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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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Form 10-K
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(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-2255
VIRGINIA ELECTRIC AND POWER COMPANY
(Exact name of registrant as specified in its charter)
VIRGINIA 54-0418825
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification no.)
701 East Cary Street
23219-3932
Richmond, Virginia (Zip Code)
(Address of principal executive offices)
(804) 771-3000
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Preferred Stock (cumulative) New York Stock Exchange
$100 liquidation value:
$5.00 dividend
Trust Preferred Securities New York Stock Exchange
$25 liquidation value:
8.05% dividend
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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. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of February 28, 1998, was zero.
As of February 28, 1998, 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
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VIRGINIA ELECTRIC AND POWER COMPANY
Page
Item Number Number
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PART I
1. Business .............................................................................. 1
The Company ........................................................................... 1
Company Management .................................................................... 1
Competition and Strategic Initiatives ................................................. 1
Regulation ............................................................................ 2
General .............................................................................. 2
Virginia ............................................................................. 2
FERC ................................................................................. 3
Environmental ........................................................................ 3
Nuclear .............................................................................. 3
Rates ................................................................................. 4
FERC ................................................................................. 4
Virginia ............................................................................. 5
North Carolina ....................................................................... 6
Capital Requirements and Financing Program ............................................ 6
Construction and Nuclear Fuel Expenditures ........................................... 6
Financing Program .................................................................... 6
Sources of Power ...................................................................... 7
Company Generating Units ............................................................. 7
Net Purchases ........................................................................ 7
Non-Utility Generation ............................................................... 7
Sources of Energy Used and Fuel Costs ................................................. 8
Nuclear Operations and Fuel Supply ................................................... 8
Fossil Operations and Fuel Supply .................................................... 8
Purchases and Sales of Energy ........................................................ 8
Future Sources of Power ............................................................... 9
Conservation and Load Management ...................................................... 9
Interconnections ...................................................................... 9
2. Properties ............................................................................ 10
3. Legal Proceedings ..................................................................... 11
4. Submission of Matters to a Vote of Security Holders ................................... 11
PART II
5. Market for the Registrant's Common Equity and Related Stockholder Matters ............. 12
6. Selected Financial Data ............................................................... 12
7. Management's Discussion and Analysis of Financial Condition and Results of Operations . 12
Liquidity and Capital Resources ....................................................... 13
Capital Requirements .................................................................. 14
Results of Operations ................................................................. 15
Future Issues ......................................................................... 17
Market Risk Sensitive Instruments and Risk Management ................................. 22
8. Financial Statements and Supplementary Data ........................................... 24
9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure .. 47
PART III
10. Directors and Executive Officers of the Registrant ................................... 48
11. Executive Compensation ............................................................... 51
12. Security Ownership of Certain Beneficial Owners and Management ....................... 55
13. Certain Relationships and Related Transactions ....................................... 55
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ..................... 56
PART I
ITEM 1. BUSINESS
THE COMPANY
Virginia Electric and Power Company is a Virginia Corporation. Our
principal office is at 701 East Cary Street, Richmond, Virginia 23219-3932,
telephone (804) 771-3000. We are a wholly owned subsidiary of Dominion
Resources, Inc. (Dominion Resources), a Virginia corporation. Dominion
Resources owns all of our common stock.
Virginia Electric and Power Company is a regulated public utility engaged
in the generation, transmission, 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. We have retail customers
(including governmental agencies) and wholesale customers such as rural
electric cooperatives, power marketers and municipalities. We serve more than
80 percent of Virginia's population. The Company has certificates of
convenience and necessity from the State Corporation Commission of Virginia
(the Virginia Commission) for service in all territories served at retail in
Virginia. The North Carolina Utilities Commission (the North Carolina
Commission) has assigned territory to the Company for substantially all of its
retail service outside certain municipalities in North Carolina.
The electric utility industry in the United States is undergoing an
evolutionary change toward less regulation and more competition. To meet the
challenges of this new competitive environment, Virginia Power has developed a
broad array of "non-traditional" product and service offerings from its
operating business units and subsidiaries:
o Energy Services -- offering electric energy and capacity in the emerging
wholesale market as well as natural gas and other energy-related products
and services;
o Fossil & Hydro -- targeting process type industries, such as chemical,
paper, plastics and petroleum to become a service provider of
instrumentation equipment;
o Nuclear Services -- offering management and operations services to other
electric utilities;
o Commercial Operations -- providing power distribution related services,
including transmission and distribution, engineering and metering services
to other gas, water and electric utilities; and
o Telecommunications -- offering telecommunications services through the
Company's existing fiber-optic network.
The Company and its subsidiaries had 9,043 full-time employees on December
31, 1997. A total of 3,452 of our employees are represented by the
International Brotherhood of Electrical Workers under a contract extending to
March 31, 1998. The Company and the union have tentatively agreed, subject to
ratification by the union membership, to a two year extension of the contract.
For a more thorough review of the changing utility industry and the
Company's strategy see COMPETITION AND STRATEGIC INITIATIVES below and Future
Issues -- Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (MD&A).
COMPANY MANAGEMENT
In April, Dr. James T. Rhodes, President and Chief Executive Officer since
1989, announced his retirement effective August 1, 1997. The Board of Directors
subsequently elected Mr. Norman Askew as the new President and Chief Executive
Officer, effective August 1, 1997. Mr. Askew was previously the Chief Executive
of East Midlands Electricity plc, a United Kingdom regional electricity company
acquired by Dominion Resources during the first quarter of 1997. Mr. Askew also
replaced Dr. Rhodes on the Board of Directors effective August 1, 1997.
COMPETITION AND STRATEGIC INITIATIVES
A number of developments in the United States are causing a trend toward
less regulation and more competition in the electric utility industry. This is
evidenced by legislative and regulatory action at both the federal and state
levels. To the extent that competition is either authorized or mandated and
regulation is eliminated or relaxed, electric utilities may no longer be
guaranteed an opportunity to recover all of their prudently incurred costs, and
utilities with costs that exceed the market prices established by the
competitive market will run the risk of suffering losses, which may be
substantial.
1
Virginia Power has responded to these trends by undertaking cost-cutting
measures, engaging in re-engineering efforts, restructuring its core business
processes, and pursuing a strategic planning initiative to encourage innovative
approaches to serving traditional markets. The Company has established separate
business units, as discussed above, to fully execute these strategies.
The Company also is vigorously participating in the state and federal
legislative actions currently underway to bring about competition in the
electric utility industry, in an effort to ensure an orderly transition from a
regulated environment.
The Company's non-traditional businesses face competition from a variety
of utility and non-utility entities.
For a full discussion of the regulatory and legislative issues related to
competition, carefully read the Future Issues section of MD&A.
REGULATION
General
In a wide variety of matters in addition to rates, Virginia Power is
presently subject to regulation by the Virginia Commission and the North
Carolina Commission, the Environmental Protection Agency (EPA), Department of
Energy (DOE), Nuclear Regulatory Commission (NRC), the Federal Energy
Regulatory Commission (FERC), the Army Corps of Engineers, and other federal,
state and local authorities. Compliance with numerous laws and regulations
increases the Company's operating and capital costs by requiring, among other
things, changes in the design and operation of existing facilities and changes
or delays in the location, design, construction and operation of new
facilities. The commissions regulating the 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 various state and federal
governmental agencies. Such approvals relate to, among other things, the
environmental impact of such activities, the relationship of such activities to
the need for providing adequate utility service and the design and operation of
proposed facilities.
Both federal and state legislative bodies have been studying competition
and restructuring in the electric utility industry. Please carefully read the
full discussion of this matter found in the Future Issues -- Competition --
Legislative Initiatives section of MD&A.
Virginia
In 1995, the Virginia Commission instituted an ongoing generic
investigation on electric industry restructuring, resulting in a number of
reports by its Staff covering such issues as retail wheeling experiments and
the status of wholesale power markets. The Staff also submitted a report to the
General Assembly calling for a cautious, two-phase, five-year period to address
restructuring issues. The report acknowledged the need for direction from the
Virginia legislature concerning policy issues surrounding competition in the
electric industry.
In November 1996, the Virginia Commission instituted a proceeding
concerning Virginia Power's cost of service and possible restructuring of the
electric utility industry as it might relate to Virginia Power. On March 24,
1997, Virginia Power filed in that proceeding a calculation of its cost of
service for 1996 and a proposed Alternative Regulatory Plan (ARP).
Subsequently, the Commission consolidated this proceeding with the proceeding
concerning the Company's 1995 Annual Informational Filing, in which the
Company's base rates were made interim and subject to refund as of March 1,
1997. Please carefully read the Future Issues -- Competition -- Legislative and
Regulatory Initiatives sections of MD&A and RATES-Virginia, below for details
concerning the ARP, its current status and related legislative developments.
In December 1995, Virginia Power applied to the Virginia Commission for
approval of arrangements with Chesapeake Paper Products Company (CPPC), under
which Virginia Power would facilitate the design, construction and financing of
a cogeneration plant to meet CPPC's energy requirements for its industrial
processes at its plant in West Point, Virginia. On August 13, 1997, the
Virginia Commission approved, in substantial part, the proposed transactions
between Virginia Power and CPPC's successor in ownership, St. Laurent Paper
Products Co. St. Laurent later determined that the current design of the
facility was no longer compatible with its long-term business strategies and
terminated its contractual arrangement with Virginia Power. The Virginia
Commission dismissed the proceeding on January 15, 1998.
In June 1997, the Virginia Commission granted the Company's request to
implement a monitoring program that requires certain non-utility generators to
provide certain information sufficient to determine continued compliance with
the "Qualifying Facility" (QF) requirements of the Public Utility Regulatory
Policies Act of 1978 (PURPA).
2
On August 8, 1997, the Virginia Commission granted the Company's request
to provide interchange telecommunications services and approved the proposed
affiliate agreements between Virginia Power and our wholly-owned subsidiary,
VPS Communications, Inc. (VPSC). Under the authority granted, VPSC will provide
a range of telecommunications services, including private line and special
access services and high-capacity fiberoptic services.
On September 3, 1997, the Virginia Commission granted the Company's
request to provide services to our wholly-owned subsidiary, Virginia Power
Services, Inc. (VPS), which would enable Virginia Power Nuclear Services
Company (VPN), a VPS subsidiary, to furnish nuclear management and operation
services to electric utilities seeking assistance in the management and
operation of their nuclear generating facilities. VPN currently provides such
services to Northeast Utilities at its Millstone Unit 2 nuclear plant.
FERC
In April 1996, FERC issued final rules in Order Nos. 888 and 889
addressing open access transmission service, stranded costs, standards of
conduct and open access same-time information systems (OASIS). In July 1996,
Virginia Power filed an open access transmission service tariff in compliance
with FERC's Order No. 888. In compliance with FERC's directive, Virginia
Power's OASIS became operational on January 3, 1997. Also, on that date the
standards of conduct requiring separation of transmission
operations/reliability functions from wholesale merchant/marketing functions
became effective. The Company also made filings to comply with FERC's directive
that, effective January 1, 1997, utilities could no longer make bundled sales
of transmission and generation services in economy energy transactions. In
certain of those filings, Virginia Power canceled or committed not to use the
economy energy rate schedules contained in interconnection agreements with
neighboring utilities. On March 4, 1997, FERC issued Order Nos. 888-A and
889-A, which addressed requests for rehearing of Order Nos. 888 and 889. Orders
No. 888-A and 889-A essentially reaffirm the basic principles of 888 and 889
and clarify and make limited modifications to those orders. On December 17,
1997, FERC issued Order Nos. 888-B and 889-B. FERC rejected all requests for
rehearing filed with respect to Order Nos. 888-A and 889-A and clarified and
made limited modifications to those orders. Several parties have appealed the
888 orders to the United States Court of Appeals for the District of Columbia
Circuit.
For a discussion of the status of the Company's Open Access Transmission
Tariff filing, see RATES -- FERC below.
For additional discussion of open access issues see Future Issues --
Competition under MD&A.
LG&E Westmoreland Southampton owns a cogeneration facility in Franklin,
Virginia, and sells its output to Virginia Power. Southampton has sought a
waiver of FERC operating requirements for Qualifying Facilities (QF's) under
PURPA, however FERC refused to grant such a waiver. On March 31, 1997, the
United States Court of Appeals for the District of Columbia Circuit granted
FERC's motion to dismiss Southampton's Petition for Review.
Environmental
From time to time, Virginia Power may be designated by the EPA as a
potentially responsible party (PRP) with respect to a Superfund site. As a
result of that designation or other regulations regarding the remediation of
waste, we may become obligated to fund remedial investigations or actions. We
do not believe that any currently identified sites will result in significant
liabilities. For a discussion of the Company's site remediation efforts, see
Note Q to the CONSOLIDATED FINANCIAL STATEMENTS.
Permits under the Clean Water Act and state laws have been issued for all
of the Company's steam generating stations now in operation. These permits are
subject to reissuance and continuing review. The Clean Air Act, as amended in
1990, requires the Company to reduce its emissions of sulfur dioxide (SO2) and
nitrogen oxides (NOx). Beginning in 1995, the SO2 reduction program is based on
the issuance of a limited number of SO2 emission allowances, each of which may
be used as a permit to emit one ton of SO2 into the atmosphere or may be sold
to someone else. The program is administered by the EPA.
For additional information on Environmental Matters, Clean Air Act
compliance and related issues see the Future Issues section of MD&A.
Nuclear
All aspects of the operation and maintenance of the Company's nuclear
power 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.
3
From time to time, the NRC adopts new requirements for the operation and
maintenance of nuclear facilities. In many cases, these new regulations require
changes in the design, operation and maintenance of existing 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.
In July 1995, the Virginia Commission instituted an investigation
regarding spent nuclear fuel disposal. As directed, Virginia Power and others
filed comments on legal and public policy issues related to spent nuclear fuel
storage and disposal. In February 1996, the Commission Staff filed its Report
recommending that adoption of a definitive policy on spent nuclear fuel
disposal issues be delayed pending the outcome of litigation against the
Department of Energy concerning spent nuclear fuel acceptance, the outcome of
proposed federal legislation concerning development of an interim storage
facility, and development of a vision of the likely outcome of the electric
utility industry's restructuring efforts. The Virginia Commission consolidated
the proceeding with Virginia Power's pending fuel cost recovery proceeding in
October 1996. On March 20, 1997, the Virginia Commission returned the spent
nuclear fuel disposal issue to a separate proceeding.
On January 31, 1997, Virginia Power joined thirty-five other electric
utilities in filing a petition in the United States Court of Appeals for the
District of Columbia Circuit, seeking to compel DOE to comply with its
obligation to begin accepting the utilities' spent nuclear fuel for disposal by
January 31, 1998, the date imposed by the Nuclear Waste Policy Act. Additional
utilities have joined since the original filing. On November 14, 1997, the
Court issued an Order finding that DOE's obligation to begin accepting spent
nuclear fuel by the deadline is unconditional, and that DOE may not excuse its
delay on the grounds that it has not prepared a permanent repository or interim
storage facility. The Court found that DOE's spent fuel disposal contracts with
the utilities offer a potentially adequate remedy for DOE's failure to meet its
obligation. DOE filed a petition for rehearing on December 29, 1997.
RATES
The Company's electric services sales were subject to rate regulation in
1997 as follows:
1997
-----------------------
Percent Percent
of of
Revenues Kwh Sales
---------- ----------
Virginia retail:
Non-Governmental customers ........... Virginia Commission 81% 76%
Governmental customers ............... Negotiated Agreements 10 12
North Carolina retail ................. North Carolina Commission 5 5
Wholesale --Sales for Resale* ......... FERC 4 7
-- --
100% 100%
=== ===
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* Excludes wholesale power marketing sales subject to FERC regulation.
Substantially all of the Company's electric service sales are subject to
recovery of changes in fuel costs either through fuel adjustment factors or
periodic adjustments to base rates, each of which requires prior regulatory
approval.
Each of these jurisdictions has the authority to disallow recovery of
costs it determines to be excessive or imprudently incurred. Various cost items
may be reviewed on occasion, including costs of constructing or modifying
facilities, on-going purchases of capacity or providing replacement power
during generating unit outages.
FERC
In compliance with FERC's Order No. 888, Virginia Power filed an open
access transmission service tariff, which became effective on July 9, 1996. In
October 1996, FERC issued a procedural order, scheduling a hearing for April
28, 1997. The Company and all parties reached a settlement of issues raised in
the proceeding, and on March 20, 1997, those parties jointly filed with FERC
the Settlement Agreement and Motion to Certify the Settlement Agreement. On
April 23, 1997 the presiding Administrative Law Judge certified the Settlement
Agreement to the FERC and on June 11, 1997, the FERC approved the settlement.
In compliance with FERC's Order No. 889, on January 3, 1997, the Company
filed its Procedures For Standards of Conduct for Unbundled Transmissions and
Wholesale Merchant Function (Standards of Conduct) effective on that date. On
July 1, 1997, the Company filed an amendment to the Standards of Conduct in
Compliance with FERC's Order No. 889-A.
4
On July 16, 1997, the Company filed another amendment in response to a FERC
Staff request. The Company is awaiting FERC action on the filing.
On September 11, 1997, FERC authorized the Company to sell power at
market-based rates but set for hearing the issue of the impact of any
transmission constraints on Virginia Power's ability to exercise generation
market power in localized areas within its service territory. If FERC finds
that transmission constraints give Virginia Power generation dominance, it
could either revoke or limit the scope of the market-based rate authority. The
hearing is scheduled to commence June 2, 1998.
On October 31, 1997, Virginia Power filed at FERC three agreements with
Old Dominion Electric Cooperative (ODEC) to amend the parties' Interconnection
and Operating Agreement (I&O Agreement) and to unbundle transmission services
provided to ODEC under the I&O Agreement. On December 22, 1997, FERC issued a
deficiency letter with respect to the filing directing the Company to provide
additional information. On January 21, 1998, the Company provided the requested
information. FERC accepted the agreements on March 12, 1998.
Virginia
In March 1997, the Virginia Commission issued an order that Virginia
Power's base rates be made interim and subject to refund as of March 1, 1997.
This order was the result of the Commission Staff's report on its review of
Virginia Power's 1995 Annual Informational Filing, which concluded that
Virginia Power's present rates would cause Virginia Power to earn in excess of
its authorized return on equity. The Staff found that, for purposes of
establishing rates prospectively, a rate reduction of $95.6 million (including
a one-time adjustment of $29.7 million to Virginia Power's deferred capacity
balance at December 31, 1996) may be necessary in order to realign rates to the
authorized level. Virginia Power filed its Alternative Regulatory Plan in March
1997, based on 1996 financial information. Subsequently, the Commission
consolidated the proceeding concerned with the 1995 Annual Informational Filing
with the proceeding that includes the ARP proposed by the Company.
In December 1997, Virginia Power sought to withdraw its ARP, having
concluded that resolution of the cost recovery issues raised by the ARP was
unlikely without General Assembly action. The Commission has agreed that the
Company may withdraw its support of the ARP but has reserved the right to
continue consideration of the ARP as well as other regulatory alternatives. In
addition, the Commission will continue to consider the issues arising out of
the 1995 Annual Informational Filing. The Commission's Staff is scheduled to
file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed
by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A
public hearing is scheduled to commence on May 19, 1998.
Virginia Power's previous filings in this proceeding support maintaining
the Company's rates at current levels; however, opposing parties have made
filings recommending rate reductions in excess of $200 million. At this time,
management cannot predict the ultimate outcome of the proceeding and its impact
on the Company's results of operations, cash flows or financial position.
In July 1996, Virginia Power proposed to substantially reduce the rates
paid under Schedule 19 to cogenerators and small power producers of 100 kW or
less. The rates became effective on an interim basis on January 1, 1997. On
January 21, 1998, the Virginia Commission approved revised Schedule 19 rates.
The approved rates do not differ in any significant way from the rates
originally proposed by the Company.
In October 1996, Virginia Power filed an application with the Virginia
Commission to increase its fuel factor from 1.299 cents per kWh to 1.322 cents
per kWh, reflecting a fuel factor annual revenue increase of approximately
$48.2 million. The increase became effective on an interim basis on December 1,
1996. On June 11, 1997, the Commission entered an Order Establishing Fuel
Factor approving the requested increase.
On October 31, 1997, Virginia Power filed with the Virginia Commission its
application for a reduction of $45.6 million in its fuel cost recovery factor
for the period December 1, 1997 through November 30, 1998. The reduction became
effective on an interim basis on December 1, 1997. Subsequently, as a result of
amendments to two non-utility power purchase contracts, the Company proposed
two additional reductions of approximately $30.2 million and $18 million for
the same period, bringing the total proposed fuel factor reduction to $93.8
million. Both additional reductions were approved on an interim basis,
effective March 1, 1998. A hearing is scheduled for April 9, 1998.
5
North Carolina
On November 4, 1996, the Company filed for approval of a new Schedule 19
which governs purchases from cogenerators and small power producers. The
Company proposed rates substantially lower than those previously specified. It
also proposed to reduce the applicability threshold to 100 kW and shorten the
maximum term of contracts under Schedule 19 to five years. On June 19, 1997,
the North Carolina Commission issued an Order requiring the Company to offer
long-term (5-,10- and 15-year) levelized capacity payments to hydroelectric and
certain landfill and waste facilities contracting for up to 5 MW; a 5-year
levelized rate option to other QFs contracting for up to 100 kW; and optional
long-term levelized energy payments for QFs rated at 100 kW or less capacity.
