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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-2255
VIRGINIA ELECTRIC AND POWER COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
VIRGINIA
(STATE OR OTHER JURISDICTION OF
INCORPORATION OR ORGANIZATION)
ONE JAMES RIVER PLAZA
RICHMOND, VIRGINIA
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
54-0418825
(I.R.S. EMPLOYER
IDENTIFICATION NO.)
23261-6666
(ZIP CODE)
(804) 771-3000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA 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 dividend
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
(TITLE OF CLASS)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X 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. (X)
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of January 31, 1995 was zero.
As of January 31, 1995, there were issued and outstanding 171,484 shares of
the registrant's common stock, without par value, all of which were held,
beneficially and of record, by Dominion Resources, Inc.
DOCUMENTS INCORPORATED BY REFERENCE.
NONE
VIRGINIA ELECTRIC AND POWER COMPANY
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..................................................... 3
County and Municipal......................................... 3
North Carolina............................................... 3
Regulation..................................................... 4
General...................................................... 4
Environmental................................................ 4
Nuclear...................................................... 5
Winter Peak.................................................. 5
Sources of Power............................................... 6
Company Generating Units..................................... 6
Net Utility Purchases........................................ 6
Non-Utility Generation....................................... 6
Sources of Energy Used and Fuel Costs.......................... 6
Nuclear Operations and Fuel Supply........................... 6
Fossil Fuel Supply........................................... 7
Purchases and Sales of Power................................. 7
Interconnections............................................... 7
Future Sources of Power........................................ 8
Company Owned Generation..................................... 8
Non-Utility Generation....................................... 9
Competition.................................................... 9
Conservation and Load Management............................... 9
2. Properties...................................................... 9
3. Legal Proceedings............................................... 10
4. Submission of Matters to a Vote of Security Holders............. 12
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters........................................... 12
6. Selected Financial Data......................................... 12
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 12
8. Financial Statements and Supplementary Data..................... 19
9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure....................................... 40
PART III
10. Directors and Executive Officers of the Registrant............. 40
11. Executive Compensation......................................... 43
12. Security Ownership of Certain Beneficial Owners and
Management..................................................... 46
13. Certain Relationships and Related Transactions................. 46
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K...................................................... 47
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 municipalities. 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 municipalities in North Carolina.
The Company strives to operate its generating facilities in accordance with
prudent utility industry practices and in conformity with applicable statutes,
rules and regulations. Like other electric utilities, the Company's generating
facilities are subject to unanticipated or extended outages for repairs,
replacements or modifications of equipment or otherwise to comply with
regulatory requirements. Such outages may involve significant expenditures not
previously budgeted, including replacement energy costs. See NUCLEAR REGULATION
under REGULATION below and NUCLEAR OPERATIONS AND FUEL SUPPLY under SOURCES OF
ENERGY USED AND FUEL COSTS.
The Company had 10,585 full-time employees on December 31, 1994. 3,794 of
the Company's employees are represented by the International Brotherhood of
Electrical Workers under a contract extending to March 31, 1995. Negotiations
are presently underway to extend the contract.
For additional information on significant corporate governance issues
relating to the nonutility business see Item 3. LEGAL PROCEEDINGS.
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 1995-1997, total $1.9 billion. It has adopted a 1995 budget for
construction and nuclear fuel expenditures as set forth below:
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ESTIMATED 1995
EXPENDITURES
(MILLIONS)
New Generating Facilities:
Clover Unit 1 and Unit 2............................................................ $ 52
Other Production:
North Anna Unit 2 steam generator replacement....................................... 70
Clean Air Act....................................................................... 25
Other............................................................................... 90
General Support Facilities............................................................ 56
Transmission.......................................................................... 59
Distribution.......................................................................... 262
Nuclear Fuel.......................................................................... 59
Total Construction Requirements and Nuclear Fuel.................................... 673
AFC.............................................................................. 11
Total Expenditures.................................................................. $684
FINANCING PROGRAM
In 1994, Virginia Power obtained $539 million from the sale of securities.
With a portion of the proceeds of the 1994 securities sales, the Company retired
$166.5 million of securities through mandatory debt maturities and sinking fund
requirements and retired an additional $167.8 million of securities through
optional redemptions. Its long-term financings included $325.0 million of First
and Refunding Mortgage Bonds, $100 million of unsecured Medium-Term Notes, $39.0
million of Pollution Control Revenue Bonds, and $75.0 million of Common Stock
sold to Dominion Resources. See LIQUIDITY AND CAPITAL RESOURCES under
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS for, among other things, a discussion of the Company's commercial
paper program.
Virginia Power's 1995 construction and nuclear fuel requirements, exclusive
of AFC, are estimated to be $673.2 million. Of this amount, it is expected that
approximately $552 million will be obtained from cash flow from operations. The
remaining $121.2 million of construction and nuclear fuel requirements, as well
as the $312.2 million of debt maturities, 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 1994 as follows:
1994
PERCENT PERCENT
OF OF
REVENUES KWH SALES
Virginia retail:
Non-Governmental customers.................... Virginia Commission 78% 73%
Governmental customers........................ Negotiated Agreements 11 12
North Carolina retail........................... 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%
Substantially 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.
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The principal rate proceedings in which the Company was involved in 1994
are described below by jurisdiction. Rate relief obtained by the Company is
frequently less than requested.
VIRGINIA
On February 3, 1994, the Virginia Commission entered its Final Order in
Virginia Power's 1992 rate case, approving an increase in annual revenues of
$241.9 million. Refunds of $129.2 million (representing the amount recovered
under interim rates in excess of the rates finally approved, with interest) were
completed by the end of April. The Commission also approved continuation of
deferral accounting to recover purchased power capacity costs, allowed inclusion
of salary incentive pay in the cost of service, 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
proposed changes in the Company's line extension policy and a proposed increase
in its summer/winter rate differential, and it disallowed from recovery through
rates the gross receipts tax component of capacity payments under certain
previously executed power purchase 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 that issue in the Company's
next rate case. The Company and several non-utility generators that will be
adversely affected by the ruling that disallowed rate recovery of the gross
receipts tax component of purchased power costs appealed that ruling to the
Virginia Supreme Court. On January 13, 1995, the Court issued its Opinion
affirming the Virginia Commission's decision. On January 23, 1995, the Company
and the other appellants filed Motions of Intent to Seek Rehearing.
On January 31, 1994, a hearing before a Hearing Examiner was held on
Virginia Power's application requesting approval of Schedule DEF -- Dispersed
Energy Facility, a rate schedule that would allow the Company to respond to the
request of an industrial or commercial customer to build and operate a
generating facility at its business location and to sell to that customer all of
the electricity and associated steam from that facility under a long-term
contract. On June 23, 1994, the Hearing Examiner recommended approval on an
experimental basis (see COMPETITION below).
On January 10, 1994, a hearing was held before a Hearing Examiner on
Virginia Power's application to revise its Schedule 19 (rates to be paid to
small qualifying facilities), which sought, among other things, 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. On April 25, 1994, the Hearing Examiner issued his Report
recommending approval of these and other features of the Company's application,
and on July 1, 1994, the Commission entered its Final Order accepting the
Examiner's recommendation as to these and most other issues.
On September 19, 1994, Virginia Power filed with the Virginia Commission an
application for a $25 million increase in the fuel factor. A hearing was held on
October 28, 1994, and the Commission approved an increase of $9.9 million
effective November 1, 1994.
Virginia Power filed an application with the Virginia Commission on
December 21, 1994, seeking approval, on an experimental basis, to implement a
real time pricing (RTP) option for its industrial customers with loads in excess
of 10 Mw. Under this option, all or a portion of an industrial customer's load
growth would be supplied at projected incremental hourly production costs,
adjusted for line losses and taxes, plus a margin of 0.6 cents per Kwh, and a
marginal cost-based Generation Capacity Adder and a Transmission Capacity Adder
would be applicable during those hours when the Virginia Power system is
approaching its forecasted annual peak demand. Up to 20% of an industrial
customer's existing load could be served on an RTP basis if the customer
executes a five-year contract for such service.
COUNTY AND MUNICIPAL
On January 30, 1995, Virginia Power reached agreement on the terms of a
three-year contract governing rates for county and municipal customers in
Virginia, which will continue through June 30, 1997. This contract resulted in a
decrease of $25.5 million in annual base revenue from the previous contract and
became effective July 1, 1994, with base rates remaining constant through the
term of the new contract.
NORTH CAROLINA
In Virginia Power's 1992 rate case before the North Carolina Commission,
the Commission disallowed recovery of certain capacity costs paid to a
cogenerator and a portion of the compensation of certain Company officers. The
Company
3
appealed the Commission's Order on those issues, and on December 9, 1994, the
North Carolina Supreme Court affirmed the disallowance of each by the
Commission. The Company filed a Motion for Rehearing on January 13, 1995.
Virginia Power filed an application with the North Carolina Commission on
September 9, 1994 for a $1.5 million increase in fuel rates. A hearing was held
on November 8, 1994, and the increase was approved on December 19, 1994.
On December 22, 1994, Virginia Power filed an application with the North
Carolina Commission for approval of Self-Generation Deferral Rates that are a
part of an Energy Agreement between North Carolina Power and Weyerhaeuser. The
Energy Agreement involves the use of a negotiated pricing structure which will
result in the deferral of the installation of additional self-generation
facilities by Weyerhaeuser.
REGULATION
GENERAL
In a wide variety of matters in addition to rates, Virginia Power is
presently subject to regulation by the Virginia Commission and the North
Carolina Commission, the Environmental Protection Agency (EPA), Department of
Energy (DOE), Nuclear Regulatory Commission (NRC), FERC, the Army Corps of
Engineers, and other federal, state and local authorities. Compliance with
numerous laws and regulations increases the Company's operating and capital
costs by requiring, among other things, changes in the design and operation of
existing facilities and changes or delays in the location, design, construction
and operation of new facilities. The commissions regulating the Company's rates
have historically permitted recovery of such costs.
Virginia Power may not construct, or incur financial commitments for
construction of, any substantial generating facilities or large capacity
transmission lines without the prior approval of state and federal governmental
agencies having jurisdiction over various aspects of its business. Such
approvals relate to, among other things, the environmental impact of such
activities, the relationship of such activities to the need for providing
adequate utility service and the design and operation of proposed facilities.
Various provisions of the Energy Policy Act of 1992 (Energy Act) that could
affect the Company include those provisions encouraging the development of
non-utility generation, giving FERC authority to order transmission access for
wholesale transactions, 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. While the full impact of the Energy Act on the Company cannot at this
time be quantified, it is likely, over time, to be significant. See COMPETITION
under BUSINESS and COMPETITION under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
ENVIRONMENTAL
From time to time, the Company may be identified as a potentially
responsible party (PRP) with respect to a Superfund site. EPA (or a state) can
either (a) allow such a party to conduct and pay for a remedial investigation
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 significant additional
expenditures in constructing new facilities or in modifying existing facilities.
The Company has installed a scrubber at its Mt. Storm Unit 3 Power Station. The
scrubber began operation on October 31, 1994. The cost of this scrubber and
related equipment was $147 million. The Company is presently conducting studies
leading to the compliance plan for Phase II of the Clean Air Act, which may
involve the installation of two additional scrubbers, the addition of nitrogen
oxide (NOx) controls and other methods for compliance. The present estimate for
the total
4
capital cost for compliance, assuming the installation of three scrubbers,
nitrogen oxide controls and emission monitoring instrumentation, is $481 million
(1992 dollars). Annual incremental compliance costs for operation, maintenance
and fuel costs are estimated to be $128 million. These cost estimates may change
upon completion of the study effort now underway. See CLEAN AIR ACT COMPLIANCE
under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
The Company continues to work with the West Virginia Office of Air Quality
concerning opacity requirements applicable to the Mt. Storm Power Station.
For additional information on ENVIRONMENTAL MATTERS, see Note O 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
substantial 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. Similar conditions were experienced
by utilities within the Pennsylvania-New Jersey-Maryland Power Pool.
5
SOURCES OF POWER
COMPANY GENERATING UNITS
TYPE SUMMER
YEARS OF CAPABILITY
NAME OF STATION, UNITS AND LOCATION INSTALLED FUEL MW
Nuclear:
Surry Units 1 & 2, Surry, Va..................................................... 1972-73 Nuclear 1,562
North Anna Units 1 & 2, Mineral, Va.............................................. 1978-80 Nuclear 1,787(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 720
North Branch Unit 1, Bayard, W. Va............................................ 1994(b) Waste Coal 74
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......................................................... 7,455
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(c)
Total hydro stations.......................................................... 1,584
Total Company generating unit capability...................................... 12,388
NET UTILITY PURCHASES.............................................................. 830
NON-UTILITY GENERATION............................................................. 3,244
Total Capability.............................................................. 16,462
(a) Includes an undivided interest of 11.6 percent (207 Mw) owned by Old
Dominion Electric Cooperative (ODEC).
(b) On December 30, 1994, the Company acquired the North Branch 80 Mw (nominal
rating) waste coal power station located in Bayard, West Virginia in Grant
County.
(c) Reflects the Company's 60 percent undivided ownership interest in the 2,100
Mw station. A 40 percent undivided interest in the facility is owned by
Allegheny Generating Company, a subsidiary of Allegheny Power System, Inc.
(APS).
The Company's highest one-hour integrated service area summer peak demand
was 13,366 Mw on July 29, 1993, and the highest one-hour integrated winter peak
demand was 14,877 Mw on January 19, 1994.
SOURCES OF ENERGY USED AND FUEL COSTS
For information as to energy supply mix and the average fuel cost of energy
supply, see RESULTS OF OPERATIONS under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
NUCLEAR OPERATIONS AND FUEL SUPPLY
In 1994, the Company's four nuclear units achieved a combined capacity
factor of 86.7 percent.
The North Anna Unit 2 steam generator replacement project is scheduled to
begin at the end of the first quarter of 1995 at a total estimated Company cost
of $110 million.
