includes compensation paid by the Company for services rendered in 1993, 1992 and 1991 for the Chief Executive Officer and the four other most highly compensated executive officers (as of December 31, 1993) as determined by total salary and incentive payments for 1993 .
.Summary Compensation Table Long Term Compensation All Annual Compensation LTIP Other Name & Principal Position Year Salary Incentives(!) Payouts Compensation
($) ($) ($) ($)
James T. Rhodes 1993 $356,000 $202,202 $97,657(2) $17,133(3)
President & CEO 1992 $340,000 $188,752 $52,833(4) $16,924(5) 1991 $274,600 $155,502 $43,519(6)
Thos. E. Capps 1993 $354,729 $ 72,100 $ 0 $ 0 Chainnan of the Board 1992 $333,698 $144,828 $ 0 $ 0 1991 $275,141 $130,504 $ 0 0 Robert F. Hill 1993 $210,350 $ 85,086 $44,677 $ 6,311(7)
Senior Vice President- 1992 $204,900 $ 71,703 $24,334 $ 6,147(7)
Commercial Operations 1991 $196,275 $ 71,085 $21,290 William L. Stewart 1993 $220,000 $103,265 $45,987 $ 6,600(7)
Senior Vice President- 1992 $202,575 $ 71,703 $24,334 $ 5,915(7)
Nuclear 1991 $192,350 $ 71,085 $21,290 Bill D. Jo~son 1993 $204,875 $ 90,954 $44,677 $ 6,146(7)
Senior Vice President- 1992 $199,250 $ 72,474 $25,167 $ 5,978(7)
Finance, Controller, Treasurer 1991 $187,625 $ 72,339 $19,106 and Corporate Secretary (1) The Company does not maintain "bonus" plans which are used by some companies to supplement salaries based on the success of the company without regard to individual performance. However, the Company has in place various incentive plans that compensate officers and employees for achieving pre-determined specified performance goals.
(2) Includes 1,118 shares of Restricted Stock and $51,540 in cash awarded on February 18, 1994 at the end of a three-year performance period. Dividends are paid on Restricted Stock. Restrictions on the shares of stock will lapse six months from the date of grant. As of December 31, 1993 no shares of Restricted Stock were held.
(3) Company match on savings plan contribution ($7;075) and insurance premium to Directors Charitable Contribution Program ($10,058).
(4) Includes 788 shares of Restricted Stock and $20,254 in cash awarded on February 19, 1993 at the end of a three-year performance period. Dividends are paid on Restricted Stock. Restrictions on the shares of stock lapsed six months from the date of grant.
(5) Company match on savings plan contribution ($6,866) and insurance premium for Directors Charitable Contribution Program ($10,058).
(6) Includes 773 shares of Restricted Stock and $15,401 in cash awarded on February 25, 1992 at the end of a three-year performance period. Dividends are paid on Restricted Stock. Restrictions on the shares of stock lapsed six months from the date of grant.
(7) Company match on savings plan contribution.
49
Long-Term Incentive Compensation Long-term incentive awards made during 1993 are shown in the following table.
Long-Term Incentive Plans - Awards in the Last Fiscal Year 1993-1995 Performance Achievement Plan Estimated Future Payouts Performance or Under Non-Stock Price Based Plans Number of Other Period Shares, Units Until Maturation Threshold Target Maximum Name or Other Rights(l) or Payout (#) (#) (#)
James T. Rhodes 3,442 3 years 1 (3) 3,442(3) 5,163(3)
Thos. E. Capps 0(2)
Robert F. Hill 1,233 3 years 1 (3) 1,233(3) 1,850(3)
William L. Stewart 1,233 3 years 1 (3) 1,233(3) 1,850(3)
Bill D. Johnson 1,233 3 years 1 (3) 1,233(3) 1,850(3)
(1) Performance shares representing Dominion Resources Common Stock to be awarded at the end of Performance period.
(2) Mr. Capps does not participate in this plan.
(3) Except for James T. Rhodes, payout of awards are tied to achieving levels of Virginia Power's return on equity (ROE) (50%) and meeting a cost per kilowatt-hour goal (50%). The threshold award will be earned if 81 % of the ROE goal or 75% of the costs per kilowatt-hour goal is achieved. The target awards will be earned if the goals are fully achieved. The maximum award will be earned at 110% or more of the ROE goal and 112% of the cost goal. Targets and goals for James T.
Rhodes were approved by Dominion Resources Organization and Compensation Committee under the Dominion Resources Long-Term Incentive Plan.