On October 10, 1997 the Company filed an application with the North
Carolina Commission for a $728,000 increase in fuel revenues. On December 29,
1997, the North Carolina Commission entered an Order Approving Fuel Charge
Adjustment. The Order approved an approximate $600,000 increase in the annual
rates and charges paid by the retail customers of North Carolina Power
effective on January 1, 1998.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Construction and Nuclear Fuel Expenditures
Virginia Power's estimated construction and nuclear fuel expenditures for
the three-year period 1998-2000, total $1.5 billion. It has adopted a 1998
budget for construction and nuclear fuel expenditures as set forth below:
Estimated 1998
Expenditures
(millions)
---------------
Production .................................................... $ 60
Technology .................................................... 150
General Support Facilities .................................... 19
Transmission .................................................. 37
Distribution .................................................. 213
Nuclear Fuel .................................................. 86
----
Total Construction Requirements and Nuclear Fuel Expenditures $565
====
In addition, the Company expects to incur approximately $23 million of
expenditures in 1998 in connection with the development of energy management
projects for customers. Contracts with such customers provide for the recovery
of these costs in future years.
Financing Program
The Company currently has three shelf registrations on file with the
Securities Exchange Commission (SEC) providing the Company with $915 million of
debt capital resources. The Company also has a Preferred Stock shelf registered
with the SEC for $100 million in aggregate principal amount, which has not been
utilized.
The Company intends to issue securities from time to time to meet its
capital requirements, which include $333.5 million of long-term debt maturities
in 1998.
Please see the Liquidity and Capital Resources section of MD&A for details
about our Financing Program.
6
SOURCES OF POWER
Company Generating Units
Type Summer
Years of Capability
Name of Station, Units and Location Installed Fuel MW
- ---------------------------------------------------------- ----------- ---------------- ------------
Nuclear:
Surry Units 1 & 2, Surry, Va ........................... 1972-73 Nuclear 1,602
North Anna Units 1 & 2, Mineral, Va .................... 1978-80 Nuclear 1,790 (a)
Total nuclear stations ................................ 3,392
--------
Fossil Fuel:
Steam:
Bremo Units 3 & 4, Bremo Bluff, Va. ................... 1950-58 Coal 227
Chesterfield Units 3-6, Chester, Va. .................. 1952-69 Coal 1,250
Clover Units 1 & 2, Clover, Va. ....................... 1995-96 Coal 882 (b)
Mt. Storm Units 1-3, Mt. Storm, W. Va. ................ 1965-73 Coal 1,587
Chesapeake Units 1-4, Chesapeake, Va. ................. 1953-62 Coal 595
Possum Point Units 3 & 4, Dumfries, Va. ............... 1955-62 Coal 322
Yorktown Units 1 & 2, Yorktown, Va. ................... 1957-59 Coal 326
Possum Point Units 1, 2, & 5, Dumfries, Va. ........... 1948-75 Oil 929
Yorktown Unit 3, Yorktown, Va. ........................ 1974 Oil & Gas 818
North Branch Unit 1, Bayard, W. Va. ................... 1994 Waste Coal 74 (c)
Combustion Turbines:
35 units (8 locations) ................................. 1967-90 Oil & Gas 1,019
Combined Cycle:
Bellmeade, Richmond, Va. ............................... 1991 Oil & Gas 230
Chesterfield Units 7 & 8, Chester, Va. ................. 1990-92 Oil & Gas 397
Total fossil stations ................................. 8,656
--------
Hydroelectric:
Gaston Units 1-4, Roanoke Rapids, N.C. ................. 1963 Conventional 225
Roanoke Rapids Units 1-4, Roanoke Rapids, N.C. ......... 1955 Conventional 99
Other .................................................. 1930-87 Conventional 3
Bath County Units 1-6, Warm Springs, Va. ............... 1985 Pumped Storage 1,260 (d)
--------
Total hydro stations .................................. 1,587
--------
Total Company generating unit capability .............. 13,635
Net Purchases ........................................... 1,480
Non-Utility Generation .................................. 3,277
--------
Total Capability ...................................... 18,392
========
- ---------
(a) Includes an undivided interest of 11.6 percent (208 MW) owned by ODEC.
(b) Includes an undivided interest of 50 percent (441 MW) owned by ODEC.
(c) Effective January 25, 1996, this unit was placed in a cold reserve
status.
(d) Reflects the Company's 60 percent undivided ownership interest in the
2,100 MW station. A 40 percent undivided interest in the facility is owned
by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc
(AE).
The Company's highest one-hour integrated service area summer peak demand
was 14,537 MW on July 28, 1997, and an all-time high one-hour integrated winter
peak demand of 14,910 MW was reached on February 5, 1996.
7
SOURCES OF ENERGY USED AND FUEL COSTS
For information as to energy supply mix and the average fuel cost of
energy supply, see Results of Operations under MD&A.
Nuclear Operations and Fuel Supply
In 1997, the Company's four nuclear units achieved a combined capacity
factor of 91.1 percent.
The Company utilizes both long-term contracts and spot purchases to
support its needs for nuclear fuel. The Company continually evaluates worldwide
market conditions in order to ensure a range of supply options at reasonable
prices. Current agreements, inventories and spot market availability will
support the Company's current and planned fuel supply needs for fuel cycles
throughout the remainder of the 1990's and into the early 2000's. Beyond that
period, additional fuel will be purchased as required to ensure optimum cost
and inventory levels.
The DOE is not expected to begin the acceptance of spent fuel in 1998 as
specified in the Company's contract with the DOE. However, on-site spent
nuclear fuel storage at the Surry Power Station (spent fuel pool and dry cask
storage) is expected to be adequate for the Company's needs until the DOE
begins accepting spent fuel. The North Anna Power Station will require
additional spent fuel storage capacity in 1998. The Company submitted a license
application to the NRC in May 1995 for a dry cask facility at North Anna. The
Company anticipates that this application will be approved in mid-1998.
For details on the issues of decommissioning and nuclear insurance, see
Note C to the CONSOLIDATED FINANCIAL STATEMENTS.
Fossil Operations and Fuel Supply
The Company's fossil fuel mix consists of coal, oil and natural gas. In
1997, Virginia Power consumed approximately 13 million tons of coal. As with
nuclear fuel, the Company utilizes both long-term contracts and spot purchases
to support its needs. The Company presently anticipates that sufficient coal
supplies at reasonable prices will be available for the remainder of the
1990's. Current projections for an adequate supply of oil remain favorable,
barring unusual international events or extreme weather conditions which could
affect both price and supply.
The Company uses natural gas as needed throughout the year for two
combined cycle units and at several combustion turbine units. For winter usage
at the combined cycle sites, gas is purchased and stored during the summer and
fall and 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 Energy
Virginia Power relies on purchases of power to meet a portion of its
capacity requirements. The Company also makes economy purchases of power from
other utility systems when it is available at a cost lower than the Company's
own 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 units of American
Electric Power Company, Inc. (AEP).
The Company has a diversity exchange agreement with AE under which AE
delivers 200 MW to Virginia Power in the summer and Virginia Power delivers 200
MW to AE in the winter.
Virginia Power also has 57 non-utility power purchase contracts with a
combined dependable summer capacity of 3,277 MW (for information on the
financial obligations under these agreements see Note Q to the CONSOLIDATED
FINANCIAL STATEMENTS). In a continuing effort to mitigate its exposure to
above-market long-term purchased power contracts, the Company is evaluating its
long-term purchased power contracts and negotiating modifications to their
terms, including cancellations, where it is determined to be economically
advantageous to do so.
The Company's wholesale power group actively participates in the purchase
and sale of wholesale electric power and natural gas in the open market. The
wholesale power group has expanded the Company's trading range beyond the
geographic limits of the Virginia Power service territory, and has developed
trading relationships with energy buyers and sellers on a nationwide basis.
8
In July 1997, the Company executed three agreements with Old Dominion
Electric Cooperative (ODEC) which provide for the amendment of the parties'
Interconnection and Operating Agreement (I&O Agreement). The first agreement
provides for the transition from cost-based rates for capacity and energy
purchases by ODEC to market-based rates by 2002. The second two agreements are
the Service and Operating Agreements for Network Integration Transmission
Service, which unbundled the transmission services provided to ODEC under the
I&O Agreement.
FUTURE SOURCES OF POWER
As reported earlier, both the Hoosier 400 MW long-term purchase and the
AEP 500 MW long-term purchase will expire on December 31, 1999. The Company
presently anticipates adding peaking capacity beginning in the year 2000 to
meet its anticipated load growth. The Company has and will pursue capacity
acquisition plans to provide that capacity and maintain a high degree of
service reliability. This capacity may be owned and operated by others and sold
to the Company or may be built by the Company if it determines it can build
capacity at a lower overall cost. The Company also pursues conservation and
demand-side management (see CONSERVATION AND LOAD MANAGEMENT below). No
Company-owned generation is currently in the planning or construction stages.
For additional information, see Note Q to the CONSOLIDATED FINANCIAL
STATEMENTS.
CONSERVATION AND LOAD MANAGEMENT
The Company is committed to evaluating and selecting demand-side and
supply-side options on a consistent basis in order to provide reliable,
low-cost service to its customers. Conservation and load management programs
are evaluated annually at Virginia Power through a resource planning process
that directly compares the stream of costs and benefits from supply-side and
demand-side options. This process supports a conservation and load management
portfolio which contributes both to the selection of low-cost resources to meet
the future electricity needs of the Company's customers, as well as the
efficient use of current resources.
Events in the evolving electric power marketplace and its regulatory and
legislative environment continue to impact utility-sponsored conservation and
load management programs. In the future, the Company anticipates a greater
reliance on the use of price signals to convey information to our customers
regarding energy-related costs, resulting in more efficient purchase decisions.
INTERCONNECTIONS
The Company maintains major interconnections with Carolina Power and Light
Company, AEP, AE and the utilities in the Pennsylvania-New Jersey-Maryland
Power Pool. Through this major transmission network, the Company has
arrangements with these utilities for coordinated planning, operation,
emergency assistance and exchanges of capacity and energy.
In December 1996, the Company joined with Allegheny Power Service
Corporation, Cleveland Electric Illuminating Company, Toledo Edison Company,
Ohio Edison Company, Pennsylvania Power Company and Southern Company Services,
Inc. (the Transmission Alliance) to file a contract with the FERC entitled the
GAPP Experiment Participation Agreement (GAPP Agreement). The Transmission
Alliance and the GAPP Agreement were established to promote fair and equitable
use of the transmission systems based on the General Agreement on Parallel
Paths (GAPP) model for coordinating the flow of bulk supplies of electricity
among utilities. GAPP principles allow electric companies to determine where
electricity actually flows in bulk power transactions, as opposed to the
"contract" paths that are based on power purchase and transmission agreements
among buying, selling and transmitting utilities.
Compensation for transmission services has historically been based on
contract paths. The GAPP Agreement was designed to determine the physical path
electricity actually takes through the system and allocate open access
transmission revenues among the parties. The GAPP Agreement was designed as an
experiment to test the GAPP methods and procedures for a period of two years.
The FERC accepted the contract on March 25, 1997. The Company and the
Transmission Alliance implemented the GAPP Agreement on April 2, 1997.
On November 14, 1997, in accordance with the FERC order accepting the GAPP
Agreement, the Transmission Alliance issued a report detailing the results of
the first six months of the experiment. The preliminary results of the
experiment indicate that it is technically possible to monitor and predict the
physical flow of electricity over multiple systems and that transmission
revenues reallocated according to actual use of the system differ significantly
from collections under a contract
9
path approach. In October 1997, Virginia Power gave notice to the Transmission
Alliance that, effective January 1, 1998, it was exercising its option under
the GAPP Agreement to terminate its involvement in the experiment.
On December 9, 1997, the Company, the Transmission Alliance and other
utilities agreed to study the creation of an independent regional transmission
entity. The memorandum of understanding to initiate this study was signed by
eleven investor-owned electric companies, including Virginia Power, Consumers
Energy, Detroit Edison, Duquesne Light Company, The Illuminating Company, Ohio
Edison Company, Pennsylvania Power Company, Toledo Edison Company, and the
Allegheny Energy Companies (Monongahela Power Company, The Potomac Edison
Company, and West Penn Power Company). This group is an outgrowth of the GAPP
Agreement and its key goals are to maintain the long-term reliability and
security of the utilities' interconnected transmission systems; ensure the most
efficient use of resources; eliminate pancaking of rates within and between
transmission entities; avoid duplication of costs and achieve transmission cost
savings; and, strike an appropriate balance among the diverse interests of
energy suppliers, customers, and shareholders. The group will also explore
cooperative agreements designed to achieve these goals while ensuring
nondiscriminatory and comparable access to all users of the group's
transmission system. The companies intend to be responsive to industry changes,
especially with the introduction of retail competition in some of the areas
served by the signatories and as some other industry participants consider
creation of independent transmission operating companies or separate
transmission companies. Further, the companies will have the flexibility to
continue to investigate and pursue other opportunities and arrangements that
could develop regarding independent system operators or independent
transmission companies.
Virginia Power and Appalachian Power Company (AEP-Virginia), an operating
unit of AEP, each sought approval from the SCC in 1991 to construct certain
interconnecting transmission facilities. These applications resulted from a
joint planning effort of Virginia Power and AEP to meet the requirements of
their customers. At the time of Virginia Power's application, particularly
during the summer of 1992, constraints were being experienced on transfers of
power into the Virginia Power service territory from the west. On November 7,
1997, the SCC issued an Order directing the Company to report to the Commission
on the continued need for certain new interconnected transmission facilities,
on the relationship between the Company's application to build the new
facilities and certain other pending proceedings, and on the Company's
construction plans, if the SCC grants the Company's application.
On December 15, 1997, the Company filed a report in compliance with the
SCC Order stating that since the filing of the Company's application, the
constraints have been less frequent, due in part to less severe summer weather,
and actual power requirements have been less than originally forecasted. In
addition, generating resources within the Virginia Power service area have been
increased by the higher performance level of the nuclear units, as well as the
completion of the Clover Station. Completion of the AEP project is a
prerequisite for the Virginia Power project to go forward. The proposed
Virginia Power project would not fulfill its intended purpose without the AEP
line being built. AEP has withdrawn its original application and has instituted
a new proceeding before the Commission in which different routing is proposed.
Virginia Power continues to monitor closely the progress of AEP in this
proceeding with respect to its new proposal, but until more is known about
these proceedings, Virginia Power cannot predict what its construction plans
will be.
ITEM 2. PROPERTIES
The Company owns its principal properties in fee (except as indicated
below), subject to defects and encumbrances that do not interfere materially
with their use. Substantially all of its property is subject to the lien of a
mortgage securing its First and Refunding Mortgage Bonds. Right-of-way grants
from the apparent owners of real estate have been obtained for most electric
lines, but underlying titles have not been examined except for transmission
lines of 69 Kv or more. Where rights of way have not been obtained, they could
be acquired from private owners by condemnation if necessary. Many electric
lines are on publicly owned property, as to which permission for use is
generally revocable. Portions of the 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 G to the
CONSOLIDATED FINANCIAL STATEMENTS.
See Company Generating Units under SOURCES OF POWER under Item 1.
BUSINESS.
10
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is alleged to be in violation or in default
under orders, statutes, rules or regulations relating to the environment,
compliance plans imposed upon or agreed to by the Company, or permits issued by
various local, state and federal agencies for the construction or operation of
facilities. From time to time, there may be administrative proceedings on these
matters pending. In addition, in the normal course of business, the Company is
involved in various legal proceedings. Management believes that the ultimate
resolution of these proceedings will not have a material adverse effect on the
Company's financial position, liquidity or results of operations.
In December 1995, two civil actions were filed in the Virginia Circuit
Court of the City of Norfolk against the City of Norfolk and Virginia Power,
one for $15 million and one for $3 million, by property owners who each alleged
contamination of their respective properties by hazardous substances
originating on nearby property now owned by the city and formerly owned by the
Company. In reference to the $15 million action, the parties reached a
settlement prior to the scheduled August 18, 1997, trial date. The related
action by the other property owner seeking $3 million is still pending, but has
not yet been scheduled for trial.
On April 2, 1997, Doswell Limited Partnership (Doswell) filed a motion for
judgment against Virginia Power in the Circuit Court of the City of Richmond.
Doswell is an independent power producer that has entered into two power
purchase agreements with Virginia Power and claims the Company breached one of
those agreements. On the same date, Doswell also filed a complaint against
Virginia Power in the United States District Court for the Eastern District of
Virginia alleging certain claims relating to the two power purchase agreements.
In March 1998, the parties agreed that both proceedings should be stayed in
order to give the parties an opportunity to negotiate amendments to the power
purchase agreements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On October 17, 1997, by Consent of the Sole Shareholder, Dominion
Resources, Inc., the number of Virginia Power Directors was expanded to a
maximum of eighteen (18) and the following Directors were elected to serve for
terms expiring at the annual shareholder meetings for the years indicated
below:
John B. Bernhardt 2000
John W. Harris 1998
Kenneth A. Randall 1999
Frank S. Royal 1998
Judith B. Sack 1999
S. Dallas Simmons 2000
David A. Wollard 1999
11
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
All of the Company's Common Stock is owned by Dominion Resources.
The Company paid quarterly cash dividends on its Common Stock as follows:
1st 2nd 3rd 4th
---------- ---------- ---------- ----------
(Millions)
1997 ............. $ 95.9 $ 93.4 $ 94.7 $ 95.9
1996 ............. $ 95.3 $ 96.5 $ 96.1 $ 97.9
ITEM 6. SELECTED FINANCIAL DATA
1997 1996
------------- -------------
(Millions, except
percentages)
Revenues .................................................... $ 5,079.0 $ 4,420.9
Income from operations ...................................... 1,019.3 1,010.0
Net income .................................................. 469.1 457.3
Balance available for Common Stock .......................... 433.4 421.8
Total assets ................................................ 11,953.4 11,828.0
Total net utility plant ..................................... 9,219.2 9,433.8
Long-term debt, noncurrent capital lease obligations,
preferred stock subject to mandatory redemption and
preferred securities of subsidiary trust ................... 3,854.4 3,916.2
Utility plant expenditures (including nuclear fuel) ......... 481.8 484.0
Capitalization ratios (percent):
Debt ....................................................... 45.4 46.4
Preferred stock ............................................ 7.6 7.5
Preferred securities ....................................... 1.5 1.5
Common equity .............................................. 45.5 44.6
Embedded cost (percent):
Long-term debt ............................................. 7.60 7.68
Preferred stock ............................................ 5.25 5.14
Preferred securities ....................................... 8.72 8.72
Weighted average ........................................... 7.29 7.34
1995 1994 1993
------------- ------------- -------------
(Millions, except percentages)
Revenues .................................................... $ 4,351.9 $ 4,170.8 $ 4,187.3
Income from operations ...................................... 971.9 957.1 1,070.6
Net income .................................................. 432.8 447.1 509.0
Balance available for Common Stock .......................... 388.7 404.9 466.9
Total assets ................................................ 11,827.7 11,647.9 11,520.5
Total net utility plant ..................................... 9,573.1 9,623.4 9,459.7
Long-term debt, noncurrent capital lease obligations,
preferred stock subject to mandatory redemption and
preferred securities of subsidiary trust ................... 4,228.0 4,157.5 4,151.1
Utility plant expenditures (including nuclear fuel) ......... 577.5 660.9 712.8
Capitalization ratios (percent):
Debt ....................................................... 47.2 46.7 46.4
Preferred stock ............................................ 7.5 9.0 9.2
Preferred securities ....................................... 1.5
Common equity .............................................. 43.8 44.3 44.4
Embedded cost (percent):
Long-term debt ............................................. 7.73 7.65 7.67
Preferred stock ............................................ 5.29 5.47 4.88
Preferred securities ....................................... 8.72
Weighted average ........................................... 7.41 7.29 7.18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This Management's Discussion and Analysis of Financial Condition and
Results of Operations contains "forward-looking statements" as defined by the
Private Securities Litigation Reform Act of 1995, including (without
limitation) discussions as to expectations, beliefs, plans, objectives and
future financial performance, or assumptions underlying or concerning matters
discussed in this document. These discussions, and any other discussions,
including certain contingency matters (and their respective cautionary
statements) discussed elsewhere in this report, that are not historical facts,
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions and uncertainties that could cause actual results or
outcomes to differ materially from those expressed in the forward-looking
statements.
Some important factors that could cause actual results or outcomes to
differ materially from those discussed in the forward-looking statements
include current governmental policies and regulatory actions (including those
of FERC, the EPA, the DOE, the NRC, the Virginia Commission and the North
Carolina Commission), industry and rate structure, operation of nuclear power
facilities, acquisition and disposal of assets and facilities, operation and
storage facilities, recovery of the cost
12
of purchased power, nuclear decommissioning costs, and present or prospective
wholesale and retail competition. The business and profitability of Virginia
Power also are influenced by economic and geographic factors including
political and economic risks, changes in and compliance with environmental laws
and policies, weather conditions and catastrophic weather-related damage,
competition for retail and wholesale customers, pricing and transportation of
commodities, market demand for energy, inflation, capital market conditions,
unanticipated changes in operating expenses and capital expenditures,
competition for new energy development opportunities and legal and
administrative proceedings. All such factors are difficult to predict, contain
uncertainties that may materially affect actual results, and may be beyond the
control of Virginia Power. New factors emerge from time to time and it is not
possible for management to predict all such factors, nor can it assess the
impact of each such factor on the business of the Company.
Any forward-looking statement speaks only as of the date on which such
statement is made, and Virginia Power undertakes no obligation to update any
forward-looking statement or statements to reflect events or circumstances
after the date on which such statement is made.