6
The Company utilizes both long-term contracts and spot purchases to support
its needs for nuclear fuel. Virginia Power's nuclear fuel supply and related
services are expected to be adequate to support current and planned nuclear
generation requirements. The Company continually evaluates worldwide market
conditions in order to obtain an adequate nuclear fuel supply. Current
agreements, inventories and market availability should 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
acceptance 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 and the Company plans to submit a
license application to the NRC in 1995 for such a facility at North Anna.
For details regarding nuclear insurance and certain related contingent
liabilities as well as a NRC rule that requires proceeds from certain insurance
policies to be used first to pay stabilization and decontamination expenses, see
Note C to FINANCIAL STATEMENTS.
FOSSIL FUEL SUPPLY
The Company's fossil fuel mix consists of coal, oil and natural gas. In
1994, Virginia Power consumed approximately 10.0 million tons of coal. As with
nuclear fuel, the Company utilizes both long-term contracts and spot purchases
to support its needs. The Company presently anticipates that sufficient coal
supplies at reasonable prices will be available for the remainder of the 1990s.
Current projections for an adequate supply of oil remain favorable, barring
unusual international events or extreme weather conditions which could affect
both price and supply.
The Company uses natural gas as needed throughout the year for two combined
cycle units and at several combustion turbine units. For winter usage at the
combined cycle sites, gas is purchased and stored during the summer and fall and
consumed during the colder months when gas supplies are not available at
favorable prices. The Company has firm transportation contracts for the delivery
of gas to the combined cycle units. Current projections indicate gas supplies
will be available for the next several years.
PURCHASES AND SALES OF POWER
Virginia Power relies on purchases of power to meet a portion of its
capacity requirements. The Company also makes economy purchases of power from
other utility systems when it is available at a cost lower than the Company's
own generation costs.
Under contracts effective January 1, 1985, Virginia Power agreed to
purchase 400 Mw of electricity annually through 1999 from Hoosier Energy Rural
Electric Cooperative, Inc. (Hoosier), and agreed to purchase 500 Mw of
electricity annually during 1987-99 from certain operating subsidiaries of
American Electric Power Company, Inc. (AEP).
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 then 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.
On June 28, 1994, FERC accepted a Power Sales Tariff filed by the Company
on March 8, 1994 and revised on May 27, 1994. This tariff allows the Company to
resell the 400 Mw Hoosier allotment to other eligible purchasers and also allows
the Company to sell system and emergency power.
Virginia Power also has 75 non-utility power purchase contracts with a
combined dependable summer capacity of 3,506 Mw. Of this amount, 3,244 Mw were
operational at the end of 1994 with the balance scheduled to come on-line
through 1997 (see NON-UTILITY GENERATION under FUTURE SOURCES OF POWER and Note
O to FINANCIAL STATEMENTS).
INTERCONNECTIONS
The Company maintains major interconnections with Carolina Power and Light
Company, 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.
7
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
transmission facilities. The proposed construction will consist of 212 miles of
new transmission lines and related substation improvements. The transmission
additions will include 116 miles of 765 Kv line to be constructed by Apco and
102 miles of 500 Kv line to be constructed by the Company. Completion of the
project, expected to be in service in the year 2000, will take 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.
FUTURE SOURCES OF POWER
The Company presently anticipates that system load growth will require
approximately 1,100 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 and CAPITAL REQUIREMENTS under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS).
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, 1994 amounted to $449.8 million.
Construction on Unit 1 is presently 98% complete and construction on Unit 2 is
54% 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, the Commission approved the
line in its Order Granting Application on May 11, 1994. A protestant group has
appealed that Order to the Virginia Supreme Court. Initial briefs of all parties
have been filed. Oral argument is expected to be scheduled during the first
quarter of 1995 and a decision of the Court is likely before mid-1995.
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 F to
FINANCIAL STATEMENTS.
8
NON-UTILITY GENERATION
NUMBER OF
PROJECTS MW
Projects Operational 65 3,244
Projects Financed 3 241
Unfinanced Projects 7 21
Total Contracts 75 3,506
COMPETITION
Competition is playing an increasingly important role in the Company's
business both in terms of source of power supply available to the Company and
alternative choices for customers meeting their energy needs. Both forms of
competition have increased as a result of changing federal and state
governmental regulations, technological developments, rising costs of
constructing generating facilities and availability of alternative energy
sources. The creation of exempt wholesale generators by the Energy Act and their
existence in the market for electric sales may have an impact on the Company's
plans for the construction or purchase of electric capacity and energy. In
addition, the Energy Act gives FERC broad power to require utilities to provide
transmission access to others. Exempt wholesale generators and other power
suppliers may seek, and FERC may require, access to the transmission systems of
investor-owned utilities, including the Company's system.
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 having discussions with these customers and has proposed a regulatory
initiative in Virginia that would enable it to provide on-site generation for
such customers (see VIRGINIA under RATES). The Company has undertaken
cost-cutting measures to maintain its position as a low-cost producer of
electricity and has pursued a strategic planning initiative, called Vision 2000,
to encourage innovative approaches to serving traditional markets and to prepare
appropriate methods by which to serve future markets. In furtherance of these
initiatives, the Company has established its nuclear and fossil and
hydroelectric operations as separate business units, has proposed innovative
pricing arrangements for incremental industrial loads in Virginia and North
Carolina, has executed long term contracts with key wholesale customers and
intends to provide an array of energy services to its customers.
Potential competition also exists for the Company's sales to its
cooperative and municipal customers. Virginia Power entered into discussions in
early 1993 with the City of Falls Church, Virginia, where it has approximately
4,100 customers, for the renewal of its franchise that expired on March 26,
1993. Before agreement on a new franchise, the City announced on October 12,
1994, that it would pursue the establishment of a municipal electric system or a
municipal purchasing agent and passed an ordinance purporting to extend the
Company's franchise until March 26, 1997. The City issued an "Informal Request
for Power Supply Proposal" to other electric suppliers on October 13, 1994 to
determine the interest in providing power to the City. On January 11, 1995, the
City sent to the Company a formal Request for Transmission Service pursuant to
Sections 211(a) and 213(a) of the Federal Power Act. The Company, consistent
with the State and Federal law, will still attempt to negotiate a new long term
franchise with the City while responding as required to the City's request for
transmission services.
See COMPETITION under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
CONSERVATION AND LOAD MANAGEMENT
The Company is committed to integrated resource planning and has developed
a detailed analysis procedure in which effective demand-side and supply-side
options are both considered in order to determine the least cost method to
satisfy the customers' needs. Demand-side programs are selected annually at
Virginia Power through an integrated resource planning process which directly
compares the stream of costs and benefits from supply-side and demand-side
options. This process ensures the ultimate selection of a demand-side package
which reduces the need for additional capacity while efficiently using the
Company's existing generation facilities.
ITEM 2. PROPERTIES
The Company owns its principal properties in fee (except as indicated
below), subject to defects and encumbrances that do not interfere materially
with their use. Substantially all of its property is subject to the lien of a
mortgage securing its First
9
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
transmission lines cross national parks and forests under permits entitling the
federal government to use, at specified charges, surplus capacity in the line if
any exists.
The Company leases certain buildings and equipment. See Note H to FINANCIAL
STATEMENTS.
See COMPANY GENERATING UNITS under SOURCES OF POWER under Item 1. BUSINESS.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company may be in violation of or in default under
orders, statutes, rules or regulations relating to protection of the
environment, compliance plans imposed upon or agreed to by the Company or
permits issued by various local, state and federal agencies for the construction
or operation of facilities. There may be pending from time to time
administrative proceedings involving violations of state or federal
environmental regulations that the Company believes are not material with
respect to it and for which its aggregate liability for fines or penalties will
not exceed $100,000. There are no material agency enforcement actions or citizen
suits pending or, to the Company's present knowledge, threatened against the
Company.
Virginia Power is involved in an arbitration with Smith Cogeneration of
Virginia, Inc. (SCV) before the Virginia Commission concerning the terms of the
purchase of power from two 158 megawatt generating units to be developed by SCV.
The arbitrator has submitted his Report to the Commission recommending that the
parties enter into a contract containing terms that would require Virginia Power
to pay what it considers to be excessive amounts for the power to be purchased.
The parities have been given until March 31, 1995 to file comments on the
Arbitrator's Report.
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 purchased power contract. Doswell 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 issues
of actual and constructive fraud were dismissed from the case, with prejudice,
leaving only the contract claim, which reduced alleged damages to approximately
$19 million. On March 2, 1995, the Court announced its verdict in favor of
Virginia Power.
On February 23, 1994, Virginia Power filed with the Virginia Commission a
Petition for Declaratory Judgment seeking a declaration that an arrangement
proposed by E.I. DuPont de Nemours & Company (DuPont) and LG&E Power, Inc.
(LG&E) for a partnership between those two companies to furnish energy services
to DuPont in Virginia Power's service territory is illegal under Virginia law.
DuPont filed a Motion to dismiss for lack of jurisdiction, to which Virginia
Power responded. Prior to any action by the Commission, DuPont and LG&E
announced that they had terminated their negotiations, and the Commission has
directed the parties to comment on whether the proceeding should be dismissed.
On January 13, 1995, Virginia Power filed its response stating that the case
should not be dismissed in the absence of a clear statement on the record by
both DuPont and LG&E that each has abandoned the power partnering concept in
Virginia Power's service territory. DuPont renewed its Motion to Dismiss and the
Commission entered its dismissal order on January 24, 1995.
A dispute over corporate governance issues between Dominion Resources and
Virginia Power arose in 1994. On June 17, 1994, Dominion Resources and Virginia
Power received an order from the Virginia Commission (the 1994 Order) that,
among other things, initiated an investigation into the affiliate relationships
and corporate governance issues between Dominion Resources and Virginia Power
(the First Proceeding). The text of the 1994 Order was set forth in the
Company's Current Report on Form 8-K of June 17, 1994. Between June and August
1994, Dominion Resources and Virginia Power made various filings with the
Commission, and the Commission issued several procedural orders, in connection
with the First Proceeding. A description of those filings and orders is set
forth in the Company's Quarterly Report on Form 10-Q for the period ending June
30, 1994.
On August 15, 1994, Dominion Resources, Virginia Power and their respective
directors entered into a Settlement Agreement resolving certain of the disputed
corporate governance issues. The terms of that settlement are summarized in the
Company's Current Report on Form 8-K of August 17, 1994. Pursuant to the
Settlement Agreement, Dominion Resources and Virginia Power filed a Joint Motion
to Dismiss certain of the corporate governance issues from the First Proceeding.
The Commission denied that Motion on August 24, 1994, continued the First
Proceeding, and instituted a new proceeding (the Second Proceeding) into the
holding company structure and the relationship between Dominion Resources and
Virginia
10
Power. The Commission stated that the Second Proceeding would be an
"investigation directed not at averting a crisis or penalizing past conduct, but
toward protecting the public interest in the future." The Commission directed
its Staff to conduct an investigation and file an interim report on or before
December 1, 1994.
On December 1, 1994, the Staff of the Virginia Commission and its
consultants filed an Interim Report in the Second Proceeding. That Report is
included in the Company's Current Report on Form 8-K of December 5, 1994. The
Interim Report made numerous recommendations for Commission involvement in
matters of corporate governance, corporate structure, affiliate service
arrangements, and operating relationships between Dominion Resources and
Virginia Power, and suggested certain financial constraints on Dominion
Resources and new regulatory authority for the Commission. Many of these
suggestions were far-reaching. On December 21, 1994, Dominion Resources and
Virginia Power filed a Joint Response to the Interim Report, in which they
accepted some of the recommendations and urged that the corporate governance
structure established by the Settlement Agreement continue while they considered
the other recommendations in the course of a strategic planning effort by
Dominion Resources.
On January 23, 1995, the Staff of the Virginia Commission issued a report
in the Second Proceeding on its investigation of a coal transportation contract
between the Company and CSX Transportation. The Staff's report concluded that
Dominion Resources improperly pressured Virginia Power to renegotiate the
contract, and recommended that approximately $11 million ($8.3 million Virginia
jurisdictional) of the coal transportation costs incurred under the contract
from 1991 through May 31, 1994 be disallowed in determining Virginia Power's
rates. The Staff's report further recommended that any future transportation
costs that it identified as excess be disallowed over the remainder of the
contract, which expires on May 31, 2000.
The Company has recorded a regulatory liability of $10.5 million at
December 31, 1994. The Company currently estimates that the total amount called
into question by the Virginia Commission Staff report is a net present value of
$60 million ($100 million over the life of the contract). On February 1, 1995,
without admitting any imprudence, fault or liability, and believing that their
relationship with the Commission would be enhanced, Dominion Resources and the
Company filed a motion offering to refund to the Company's customers $8.3
million in settlement of these issues regarding transportation rates.
During the 1995 session of the Virginia General Assembly, the Virginia
Commission caused legislation to be introduced that addressed the Commission's
authority to intervene in disputes involving public utilities owned by separate
holding companies. That legislation was opposed by Dominion Resources. On
February 20, 1995, the proposed legislation was withdrawn and Dominion
Resources, Virginia Power and the Virginia Commission Staff consented to an
order that is included in Virginia Power's Current Report on Form 8-K of
February 21, 1995. Under this order, which will be effective until July 2, 1996,
Dominion Resources must obtain the Commission's approval before taking steps
such as removing Virginia Power's board members or officers or changing Virginia
Power's articles of incorporation or by-laws. Although the order imposes for a
period of time significant restrictions on the ability of Dominion Resources to
select the Board and management of its subsidiary, Dominion Resources and
Virginia Power agreed to the order in the interest of enhancing relations with
the Virginia Commission and achieving the purposes of the Settlement Agreement.
