- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------
FORM 10-K
---------------
(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, 1998
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)
---------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
- -------------------------------- ------------------------
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
---------------
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, 1999, was zero.
As of February 28, 1999, there were issued and outstanding 171,484 shares
of the registrant's common stock, without par value, all of which were held,
beneficially and of record, by Dominion Resources, Inc.
DOCUMENTS INCORPORATED BY REFERENCE.
NONE
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
VIRGINIA ELECTRIC AND POWER COMPANY
PAGE
ITEM NUMBER NUMBER
- ------------------------------------------------------------------------------------------ -------
PART I
1. Business .............................................................................. 1
The Company ........................................................................... 1
Competition ........................................................................... 1
Regulation ............................................................................ 2
General .............................................................................. 2
Virginia ............................................................................. 2
FERC ................................................................................. 2
Environmental ........................................................................ 3
Nuclear .............................................................................. 3
Rates ................................................................................. 4
FERC ................................................................................. 4
Virginia ............................................................................. 5
North Carolina ....................................................................... 5
Capital Requirements and Financing Program ............................................ 6
Construction and Nuclear Fuel Expenditures ........................................... 6
Financing Program .................................................................... 6
Sources of Power ...................................................................... 7
Virginia Power Generating Units ...................................................... 7
Net Purchases ........................................................................ 7
Non-Utility Generation ............................................................... 7
Sources of Energy Used, Fuel Costs and Operations ..................................... 7
Nuclear Operations and Fuel Supply ................................................... 8
Fossil Operations and Fuel Supply .................................................... 8
Purchases and Sales of Energy ........................................................ 8
Future Sources of Power ............................................................... 8
Conservation and Load Management ...................................................... 9
Interconnections ...................................................................... 9
2. Properties ............................................................................ 9
3. Legal Proceedings ..................................................................... 10
4. Submission of Matters to a Vote of Security Holders ................................... 10
PART II
5. Market for the Registrant's Common Equity and Related Stockholder Matters ............. 11
6. Selected Financial Data ............................................................... 11
7. Management's Discussion and Analysis of Financial Condition and Results of Operations . 11
Liquidity and Capital Resources ....................................................... 12
Capital Requirements .................................................................. 13
Results of Operations ................................................................. 13
Future Issues ......................................................................... 16
Market Risk Sensitive Instruments and Risk Management ................................. 23
7A. Quantitative and Qualitative Disclosures About Market Risk ........................... 23
8. Financial Statements and Supplementary Data ........................................... 25
9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure .. 49
PART III
10. Directors and Executive Officers of the Registrant ................................... 50
11. Executive Compensation ............................................................... 53
12. Security Ownership of Certain Beneficial Owners and Management ....................... 57
13. Certain Relationships and Related Transactions ....................................... 58
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ..................... 58
PART I
ITEM 1. BUSINESS
THE COMPANY
Virginia Electric and Power Company is a Virginia corporation with its
principal office located at 701 East Cary Street, Richmond, Virginia
23219-3932. The telephone number is (804) 771-3000. All of our common stock is
held by Dominion Resources, Inc., a Virginia corporation (Dominion Resources).
Virginia Electric and Power Company is a 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. We supply
energy at retail to approximately two million customers. In addition, we sell
electricity at wholesale to rural electric cooperatives, power marketers and
certain municipalities. Within this document the term "Virginia Power" refers
to the entirety of Virginia Electric and Power Company, including our Virginia
and North Carolina operations and all of our subsidiaries.
In Virginia we trade under the name "Virginia Power." The Virginia service
area comprises about 65 percent of Virginia's total land area, but accounts for
over 80 percent of its population. In North Carolina we trade under the name
"North Carolina Power" and serve retail customers located in the northeastern
region of the state, excluding certain municipalities. We also engage in
off-system wholesale purchases and sales of electricity and purchases and sales
of natural gas and are developing trading relationships beyond the geographic
limits of our retail service territory. The Federal Energy Regulatory
Commission (FERC), the State Corporation Commission of Virginia (the Virginia
Commission) and the North Carolina Utilities Commission (the North Carolina
Commission) are the principal regulators of our electric operations.
Various factors are currently affecting the electric utility industry,
including increasing competition and related regulatory changes, costs to
comply with environmental regulations, and the potential for new business
opportunities outside of traditional rate-regulated operations. To meet the
challenges of this new competitive environment, we continue to consider new
business opportunities, particularly those which allow us to use the expertise
and resources developed through our regulated utility experience. Over the past
several years we have developed a broad array of "non-traditional" products and
services. Examples of non-traditional services include wholesale power
marketing and telecommunications. We also market our services to other
utilities in areas such as nuclear consulting and management and power
distribution (i.e., transmission, distribution, engineering and metering
services). We are continuing to focus on new and existing programs to enhance
customer satisfaction and energy efficiency.
Virginia Power had 8,981 full-time employees on December 31, 1998. A total
of 3,126 of our employees are represented by the International Brotherhood of
Electrical Workers under a contract extending to March 31, 2000.
COMPETITION
For most of this century, the structure of the electric industry in
Virginia Power's service territory and throughout the United States has been
relatively stable. Recently, however, there have been both federal and state
developments toward less regulation and increased competition. Electric
utilities have been required to open up their transmission systems for non-
discriminatory use by potential wholesale competitors. In addition, non-utility
power marketers now compete with electric utilities in the wholesale generation
market. At the federal level, retail competition is under consideration. Some
states, including Virginia, have enacted legislation requiring retail
competition.
Currently, as in the past, there is no general retail competition in our
principal service area. Today our only competition for retail sales is if
certain of our business customers move into another utility service territory,
use other energy sources instead of electric power, or generate their own
electricity. However, Virginia has adopted legislation requiring retail
competition beginning in 2002 and North Carolina is considering implementing
retail competition. To the extent that competition is permitted, our ability to
sell power at prices that will allow us to recover our prudently incurred costs
may be an issue.
The Virginia General Assembly is actively considering in its current
session, legislative proposals that would address more specifically the
timetable for retail competition in the state; deregulation of the generation
of electricity; transfer of management and control of transmission systems to a
regional transmission entity; recovery of prudently incurred stranded costs and
consumer protection issues. Additionally, we are in the process of developing a
retail access pilot program for implementation in Virginia.
1
We continue to participate actively in both the legislative and regulatory
processes relating to industry restructuring in an effort to ensure an orderly
transition from a regulated environment. We have also responded to the trends
toward competition by cutting costs, re-engineering our core business processes
and pursuing innovative approaches to servicing traditional and future markets.
In addition, we are developing certain "non-traditional" products and services
as described in the above section entitled THE COMPANY in an effort to provide
growth in future earnings.
For a more thorough review of our changing industry environment see Future
Issues--COMPETITION under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (MD&A).
REGULATION
GENERAL
The Virginia Commission and the North Carolina Commission regulate our
rates for retail electric sales within their respective states. FERC approves
our rates for electric sales to wholesale customers. A discussion of rate
related matters is in the section below entitled RATES.
In addition to rates, many other aspects of Virginia Power's business are
presently subject to regulation by the Virginia Commission, the North Carolina
Commission, FERC, the Environmental Protection Agency (EPA), Department of
Energy (DOE), Nuclear Regulatory Commission (NRC), the Army Corps of Engineers
and other federal, state and local authorities.
Virginia Power holds certificates of public convenience and necessity
issued by the Virginia Commission and the North Carolina Commission authorizing
it to construct and operate the electric facilities now in operation for which
certificates are required, and to sell electricity to retail customers.
However, we 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.
The following sections discuss various regulatory proceedings in which we
are or have recently been involved. Rate specific proceedings are discussed
separately in the section below entitled RATES.
VIRGINIA
Virginia Power is subject to the jurisdiction of the Virginia Commission,
which has broad powers of supervision and regulation over public utilities,
including rates, service regulations and sales of securities. The following is
a description of recent Virginia proceedings.
On March 21, 1998, the Virginia Commission issued an Order Establishing
Investigation with regard to independent system operators (ISO's), regional
power exchanges (RPX's) and retail access pilot programs. The Order directed
all investor-owned electric utilities to begin work, in conjunction with the
Virginia Commission Staff and other interested stakeholders, to develop one or
more ISO's and RPX's to serve the public interest in Virginia. In addition, the
Order instructed Virginia Power and AEP-Virginia, as the Commonwealth's two
largest investor-owned utilities, each to design and file a retail access pilot
program. In response to the Order, we filed a report describing the details,
objectives and characteristics of our proposed retail access pilot. For more
details on the proposed retail access pilot program, see Future Issues --
COMPETITION -- REGULATORY INITIATIVES under MD&A.
We have sought approval from the Virginia Commission for the construction
of four gas fired turbine generators in Virginia and is soliciting bids in
accordance with the Virginia Commission's Order dated January 14, 1999. We have
obtained the applicable zoning permits for the construction of the generators
and have applied for other required environmental permits.
On January 28, 1999, the Virginia Commission issued an order approving the
addition of two wholly-owned subsidiaries of Virginia Power Services, Inc.,
namely Virginia Power Services Energy Corp., Inc. (VPSE) and Virginia Power
Energy Marketing, Inc. (VPEM), to the Affiliate Services Agreement approved by
the Virginia Commission in its Order dated September 3, 1997. In connection
with the organization of VPSE and VPEM, the Virginia Commission issued two
related orders approving our transfer of certain contracts relating to the
storage, transportation, procurement and management of our natural gas and oil
inventory to these subsidiaries.
FERC
The Federal Power Act subjects Virginia Power to regulation by FERC as a
company engaged in the transmission or sale of wholesale electric energy in
interstate commerce. The Energy Policy Act of 1992 (EPACT) and FERC's
subsequent
2
rulemaking activities allow FERC to order access for third parties to
transmission facilities owned by another entity. This authority is limited,
however, and does not permit FERC to issue orders requiring transmission access
to retail customers. FERC has issued orders for third-party transmission
service. FERC has also issued a number of rules of general applicability,
including Orders 888 and 889.