Liquidity and Capital Resources
Operating activities continue to be a strong source of cash flow,
providing $1,091 million in 1997 compared to $1,115 million in 1996. The
decrease of $24 million (or 2 percent) from the previous year is attributable
to normal business fluctuations. Over the past three years, cash flow from
operating activities has, on average, covered 134 percent of our total
construction requirements and provided 81 percent of our total cash
requirements. Our remaining cash needs are met generally with proceeds from the
sale of securities and short-term borrowings.
Financing activities have represented a net outflow of cash in recent
years as strong cash flow from operations and the absence of major construction
programs have reduced the Company's reliance on debt financing.
Cash from (used in) financing activities was as follows:
1997 1996 1995
----------- ------------ -----------
(Millions)
Issuance of long-term debt ................................... $ 270.0 $ 24.5 $ 240.0
Issuance of preferred securities of subsidiary trust ......... 135.0
Issuance (Repayment) of short-term debt ...................... ( 86.2) 143.4 169.0
Repayment of long-term debt and preferred stock .............. (311.3) (284.1) (439.0)
Dividend payments ............................................ (415.6) (421.4) (438.6)
Other ........................................................ ( 13.5) ( 13.2) ( 13.7)
-------- -------- --------
Total ....................................................... $ (556.6) $ (550.8) $ (347.3)
======== ======== ========
We have taken advantage of declining interest rates by issuing new debt at
lower rates as higher-rate debt has matured. For example, in 1997, $311.3
million of the Company's long-term debt securities matured with an average
effective rate of 8.08 percent. As a partial replacement for this maturing
debt, we issued $270 million of long-term debt securities during the year with
an average effective rate of 6.84 percent.
We currently have three shelf registration statements effective with the
Securities and Exchange Commission from which we can obtain additional debt
capital: $400 million of Junior Subordinated Debentures; $375 million of Debt
Securities, including First and Refunding Mortgage Bonds, Senior Notes and
Senior Subordinated Notes filed in February 1998; and $200 million of
Medium-Term Notes, Series F. The remaining principal amount of debt that can be
issued under these registrations totals $915 million. An additional capital
resource of $100 million in preferred stock also is registered with the
Securities and Exchange Commission.
The Company has a commercial paper program that is supported by two credit
facilities totaling $500 million. Proceeds from the sale of commercial paper
are primarily used to provide working capital. Net borrowings under the program
were $226.2 million at December 31, 1997.
Investing activities in 1997 resulted in a net cash outflow of $546.1
million, primarily due to $397.0 million of construction expenditures and $84.8
million of nuclear fuel expenditures. The construction expenditures included
approximately $252.4 million for transmission and distribution projects, $52.1
million for production projects, $49.7 million for information technology
projects and $42.8 million for other projects.
13
Cash used in investing activities was as follows:
1997 1996 1995
------------ ------------ ------------
(Millions)
Utility plant expenditures (excluding AFC -- other funds) ......... $ (397.0) $ (393.8) $ (519.9)
Nuclear fuel (excluding AFC -- other funds) ....................... ( 84.8) ( 90.2) ( 57.6)
Nuclear decommissioning contributions ............................. ( 36.2) ( 36.2) ( 28.5)
Sale of accounts receivable, net .................................. (160.0)
Purchase of assets ................................................ ( 19.8) ( 13.7)
Other ............................................................. ( 8.3) ( 12.5) ( 11.1)
-------- -------- --------
Total ............................................................ $ (546.1) $ (546.4) $ (777.1)
======== ======== ========
Capital Requirements
Capacity -- The Company anticipates that kilowatt-hour sales will grow
approximately 2.36 percent a year through 2000. We will continue to pursue
capacity acquisition plans to meet the anticipated load growth and maintain a
high degree of service reliability. The additional capacity may be purchased
from others or built by the Company if we can build capacity at a lower overall
cost. We have long-term purchase agreements with Hoosier (400 MW) and AEP (500
MW) which will expire on December 31, 1999. We presently anticipate adding
peaking capacity beginning in the year 2000 to meet future load growth.
Fixed Assets -- The Company's construction and nuclear fuel expenditures
(excluding AFC), during 1998, 1999 and 2000 are expected to total $588.1
million, $476.2 million and $395.1 million, respectively. The Company presently
estimates that all of its 1998 construction and nuclear fuel expenditures will
be met through cash flow from operations.
Long-term Debt -- The Company will require $333.5 million to meet
maturities of long-term debt in 1998, which we expect to meet with cash flow
from operations and issuance of replacement debt securities. Other capital
requirements will be met through a combination of sales of securities and
short-term borrowings.
Customer Service -- The Company has adopted a plan to improve customer
service, requiring an investment in excess of $100 million. Our plan includes:
o installing automated electric meters in metropolitan and inaccessible
rural and urban locations,
o installing a new work management system,
o making technological changes to enhance the Company's ability to handle
customer calls during power outages,
o installing mobile data dispatch technology in the Company's service
fleet, accompanied by digitized mapping of our service territory, and
o initiating both local and regional distribution line improvement
projects.
Expenditures in 1997 for these projects were approximately $23 million; future
expenditures are expected to be approximately $68 million in 1998 and $15
million in 1999. We anticipate funding these projects with cash flow from
operations.
14
Results of Operations
The following is a discussion of results of operations for the years ended
1997 as compared to 1996, and 1996 as compared to 1995.
1997 Compared to 1996
Revenue changed from the prior year primarily due to the following:
1997 1996
---------- ----------
(Millions)
Revenue -- Electric Service
Customer growth ...................... $ 55.8 $ 45.1
Weather .............................. (111.1) 4.4
Base rate variance ................... ( 18.7) (35.5)
Fuel rate variance ................... 44.1 (89.6)
Other retail, net .................... 47.7 41.5
-------- -------
Total retail ....................... 17.8 (34.1)
Other electric service ............... 11.0 (49.8)
-------- -------
Total electric service ............. 28.8 (83.9)
-------- -------
Revenue -- Other
Wholesale -- power marketing ......... 363.4 96.6
Natural gas .......................... 232.6 33.2
Other, net ........................... 33.3 23.1
-------- -------
Total revenue -- other ............. 629.3 152.9
-------- -------
Total revenue ..................... $ 658.1 $ 69.0
======== =======
Electric service revenue consists of sales to retail customers in our
service territory at rates authorized by the Virginia and North Carolina
Commissions and sales to cooperatives and municipalities at wholesale rates
authorized by FERC. The primary factors affecting this revenue in 1997 were
customer growth, weather, and fuel rates.
Customer growth -- There were 50,899 new customer connections to our system
in 1997, the largest number of new connections in any year since 1990. This
had the effect of increasing our sales by $55.8 million in 1997 over 1996.
Weather -- The mild weather in 1997 caused customers to use less
electricity for heating and cooling, which reduced revenue by approximately
$111.1 million from the previous year. Heating and cooling degree days were
as follows:
1997 1996 Normal
------------ ------------- -------
Cooling degree days ............................... 1,349 1,365 1,530
Percentage change compared to prior year .......... (1.2)% (18.1)%
Heating degree days ............................... 3,787 4,131 3,726
Percentage change compared to prior year .......... (8.3)% 9.0%
Fuel rates -- The increase in fuel rate revenues is primarily attributable
to higher fuel rates which went into effect December 1, 1996, increasing
recovery of fuel costs by approximately $48.2 million. The regulatory
commissions having jurisdiction over the Company allow us to charge
customers for the cost of fuel used in generating electricity.
Other revenue includes sales of electricity beyond our service territory,
natural gas, nuclear consulting services, energy management services and other
revenue. The growth in power marketing and natural gas sales revenue is
primarily due to our success at marketing electricity and natural gas beyond
our service territory. The Company began pursuing these new lines of business
in 1996. We expect that revenue from such non-traditional business activities
will continue to grow in the near future.
15
Kilowatt-hour sales changed as follows:
Increase
(Decrease) From
Prior Year
------------------------
1997 1996
------------ ---------
Residential ............................ ( 1.8)% 2.3%
Commercial ............................. 0.6 2.3
Industrial ............................. 2.1 2.3
Public authorities ..................... ( 4.7) 2.6
Total retail sales ..................... ( 0.5) 2.4
Wholesale -- system .................... 2.5 (24.3)
Wholesale -- power marketing ........... 196.0 200.3
Total sales ............................ 17.2 6.3
The decrease in retail kilowatt-hour sales in 1997 as compared to 1996 reflects
the impact of weather on our traditional electricity service business, despite
continued customer growth. The increase in wholesale kilowatt-hour sales was
primarily due to the Company's power marketing efforts.
Fuel, net increased as compared to 1996, primarily due to the cost of the
power marketing and natural gas sales which reflects increased purchases of
energy from other wholesale power suppliers and purchases of natural gas.
System energy output by energy source and the average fuel cost for each are
shown below. Fuel cost is presented in mills (one tenth of one cent) per
kilowatt hour.
1997 1996 1995
-------------------- -------------------- --------------------
Source Cost Source Cost Source Cost
-------- --------- -------- --------- -------- ---------
Nuclear (*) .................. 34% 4.52 32% 4.48 32% 4.92
Coal (**) .................... 40 13.54 38 14.32 39 14.44
Oil .......................... 1 26.32 1 27.75 1 25.11
Purchased power, net ......... 23 21.54 27 21.99 25 22.50
Other ........................ 2 30.65 2 26.98 3 23.82
-- -- --
Total ...................... 100% 100% 100%
=== === ===
Average fuel cost .......... 12.67 13.47 13.73
- ---------
(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power
Station.
(**) Excludes ODEC's 50 percent ownership interest in the Clover Power Station.
Other operations and maintenance increased as compared to 1996 as a result
of costs associated with the growth in sales by the Company's energy services
business unit. These higher costs were offset partially by a reduction in
expenses attributable to the Company's strategic initiatives. Expenses in 1996
include high storm damage costs resulting from destructive summer storms,
including Hurricane Fran.
Depreciation and amortization increased as compared to 1996 due to the
recognition of additional depreciation and nuclear decommissioning expense to
reflect adjustments in the Company's filing currently pending before the
Virginia Commission and higher depreciation expense related to Clover Unit 2,
which began operations in March 1996. See Future Issues -- Utility Rate
Regulation for additional information on current rate proceedings.
Restructuring expenses decreased as compared to 1996 as the Company nears
completion of its Vision 2000 strategic initiative. Charges for restructuring
primarily include employee severance costs, costs to restructure agreements to
purchase power from third parties and, when necessary, to negotiate settlement
and termination of these contracts, and other costs. The Company estimates that
staffing reductions will result in annual savings, in the range of $80 million
to $90 million. However, these savings are being offset by salary increases,
outsourcing costs and increased payroll costs associated with staffing for
growth opportunities. See also Note O to the CONSOLIDATED FINANCIAL STATEMENTS.
Accelerated cost recovery represents a reserve for potential adjustments
to regulatory assets. In this increasingly competitive environment, the Company
has concluded that it is appropriate to utilize available cost reductions, such
as those generated by the Vision 2000 program, to accelerate the write-off of
unamortized regulatory assets and potentially stranded costs (see Future Issues
- -- Competition).
16
1996 Compared to 1995
Electric service revenues decreased as compared to 1995 due to the effect
of mild weather on the Company's summer retail rates, which are designed to
reflect normal weather conditions. These revenues also were affected by reduced
sales to Old Dominion Electric Cooperative (ODEC) due to the completion of
Clover Units 1 and 2, of which ODEC owns a fifty percent interest.
Other revenues increased as compared to 1995 due to growth in our power
marketing and energy services business, which was organized as a distinct
business unit in 1996.
Fuel, net increased as compared to 1995, primarily as a result of
increased energy purchases associated with our power marketing sales, offset in
part by a higher recovery of fuel expenses subject to deferral accounting in
1995.
Operations and maintenance decreased slightly as compared to 1995,
primarily as a result of a reduction in expenses attributable to the Company's
strategic initiatives, offset partly by the high storm damage costs incurred in
1996 from destructive summer storms, including Hurricane Fran.
Depreciation and amortization increased as compared to 1995, primarily as
a result of greater nuclear decommissioning expense and depreciation related to
Clover Units 1 and 2, which were placed in service in October 1995 and March
1996, respectively.
Restructuring decreased as compared to 1995 as the implementation phase of
the Vision 2000 initiative continued. Restructuring charges in 1996 included
severance costs, costs to restructure or settle certain contracts to purchase
power and other costs. In addition, 1995 restructuring costs included one-time
charges to cancel specific capital projects and adjustments to inventory and
certain real estate to reflect adoption of changes in business strategies and
processes.
Accelerated cost recovery represents a provision for management's estimate
of a reserve that may ultimately be used to accelerate the write-off of
unamortized regulatory assets and potentially stranded costs (see Future Issues
- -- Competition).
Future Issues
Competition in the Electric Industry -- General
For most of this century, the structure of the electric industry in
Virginia and throughout the United States has been relatively stable. We have
recently seen, however, federal and state developments toward increased
competition. Electric utilities have been required to open up their
transmission systems for use by potential wholesale competitors. In addition,
non-utility power producers now compete with electric utilities in the
wholesale generation market. At the federal level, retail competition is under
consideration. Some states have enacted legislation requiring retail
competition.
Today, Virginia Power faces competition in the wholesale market.
Currently, there is no general retail competition in Virginia Power's principal
service area. To the extent that competition is permitted, Virginia Power's
ability to sell power at prices that allow it to recover its prudently incurred
costs may be an issue. See Future Issues -- Competition -- Exposure to
Potentially Stranded Costs.
In response to competition, Virginia Power has successfully renegotiated
long term contracts with wholesale and large federal government customers. In
addition, the Company has obtained regulatory approval of innovative pricing
proposals for large industrial customers. Rate concessions resulting from these
contract negotiations and innovative pricing proposals are expected to reduce
the Company's 1998 revenue by approximately $40 million. To date, the Company
has not experienced any material loss of load.
Virginia Power is actively participating in the legislative and regulatory
processes relating to industry restructuring. The Company has also responded to
these trends toward competition by cutting its costs, re-engineering its core
business processes, and pursuing innovative approaches to serving traditional
markets and future markets. In addition, a significant part of the Company's
strategy relies on developing "non-traditional" businesses within the Company's
business units and subsidiaries designed to provide growth in future earnings,
including:
o Energy Services -- offering electric energy and capacity in the emerging
wholesale market as well as natural gas, and other energy related products
and services;
o Fossil & Hydro -- targeting process type industries, such as chemical,
paper, plastics and petroleum to become a service provider of
instrumentation equipment;
o Nuclear Services -- offering management and operations services to other
electric utilities;
17
o Commercial Operations -- providing power distribution related services,
including transmission and distribution, engineering and metering services
to other gas, water and electric utilities; and
o Telecommunications -- offering telecommunications services through the
Company's existing fiber-optic network.
The Company's non-traditional businesses face competition from a variety
of utility and non-utility entities. In addition, Virginia Power may from time
to time identify and investigate opportunities to expand its markets through
strategic alliances with partners whose strengths, market position and
strategies complement those of the Company.
Competition -- Wholesale
During 1997, sales to wholesale customers represented approximately 17
percent of the Company's total revenues from electric sales. Approximately 73
percent of wholesale revenues resulted from the Company's power marketing
efforts.
In July 1997, Virginia Power filed amendments to its existing rate tariffs
with FERC so it could make wholesale sales at market-based rates. Under a FERC
order conditionally accepting the Company rates for filing, Virginia Power
began making market-based sales in 1997. FERC set for hearing in June 1998 the
issue of whether transmission constraints limiting the transfer of power into
the Company's service territory provide Virginia Power with generation
dominance in localized markets. If FERC finds transmission constraints give
Virginia Power generation dominance, it could revoke or limit the scope of the
Company's market-based rate authority.
Virginia Power has successfully negotiated a new power supply arrangement
with its largest wholesale customer. The new arrangement provides for a
transition from cost-based rates to market-based rates, subject to FERC
approval. Virginia Power estimates the reduced rates, offset in part by other
revenues which may be earned under the agreement, will decrease income before
taxes by approximately $38 million through 2005. Virginia Power anticipates
that additional contract negotiations with other wholesale customers will take
place in the future.
Competition -- Retail
Currently, Virginia Power has the exclusive right to provide electricity
at retail within its assigned service territories in Virginia and North
Carolina. As a result, Virginia Power now only faces competition for retail
sales if certain of its business customers move into another utility service
territory, use other energy sources instead of electric power, or generate
their own electricity. However, both Virginia and North Carolina are
considering implementing retail competition.
Competition -- Legislative Initiatives
Virginia: In the 1998 Session, the Virginia General Assembly passed House
Bill No. 1172 (HB1172) to establish a schedule for Virginia's transition to
retail competition in the electric utility industry. The Company actively
supported HB1172, which passed both houses of the General Assembly in amended
form and now awaits action by the Governor. HB1172 requires the following:
o establishment of one or more independent system operators (ISO) and one
or more regional power exchanges (RPX) for Virginia by January 1, 2001;
o deregulation of generating facilities beginning January 1, 2002;
o transition to retail competition to begin on January 1, 2002, with
retail competition to begin on January 1, 2004;
o recovery of just and reasonable net stranded costs; and
o appropriate consumer safeguards related to stranded costs and
consideration of stranded benefits.
If HB1172 becomes law, it will become effective July 1, 1998. While the
bill establishes a timeline for the transition to competition in Virginia, a
detailed plan to implement that transition must be developed through future
legislative and regulatory action. The Company is unable at this time to
predict its timing or details.
Federal: The U.S. Congress is expected to consider federal legislation in
the near future authorizing or requiring retail competition. Virginia Power
cannot predict what, if any, definitive actions the Congress may take.
North Carolina: The 1997 Session of the North Carolina General Assembly
created a Study Commission on the Future of Electric Service in North Carolina.
An interim report is expected in 1998 with final recommendations made to the
1999 session of the North Carolina General Assembly.
18
Competition -- Regulatory Initiatives
The Virginia Commission also has been actively interested in industry
restructuring and competition, as shown in the following generic and
utility-specific proceedings.
In 1995, the Commission instituted an ongoing generic investigation on
restructuring, resulting in a number of reports by its Staff covering such
issues as retail wheeling experiments and the status of wholesale power
markets.
In November 1996, the Commission ordered Virginia Power to file studies
and reports on possible restructuring of the electric industry in Virginia. The
Commission also invited Virginia Power to submit a proposed alternative
regulation plan with its filing. A two-phase alternative regulatory plan (ARP)
was filed March 1997. During Phase I (1997 to December 2002), Virginia Power
proposed implementing a freeze of its current base rates and devoting a portion
of earnings above a 11.5% return-on-equity to accelerate the write-off of
generation-related regulatory assets and to mitigate the costs associated with
payments under power purchase contracts with non-utility generators that may be
above market if competition is authorized in Virginia. During Phase II (beyond
December 31, 2002), Virginia Power would seek Commission approval of stranded
cost recovery if retail competition is implemented in Virginia and a transition
cost charge mechanism by which stranded costs would be recovered. Virginia
Power presented illustrative estimates of stranded costs based on hypothetical
market prices as part of its Phase II filing. When the Company filed its ARP,
the Commission consolidated its consideration of the ARP with its consideration
of the Company's 1995 Annual Information Filing. For a discussion of the 1995
Annual Information Filing, See Future Issues -- Utility Rate Regulation.
In November 1997, the Commission Staff issued its report to the General
Assembly calling for a cautious, two-phase, five-year period to address
restructuring issues. The report acknowledged the need for direction from the
Virginia legislature concerning policy issues surrounding competition in the
electric industry. Virginia Power sought to withdraw its ARP in December 1997,
having concluded that resolution of the cost recovery issues raised by the ARP
was unlikely without General Assembly action. The Commission has agreed that
the Company may withdraw its support of the ARP, but has reserved the right to
continue consideration of the ARP as well as other regulatory alternatives. In
addition, the Commission will continue to consider the issues arising out of
the 1995 Annual Informational Filing (See Future Issues -- Utility Rate
Regulation).
Competition -- SFAS 71
Virginia Power's regulated rates are designed to recover its prudently
incurred costs of providing service, including the opportunity to earn a
reasonable return on its shareholder's investment. The Company's financial
statements reflect assets and costs under this cost-based rate regulation in
accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71),
"Accounting for the Effects of Certain Types of Regulation." SFAS 71 provides
that certain expenses normally reflected in income are deferred on the balance
sheet as regulatory assets and are recognized as the related amounts are
included in rates and recovered from customers. Continued accounting under SFAS
71 requires that rates designed to recover the utility's specific costs of
providing service, are, and will continue to be, established by regulators. The
presence of increasing competition that limits the utility's ability to charge
rates that recover its costs, or a change in the method of regulation with the
same effect, could result in the discontinued applicability of SFAS 71.
Rate-regulated companies are required to write off regulatory assets
against earnings whenever those assets no longer meet the criteria for
recognition as defined by SFAS 71. In addition, SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
requires a review of long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Thus, events or changes in circumstances that cause the
discontinuance of SFAS 71, and write off of regulatory assets, may also require
a review of utility plant assets for possible impairment. If such review
indicates utility plant assets are impaired, the carrying amount of the
affected assets would be written down. This would result in a loss being
charged to earnings, unless recovery of the loss is provided through operations
that remain regulated.