Disagreements between the companies have arisen from time to time since the
Settlement Agreement was executed. On February 28, 1995, upon recommendation of
a Joint Committee created under the Settlement Agreement, the Boards of Dominion
Resources and Virginia Power took further action to enhance cooperation between
the two companies and their relationship with the Virginia Commission. Among
other things, the Boards expanded the authority of the Joint Committee to act
for the Boards on issues presented to it by the chief executives of the
companies. Each Board directed corporate officials and employees of its company
to cooperate fully with the Joint Committee in resolution of issues acted on by
the Committee and to support actions taken by the Committee. In connection with
these initiatives, the chief executive officers of both companies made known
their intentions to retire in July 1996 and the Boards directed the development
of executive succession plans for each company. Also, the Dominion Resources
Board received the resignations of directors Bruce C. Gottwald and John W. Snow
and the Virginia Power Board received the resignations of directors William W.
Berry and Frank S. Royal, and both Boards voted to reduce their size by two
members.
At this time, Virginia Power is unable to predict the ultimate resolution
of these matters or their effect on the Company.
11
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 1994 and 1993, the Company paid quarterly cash dividends on its
Common Stock as follows:
1ST 2ND 3RD 4TH
(MILLIONS)
1994................................ $97.7 $98.2 $99.0 $100.6
1993................................ $93.3 $93.9 $94.5 $ 97.2
ITEM 6. SELECTED FINANCIAL DATA
1994 1993 1992 1991 1990
(MILLIONS, EXCEPT PERCENTAGES)
Operating revenues........................ $4,170.8 $4,187.3 $3,679.6 $3,688.1 $3,461.5
Operating income.......................... 731.4 813.4 761.6 816.8 805.8
Income before cumulative effect of a
change in accounting principle.......... 447.1 509.0 455.2 487.4 450.3
Cumulative effect of a change in
accounting principle.................... 14.3
Net income................................ 447.1 509.0 469.5 487.4 450.3
Balance available for Common Stock........ 404.9 466.9 423.8 435.9 392.2
Total assets.............................. 11,647.9 11,520.5 11,316.7 10,205.0 10,105.4
Total net utility plant................... 9,623.4 9,459.0 9,254.7 9,064.6 8,830.8
Long-term debt, noncurrent capital
lease obligations and preferred
stock subject to
mandatory redemption.................... 4,157.5 4,151.1 4,089.5 4,119.9 4,146.8
Utility plant expenditures
(including nuclear fuel)................ 660.9 712.8 716.5 727.8 803.4
Capitalization ratios (percent):
Debt.................................... 46.7 46.4 46.3 47.4 49.1
Preferred stock......................... 9.0 9.2 9.7 9.0 9.4
Common equity........................... 44.3 44.4 44.0 43.6 41.5
Embedded cost (percent):
Long-term debt.......................... 7.65 7.67 7.86 8.43 8.80
Preferred stock......................... 5.47 4.88 5.38 6.54 7.40
Weighted average........................ 7.29 7.18 7.42 8.11 8.57
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, 74
percent of the Company's cash requirements over the past three years.
Net cash provided by operating activities decreased by $4.6 million in 1994
as compared to 1993, primarily as a result of a number of factors resulting from
normal operations, partially offset by a rate refund of $129.2 million in 1994.
12
Net cash provided by operating activities decreased $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 from (to) financing activities was as follows:
1994 1993 1992
(MILLIONS)
Common stock................................................ $ 75.0 $ 50.0 $ 75.0
Preferred stock............................................. 150.0 240.0
Mortgage bonds.............................................. 325.0 1,035.0 1,125.0
Medium-term notes........................................... 100.0 60.0
Pollution control securities................................ 39.0 56.0
Repayment of long-term debt and preferred stock............. (334.3) (1,072.1) (1,315.0)
Dividends................................................... (438.2) (421.1) (416.1)
Other....................................................... (50.8) (89.8) (154.3)
Total.................................................. $ (284.3) $ (348.0) $ (329.4)
The Company sold $325.0 million of First and Refunding Mortgage Bonds in
1994. With a portion of the proceeds, the Company refinanced $119.0 million of
its higher-cost debt. The remainder of the proceeds was used to meet a portion
of the Company's capital requirements.
In 1994, the Company also issued $100 million of unsecured Medium-Term
Notes with annual interest rates ranging from 6.15% to 7.27%, the proceeds of
which were used to meet a portion of the Company's capital requirements. The
Company also issued $39 million of variable and fixed rate Pollution Control
Securities in 1994 to refinance $39 million of higher-cost Pollution Control
Securities.
In 1994, the Company issued to Dominion Resources $75 million of Common
Stock.
During the year, the Company retired $166.5 million of securities through
mandatory debt maturities and sinking fund requirements and repurchased $7.5
million of its debt securities and $2.3 million of preferred stock.
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. At December 31,
1994, no amount was outstanding under this program.
Cash from (used in) investing activities was as follows:
1994 1993 1992
(MILLIONS)
Utility plant expenditures.................................. $ (580.9) $ (644.9) $ (662.2)
Nuclear fuel................................................ (80.0) (67.9) (54.3)
Nuclear decommissioning contributions....................... (24.5) (24.4) (24.3)
Pollution control project funds............................. 6.9 32.7 (55.3)
Sale of accounts receivable................................. (40.0)
Other....................................................... (8.3) (13.9) (5.5)
Total..................................................... $ (726.8) $ (718.4) $ (801.6)
Investing activities in 1994 resulted in a net cash outflow of $726.8
million primarily due to $580.9 million of construction expenditures and $80
million of nuclear fuel expenditures. Of the construction expenditures,
approximately $67.3 million was spent on new generating facilities, $173.8
million on other production projects, and $291.3 million on transmission and
distribution projects.
CAPITAL REQUIREMENTS
The Company presently anticipates that kilowatt-hour sales will grow
approximately 2.1 percent a year through 2014. Capacity needed to support this
growth will be provided through a combination of Company-constructed generating
units, purchases from non-utility generators and other utility generators. Each
of these options plays an important role in the Company's overall plan to meet
capacity needs.
The Company's construction and nuclear fuel expenditures (excluding AFC),
during 1995, 1996 and 1997 are expected to aggregate $673.2 million, $600.3
million and $615.2 million, respectively. Construction continues on the 782 Mw
coal-
13
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 $533.0 million of which $449.8 million had been
incurred as of December 31, 1994. 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 2005, the Company will need to add only peaking units to meet
anticipated demand.
The Company will require $312.2 million to meet long-term debt maturities
in 1995. The Company presently estimates that, for 1995, 82 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
1994 as compared to 1993, and 1993 as compared to 1992.
1994 COMPARED TO 1993
OPERATING REVENUES changed principally due to the following:
INCREASE
(DECREASE) FROM
PRIOR YEAR
1994 1993
(MILLIONS)
Kwh sales........................... $ 22.5 $ 333.5
Change in base rates................ (35.0) 230.7
Fuel cost recovery.................. (7.9) (55.2)
Other, net.......................... 3.9 (1.3)
Total............................. $(16.5) $ 507.7
As detailed in the chart above, the decrease in revenues is primarily due
to a decrease in base revenues.
Base revenues were lower in 1994 primarily as a result of additional
revenue reserves established during the year.
During 1994, the Company had 46,741 new connections to its system compared
to 43,014 and 39,807 in 1993 and 1992, respectively.
Kilowatt-hour sales changed as follows:
INCREASE
(DECREASE) FROM
PRIOR YEAR
1994 1993
Residential......................... (1.0)% 9.3%
Commercial.......................... 0.8 4.7
Industrial.......................... 5.4 4.5
Public authorities.................. (0.3) 5.3
Total retail sales.................. 0.7 6.4
Resale.............................. 4.1 47.3
Total sales......................... 1.1 9.6
The increase in kilowatt-hour sales in 1994 as compared to 1993 reflects
the extreme weather experienced in January 1994, partially offset by lower sales
during the second half of 1994, due to milder weather. The number of actual
cooling degree days in 1994 was 5.7 percent above the normal number of cooling
degree days and the number of actual heating degree days was 3.8 percent below
the number of normal heating degree days. The increase in kilowatt-hour sales in
1993 as compared to 1992 reflects the warmer than normal summer weather in 1993
as compared to the moderate 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 increase in sales for resale in 1993 as compared to 1992 was primarily
due to the sale of firm capacity and associated energy to ODEC. Under the terms
of the agreement signed November 26, 1991, the Company is committed to sell up
to 300 Mw of capacity to ODEC through the commercial operation date of Clover
Power Station.
14
The average fuel cost of system energy output is shown below:
MILLS PER KILOWATT-HOUR
1994 1993 1992
Nuclear............................. 4.89 4.60 4.67
Coal................................ 14.61 14.69 14.87
Oil................................. 23.00 26.55 26.61
Purchased power, net................ 23.99 24.54 25.94
Other............................... 25.46 24.35 24.45
Average fuel cost................... 14.02 14.42 13.84
System energy output is shown below:
ESTIMATED ACTUAL
1995 1994 1993 1992
Nuclear(*).......................... 28% 34 % 31 % 35 %
Coal................................ 42 36 39 41
Oil................................. 1 3 3 2
Purchased power, net................ 26 23 23 19
Other............................... 3 4 4 3
100% 100 % 100 % 100 %
(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power
Station (see Note F to FINANCIAL STATEMENTS).
OPERATION EXPENSES-OTHER increased as compared to 1993 primarily as a
result of recognition of costs associated with the Early Retirement and
Voluntary Separation Programs offered by the Company in 1994.
INCOME TAXES-OPERATING decreased as compared to 1993 primarily as a result
of decreased pretax book income.
INTEREST CHARGES-OTHER decreased in 1994 primarily as a result of a
reduction of $10.6 million in the interest accrued for prior years on certain
tax obligations.
1993 COMPARED TO 1992
FUEL, NET 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.
PURCHASED POWER CAPACITY, NET resulted in an increase in 1993. In 1992, the
Company implemented deferral accounting for certain capacity expenses. The
increase in expense in 1993 primarily reflects the recovery of expenses deferred
in 1992.
OPERATION EXPENSES, OTHER increased as compared to 1992 primarily as a
result of the increased expenses associated with accrual of other postretirement
benefits due to the implementation of Statement of Financial Accounting
Standards (SFAS) No. 106, "Employers' Accounting for Postretirement Benefits
Other than Pensions" effective January 1, 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.
OTHER INCOME AND OTHER INTEREST CHARGES decreased as compared to 1992
primarily as a result of a reclassification of the imputed interest on the
nuclear decommissioning obligation which was previously included in Other
Interest Charges ($14.8 million) and is now included in OTHER INCOME, as
approved by FERC. This increase was 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 Statement of Financial
Accounting Standards (SFAS) 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 SFAS No. 109
15
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.
FUTURE ISSUES
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.
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. These 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; however, 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 and will be applicable to the Company as
Virginia Pollution Discharge Elimination System Permits are reissued. 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 $67.3 million, $72.2 million and $65.2 million
(including depreciation) during 1994, 1993 and 1992, respectively, in connection
with the use of environmental protection facilities and expects these expenses
to be approximately $64.3 million in 1995. In addition, capital expenditures to
limit or monitor hazardous substances were $4.0 million, $3.6 million and $6.6
million for 1994, 1993 and 1992, respectively. The amount estimated for 1995 for
these expenditures is $33.1 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. 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 is administered by the EPA.
The Company is assessing the economic reasonableness of constructing two
additional scrubbers at its Mt. Storm Power Station or acquiring allowances as a
means of maintaining compliance with the Air Act's standards.
For additional information on the Clean Air Act, see REGULATION under Item
1. BUSINESS.
16
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 continuing 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 1994, the Company's four nuclear units operated at a combined capacity
factor of 86.7 percent, reflecting a record 31 day refueling outage at North
Anna Unit 1, a 63 day refueling/ten-year in-service inspection outage at Surry
Unit 1, and two scheduled steam generator chemical cleaning outages at Surry
Units 1 and 2, which took 27 and 21 days respectively. Nuclear refueling outages
typically occur every eighteen months and last 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 an outage should result in increased availability of low-cost
nuclear generation, thereby lowering expenses. Three refueling outages are
currently scheduled in 1995. The North Anna Unit 2 outage will include steam
generator replacement. The Surry Unit 2 outage will include a ten year
in-service inspection while the Surry Unit 1 outage will be for 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 North Anna Unit 1 steam generators was completed in 1993
at a cost of $106 million. Replacement of the North Anna Unit 2 steam generators
is scheduled for 1995 at a total estimated Company cost of $110 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 and Unit 2 are expected to be recovered through rates.
The NRC has proposed revisions to the nuclear power plant license renewal
rules issued in 1991. The Company intends to work with industry groups on life
extension programs, and comment on the proposed rulemaking.
In addition to improving nuclear unit productivity and efficiency, the
Company has completed engineering analyses and evaluations to support uprating
the capability of the units. The plant modifications have been completed at the
North Anna facility, and the upgraded core improvement has resulted in a 4.2%
increase in the gross electrical output for each of the units. A similar project
has been initiated to uprate both Surry Units 1 and 2 in 1995. Analyses and
evaluations to support the uprate have been completed and a license amendment is
pending before the Nuclear Regulatory Commission.
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 to provide transmission
services, under certain conditions.
FERC has completed an industry-wide formal inquiry aimed at reforming the
pricing of transmission services. The Company was 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 plan facilities 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 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 ultimate customers. Broader retail competition
that would allow customers to choose among electric suppliers has been the
subject of intense debate in federal and state
17
forums. If such competition were to develop, it would have the potential to
shift costs among customer classes and to create significant transitional costs.
Certain state actions that affect retail competition may be preempted by federal
law.
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 material loss of load, revenues or net income due to competition
for its customers. The Company believes it has a strong capability to meet
future competition.
For additional information on competition, see COMPETITION under Item 1.
BUSINESS.
In accordance with SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation", the Company's financial statements reflect assets and
costs based on current cost-based ratemaking regulations. Continued accounting
under SFAS 71 requires that the following criteria be met:
a) A utility's rates for regulated services provided to its customers
are established by, or are subject to approval by, an independent
third-party regulator;
b) The regulated rates are designed to recover specific costs of
providing the regulated services or products; and
c) In view of the demand for the regulated services and the level of
competition, direct and indirect, it is reasonable to assume that rates set
at levels that will recover a utility's costs can be charged to and
collected from customers. This criterion requires consideration of
anticipated changes in levels of demand or competition during the recovery
period for any capitalized costs.