Pursuant to FERC's final rules, we established an open access same-time
information system (OASIS) which became operational January 1997. In addition,
in July 1997 we filed amendments to our existing rate tariff with FERC so that
we could make wholesale power sales at market-based rates. Under a FERC order
conditionally accepting our market-based rate schedule, we began making
market-based sales of wholesale power in 1997. FERC set for hearing the issue
of whether transmission constraints limiting the transfer of power into our
service territory would provide us with generation dominance in local markets.
This issue was resolved through FERC's acceptance of an offer of settlement in
which we agreed to refrain from making sales under our market-based tariff to
loads located within our service territory. This settlement did not preclude us
from requesting FERC authorization of such sales in the future, but until such
authorization has been granted by FERC, agreements by Virginia Power to sell
wholesale power to loads located within our service territory are to be at
cost-based rates accepted by FERC.
On November 6, 1998, Virginia Power, along with American Electric Power
(AEP), First Energy Corp. and Consumers Energy announced their agreement to
move forward on a proposal to prepare a FERC filing to establish a regional
transmission organization. For more detail on this proposal, see the
INTERCONNECTIONS section below.
LG&E Westmoreland Southhampton (Southhampton) has requested waivers of
FERC operating requirements with respect to its cogeneration facility in
Franklin, Virginia. We have previously reported the existence and history of
this proceeding. The parties have reached a settlement, which was accepted by
FERC in December 1998.
ENVIRONMENTAL
We face substantial regulation and compliance costs with respect to
environmental matters. For discussion of significant aspects of these matters,
including our planned capital expenditures in 1999 relating to environmental
compliance, see Future Issues -- ENVIRONMENTAL MATTERS, ENVIRONMENTAL
PROTECTION AND MONITORING EXPENDITURES, CLEAN AIR ACT COMPLIANCE, AND GLOBAL
CLIMATE CHANGE under MD&A.
From time to time we may be identified as a potentially responsible party
(PRP) with respect to a superfund site. EPA (or a state) can either (a) allow
such a party to conduct and pay for a remedial investigation, feasibility study
and remedial action or (b) conduct the remedial investigation and action and
then seek reimbursement from the parties. Each party can be held jointly,
severally and strictly liable for all costs, but the parties can then bring
contribution actions against each other and seek reimbursement from their
insurance companies. As a result of the Superfund Act or other laws or
regulations regarding the remediation of waste, we may be required to expend
amounts on remedial investigations and actions. We do not believe that any
currently identified sites will result in significant liabilities. For a
discussion of certain remediation efforts in which we are involved, see
ENVIRONMENTAL MATTERS, Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
In accordance with applicable Federal and state environmental laws, we
have applied for or obtained the necessary environmental permits material to
the operation of our generating stations. Many of these permits are subject to
re-issuance and continuing review.
NUCLEAR
All aspects of the operation and maintenance of our nuclear power stations
are regulated by the NRC. Operating licenses issued by the NRC are subject to
revocation, suspension or modification, and operation of a nuclear unit may be
suspended if the NRC determines that the public interest, health or safety so
requires.
From time to time, the NRC adopts new requirements for the operation and
maintenance of nuclear facilities. In many cases, these new regulations require
changes in the design, operation and maintenance of existing nuclear
facilities. If the NRC adopts such requirements in the future, it could result
in substantial increases in the cost of operating and maintaining our nuclear
generating units.
One of the issues associated with operation and decommissioning of nuclear
facilities is disposal of spent nuclear fuel (SNF). The Nuclear Waste Policy
Act of 1982 required the Federal Government to make available by January 31,
1998 a permanent repository for high-level radioactive waste and spent nuclear
fuel. The Federal Government has not made such a repository available.
3
In July 1995, the Virginia Commission instituted an investigation
regarding SNF 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
(DOE) 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 SNF
disposal issue to a separate proceeding. No procedural order has been issued,
but the proceeding is pending.
In response to DOE's insufficient progress towards providing a permanent
repository for SNF, in January 1997, Virginia Power and numerous other electric
utilities requested the United States Court of Appeals for the District of
Columbia Circuit (the DC Circuit) to order the DOE to begin accepting the
utilities' SNF for disposal by January 31, 1998. In November 1997, the DC
Circuit found that DOE's obligation to begin accepting SNF by the deadline is
"unconditional" and that DOE may not excuse its delay on the grounds that
delays were unavoidable. In February 1998, Virginia Power and other electric
utilities requested the DC Circuit to require DOE to begin moving SNF, prohibit
DOE from using the Nuclear Waste Fund (NWF) to pay damages and relieve
utilities of their obligation to pay NWF fees unless and until DOE complies
with its obligations. In May 1998, the DC Circuit refused to require DOE to
begin moving SNF and found that utilities should pursue their remedies under
their SNF contracts with DOE. In November 1998 the U.S. Supreme Court denied
DOE's request for review of the DC Circuit's decisions.
When our nuclear units cease to operate, we will be obligated to
decontaminate the facilities. This process is referred to as decommissioning,
and we are required by the NRC to prepare for it financially. For information
on our compliance with the NRC financial assurance requirements, see Future
Issues -- NRC NUCLEAR DECOMMISSIONING RULE under MD&A and Note C to
CONSOLIDATED FINANCIAL STATEMENTS.
RATES
Our electric service sales for 1998 included 64.3 million megawatt-hours
of retail sales and 4.5 million megawatt-hours of sales to wholesale
requirements contract customers and were composed of the following:
1998
-----------------------
PERCENT PERCENT
OF OF
REVENUES KWH SALES
---------- ----------
Virginia retail:
Non-Governmental customers ......... Virginia Commission 81% 77%
Governmental customers ............. Negotiated Agreements 10 13
North Carolina retail ............... North Carolina Commission 5 5
Wholesale* .......................... FERC 4 5
-- --
100% 100%
=== ===
- ---------
* Excludes power marketing sales which are also subject to FERC regulation.
Substantially all of our electric service sales are currently 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.
Where cost-based rates are in effect, 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
Recent FERC proceedings relating to our rates include the following:
o In compliance with FERC's Order 889, on January 3, 1997, we filed our
Procedures For Standards of Conduct for Unbundled Transmissions and Wholesale
Merchant Function (Standards of Conduct) effective on that date. In July 1997,
we filed several amendments to the Standards of Conduct in compliance with
FERC's Order 889-A. On September 29, 1998 FERC accepted our revised Standards
of Conduct with only minor modifications.
4
o On September 11, 1997, FERC authorized Virginia Power to make wholesale
power sales under our Market-Based Sales Tariff but set a hearing to consider
the effect of transmission constraints on our ability to exercise generation
market power in localized areas within our service territory. Based upon a
settlement in principle reached by the participants, the hearing schedule was
suspended and we were directed to file a formal Offer of Settlement by May 11,
1998. The participants subsequently filed a formal Offer of Settlement that was
accepted by FERC in January 1999. Under the Offer of Settlement, we agreed to
refrain from wholesale power sales under our Market-Based Sales Tariff to loads
located within our service territory. This settlement did not preclude us from
requesting FERC authorization of such sales in the future, but until such
authorization has been granted by FERC, agreements by Virginia Power to sell
wholesale power to loads located within our service territory must be at
cost-based rates accepted by FERC.
VIRGINIA
Recent Virginia proceedings related to our rates include the following:
o On June 8, 1998, Virginia Power, the Staff of the Virginia Commission,
the office of the Virginia Attorney General, the Virginia Committee for Fair
Utility Rates and the Apartment and Office Building Association of Metropolitan
Washington agreed to settle our pending rate proceedings before the Virginia
Commission. The Virginia Commission, by Order dated August 7, 1998, approved
the settlement with only a minor redistribution of the agreed rate reduction
among customer classes. The settlement defines a new regulatory framework for
our transition to retail competition. For provisions of the settlement, see
Note P to CONSOLIDATED FINANCIAL STATEMENTS.
o On October 31, 1997, we filed with the Virginia Commission an
application for a reduction of $45.6 million in our 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, we 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. On April 24, 1998, the Virginia Commission approved
the decrease in the fuel factor effective May 1, 1998.
o On September 11, 1998, we filed an application with the Virginia
Commission to modify our cogeneration and small power production rates under
Schedule 19. An evidentiary hearing was held on this matter February 24, 1999.
o On October 19, 1998, we filed an application with the Virginia
Commission for an increase of $55 million in fuel rates. The increase was
approved effective December 1, 1998.
NORTH CAROLINA
Recent North Carolina proceedings related to our rates include the
following:
o On November 6, 1998, we filed for approval of a new Schedule 19 which
governs purchases from cogenerators and small power producers. We proposed
shortening the maximum term of contracts under Schedule 19 to three years. A
public hearing took place on February 2, 1999. All proposed orders will be
filed by March 12, 1999.
o On September 11, 1998, we filed an application with the North Carolina
Commission for a $1.4 million increase in fuel rates. On December 23, 1998, the
North Carolina Commission approved our request. This increases the annual fuel
rates and charges paid by the retail customers of North Carolina Power
effective on January 1, 1999.
5
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
CONSTRUCTION AND NUCLEAR FUEL EXPENDITURES
Virginia Power's estimated construction and nuclear fuel expenditures for
the three-year period 1999-2001, total $2.3 billion. We have adopted a 1999
budget for construction and nuclear fuel expenditures as set forth below:
ESTIMATED 1999
EXPENDITURES
---------------
(MILLIONS)
Production ............................................................. $ 349*
Technology ............................................................. 109
General Support Facilities ............................................. 42
Transmission ........................................................... 20
Distribution ........................................................... 210
Nuclear Fuel ........................................................... 72
------
Total Construction Requirements and Nuclear Fuel Expenditures ......... $ 802
======
- ---------
* Includes amounts related to our proposed construction of four gas-fired
turbine generator units in Fauquier County, Virginia. See FUTURE SOURCES OF
POWER.
FINANCING PROGRAM
We currently have three shelf registrations on file with the Securities
and Exchange Commission (SEC) providing us with $645 million of debt capital
resources. We also have a Preferred Stock shelf registered with the SEC for
$100 million in aggregate principal amount, which has not been utilized.