Virginia Power's regulated operations currently satisfy the SFAS 71
criteria. However, if events or circumstances should change so that those
criteria are no longer satisfied, management believes that a material adverse
effect on the Company's results of operations and financial position may
result. The form of cost-based rate regulation under which Virginia Power
operates is likely to evolve as a result of various legislative or regulatory
initiatives. At this time, management can predict neither the ultimate outcome
of regulatory reform in the electric utility industry nor the impact such
changes would have on Virginia Power.
19
Competition -- Exposure to Potentially Stranded Costs
Under traditional cost-based regulation, utilities have generally had an
obligation to serve supported by an implicit promise of the opportunity to
recover prudently incurred costs. The most significant potential adverse effect
of competition is "stranded costs." Stranded costs are those costs incurred or
commitments made by utilities under cost-based regulation that may not be
reasonably expected to be recovered in a competitive market.
The Company's potential exposure to stranded costs is comprised of the
following:
o long-term purchased power contracts that may be above market (see Note Q
to the CONSOLIDATED FINANCIAL STATEMENTS);
o costs pertaining to certain generating plants that may become uneconomic
in a deregulated environment;
o regulatory assets for items such as income tax benefits previously
flowed-through to customers, deferred losses on reacquired debt and other
costs; (see Note F to the CONSOLIDATED FINANCIAL STATEMENTS); and
o unfunded obligations for nuclear plant decommissioning and postretirement
benefits not yet recognized in the financial statements (see Notes C and N
to the CONSOLIDATED FINANCIAL STATEMENTS).
Any forecast of potentially stranded costs is extremely sensitive to the
various assumptions made. Such assumptions include:
o the timing and extent of customer choice in the market for electric
service;
o estimates of future competitive market prices;
o sales and load growth forecasts;
o power stations' future operating performance;
o rate revenues permitted during the transition;
o estimated costs of utility operations over time;
o mitigation opportunities;
o stranded cost recovery mechanisms and other factors.
Certain combinations of these assumptions as applied to Virginia Power
would produce little to no stranded costs; under other scenarios Virginia
Power's exposure to potentially stranded costs could be substantial.
Virginia Power has assessed the reasonableness of various possible
assumptions, but has not been able to settle on any particular combination
thereof. Thus, the Company's maximum exposure to potentially stranded costs is
uncertain. Management believes that recovery of any potentially stranded costs
is appropriate and will vigorously pursue such recovery with the regulatory
commissions having jurisdiction over its operations. However, Virginia Power
cannot predict the extent to which such costs, if any, will be recoverable from
customers. Also, in an effort to mitigate the amount at risk, the Company will
continue to implement cost reduction measures.
Utility Rate Regulation
In March 1997, the Virginia Commission issued an order that Virginia
Power's base rates be made interim and subject to refund as of March 1, 1997.
This order was the result of the Commission Staff's report on its review of
Virginia Power's 1995 Annual Informational Filing, which concluded that
Virginia Power's present rates would cause Virginia Power to earn in excess of
its authorized return on equity. The Staff found that, for purposes of
establishing rates prospectively, a rate reduction of $95.6 million (including
a one-time adjustment of $29.7 million to Virginia Power's deferred capacity
balance at December 31, 1996) may be necessary in order to realign rates to the
authorized level. Virginia Power filed its ARP in March 1997, based on 1996
financial information. Subsequently, the Commission consolidated the proceeding
concerned with the 1995 Annual Informational Filing with the proceeding that
includes the ARP proposed by the Company.
In December 1997, Virginia Power sought to withdraw its ARP, having
concluded that resolution of the cost recovery issues raised by the ARP was
unlikely without General Assembly action. The Commission has agreed that the
Company may withdraw its support of the ARP but has reserved the right to
continue consideration of the ARP as well as other regulatory alternatives. In
addition, the Commission will continue to consider the issues arising out of
the 1995 Annual Informational Filing. The Commission's Staff is scheduled to
file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed
by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A
public hearing is scheduled to commence on May 19, 1998.
Virginia Power's previous filings in this proceeding support maintaining
the Company's rates at current levels; however, opposing parties have made
filings recommending rate reductions in excess of $200 million. At this time,
management cannot predict the ultimate outcome of the proceeding and its impact
on the Company's results of operations, cash flows or financial position.
20
Utility Operations
The Company strives to operate its generating facilities in accordance
with prudent utility industry practices and in conformity with applicable
statutes, rules and regulations. Like other electric utilities, the Company's
generating facilities are subject to unanticipated or extended outages for
repairs, replacements or modification of equipment or otherwise to comply with
regulatory requirements. Such outages may involve significant expenditures not
previously budgeted, including replacement energy costs.
On September 10, 1997, the NRC published a proposed rule for financial
assurance requirements related to nuclear decommissioning. If the NRC's
proposed rule were implemented without further clarification or modification,
the Company may have to either pre-fund or provide acceptable security for a
portion of its nuclear decommissioning obligation. See Note C to the
CONSOLIDATED FINANCIAL STATEMENTS.
Environmental Matters
The Company is subject to rising costs resulting from a steadily
increasing number of federal, state and local laws and regulations designed to
protect human health and the environment. These laws and regulations affect
future planning and existing operations. They can result in increased capital,
operating and other costs as a result of compliance, remediation, containment
and monitoring obligations of the Company. These costs have been historically
recovered from customers through utility rates. However, to the extent that the
regulatory environment departs from cost-based rates, the Company's results of
operations and financial condition could be adversely impacted.
Environmental Protection and Monitoring Expenditures
The Company incurred $70.4 million, $71.1 million and $68.3 million
(including depreciation) during 1997, 1996 and 1995, respectively, in
connection with the use of environmental protection facilities and expects
these expenses to be approximately $69.1 million in 1998. In addition, capital
expenditures to limit or monitor hazardous substances were $24.6 million, $22.4
million and $23.4 million for 1997, 1996 and 1995, respectively. The amount
estimated for 1998 for these expenditures is $10.0 million.
Clean Air Act Compliance
The Clean Air Act, as amended in 1990, requires the Company to reduce its
emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx). The Clean Air Act
also requires the Company to obtain operating permits for all major emissions-
emitting facilities. Permit applications have been submitted for the Company's
power stations located in North Carolina and West Virginia. Applications for
the Company's power stations located in Virginia will be filed in 1998.
The Clean Air Act's SO2 reduction program is based on the issuance of a
limited number of SO2 emission allowances, each of which may be used as a
permit to emit one ton of SO2 into the atmosphere or may be sold to someone
else. The program is administered by the EPA. The Company's compliance plans
may include switching to lower sulfur coal, purchase of emission allowances and
installation of SO2 control equipment. Maximum flexibility and least-cost
compliance will be maintained through annual studies.
The Company began complying with Clean Air Act Phase I NOx limits at eight
of its units in Virginia in 1997, three years earlier than otherwise required.
As a result, the units will not be subject to more stringent Phase II limits
until 2008. Furthermore, in order to avoid the necessity of more stringent
regulations, the Company made voluntary commitments in 1996 to cap NOx
emissions at its Chesterfield and Yorktown Power Stations and the Chesapeake
Energy Center during the ozone season beginning in 2000.
From 1994 through 1997, the Company invested more than $160 million to
install and upgrade SO2 and NOx emission control equipment at its Mt. Storm and
Possum Point power stations. Capital expenditures related to Clean Air Act
compliance over the next five years are projected to be approximately $40
million. Changes in the regulatory environment, availability of allowances, and
emissions control technology could substantially impact the timing and
magnitude of compliance expenditures.
In November 1997, the EPA proposed new requirements for 22 states,
including North Carolina, Virginia and West Virginia, to reduce and cap
emissions of NOx. The EPA will issue a final rule by September 1998. Although
the proposal allows each state to determine how to achieve the required
reduction in emissions, the caps were calculated based on emission limits for
utility boilers. If the states in which Virginia Power operates choose to
impose this limit, major additional emission control equipment, with attendant
significant capital and operating costs, could be required.
21
Global Climate Change
In 1993, the United Nation's Global Warming Treaty became effective. The
objective of the treaty is the stabilization of greenhouse gas concentrations
at a level that would prevent man-made emissions from interfering with the
climate system.
As a continuation of the effort to limit man-made greenhouse emissions, an
international Protocol was formulated on December 10, 1997, in Kyoto, Japan.
This Protocol calls for the United States to reduce greenhouse emissions by 7
percent from 1990 baseline levels by the period 2008-2012. The Protocol will
not constitute a binding commitment unless submitted to and approved by the
United States Senate. Emission reductions of the magnitude included in the
Protocol, if adopted, would likely result in a substantial financial impact on
companies that consume or produce fossil fuel-derived electric power, including
Virginia Power.
Recently Issued Accounting Standards
During 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income," and SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." Each of these statements is effective for
fiscal years beginning after December 15, 1997. At this time, the Company does
not expect the implementation of these standards to have a material impact on
its results of operations or financial position.
Year 2000 Compliance
Virginia Power is taking an aggressive approach regarding computer issues
associated with the onset of the new millenium -- specifically, the impact of
the possible failure of computer systems and computer-driven equipment due to
the rollover to the year 2000. The year 2000 problem is pervasive and complex
as virtually every computer operation could be affected in some way by the
rollover of the two-digit year value from 99 to 00. The issue is whether
computer systems will properly recognize date-sensitive information when the
year changes to 2000. Systems that do not properly recognize such information
could generate erroneous data or fail.
If not properly addressed, the year 2000 computer problem could result in
failures in computer systems in the Company and the computer systems of third
parties with which the Company transacts business. Such failures of the
Company's or third parties' computer systems could have a material impact on
the Company's ability to conduct business.
Since January 1997, the Company has organized a formal year 2000 project
team to identify, correct or reprogram and test its systems for year 2000
compliance. At this time, the project team has completed its preliminary
assessment. Based on the team's evaluation, the costs of testing and conversion
of system applications are projected to be within the range of $30 million to
$50 million. The range is a function of our ongoing evaluation as to whether
certain systems and equipment will be corrected or replaced, which is dependent
on information yet to be obtained from suppliers and other external sources.
Maintenance or modification costs will be expensed as incurred, while the costs
of new software and hardware will be capitalized and amortized over the asset's
useful life.
At this time, Virginia Power is actively pursuing solutions to its year
2000-related computer problems in order to ensure that foreseeable situations
related to Company computer systems are effectively addressed. The Company
cannot estimate or predict the potential adverse consequences, if any, that
could result from a third party's failure to effectively address this issue.
Market Rate Sensitive Instruments and Risk Management
Virginia Power is subject to market risk as a result of its use of various
financial instruments and derivative commodity instruments. Interest rate risk
generally is associated with the Company's outstanding debt, preferred stock
and trust-issued securities. The Company also is exposed to interest rate risk
as well as equity price risk as a result of its nuclear decommissioning trust
investments in debt and equity securities.
The Company's wholesale power group is involved in trading activities
which use derivative commodity instruments. However, the fair value of such
instruments at December 31, 1997, is not material to the Company's financial
position. Also, the potential near term losses in future earnings, fair values,
or cash flows, resulting from reasonably possible near term changes in market
prices for such instruments are not anticipated to be material to the Company's
results of operations, financial position or cash flows.
22
The following analysis does not include the price risks associated with
the nonfinancial assets and liabilities of utility operations, including
underlying fuel requirements.
Interest-rate risk
Virginia Power uses both fixed rate and variable rate debt and preferred
securities as sources of capital. The following table presents the financial
instruments that are held or issued by the Company at December 31, 1997, and
are sensitive to interest rate changes in some way. Weighted average variable
rates are based on implied forward rates derived from appropriate annual spot
rate observations as of December 31, 1997.
Expected Maturity Date
--------------------------------------------------------------- Fair
1998 1999 2000 2001 2002 Thereafter Total Value
---------- --------- --------- --------- --------- ------------ ----------- -----------
(Millions of Dollars, Except Percentages)
ASSETS
Nuclear decommissioning
trust investments ............. $ 17.7 $ 5.3 $ 2.1 $ 7.1 $ 3.1 $ 165.0 $ 200.3 $ 190.7
Average interest rate (1) ..... 5.5% 5.5% 5.5% 5.5% 5.5% 5.5%
LIABILITIES -- Fixed rate
Mortgage bonds .................. 225.0 100.0 135.0 100.0 255.0 2,009.5 2,824.5 2,937.7
Average interest rate ......... 6.7% 8.9% 5.9% 6.0% 4.5% 7.6%
Medium term notes ............... 108.5 221.0 60.5 60.6 60.0 40.5 551.1 573.7
Average interest rate ......... 7.6% 8.5% 9.7% 8.4% 7.6% 9.0%
Tax-exempt financing ............ 10.0 10.0 10.4
Average interest rate ......... 5.2%
Short-term debt ................. 226.2 226.2 226.2
Average interest rate ......... 5.9%
Preferred stock, subject to
mandatory redemption ............ 180.0 180.0 186.6
Average dividend rate ......... 6.2%
Mandatorily redeemable
trust-issued preferred
securities ...................... 135.0 135.0 137.7
Average dividend rate ......... 8.1%
LIABILITIES -- Variable rate
Tax-exempt financing (2) ........ 488.6 488.6 488.6
Average interest rate ......... 4.1%
- ---------
(1) Rates are based on average yield for entire portfolio at December 31, 1997.
(2) Interest rates on the tax-exempt bonds are based on short-term, tax-exempt
market rates and are reset for periods of one to 270 days in length. The
Company has the option to convert these bonds to fixed rate securities
upon 40 days written notice. See Note H to the CONSOLIDATED FINANCIAL
STATEMENTS.
Equity price risk
The following table presents a description of marketable equity securities
held by the Company at December 31, 1997. As prescribed by Statement of
Financial Accounting Standards No. 115, "Accounting for Certain Investments in
Debt and Equity Securities," these securities are reported on the balance sheet
at fair value.
Fair
Cost Value
------------ ------------
(Millions of Dollars)
Nuclear decommissioning trust investments ......... $ 219.4 $ 360.4
23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Page
No.
-----
Report of Management ......................................................... 25
Report of Independent Auditors ............................................... 26
Consolidated Statements of Income for the years ended
December 31, 1997, 1996 and 1995 ............................................ 27
Consolidated Balance Sheets at December 31, 1997 and 1996 .................... 28
Consolidated Statements of Earnings Reinvested in Business for the years ended
December 31, 1997, 1996 and 1995 ............................................ 30
Consolidated Statements of Cash Flows for the years ended
December 31, 1997, 1996 and 1995 ............................................ 31
Notes to Consolidated Financial Statements ................................... 32
24
REPORT OF MANAGEMENT
The Company's management is responsible for all information and
representations contained in the Consolidated Financial Statements and other
sections of the Company's annual report on Form 10-K. The Consolidated
Financial Statements, which include amounts based on estimates and judgments of
management, have been prepared in conformity with generally accepted accounting
principles. Other financial information in the Form 10-K is consistent with
that in the Consolidated Financial Statements.
Management maintains a system of internal accounting controls designed to
provide reasonable assurance, at a 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 1997 the system of internal control was adequate to
accomplish the intended objective.
The Consolidated Financial Statements have been audited by Deloitte &
Touche LLP, independent auditors, who have been engaged by the Board of
Directors. Their audits were conducted in accordance with generally accepted
auditing 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
Consolidated Financial Statements are not materially misleading and do not
contain material errors.
The Audit Committee of the Board of Directors, composed entirely of
directors who are not officers or employees of the Company, meets periodically
with the independent auditors, the internal auditors and management to discuss
auditing, internal accounting control and financial reporting matters and to
ensure that each is properly 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
Norman Askew M. S. Bolton, Jr.
President and Controller and
Chief Executive Principal Accounting
Officer Officer
25
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors of Virginia Electric and Power Company:
We have audited the accompanying consolidated balance sheets of Virginia
Electric and Power Company (a wholly owned subsidiary of Dominion Resources,
Inc.) and subsidiaries (the Company) as of December 31, 1997 and 1996, and the
related consolidated statements of income, earnings reinvested in business, and
cash flows for each of the three years in the period ended December 31, 1997.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material 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 consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
1997 and 1996, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1997, in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Richmond, Virginia
February 9, 1998
26
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended
December 31,
-----------------------------------------
1997 1996 1995
------------- ------------- -------------
(Millions)
Revenues:
Electric service ......................................... $ 4,239.0 $ 4,210.2 $ 4,294.1
Other .................................................... 840.0 210.7 57.8
---------- ---------- ----------
Total ................................................... 5,079.0 4,420.9 4,351.9
---------- ---------- ----------
Expenses: ..................................................
Fuel, net ................................................ 1,620.7 1,016.6 1,009.7
Purchased power capacity, net ............................ 717.5 700.6 688.4
Operations and maintenance ............................... 812.7 803.1 805.6
Depreciation and amortization ............................ 549.9 502.0 469.1
Restructuring ............................................ 18.4 64.9 117.9
Accelerated cost recovery ................................ 38.4 26.7
Amortization of terminated construction project costs .... 34.4 34.4 34.4
Taxes other than income .................................. 267.7 262.6 254.9
---------- ---------- ----------
Total ................................................... 4,059.7 3,410.9 3,380.0
---------- ---------- ----------
Income from operations ..................................... 1,019.3 1,010.0 971.9
Other income ............................................... 14.2 6.8 10.0
---------- ---------- ----------
Income before interest and income taxes .................... 1,033.5 1,016.8 981.9
---------- ---------- ----------
Interest and related charges:
Interest expense, net .................................... 304.2 308.4 317.9
Distributions -- preferred securities of subsidiary trust 10.9 10.9 3.7
---------- ---------- ----------
Total ................................................... 315.1 319.3 321.6
---------- ---------- ----------
Income before income taxes ................................. 718.4 697.5 660.3
Income taxes ............................................... 249.3 240.2 227.5
---------- ---------- ----------
Net income ................................................. 469.1 457.3 432.8
Preferred dividends ........................................ 35.7 35.5 44.1
---------- ---------- ----------
Balance available for Common Stock ......................... $ 433.4 $ 421.8 $ 388.7
========== ========== ==========
The accompanying notes are an integral part of the financial statements.
27
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS
Assets
At December 31,
-------------------------
1997 1996
------------ ------------
(Millions of Dollars)
CURRENT ASSETS:
Cash and cash equivalents ........................................................ $ 36.0 $ 47.9
Accounts receivable:
Customers (less allowance for doubtful accounts of $2.4 in 1997 and 1996) ...... 462.4 354.8
Other .......................................................................... 108.0 80.4
Accrued unbilled revenues ........................................................ 245.2 180.3
Materials and supplies at average cost or less:
Plant and general .............................................................. 145.2 148.7
Fossil fuel .................................................................... 67.4 76.8
Other ............................................................................ 134.7 107.0
---------- ----------
Total current assets .......................................................... 1,198.9 995.9
---------- ----------
INVESTMENTS:
Nuclear decommissioning trust funds .............................................. 569.1 443.3
Other ............................................................................ 38.3 34.5
---------- ----------
Total net investments .......................................................... 607.4 477.8
---------- ----------
DEFERRED DEBITS AND OTHER ASSETS:
Regulatory assets:
Deferred capacity expenses ..................................................... 47.3 6.1
Other .......................................................................... 729.3 767.8
Unamortized debt issuance costs .................................................. 24.2 24.7
Other ............................................................................ 127.1 121.9
---------- ----------
Total deferred debits and other assets ......................................... 927.9 920.5
---------- ----------
UTILITY PLANT:
Plant (includes plant under construction of $240.9 in 1997 and $180.1 in 1996) ... 14,794.2 14,506.8
Less accumulated depreciation .................................................... 5,724.3 5,218.3
---------- ----------
9,069.9 9,288.5
Nuclear fuel (less accumulated amortization of $705.0 in 1997 and $698.5 in 1996) 149.3 145.3
---------- ----------
Total net utility plant ........................................................ 9,219.2 9,433.8
---------- ----------
Total assets ................................................................... $ 11,953.4 $ 11,828.0
========== ==========
The accompanying notes are an integral part of the financial statements.
28
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS
Liabilities and Shareholders' Equity
At December 31,
---------------------------
1997 1996
------------- -------------
(Millions of Dollars)
CURRENT LIABILITIES:
Securities due within one year .................................... $ 333.5 $ 311.3
Short-term debt ................................................... 226.2 312.4
Accounts payable, trade ........................................... 452.0 368.5
Customer deposits ................................................. 44.6 50.0
Payrolls accrued .................................................. 77.5 73.2
Severance costs accrued ........................................... 29.7 50.2
Interest accrued .................................................. 95.1 95.3
Other ............................................................. 161.6 126.1
---------- ----------
Total current liabilities ........................................ 1,420.2 1,387.0
---------- ----------
LONG-TERM DEBT ...................................................... 3,514.6 3,579.4
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes ................................. 1,607.0 1,565.2
Deferred investment tax credits ................................... 238.4 255.3
Deferred fuel expenses ............................................ 12.8 3.3
Other ............................................................. 220.3 151.1
---------- ----------
Total deferred credits and other liabilities .................... 2,078.5 1,974.9
---------- ----------
COMMITMENTS AND CONTINGENCIES (See Note Q)
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST* ................................... 135.0 135.0
---------- ----------
PREFERRED STOCK:
Preferred stock subject to mandatory redemption ................... 180.0 180.0
---------- ----------
Preferred stock not subject to mandatory redemption ............... 509.0 509.0
---------- ----------
COMMON STOCKHOLDER'S EQUITY:
Common Stock, no par, 300,000 shares authorized, 171,484 shares
outstanding at December 31, 1997 and 1996 ........................ 2,737.4 2,737.4
Other paid-in capital ............................................. 16.9 16.9
Earnings reinvested in business ................................... 1,361.8 1,308.4
---------- ----------
Total common stockholder's equity ................................ 4,116.1 4,062.7
---------- ----------
Total liabilities and shareholders' equity ....................... $ 11,953.4 $ 11,828.0
========== ==========
(*) As described in Note I to CONSOLIDATED FINANCIAL STATEMENTS, the 8.05%
Junior Subordinated Notes totalling $139.2 million principal amount
constitute 100% of the Trust's assets.