A utility's operations or portion of operations can cease to meet these
criteria for various reasons, including a change in the method of regulation or
a change in the competitive environment for regulated services. A utility whose
operations or portion of operations cease to meet these criteria should
discontinue application of SFAS 71 and write-off any regulatory assets and
liabilities for those operations that no longer meet the requirements of SFAS
71. The Company's operations currently satisfy the SFAS 71 criteria. However, if
events or circumstances should change so that those criteria are no longer
satisfied, Management believes that a material adverse effect on the Company's
results of operations and financial position may result.
COMMITMENTS AND CONTINGENCIES
A dispute over corporate governance issues between Dominion Resources and
Virginia Power arose in 1994. In connection with that dispute, the Virginia
Commission commenced proceedings investigating these and related issues. A
Settlement Agreement was entered into by the two Companies and their respective
Boards with respect to these matters in August 1994. The Settlement Agreement is
also described in Item 3. LEGAL PROCEEDINGS.
During the 1995 session of the Virginia General Assembly, the Virginia
Commission caused legislation to be introduced that addressed the Commission's
authority to intervene in disputes involving public utilities owned by separate
holding companies. That legislation was opposed by Dominion Resources. On
February 20, 1995, the proposed legislation was withdrawn and Dominion
Resources, Virginia Power and the Virginia Commission Staff consented to an
order that is included in Virginia Power's Current Report on Form 8-K of
February 21, 1995. Under this order, which will be effective until July 2, 1996,
Dominion Resources must obtain the Commission's approval before taking steps
such as removing Virginia Power's board members or officers or changing Virginia
Power's articles of incorporation or by-laws. Although the order imposes for a
period of time significant restrictions on the ability of Dominion Resources to
select the Board and management of its subsidiary, Dominion Resources and
Virginia Power agreed to the order in the interest of enhancing relations with
the Virginia Commission and achieving the purposes of the Settlement Agreement.
Disagreements between the companies have arisen from time to time since the
Settlement Agreement was executed. On February 28, 1995, upon recommendation of
a Joint Committee created under the Settlement Agreement, the Boards of Dominion
Resources and Virginia Power took further action to enhance cooperation between
the two companies and their relationship with the Virginia Commission. Among
other things, the Boards expanded the authority of the Joint Committee to act
for the Boards on issues presented to it by the chief executives of the
companies. Each Board directed corporate officials and employees of its company
to cooperate fully with the Joint Committee in resolution of issues acted on by
the Committee and to support actions taken by the Committee. In connection with
these initiatives, the chief executive officers of both companies made known
their intentions to retire in July 1996 and the Boards directed the development
of executive succession plans for each company. Also, the Dominion Resources
Board received the resignations of directors Bruce C. Gottwald and John W. Snow
and the Virginia Power Board received the resignations of directors William W.
Berry and Frank S. Royal, and both Boards voted to reduce their size by two
members.
At this time, Virginia Power is unable to predict the ultimate resolution
of these matters or their effect on the Company.
18
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
PAGE
NO.
Report of Management........................................................................................ 20
Report of Independent Auditors.............................................................................. 21
Statements of Income for the years ended December 31, 1994, 1993 and 1992................................... 22
Balance Sheets at December 31, 1994 and 1993................................................................ 23
Statements of Earnings Reinvested in Business for the years ended December 31, 1994, 1993 and 1992.......... 25
Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992............................... 26
Notes to Financial Statements............................................................................... 27
19
REPORT OF MANAGEMENT
The Company's management is responsible for all information and
representations contained in the Financial Statements and other sections of the
Company's annual report on Form 10-K. The Financial Statements, which include
amounts based on estimates and judgments of management, have been prepared in
conformity with generally accepted accounting principles. Other financial
information in the Form 10-K is consistent with that in the Financial
Statements.
Management maintains a system of internal accounting controls designed to
provide reasonable assurance, at a reasonable cost, that the Company's assets
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. Management believes that
during 1994 the system of internal control was adequate to accomplish the
intended objective.
The Financial Statements have been audited by Deloitte & Touche LLP,
independent auditors, whose designation was approved by the Board of Directors.
Their audits were conducted in accordance with generally accepted auditing
standards and included a review of the Company's accounting systems, procedures
and internal controls, and the performance of tests and other auditing
procedures sufficient to provide reasonable assurance that the Financial
Statements are not materially misleading and do not contain material errors.
The Audit Committee of the Board of Directors, composed entirely of
directors who are not officers or employees of the Company, meets periodically
with the independent auditors, the internal auditors and management to discuss
auditing, internal accounting control and financial reporting matters and to
ensure that each is properly discharging its responsibilities. Both the
independent auditors and the internal auditors periodically meet alone with the
Audit Committee and have free access to the Committee at any time.
Management recognizes its responsibility for fostering a strong ethical
climate so that the Company's affairs are conducted according to the highest
standards of personal and corporate conduct. This responsibility is
characterized and reflected in the Company's Code of Ethics, which is
distributed throughout the Company. The Code of Ethics addresses, among other
things, the importance of ensuring open communication within the Company;
potential conflicts of interest; compliance with all domestic and foreign laws,
including those relating to financial disclosure; the confidentiality of
proprietary information; and full disclosure of public information.
VIRGINIA ELECTRIC AND POWER COMPANY
J. T. Rhodes R. E. Rigsby
President and Senior Vice President-Finance
Chief Executive & Controller
Officer
20
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors of Virginia Electric and Power Company:
We have audited the accompanying balance sheets of Virginia Electric and
Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) as of
December 31, 1994 and 1993 and the related statements of income, earnings
reinvested in business, and cash flows for each of the three years in the period
ended December 31, 1994. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Virginia Electric and Power Company at
December 31, 1994 and 1993 and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1994 in conformity
with generally accepted accounting principles.
The Company changed its methods of accounting for postretirement benefits
other than pensions in 1993 (see Note M) and for accounting for income taxes in
1992 (see Note B) in order to conform with recently issued accounting standards.
DELOITTE & TOUCHE LLP
Richmond, Virginia
February 6, 1995
21
VIRGINIA ELECTRIC AND POWER COMPANY
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31,
1994 1993 1992
(MILLIONS)
Operating revenues................................................ $4,170.8 $4,187.3 $3,679.6
Operating expenses:
Operation:
Fuel, net.................................................... 973.0 959.5 917.9
Purchased power capacity, net................................ 669.4 646.1 348.8
Other........................................................ 577.4 525.7 477.7
Maintenance..................................................... 263.2 279.5 280.6
Depreciation and amortization................................... 446.3 426.8 399.9
Amortization of terminated construction project costs........... 34.4 36.1 37.7
Taxes -- Income................................................. 223.0 253.5 222.2
-- Other.................................................. 252.7 246.7 233.2
Total...................................................... 3,439.4 3,373.9 2,918.0
Operating income.................................................. 731.4 813.4 761.6
Other income...................................................... 10.9 11.4 19.3
Income before interest charges.................................... 742.3 824.8 780.9
Interest charges:
Interest on long-term debt...................................... 291.9 300.2 300.9
Other........................................................... 7.5 19.1 29.5
Allowance for borrowed funds used during construction........... (4.2) (3.5) (4.7)
Total...................................................... 295.2 315.8 325.7
Income before cumulative effect of a change in accounting
principle....................................................... 447.1 509.0 455.2
Cumulative effect on prior years of changing method of accounting
for income taxes................................................ 14.3
Net income........................................................ 447.1 509.0 469.5
Preferred dividends............................................... 42.2 42.1 45.7
Balance available for Common Stock................................ $ 404.9 $ 466.9 $ 423.8
The accompanying notes are an integral part of the financial statements.
22
VIRGINIA ELECTRIC AND POWER COMPANY
BALANCE SHEETS
ASSETS
AT DECEMBER 31,
1994 1993
(MILLIONS OF DOLLARS)
UTILITY PLANT:
Plant (includes plant under construction of $828.2 in 1994 and $913.1 in
1993).................................................................... $13,896.6 $13,376.1
Less accumulated depreciation............................................... 4,426.9 4,065.9
9,469.7 9,310.2
Nuclear fuel (less accumulated amortization of $663.5 in 1994 and $665.3 in
1993).................................................................... 153.7 148.8
Total net utility plant................................................ 9,623.4 9,459.0
INVESTMENTS:
Nuclear decommissioning trust funds......................................... 260.9 226.4
Pollution control project funds............................................. 20.3 27.2
Other....................................................................... 21.1 21.5
Total net investments.................................................. 302.3 275.1
CURRENT ASSETS:
Cash and cash equivalents................................................... 28.8 21.6
Customer accounts receivable (less allowance for doubtful accounts of $1.7
in 1994 and 1993)........................................................ 202.7 202.9
Accrued unbilled revenues................................................... 97.4 105.7
Materials and supplies at average cost or less:
Plant and general........................................................ 186.7 182.0
Fossil fuel.............................................................. 122.9 121.0
Other....................................................................... 104.9 112.2
Total current assets................................................... 743.4 745.4
DEFERRED DEBITS AND OTHER ASSETS:
Regulatory assets........................................................... 871.0 930.5
Unamortized debt issuance costs............................................. 22.8 23.7
Other....................................................................... 85.0 86.8
Total deferred debits and other assets................................. 978.8 1,041.0
Total assets........................................................... $11,647.9 $11,520.5
The accompanying notes are an integral part of the financial statements.
23
VIRGINIA ELECTRIC AND POWER COMPANY
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
AT DECEMBER 31,
1994 1993
(MILLIONS OF DOLLARS)
LONG-TERM DEBT................................................................ $ 3,910.4 $ 3,899.9
PREFERRED STOCK:
Preferred stock subject to mandatory redemption............................. 221.7 224.0
Preferred stock not subject to mandatory redemption......................... 594.0 594.0
COMMON STOCKHOLDER'S EQUITY:
Common Stock, no par, 300,000 shares authorized, 171,484 shares outstanding
at December 31, 1994 and 168,277 shares outstanding at December 31,
1993..................................................................... 2,737.4 2,662.4
Other paid-in capital....................................................... 20.4 20.3
Earnings reinvested in business............................................. 1,277.8 1,269.3
Total common stockholder's equity...................................... 4,035.6 3,952.0
CURRENT LIABILITIES:
Securities due within one year.............................................. 312.2 167.3
Short-term debt............................................................. 43.0
Accounts payable, trade..................................................... 318.3 297.2
Customer deposits........................................................... 55.0 53.9
Payrolls accrued............................................................ 59.5 68.3
Provision for rate refunds.................................................. 12.2 101.7
Interest accrued............................................................ 96.2 101.7
Other....................................................................... 95.7 86.0
Total current liabilities.............................................. 949.1 919.1
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes........................................... 1,466.7 1,449.7
Deferred investment tax credits............................................. 289.2 306.3
Deferred fuel expenses...................................................... 51.5 54.1
Other....................................................................... 129.7 121.4
Total deferred credits and other liabilities........................... 1,937.1 1,931.5
COMMITMENTS AND CONTINGENCIES (See Note O)
Total liabilities and shareholders' equity............................. $11,647.9 $11,520.5
The accompanying notes are an integral part of the financial statements.
24
VIRGINIA ELECTRIC AND POWER COMPANY
STATEMENTS OF EARNINGS REINVESTED IN BUSINESS
FOR THE YEARS ENDED DECEMBER 31,
1994 1993 1992
(MILLIONS)
Balance at beginning of year...................................... $1,269.3 $1,182.7 $1,132.9
Net income........................................................ 447.1 509.0 469.5
Total...................................................... 1,716.4 1,691.7 1,602.4
Cash dividends:
Preferred stock subject to mandatory redemption................. 14.4 17.2 22.4
Preferred stock not subject to mandatory redemption............. 28.3 25.0 23.9
Common Stock.................................................... 395.5 378.9 369.8
Total dividends............................................ 438.2 421.1 416.1
Other deductions, net............................................. 0.4 1.3 3.6
Balance at end of year............................................ $1,277.8 $1,269.3 $1,182.7
The accompanying notes are an integral part of the financial statements.
25
VIRGINIA ELECTRIC AND POWER COMPANY
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31,
1994 1993 1992
(MILLIONS)
Cash Flow From Operating Activities:
Net income............................................................... $ 447.1 $ 509.0 $ 469.5
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....................................... 558.3 546.6 547.9
Allowance for other funds used during construction.................. (6.4) (5.1) (4.8)
Deferred income taxes............................................... 56.7 (6.7) 105.1
Deferred investment tax credits..................................... (17.1) (19.2) (19.4)
Noncash return of terminated construction project costs-pretax...... (10.3) (11.9) (13.7)
Deferred fuel expenses, net......................................... (2.6) (36.1) 45.2
Deferred capacity expenses.......................................... 26.5 72.9 (102.7)
Changes in:
Accounts receivable.............................................. 36.5 (33.6) (34.1)
Accrued unbilled revenues........................................ 11.9 (6.3) 2.8
Materials and supplies........................................... (6.5) 27.5 (33.8)
Accounts payable, trade.......................................... 21.1 18.4 79.2
Accrued expenses................................................. (29.0) 28.2 (26.7)
Provision for rate refunds....................................... (89.5) (87.6) 161.9
Other............................................................... 21.6 26.8 12.9
Net Cash Flow From Operating Activities.................................... 1,018.3 1,022.9 1,175.0
Cash Flow From (To) Financing Activities:
Issuance of Common Stock................................................. 75.0 50.0 75.0
Issuance of preferred stock.............................................. 150.0 240.0
Issuance of long-term debt............................................... 464.0 1,035.0 1,241.0
Repayment of short-term debt............................................. (43.0) (6.5) (55.4)
Inter-company credit agreement........................................... (32.5)
Repayment of long-term debt and preferred stock.......................... (334.3) (1,072.1) (1,315.0)
Common Stock dividend payments........................................... (395.5) (378.9) (369.8)
Preferred stock dividend payments........................................ (42.7) (42.2) (46.3)
Other.................................................................... (7.8) (83.3) (66.4)
Net Cash Flow From (To) Financing Activities............................... (284.3) (348.0) (329.4)
Cash Flow From (Used In) Investing Activities:
Utility plant expenditures (excluding AFC-other funds)................... (580.9) (644.9) (662.2)
Nuclear fuel (excluding AFC-other funds)................................. (80.0) (68.1) (54.3)
Pollution control project funds.......................................... 6.9 32.7 (55.3)
Nuclear decommissioning contributions.................................... (24.5) (24.4) (24.3)
Sale of accounts receivable.............................................. (40.0)
Other.................................................................... (8.3) (13.7) (5.5)
Net Cash Flow From (Used In) Investing Activities.......................... (726.8) (718.4) (801.6)
Increase (Decrease) in cash and cash equivalents........................... 7.2 (43.5) 44.0
Cash and cash equivalents at beginning of year............................. 21.6 65.1 21.1
Cash and cash equivalents at end of year................................... $ 28.8 $ 21.6 $ 65.1
Cash paid during the year for:
Interest (reduced for the cost of borrowed funds capitalized as AFC)..... $ 302.9 $ 324.8 $ 325.3
Income taxes............................................................. 190.5 268.1 163.8
Non-cash transactions for financing and investing activities:
Assumption of obligations................................................ 26.3
Acquisition of utility property.......................................... 26.3
The accompanying notes are an integral part of the financial statements.