Payout of award for James T. Rhodes is based on performance shares to be paid out in shares of restricted stock based on the achievement of three specified goals over a three-year performance period (1993-1995), weighted as follows: a total return to Dominion Resources Shareholders superior to that of the S&P Utility Index (50% ), utility return on equity equal to the average ROE achieved by a group of comparable utilities (25% ), and restraint of utility costs to a growth rate less than that of the Consumer Price Index (25% ).
The target number of shares will be earned if all goals are fully achieved. The threshold amount will be earned if at least 71 % of the total return goal, 81 % of the ROE goal, and 75% of the cost control goal are achieved. The maximum amount will be earned if at least 114% of the total return goal, 110% of the ROE goal, and .112 % of the cost control goal are achieved.
Retirement Plans The table below sets forth the estimated annual straight life benefit that would be paid following retirement under the Dominion Resources, Inc. Retirement Plan's (the Retirement Plan) benefit formula.
Estimated Annual Benefits Payable Upon Retirement Credited Years of Service Final Average Earnings 15 20 25 30
$150,000 $ 41,096 $ 54,794 $ 68,493 $ 82,192 175,000 48,634 64,844 82,056 97,267 200,000 56,171 74,894 93,618 112,342 225,000 63,708 84,944 106,181 127,417 250,000 71,246 94,994 118,743 142,492 300,000 86,321 115,094 143,868 172,642 350,000 101,396 135,194 168,993 202,792 400,000 116,471 155,294 194,118 232,942 450,000 131,546 175,394 219,243 263,092 500,000 146,621 195,494 244,368 293,242 550,000 161,696 215,594 269,493 323,392 600,000 176,771 235,694 294,618 353,542 50
- -- -I' Benefits under the Retirement Plan are based on (i) average base compensation over the consecutive 60-month period in which pay is highest, (ii) years of credited service, (iii) age at retirement, and (iv) the offset of Social Security Benefits.
Certain officers have entered into retirement agreements that give additional credited years of service for retirement and retirement life insurance purposes, contingent upon the officer reaching a specified age and remaining in the employ of the Company.
For purposes of the above table, based on 1993 compensation, credited years of service (including any additional years earned in connection with the retirement.agreements) for each of the individuals named in the cash compensation table would be as follows:
James T. Rhodes: 22; Thos. E. Capps: 23; Robert F. Hill: 29; William L. Stewart: 23; and Bill D. Johnson 30.
The Internal Revenue Code limits the annual retirement benefit that may be paid from a qualified retirement plan and the amount of compensation that may be recognized by the Retirement Plan. To the extent that benefits determined under the Retirement Plan's benefit formula exceed the limitations imposed by the Internal Revenue Code, they will be paid under the Dominion Resources, Inc. Benefit Restoration Plan.
The Company also provides an Executive Supplemental Retirement Plan (the Supplemental Plan) to its elected officers designated to participate by the Board of Directors. The Supplemental Plan provides an annual retirement benefit equal to 25 percent of a participant's final compensation (base pay plus annual incentive plan payments). The normal form of benefit is payable in equal monthly installments for 120 months to a participant with 60 months of service, who (i) retires at or after age 55 from the employ of the Company, (ii) has become permanently disabled, or (iii) dies. If a participant dies while employed, the normal form of benefit will be paid to a designated beneficiary. If a participant dies while retired, but before receiving all benefit payments, the remaining installments will be paid to a designated beneficiary. In order to be entitled to benefits under the Supplemental Plan, an employee must be employed as an elected officer of the Company until death, disability or retirement.
Based on 1993 compensation, the estimated annual retirement benefit for each of the executive officers under the Sup-plemental Plan would be as follows: James T. Rhodes: $140,606; Thos. E. Capps: $127,354; Robert F. Hill: $75,369; Wil-liam L. Stewart: $82,079; and B. D. Johnson: $73,994.
Employment Agreements The Company has entered into employment agreements (the Agreements) with key management executives, including James T. Rhodes, Thos. E. Capps, Robert F. Hill, William L. Stewart and Bill D. Johnson. Each Agreement has a three-year term and thereafter is automatically extended on its anniversary date for an additional year unless notified that the Agreement will not be extended by the Company. If, following a change in control of Dominion Resources (as defined in the Agree-ments), an executive's employment is terminated by the Company without cause, or voluntarily by the executive within sixty days after a material reduction in the executive's compensation, benefits or responsibilities, the Company will be obligated to pay to the executive continued compensation equaling the average base salary and cash incentive bonuses for the thirty-six full month period of employment preceding the change in control or employment termination. In addition, the terminated executive will continue to be entitled to any benefits due under any stock or benefit plans. The Agreements do not alter the compensation and benefits available to an executive whose employment with the Company continues for the full term of the executive's Agreement. The amount of benefits provided under each executive's Agreement will be reduced by any compen-sation earned by the executive from comparable employment by another employer during the thirty-six months following termination of employment with the Company. An executive shall not be entitled to the above benefits in the event termina-tion is for cause.