We intend to issue securities from time to time to meet our capital
requirements, which include $321 million of long-term debt maturities in 1999.
Please see the Liquidity and Capital Resources section of MD&A for details
about our financing program.
6
SOURCES OF POWER
VIRGINIA POWER 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 generating unit capability .................... 13,635
NET PURCHASES .......................................... 1,230
NON-UTILITY GENERATION ................................. 3,285
---------
Total Capability .................................... 18,150
=========
- ---------
(a) Includes an undivided interest of 11.6 percent (208 MW) owned by Old
Dominion Electric Cooperative (ODEC).
(b) Includes an undivided interest of 50 percent (441 MW) owned by ODEC.
(c) This unit was placed in a cold reserve status January 25, 1996.
(d) Reflects Virginia Power'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).
Virginia Power's highest one-hour integrated service area summer peak
demand was 15,399 MW on July 22, 1998, and an all-time high one-hour integrated
winter peak demand of 14,910 MW was reached on February 5, 1996.
SOURCES OF ENERGY USED, FUEL COSTS AND OPERATIONS
For information as to energy supply mix and the average fuel cost of
energy supply, see Results of Operations under MD&A.
7
NUCLEAR OPERATIONS AND FUEL SUPPLY
In 1998, Virginia Power's four nuclear units achieved a combined capacity
factor of 91.7 percent.
Virginia Power utilizes both long-term contracts and spot purchases to
support our needs for nuclear fuel. We continually evaluate worldwide market
conditions in order to ensure a range of supply options at reasonable prices.
Current agreements, inventories and spot market availability will support our
current and planned fuel supply needs for fuel cycles into the early 2000's.
Beyond that period, additional fuel will be purchased as required to ensure
optimum cost and inventory levels.
The DOE did not begin the acceptance of spent fuel in 1998 as specified in
Virginia Power's contract with the DOE. However, on-site spent nuclear fuel
pool and dry container storage at the Surry and North Anna Power Stations is
expected to be adequate for our needs until the DOE begins accepting spent
fuel.
For details on the issues of decommissioning and nuclear insurance, see
Note C to CONSOLIDATED FINANCIAL STATEMENTS.
FOSSIL OPERATIONS AND FUEL SUPPLY
Our fuel mix consists of coal, oil and natural gas. During 1998, we burned
approximately 14 million tons of coal. We utilize both long-term contracts and
spot purchases to support our coal needs. We presently anticipate sufficient
supplies of coal will be available at reasonable prices for the next 5 to 10
years. A sufficient supply of oil and natural gas is expected over the same
period with stable prices.
We use natural gas as needed throughout the year primarily for three
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 may not be
available. We have firm transportation contracts for the delivery of gas to the
Chesterfield combined-cycle units.
PURCHASES AND SALES OF ENERGY
We purchase electricity under long-term contracts with other suppliers to
meet a portion of our own system capacity requirements, as well as for
short-term sales transactions in the eastern United States. In addition to
wholesale electric power transactions, we also actively participate in the
purchase and sale of natural gas in the open market.
From the mid-1980's until the start of the 1990's, we entered into a
number of long-term purchase contracts for electricity with both utilities and
non-utility generators. At the end of 1999, 900 MW of these purchases from
other utilities will end, and by the first quarter of 2000, an additional 200
MW of diversity exchange transactions will be suspended. However, we continue
to have contracts with 55 non-utility generators with a combined dependable
summer capacity of 3,285 MW. During 1998, we entered into a long-term agreement
to purchase 560 MW of electricity for sale to the wholesale market from two of
three generating units at a plant being constructed in Mississippi. For
information on the financial obligations under these agreements, see PURCHASED
POWER CONTRACTS, Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
In a continuing effort to mitigate our exposure to above-market long-term
purchased power contracts, we are evaluating our long-term purchased power
contracts and negotiating modifications to their terms, including
cancellations, where it is determined to be economically advantageous to do so.
In 1997, Virginia Power executed three agreements with 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
Both the Hoosier 400 MW long-term purchase contract and the AEP 500 MW
long-term purchase contract will expire on December 31, 1999. We presently
anticipate adding peaking capacity beginning in the year 2000 to meet our
anticipated load growth. In addition, work is being done to return the North
Branch unit to full operational capacity in the year 2000.
On August 11, 1998, Virginia Power filed an application with the Virginia
Commission for a Certificate of Public Convenience and Necessity to construct
five gas-fired combustion turbine generator units in Virginia. On October 21,
1998, we
8
modified our application to seek approval for one additional unit and expressed
our intention to build four units in Fauquier County for operation in July 2000
and to build the remaining two units in Caroline County for operation in July
2001. On December 23, 1998, we further modified our application, withdrawing
the pending request to construct the two combustion turbine units in Caroline
County and seeking approval only for the four units to be constructed in
Fauquier County for a total of 600 MW. We proposed to seek the additional
capacity from the wholesale market.
A hearing before the Commission was held in January 1999 at which the
Virginia Commission determined that the Rules Governing the Use of Bidding
Programs to Purchase Electricity from Other Power Suppliers were applicable to
the proposed transaction. The Virginia Commission issued an Order directing
Virginia Power to issue a Request for Proposals (RFP) for the capacity needed.
The Order further provided for the Virginia Commission Staff to review the
solicitation process and set an expedited schedule that requires bidders to
submit responses to our RFP no later than March 26, 1999. Our proposed build
option will be considered as the benchmark for assessing the bid responses and,
if our option represents the successful bid, we will be permitted to construct
the four units proposed in our modified application. We have obtained the
applicable zoning permits for construction of the combustion turbine generators
in Fauquier County and have applied for other required permits including
applicable environmental permits.
We also continue to pursue conservation and demand-side management (see
CONSERVATION AND LOAD MANAGEMENT below).
CONSERVATION AND LOAD MANAGEMENT
Conservation and load management programs are evaluated in conjunction
with our annual resource planning process. This process supports a conservation
and load management portfolio, which contributes to the selection of low-cost
resources to meet the future electricity needs of our customers.
Events in the evolving electric power marketplace and our regulatory and
legislative environment continue to impact utility-sponsored conservation and
load management programs. We continue to anticipate a greater reliance on price
signals to convey information to our customers regarding energy-related costs,
resulting in more efficient purchase decisions.
INTERCONNECTIONS
We maintain 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, we have arrangements with these
utilities for coordinated planning, operation, emergency assistance and
exchanges of capacity and energy.
On November 6, 1998, Virginia Power, AEP, FirstEnergy Corp., and Consumers
Energy announced their agreement to move forward on a proposal to prepare a
FERC filing to establish a regional transmission organization. The proposed
organization would operate the transmission systems of the companies, ensure
transmission reliability and provide non-discriminatory access to the
transmission grid. These companies have established a target date of Spring
1999 to prepare the filing.
As proposed, the governance and organization structures of the regional
transmission organization will enable the formation of an ISO or a regional
transmission company (TransCo). It will detail the mechanisms needed to
transition from an ISO to a TransCo in the event the organization does not
initially operate as a TransCo. It will be designed to meet the goals of
reducing transmission costs that result from pancaked rates (accumulated
transmission access fees resulting from transferring power over several
transmission systems). It will also address transmission tariff, congestion
management, operations and planning issues, as well as assisting in the
development of a market approach to providing ancillary services.
While the companies are drafting the proposal and will be responsible to
seek appropriate regulatory approval, the companies will continue to utilize
the Alliance transmission development process established in December 1997.
This is an open and cooperative effort, involving regular meetings and
discussions with representatives from other investor-owned utilities,
regulatory staff members, transmission customers, public power companies,
municipal systems and rural electric cooperatives. This process provides input
from diverse sources to assist in the formation of the organization.
ITEM 2. PROPERTIES
We own our principal properties in fee (except as indicated below),
subject to defects and encumbrances that do not interfere materially with their
use. Substantially all of Virginia Power's property is subject to the lien of a
mortgage securing our First and Refunding Mortgage Bonds. Right-of-way grants
from the apparent owners of real estate have been
9
obtained for most of our 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 our
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.
We lease certain buildings and equipment. See Note G to CONSOLIDATED
FINANCIAL STATEMENTS for details on our lease obligations.
See Virginia Power Generating Units under SOURCES OF POWER under Item 1.
BUSINESS for a list of our principal generating facilities.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are 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 us, or permits issued by various local,
state and federal agencies for the construction or operation of facilities.
From time to time, there may be pending administrative proceedings on these
matters. In addition, in the normal course of business, we are involved in
various legal proceedings. Management believes that the ultimate resolution of
these proceedings will not have a material adverse effect on our financial
position, liquidity or results of operations.
See REGULATION and RATES under Item 1. BUSINESS for information on various
regulatory proceedings to which we are a party.
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. These matters have been resolved
through settlement by the parties. 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. On the same date, Doswell also filed a
complaint against Virginia Power in the United States District Court for the
Eastern District of Virginia. These matters have been settled and the suits
dismissed.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
10
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
Dominion Resources owns all of the Company's Common Stock.
The Company paid quarterly cash dividends on its Common Stock as follows:
1ST 2ND 3RD 4TH
---------- ---------- ---------- ----------
(MILLIONS)
1998 ......... $ 99.7 $ 91.4 $ 94.6 $ 92.0
1997 ......... $ 95.9 $ 93.4 $ 94.7 $ 95.9
ITEM 6. SELECTED FINANCIAL DATA
1998 1997 1996 1995 1994
-------------- -------------- -------------- -------------- --------------
(MILLIONS, EXCEPT PERCENTAGES)
Revenue ............................................. $ 4,284.6 $ 4,663.9 $ 4,382.0 $ 4,351.9 $ 4,170.8
Income from operations .............................. 685.8 1,014.7 999.8 971.9 957.1
Net income .......................................... 229.9 469.1 457.3 432.8 447.1
Balance available for Common Stock .................. 194.1 433.4 421.8 388.7 404.9
Total assets ........................................ 11,984.9 11,925.1 11,828.0 11,827.7 11,647.9
Total net property, plant and equipment ............. 9,081.9 9,271.8 9,433.8 9,573.1 9,623.4
Long-term debt, noncurrent capital lease obligations,
preferred stock subject to mandatory redemption and
preferred securities of subsidiary trust ........... 3,805.4 3,854.4 3,916.2 4,228.0 4,157.5
Plant expenditures (including nuclear fuel) ......... 531.7 481.8 484.0 577.5 660.9
Capitalization ratios (percent):
Debt ............................................... 46.0 45.4 46.4 47.2 46.7
Preferred stock .................................... 7.8 7.6 7.5 7.5 9.0
Preferred securities ............................... 1.5 1.5 1.5 1.5
Common equity ...................................... 44.7 45.5 44.6 43.8 44.3
Embedded cost (percent):
Long-term debt ..................................... 7.39 7.60 7.68 7.73 7.65
Preferred stock .................................... 5.19 5.25 5.14 5.29 5.47
Preferred securities ............................... 8.72 8.72 8.72 8.72
Weighted average ................................... 7.10 7.29 7.34 7.41 7.29
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.