26
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 1994, 1993
and 1992.
Operating expenses include amortization of nuclear fuel, which is provided
on a unit of production basis sufficient to fully amortize, over the estimated
service life, the cost of the fuel plus permanent storage and disposal costs.
FEDERAL INCOME TAXES
The Company adopted 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. 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 borrowed funds used for construction
purposes and a reasonable rate on other funds when so used.
The pretax AFC rates for 1994, 1993 and 1992 were 8.9, 9.4 and 10.3
percent, respectively. Approximately 83 percent of the Company's construction
work in progress is now included in rate base, and a cash return is collected
currently thereon.
DEFERRED CAPACITY AND FUEL EXPENSE
In 1992, the Company began to defer certain capacity expenses based on an
order of the Virginia Commission. Approximately 80 percent of capacity expenses
and 90 percent of fuel expenses are subject to deferral accounting. The
difference
27
between reasonably incurred actual expenses and the level of expenses included
in current rates is deferred and matched against future revenues.
AMORTIZATION OF DEBT ISSUANCE COSTS
The Company defers and amortizes any expenses incurred in the issuance of
long-term debt, including premiums and discounts associated with such debt over
the lives of the respective issues. Any gains or losses resulting from the
refinancing of debt are also deferred and amortized over the lives of the new
issues of long-term debt as permitted by the appropriate regulatory
jurisdictions. Gains or losses resulting from the redemption of debt without
refinancing are amortized over the remaining lives of the redeemed issues.
CASH AND OTHER INVESTMENTS
Current banking arrangements generally do not require checks to be funded
until actually presented for payment. At December 31, 1994 and 1993, the
Company's accounts payable included the net effect of checks outstanding but not
yet presented for payment of $66.8 million and $72.5 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 1993 and 1992 financial statements have been
reclassified to conform to the 1994 presentation.
B. INCOME TAXES:
Details of income tax expense are as follows:
YEARS
1994 1993 1992
(MILLIONS)
Current expense:
Federal............................................................ $ 185.6 $ 283.0 $ 142.9
State.............................................................. 2.1 (0.3) 3.0
187.7 282.7 145.9
Deferred expense:
Plant related items................................................ 39.0 45.0 53.3
Deferred fuel and capacity......................................... (8.2) (12.9) 19.5
Debt issuance costs................................................ 3.7 8.3 15.4
Customer accounts reserve.......................................... 36.8 (34.9) 7.5
Terminated construction project costs.............................. (7.3) (7.7) (7.9)
Other.............................................................. (11.6) (7.8) 7.9
52.4 (10.0) 95.7
Net deferred investment tax credits-amortization..................... (17.1) (19.2) (19.4)
Income tax expense-operating income.................................. 223.0 253.5 222.2
Income tax expense associated with nonoperating income:
Current expense:
Federal............................................................ (1.7) (0.2) (6.1)
State.............................................................. 0.1
(1.7) (0.2) (6.0)
Deferred expense..................................................... 4.3 3.9 9.4
Income tax expense-nonoperating income............................... 2.6 3.7 3.4
Total income tax expense............................................. $ 225.6 $ 257.2 $ 225.6
28
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
1994 1993 1992
(MILLIONS, EXCEPT
PERCENTAGES)
Federal income tax expense at statutory rate of 35% (34%
in 1992)............................................... $234.4 $266.5 $230.4
Increases (decreases) resulting from:
Utility plant differences.............................. (1.8) (6.2) 4.6
Ratable amortization of investment tax credits......... (17.1) (16.1) (15.2)
Terminated construction project costs.................. 5.0 5.2 5.0
Other, net............................................. 2.1 3.0 (2.2)
(11.8) (14.1) (7.8)
Total federal income tax expense......................... $222.6 $252.4 $222.6
Effective tax rate....................................... 33.2% 33.1% 32.8%
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 $459.0 million and resulted in the establishment of a net regulatory asset of
$459.0 million. For additional information see FEDERAL INCOME TAXES under Note A
to FINANCIAL STATEMENTS.
The Company's net accumulated deferred income taxes consist of the
following:
YEARS
1994 1993
(MILLIONS)
Deferred income tax assets:
Investment tax credits................................................... $ 102.4 $ 108.5
Deferred income tax liabilities:
Plant-Method and basis differences....................................... 1,338.2 1,299.3
Terminated construction project costs.................................... 23.9 27.6
Income taxes recoverable through future rates............................ 172.9 176.3
Other.................................................................... 34.1 55.0
Total deferred income tax liabilities...................................... 1,569.1 1,558.2
Total net accumulated deferred income taxes................................ $1,466.7 $1,449.7
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
accumulated 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
decontamination 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
1994, total decommissioning costs, including reclamation costs, are estimated to
be $1.0 billion in 1994 dollars.
The accumulated provision for decommissioning of $260.9 million and $226.4
million is included in Utility Plant Accumulated Depreciation at December 31,
1994 and 1993, respectively. Provisions for decommissioning of $24.5 million,
$24.4 million and $24.3 million applicable to 1994, 1993 and 1992, respectively,
are included in Depreciation and Amortization Expense. The balance in the
Company's Nuclear Decommissioning trust funds was $260.9 million and $226.4
million at December 31, 1994 and 1993, respectively. The net unrealized loss of
$5.2 million at December 31, 1994 is included in the accumulated provision for
decommissioning.
29
Earnings of the trust funds were $15.2 million, $16.3 million and $9.1
million for 1994, 1993 and 1992, respectively, and are included in Other Income
in the Company's Statements of Income. In 1994 and 1993, the accretion of the
accumulated provision for decommissioning, equal to the earnings of the trust
funds, was recorded in Other Income. 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 were recorded in Interest
Charges, Other.
The Financial Accounting Standards Board (FASB) is reviewing the accounting
for nuclear plant decommissioning. If current electric utility industry
practices for such decommissioning are changed, annual provisions for
decommissioning could increase. FASB may ultimately determine that the estimated
cost of decommissioning should be reported as a liability rather than as
accumulated depreciation and that a substantial portion of the decommissioning
obligation should be recognized earlier in the operating life of the nuclear
plant.
INSURANCE
The Price-Anderson Act limits the public liability of an owner of a nuclear
power plant to $8.9 billion for a single nuclear incident. The Price-Anderson
Amendments Act of 1988 allows for an inflationary provision adjustment every
five years. The Company has purchased $200 million of coverage from the
commercial insurance pools with the remainder provided through a mandatory
industry risk sharing program. In the event of a nuclear incident at any
licensed nuclear reactor in the United States, the Company could be assessed up
to $81.7 million (including a 3 percent insurance premium tax for Virginia) for
each of its four licensed reactors not to exceed $10.3 million (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 $12.7 million (including a 3 percent
insurance premium tax for Virginia).
The Company's current level of property insurance coverage ($2.55 billion
for North Anna and $2.40 billion for Surry) exceeds the NRC's minimum
requirement for nuclear power plant licensees of $1.06 billion per reactor site
and includes coverage for premature decommissioning and functional total loss.
The NRC requires that the proceeds from this insurance be used first to return
the reactor to and maintain it in a safe and stable condition and second to
decontaminate the reactor and station site in accordance with a plan approved by
the NRC. The property insurance coverage provided to 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 $45.4 million and the maximum
assessment related to a second incident is an additional $15.1 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 $9.2 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, 1994 and 1993, $160
million and $200 million, respectively, of receivables had been sold and were
outstanding under this agreement. The limited recourse is provided by the
Company's assignment of an
30
additional undivided interest in accounts receivable to cover any potential
losses to the purchaser due to uncollectible accounts. The Company has provided
for the estimated amount of such losses in its accounts.
E. UTILITY PLANT:
Utility plant at December 31, consisted of the following:
YEAR
1994 1993
(MILLIONS)
Production.......................................................................................... $ 6,916.6 $ 6,659.0
Transmission........................................................................................ 1,301.2 1,248.4
Distribution........................................................................................ 3,989.8 3,761.0
Other............................................................................................... 860.8 794.6
13,068.4 12,463.0
Construction work in progress....................................................................... 828.2 913.1
Total........................................................................................ $13,896.6 $13.376.1
F. JOINTLY OWNED PLANTS:
The following information relates to the Company's proportionate share of
jointly owned plants at December 31, 1994:
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....................................... $1,078.3 $1,774.5
Accumulated depreciation....................................... 173.3 598.4
Nuclear fuel................................................... 409.8
Accumulated amortization of nuclear fuel....................... 382.0
Construction work in progress.................................. 0.6 163.6 $449.8
The co-owners are obligated to pay their share of all future construction
expenditures and operating costs of the jointly owned facilities in the same
proportion as their respective ownership interest. The Company's share of
operating costs is classified in the appropriate operating expense (fuel,
maintenance, depreciation, taxes, etc.) in the Statements of Income.
G. REGULATORY ASSETS:
Certain expenses normally reflected in income are deferred on the balance
sheet as regulatory assets and are recognized in income as the related amounts
are included in rates and recovered from customers. The Company's regulatory
assets included the following:
AT DECEMBER 31,
1994 1993
(MILLIONS)
Income taxes recoverable through future rates.............................................................. $488.2 $497.8
Cost of decommissioning DOE uranium enrichment facilities.................................................. 83.7 85.2
Deferred losses or gains on reacquired debt................................................................ 107.0 103.6
North Anna Unit 3 project termination costs................................................................ 128.5 153.3
Other...................................................................................................... 63.6 90.6
Total............................................................................................... $871.0 $930.5
Income taxes recoverable through future rates represent principally the tax
effect of depreciation differences not normalized. These amounts are amortized
as the related temporary differences reverse.
31
The costs of decommissioning the Department of Energy's (DOE) uranium
enrichment facilities have been deferred and represents the unamortized portion
of Virginia Power's required contributions to a fund for decommissioning and
decontaminating the DOE's uranium enrichment facilities. Virginia Power is
making such contributions over a fifteen-year period with escalation for
inflation. These costs are being recovered in fuel rates.
Deferred losses or gains on reacquired debt are deferred and amortized over
the lives of the new issues of long-term debt. Gains or losses resulting from
the redemption of debt without refinancing are amortized over the remaining
lives of the redeemed issues.
The construction of North Anna Unit 3 was terminated in November 1982. All
retail jurisdictions have permitted recovery of the incurred costs. The amounts
deferred are being amortized over a fifteen-year period for Virginia and FERC
jurisdictional customers.
H. LEASES:
Plant and property under capital leases included the following:
1994 1993
(MILLIONS)
Office buildings (*)....................................................... $34.4 $35.7
Data processing equipment.................................................. 5.8 6.9
Total plant and property under capital leases....................... 40.2 42.6
Less accumulated amortization.............................................. 12.5 12.8
Net plant and property under capital leases................................ $27.7 $29.8
(*) The Company leases its principal office building from its parent, Dominion
Resources. The capitalized cost of the property under that lease, net of
accumulated amortization, represented $25.0 million and $26.0 million at
December 31, 1994 and 1993, respectively. Rental payments for such lease were
$3.0 million for each of the three years ended December 31, 1994, 1993 and 1992.
The Company is responsible for expenses in connection with the leases noted
above, including maintenance.
Future minimum lease payments under noncancellable capital leases and for
operating leases that have initial or remaining lease terms in excess of one
year as of December 31, 1994, are as follows:
CAPITAL OPERATING
LEASES LEASES
(MILLIONS)
1995....................................................................... $ 4.4 $ 6.3
1996....................................................................... 3.8 5.6
1997....................................................................... 3.6 4.7
1998....................................................................... 3.2 3.0
1999....................................................................... 3.0 2.7
After 1999................................................................. 25.7 29.4
Total future minimum lease payments........................................ 43.7 $51.7
Less interest element included above....................................... 16.0
Present value of future minimum lease payments............................. $27.7
Rents on leases, which have been charged to other operation expenses, were
$9.6 million, $11.2 million and $10.6 million for 1994, 1993 and 1992,
respectively.