The accompanying notes are an integral part of the financial statements.
29
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS REINVESTED IN BUSINESS
For the Years Ended December 31,
-----------------------------------------
1997 1996 1995
------------- ------------- -------------
(Millions)
Balance at beginning of year ........................ $ 1,308.4 $ 1,272.5 $ 1,277.8
Net income .......................................... 469.1 457.3 432.8
---------- ---------- ----------
Total .............................................. 1,777.5 1,729.8 1,710.6
---------- ---------- ----------
Cash dividends:
Preferred stock subject to mandatory redemption .... 11.1 11.1 13.5
Preferred stock not subject to mandatory redemption 24.7 24.5 30.8
Common Stock ....................................... 379.9 385.8 394.3
---------- ---------- ----------
Total dividends ................................... 415.7 421.4 438.6
---------- ---------- ----------
Other additions (deductions), net ................... 0.5
----------
Balance at end of year .............................. $ 1,361.8 $ 1,308.4 $ 1,272.5
========== ========== ==========
The accompanying notes are an integral part of the financial statements.
30
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
-------------------------------------
1997 1996 1995
------------ ------------ -----------
(Millions)
Cash Flow From Operating Activities:
Net income ........................................................................... $ 469.1 $ 457.3 $ 432.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization ....................................................... 664.7 616.0 585.1
Deferred income taxes ............................................................... 36.1 69.1 11.8
Deferred investment tax credits ..................................................... ( 16.9) ( 16.9) ( 16.9)
Noncash return on terminated construction project costs -- pretax ................... ( 4.2) ( 6.4) ( 8.4)
Deferred fuel expenses, net ......................................................... 9.6 ( 54.4) 6.2
Deferred capacity expenses .......................................................... ( 41.2) ( 9.2) 6.4
Restructuring ....................................................................... 12.5 29.6 96.2
Accelerated cost recovery ........................................................... 38.4 26.7
Changes in:
Accounts receivable ................................................................ ( 135.2) ( 11.3) ( 54.3)
Accrued unbilled revenues .......................................................... ( 64.9) 17.6 ( 27.7)
Materials and supplies ............................................................. 12.9 6.0 61.1
Accounts payable, trade ............................................................ 82.8 57.8 ( 8.9)
Accrued expenses ................................................................... ( 13.9) ( 62.6) 44.7
Other ............................................................................... 41.0 ( 4.0) ( 2.7)
--------- --------- ---------
Net Cash Flow From Operating Activities ............................................... 1,090.8 1,115.3 1,125.4
Cash Flow From (To) Financing Activities:
Issuance of long-term debt ........................................................... 270.0 24.5 240.0
Issuance of preferred securities of subsidiary trust ................................. 135.0
Issuance (Repayment) of short-term debt .............................................. ( 86.2) 143.4 169.0
Repayment of long-term debt and preferred stock ...................................... ( 311.3) ( 284.1) ( 439.0)
Common Stock dividend payments ....................................................... ( 379.9) ( 385.8) ( 394.3)
Preferred stock dividend payments .................................................... ( 35.7) ( 35.6) ( 44.3)
Distribution-preferred securities of subsidiary trust ................................ ( 10.9) ( 10.9) ( 3.7)
Other ................................................................................ ( 2.6) ( 2.3) ( 10.0)
--------- --------- ---------
Net Cash Flow To Financing Activities ................................................. ( 556.6) ( 550.8) ( 347.3)
--------- --------- ---------
Cash Flow Used In Investing Activities:
Utility plant expenditures (excluding AFC -- other funds) ............................ ( 397.0) ( 393.8) ( 519.9)
Nuclear fuel (excluding AFC -- other funds) .......................................... ( 84.8) ( 90.2) ( 57.6)
Nuclear decommissioning contributions ................................................ ( 36.2) ( 36.2) ( 28.5)
Sale of accounts receivable, net ..................................................... ( 160.0)
Purchase of assets ................................................................... ( 19.8) ( 13.7)
Other ................................................................................ ( 8.3) ( 12.5) ( 11.1)
--------- --------- ---------
Net Cash Flow Used In Investing Activities ............................................ ( 546.1) ( 546.4) ( 777.1)
--------- --------- ---------
Increase in cash and cash equivalents ................................................. ( 11.9) 18.1 1.0
Cash and cash equivalents at beginning of year ........................................ 47.9 29.8 28.8
--------- --------- ---------
Cash and cash equivalents at end of year .............................................. $ 36.0 $ 47.9 $ 29.8
========= ========= =========
Cash paid during the year for:
Interest (reduced for the cost of borrowed funds capitalized as AFC) ................. $ 277.1 $ 295.4 $ 314.5
Income taxes ......................................................................... 230.0 216.1 215.8
The accompanying notes are an integral part of the financial statements.
31
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Significant Accounting Policies:
General
Virginia Electric and Power Company is a regulated public utility engaged
in the generation, transmission, distribution and sale of electric energy
within a 30,000 square-mile area in Virginia and northeastern North Carolina.
It sells electricity to retail customers (including governmental agencies) and
to wholesale customers such as rural electric cooperatives, municipalities,
power marketers and other utilities. The Virginia service area comprises about
65 percent of Virginia's total land area, but accounts for over 80 percent of
its population. The Company has organized a wholesale power group to engage in
off-system wholesale purchases and sales of electricity and purchases and sales
of natural gas, and that group is developing trading relationships beyond the
geographic limits of Virginia Power's retail service territory. Within this
document, the terms "Virginia Power" and the "Company" shall refer to the
entirety of Virginia Electric and Power Company, including, without limitation,
its Virginia and North Carolina operations, and all of its subsidiaries.
The Company's accounting practices are generally prescribed by the Uniform
System of Accounts promulgated by the regulatory commissions having
jurisdiction and are in accordance with generally accepted accounting
principles applicable to regulated enterprises. The financial statements
include the accounts of the Company and its subsidiaries, with all significant
intercompany transactions and accounts being eliminated on consolidation.
The Company is a wholly-owned subsidiary of Dominion Resources, Inc., a
Virginia corporation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
disclosure of contingent liabilities at the date of the financial statements
and revenues and expenses during the reporting period. Actual results could
differ from those estimates.
Revenues
Revenues are recorded on the basis of services rendered, commodities
delivered or contracts settled.
Property, Plant and Equipment
Utility plant is recorded at original cost, which includes labor,
materials, services, AFC, where permitted by regulators, and other indirect
costs. The cost of maintenance and repairs is charged to the appropriate
operating expense and clearing accounts. The cost of additions and replacements
is charged to the appropriate utility plant account, except that the cost of
minor additions and replacements, as provided in the Uniform System of
Accounts, is charged to maintenance expense.
Depreciation and Amortization
Depreciation of utility plant (other than nuclear fuel) is computed on the
straight-line method based on projected 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 provides
for the recovery of the cost of assets including the estimated cost of removal,
net of salvage, and is based on the weighted average depreciable plant using a
rate of 3.2 percent for 1997, 1996 and 1995.
Operating expenses include amortization of nuclear fuel, which is provided
on a unit of production basis sufficient to fully amortize, over the estimated
service life, the cost of the fuel plus permanent storage and disposal costs.
Federal Income Taxes
The Company files a consolidated federal income tax return with Dominion
Resources.
Deferred investment tax credits are being amortized over the service lives
of the property giving rise to such credits.
32
Allowance for Funds Used During Construction
The applicable regulatory Uniform System of Accounts defines AFC as the
cost during the construction period of borrowed funds used for construction
purposes and a reasonable rate on other funds when so used.
The pretax AFC rates for 1997, 1996 and 1995 were 6.6 percent, 8.1 percent
and 8.9 percent, respectively. No AFC is accrued for approximately 83 percent
of the Company's construction work in progress, which is instead included in
rate base. A cash return is currently collected on the portion of construction
work in progress included in rate base.
Deferred Capacity and Deferred Fuel Expense
Approximately 80 percent of capacity expenses and 90 percent of fuel
expenses incurred as part of providing regulated electric service are subject
to deferral accounting. The difference between reasonably incurred actual
expenses and the level of expenses included in current rates is deferred and
matched against future revenues.
Amortization of Debt Issuance Costs
The Company defers and amortizes any expenses incurred in the issuance of
long-term debt, including premiums and discounts associated with such debt,
over the lives of the respective issues. Any gains or losses resulting from the
refinancing of debt are also deferred and amortized over the lives of the new
issues of long-term debt as permitted by the appropriate regulatory
jurisdictions. Gains or losses resulting from the redemption of debt without
refinancing are amortized over the remaining lives of the redeemed issues.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded
until actually presented for payment. At December 31, 1997 and 1996, the
Company's accounts payable included the net effect of checks outstanding but
not yet presented for payment of $55.8 million and $64.8 million, respectively.
For purposes of the Consolidated Statements of Cash Flows, the Company
considers cash and cash equivalents to include cash on hand and temporary
investments purchased with an initial maturity of three months or less.
Commodity Contracts
The trading activities of Virginia Power's wholesale power group include
fixed-price forward contracts and the purchase and sale of over-the-counter
options that require physical delivery of the underlying commodity.
Furthermore, in order to manage price risk associated with natural gas sales
and fuel requirements for the utility operations, the Company uses
exchange-for-physical contracts, basis swaps, NYMEX natural gas futures
contracts, as well as options on natural gas futures contracts.
Options, exchange-for-physical contracts, basis swaps and futures
contracts are marked to market with resulting gains and losses reported in
earnings, unless such instruments are designated as hedges for accounting
purposes. Fixed price forward contracts, initiated for trading purposes, also
are marked to market with resulting gains and losses reported in earnings. For
exchange-for-physical contracts, basis swaps, fixed price forward contracts and
options which require physical delivery of the underlying commodity, market
value reflects management's best estimates considering over-the-counter
quotations, time value and volatility factors of the underlying commitments.
Futures contracts and options on futures contracts are marked to market based
on closing exchange prices. No contracts were designated as hedges during 1997.
Purchased options and options sold are reported in Deferred Debits and
Other Assets -- Other and in Deferred Credits and Other Liabilities -- Other,
respectively, until exercise or expiration. Gains and losses resulting from
marking positions to market are reported in Other Income. Net gains and losses
resulting from futures contracts and options on futures contracts and
settlement of basis swaps are included in Fuel, Net. Amortization of option
premiums associated with sales and purchases are included in Revenues -- Other
and Fuel, Net, respectively. Cash flows from trading activities are reported in
Net Cash Flow from Operating Activities.
Reclassification
Certain amounts in the 1996 and 1995 financial statements have been
reclassified to conform to the 1997 presentation.
33
B. Income Taxes:
Details of income tax expense are as follows:
Years
---------------------------------------
1997 1996 1995
----------- ----------- -----------
(Millions)
Current expense:
Federal ................................................. $ 222.1 $ 185.6 $ 230.6
State ................................................... 8.6 2.4 2.1
-------- -------- --------
230.7 188.0 232.7
-------- -------- --------
Deferred expense:
Utility plant differences ............................... 41.3 65.4 48.9
Deferred fuel and capacity .............................. 11.0 22.3 ( 6.0)
Debt issuance costs ..................................... ( 2.1) ( 2.8) 1.3
Terminated construction project costs ................... ( 5.8) ( 5.1) ( 4.4)
Other ................................................... ( 8.9) ( 10.7) ( 28.1)
-------- -------- --------
35.5 69.1 11.7
-------- -------- --------
Net deferred investment tax credits-amortization ......... ( 16.9) ( 16.9) ( 16.9)
-------- -------- --------
Total income tax expense ................................. $ 249.3 $ 240.2 $ 227.5
======== ======== ========
Total federal income tax expense differs from the amount computed by
applying the statutory federal income tax rate to pretax income for the
following reasons:
Years
---------------------------------------
1997 1996 1995
----------- ----------- -----------
(Millions)
Federal income tax expense at statutory rate of 35 percent ......... $ 251.4 $ 244.1 $ 231.1
------- ------- -------
Increases (decreases) resulting from:
Utility plant differences ......................................... 7.7 5.7 3.2
Ratable amortization of investment tax credits .................... ( 16.9) ( 16.9) ( 16.9)
Terminated construction project costs ............................. 5.0 5.0 5.0
State income tax, net of federal tax benefit ...................... 4.9 2.4 2.2
Other, net ........................................................ ( 2.8) ( 0.1) 2.9
-------- -------- --------
( 2.1) ( 3.9) ( 3.6)
-------- -------- --------
Total income tax expense ........................................... $ 249.3 $ 240.2 $ 227.5
======== ======== ========
Effective tax rate ................................................. 34.7% 34.4% 34.5%
The Company's net accumulated deferred income taxes consist of the
following:
Years
---------------------------
1997 1996
------------ ------------
(Millions)
Deferred income tax assets:
Investment tax credits ................................ $ 84.4 $ 90.3
--------- ---------
Deferred income tax liabilities:
Utility plant differences ............................. 1,479.8 1,440.5
Terminated construction project costs ................. 8.6 14.4
Income taxes recoverable through future rates ......... 169.5 168.8
Other ................................................. 33.5 31.8
--------- ---------
Total deferred income tax liabilities .................. 1,691.4 1,655.5
--------- ---------
Total net accumulated deferred income taxes ............ $ 1,607.0 $ 1,565.2
========= =========
34
C. Nuclear Operations:
Decommissioning
When the Company's nuclear units cease operations, we are obligated to
decontaminate or remove radioactive contaminants so that the property will not
require NRC oversight. This phase of a nuclear power plant's life cycle is
termed decommissioning. While the units are operating, we are collecting from
ratepayers amounts that, when combined with investment earnings, will be used
to fund this future obligation.
The amount being accrued for decommissioning is equal to the amount being
collected from ratepayers and is included in Depreciation and Amortization
Expense. The decommissioning collections were $45.8 million, $36.2 million and
$28.5 million in 1997, 1996 and 1995, respectively. These dollars are deposited
into external trusts through which the funds are invested.
Net earnings of the trusts' investments are included in Other Income in
the Company's Consolidated Statements of Income. In 1997, 1996 and 1995,
respectively, net earnings were $20.5 million, $16.0 million and $15.9 million.
The accretion of the decommissioning obligation is equal to the trusts' net
earnings and also is recorded in Other Income. Thus, the net impact of the
trusts on Other Income is zero.
The accumulated provision for decommissioning, which is included in
Utility Plant Accumulated Depreciation in the Company's Consolidated Balance
Sheets, includes the accrued expense and accretion described above and any
unrealized gains and losses on the trusts' investments. At December 31, 1997,
the net unrealized gains were $149.5 million, which is an increase of $69.0
over the December 31, 1996, amount of $80.5 million. The total accumulated
provision for decommissioning at December 31, 1997, was $578.7 million,
including $9.6 million accrued in 1997 and deposited to the trusts in January
1998. The provision was $443.3 million at December 31, 1996.
The total estimated cost to decommission the Company's four nuclear units
is $1 billion based upon a site-specific study that was completed in 1994. We
plan to update this estimate in 1998. The cost estimate assumes that the method
of completing decommissioning activities is prompt dismantlement. This method
assumes that dismantlement and other decommissioning activities will begin
shortly after cessation of operations, which under current operating licenses
will begin in 2012 as detailed in the table below.
Surry North Anna
------------------------- ------------------------- Total
Unit 1 Unit 2 Unit 1 Unit 2 All Units
----------- ----------- ----------- ----------- -------------
NRC license expiration year .................. 2012 2013 2018 2020
(Millions)
Current cost estimate (1994 dollars) ......... $ 272.4 $ 274.0 $ 247.0 $ 253.6 $ 1,047.0
Funds in external trusts at 12/31/97 ......... 156.5 151.8 134.2 126.6 569.1
1997 contribution to external trusts ......... 10.6 10.8 7.6 7.2 36.2
The Financial Accounting Standards Board (FASB) is reviewing the
accounting for nuclear plant decommissioning. In 1996, the FASB tentatively
determined that the estimated cost of decommissioning should be reported as a
liability rather than as accumulated depreciation and that a substantial
portion of the decommissioning obligation should be recognized earlier in the
operating life of the nuclear unit. If the industry's accounting were changed
to reflect FASB's tentative proposal, then the annual provisions for nuclear
decommissioning would increase. During its deliberations, the FASB expanded the
scope of the project to include similar unavoidable obligations to perform
closure and post-closure activities for non-nuclear power plants. Therefore,
any forthcoming standard also may change industry plant depreciation practices.
Any impact related to other Company assets cannot be determined at this time.
Insurance
The Price-Anderson Act limits the public liability of an owner of a
nuclear power plant to $8.9 billion for a single nuclear incident. The
Price-Anderson Amendments Act of 1988 allows for an inflationary provision
adjustment every five years. The Company has purchased $200 million of coverage
from the commercial insurance pools with the remainder 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.
35
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 $12.3 million (including a 3 percent
insurance premium tax for Virginia).
The Company's current level of property insurance coverage ($2.55 billion
for North Anna and $2.40 billion for Surry) exceeds the NRC's minimum
requirement for nuclear power plant licensees of $1.06 billion per reactor site
and includes coverage for premature decommissioning and functional total loss.
The NRC requires that the proceeds from this insurance be used first to return
the reactor to and maintain it in a safe and stable condition and second to
decontaminate the reactor and station site in accordance with a plan approved
by the NRC. The Company's nuclear property insurance is provided by Nuclear
Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL), two mutual
insurance companies, and is subject to retrospective premium assessments, in
any policy year in which losses exceed the funds available to these insurance
companies. The maximum assessment for the current policy period is $37.0
million. Based on the severity of the incident, the Boards of Directors of the
Company's nuclear insurers have the discretion to lower the maximum
retrospective premium assessment or eliminate either or both completely. For
any losses that exceed the limits or for which insurance proceeds are not
available because they must first be used for stabilization and
decontamination, the Company has the financial responsibility for these losses.
The Company purchases insurance from NEIL to cover the cost of replacement
power during the prolonged outage of a nuclear unit due to direct physical
damage of the unit. Under this program, Virginia Power is subject to a
retrospective premium assessment for any policy year in which losses exceed
funds available to NEIL. The current policy period's maximum assessment is $8.7
million.
As part owner of the North Anna Power Station, ODEC is responsible for its
share of the nuclear decommissioning obligation and insurance premiums
applicable to that station, including any retrospective premium assessments and
any losses not covered by insurance.
D. Utility Plant:
Utility plant consisted of the following:
At December 31,
-----------------------------
1997 1996
------------- -------------
(Millions)
Production ............................ $ 7,684.2 $ 7,691.9
Transmission .......................... 1,415.7 1,386.5
Distribution .......................... 4,559.2 4,385.4
Other ................................. 894.2 862.9
---------- ----------
14,553.3 14,326.7
Construction work in progress ......... 240.9 180.1
---------- ----------
Total ............................. $ 14,794.2 $ 14,506.8
========== ==========
36
E. Jointly Owned Plants:
The following information relates to the Company's proportionate share of
jointly owned plants at December 31, 1997:
North
Bath County Anna Clover
Pumped Storage Power Power
Station Station Station
---------------- ------------ ----------
Ownership interest ............................... 60.0% 88.4% 50.0%
(Millions)
Utility plant in service ......................... $ 1,072.9 $ 1,819.4 $ 533.3
Accumulated depreciation ......................... 229.1 819.2 26.3
Nuclear fuel ..................................... 403.6
Accumulated amortization of nuclear fuel ......... 383.4
Construction work in progress .................... .1 61.2 1.1
The co-owners are obligated to pay their share of all future construction
expenditures and operating costs of the jointly owned facilities in the same
proportion as their respective ownership interest. The Company's share of
operating costs is classified in the appropriate operating expense (fuel,
operations and maintenance, depreciation, taxes, etc.) in the Consolidated
Statements of Income.
F. Regulatory Assets-Other
Certain expenses normally reflected in income are deferred on the balance
sheet as regulatory assets and are recognized in income as the related amounts
are included in rates and recovered from customers. The Company's regulatory
assets included the following:
At December 31,
-------------------------
1997 1996
----------- -----------
(Millions)
Income taxes recoverable through future rates ..................... $ 478.9 $ 477.0
Cost of decommissioning DOE uranium enrichment facilities ......... 67.6 73.5
Deferred losses on reacquired debt, net ........................... 85.4 91.5
North Anna Unit 3 project termination costs ....................... 42.3 73.1
Other ............................................................. 55.1 52.7
-------- --------
Total ............................................................. $ 729.3 $ 767.8
======== ========
Income taxes recoverable through future rates represent principally the
tax effect of depreciation differences not normalized in earlier years for
ratemaking purposes. These amounts are amortized as the related temporary
differences reverse.
The costs of decommissioning the Department of Energy's (DOE) uranium
enrichment facilities have been deferred and represent the unamortized portion
of Virginia Power's required contributions to a fund for decommissioning and
decontaminating the DOE's uranium enrichment facilities. Virginia Power is
making such contributions over a 15-year period with escalation for inflation.
These costs are being recovered in fuel rates.
Losses or gains on reacquired debt are deferred and amortized over the
lives of the new issues of 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. For
Virginia and FERC jurisdictional customers, the amounts deferred are being
amortized from the date termination costs were first includible in rates.