The business and financial condition of Virginia Power are influenced by a
number of factors including political and economic risks, market demand for
energy, inflation, capital market conditions, governmental policies,
legislative 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 and legal and administrative proceedings. Some other
important factors that could cause actual results or outcomes to differ
materially from those discussed in the forward-looking statements include
changes in and compliance with environmental laws and policies, weather
conditions and catastrophic weather-related damage, present or prospective
wholesale and retail competition, competition for new energy development
opportunities, pricing and transportation of commodities, operation of nuclear
power facilities, acquisition and disposition of assets and facilities,
11
recovery of the cost of purchased power, nuclear decommissioning costs, the
ability of the Company, its suppliers, and its customers to successfully
address Year 2000 compliance issues, exposure to changes in the fair value of
commodity contracts, counter-party credit risk and unanticipated changes in
operating expenses and capital expenditures. 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 to predict all such factors, nor can we assess the
impact of each such factor on Virginia Power.
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 $1,094 million in 1998 compared to $1,091 million in 1997. Over the
past three years, cash flow from operating activities, after dividend payments,
has, on average, covered 137 percent of our total construction requirements and
provided 83 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:
1998 1997 1996
----------- ----------- ------------
(MILLIONS)
Issuance of long-term debt ...................... $ 270.0 $ 270.0 $ 24.5
Issuance (repayment) of short-term debt ......... ( 4.5) ( 86.2) 143.4
Repayment of long-term debt ..................... (333.5) (311.3) (284.1)
Dividend payments ............................... (413.3) (415.7) (421.4)
Other ........................................... ( 17.3) ( 13.4) ( 13.2)
-------- -------- --------
Total .......................................... $ (498.6) $ (556.6) $ (550.8)
======== ======== ========
We have continued to take advantage of declining interest rates by issuing
new debt at lower rates as higher-rate debt has matured. In 1998, $333.5
million of the Company's long-term debt securities matured with an average
effective rate of 8.36 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 6.71 percent.
We currently have three shelf registration statements effective with the
SEC 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; and $200
million of Medium-Term Notes, Series F. The remaining principal amount of debt
that can be issued under these registrations totals $645 million. An additional
capital resource of $100 million in preferred stock also is registered with the
SEC.
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 $221.7 million at December 31, 1998.
INVESTING ACTIVITIES in 1998 resulted in a net cash outflow of $581.9
million, primarily due to $450.8 million of construction expenditures and $80.9
million of nuclear fuel expenditures. The construction expenditures included
approximately $281.8 million for transmission and distribution projects, $80.5
million for production projects, $57.9 million for information technology
projects and $30.6 million for other projects.
12
Cash used in investing activities was as follows:
1998 1997 1996
------------ ------------ ------------
(MILLIONS)
Plant and equipment expenditures (excluding AFC -- other funds) ......... $ (450.8) $ (397.0) $ (393.8)
Nuclear fuel (excluding AFC -- other funds) ............................. ( 80.9) ( 84.8) ( 90.2)
Nuclear decommissioning contributions ................................... ( 37.5) ( 36.2) ( 36.2)
Purchase of assets ...................................................... ( 19.8) ( 13.7)
Other ................................................................... ( 12.7) ( 8.3) ( 12.5)
-------- -------- --------
Total .................................................................. $ (581.9) $ (546.1) $ (546.4)
======== ======== ========
CAPITAL REQUIREMENTS
CAPACITY -- We anticipate that kilowatt-hour sales will grow approximately
3 percent a year through 2001. In addition, our purchase agreements with
Hoosier (400 MW) and AEP (500 MW) will expire on December 31, 1999. To meet
these requirements, we have developed plans to construct four 150 MW combustion
turbines in Fauquier County, Virginia by midyear 2000 at a projected cost of
$175 million to $190 million. However, on January 14, 1999, the Virginia
Commission issued an Order directing the Company to solicit bids from
independent suppliers to determine if a lower overall cost option is available.
FIXED ASSETS -- The Company's construction and nuclear fuel expenditures,
during 1999, 2000 and 2001 are expected to total $802.5 million, $756.7 million
and $762.7 million, respectively. We expect 1999 construction and nuclear fuel
expenditures to be met through cash flow from operations, sales of securities
and short-term borrowings.
We plan to install sulfur dioxide (SO2) emission control equipment at two
coal fired generating units, and this will require a $115 million investment
over the next four years. Management believes the installation of scrubbers on
these two units will provide the most cost effective means of complying with
the Clean Air Act.
In response to a rule adopted by the EPA in September 1998, we plan to
install nitrogen oxides (NOx) reduction equipment at our coal fired generating
stations at an estimated capital cost of $500 million over the next five years.
Whether these costs are actually incurred is dependent on the implementation
plans adopted by the states in which we operate. See Future Issues -- CLEAN AIR
ACT COMPLIANCE.
LONG-TERM DEBT -- The Company will require $321 million to meet maturities
of long-term debt in 1999, 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.
RESULTS OF OPERATIONS
The following is a discussion of results of operations for the years ended
1998 as compared to 1997, and 1997 as compared to 1996.
1998 COMPARED TO 1997
Balance available for common stock decreased by $239.3 million as compared
to 1997, primarily due to settlement of the Company's rate case before the
Virginia Commission in 1998. The settlement resulted in a rate reduction and
refund and a writedown of regulatory assets. See Note P to CONSOLIDATED
FINANCIAL STATEMENTS.
13
REVENUE changed from the prior year primarily due to the following:
1998 1997
------------- -----------
(MILLIONS)
Revenue -- Electric Service
Customer growth ................ $ 50.1 $ 55.8
Weather ........................ ( 7.0) ( 111.1)
Base rate variance ............. ( 226.3) ( 18.7)
Fuel rate variance ............. ( 120.9) 44.1
Other retail, net .............. 93.2 47.7
--------- --------
Total retail ................. ( 210.9) 17.8
Other electric service ......... ( 6.3) 9.8
--------- --------
Total ........................ ( 217.2) 27.6
--------- --------
Revenue -- Other ................ ( 162.1) 254.3
--------- --------
Total revenue ................ $ (379.3) $ 281.9
========== ========
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 1998 were a
base rate refund and rate reduction arising from settlement of the Company's
rate proceedings before the Virginia Commission and adjustments to annual fuel
rates. See Note P to CONSOLIDATED FINANCIAL STATEMENTS. In addition, this
revenue was affected by weather and customer growth.
Customer growth -- Sales resulting from new customer connections increased
our revenue by $50.1 million in 1998 over 1997.
Weather -- The mild winter weather in 1998 caused customers to use less
electricity than normal for heating. This reduction in sales was
substantially offset by increased 1998 third quarter sales, as compared to
third quarter 1997, resulting from warmer weather and increased usage by
customers for cooling. This reduced 1998 revenue by $7.0 million as
compared to 1997. Heating and cooling degree days were as follows:
1998 1997 NORMAL
------------ ------------ -------
Cooling degree days ............................... 1,640 1,349 1,564
Percentage change compared to prior year .......... 21.6% (1.2)%
Heating degree days ............................... 3,197 3,787 3,753
Percentage change compared to prior year .......... (15.6)% (8.3)%
Fuel rates -- The regulatory commissions having jurisdiction over the
Company currently allow us to charge customers for the cost of fuel used in
generating electricity. The decrease in fuel rate revenues is primarily
attributable to lower fuel rates that went into effect December 1, 1997,
and additional reductions effective March 1, 1998 and May 1, 1998 to
recognize savings from negotiated changes to power supply contracts. These
reductions were partially offset by an increase from the Company's annual
fuel case that went into effect December 1, 1998. The rate changes
decreased fuel revenues by $120.9 million as compared to 1997.
OTHER REVENUE includes sales of electricity beyond our service territory
and sales of natural gas, net of the related cost of purchased commodities. It
also includes revenue from nuclear consulting services and energy management
services. Other revenue decreased in 1998 as compared to 1997 due to
electricity trading revenues being reported net of purchased energy for the
entirety of 1998 and only for the last four months of 1997. Such revenues are
reported gross for the first eight months of 1997 as a result of being subject
to cost of service rate regulation during that time.
EXPENSES changed from the prior year primarily due to the following:
FUEL, NET decreased in 1998, as compared to 1997, primarily due to the
inclusion of the cost of power marketing purchases for the first eight months
of 1997. However, the cost of power marketing purchases for the last four
months of 1997 and the entirety of 1998 is being reported net of related
revenues in Other revenue. Prior to September 1997, this activity was subject
to cost of service rate regulation.
14
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.
1998 1997 1996
-------------------- -------------------- --------------------
SOURCE COST SOURCE COST SOURCE COST
-------- --------- -------- --------- -------- ---------
Nuclear (*) .................. 33% 4.71 34% 4.52 32% 4.48
Coal (**) .................... 42 13.21 40 13.54 38 14.32
Oil .......................... 3 22.52 1 26.32 1 27.75
Purchased power, net ......... 19 21.85 23 21.54 27 21.99
Other ........................ 3 27.27 2 30.65 2 26.98
-- -- --
Total ...................... 100% 100% 100%
=== === ===
Average fuel cost .......... 12.71 12.67 13.47
- ---------
(*) 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.