32
I. LONG-TERM DEBT:
Long-term debt included the following:
AT DECEMBER 31,
1994 1993
(MILLIONS)
First and Refunding Mortgage Bonds (1):
1987 Series B, 9.375%, due 1994......................................................... $ 100.0
1992 Series A, 6.375%, due 1995......................................................... $ 180.0 180.0
Series T, 4.5%, due 1995................................................................ 56.6 56.6
Series U, 5.125%, due 1997.............................................................. 49.3 49.3
1992 Series B, 7.25%, due 1997.......................................................... 250.0 250.0
1988 Series A, 9.375%, due 1998......................................................... 150.0 150.0
1992 Series F, 6.25%, due 1998.......................................................... 75.0 75.0
1989 Series B, 8.875%, due 1999......................................................... 100.0 100.0
Various series, 5.875-8%, due 2000-2004................................................. 940.0 940.0
Various series, 6.75-7.625%, due 2005-2009.............................................. 215.0 234.5
Various series, 9.75%, due 2014-2019.................................................... 119.0
Various series, 5.45-8.75%, due 2020-2024............................................... 944.5 600.0
Total First and Refunding Mortgage Bonds........................................... 2,960.4 2,854.4
Other long-term debt:
Bank loans, notes and term loans:
Fixed interest rate, 6.15%-10.8%, due 1994-2003...................................... 798.2 770.8
Pollution control financings (2):
Fixed interest rate, 5.625%, due 2002................................................ 19.5
Money Market Municipals, due 2008-2027 (3)........................................... 488.6 444.6
Total other long-term debt......................................................... 1,286.8 1,234.9
4,247.2 4,089.3
Less amounts due within one year:
First and Refunding Mortgage Bonds...................................................... 236.6 100.0
Bank loans, notes and term loans........................................................ 75.6 65.0
Sinking fund obligations................................................................ 0.8
Total amount due within one year................................................... 312.2 165.8
Less unamortized discount, net of premium................................................. 24.6 23.6
Total long-term debt............................................................... $ 3,910.4 $ 3,899.9
(1) Substantially all of the Company's property is subject to the lien of
its mortgage, securing its First and Refunding Mortgage Bonds.
(2) Certain pollution control facilities at the Company's generating
facilities have been pledged or conveyed to secure the financings.
(3) Interest rates vary based on short-term, tax-exempt market rates. The
weighted average daily interest rates were 2.96% and 2.53% for 1994 and 1993,
respectively. 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.
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 any one time, less amounts outstanding under the commercial paper
program. At December 31, 1994, there were no amounts outstanding under the
Agreement and no amounts were borrowed during 1994.
With a portion of the proceeds from the sale of $200 million First and
Refunding Mortgage Bonds of 1993, Series G, the Company in 1993 irrevocably
placed $138.2 million in a trust to defease $119.1 million 1990 Series A Bonds.
As a result, the
33
1990 Series A Bonds were considered to be extinguished for financial reporting
purposes and were excluded from the balance sheet at December 31, 1994 and 1993.
The cost of $19.1 million was deferred and is being amortized over the life of
the new issue.
Maturities through 1999 are as follows (millions): 1995 -- $312.2;
1996 -- $259.6; 1997 -- $311.3; 1998 -- $293.5; and 1999 -- $261.0.
J. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION:
Preferred stock subject to mandatory redemption, $100 liquidation
preference, at December 31, 1994, was as follows:
ANNUAL
ENTITLED PER SHARE UPON REDEMPTION SINKING FUND
ISSUED AND AND THEREAFTER TO REQUIREMENTS
OUTSTANDING AMOUNTS DECLINING AT $100 PER SHARE
DIVIDEND SHARES AMOUNT THROUGH IN STEPS TO SHARES
$5.58............. 400,000 (a) (b)
6.35............. 1,400,000 (a) (c)
7.30............. 417,319 $105.84 4/14/95 $100.00 after 4/14/02 15,000(d)
Total...... 2,217,319
(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.
(d) The 1995 and a portion of the 1996 sinking fund requirements were satisfied
by the 1994 open market purchase.
Maturities are $0.7 million for 1996 and $1.5 million for each of the years
1997-1999.
During the years 1992 through 1994, the following shares were redeemed:
YEAR DIVIDEND SHARES
1994......................................... $7.30 37,681
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
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.
34
K. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION:
Preferred stock not subject to mandatory redemption, $100 liquidation
preference, at December 31, 1994, 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 7/31/03 $100.00 after 7/31/13
6.98............................................................ 600,000 105.00 8/31/03 $100.00 after 8/31/13
MMP 1/87 (*)..................................................... 500,000 100.00
MMP 6/87 (*)..................................................... 750,000 100.00
MMP 10/88 (*).................................................... 750,000 100.00
MMP 6/89 (*)..................................................... 750,000 100.00
MMP 9/92A (*).................................................... 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 1994, 1993 and 1992, including fees for broker/dealer
agreements, were 3.75 percent, 3.01 percent and 3.43 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.
L. COMMON STOCK:
During the years 1992 through 1994 the following changes in Common Stock
occurred:
YEARS
1994 1993 1992
SHARES SHARES SHARES
OUTSTANDING AMOUNT OUTSTANDING AMOUNT OUTSTANDING AMOUNT
(MILLIONS, EXCEPT SHARES)
Balance at January 1............ 168,277 $ 2,662.4 166,109 $ 2,612.4 162,741 $ 2,549.1
Transfer from (to) Other Paid-in
Capital....................... (11.7)
Issuance to Dominion
Resources..................... 3,207 75.0 2,168 50.0 3,368 75.0
Balance at December 31.......... 171,484 $ 2,737.4 168,277 $ 2,662.4 166,109 $ 2,612.4
M. RETIREMENT PLAN AND POSTRETIREMENT BENEFITS:
The Company participates in the Dominion Resources, Inc. Retirement Plan
(the Retirement Plan), a defined benefit pension plan. The Retirement Plan
covers virtually all employees of Dominion Resources and its subsidiaries,
including the Company. The benefits are based on years of service and average
base compensation over the consecutive 60-month period in which pay is highest.
Pension plan expenses were $19.3 million, $15.9 million and $13.1 million
for 1994, 1993 and 1992, respectively and the amounts funded were $42.7 million,
$16.0 million and $12.3 million in 1994, 1993 and 1992, respectively.
35
The Company adopted the provisions of Statement of Financial Accounting
Standards No. 106, "Employers' Accounting 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 for these benefits in 1992.
Under the terms of its benefit plans, the Company reserves the right to
change, modify or terminate the plans. From time to time in the past, benefits
have changed, and some of these changes have reduced benefits.
Net periodic postretirement benefit expense for 1994 and 1993 was as
follows:
YEAR ENDING DECEMBER 31,
1994 1993
(MILLIONS)
Service cost............................................................ $11.0 $ 9.7
Interest cost........................................................... 21.6 20.6
Return on plan assets................................................... 0.9 (2.0)
Amortization of transition obligation................................... 12.1 12.0
Net amortization and deferral........................................... (4.1) 0.7
Net periodic postretirement benefit expense............................. $41.5 $41.0
The following table sets forth the funded status of the plan:
AT DECEMBER 31,
1994 1993
(MILLIONS)
Fair value of plan assets.................................................. $ 59.7 $ 28.4
Accumulated postretirement benefit obligation:
Retirees................................................................. $208.4 $142.4
Active plan participants................................................. 91.7 110.0
Accumulated postretirement benefit obligation......................... 300.1 252.4
Accumulated postretirement benefit obligation in excess of plan
assets.............................................................. (240.4) (224.0)
Unrecognized transition obligation......................................... 216.9 229.0
Unrecognized net experience (gain)/loss.................................... 16.6 (9.2)
Accrued postretirement benefit cost........................................ $ (6.9) $ (4.2)
A one percent increase in the health care cost trend rate would result in
an increase of $4.8 million in the service and interest cost components and a
$26.9 million increase in the accumulated postretirement benefit obligation.
Significant assumptions used in determining the postretirement benefit
obligation were:
1994 1993
Discount rates.............................................................. 8.25% 7.75%
Assumed return on plan assets............................................... 9.0% 9.0%
Medical cost trend rate..................................................... 10% for 1st year 11% for 1st year
9% for 2nd year 10% for 2nd year
Scaling down to Scaling down to
4.75% beginning 4.75% beginning
in the year 2001 in the year 2001
The Company is recovering these costs in rates on an accrual basis in all
material respects, in all jurisdictions. Current and future 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.
N. EARLY RETIREMENT AND VOLUNTARY SEPARATION PROGRAMS:
During the first quarter of 1994, the Company offered an early retirement
program to employees aged 50 or older and offered a voluntary separation program
to all regular full-time employees. The offers under the program expired
September 1,
36
1994. Approximately 1,400 employees accepted offers under these programs. The
costs associated with these programs were $90.1 million. The Company capitalized
$25.9 million based upon prior regulatory precedent and expensed $64.2 million.
O. COMMITMENTS AND CONTINGENCIES:
The Company is involved in legal, tax and regulatory proceedings before
various courts, regulatory commissions and governmental agencies regarding
matters arising in the ordinary course of business, some of which involve
substantial amounts. Management is of the opinion that the final disposition of
these proceedings will not have a material adverse effect on the results of
operations or the financial position of the Company.
RATE MATTERS
For information on the principal rate proceedings in which the Company was
involved in 1994, see RATES under Item 1. BUSINESS.
For information on the effect of rate changes see Results of Operations
under Item 7. MANAGEMENT's DISCUSSION 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 assessments in any policy year in which losses
exceed the funds available to these insurance companies. For additional
information, see Note C to FINANCIAL STATEMENTS.
CONSTRUCTION PROGRAM
The Company has made substantial commitments in connection with its
construction program and nuclear fuel expenditures. Those expenditures are
estimated to total $673.2 million (excluding AFC) for 1995. 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 75 non-utility purchase contracts
with a combined dependable summer capacity of 3,506 Mw. Of these, 65 projects
(aggregating 3,244 Mw) were operational as of the end of 1994 with the balance
to become operational at various dates before 1997.
The table below reflects the Company's minimum commitments as of December
31, 1994, for power purchases from utility and non-utility suppliers that are
currently operating or have obtained construction financing.
COMMITMENT
YEAR CAPACITY OTHER
(MILLIONS)
1995......................................... $ 735.5 $ 198.6
1996......................................... 750.8 203.9
1997......................................... 796.9 210.5
1998......................................... 800.4 216.8
1999......................................... 803.5 217.9
Later years.................................. 12,186.3 2,839.0
Total...................................... $16,073.4 $ 3,886.7
Present value of the total................... $ 7,104.7 $ 1,602.4
In addition to the minimum purchase commitments in the table above, under
some of these contracts the Company may purchase, at its option, additional
power as needed. Actual payments for purchased power (including economy,
emergency, limited term, short-term and long-term purchases) for the years 1994,
1993 and 1992 were $1,025.0 million, $958.0 million and $766.0 million,
respectively.
37
FUEL PURCHASE COMMITMENTS
The Company's estimated fuel purchase commitments for the next five years
for system generation are as follows (millions): 1995 -- $351; 1996 -- $266;
1997 -- $153; 1998 -- $33; and 1999 -- $32.
SALE 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.
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 DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
SITE REMEDIATION
The EPA has identified the Company and several other entities as
Potentially Responsible Parties (PRPs) at two Superfund sites located in
Kentucky and Pennsylvania. The estimated future remediation costs for the sites
are in the range of $46.5 million to $134.6 million. The Company's proportionate
share of the cost is expected to be in the range of $0.5 million to $6.7
million, based upon allocation formulas and the volume of waste shipped to the
sites. As of December 31, 1994, the Company had provided for $1.4 million to
meet its obligations at these two sites. Based on a financial assessment of the
PRPs involved at these sites, the Company has determined that it is probable
that the PRPs will fully pay the costs 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
provided a $2 million reserve to meet its estimated liability based on site
studies and investigations performed at these sites.
The Company generally seeks to recover its costs associated with
environmental remediation from third party insurers. At December 31, 1994 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.
LEGAL PROCEEDINGS
For information on legal proceedings see Item 3. LEGAL PROCEEDINGS.
P. 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 indicative of the amounts the Company could realize in a market
exchange. In addition, the use of different market assumptions may have a
material effect on the estimated fair value amounts.
38
DECEMBER 31,
1994 1993
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
(MILLIONS)
Assets:
Cash and cash equivalents.................................... $ 28.8 $ 28.8 $ 21.6 $ 21.6
Nuclear decommissioning trust funds.......................... 260.9 260.9 226.4 243.8
Pollution control project funds.............................. 20.3 20.3 27.2 27.2
Liabilities and capitalization:
Short-term debt.............................................. 43.0 43.0
Long-term debt:
First and refunding mortgage bonds........................ 2,960.4 2,763.2 2,854.4 2,996.0
Medium-term notes......................................... 798.2 807.2 770.8 856.3
Pollution control bonds................................... 19.5 18.4
Money Market Municipal pollution control notes............ 488.6 488.6 444.6 444.6
Preferred stock subject to mandatory redemption.............. 221.7 201.2 225.5 251.8
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 is based on
market quotations or is estimated by discounting the dividend and principal
payments for a representative issue of each series over the average remaining
life of the series.
Q. QUARTERLY FINANCIAL DATA (UNAUDITED):
The following amounts reflect all adjustments, consisting of only normal
recurring accruals (except as discussed below), necessary in the opinion of the
management for a fair statement of the results for the interim periods.
BALANCE AVAILABLE
OPERATING OPERATING NET FOR COMMON
QUARTER REVENUES INCOME INCOME STOCK
(MILLIONS)
1994
1st..................... $1,102.1 $ 207.1 $133.4 $ 123.4
2nd..................... 990.2 175.2 102.1 91.7
3rd..................... 1,151.2 241.0 165.9 155.2
4th..................... 927.3 108.1 45.7 34.6
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
Results for interim periods may fluctuate as a result of weather
conditions, rate relief and other factors.
During the first quarter of 1994, the Company offered an early retirement
program to employees aged 50 or older and offered a voluntary separation program
to all regular full-time employees. The offers under the programs expired
September 1, 1994. Approximately 1,400 employees accepted offers under these
programs. The costs associated with these programs were $90.1 million. The
Company capitalized $25.9 million based upon prior regulatory precedent and
expensed $2.8 million, $10.4 million and $51 million during the second, third
and fourth quarters, respectively. The impact of the write-off was to reduce
Balance Available for Common Stock by $1.8 million, $6.7 million and $33.1
million for the second, third and fourth quarters, respectively.