The incurred costs underlying these regulatory assets may represent
expenditures by the Company or may represent the recognition of liabilities
that ultimately will be settled at some time in the future. For some of those
regulatory assets representing past expenditures that are not included in the
Company's rate base or used to adjust the Company's capital structure, the
Company is not allowed to earn a return on the unrecovered balance. Of the
$729.3 million of regulatory assets at December 31, 1997, approximately $57.7
million represent past expenditures that are effectively excluded from rate
base by the Virginia State Corporation Commission which has primary
jurisdiction over the Company's rates. However, of that amount $42.3 million
represent the present value of amounts to be recovered through future rates for
North Anna Unit 3
37
project termination costs, and thus reflect a reduction in the actual dollars
to be recovered through future rates for the time value of money. The Company
does not earn a return on the remaining $15.4 million of regulatory assets,
effectively excluded from rate base, to be recovered over various recovery
periods up to 21 years, depending on the nature of the deferred costs.
G. Leases:
Plant and property under capital leases included the following:
At December 31,
-----------------------
1997 1996
---------- ----------
(Millions)
Office buildings (*) ...................................... $ 34.4 $ 34.4
Data processing equipment ................................. 13.3 2.5
------- -------
Total plant and property under capital leases ......... 47.7 36.9
Less accumulated amortization ............................. 17.8 13.3
------- -------
Net plant and property under capital leases ............... $ 29.9 $ 23.6
======= =======
- ---------
(*) The Company leases its principal office building from its parent, Dominion
Resources. The capitalized cost of the property under that lease, net of
accumulated amortization, represented $22 million and $23 million at December
31, 1997 and 1996, respectively. Rental payments for such lease were $3 million
for each of the three years ended December 31, 1997, 1996 and 1995.
The Company is responsible for expenses in connection with the leases
noted above, 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, 1997, are as follows:
Capital Operating
Leases Leases
--------- ----------
(Millions)
1998 ................................................... $ 7.1 $ 11.4
1999 ................................................... 6.4 9.9
2000 ................................................... 4.3 7.1
2001 ................................................... 3.2 3.9
2002 ................................................... 3.0 3.2
After 2002 ............................................. 16.7 22.9
------ -------
Total future minimum lease payments .................... $ 40.7 $ 58.4
=======
Less interest element included above ................... 10.8
------
Present value of future minimum lease payments ......... $ 29.9
======
Rents on leases, which have been charged to operations expense, were $17.6
million, $16.5 million and $13.6 million for 1997, 1996 and 1995, respectively.
38
H. Long-term Debt:
Long-term debt included the following:
At December 31,
--------------------------
1997 1996
------------ -----------
(Millions)
First and Refunding Mortgage Bonds (1):
Series U, 5.125%, due 1997 ................................. $ 49.3
1992 Series B, 7.25%, due 1997 ............................. 250.0
1988 Series A, 9.375%, due 1998 ............................ $ 150.0 150.0
1992 Series F, 6.25%, due 1998 ............................. 75.0 75.0
1989 Series B, 8.875%, due 1999 ............................ 100.0 100.0
1993 Series C, 5.875%, due 2000 ............................ 135.0 135.0
Various series, 6.0-8%, due 2001-2004 ...................... 805.0 805.0
Various series 6.75%-7.625%, due 2007 ...................... 415.0 215.0
Various series, 5.45%-8.75%, due 2021-2025 ................. 1,144.5 1,144.5
--------- ---------
Total First and Refunding Mortgage Bonds ................ 2,824.5 2,923.8
--------- ---------
Other long-term debt:
Term notes:
Fixed interest rate, 6.15%-10.00%, due 1997-2003 ......... 551.1 503.1
Tax exempt financings (2):
Money Market Municipals, due 2007-2027(3) ................ 488.6 488.6
Convertible interest rate, due 2022 ...................... 10.0
---------
Total other long-term debt .............................. 1,049.7 991.7
--------- ---------
3,874.2 3,915.5
--------- ---------
Less amounts due within one year:
First and Refunding Mortgage Bonds ......................... 225.0 299.3
Term notes ................................................. 108.5 12.0
--------- ---------
Total amount due within one year ........................ 333.5 311.3
--------- ---------
Less unamortized discount, net of premium ................... 26.1 24.8
--------- ---------
Total long-term debt .................................... $ 3,514.6 $ 3,579.4
========= =========
- ---------
(1) The First and Refunding Mortgage Bonds are secured by a mortgage lien
on substantially all of the Company's property.
(2) Certain pollution control facilities at the Company's generating
facilities have been pledged or conveyed to secure the financings.
(3) Interest rates vary based on short-term, tax-exempt market rates. For
1997 and 1996, the weighted average daily interest rates were 3.74 percent and
3.57 percent, respectively. Although these bonds are re-marketed within a one
year period, they are classified as long-term debt because the Company intends
to maintain the debt and they are supported by long-term bank commitments.
The following amounts of debt will mature during the next five years (in
millions): 1998 -- $333.5; 1999 -- $321.0; 2000 -- $195.5; 2001 -- $160.7; and
2002 -- $315.0.
I. Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
Trust:
Virginia Power Capital Trust I (VP Capital Trust) was established as a
subsidiary of the Company for the sole purpose of selling $135 million of
Preferred Securities (5.4 million shares at $25 par) in 1995. The Company
concurrently issued $139.2 million of its 1995 Series A, 8.05% Junior
Subordinated Notes (the Notes) in exchange for the $135 million realized from
the sale of the Preferred Securities and $4.2 million of common securities of
VP Capital Trust. The Preferred Securities and the common securities represent
the total beneficial ownership interest in the assets held by VP Capital Trust.
The Notes are the sole assets of VP Capital Trust.
39
The Preferred Securities are subject to mandatory redemption upon
repayment of the Notes at a liquidation amount of $25 plus accrued and unpaid
distributions, including interest. The Notes are due September 30, 2025.
However, that date may be extended up to an additional ten years if certain
conditions are satisfied.
J. Preferred Stock Subject to Mandatory Redemption:
The total number of authorized shares for all preferred stock (whether or
not subject to mandatory redemption) is 10,000,000 shares. Upon involuntary
liquidation, dissolution or winding-up of the Company, all presently
outstanding preferred stock is entitled to receive $100 per share plus accrued
dividends. Dividends are cumulative.
There are two series of preferred stock subject to mandatory redemption
outstanding as of December 31, 1997:
Issued and
Outstanding
Dividend Shares
- ------------------- ------------
$5.58 ............. 400,000 Shares are non-callable prior to redemption at 3/1/2000
$6.35 ............. 1,400,000 Shares are non-callable prior to redemption at 9/1/2000
---------
Total ......... 1,800,000
=========
There were no redemptions of preferred stock during 1997 or 1996. In 1995,
the Company redeemed 417,319 shares of its $7.30 dividend preferred stock
subject to mandatory redemption.
K. Preferred Stock Not Subject to Mandatory Redemption:
Shown below are the series of preferred stock not subject to mandatory
redemption that were outstanding as of December 31, 1997.
Entitled per Share upon Liquidation
-------------------------------------------------
Issued and And Thereafter to
Outstanding Amounts Declining in
Dividend Shares Amount Through Steps to
- -------------------------------- ------------- ------------ --------- ----------------------
$5.00 .......................... 106,677 $ 112.50
4.04 .......................... 12,926 102.27
4.20 .......................... 14,797 102.50
4.12 .......................... 32,534 103.73
4.80 .......................... 73,206 101.00
7.05 .......................... 500,000 105.00 7/31/03 $100.00 after 7/31/13
6.98 .......................... 600,000 105.00 8/31/03 $100.00 after 8/31/13
MMP 1/87 (*) ................... 500,000 100.00
MMP 6/87 (*) ................... 750,000 100.00
MMP 10/88 (*) .................. 750,000 100.00
MMP 6/89 (*) ................... 750,000 100.00
MMP 9/92, Series A (*) ......... 500,000 100.00
MMP 9/92, Series B (*) ......... 500,000 100.00
-------
Total .......................... 5,090,140
=========
- ---------
(*) Money Market 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 1997, 1996 and 1995, including fees for broker/dealer agreements,
were 4.71 percent, 4.48 percent and 4.93 percent, respectively.
In 1995, the Company redeemed 400,000 shares of its $7.45 dividend
preferred stock not subject to mandatory redemption and 450,000 shares of its
$7.20 dividend preferred stock not subject to mandatory redemption.
L. Common Stock:
There were no changes in the number of authorized and outstanding shares
of the Company's Common Stock during the three years ended December 31, 1997.
40
M. Short-term Debt:
The Company's commercial paper program has a maximum borrowing capacity of
$500 million. It is supported by two credit facilities. One is a $300 million,
five-year credit facility that was effective on June 7, 1996, and expires on
June 7, 2001. The other is a $200 million credit facility that originated on
June 7, 1996, with an initial term of 364 days and provisions for subsequent
364-day extensions. It was renewed on June 6, 1997, for 364 days.
The total amount of commercial paper outstanding as of December 31, 1997,
was $226.2 million with a weighted average interest rate of 5.88 percent. This
represents a decrease of $86.2 million from the December 31, 1996, balance of
$312.4 million and a weighted average interest rate of 5.51 percent.
N. Retirement Plan, Postretirement Benefits and Other Benefits:
Under the terms of its benefit plans, the Company reserves the right to
change, modify or terminate the plans. From time to time in the past, benefits
have changed, and some of these changes have reduced benefits.
Retirement Plan
The Company participates in the Dominion Resources, Inc. Retirement Plan
(the Retirement Plan), a defined benefit pension plan. The benefits are based
on years of service and average base compensation over the consecutive 60-month
period in which pay is highest.
The Company's pension plan expenses were $20.6 million, $24.8 million and
$20.3 million for 1997, 1996 and 1995, respectively, and the amounts funded by
the Company were $27.0 million, $28.4 million and $42.7 million in 1997, 1996
and 1995, respectively.
Postretirement Benefits
In addition to providing pension benefits, Dominion Resources and the
Company provide certain health care and life insurance benefits for retired
employees. Health care benefits are provided to retirees who have completed at
least 10 years of service after attaining age 45. These and similar benefits
for active employees are provided through insurance companies. Under the terms
of its benefit plans, the Company reserves the right to change, modify or
terminate the plans. From time to time in the past, benefits have changed, and
some of these changes have reduced benefits.
Net periodic postretirement benefit expense was as follows:
Year Ended
December 31,
---------------------
1997 1996
---------- ----------
(Millions)
Service cost ..................................... $ 12.3 $ 12.1
Interest cost .................................... 25.1 23.9
Return on plan assets ............................ (25.3) (16.6)
Amortization of transition obligation ............ 12.1 12.1
Net amortization and deferral .................... 13.4 7.1
------- -------
Net periodic postretirement benefit expense ...... $ 37.6 $ 38.6
======= =======
41
The following table sets forth the funded status of the plan:
At December 31,
-----------------------
1997 1996
----------- -----------
(Millions)
Fair value of plan assets .................................................... $ 176.6 $ 133.0
Accumulated postretirement benefit obligation:
Retirees .................................................................... $ 224.5 $ 201.7
Active plan participants .................................................... 136.3 122.2
-------- --------
Accumulated postretirement benefit obligation .............................. 360.8 323.9
-------- --------
Accumulated postretirement benefit obligation in excess of plan assets ..... (184.2) (190.9)
Unrecognized transition obligation ........................................... 180.8 192.8
Unrecognized net experience (gain)/loss ...................................... ( 1.8) ( 3.6)
-------- --------
Accrued postretirement benefit cost .......................................... $ (5.2) $ (1.7)
======== ========
A one percent increase in the health care cost trend rate would result in
an increase of $5.0 million in the service and interest cost components and a
$39.5 million increase in the accumulated postretirement benefit obligation.
Significant assumptions used in determining the postretirement benefit
obligation were:
1997 1996
----------------------- ----------------------
Discount rates .................... 7.75% 8%
Assumed return on plan assets ..... 9% 9%
Medical cost trend rate ........... 6% for 1st year 7% for 1st year
5% for 2nd year 6% for 2nd year
Scaling down to 4.75% Scaling down to 4.75%
beginning in the year beginning in the year
2000 2000
The Company is recovering these costs in rates on an accrual basis in all
material respects, in all jurisdictions. The funds being collected for Other
Postretirement Benefits (OPEB) in rates, in excess of OPEB benefits actually
paid during the year, are contributed to external benefit trusts under the
Company's current funding policy (see Future Issues -- Competition -- Exposure
to Potentially Stranded Costs under MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS).
O. Restructuring:
The Company announced the implementation phase of its Vision 2000 program
in March 1995. During this phase, the Company began reviewing operations with
the objective of outsourcing services where economical and appropriate and
re-engineering the remaining functions to streamline operations. The
re-engineering process has resulted in outsourcing, decentralization,
reorganization and downsizing for portions of the Company's operations. As part
of this process, the Company has reevaluated its utilization of capital
resources in the operations of the Company to identify further opportunities
for operational efficiencies through outsourcing or re-engineering of its
processes.
Restructuring charges of $18.4 million, $64.9 million, and $117.9 million
in 1997, 1996 and 1995, respectively, included severance costs, purchased power
contract restructuring and negotiated settlement costs, capital project
cancellation costs, and other costs incurred directly as a result of the Vision
2000 initiatives. While the Company may incur additional charges for severance
in 1998, the amounts are not expected to be significant.
Employee Severance
In 1995, the Company established a comprehensive involuntary severance
package for salaried employees who may no longer be employed as a result of
these initiatives. The Company is recognizing the cost associated with employee
terminations in accordance with Emerging Issues Task Force Consensus No. 94-3
as management identifies the positions to be eliminated. Severance payments
will be made over a period not to exceed twenty months. Through December 31,
1997, management had identified 1,977 positions to be eliminated. The
recognition of severance costs resulted in charges to operations in 1997, 1996
and 1995 of $12.5 million, $49.2 million and $51.2 million, respectively. At
December 31, 1997, 1,619 employees had been terminated and severance payments
totaling $74 million had been paid. The Company estimates that
42
these staffing reductions will result in annual savings, in the range of $80
million to $90 million. However, such savings are being offset by salary
increases, outsourcing costs and increased payroll costs associated with
staffing for growth opportunities.
Purchased Power Contracts
In an effort to minimize its exposure to potential stranded investment,
the Company is evaluating its long-term purchased power contracts and
negotiating modifications to their terms, including cancellations, where it is
determined to be economically advantageous to do so. The Company has also
negotiated settlements with several other parties to terminate their rights to
sell power to the Company. The cost of contract modifications, contract
cancellations and negotiated settlements was $3.8 million, $7.8 million and
$8.1 million in 1997, 1996 and 1995, respectively. Using contract terms,
estimated quantities of power that would have otherwise been delivered and
other relevant factors at the time of each transaction, the Company estimated
that its annual future purchased power costs, including energy payments, would
be reduced by up to $0.8 million, $5.8 million and $147.0 million for the 1997,
1996 and 1995 transactions, respectively. The cost of alternative sources of
power that might ultimately be required as a result of these settlements is
expected to be significantly less than the estimated reduction in purchased
power costs.
Construction Project
Restructuring charges reported in 1995 included $37.3 million for the
cancellation of a project to construct a facility to handle low level
radioactive waste at the Company's North Anna Power Station. As a result of
reevaluating the handling of low level radioactive waste, the Company concluded
that the facility should not be completed due to the additional capital
investment required, decreased Company volumes of low level radioactive waste
resulting from improvements in station procedures and the availability of more
economical offsite processing.
P. Accelerated Cost Recovery:
In this increasingly competitive environment, the Company also has
concluded that it is appropriate to utilize available cost reductions, such as
those generated by the Vision 2000 program (see Note O to the CONSOLIDATED
FINANCIAL STATEMENTS), to accelerate the write-off of existing unamortized
regulatory assets. Not only will this strategically position the Company in
anticipation of competition, but it also reflects the Company's commitment to
mitigate its exposure to potentially stranded costs (see Competition in
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS). The Company identified savings of $38.4 million in 1997 and $26.7
million in 1996 which were used to establish a reserve for expected adjustments
to regulatory assets.
Q. Commitments and Contingencies:
The Company is involved in legal, tax and regulatory proceedings before
various courts, regulatory commissions and governmental agencies regarding
matters arising in the ordinary course of business, some of which involve
substantial amounts. Management is of the opinion that the final disposition of
these proceedings will not have a material adverse effect on the results of
operations or the financial position of the Company.
Utility Rate Regulation
In March 1997, the Virginia Commission issued an order that Virginia
Power's base rates be made interim and subject to refund as of March 1, 1997.
This order was the result of the Commission Staff's report on its review of
Virginia Power's 1995 Annual Informational Filing, which concluded that
Virginia Power's present rates would cause Virginia Power to earn in excess of
its authorized return on equity. The Staff found that, for purposes of
establishing rates prospectively, a rate reduction of $95.6 million (including
a one-time adjustment of $29.7 million to Virginia Power's deferred capacity
balance at December 31, 1996) may be necessary in order to realign rates to the
authorized level. In March 1997, Virginia Power filed its Alternative
Regulatory Plan (ARP) based on 1996 financial information. Subsequently, the
Commission consolidated the proceeding concerned with the 1995 Annual
Informational Filing with the proceeding that includes the ARP proposed by the
Company.
In December 1997, Virginia Power sought to withdraw its ARP, having
concluded that resolution of the cost recovery issues raised by the ARP was
unlikely without General Assembly action. The Commission has agreed that the
Company may withdraw its support of the ARP but has reserved the right to
continue consideration of the ARP as well as other regulatory alternatives. In
addition, the Commission will continue to consider the issues arising out of
the 1995 Annual Informational
43
Filing. The Commission's Staff is scheduled to file its testimony on March 24,
1998; Virginia Power's rebuttal is to be filed by April 27, 1998; and the reply
testimony is to be filed by May 11, 1998. A public hearing is scheduled to
commence on May 19, 1998.
Virginia Power's previous filings in this proceeding support maintaining
the Company's rates at current levels; however, opposing parties have made
filings recommending rate reductions in excess of $200 million. At this time,
management cannot predict the ultimate outcome of the proceeding and its impact
on the Company's results of operations, cash flows or financial position.
Retrospective Premium Assessments
Under several of the Company's nuclear insurance policies, the Company is
subject to retrospective premium assessments in any policy year in which losses
exceed the funds available to these insurance companies. For additional
information, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.
Construction Program
The Company has made substantial commitments in connection with its
construction program and nuclear fuel expenditures. Those expenditures are
estimated to total $588.1 million (excluding AFC) for 1998. The Company
presently estimates that all of its 1998 construction expenditures, including
nuclear fuel, will be met through cash flow from operations.
Purchased Power Contracts
Since 1984, the Company has entered into contracts for the long-term
purchases of capacity and energy from other utilities, qualifying facilities
and independent power producers. The Company has 57 non-utility purchase
contracts with a combined dependable summer capacity of 3,277 MW.
The table below reflects the Company's minimum commitments as of December
31, 1997, for power purchases from utility and non-utility suppliers.
Commitment
---------------------------
Year Capacity Other
- ---------------------------------------- ------------- -----------
(Millions)
1998 ............................... $ 813.5 $ 154.9
1999 ............................... 816.7 156.7
2000 ............................... 723.8 92.0
2001 ............................... 716.0 83.7
2002 ............................... 721.1 81.5
Later years ........................ 9,069.6 388.2
---------- --------
Total ............................ $ 12,860.7 $ 957.0
========== ========
Present value of the total ......... $ 5,878.0 $ 553.3
========== ========
Payments made by Virginia Power in satisfaction of the minimum purchase
commitments shown in the above table are subject to reduction or partial refund
if (1) the non-utility suppliers fail to meet performance requirements or (2)
changes in federal or state law or administrative actions disallow or have the
effect of disallowing Virginia Power's recovery of such costs from its
customers. The amount of such payment reductions or refunds, if any, will be
determined and administered as provided in individual supply contracts,
although (1) the deferral of refund obligations, (2) disputes over the
applicability of such payment reductions or refund obligations and (3) the
ability of some non-utility suppliers to make refunds could limit Virginia
Power's ability to benefit from these contract provisions.
In addition to the minimum purchase commitments in the table above, under
some of these contracts, the Company may purchase, at its option, additional
power as needed. Actual payments for purchased power (including economy,
emergency, limited term, short-term and other purchases for utility operations,
as well as for trading purposes) for the years 1997, 1996 and 1995 were $1,381
million, $1,183 million and $1,093 million, respectively. For a discussion of
the Company's efforts to restructure certain purchased power contracts, see
Note O to CONSOLIDATED FINANCIAL STATEMENTS.
Fuel Purchase Commitments
The Company's estimated fuel purchase commitments for the next five years
for system generation are as follows (millions): 1998 -- $293; 1999 -- $233;
2000 -- $144; 2001 -- $144; and 2002 -- $127.
44
Sale of Power
The Company enters into agreements with other utilities and with other
parties to purchase and sell capacity and energy. These agreements may cover
current and future periods ("forward positions"). The volume of these
transactions varies from day to day based on the market conditions, our current
and anticipated load, and other factors. The combined amounts of sales and
purchases range from 500 MW to 7,000 MW at various times during a given year.
These operations are closely monitored from a risk management perspective.