PURCHASED POWER CAPACITY, NET increased in 1998 as compared to 1997
primarily due to (1) increased expenses associated with the restructuring of
certain contracts and (2) the discontinuance of deferral accounting for such
expenses. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
IMPAIRMENT OF REGULATORY ASSETS in 1998 is a write down of regulatory
assets as a result of the Company's settlement of the rate proceeding before
the Virginia Commission. See Note P to CONSOLIDATED FINANCIAL STATEMENTS. The
1996 and 1997 amounts represent a reserve for potential adjustments to
regulatory assets.
OPERATIONS AND MAINTENANCE increased in 1998 as compared to 1997 primarily
due to (1) costs to repair storm damage caused by December 1998 ice storms and
by hurricane Bonnie in the third quarter of 1998 and (2) the cost of preparing
the Company's computer systems for year 2000. See Future Issues -- YEAR 2000
COMPLIANCE.
RESTRUCTURING EXPENSES decreased in 1998 as compared to 1997. Although we
are continuing to evaluate the Company's operations in anticipation of the
restructuring of the electric industry, no significant restructuring expenses
were incurred in 1998. See Note O to CONSOLIDATED FINANCIAL STATEMENTS.
DEPRECIATION AND AMORTIZATION decreased in 1998 as compared to 1997 due to
adjustments to the provision for depreciation and decommissioning expenses to
reflect terms of the settlement of our Virginia rate proceeding. See Note P to
CONSOLIDATED FINANCIAL STATEMENTS.
TAXES OTHER THAN INCOME increased in 1998 as compared to 1997 due to
increased taxes associated with our wholesale power and natural gas marketing
activities.
INCOME TAXES in 1998 decreased as compared to 1997 primarily due to the
income tax provision associated with the effects of the settlement of our
Virginia rate proceeding. See Note P to CONSOLIDATED FINANCIAL STATEMENTS.
1997 COMPARED TO 1996
ELECTRIC SERVICE REVENUES grew marginally in 1997 as compared to 1996. The
primary factors affecting this revenue in 1997 were customer growth, weather,
and fuel rates.
Customer growth -- There were more than 50,000 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.
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.
OTHER REVENUE includes sales of electricity beyond our service territory,
natural gas, nuclear consulting services and energy management services. The
increase in revenue in 1997 compared to 1996 is primarily due to marketing of
electricity beyond our service territory.
15
FUEL, NET increased in 1997 as compared to 1996, primarily due to the cost
of the increased purchases of energy from other wholesale power suppliers
associated with power marketing. Effective September 1997, these purchases are
being reported in Other revenue with the related sales revenue. Prior to
September 1997, this activity was subject to cost of service rate regulation.
OPERATIONS AND MAINTENANCE increased in 1997 as compared to 1996 as a
result of costs associated with the growth in sales of energy management
services. These higher costs were offset partially by a reduction in expenses
attributable to the Company's strategic initiatives. See Note O to CONSOLIDATED
FINANCIAL STATEMENTS. Expenses in 1996 include high storm damage costs
resulting from destructive summer storms, including Hurricane Fran.
RESTRUCTURING EXPENSES decreased in 1997 as compared to 1996 due to lower
expenses from the Company's strategic initiatives in anticipation of industry
restructuring. 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. See Note O to CONSOLIDATED FINANCIAL STATEMENTS.
DEPRECIATION AND AMORTIZATION increased in 1997 as compared to 1996 due to
the recognition of additional depreciation and nuclear decommissioning expense
to reflect adjustments in the rate proceeding then pending before the Virginia
Commission and higher depreciation expense related to Clover Unit 2, which
began operations in March 1996.
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, including Virginia, have enacted legislation
requiring the introduction of retail competition.
Today, Virginia Power faces competition in the wholesale market. There is
no general retail competition in Virginia Power's principal service area at
this time. However, during its 1998 session, the Virginia legislature passed a
law that requires a transition to retail competition between January 1, 2002
and January 1, 2004. The legislation established the principle that just and
reasonable net stranded costs would be recoverable, but it left the details as
to how that would be accomplished to future enabling legislation.
At the time of this report, the General Assembly of Virginia is in session
and is considering proposed legislation that would establish a detailed plan to
restructure the electric utility industry in Virginia. We are actively
supporting restructuring legislation, which would provide the necessary details
to implement the legislation passed in 1998. See COMPETITION -- RETAIL AND
COMPETITION -- LEGISLATIVE INITIATIVES below.
In addition to our legislative activity, we have responded to the trend
toward competition by renegotiating long-term contracts with wholesale and
large federal government customers. We have 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 1999 revenue by approximately $45 million as
compared to the amounts that would have been billed prior to such measures.
We have also responded to the trend toward competition by cutting costs,
re-engineering our core business processes, and pursuing innovative approaches
to serving traditional markets and future markets. Our strategy also includes
the development of non-traditional products and services with an objective of
providing growth in future earnings. These products and services include
electric energy and capacity in the emerging wholesale market; natural gas and
other energy-related products and services; nuclear management and consulting
services; power distribution and transmission related services, including
engineering and metering; and telecommunication services. In addition, we may
from time to time, identify and investigate opportunities to expand our markets
through strategic alliances with partners whose strengths, market position and
strategies complement those of Virginia Power.
16
COMPETITION -- WHOLESALE
On September 11, 1997 FERC authorized us to make wholesale power sales
under our Market Based Sales Tariff, but set a hearing to consider the effect
of transmission constraints on our ability to exercise generation market power
in localized areas within our service territory. In connection with such
proceeding, the participants filed a formal Offer of Settlement that was
accepted by FERC in January 1999. Under the Offer of Settlement, we agreed not
to make wholesale power sales under our Market-Based Sales Tariff to loads
located within our service territory. This settlement did not preclude us from
requesting FERC authorization of such sales in the future, but until such
authorization has been granted by FERC, any agreements which allow us to sell
wholesale power to loads located within our service territory are to be at
cost-based rates accepted by FERC.
During 1998, sales to wholesale customers under requirements contracts
represented approximately 4 percent of our total revenues from electric sales.
Since FERC issued its Order 888 requiring open access to transmission service,
we have faced increased competitive pressures on sales to wholesale customers
served under requirements contracts. In response, we have renegotiated
long-term contracts with wholesale customers. We have implemented a new
arrangement with our largest wholesale customer that provides for a transition
from cost-based rates to market-based rates. The reduced rates, offset in part
by other revenues which may be earned under the agreement, are expected to
decrease net income by approximately $21 million during the period 1999 through
2005.
As a result of the increased competitive pressures on sales to wholesale
customers, we are reevaluating the recoverability of regulatory assets
previously assigned to our wholesale customers from such customers or by
reallocation to our retail customers. Based on the principles included in the
settlement of our Virginia rate proceedings in 1998 and the restructuring
legislation now before the Virginia General Assembly, recovery of these costs
from our Virginia retail customers would be unlikely. Furthermore, although
future federal legislation may ultimately address the restructuring of the
electric utility industry, we do not believe it would provide for the recovery
of regulatory assets from our wholesale customers. See COMPETITION -- SFAS 71.
COMPETITION -- RETAIL
Currently, we have the exclusive right to provide electricity at retail
within our assigned service territories in Virginia and North Carolina. As a
result, our company now faces competition for retail sales only 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, the 1998 Virginia General Assembly passed House Bill No. 1172
(HB1172) which established the principles and a schedule for Virginia's
transition to retail competition in the electric utility industry. The new law,
which became effective on July 1, 1998, 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 full
retail competition to be completed 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.
This legislation established a timeline for deregulation of retail
electric service but left the details regarding implementation to future
enabling legislation. Such legislation is now under consideration by the
Virginia General Assembly. See COMPETITION -- LEGISLATIVE INITIATIVES below.
North Carolina is also considering implementing retail competition.
COMPETITION -- LEGISLATIVE INITIATIVES
Virginia: We actively supported HB1172 during the 1998 General Assembly
session and currently support comprehensive restructuring legislation being
considered by the 1999 General Assembly. A special joint legislative
subcommittee, which has been proactively examining electric industry
restructuring for the past three years, has drafted and presented a bill to the
17
Senate for consideration during the 1999 session of the General Assembly. The
major elements of the bill, which is supported by a broad coalition of consumer
groups and utilities, include:
o phase-in of retail customer choice beginning in 2002 with full retail
customer choice by 2004; the schedule is to be determined by the Virginia
Commission, which has the authority to accelerate or delay implementation
under certain conditions; however, the phase-in of retail customer choice
may not be delayed beyond January 1, 2005;
o no mandatory divestiture of generating assets;
o deregulation of generation in 2002;
o capped base rates from January 1, 2001 to July 1, 2007;
o recovery of net stranded costs through capped base rates or a wires
charge paid by those customers opting, while capped rates are in effect,
to purchase energy from a competitive supplier;
o consumer protection safeguards;
o establishment of default service beginning January 1, 2004; and
o creation of a Legislative Transition Task Force to oversee the
implementation of the statute.
Under this proposed legislation, the Company's base rates would remain
unchanged until July 2007. If this legislation is enacted, the generation
portion of our Virginia jurisdictional operations would no longer be subject to
cost-based rate regulation beginning in 2002, although recovery of
generation-related costs would continue to be provided through the capped rates
until July 2007.
The Senate approved this legislation in Senate Bill No. 1269 on February
9, 1999 (the Senate Bill). Whether all of the provisions of the Senate Bill
will ultimately be included in enacted legislation is uncertain. We believe
passage of Virginia restructuring legislation is likely in 1999 but cannot
predict what provisions would be included, if restructuring legislation is
ultimately enacted. See COMPETITION -- EXPOSURE TO POTENTIALLY STRANDED COSTS
and COMPETITION -- SFAS 71.
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.
The North Carolina Commission received and published comments from interested
parties in May 1998. An interim report was expected in 1998 but has not yet
been issued.