Compensation of Directors The non-employee members of the Board receive an annual retainer of $19,000 and a fee of $800 for each Board or committee meeting attended. These Directors may elect to defer their annual retainer and/or their meeting fees under the Deferred Compensation Plan until they retire from the Board or otherwise direct. The deferred fees are credited, for book-keeping purposes, with earnings and losses as if they were invested in either an interest bearing account or Dominion Resources Common Stock, depending on the Director's election.
In addition, the Company makes payments to non-employee Directors or their designated beneficiaries upon those Directors' retirement, death or disability. Payments to a retired Director, including one who becomes disabled after retire-ment, are made for a period of four years, or for a period of years equal to the Director's service on the Board of the Company or one of its subsidiaries, whichever is longer. If a non-employee Director becomes disabled prior to retirement, 51
these payments are made for four years. Each year, these payments equal the annual retainer in effect at the time the pay-ments begin. Upon the death of a non-employee Director, the unpaid portion of these payments, up to a maximum of four times the annual amount due, is paid in a lump sum to the Director's designated beneficiary.
Directors Charitable Contribution Program Dominion Resources administers a Directors' Charitable Contribution Program (the Program) for all its subsidiaries, including the Company, as part of its overall program of charitable giving. Beginning at the death of a Director a donation in an aggregate amount of $50,000 per year for 10 years will be made to one or more qualifying charitable organizations recommended by the individual Director. Life insurance policies have been purchased on the lives of the Directors in connec-tion with the Program. These policies are owned by Dominion Resources, which is also the beneficiary. The Directors derive no financial or tax benefits from the Program.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below sets forth as of January 31, 1994, except as noted, the number of shares of Common Stock of Dominion Resources owned by Directors and four other more highly compensated executive officers of Virginia Electric and Power Company.
Shares of Common Stock Name Beneficially Owned James *T. Rhodes .......................................... . 7,088 Thos. E. Capps ............................................. . 48,199(a)
Robert F. Hill ........... :.. :.......................... :..... . 4,241 William L. Stewart ...................................... . 2,404 Bill D. Johnson ............................................ . 9,644 John B. Adams, Jr....................................... . 2,584 William W. Berry ........................................ . 14,420 Anna Ruth Inskeep ...................................... . 4,909 Benjamin J. Lambert, III ............................. . 376 Harvey L. Lindsay, Jr.................................. . 400 William T. Roos ......................................... .. 5,894(b)
William G. Thomas ..................................... . *o (a) Mr. Capps disclaims beneficial ownership of 1,086 shares that are held by family members. A member of Mr. Capp's family is a beneficiary of a trust that owns an additional 750 .shares of Common Stock.
(b) Members of Mr. Roos' family are beneficiaries of trusts that own an additional 3,618 shares of Common Stock for which he disclaimed beneficial ownership.
All current Directors and executive officers as a group (31 persons) beneficially owri, in the aggregate, 169,759 shares of Common Stock of Dominion Resources. No shares of the Company's Preferred Stock are owned by the Directors or execu-tive officers as a group.
ITEM 13. CERTAIN RELATIONSIIlPS AND RELATED TRANSACTIONS None.
52
PART IV ITEM 14.. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed 'as part of this Form 10-K:
- 1. Financial Statements See Index on page 18.
- 2. Finandal Stat~ment Schedules See Index on page 18.
- 3. Exhibits 3(i)*'
- Restated Articles of Incorporation, as amended, as in effect on August 12, 1993 (filed herewith).
3(ii)*. . Bylaws, as amended, as in effect* on April 1, 1989 (filed herewith)
- 4(i) See Exhibit (3(i)) above; .. . . ..