Environmental Matters
The Company is subject to rising costs resulting from a steadily
increasing number of federal, state and local laws and regulations designed to
protect human health and the environment. These laws and regulations affect
future planning and existing operations. These laws and regulations can result
in increased capital, operating and other costs as a result of compliance,
remediation, containment and monitoring obligations of the Company. These costs
have been historically recovered through the ratemaking process; however,
should material costs be incurred and not recovered through rates, the
Company's results of operations and financial condition could be adversely
impacted.
Site Remediation
The EPA has identified the Company and several other entities as
Potentially Responsible Parties (PRPs) at two Superfund sites located in
Kentucky and Pennsylvania. The estimated future remediation costs for the sites
are in the range of $61.5 million to $72.5 million. The Company's proportionate
share of the cost is expected to be in the range of $1.7 million to $2.5
million, based upon allocation formulas and the volume of waste shipped to the
sites. The Company has accrued a reserve of $1.7 million to meet its
obligations at these two sites. Based on a financial assessment of the PRPs
involved at these sites, the Company has determined that it is probable that
the PRPs will fully pay the costs apportioned to them.
The Company and Dominion Resources have remedial action responsibilities
remaining at two coal tar sites. The Company accrued a $2 million reserve to
meet its estimated liability based on site studies and investigations performed
at these sites. In addition, two civil actions have been instituted against the
City of Norfolk and Virginia Power by property owners who allege that their
property has been contaminated by toxic pollutants originating from one of the
coal tar sites now owned by the City of Norfolk and formerly owned by the
Company. The first civil action reached settlement without trial in September
1997. The remaining plaintiff is seeking compensatory damages of $2 million and
punitive damages of $1 million. It is too early in this case for the Company to
predict the outcome. The Company has filed answers denying liability. No trial
date has been set.
The Company generally seeks to recover its costs associated with
environmental remediation from third party insurers. At December 31, 1997, any
pending or possible claims were not recognized as an asset or offset against
recorded obligations of the Company.
R. Fair Value of Financial Instruments:
The Company used available market information and appropriate valuation
methodologies to estimate the fair value of each class of financial instrument
for which it is practicable to estimate fair value. These estimates are not
necessarily 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.
45
December 31,
-------------------------------------------------
1997 1996
----------------------- -----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ----------
(Millions)
Assets:
Cash and cash equivalents ............................... $ 36.0 $ 36.0 $ 47.9 $ 47.9
Nuclear decommissioning trust funds ..................... 569.1 569.1 443.3 443.3
Liabilities and capitalization:
Short-term debt ......................................... 226.2 226.2 312.4 312.4
Long-term debt:
First and Refunding Mortgage Bonds .................... 2,824.5 2,937.7 2,923.8 2,957.4
Medium-term notes ..................................... 551.1 573.7 503.1 531.3
Money Market Municipal tax-exempt securities .......... 488.6 488.6 488.6 488.6
Convertible interest rate tax-exempt bonds ............ 10.0 10.4
Preferred stock subject to mandatory redemption ......... 180.0 186.6 180.0 185.8
Preferred securities of subsidiary trust ................ 135.0 137.7 135.0 135.0
Cash and cash equivalents and short-term debt: The carrying amount of
these items approximates fair value because of their short maturity.
Nuclear decommissioning trust funds: The fair value is based on available
market information and generally is the average of bid and asked price.
First and Refunding Mortgage Bonds: Fair value is based on market
quotations.
Medium-term notes: These notes were valued by discounting the remaining
cash flows at a rate estimated for each issue. A yield curve rate was estimated
to relate Treasury Bond rates for specific issues to the corresponding
maturities.
Money Market Municipal tax-exempt securities: The interest rates for these
notes vary so that fair value approximates carrying value.
Convertible interest rate tax-exempt bonds and preferred stock subject to
mandatory redemption: The fair value is based on market quotations or is
estimated by discounting the dividend and principal payments for a
representative issue of each series over the average remaining life of the
series.
Preferred securities of subsidiary trust: Fair value is based on market
quotations.
S. Quarterly Financial Data (unaudited):
The following amounts reflect all adjustments, consisting of only normal
recurring accruals (except as discussed below), necessary in the opinion of the
management for a fair statement of the results for the interim periods.
Income from Net Balance Available
Quarter Revenues Operations Income for Common Stock
- ------------- ------------- ------------- ----------- ------------------
(Millions)
1997
- ----
1st ......... $ 1,174.8 $ 248.6 $ 110.3 $ 101.5
2nd ......... 1,051.5 184.6 72.3 63.3
3rd ......... 1,499.9 381.0 201.1 192.1
4th ......... 1,352.8 205.1 85.4 76.5
1996
- ----
1st ......... $ 1,169.7 $ 311.1 $ 152.8 $ 143.8
2nd ......... 1,032.1 224.0 96.6 87.8
3rd ......... 1,180.8 325.8 162.2 153.3
4th ......... 1,038.3 149.1 45.7 36.9
Results for interim periods may fluctuate as a result of weather
conditions, rate relief and other factors.
46
Certain accruals were recorded in 1997 and 1996 that are not ordinary,
recurring adjustments, consisting of restructuring (see Note O to CONSOLIDATED
FINANCIAL STATEMENTS) and accelerated cost recovery (see Note P to CONSOLIDATED
FINANCIAL STATEMENTS).
Restructuring -- The Company expensed $6.3 million, $1.4 million and $10.7
million during the second, third and fourth quarters of 1997, respectively, and
$5.4 million, $19.3 million, $4.6 million and $35.6 million during the first,
second, third and fourth quarters of 1996.
Accelerated cost recovery -- Amounts reserved for accelerated cost
recovery were $2.8 million, $28.3 million and $7.3 million during the second,
third and fourth quarters of 1997, respectively, and $26.7 million during the
fourth quarter of 1996.
Charges for restructuring and accelerated cost recovery reduced Balance
Available for Common Stock by $5.8 million, $19.3 million, and $11.7 million
for the second, third, and fourth quarters of 1997, respectively, and $3.5
million, $12.5 million, $3.0 million and $40.6 million for first, second, third
and fourth quarters of 1996.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
47
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
On September 12, 1997, the Board of Directors elected Thos. E. Capps as
Chairman, succeeding John B. Adams, Jr., who had held the position since 1994.
Mr. Capps also is Chairman of the Board of Directors of Dominion Resources,
Inc., the parent company of Virginia Power.
(a) Information concerning directors of Virginia Electric and Power
Company is as follows:
Year First
Principal Occupation for Last 5 Years, Elected a Term
Name and Age Directorships in Public Corporations Director Expires
- ------------------------------- -------------------------------------------------------------- ----------- --------
Thos. E. Capps (62) Chairman of the Board of Directors of Virginia Electric an d 1986 2000
Power Company from September 12, 1997 to date and
Chairman, President and Chief Executive Officer of
Dominion Resources from September 1, 1995 to date
(from August 15, 1994 to September 1, 1995, Chairman
and Chief Executive Officer; prior to August 15, 1994,
Chairman, President and Chief Executive Officer). He is a
Director of Bassett Furniture Industries, Inc. and
NationsBank Corporation.
Norman Askew (55) President and Chief Executive Officer of Virginia Electric 1997 1998
and Power Company and Executive Vice President of
Dominion Resources from August 1, 1997 to date;
Executive Vice President of Dominion Resources and
Chief Executive of East Midlands from February 21, 1997
to August 1, 1997; Chief Executive of East Midlands from
April 1, 1994 to February 21, 1997; Managing Director
prior to April 1, 1994.
John B. Adams, Jr. (53) President and Chief Executive Officer of The Bowman 1987 1998
Companies, Fredericksburg, Virginia, a manufacturer and
bottler of alcohol beverages and he is a Director of
Dominion Resources.
John B. Bernhardt (68) Managing Director, Bernhardt/Gibson Financial 1986 2000
Opportunities, financial services, Newport News, Virginia.
He is a Director of Resource Bank and Dominion
Resources.
James F. Betts (65) Former Chairman of the Board and President, The Life 1978 2000
Insurance Company of Virginia, Richmond, Virginia. He is
a Director of Wachovia Corporation.
Jean E. Clary (53) President and owner of Century 21 Clary and Associates, 1996 2000
Inc., South Hill, Virginia.
John W. Harris (50) President, The Harris Group, a real estate consulting firm, 1997 1998
Charlotte, North Carolina. He is a Director of Piedmont
Natural Gas Company, Inc. and US Airways Group, Inc.
Benjamin J. Lambert, III (61) Optometrist, Richmond, Virginia. He is a Director of 1992 1998
Consolidated Bank and Trust Company, Student Loan
Marketing Association (SallieMae) and Dominion
Resources.
Richard L. Leatherwood (58) Retired, Baltimore, Maryland. Former President and Chief 1994 1998
Executive Officer, CSX Equipment, an operating unit of
CSX Transportation, Inc.). He is a Director of Dominion
Resources and CACI International, Inc.
Harvey L. Lindsay, Jr. (68) Chairman and Chief Executive Officer of Harvey Lindsay 1986 1999
Commercial Real Estate, Norfolk, Virginia, a commercial
real estate firm. He is a Director of Dominion Resources.
Kenneth A. Randall (70) Corporate Director for various companies, Williamsburg, 1971 1999
Virginia. He is a Director of Oppenheimer Funds, Inc.,
Kemper Insurance Companies and Prime Retail, Inc. He is
a Director of Dominion Resources.
48
Retired, Hampton, Virginia (prior to December 31, 1993,
President of Penn Luggage, Inc., retail specialty stores).
William T. Roos (69) He is a Director of Dominion Resources. 1975 1999
Frank S. Royal (58) Physician, Richmond, Virginia. He is a Director of 1997 1998
Columbia/HCA Healthcare Corporation, Crestar Financial
Corporation, Chesapeake Corporation, CSX Corporation
and Dominion Resources.
Judith B. Sack (49) Senior Advisor, Morgan Stanley & Co., Inc., an investment 1997 1999
banking firm, New York, New York, as of September 1,
1995 (prior to September 1, 1995, Advisor). She is a
Director of Dominion Resources.
S. Dallas Simmons (58) President of Virginia Union University, Richmond, Virginia. 1997 2000
He is a Director of Dominion Resources.
Robert H. Spilman (70) President, Spilman Properties, Basset, Virginia and Chairman 1994 2000
of the Board and a Director of Jefferson-Pilot Corp.,
Greensboro, North Carolina. Retired Chairman and Chief
Executive Officer of Bassett Furniture Industries, Inc. He
is a Director of International Home Furnishing Center,
The Pittston Company and Dominion Resources.
William G. Thomas (58) President of Hazel & Thomas, Alexandria, Virginia, a law 1987 1999
firm.
David A. Wollard (60) Retired President, Bank One Colorado, N.A., Denver, 1997 1999
Colorado.
The Directors are divided into three classes, with staggered terms. Each
class consists, as nearly as possible, of one-third of the total number of
Directors. Each Director holds office until the annual meeting for the year in
which his class term expires, or until his successor is duly qualified and
elected as provided in the Company's Articles of Incorporation.
Mr. Thomas has entered into a Consent Decree with the Office of Thrift
Supervision in connection with the lending and credit granting activities of
Perpetual Savings Bank, FSB, which Mr. Thomas formerly served as a director.
The Consent Decree requires that Mr. Thomas obtain approval from the
appropriate federal banking agency before accepting certain positions involving
lending or credit activities with an insured depository institution.
(b) Information concerning the executive officers of Virginia Electric and
Power Company is as follows:
Name and Age Business Experience past Five Years
- ---------------------------- ---------------------------------------------------------------------------------------
Norman Askew (55) President and Chief Executive Officer of Virginia Electric and Power Company and
Executive Vice President of Dominion Resources from August 1, 1997 to date;
Executive Vice President of Dominion Resources and Chief Executive of East
Midlands from February 21, 1997 to August 1, 1997; Chief Executive of East
Midlands from April 1, 1994 to February 21, 1997; Managing Director prior to
April 1, 1994.
Thomas F. Farrell, II (43) Executive Vice President of Virginia Electric and Power Company and Senior Vice
President-Corporate Affairs of Dominion Resources, September 1, 1997 to date;
Senior Vice President-Corporate & General Counsel of Dominion Resources,
January 1, 1997 to September 1, 1997; Vice President and General Counsel of
Dominion Resources, July 1, 1995 to January 1, 1997; Partner in the law firm of
McGuire, Woods, Battle, & Boothe LLP prior to July 1, 1995.
Robert E. Rigsby (48) Executive Vice President, January 1, 1996 to date; Senior Vice President-Finance and
Controller, January 1, 1995 to January 1, 1996; Vice President-Human Resources
prior to January 1, 1995.
William R. Cartwright (55) Senior Vice President-Fossil and Hydro, July 1, 1995 to date; Vice President Fossil
and Hydro prior to July 1, 1995.
Lawrence E. De Simone (50) Senior Vice President-Energy Services, July 15, 1996 to date; vice president-strategic
planning for Central & South West Corp., a Dallas-based electric utility holding
company, prior to July 15, 1996.
Larry M. Girvin (54) Senior Vice President-Commercial Operations, January 1, 1996 to date; Vice
President-Human Resources, January 1, 1995 to January 1, 1996; Vice President-
Nuclear Services prior to January 1, 1995.
James P. O'Hanlon (54) Senior Vice President-Nuclear, June 1, 1994 to date; Vice President-Nuclear
Operations prior to June 1, 1994.
49
Senior Vice President-Finance, March 16, 1998 to date; Vice President Financial
Service for ARCO Chemical Company, Philadelphia, Pennsylvania, prior to
March 16, 1998. During the past 5 years, he has also served as Treasurer and
John A. Shaw (49) Controller of ARCO Chemical.
Eva S. Teig (53) Senior Vice President-External Affairs & Corporate Communications, September 1,
1997 to date; Vice President-External Affairs & Corporate Communications, June 1,
1997 to September 1, 1997; Vice President-Public Affairs prior to June 1, 1997.
Said Ziai (44) Senior Vice President-Corporate Strategy, October 1,1997 to date; Corporate Planning
Director, East Midlands Electricity plc, Nottingham, England prior to October 1,
1997.
Thomas L. Caviness, Jr. (52) Vice President-Retail Energy Services, July 1, 1995 to date;Vice President-Eastern
Division prior to July 1, 1995.
David A. Christian (43) Site Vice President-Surry, March 1, 1998 to date; Station Manager-Surry Power
Station, September 1, 1994 to March 1, 1998; Assistant Station Manager-Surry,
prior to September 1, 1994.
J. Kennerly Davis, Jr. (52) Vice President-Finance and Administrative Services, Treasurer and Corporate
Secretary, January 1, 1996 to date; Vice President, Treasurer and Corporate
Secretary, October 1, 1994 to January 1, 1996; Vice President and Corporate
Secretary of Dominion Resources prior to October 1, 1994.
James T. Earwood, Jr. (54) Vice President-Bulk Power Delivery, January 1, 1997 to date;Vice President-Energy
Efficiency and Division Services, January 1, 1996 to January 1, 1997; Vice
President-Division Services prior to January 1, 1996.
E. Paul Hilton (54) Vice President-Regulation, October 1, 1997 to date; Manager, Rates and Regulation,
February 20, 1996 to October 1, 1997; Manager, Rates prior to February 20, 1996.
Thomas A. Hyman, Jr. (46) Vice President-Distribution Operations and North Carolina Power, June 1, 1997 to
date;Vice President-Eastern Division and North Carolina Power, July 1, 1995 to
June 1, 1997; Vice President-Southern Division, June 1, 1994 to July 1, 1995;
Station Manager-Bremo Power Station prior to June 1, 1994.
Michael R. Kansler (43) Vice President-Nuclear Operations, January 1, 1997 to date;Vice President-Nuclear
Engineering and Services, October 1, 1995 to January 1, 1997; Vice President-
Nuclear Services, January 1, 1995 to October 1, 1995 ; Manager-Nuclear Operations
Support, September 1, 1994 to January 1, 1995; Station Manager-Surry Nuclear
Power Station prior to September 1, 1994.
William R. Matthews (51) Site Vice President-North Anna, March 1, 1998 to date; Station Manager-North Anna
Power Station, May 1, 1996 to March 1, 1998; Assistant Station Manager-North
Anna Power Station, December 1, 1993 to May 1, 1996; Superintendent-
Maintenance, prior to December 1, 1993.
Mark F. McGettrick (40) Vice President-Customer Service, January 1, 1997 to date; Corporate Restructuring
Project Manager, February 1, 1995 to January 1, 1997; Assistant Controller prior to
February 1, 1995.
William S. Mistr (50) Vice President-Information Technology, January 1, 1996 to date and Vice President of
Dominion Resources, February 20, 1997 to date; Vice President and Treasurer,
Dominion Energy, Inc., October 1, 1994 to January 1, 1996; Assistant Treasurer,
Dominion Resources prior to October 1, 1994.
Thomas J. O'Neil (55) Vice President-Human Resources, January 1, 1996 to date; Vice President-Energy
Efficiency prior to January 1, 1996.
Edward J. Rivas (53) Vice President-Fossil & Hydro Operations, January 1, 1998 to date; Manager-Clover
Power Station, March 16, 1994 to January 1, 1998; Manager-Fossil & Hydro
Training prior to March 16, 1994.
Robert F. Saunders (54) Vice President-Nuclear Engineering and Services, January 1, 1997 to date; Vice
President-Nuclear Operations, June 1, 1994 to January 1, 1997; Assistant Vice
President-Nuclear Operations, prior to June 1, 1994.
Johnny V. Shenal (52) Vice President-Distribution Construction, June 1, 1997 to date;Vice President-Northern
and Western Divisions, June 1, 1994 to June 1, 1997; Vice President-Western
Division, prior to June 1, 1994.
Richard T. Thatcher (48) Vice President-Wholesale Power Group, September 1, 1997 to date; Managing
Director, Wholesale Power, April 10, 1997 to September 1, 1997; Manager,
Wholesale Power Group, July 1, 1995 to April 10, 1997; Project Manager,
January 1, 1995 to July 1, 1995; Director-Generation and Interconnection Planning
prior to January 1, 1995.
There is no family relationship between any of the persons named in
response to Item 10.
50
Section 16(a) Beneficial Ownership Reporting Compliance
Our Directors and Executive Officers report their ownership of our
preferred stock pursuant to Section 16(a) of the Exchange Act. Through
administrative oversight, the following individuals failed to file their initial
statements of beneficial ownership on Form 3 on a timely basis: Thos. E. Capps,
Norman Askew, John B. Bernhardt, John W. Harris, Kenneth A. Randall, Frank S.
Royal, Judith B. Sack, S. Dallas Simmons, David A. Wollard, Thomas F. Farrell,
II, Said Ziai, E. Paul Hilton, Richard T. Thatcher, David A. Christian and
William R. Matthews.
None of the individuals owned any of our preferred stock at the time their
initial reports should have been filed nor have they or any other Director or
Executive Officer have any reportable transactions in the preferred stock which
have not been reported. The required filings have now been made.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The Summary Table below includes compensation paid by the Company for
services rendered in 1997, 1996 and 1995 for the Chief Executive Officer and
the four other most highly compensated executive officers (as of December 31,
1997) as determined by total salary and incentive payments for 1997.
Summary Compensation Table
Annual Compensation
-------------------------------------------------------
Other Annual
Name & Principal Position Year Salary Incentive(1) Compensation(2)
- --------------------------- ------ ----------- ------------------ -----------------
James T. Rhodes 1997 $244,800 $ 159,250 (4) $ 0
President and CEO 1996 $410,575 $ 247,606 $ 0
(retired August 1, 1997) 1995 $406,075 $ 273,000 $ 0
Norman Askew 1997 $177,084 $ 85,833 $14,560
President and CEO
(effective August 1, 1997)
Robert E. Rigsby 1997 $254,850 $ 129,920 $ 0
Executive Vice President 1996 $226,469 $ 143,892 $ 0
1995 $171,456 $ 105,000 $ 0
James P. O'Hanlon 1997 $270,250 $ 110,240 $ 0
Senior Vice President -- 1996 $220,815 $ 128,511 $ 0
Nuclear 1995 $207,555 $ 136,400 $ 0
Lawrence E. DeSimone 1997 $212,751 $ 85,520 $ 0
Senior Vice President -- 1996 $ 94,419 $ 50,441 $ 0
Energy Services
Larry M. Girvin 1997 $187,050 $ 85,520 $ 0
Senior Vice President -- 1996 $164,600 $ 89,200 $ 0
Commercial Operations 1995 $139,650 $ 66,606 $ 0
Long Term
Compensation Awards
------------------------
Securities Payouts
Restricted Underlying ----------------------------------------
Stock Options/ LTIP All Other
Name & Principal Position Awards SAR Grants Pay out Compensation(3)
- --------------------------- ------------ ----------- ------------------- --------------------
James T. Rhodes $ 0 $0 $ 803,429(5) $ 7,977,039 (6)
President and CEO $ 0 $0 $ 75,684 $ 4,500
(retired August 1, 1997) $ 0 $0 $ 77,970 $ 4,500
Norman Askew $ 0(7) $0 $ 18,791(8) $ 120,000(9)
President and CEO
(effective August 1, 1997)
Robert E. Rigsby $0(10 ) $0 $ 83,171(11) $ 4,800
Executive Vice President $ 0 $0 $ 43,157 $ 4,500
$ 0 $0 $ 34,569 $ 4,500
James P. O'Hanlon $ 0(12) $0 $ 80,140(13) $ 4,800
Senior Vice President -- $ 0 $0 $ 56,152 $ 4,500
Nuclear $ 0 $0 $ 45,109 $ 4,500
Lawrence E. DeSimone $ 0(14) $0 $ 0 $ 3,180
Senior Vice President -- $ 0 $0 $ 0 $ 0
Energy Services
Larry M. Girvin $ 0(15) $0 $ 52,935 (16) $ 4,800
Senior Vice President -- $ 0 $0 $ 30,717 $ 4,500
Commercial Operations $ 0 $0 $ 24,685 $ 4,500
- ---------
(1) The Company does not maintain "bonus" plans which are used by some
companies to supplement salaries based on the success of the company
without regard to individual performance. However, the Company has in
place various incentive plans that compensate officers and employees for
achieving specified performance goals.