COMPETITION -- REGULATORY INITIATIVES
The Virginia Commission has been actively interested in industry
restructuring and competition, as illustrated by its establishment of several
generic and utility-specific restructuring related proceedings since 1995.
On March 20, 1998, the Virginia Commission issued an Order regarding the
establishment of ISOs, RPXs and retail access pilot programs. In direct
response to that Order, we filed a report on November 2, 1998, describing the
details, objectives and characteristics of our proposed retail access pilot
program. We are also complying with the Order by filing reports on a regular
basis on activities concerning our efforts to establish an ISO and RPX.
Our proposed retail access pilot program envisions retail customer choice
being available to 24,000 customers, or about 1% of our retail load under the
jurisdiction of the Virginia Commission. The Virginia Commission created a
generic proceeding to address issues common to both electric and gas retail
access pilot programs throughout the Commonwealth of Virginia. On December 3,
1998, the Virginia Commission issued an Order setting our retail access pilot
program proposal for hearing on June 29, 1999, to consider the remaining issues
and details. It is anticipated that the regulatory proceedings will take much
of 1999 to complete and delivery of competitively procured electricity under
our pilot program will not occur until mid-2000.
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 impact of
transitioning from a regulated to a competitive environment is "stranded
costs." Stranded costs are those costs incurred or commitments made
18
by utilities under cost-based regulation that may not be reasonably expected to
be recovered in a competitive market. If no recovery mechanism is provided
during the transition, the financial position of a utility could be materially
adversely affected.
The Company's exposure to stranded costs is comprised of the following:
o long-term purchased power contracts that may be above market (see
PURCHASED POWER CONTRACTS, 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 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 CONSOLIDATED FINANCIAL STATEMENTS).
As previously discussed under COMPETITION -- LEGISLATIVE INITIATIVES, any
recovery of potentially stranded costs from Virginia retail customers under the
Senate Bill would occur during the rate freeze period. See COMPETITION -- SFAS
71 below. If such legislation is enacted, the extent of our recovery for these
costs would depend on many factors, including, but not limited to, weather,
sales and load growth, future power station performance and unanticipated
expenses (e.g., equipment failures and storm damage).
COMPETITION -- SFAS 71
Virginia Power's financial statements reflect assets and costs under
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. Regulatory assets
represent probable future revenue associated with certain costs that will be
recovered from customers through the ratemaking process. 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 would
not be recoverable. Thus, events or changes in circumstances that cause the
discontinuance of SFAS 71, and write-off of regulatory assets, would 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. See Note D to CONSOLIDATED FINANCIAL
STATEMENTS. This would result in a loss being charged to earnings, unless
recovery of the loss is provided through operations that remain regulated. It
would also be appropriate to review long-term purchase commitments for
potential impairment in accordance with SFAS 5, ACCOUNTING FOR CONTINGENCIES.
See PURCHASED POWER CONTRACTS, Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
At December 31, 1998, our regulated operations satisfied SFAS 71
requirements for continued recognition of regulatory assets. However, if the
Senate Bill is enacted, the generation portion of our Virginia jurisdictional
operations would no longer be subject to cost-based regulation beginning in
2002, although recovery of generation-related costs would continue to be
provided through the capped rates until July 2007. When enacted legislation
provides sufficient details about the transition to deregulation of generation,
we would discontinue the application of SFAS 71 for the generation portion of
our Virginia jurisdictional operations and determine the amount of regulatory
assets to be written off.
In order to measure the amount of regulatory assets to be written off, we
must evaluate to what extent recovery of regulatory assets would be provided
through cost-based rates. We would not be required to write off regulatory
assets for which recovery would be provided by either cost-based rates or a
separate, stranded cost recovery mechanism. Emerging Issues Task Force Issue
No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the
Application of FASB Statements No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN
TYPES OF REGULATION, and No. 101, REGULATED ENTERPRISES -- ACCOUNTING FOR THE
DISCONTINUANCE OF APPLICATION OF FASB STATEMENT NO. 71" (EITF 97-4), provides
guidance about writing off regulatory assets when SFAS 71 is discontinued for
only a portion of a utility's operations. However, until the final provisions
of the Virginia legislation are known, we believe the measurement of regulatory
assets to be written off under SFAS
19
71 and EITF 97-4 is uncertain. If a write-off of regulatory assets is required,
such write-off could materially affect Virginia Power's financial position and
results of operations. See Note F to CONSOLIDATED FINANCIAL STATEMENTS. At the
time of this report, we believe passage of Virginia restructuring legislation
is likely in 1999 but cannot predict what provisions would be included, if
restructuring legislation is ultimately enacted.
We believe the stable rates that would be provided until July 2007 by the
Senate Bill, coupled with the opportunity to pursue further reductions in our
operating costs, would present a reasonable opportunity to recover a
substantial portion of our potentially stranded costs. However, as discussed
above, if the application of SFAS 71 is discontinued for any part of utility
operations, we would also perform an impairment evaluation with respect to
property, plant and equipment as well as long-term power purchase commitments.
The impairment assessment may be required on a disaggregated basis rather than
as an aggregate portfolio. Thus, the recognition of impairments, if any, could
potentially not be mitigated by other assets or contracts with estimated values
in excess of respective carrying amounts or contract payments. If our
evaluation concludes that an impairment exists, an additional loss would be
charged to earnings. Because the impairment evaluation has not been completed,
we cannot estimate the amount of loss, if any, that would be recognized.
However, such amount could materially affect the Company's financial position
and results of operations.
ENVIRONMENTAL MATTERS
Virginia Power 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. These costs have been historically recovered from
customers through utility rates. However, see COMPETITION -- LEGISLATIVE
INITIATIVES for a discussion of legislation that, if enacted, would provide a
transition from cost based to competitive pricing in Virginia.
ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
We incurred $71.9 million, $70.4 million, and $71.1 million (including
depreciation) during 1998, 1997 and 1996, respectively, in connection with the
use of environmental protection facilities, and we expect these expenses to be
$71.1 million in 1999. In addition, capital expenditures to limit or monitor
hazardous substances were $22.2 million, $24.6 million and $22.4 million for
1998, 1997 and 1996, respectively. The amount estimated for 1999 for these
expenditures is $106.9 million.
CLEAN AIR ACT COMPLIANCE
The Clean Air Act, as amended in 1990, requires the Company to reduce its
emissions of SO2 and NOx which are gaseous by-products of fossil fuel
combustion.The Clean Air Act also requires us to obtain operating permits for
all major emissions-emitting facilities. Permit applications have been
submitted for the Company's power stations.
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 EPA administers the program. Our compliance plans are reviewed
periodically and may include switching to lower sulfur coal, purchase of
emission allowances and installation of SO2 control equipment. In December 1998
we initiated a capital project to install SO2 control equipment on two units at
our Mt. Storm power station at an estimated cost of $115 million.
We began complying with Clean Air Act Phase I NOx limits at eight of our
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.
However, in September 1998, the EPA adopted a rule which requires 22
states, including Virginia, North Carolina, and West Virginia, to reduce and
cap NOx emissions beginning in 2003. The rule allows each state to determine
how to achieve the required reduction in emissions. By September 1999, each
affected state must develop and submit a plan to the EPA that details how the
state will achieve its emission cap. If states adopt the approach suggested by
the EPA, it is probable we will incur major capital expenditures, in the range
of $500 million. These expenditures would satisfy the Clean Air Act Phase II
standards for NOx, thereby eliminating the need under existing law to make
additional investment beginning in 2008. We will closely monitor the
development of NOx emission cap plans by the various states.
Evaluation and planning on future projects to comply with SO2 and NOx
reduction requirements are ongoing and will be influenced by changes in the
regulatory environment, availability of SO2 allowances and emission control
technology.
20
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 has
been signed by the United States but 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.
NRC NUCLEAR DECOMMISSIONING RULE
Effective November 23, 1998, the NRC amended its nuclear decommissioning
financial assurance requirements. In particular, the NRC limited the use of the
sinking fund method to only that portion of a licensee's collections for
decommissioning that is recovered through either traditional cost of service
rate regulation or through non-bypassable charges. The majority of our
decommissioning collections are currently recovered through cost of service
rate regulation. However, a portion of our decommissioning collections are
recovered through contracted rates, and we have established a parent company
guarantee to satisfy the NRC's revised requirements. Furthermore, we will be
evaluating the implications on our method of satisfying the NRC financial
assurance requirements that may result from enactment of the legislation
currently before the Virginia General Assembly. See COMPETITION -- LEGISLATIVE
INITIATIVES.
RECENTLY ISSUED ACCOUNTING STANDARDS
In June 1998, the FASB issued SFAS No. 133, ACCOUNTING FOR DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES. The statement requires that derivative
instruments (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at fair value. The statement requires that changes in a derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement and requires that a company formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for the Company beginning in 2000; however, it
may be adopted earlier. It cannot be applied retroactively to financial
statements of prior periods.
We have not yet quantified the impacts of adopting SFAS No. 133 and have
not yet determined the timing of, or method of, adoption. Since the impact is a
function of market prices and other measures of fair value, any quantification
would be subject to change. The adoption of the statement could increase
volatility in earnings and other comprehensive income.
In November 1998, the Emerging Issues Task Force reached consensus on
Issue No. 98-10, ACCOUNTING FOR CONTRACTS INVOLVED IN ENERGY TRADING AND RISK
MANAGEMENT ACTIVITIES (EITF Issue 98-10). We must adopt EITF Issue 98-10 in
1999. EITF Issue 98-10 requires energy trading contracts to be recorded at fair
value on the balance sheet with the changes in fair value included in earnings.
The effects of the initial application of EITF Issue 98-10 will be reported as
a cumulative effect of a change in accounting principle.
We manage a portfolio of energy contracts which are currently recorded at
fair value on the balance sheet with the changes in fair value included in
earnings as required by EITF Issue 98-10. However, we have not yet completed
our review of other energy-related contracts held by the Company that could
possibly be subject to EITF Issue 98-10. Thus, we have not yet quantified the
impact of adoption.