4(ii) Indenture of Mortgage of the Company, dated November l, 1935, as supplemented and modified by fifty-eight Supplemental Indentures, Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 19~5,:FilyNo, 1-2255, incorporated by refererice; 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; Sixty-Seventh Suppl~mental Indenture; Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference; Sixty-Eighth Supplemental Indenture, Exhibit 4(i), Sixty-Ninth Supplemental Indenture, Exhibit 4(ii) and Seventieth Supplemental Indenture, Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference; Seventy-First Supplemental Indenture, Exhibit 4(i) and Seventy-Second Supplementanndenture, Exhibit 4(ii), Form 8-K, dated July 7, 19n, File No. 1-2255, incorporated by reference; Seventy~Third Supplemental Indenture, Exhibit 4(i), Form 8-K, dated
- August 6, 1992, File Ne:,. 1-2255, incorporated by reference; Seventy-Fourth Supplemental Indenture, Exhibit 4(i),' Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference; Seventy-Fifth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated April 6, 1993, File No. 1-2255, incorporated by reference; Seventy-Sixth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference; Seventy-Seventh Supplemental Indenture, Exhibit 4(i), Form 8-K; dated June 8, 1993, File No. 1-2255, incorporated by reference; Seventy-Eighth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference; Seventy-.
Ninth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference; Eightieth Supplemental Indenture, Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1-2255, incorporated by reference; and Eighty-Second Supplemental Indenture, Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1-2255, incorporated by reference.
4(iii) Eighty-First Supplemental Indenture, dated January 1, 1994 (filed herewith) 4(iv)* Indenture, dated April 1, 1985, between Virginia Electric and Power Company and Crestar Bank (formerly United Virginia Bank) (filed herewith) 4(v)* Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and Chemical Bank (filed herewith) 4(vi)* Indenture, dated April l, 1988, between Virginia Electric and Power Company and Chemical Bank as supplemented and modified by a First Supplemental Indenture, dated August 1, 1989 (filed herewith) 4(vii) Virginia Electric and Power Company agrees to furnish to the Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized thereunder does not exceed 10 percent of Virginia Electric and Power Company's total assets.
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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).
lO(iv) Nuclear Fuel Agreement, dated as of December 28, 1982 as amended and restated on October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(x),
. Form 10-K for the fiscal year ended December 31, 1983, File No. 1-2255, incorporated by reference).
lO(v) Inter-Company Credit Agreement, dated July 1, 1986, as amended and restated as of Decembef31, 1992 between Dominion Resources and Virginia Electric and Power Company (Exhibit lO(v), Form 10-K for the fiscal year ended December 31, 1992, File No. 1-2255, incorporated by reference).
lO(vi) Credit Agreement, dated December 1, 1985, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xix), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference).
lO(vii) Agreement for Northern Virginia Services, dated as of November 1; 1985, between Potomac Electric Power Company and Virginia Electric and Power Company (Exhibit lO(xxi), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference).
lO(viii) Purchase, Construction and Ownership Agreement, dated May 31, 1990, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xi), Form 10-K for the fiscal year ended Dec~mber 31, 1990, Fil.e No. 1-2255, incorporated by reference).
lO(ix) Operating Agreement, dated May 31, 1990, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xii), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).
lO(x) Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and 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).
lO(xi) Receivables Purchase Agreement, dated as of December 11, 1991, between Virginia Electric and Power Company and Dynamic Funding Corporation (Exhibit lO(xv) Form 10-K for the fiscal year ended Decelllber 31, 1991, File No. 1-2255, incorporated by reference).
lO(xii) Description of arrangements with certain officers regarding additional credited years of service for retirement purposes (Exhibit lO(xii), Form 10-K for the fiscal year ended December 31, 1992, File No.
1-2255, incorporated by reference).
23(i) Consent of Hunton & Williams (filed herewith).
23(ii) Consent of Jackson & Kelly (filed herewith).
23(iii) Consent of Deloitte & Touche (filed herewith).
- EDGAR System da.tabase filing (b) Reports on Form 8-K The Company filed a report on Form 8-K, dated January 18, 1994, relating to the sale of $125 million of First and Refunding Mortgage Bonds.
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- SIGNATURES e
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
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this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VIRGINIA ELECTRIC AND POWER COMPANY Date: February 22, 1994 By THos. E. CAPPS (Thos. E. Capps, Chairman of the Board of Directors)
Pursuant to the requirements of the Securities. Exchange Act of 1934, this report has been signed below by the following persons onbehalf of the registrant and in the capacities and on _the date indicated.
Signature Title Date THos. E. CAPPS Chairman of the Board of Directors and February 22, 1994 Thos. E. Capps Director J. T. RHODES President (Chief Executive Officer) and February 22, 1994 J. T. Rhodes Director JOHN B. ADAMS, JR. Director February 22, 1994 John B. Adams, Jr.