(2) Unless noted, none of the executive officers above received perquisites or
other personal benefits in excess of either $50,000 or 10% of total salary
and incentive payment.
(3) Employer matching contribution of $4,800 on Employee Savings Plan
contributions, unless otherwise noted.
(4) Amount represents a lump sum settlement of his rights under the 1997 Annual
Incentive Plan.
(5) $158,025 was paid under the 1995-1997 Performance Achievement Plan. 7,326
shares of Dominion Resources, Inc. Common Stock (worth $269,231 @ $36.75
per share) were issued under the 1996-1998 Long Term Incentive Plan.
10,326 shares of Dominion Resources, Inc. Common Stock (worth $376,173 @
$36.75 per share) were issued under the 1997-1999 Long Term Incentive
Plan.
51
(6) Upon his retirement, Dr. Rhodes received the following payments from the
Company: $51,078 for unused vacation; $1,023,271 as provided by his
employment contract; $4,184,220 lump sum settlement of pension benefits
not payable from the qualified retirement plan; $2,715,926 as a lump sum
settlement of his benefit under the Executive Supplemental Retirement
Plan, and $2,544 in employer match on Employee Savings Plan contributions.
(7) Mr. Askew held no restricted stock as of 12/31/97.
(8) Amount represents incentive plan pay outs from Virginia Power, on a
prorated basis, for performance cycles that ended in 1997: $7,550 in lieu
of dividends on restricted stock for partial participation in the
1996-1998 and the 1997-1999 performance cycles; and $11,241 for the
1995-1997 performance cycle.
(9) A one time payment related to his international transfer from the UK to the
US.
(10) Aggregate number of shares of restricted stock on December 31, 1997:
13,763 with an aggregate value of $585,788 (based on a closing price on
December 31, 1997 of $42.5625 per share).
(11) 2,085 shares of stock, with 50% of the value awarded in cash ($41,133) and
the remaining 1,042 shares being issued (valued at $42,038 or $40.3437 per
share as of 2/20/98).
(12) Aggregate number of shares of restricted stock on December 31, 1997: 9,773
with aggregate value of $415,963 (closing price on December 31, 1997 of
$42.5625 per share).
(13) 2,009 shares of stock, with 50% of the value awarded in cash ($39,635) and
the remaining 1,004 shares being issued (valued at $40,505 or $40.3437 per
share as of 2/20/98).
(14) Mr. DeSimone held no restricted stock as of 12/31/97.
(15) Aggregate number of shares of restricted stock on December 31, 1997: 7,528
with aggregate value of $320,411 (closing price on December 31, 1997 of
$42.5625 per share).
(16) 1,327 shares of stock, with 50% of the value awarded in cash ($26,187) and
the remaining 663 shares being issued (valued at $26,748 or $40.3437 per
share as of 2/20/98).
Long-term Incentive Compensation
Long-term incentive awards made during 1997 are shown in the following
table.
Long-term Incentive Plans -- Awards in the Last Fiscal Year
1997-1999 Long-term Incentive Plan
Estimated Future Payouts
under Non-stock Price
Based
Performance or Plans
Number of Other Period -------------------------
Shares, Units until Maturation Threshold Target
Name or Other Rights(#) or Payout ($ or #) ($ or #)
- ----------------------- -------------------- ----------------- ----------- -----------
J.T. Rhodes ........... $259,448 3 years $129,724 $259,448
N. Askew .............. $261,250 3 years $130,625 $261,250
J.P. O'Hanlon ......... $112,843 3 years $ 56,422 $112,843
R.E. Rigsby ........... $163,714 3 years $ 81,857 $163,714
L.E. DeSimone ......... 87,750 3 years $ 43,875 $ 87,750
L.M. Girvin ........... 87,750 3 years $ 43,875 $ 87,750
52
Retirement Plans
The table below sets forth the estimated annual straight life benefit that
would be paid following retirement under the benefit formula of the Dominion
Resources, Inc. Retirement Plan (the Retirement Plan).
Estimated Annual Benefits Payable upon Retirement
Credited Years of Service
--------------------------------------------
Final Average Earnings 15 20 25 30
- ----------------------- ---------- ---------- ---------- -----------
$ 185,000 $ 51,501 $ 68,668 $ 85,836 $103,003
200,000 56,069 74,758 93,448 112,138
225,000 63,681 84,908 106,136 127,363
250,000 71,294 95,058 118,823 142,588
300,000 86,519 115,358 144,198 173,038
350,000 101,744 135,658 169,573 203,488
400,000 116,969 155,958 194,948 233,938
450,000 132,194 176,258 220,323 264,388
500,000 147,419 196,558 245,698 294,838
550,000 162,644 216,858 271,073 325,288
600,000 177,869 237,158 296,448 355,738
650,000 193,094 257,458 321,823 386,188
750,000 223,544 298,058 372,573 447,088
Benefits under the Retirement Plan are based on (i) average base
compensation over the consecutive 60-month period in which pay is highest, (ii)
years of credited service, (iii) age at retirement, and (iv) the offset of
Social Security Benefits.
Certain officers have entered into retirement agreements that give
additional credited years of service for retirement and retirement life
insurance purposes, and retirement medical benefit purposes contingent upon the
officer reaching a specified age and remaining in the employ of the Company or
an affiliate.
For purposes of the above table, based on 1997 compensation, credited
years of service (including any additional years earned in connection with the
retirement agreements) for each of the individuals named in the cash
compensation table would be as follows:
James T. Rhodes: 30; Norman Askew: 0; Robert E. Rigsby: 26; James P.
O'Hanlon: 8; Lawrence E. De Simone: 0; Larry M. Girvin: 31.
Virginia Power's executive compensation program has placed increased
emphasis on incentive compensation opportunities linked to financial and
operating performance. Base salaries have been held below the mean for
comparable positions at comparable companies. The Retirement Plan benefit
formula recognizes base salary, but not incentive compensation payments.
Therefore, each year the Organization and Compensation Committee approves a
market-based adjustment to executive base salaries for use in calculating the
retirement benefit under the Dominion Resources, Inc. Benefit Restoration Plan
(the Restoration Plan). In 1997, this adjustment was 11 percent. Also, the
Internal Revenue Code limits the annual 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 monthly installments
for 120 months to a participant with 60 months of service, who (i) retires at
or after age 55 from the employ of the Company, (ii) has become permanently
disabled, or (iii) dies. The accrued benefit vests proportionately between the
time an officer is elected and when he or she reaches age 55 when the benefit
is fully vested If a participant dies while employed, the normal form of
benefit will be paid to a designated beneficiary. If a participant dies while
retired, but before receiving all benefit payments, the remaining installments
will be paid to a designated beneficiary. A lump sum payment is available under
certain conditions.
Based on 1997 compensation, the estimated annual retirement benefit for
each of the executive officers under the Supplemental Plan would be as follows:
N. Askew: $167,406; R.E. Rigsby: $104,345; J.P. O'Hanlon: $113,228; L.E. De
Simone: $79,139; L.M. Girvin: $73,764.
53
Retirement Benefit Funding Plan
The Company maintains a Retirement Benefit Funding Plan to provide a means
to secure obligations under the Supplemental Plan, the Restoration Plan, and
retirement agreements. The Retirement Benefit Funding Plan does not provide any
additional benefits; it simply helps secure the funding for these benefit
obligations. The amount payable by Virginia Power under the Supplemental Plan,
the Restoration Plan and retirement agreements is reduced, on a
dollar-for-dollar basis, by the funds available under the Retirement Benefit
Funding Plan.
Employment Agreements
The Company has entered into employment continuity agreements (the
Agreements) with its key management executives, including, Norman Askew, Robert
E. Rigsby, James P. O'Hanlon, Lawrence E. De Simone, and Larry M. Girvin, which
provide benefits in the event of a change in control. Each Agreement has a
three-year term and thereafter is 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.
Compensation of Directors
The non-employee members of the Board receive an annual retainer of
$19,000 and a fee of $900 for each Board or committee meeting attended.
Committee chairmen receive an additional annual retainer of $3,000. Consistent
with the Company's philosophy concerning equity-based compensation for
officers, effective in 1998 non-employee directors will also receive an annual
retainer in Dominion Resources common stock valued at $19,000. These Directors
may elect to defer their annual retainer and/or their meeting fees under the
Deferred Compensation Plan until they retire from the Board or 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.
Directors Charitable Contribution Program
Dominion Resources administers a Directors' Charitable Contribution
Program (the Program) that covers Directors of the Company, as part of its
overall program of charitable giving. Beginning at the death of a Director a
donation in an aggregate amount of $50,000 per year for 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.
54
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The table below sets forth as of February 20, 1998, except as noted, the
number of shares of Common Stock of Dominion Resources owned by Directors and
four other more highly compensated executive officers of Virginia Electric and
Power Company.
Shares of Common Stock Director Plan
Name Beneficially Owned Accounts(1)
- ----------------------------------------- ------------------------ --------------
John B. Adams, Jr. ...................... 3,891 9,091
John B. Bernhardt ....................... 1,500 9,091
James F. Betts .......................... 7,500 9,091
Thos. E. Capps .......................... 44,914(2)
Jean E. Clary ........................... 116 9,162
John W. Harris .......................... 500 9,091
Benjamin J. Lambert, III ................ 90 10,212
Richard L. Leatherwood .................. 1,000 17,616
Harvey L. Lindsay ....................... 400 9,091
Kenneth A. Randall ...................... 3,027 9,091
William T. Roos ......................... 14,603(3) 9,091
Frank S. Royal .......................... 10,430
Judith B. Sack .......................... 1,000 14,575
S. Dallas Simmons ....................... 650 13,370
Robert H. Spilman ....................... 1,187 9,091
William G. Thomas ....................... 1,000 13,257
David A. Wollard ........................ 9,879
Norman Askew ............................ 1,290(2)
Lawrence E. De Simone ................... 92
Larry M. Girvin ......................... 7,654
James P. O'Hanlon ....................... 11,100
Robert E. Rigsby ........................ 22,079
All Directors and Executive Officers as a
group -- 41 persons (4) ................ 397,599(2)(5)
- ---------
(1) Amounts in this column represent share equivalents accumulated under the
non-employee director Stock Accumulation Plan. Balances of 9,091 shares
are the amounts accumulated thus far under the plan. Because of the plan's
vesting provisions, these amounts will not necessarily be distributed to a
director. Any balance in excess of 9,091 is an amount of shares
accumulated-at the director's election-under the Deferred Cash
Compensation plan. That excess amount will be distributed in actual shares
to the director.
(2) Amounts include restricted stock as follows: Mr. Capps -- 23,984 shares;
Mr. Askew -- 1,290; and all directors and executive officers as a group --
89,859.
(3) Mr. Roos disclaims beneficial ownership of 4,387 shares that are held in
trusts for family members.
(4) All current directors and executive officers as a group own less than one
percent of the number of shares outstanding as of February 20, 1998.
(5) Beneficial ownership is disclaimed for a total of 4,786 shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Hazel & Thomas, a professional corporation, from time to time acts as
counsel to the Company. Mr. Thomas, a Director of the Company, is a shareholder
of Hazel & Thomas.
55
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Form 10-K:
1. Financial Statements
See Index on page 21.
2. Exhibits
3.1 -- Restated Articles of Incorporation, as amended, as in effect on September 12, 1994
(Exhibit 3(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by
reference).
3.2 -- Bylaws, as amended, as in effect on October 17, 1997 (Exhibit 3(ii), Form 10-Q for
the period ended September 30, 1997, File No. 1-2255, incorporated by reference).
4.1 -- See Exhibit 3 (i) above.
4.2 -- Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and
modified by fifty-eight Supplemental Indentures (Exhibit 4(ii), Form 10-K for the
fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference);
Fifty-Ninth Supplemental Indenture (Exhibit 4(ii), Form 10-Q for the quarter ended
March 31, 1986, File No. 1-2255, incorporated by reference); Sixtieth Supplemental
Indenture (Exhibit 4(ii), Form 10-Q for the quarter ended September 30, 1986, File
No. 1-2255, incorporated by reference); Sixty-First Supplemental Indenture (Exhibit
4(ii), Form 8-K, dated June 2, 1987, File No. 1-2255, incorporated by reference);
Sixty-Second Supplemental Indenture (Exhibit 4(i), Form 8-K, dated November 3,
1987, File No. 1-2255, incorporated by reference); Sixty-Third Supplemental Indenture
(Exhibit 4(i), Form 8-K, dated June 8, 1988, File No. 1-2255, incorporated by
reference); Sixty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated
February 8, 1989, File No. 1-2255, incorporated by reference); Sixty-Fifth
Supplemental Indenture (Exhibit 4(i), Form 8-K, dated June 22, 1989, File No. 1-2255,
incorporated by reference); Sixty-Sixth Supplemental Indenture (Exhibit 4(i), Form
8-K, dated February 27, 1990, File No. 1-2255, incorporated by reference);
Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991,
File No. 1-2255, incorporated by reference); Sixty-Eighth Supplemental Indenture
(Exhibit 4(i)), Sixty-Ninth Supplemental Indenture (Exhibit 4(ii)) and Seventieth
Supplemental Indenture (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No.
1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i))
and Seventy-Second Supplemental Indenture (Exhibit 4(ii), Form 8-K, dated July 7,
1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental
Indenture (Exhibit 4(i), Form 8-K, 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); Eighty-Third Supplemental Indenture (Exhibit 4(i),
Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference);
Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 22, 1995,
File No. 1-2255, incorporated by reference; and Eighty-Fifth Supplemental Indenture
(Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by
reference).
56
4.3 -- 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).
4.4 -- Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company
and The Chase Manhattan Bank (formerly Chemical Bank) (Exhibit 4(v), Form 10-K
for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by
reference).
4.5 -- Indenture, dated April 1, 1988, between Virginia Electric and Power Company and The
Chase Manhattan Bank (formerly Chemical Bank), as supplemented and modified by a
First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the
fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).
4.6 -- Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and
Power Company and The Chase Manhattan Bank (formerly Chemical Bank), as
Trustee, as supplemented (Exhibit 4(a), Form S-3 Registration Statement File No.
333-20561 as filed on January 28, 1997, incorporated by reference).
4.7 -- Virginia Electric and Power Company agrees to furnish to the Commission upon
request any other instrument with respect to long-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.
10.1 -- 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).
10.2 -- Purchase, Construction and Ownership Agreement, dated as of December 28, 1982 but
amended and restated on October 17, 1983, between Virginia Electric and Power
Company and Old Dominion Electric Cooperative (Exhibit 10(viii), Form 10-K for the
fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference).
10.3 -- Amended and Restated Interconnection and Operating Agreement, dated as of July 29,
1997 between Virginia Electric and Power Company and Old Dominion Electric
Cooperative (filed herewith).
10.4 -- Nuclear Fuel Agreement, dated as of December 28, 1982 as amended and restated on
October 17, 1983, between Virginia Electric and Power Company and Old Dominion
Electric Cooperative (Exhibit 10(x), Form 10-K for the fiscal year ended December 31,
1983, File No. 1-8489, incorporated by reference).
10.5 -- Credit Agreements dated June 7, 1996, between The Chase Manhattan Bank (formerly
Chemical Bank) and Virginia Electric and Power Company (Exhibits 10(i) and 10(ii),
Form 10-Q for the period ended June 30, 1996, File No. 1-2255, incorporated by
reference).
10.6 -- Credit Agreement, dated December 1, 1985, between Virginia Electric and Power
Company and Old Dominion Electric Cooperative (Exhibit 10(xix), Form 10-K for the
fiscal year ended December 31, 1985, File No. 1-8489, incorporated by reference).
10.7 -- Agreement for Northern Virginia Services, dated as of November 1, 1985, between
Potomac Electric Power Company and Virginia Electric and Power Company (Exhibit
10(xxi), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-8489,
incorporated by reference).
10.8 -- Purchase, Construction and Ownership Agreement, dated May 31, 1990, between
Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit
10(xi), Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255,
incorporated by reference).
10.9 -- Operating Agreement, dated May 31, 1990, between Virginia Electric and Power
Company and Old Dominion Electric Cooperative (Exhibit 10(xii), Form 10-K for the
fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).
10.10 -- Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and the Unit 2
Amendment (Volume 1), dated May 31, 1990 between Virginia Electric and Power
Company and Old Dominion Electric Cooperative, Westinghouse, Black & Veatch,
Combustion Engineering and H. B. Zachry (Volumes 2-11 contain technical specifi-
cations) (Exhibit 10(xiii), Form 10-K for the fiscal year ended December 31, 1990,
File No. 1-2255, incorporated by reference).
10.11* -- Description of arrangements with certain 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).
57
10.12* -- Dominion Resources, Inc. Directors' Deferred Compensation Plan effective July 1,
1986, as amended and restated on January 1, 1996 (Exhibit 10(xii), Form 10-K for the
fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference).
10.13* -- Dominion Resources, Inc. Performance Achievement Plan, effective January 1, 1986,
as amended and restated effective February 19, 1988 (Exhibit 10(xxiii), Form 10-K for
the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).
10.14* -- Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective
January 1, 1981 as amended and restated September 1, 1996 with first amendment
dated June 20, 1997 and second amendment dated March 3, 1998 (filed herewith).
10.15* -- Dominion Resources, Inc.'s Cash Incentive Plan as adopted December 20, 1991
(Exhibit 10(xxv), Form 10-K for the fiscal year ended December 31, 1994, File
No. 1-2255, incorporated by reference).
10.16* -- Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as
amended and restated September 1, 1996 (filed herewith).
10.17* -- Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective
January 1, 1991 as amended and restated September 1, 1996 (filed herewith).
10.18* -- Dominion Resources, Inc. Executives' Deferred Compensation Plan, effective
January 1, 1994, as amended and restated on January 1, 1997 (Exhibit 10(xix), Form
10-K for the fiscal year ended December 31, 1996, File No. 1-2255, incorporated by
reference).
10.19* -- Form of an Employment Agreement dated June 23, 1994 between Virginia Power and
certain executive officers (Exhibit 10(xxi), Form 10-K for the fiscal year ended
December 31, 1996, File No. 1-2255, incorporated by reference).
10.20* -- Employment Agreement dated September 15, 1995 between Virginia Power and
Robert E. Rigsby (Exhibit 10(xxii), Form 10-K for the fiscal year ended December 31,
1996, File No. 1-2255, incorporated by reference).
10.21* -- Employment Agreement dated February 21, 1997 between Dominion Resources and
Norman Askew (filed herewith).
10.22* -- Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, effective
April 23, 1996 (Exhibit 10(xxiv), Form 10-K for the fiscal year ended December 31,
1996, File No. 1-2255, incorporated by reference).
10.23* -- Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997 (filed
herewith)
23.1 -- Consent of Hunton & Williams (filed herewith).
23.2 -- Consent of Jackson & Kelly (filed herewith).
23.3 -- Consent of Deloitte & Touche LLP (filed herewith).
27 -- Financial Data Schedule (filed herewith).
- ---------
* Indicates management contract or compensatory plan or arrangement
(b) Reports on Form 8-K
None
58
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 20, 1998
By THOS. E. CAPPS
-- ------------------------------------------------------
(Thos. E. Capps., Chairman of the
Board of Directors)
Pursuant to the requirements of the
Securities Exchange Act of 1934, this
report has been signed below by the
following persons on behalf of the
registrant and in the capacities
indicated on March 20, 1998.
Signature Title
- ------------------------------------------ ----------------------------------------
THOS E. CAPPS Chairman of the Board of Directors and
----------------------------------
Thos E. Capps Director
JOHN B. ADAMS, JR. Director
----------------------------------
John B. Adams, Jr.
NORMAN ASKEW President (Chief Executive Officer) and
----------------------------------
Norman Askew Director
JOHN B. BERNHARDT Director
----------------------------------
John B. Bernhardt
JAMES F. BETTS Director
----------------------------------
James F. Betts
JEAN E. CLARY Director
----------------------------------
Jean E. Clary
JOHN W. HARRIS Director
----------------------------------
John W. Harris
BENJAMIN J. LAMBERT, III Director
----------------------------------
Benjamin J. Lambert, III
RICHARD L. LEATHERWOOD Director
----------------------------------
Richard L. Leatherwood
HARVEY L. LINDSAY, JR. Director
----------------------------------
Harvey L. Lindsay, Jr.
59
Signature Title
- ------------------------------------------ ---------------------------------
Director
----------------------------------
Kenneth A. Randall
WILLIAM T. ROOS Director
----------------------------------
William T. Roos
FRANK S. ROYAL Director
----------------------------------
Frank S. Royal
JUDITH B. SACK Director
----------------------------------
Judith B. Sack
S. DALLAS SIMMONS Director
----------------------------------
S. Dallas Simmons
ROBERT H. SPILMAN Director
----------------------------------
Robert H. Spilman
WILLIAM G. THOMAS Director
----------------------------------
William G. Thomas
Director
----------------------------------
David A. Wollard
M. S. BOLTON, JR. Controller (Principal Accounting
----------------------------------
M. S. Bolton, Jr. Officer)
60