YEAR 2000 COMPLIANCE
We are preparing our computer systems and computer-driven equipment and
devices for the year 2000. Virtually every computer operation could be affected
in some way by the rollover of the two-digit year value from 99 to 00. Systems
or devices that use computer chips that do not properly recognize
date-sensitive information when the year changes to 2000 could generate
erroneous data or fail.
If not properly addressed, the year 2000 problem could result in computer
and other equipment failures both within Virginia Power and at third parties
with which we transact business. Because of the extensive use of technology
throughout our business and the businesses of our suppliers and customers,
failures in any of these areas could impact our business.
21
Our objective is to be year 2000 ready. "Year 2000 ready" means that
critical systems, devices, applications and business relationships have been
evaluated and are expected to be suitable for continued use into and beyond the
year 2000.
We have organized formal year 2000 project teams to identify, correct or
reprogram and test our systems for year 2000 readiness. These teams are
addressing all critical aspects of our business, including information systems,
embedded systems and external relationships with business partners. Information
systems encompass traditional information technology systems such as financial
reporting, accounting and purchasing systems. Embedded systems primarily
represent specialized computers used to control, monitor or assist the
operations of equipment. External relationships include suppliers and other
service providers. The teams are overseen by an executive who reports regularly
to the Board of Directors.
Our year 2000 remediation program involves completing four major phases:
(1) inventorying of computer systems and embedded systems that could
potentially be affected by the year 2000 problem; (2) screening to determine
date sensitivity within the inventoried systems; (3) impact assessment; and (4)
remediation and testing. We have completed the first three phases.
Approximately 93% of our systems identified as critical to Company operations
were year 2000 ready at December 31, 1998. We anticipate that 99% of such
systems will be year 2000 ready in July 1999 with 100% completion prior to
January 1, 2000.
In addition to these internal efforts, we are assessing the state of
readiness of our major suppliers and service providers. We have implemented
initiatives to prevent the future procurement of non-year 2000 compliant
technology. We are also meeting with the non-utility power producers who supply
us energy under power purchase contracts to share information about year 2000
readiness.
We expect year 2000 costs to be within the range of $30 million to $40
million, which is a change from our original estimate of $40 million to $50
million. This downward revision is due in part to completion of the assessment
phase, progress made on the remediation and testing phase, and an increase in
information from critical suppliers and other significant external sources.
Actual year 2000 costs as of December 31, 1998 are $10.8 million. The
effort to date has been primarily focused on critical systems and the remaining
expenditures are for critical and non-critical year 2000 preparedness. Some
expenditure for non-critical systems will be incurred in the year 2000.
Maintenance and 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. These costs do not include capital expenditures for major
information systems that were initiated for normal business reasons without
regard to year 2000 issues.
Congress has directed the Department of Energy (DOE) to ascertain the
readiness of all electric utilities for year 2000. DOE has in turn asked the
North American Electric Reliability Council (NERC) to coordinate and monitor
year 2000 activities in the electric industry. NERC is comprised of ten
regional councils whose members represent the major bulk power suppliers of the
electric industry. We are actively participating with other NERC members,
including our local regional council, the Southeastern Electric Reliability
Council (SERC). Of primary importance is the reliability of the transmission
network for delivery of energy to customers. This reliability is achieved by
participation of many utilities in the supply to, and control of, their
individually owned portions of the network. The failure of an individual
utility to manage successfully its transmission network could affect this
reliability which could have a material adverse effect on the Company.
Our contingency planning efforts to ensure continuity of operations into
and beyond the year 2000 are on schedule to be completed by June 30, 1999. The
Company and the U.S. electric utility industry already have extensive
contingency plans in place for many events such as extreme heat, storms and
equipment failures. Our Year 2000 contingency planning is an extension of these
existing plans. We are coordinating our efforts with SERC and NERC, and will
participate in the nationwide drills planned by NERC for April 9, 1999 and
September 9, 1999. As part of this process, we must consider and evaluate
reasonably likely worst case scenarios and their impact on critical business
processes.
Based on our preliminary evaluations, which include SERC and NERC efforts
to date, reasonably likely worst case scenarios could include:
o minor variations in voltage or frequency with no significant effect on
electric service;
o temporary loss of a portion of generation capacity, including possibly
non-utility generators; however, such loss is not expected to be
sufficient to adversely affect electric service;
o temporary loss of some telecommunications functionality and other
services with no impact expected on electric service; and
22
o temporary loss of a small portion of commercial and industrial customer
loads.
We cannot estimate or predict the potential adverse consequences, if any,
that could result from a third party's failure to effectively address the year
2000 issue but we believe that any impact would be short-term in nature and
would not have a material adverse impact on our business or results of
operations. The objective of the contingency planning process is to mitigate
internal and external risks and assure a continuous and sustained delivery of
electricity to all customers. Based on Company and industry analyses to date,
we do not believe the reasonably likely worst case scenarios identified above,
if they were to occur, would have a material adverse effect on our business or
results of operations. We plan to have all contingency plans identified and
tested prior to year-end 1999.
The descriptions herein of the elements of our year 2000 effort are
forward-looking statements. Of necessity, this effort is based on estimates of
assessment, remediation, testing and contingency planning activities and
perceived problems not yet identified. There can be no assurance that actual
results will not differ materially from expectations.
ITEM 7A. MARKET RISK 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 our outstanding debt, preferred stock and
trust-issued securities. We are also exposed to interest rate risk as well as
equity price risk as a result of our nuclear decommissioning trust investments
in debt and equity securities.
COMMODITY PRICE RISK
As part of our strategy to market energy from our generation capacity and
to manage related risks, we manage a portfolio of derivative commodity
contracts held for trading purposes. These contracts are sensitive to changes
in the prices of natural gas and electricity. We employ established policies
and procedures to manage the risks associated with these price fluctuations and
use various commodity instruments, such as futures, swaps and options, to
reduce risk by creating offsetting market positions. In addition, we seek to
use our generation capacity, when not needed to serve customers in our service
territory, to satisfy commitments to sell energy.
One of the techniques commonly used to measure risk in a commodity trading
portfolio is sensitivity analysis, which determines a hypothetical change in
the fair value of the portfolio which would result from an assumed change in
the market prices of the related commodities. The fair value of the portfolio
is a function of the underlying commodity, contract prices and market prices
represented by each derivative commodity contract. For exchange-for-physical
contracts, basis swaps, fixed price forward contracts and options which require
physical delivery of the underlying commodity, market value reflects our best
estimates considering over-the-counter quotations, time value and volatility
factors of the underlying commitments. Exchange-traded futures and options are
marked to market based on closing exchange prices.
We have determined a hypothetical loss by calculating a hypothetical fair
value for each contract assuming a 10% unfavorable change in the market prices
of the related commodity and comparing it to the fair value of the contracts
based on market prices at December 31, 1998 and 1997. This hypothetical 10%
change in commodity prices would have resulted in a hypothetical loss of
approximately $13.5 million and $2.5 million in the fair value of our commodity
contracts as of December 31, 1998 and 1997, respectively. The commodity
contracts' sensitivity to unfavorable price changes increased in 1998 as
compared to 1997 primarily due to the increased volume of contracts and
associated commodities.
The sensitivity analysis does not include the price risks associated with
utility operations, including those underlying utility fuel requirements. In
the normal course of business, we also face risks that are either nonfinancial
or nonquantifiable. Such risks principally include credit risk, which is not
reflected in the sensitivity analysis above.
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, 1998 and
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, 1998 and 1997.
23
EXPECTED MATURITY DATE
-------------------------------------------------------------------
1999 2000 2001 2002 2003 THEREAFTER
---------- ---------- ---------- ---------- ---------- ------------
(MILLIONS OF DOLLARS, EXCEPT PERCENTAGES)
ASSETS
Nuclear decommissioning trust
investments .................... $ 4.0 $ 15.4 $ 6.2 $ 6.5 $ 7.9 $ 190.8
Average interest rate (1) ...... 4.9% 4.9% 4.9% 4.9% 4.9% 4.9%
LIABILITIES -- Fixed rate
Mortgage bonds .................. 100.0 135.0 100.0 255.0 200.0 1,809.5
Average interest rate .......... 8.9% 5.9% 6.0% 6.8% 6.6% 7.6%
Medium-term notes and Sr.
unsecured notes ................ 221.0 60.5 60.7 60.0 40.5 269.9
Average interest rate .......... 8.5% 9.7% 8.3% 7.6% 9.0% 6.5%
Tax-exempt financing ............ 10.0
Average interest rate .......... 5.2%
Short-term debt ................. 221.7
Average interest rate .......... 5.4%
Preferred stock, subject to
mandatory redemption ........... 180.0
Average dividend rate .......... 6.2%
Mandatorily redeemable
trust-issued preferred
securities ..................... 135.0
Average dividend rate .......... 8.1%
LIABILITIES -- Variable rate
Tax-exempt financing (2) ........ 488.6
Average interest rate .......... 3.1%
Unrecognized financial
instruments:
Forward treasury lock
agreements (3) .................
AT DECEMBER 31,
-------------------------------------------------
1998 1997
------------------------ ------------------------
FAIR FAIR
TOTAL VALUE TOTAL VALUE
------------ ----------- ------------ -----------
(MILLIONS OF DOLLARS, EXCEPT PERCENTAGES)
ASSETS
Nuclear decommissioning trust
investments .................... $ 230.8 $ 221.4 $ 200.3 $ 190.7
Average interest rate (1) ...... 4.9% 5.5%
LIABILITIES -- Fixed rate
Mortgage bonds .................. 2,599.5 2,780.6 2,824.5 2,937.7
Average interest rate .......... 7.4% 7.4%
Medium-term notes and Sr.
unsecured notes ................ 712.6 736.6 551.1 573.7
Average interest rate .......... 7.8% 8.4%
Tax-exempt financing ............ 10.0 10.4 10.0 10.4
Average interest rate .......... 5.2% 5.2%
Short-term debt ................. 221.7 221.7 226.2 226.2
Average interest rate .......... 5.4% 5.9%
Preferred stock, subject to
mandatory redemption ........... 180.0 186.2 180.0 186.6
Average dividend rate .......... 6.2% 6.2%
Mandatorily redeemable
trust-issued preferred
securities ..................... 135.0 138.0 135.0 137.7
Average dividend rate .......... 8.1% 8.1%
LIABILITIES -- Variable rate
Tax-exempt financing (2) ........ 488.6 488.6 488.6 488.6
Average interest rate .......... 3.1% 4.1%
Unrecognized financial
instruments:
Forward treasury lock
agreements (3) ................. 1.5
- ---------
(1) Rates are based on average yield for entire portfolio at December 31, 1998
and 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. We
have the option to convert these bonds to fixed rate securities upon 40
days written notice. See Note H to CONSOLIDATED FINANCIAL STATEMENTS.