39
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
John B. Adams, Jr. (50) President and Chief Executive Officer of A. Smith Bowman 1987
Distillery, Inc., Fredericksburg, Virginia, a manufacturer
and bottler of alcohol beverages and Chairman of the Board
of Directors and a Director of Virginia Electric and Power
Company. He is a Director of Dominion Resources.
James T. Rhodes (53) President and Chief Executive Officer of Virginia Electric and 1989
Power Company. He is a Director of NationsBank of Virginia,
N.A.
Tyndall L. Baucom (53) President and Chief Operating Officer of Dominion Resources, 1994
Inc. (prior to August 16, 1994, Senior Vice President of
Dominion Resources). He is a Director of Dominion Resources.
William W. Berry (62) 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 Officer of
Dominion Resources). He is a Director of Ethyl Corporation,
Scott & Stringfellow Financial, Inc. and Universal
Corporation.
James F. Betts (62) Management Consultant, Richmond, Virginia (from April 15, 1994 1978
to July 15, 1994, Vice Chairman of the Board of Directors of
Dominion Resources, Inc.; prior to April 15, 1994, Director
of Dominion Resources). He is a Director of Central Fidelity
Bank, Inc.
Benjamin J. Lambert, III (58) Optometrist, Richmond, Virginia. He is a Director of 1992
Consolidated Bank and Trust Company and Dominion Resources.
Richard L. Leatherwood (55) Retired, Baltimore, Maryland (prior to December 1, 1991, 1994
President and Chief Executive Officer, CSX Equipment, an
operating unit of CSX Transportation, Inc.). He is a
Director of Dominion Resources.
Harvey L. Lindsay, Jr. (65) Chairman and Chief Executive Officer of Harvey Lindsay 1986
Commercial Real Estate, Norfolk, Virginia, a commercial real
estate firm. He is a Director of Dominion Resources.
William T. Roos (67) Retired, Hampton, Virginia (prior to December 31, 1993, 1975
President of Penn Luggage, Inc., retail specialty stores).
He is a Director of Dominion Resources.
Frank S. Royal (55) Physician, Richmond, Virginia. He is a Director of 1994
Columbia/HCA Healthcare Corporation, Crestar Financial
Corporation, Chesapeake Corporation, CSX Corporation and
Dominion Resources.
40
Richard L. Sharp (47) Chairman, President and Chief Executive Officer and a Director 1994
of Circuit City Stores, Inc., Richmond, Virginia, retail
consumer electronics and appliances stores. He is a Director
of S&K Famous Brands, Inc., Flextronics International, Ltd.
and Dominion Resources.
Robert H. Spilman (67) Chairman, President, Chief Executive Officer and a Director of 1994
Bassett Furniture Industries, Inc., Bassett, Virginia. He is
Chairman of the Board and a Director of Jefferson-Pilot
Corp., Greensboro, North Carolina. He is a Director of
NationsBank Corporation, TRINOVA Corporation, The Pittston
Company and Dominion Resources.
William G. Thomas (55) President of Hazel & Thomas, Alexandria, Virginia, a law firm. 1987
Each Director holds office until the next Annual Meeting of Shareholders or
until his successor is duly elected.
41
(b) Information concerning the executive officers of Virginia Electric and
Power Company is as follows:
NAME AND AGE BUSINESS EXPERIENCE PAST FIVE YEARS
James T. Rhodes (53) President and Chief Executive Officer.
John A. Ahladas (52) Senior Vice President-Corporate Services.
Larry W. Ellis (54) Senior Vice President-Power Operations and Planning.
Robert F. Hill (59) Senior Vice President-Commercial Operations.
James P. O'Hanlon (51) Senior Vice President-Nuclear, June 1, 1994 to date; Vice President-Nuclear Operations,
January 1, 1992 to June 1, 1994; Vice President-Nuclear Services prior to January 1,
1992.
Robert E. Rigsby (45) Senior Vice President-Finance and Controller, January 1, 1995 to date; Vice
President-Human Resources, October 1, 1991 to January 1, 1995; Vice President-
Information Systems prior to October 1, 1991.
Charles A. Brown (52) Vice President-Central Division, September 1, 1992 to date; Vice President-Procurement
prior to September 1, 1992.
William R. Cartwright (52) Vice President-Fossil and Hydro.
Thomas L. Caviness, Jr. (49) Vice President-Eastern Division.
J. Kennerly Davis, Jr. (49) Vice President, Treasurer and Corporate Secretary, October 1, 1994 to date; Vice
President and Corporate Secretary of Dominion Resources prior to October 1, 1994.
James T. Earwood, Jr. (51) Vice President-Division Services.
Larry M. Girvin (51) Vice President-Human Resources, January 1, 1995 to date; Vice President-Nuclear Services,
September 1, 1992 to January 1, 1995; Vice President-Central Division, January 1, 1991
to September 1, 1992; District Manager Richmond, prior to January 1, 1991.
E. Wayne Harrell (48) 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, prior to January 1, 1992.
Thomas A. Hyman, Jr. (43) Vice President-Southern Division, June 1, 1994 to date; Station Manager-Bremo Power
Station, September 1, 1992 to June 1, 1994; Assistant Controller Financial Services,
March 1, 1990 to September 1, 1992; District Manager-Roanoke prior to March 1, 1990.
Michael R. Kansler (40) Vice President-Nuclear Services, January 1, 1995 to date; Manager-Nuclear Operations
Support, September 1, 1994 to January 1, 1995; Station Manager-Surry Nuclear Power
Station prior to September 1, 1994.
F. Kenneth Moore (53) Vice President-Procurement, September 1, 1992 to date; Vice President-Nuclear Engineering
Services prior to September 1, 1992.
Thomas J. O'Neil (52) Vice President-Energy Efficiency, September 1, 1992 to date; Vice President-Regulation,
prior to September 1, 1992.
Edgar M. Roach, Jr. (46) Vice President-Regulation and General Counsel, January 1, 1995 to date; Vice
President-Regulation, February 1, 1994 to January 1, 1995; Partner in the law firm of
Hunton & Williams, Raleigh, North Carolina prior to February 1, 1994.
Johnny V. Shenal (49) Vice President-Northern and Western Divisions, June 1, 1994 to date; Vice President-
Western Division, prior to June 1, 1994.
Eva S. Teig (50) Vice President-Public Affairs, September 7, 1990 to date; Vice President-Government
Affairs, prior to September 7, 1990.
Robert F. Saunders (51) Vice President-Nuclear Operations, June 1, 1994 to date; Assistant Vice President-Nuclear
Operations, November 1, 1990 to June 1, 1994; Manager, Nuclear Licensing and Programs,
prior to November 1, 1990.
There is no family relationship between any of the persons named in
response to Item 10.
42
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The Summary Table below includes compensation paid by the Company for
services rendered in 1994, 1993 and 1992 for the Chief Executive Officer and the
four other most highly compensated executive officers (as of December 31, 1994)
as determined by total salary and incentive payments for 1994.
SUMMARY COMPENSATION TABLE
LONG TERM
COMPENSATION ALL
ANNUAL COMPENSATION LTIP OTHER
NAME & PRINCIPAL POSITION YEAR SALARY INCENTIVES(1) PAYOUTS COMPENSATION
($) ($) ($) ($)
James T. Rhodes 1994 $384,575 $ 193,830 $ 69,709 $ 14,558(8)
President & CEO 1993 $356,000 $ 202,202 $ 97,657(2) $ 17,133(3)
1992 $340,000 $ 188,752 $ 52,833(4) $ 16,924(5)
John A. Ahladas 1994 $192,385 $ 86,100 $ 29,096 $ 4,500(6)
Senior Vice President- 1993 $183,150 $ 90,954 $ 44,677 $ 5,495
Corporate Services 1992 $176,525 $ 72,474 $ 24,334 $ 5,296
Robert F. Hill 1994 $219,526 $ 74,550 $ 29,096 $ 4,500(6)
Senior Vice President- 1993 $210,350 $ 85,086 $ 44,677 $ 6,311(6)
Commercial Operations 1992 $204,900 $ 71,703 $ 24,334 $ 6,147(6)
Larry W. Ellis 1994 $181,160 $ 82,950 $ 29,096 $ 4,500(6)
Senior Vice President- 1993 $174,000 $ 81,174 $ 44,667 $ 5,220
Power Operations and Planning 1992 $168,750 $ 70,161 $ 24,334 $ 5,063
Bill D. Johnson (7) 1994 $213,860 $ 86,100 $ 29,096 $161,360(9)
Senior Vice President 1993 $204,875 $ 90,954 $ 44,677 $ 6,146(6)
and Controller 1992 $199,250 $ 72,474 $ 25,167 $ 5,978(6)
(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) Company match on savings plan contribution.
(7) Retired December 31, 1994.
(8) Company match on savings plan contribution ($4,500) and insurance
premium to Directors Charitable Contribution Program ($10,058).
(9) Company match on savings plan contribution ($4,500) retirement payment
as provided by Company's Early Retirement and Voluntary Separation Program
($112,000) and payment at retirement for accrued vacation ($44,860).
43
LONG-TERM INCENTIVE COMPENSATION
Long-term incentive awards made during 1994 are shown in the following
table.
LONG-TERM INCENTIVE PLANS -- AWARDS IN THE LAST FISCAL YEAR
1994-1996 PERFORMANCE ACHIEVEMENT PLAN
PERFORMANCE OR ESTIMATED FUTURE PAYOUTS
NUMBER OF OTHER PERIOD UNDER NON-STOCK PRICE BASED PLANS
SHARES, UNITS UNTIL MATURATION THRESHOLD TARGET MAXIMUM
NAME OR OTHER RIGHTS(1) OR PAYOUT (#) (#) (#)
James T. Rhodes 3,449 3 years 1 (2) 3,449(2) 5,174 (2)
John A. Ahladas 1,185 3 years 1 (2) 1,185(2) 1,778 (2)
Robert F. Hill 1,185 3 years 1 (2) 1,185(2) 1,778 (2)
Larry W. Ellis 1,185 3 years 1 (2) 1,185(2) 1,778 (2)
Bill D. Johnson 1,185 3 years 1 (2) 1,185(2) 1,778 (2)
(1) Performance shares representing Dominion Resources Common Stock to be
awarded at the end of Performance period.
(2) Except for James T. Rhodes, payout of awards are tied to achieving
levels of Virginia Power's return on equity (ROE) (50%) and meeting a cost per
kilowatt-hour goal (50%). The threshold 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 the Dominion Resources Organization and
Compensation Committee under the Dominion Resources Long-Term Incentive Plan.
The award for James T. Rhodes will be paid out in shares of restricted
stock based on the achievement of three specified goals over a three-year
performance period (1994-1996), 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
15$0,000 $ 41,134 $ 54,845 $ 68,556 $ 82,267
175,000 48,709 64,945 81,181 97,417
200,000 56,284 75,045 93,806 112,567
225,000 63,859 85,145 106,431 127,717
250,000 71,434 95,245 119,056 142,867
300,000 86,584 115,445 144,306 173,167
350,000 101,734 135,645 169,556 203,467
400,000 116,884 155,845 194,806 233,767
450,000 132,034 176,045 220,056 264,067
500,000 147,184 192,245 245,306 294,367
550,000 162,334 216,445 270,556 324,667
600,000 177,484 236,645 295,806 354,967
650,000 192,634 256,845 321,056 385,267
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.
44
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 1994 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: 23; John A. Ahladas: 29; Robert F. Hill: 30; Larry W.
Ellis: 30 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 1994 compensation, the estimated annual retirement benefit for
each of the executive officers under the Supplemental Plan would be as follows:
James T. Rhodes: $160,290; John A. Ahladas: $72,500; Robert F. Hill: $79,025;
Larry W. Ellis: $69,650; and Bill D. Johnson: $77,650.
EMPLOYMENT AGREEMENTS
The Company has entered into employment agreements (the Agreements) with
its key management executives, including James T. Rhodes, John A. Ahladas,
Robert F. Hill, Larry W. Ellis 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 (as defined in the Agreements)
of Dominion Resources or the Company, an executive's employment is terminated by
the Company without cause, or voluntarily by the executive within sixty days
after a material reduction in the executive's compensation, benefits or
responsibilities, the Company will be obligated to pay to the executive
continued compensation equaling the average base salary and cash incentive
bonuses for the thirty-six full month period of employment preceding the change
in control or employment termination. In addition, the terminated executive will
continue to be entitled to any benefits due under any stock or benefit plans.
The Agreements do not alter the compensation and benefits available to an
executive whose employment with the Company continues for the full term of the
executive's Agreement. The amount of benefits provided under each executive's
Agreement will be reduced by any compensation earned by the executive from
comparable employment by another employer during the thirty-six months following
termination of employment with the Company. An executive shall not be entitled
to the above benefits in the event termination is for cause.
James T. Rhodes has an employment agreement with Virginia Power, for a
three-year period ending April 21, 1997. During the term of the agreement, if
James T. Rhodes' employment as an officer of Virginia Power is terminated for
any reason other than cause, James T. Rhodes will receive the amount that he
would have otherwise received in base salary and incentive compensation. He will
also receive a benefit equal to his then annual base salary or, at his election,
the retirement and other benefits that he would have received as a participant
in Virginia Power's 1994 early retirement program. Virginia Power's 1994 early
retirement program provided five additional years of service and age credit for
purposes of retirement benefits, a severance benefit equal to six months'
salary, and continuation of certain benefits for a period of time. If James T.
Rhodes remains in the employ of Virginia Power through April 21, 1997, he will
receive a benefit when he later retires or otherwise terminates employment equal
to his then annual base salary or, at his election, the retirement and other
benefits that he would have received as a participant in Virginia Power's 1994
early retirement program. The payments under this agreement are provided in
addition to any payments under James T. Rhodes' employment continuity agreement.