WILLIAM W. BERRY Director February 22, 1994
. William W. Berry ANNA Rum INSKEEP Director February 22, 1994 Anna Ruth Inskeep BENJAMIN J. LAMBERT, III Director* February 22, 1994 Benjamin J. Lambert, m HARVEY L. LINDSAY, JR. Director February. 22, 1994 Harvey L. Lindsay, Jr; WILLIAM T. Roos Director February 22, 1994 William T. Roos WILLIAM G. THOMAS Director February 22, 1994 William G. Thomas B. D. JOHNSON Senior Vice President, February 22, 1994 B. D. Johnson Controller and Treasurer (Principal Accounting Officer and Chief Financial Officer) 55
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I
- I VIRGINIA ELECTRIC AND POWER COMPANY STATEMENTS OF INCOME (Unaudited)
Three Months Ended December 31.
1993 1992 (Millions)
Operating revenues $963.9 $ 840.9 Operating expenses:
Operation:
Fuel used in current generation 143.1 120.5 Purchased power expenses-fuel 77.4 77.1
-capacity 145.9 147.3 Deferred expenses-fuel 6.1 18.8
-capacity 7.0 (102. 7)
Other 146.5 114.0 Maintenance 55.4 43.3 Depreciation and amortization 106.0 103.0 Amortization of terminated construction project costs 8.6 9.2 Taxes-Income 39.1 60.8
-Other 57.4 59.7 Total 792.5 651.0 Operating income 171.4 189.9 Other income:
Allowance for other funds used during construction 1.4 1.3 Miscellaneous, net ( 10. 8) ( 5. 2)
Income taxes associated with miscellaneous, net ( 0. 8) 3.9 Total (10. 2) 0.0 Income before interest charges 161.2 189.9 Interest charges:
Interest on long-term debt 74.9 73.1 Other ( 6. 7) ( 0. 2)
Allowance for borrowed funds used during construction ( 0. 9) ( 3 . 3)
Total 67.3 69.6 Net income 93.9 120.3 Preferred dividends 10.0 11.0 Balance available for Common Stock $ 83.~ $ 109.3
Virginia Electric & Power Company 1994 Estimated Internal Cash Flow (Millions of Dollars)
Jan Apr Jul Oct Estimated thru thru thru thru 1994 Mar Jun Sep Dec Total Cash Receipts $1,103.2 $965.3 $1,161.6 $1,027.0 $4,257.1 Less:
Cash for Operations 517.8 571.8 835.1 640.1 2,564.8 Taxes 32.9 196.2 138.1 146.0 513.2 Interest 74.9 70.7 82.3 75.7 303.6 Dividends
- Preferred Stock 9.4 10.4 10.1 10.7 40.6 Common Stock 96.4 96.7 97.1 101.3 391.5 Decommissioning Trust 6.1 6.1 6.1 6.1 24.4 Changes in Working Capital 182.8 (5.1) (5.6) (76.6) 95.5 Other (0.4) (0.4) (0.4) (0.4) .Qfil Total Cash Flow (1) ~ i1U ~ lliil ~
(1) Before Financing and Construction Requirements.
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 1994, provided herewith, is based on the best available information known at this time and is a reasonably accurate projection of the Company's 1994 cash flow.
. . o nson Senior Vice Pr sident-Finance Controller, 1 reasurer and Corporate Secretary Commonwealth of Virginia City of Richmond Sworn to and subscribed before me this Ii-/ H'-Clay of f{\u..i{ cL 1994.
Notary Pubhc My commission expires: _Jurie... SD, lt{q/o NOTARIAL SEAL
1 VIRGINIA ELECTRIC AND POWER COMPANY STATEMENT The Company currently estimates 1994 construction and nuclear fuel expenditures (exclusive of Allowance for Funds Used During Construction) to be $691 million. Of this amount, it is expected that approximately $325 million will be obtained from internal sources. The remaining $366 million of construction requirements , as well as the $167 million of debt and preferred stock maturities and sinking fund requirements, will be obtained by a combination of sales of securities and short-term borrowings. The Company is reasonably assured that, based on the best available cash flow projections which are provided herewith, curtailment of capital expenditures for required nuclear programs would not be required to cover the Price-Anderson maximum retrospective premium assessment for a single incident of $326.8 million ($81. 7 million, including a 3 percent insurance premium tax for Virginia, for each of the four reactors owned by the Company with assessments not to exceed $10.3 million per reactor per year) currently in force.