Other officers (including Messrs. Ahladas, Hill, Ellis and Johnson) have similar
agreements for a period ending June 21, 1997. In addition to the foregoing
agreement, the Settlement Agreement dated as of August 15, 1994, among Dominion
Resources, Virginia Power and the members of their Boards of Directors, provides
that Virginia Power will make available to James T. Rhodes Virginia Power's 1994
Early Retirement Program for the three-year period beginning on August 24, 1994.
Messrs.
45
Hill and Johnson had available to them agreements which provided for the Early
Retirement Program if they continued employment to December 31, 1994.
COMPENSATION OF DIRECTORS
The non-employee members of the Board receive an annual retainer of $19,000
and a fee of $900 for each Board or committee meeting attended. Committee
chairmen receive an additional annual retainer of $3,000. These Directors may
elect to defer their annual retainer and/or their meeting fees under the
Deferred Compensation Plan until they retire from the Board or otherwise direct.
The deferred fees are credited, for bookkeeping purposes, with earnings and
losses as if they were invested in either an interest bearing account or
Dominion Resources Common Stock, depending on the Director's election.
In addition, the Company makes payments to non-employee Directors or their
designated beneficiaries upon those Directors' retirement, death or disability.
Payments to a retired Director, including one who becomes disabled after
retirement, are made for a period of four years, or for a period of years equal
to the Director's service on the Board of the Company or one of its
subsidiaries, whichever is longer. If a non-employee Director becomes disabled
prior to retirement, these payments are made for four years. Each year, these
payments equal the annual retainer in effect at the time the payments begin.
Upon the death of a non-employee Director, the unpaid portion of these payments,
up to a maximum of four times the annual amount due, is paid in a lump sum to
the Director's designated beneficiary.
DIRECTORS CHARITABLE CONTRIBUTION PROGRAM
Dominion Resources administers a Directors' Charitable Contribution Program
(the Program) for all its subsidiaries, including the Company, as part of its
overall program of charitable giving. Beginning at the death of a Director a
donation in an aggregate amount of $50,000 per year for 10 years will be made to
one or more qualifying charitable organizations recommended by the individual
Director. Life insurance policies have been purchased on the lives of the
Directors in connection with the Program. These policies are owned by Dominion
Resources, which is also the beneficiary. The Directors derive no financial or
tax benefits from the Program.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The table below sets forth as of January 31, 1995, 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 DEFERRED COMPENSATION
NAME BENEFICIALLY OWNED PLAN ACCOUNT (A)
James T. Rhodes.............................. 8,970
John A. Ahladas.............................. 4,025
Robert F. Hill............................... 4,664
Larry W. Ellis............................... 9,684
Bill D. Johnson.............................. 10,754
John B. Adams, Jr............................ 3,111
Tyndall L. Baucom............................ 5,965
William W. Berry............................. 11,806
James F. Betts............................... 7,603
Benjamin J. Lambert, III..................... 0 402
Richard L. Leatherwood....................... 1,000 1,727
Harvey L. Lindsay, Jr........................ 400
William T. Roos.............................. 10,957(b) 2,542
Frank S. Royal............................... 0 500
Richard L. Sharp............................. 1,000
Robert H. Spilman............................ 1,017
William G. Thomas............................ 0 2,857
(a) Represents shares the Directors have accumulated under the Deferred
Compensation Plan.
(b) Members of Mr. Roos' family are beneficiaries of trusts that own 3,818
shares of Common Stock for which he disclaims beneficial ownership.
All Directors and executive officers as a group (34 persons) beneficially
own, in the aggregate, 171,218 shares of Common Stock of Dominion Resources
which includes 3,585 shares represented by options awarded and exercisable under
Dominion Resources' Long-Term Incentive Plan. Beneficial ownership of 3,818
shares of the total are disclaimed. No shares of the Company's Preferred Stock
are owned by the Directors or executive officers as a group.
46
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In October 1994, in connection with the Settlement Agreement that is
summarized in the Company's Current Report on Form 8-K of August 17, 1994,
Dominion Resources and Virginia Power paid $77,646 and $76,530, respectively, to
a law firm that represented the following persons in connection with the
corporate governance dispute that led to the execution of the Settlement
Agreement: William W. Berry, James F. Betts, Bruce C. Gottwald, T. Justin Moore,
Jr. and James T. Rhodes. Messrs. Berry and Betts and Dr. Rhodes were directors
of Virginia Power at the time the legal expenses were incurred, and all of these
persons were directors of Dominion Resources at that time. Dr. Rhodes is also
President and Chief Executive Officer of Virginia Power.
47
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 19.
2. EXHIBITS
3(i) -- Restated Articles of Incorporation, as amended, as in effect on September 12, 1994 (Exhibit 3(i),
Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference).
3(ii) -- Bylaws, as amended, as in effect on December 31, 1994 (filed herewith).
4(i) -- See Exhibit 3(i) above.
4(ii) -- Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight
Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No.
1-2255, incorporated by reference); Fifty-Ninth Supplemental Indenture (Exhibit 4(ii), Form 10-Q for the
quarter ended March 31, 1986, File No. 1-2255, incorporated by reference); Sixtieth Supplemental Indenture
(Exhibit 4(ii), Form 10-Q for the quarter ended September 30, 1986, File
No. 1-2255, incorporated by reference); Sixty-First Supplemental Indenture (Exhibit 4(ii), Form 10-Q for
the quarter ended June 30, 1987, File No. 1-2255, incorporated by reference); Sixty-Second Supplemental
Indenture (Exhibit 4(ii), Form 8-K, dated November 3, 1987, File No. 1-2255, incorporated by reference);
Sixty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated June 8, 1988, File No. 1-2255,
incorporated by reference); Sixty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 8,
1989, File No. 1-2255, incorporated by reference); Sixty-Fifth Supplemental Indenture (Exhibit 4(i), Form
8-K, dated June 22, 1989, File No. 1-2255, incorporated by reference); Sixty-Sixth Supplemental Indenture,
(Exhibit 4(i), Form 8-K, dated February 27, 1990, File No. 1-2255, incorporated by reference);
Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255,
incorporated by reference); Sixty-Eighth Supplemental Indenture, (Exhibit 4(i)), Sixty-Ninth Supplemental
Indenture, (Exhibit 4(ii)) and Seventieth Supplemental Indenture, (Exhibit 4(iii), Form 8-K, dated
February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture
(Exhibit 4(i)) and Seventy-Second Supplemental Indenture, (Exhibit 4(ii), Form 8-K, dated July 7, 1992,
File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture, (Exhibit 4(i), Form
8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference); 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); Eighty-First Supplemental Indenture, (Exhibit 4(iii),
Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference);
Eighty-Second Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1-2255,
incorporated by reference) and Eighty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October
19, 1994, File No. 1-2255, incorporated by reference).
4(iii) -- Indenture, dated April 1, 1985, between Virginia Electric and Power Company and Crestar Bank (formerly
United Virginia Bank) (Exhibit 4(iv), Form 10-K for the fiscal year ended December 31, 1993, File No.
1-2255, incorporated by reference).
4(iv) -- Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and Chemical Bank
(Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by
reference).
4(v) -- Indenture, dated April 1, 1988, between Virginia Electric and Power Company and Chemical Bank, as
supplemented and modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form
10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).
48
4(vi) -- Virginia Electric and Power Company agrees to furnish to the Commission upon request any other instrument
with respect to long-term debt as to which the total amount of securities authorized thereunder does not
exceed 10 percent of Virginia Electric and Power Company's total assets.
10(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 10(vi), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by
reference).
10(ii) -- Purchase, Construction and Ownership Agreement, dated as of December 28, 1982 but amended and restated on
October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative
(Exhibit 10(viii), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by
reference).
10(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
10(ix), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by
reference).
10(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 10(x), Form 10-K for
the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference).
10(v) -- Inter-Company Credit Agreement, dated July 1, 1986, as amended and restated December 31, 1992 between
Dominion Resources and Virginia Electric and Power Company (Exhibit 10(v), Form 10-K for the fiscal year
ended December 3, 1993, File No. 1-2255, incorporated by reference).
10(vi) -- Credit Agreement, dated December 1, 1985, between Virginia Electric and Power Company and Old Dominion
Electric Cooperative (Exhibit 10(xix), Form 10-K for the fiscal year ended December 31, 1985, File No.
1-8489, incorporated by reference).
10(vii) -- Agreement for Northern Virginia Services, dated as of November 1, 1985, between Potomac Electric Power
Company and Virginia Electric and Power Company (Exhibit 10(xxi), Form 10-K for the fiscal year ended
December 31, 1985, File No. 1-8489, incorporated by reference).
10(viii) -- Purchase, Construction and Ownership Agreement, dated May 31, 1990, between Virginia Electric and Power
Company and Old Dominion Electric Cooperative (Exhibit 10(xi), Form 10-K for the fiscal year ended
December 31, 1990, File No. 1-2255, incorporated by reference).
10(ix) -- Operating Agreement, dated May 31, 1990, between Virginia Electric and Power Company and Old Dominion
Electric Cooperative (Exhibit 10(xii), Form 10-K for the fiscal year ended December 31, 1990, File No.
1-2255, incorporated by reference).
10(x) -- Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and the Unit 2 Amendment (Volume 1),
dated May 31, 1990 between Virginia Electric and Power Company and Old Dominion Electric Cooperative,
Westinghouse, Black & Veatch, Combustion Engineering and H. B. Zachry (Volumes 2-11 contain technical
specifications) (Exhibit 10(xiii), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255,
incorporated by reference).
10(xi) -- Receivables Purchase Agreement, dated as of December 11, 1991, between Virginia Electric and Power Company
and Dynamic Funding Corporation (Exhibit 10(xv), Form 10-K for the fiscal year ended December 31, 1991,
File No. 1-2255, incorporated by reference).
10(xxi)* -- Description of arrangements with certain officers regarding additional credited years of service for
retirement purposes (Exhibit 10(xii), Form 10-K for the fiscal year ended December 31, 1992, File No.
1-2255, incorporated by reference).
10(xxii)* -- Dominion Resources, Inc. Directors' Deferred Compensation Plan, effective July 1, 1986 (filed herewith).
10(xxiii)* -- Dominion Resources, Inc. Performance Achievement Plan, effective January 1, 1986, as amended and restated
effective February 19, 1988 (filed herewith).
10(xxiv)* -- Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 1981 as amended and
restated effective October 22, 1988 and as amended and restated June 15, 1990 (filed herewith).
10(xxv)* -- Dominion Resources, Inc.'s Cash Incentive Plan as adopted December 20, 1991 (filed herewith).
10(xxvi)* -- Dominion Resources, Inc. Long-Term Incentive Plan, effective April 17, 1987 (filed herewith).
10(xxvii)* -- Employment Continuity Agreement for James T. Rhodes of Virginia Power (filed herewith).
10(xxviii)* -- Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 (filed herewith).
10(xxix)* -- Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective January 1, 1991 (filed
herewith).
10(xxx)* -- Dominion Resources, Inc. Executives' Deferred Compensation Plan, effective January 1, 1994 (filed
herewith).
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10(xxxi)* -- Employment Agreement dated June 30, 1994 between Virginia Power and James T. Rhodes (filed herewith).
10(xxxii)* -- Employment Agreement dated June 23, 1994 between Virginia Power and B.D. Johnson (filed herewith).
10(xxxiii)* -- Employment Agreement dated June 23, 1994 between Virginia Power and R.F. Hill (filed herewith).
10(xxxiv)* -- Employment Agreement dated June 23, 1994 between Virginia Power and L.W. Ellis (filed herewith).
10(xxxv)* -- Employment Agreement dated June 23, 1994 between Virginia Power and J.A. Ahladas (filed herewith).
23(i) -- Consent of Hunton & Williams (filed herewith).
23(ii) -- Consent of Jackson & Kelly (filed herewith).
23(iii) -- Consent of Deloitte & Touche LLP (filed herewith).
27 -- Financial Data Schedule (filed herewith).
*Indicates management contract or compensatory plan or arrangement
(b) Reports of Form 8-K
Virginia Power filed a report on Form 8-K, dated December 5, 1994,
reporting the release by the Staff of the Virginia State Corporation Commission
(the Staff) of a report filed December 1, 1994 entitled "Staff Investigation of
Corporate Relationships, Affiliate Arrangements, and Financial and
Diversification Issues of Dominion Resources, Inc. and Virginia Power."
Virginia Power filed a report on Form 8-K dated February 21, 1995,
reporting the entry of a Consent Order by the Virginia State Corporation
Commission (the Commission) on the joint motion of Dominion Resources, Virginia
Power and the Staff and the withdrawal by Delegate Clinton Miller of certain
legislation introduced by Delegate Miller in the 1995 Virginia General Assembly
at the request of the Commission.
50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
VIRGINIA ELECTRIC AND POWER COMPANY
Date: March 8, 1995
By JOHN B. ADAMS, JR.
(JOHN B. ADAMS, JR., CHAIRMAN OF THE
BOARD OF DIRECTORS)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on March 8, 1995.
SIGNATURE TITLE
JOHN B. ADAMS, JR. Chairman of the Board of Directors and
Director
JOHN B. ADAMS, JR.
TYNDALL L. BAUCOM Director
TYNDALL L. BAUCOM
Director
WILLIAM W. BERRY
JAMES F. BETTS Director
JAMES F. BETTS
Director
BENJAMIN J. LAMBERT, III
RICHARD L. LEATHERWOOD Director
RICHARD L. LEATHERWOOD
HARVEY L. LINDSAY, JR. Director
HARVEY L. LINDSAY, JR.
J. T. RHODES President (Chief Executive
Officer) and Director
J. T. RHODES
WILLIAM T. ROOS Director
WILLIAM T. ROOS
FRANK S. ROYAL Director
FRANK S. ROYAL
Director
RICHARD L. SHARP
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ROBERT H. SPILMAN Director
ROBERT H. SPILMAN
WILLIAM G. THOMAS Director
WILLIAM G. THOMAS
R. E. RIGSBY Senior Vice President-Finance and
Controller (Principal Accounting Officer
R. E. RIGSBY and Chief Financial Officer)
52