(3) Notional amount of contracts is $150 million. On February 5, 1999 these
contracts were closed resulting in a gain of $5.6 million.
EQUITY PRICE RISK
The following table presents a description of marketable equity securities
held by the Company at December 31, 1998 and 1997. In accordance with SFAS 115,
ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES, these
securities are reported on the balance sheet at fair value. See Future Issues
- -- NRC NUCLEAR DECOMMISSIONING RULE.
AT DECEMBER 31,
-----------------------------------------------------
1998 1997
------------------------- -------------------------
FAIR FAIR
COST VALUE COST VALUE
----------- ----------- ----------- -----------
(MILLIONS OF DOLLARS)
Nuclear decommissioning trust investments ......... $ 252.4 $ 470.3 $ 219.4 $ 360.4
24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
PAGE
NO.
-----
Report of Management ......................................................... 26
Report of Independent Auditors ............................................... 27
Consolidated Statements of Income for the years ended
December 31, 1998, 1997 and 1996 ............................................ 28
Consolidated Balance Sheets at December 31, 1998 and 1997 .................... 29
Consolidated Statements of Earnings Reinvested in Business for the years ended
December 31, 1998, 1997 and 1996 ............................................ 31
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996 ............................................ 32
Notes to Consolidated Financial Statements ................................... 33
25
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 1998 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
/s/ Norman Askew /s/ J.A. Shaw /s/ M.S. Bolton, Jr.
President and Senior Vice President, Vice President, Controller
Chief Executive Chief Financial and Principal Accounting
Officer Officer and Treasurer Officer
26
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, 1998 and 1997, 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, 1998.
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,
1998 and 1997, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
Richmond, Virginia
February 8, 1999
27
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------------------------
1998 1997 1996
------------- ------------- -------------
(MILLIONS)
Revenue:
Electric service .................................................. $ 4,012.7 $ 4,229.9 $ 4,202.3
Other ............................................................. 271.9 434.0 179.7
---------- ---------- ----------
Total ........................................................... 4,284.6 4,663.9 4,382.0
---------- ---------- ----------
Expenses:
Fuel, net ......................................................... 953.5 1,204.2 979.3
Purchased power capacity, net ..................................... 806.0 717.5 700.6
Impairment of regulatory assets ................................... 158.6 38.4 26.7
Operations and maintenance ........................................ 854.3 818.7 811.7
Restructuring ..................................................... 18.4 64.9
Depreciation and amortization ..................................... 502.5 549.9 502.0
Amortization of terminated construction project costs ............. 33.9 34.4 34.4
Taxes other than income ........................................... 290.0 267.7 262.6
---------- ---------- ----------
Total ........................................................... 3,598.8 3,649.2 3,382.2
---------- ---------- ----------
Income from operations ............................................. 685.8 1,014.7 999.8
Other income ....................................................... 18.0 18.8 17.0
---------- ---------- ----------
Income before interest and income taxes ............................ 703.8 1,033.5 1,016.8
---------- ---------- ----------
Interest and related charges:
Interest expense .................................................. 305.7 304.2 308.4
Distributions -- preferred securities of subsidiary trust ......... 10.9 10.9 10.9
---------- ---------- ----------
Total ........................................................... 316.6 315.1 319.3
---------- ---------- ----------
Income before income taxes ......................................... 387.2 718.4 697.5
Income taxes ....................................................... 157.3 249.3 240.2
---------- ---------- ----------
Net income ......................................................... 229.9 469.1 457.3
Preferred dividends ................................................ 35.8 35.7 35.5
---------- ---------- ----------
Balance available for Common Stock ................................. $ 194.1 $ 433.4 $ 421.8
========== ========== ==========
The Company had no other comprehensive income reportable in accordance with
SFAS 130, REPORTING COMPREHENSIVE INCOME.
The accompanying notes are an integral part of the financial statements.
28
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
AT DECEMBER 31,
-----------------------------
1998 1997
------------- -------------
(MILLIONS OF DOLLARS)
CURRENT ASSETS:
Cash and cash equivalents ......................................................... $ 49.6 $ 36.0
Accounts receivable:
Customers (less allowance for doubtful accounts of $5.4 in 1998 and $2.4 in 1997) 777.8 742.2
Other ........................................................................... 76.2 70.5
Materials and supplies at average cost or less:
Plant and general ............................................................... 142.0 145.2
Fossil fuel ..................................................................... 95.0 67.4
Commodity contract assets ......................................................... 179.8 40.6
Other ............................................................................. 149.9 134.7
---------- ----------
Total current assets ........................................................... 1,470.3 1,236.6
---------- ----------
INVESTMENTS:
Nuclear decommissioning trust funds ............................................... 705.1 569.1
Other ............................................................................. 45.6 15.5
---------- ----------
Total net investments ........................................................... 750.7 584.6
---------- ----------
DEFERRED DEBITS AND OTHER ASSETS:
Regulatory assets ................................................................. 620.0 757.4
Unamortized debt issuance costs ................................................... 28.5 24.2
Commodity contract assets ......................................................... 17.5 .3
Other ............................................................................. 16.0 50.2
---------- ----------
Total deferred debits and other assets .......................................... 682.0 832.1
---------- ----------
PROPERTY, PLANT AND EQUIPMENT:
Plant (includes $449.3 plant under construction in 1998 and $240.9 in 1997) ....... 15,207.6 14,866.4
Less accumulated depreciation ..................................................... 6,278.8 5,743.9
---------- ----------
8,928.8 9,122.5
Nuclear fuel, net ................................................................. 153.1 149.3
---------- ----------
Net property, plant and equipment ............................................... 9,081.9 9,271.8
---------- ----------
Total assets .................................................................... $ 11,984.9 $ 11,925.1
========== ==========
The accompanying notes are an integral part of the financial statements.
29
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
AT DECEMBER 31,
---------------------------
1998 1997
------------ ------------
(MILLIONS OF DOLLARS)
CURRENT LIABILITIES:
Securities due within one year ............................................... $ 321.0 $ 333.5
Short-term debt .............................................................. 221.7 226.2
Accounts payable, trade ...................................................... 566.5 474.9
Customer deposits ............................................................ 45.9 44.6
Payrolls accrued ............................................................. 79.0 77.5
Interest accrued ............................................................. 93.8 95.1
Taxes accrued ................................................................ 48.1 30.5
Commodity contract liabilities ............................................... 265.8 52.9
Other ........................................................................ 132.8 95.6
---------- ----------
Total current liabilities .................................................. 1,774.6 1,430.8
---------- ----------
LONG-TERM DEBT ................................................................ 3,464.7 3,514.6
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accumulated deferred income taxes ............................................ 1,563.6 1,607.0
Deferred investment tax credits .............................................. 221.4 238.4
Commodity contract liabilities ............................................... 11.4 1.9
Other ........................................................................ 192.5 192.3
---------- ----------
Total deferred credits and other liabilities ............................... 1,988.9 2,039.6
---------- ----------
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, 1998 and 1997 ................................................. 2,737.4 2,737.4
Other paid-in capital ........................................................ 16.9 16.9
Earnings reinvested in business .............................................. 1,178.4 1,361.8
---------- ----------
Total common stockholder's equity .......................................... 3,932.7 4,116.1
---------- ----------
Total liabilities and shareholders' equity ................................. $ 11,984.9 $ 11,925.1
========== ==========
(*) As described in Note I to CONSOLIDATED FINANCIAL STATEMENTS, the 8.05%
Junior Subordinated Notes totaling $139.2 million principal amount
constitute 100% of the Trust's assets.
The accompanying notes are an integral part of the financial statements.
30
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS REINVESTED IN BUSINESS
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
------------- ------------- -------------
(MILLIONS)
Balance at beginning of year ................................. $ 1,361.8 $ 1,308.4 $ 1,272.5
Net income ................................................... 229.9 469.1 457.3
---------- ---------- ----------
Total ....................................................... 1,591.7 1,777.5 1,729.8
---------- ---------- ----------
Cash dividends:
Preferred stock subject to mandatory redemption ............. 11.1 11.1 11.1
Preferred stock not subject to mandatory redemption ......... 24.5 24.7 24.5
Common Stock ................................................ 377.7 379.9 385.8
---------- ---------- ----------
Total dividends ........................................... 413.3 415.7 421.4
---------- ---------- ----------
Balance at end of year ....................................... $ 1,178.4 $ 1,361.8 $ 1,308.4
========== ========== ==========
The accompanying notes are an integral part of the financial statements.
31
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
(MILLIONS)
Cash Flow From (Used in) Operating Activities:
Net income ...................................................... $ 229.9 $ 469.1 $ 457.3
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization ................................. 613.5 664.7 616.0
Deferred income taxes ......................................... ( 5.4) 36.1 69.1
Deferred investment tax credits ............................... ( 16.9) ( 16.9) ( 16.9)
Deferred fuel expenses, net ................................... ( 34.4) 9.6 ( 54.4)
Deferred capacity expenses .................................... ( 16.2) ( 41.2) ( 9.2)
Restructuring ................................................. 12.5 29.6
Impairment of regulatory assets ............................... 158.6 38.4 26.7
Changes in:
Accounts receivable .......................................... ( 41.3) ( 200.1) 6.3
Materials and supplies ....................................... ( 24.4) 12.9 6.0
Accounts payable, trade ...................................... 91.6 82.8 57.8
Accrued expenses ............................................. 17.8 ( 13.9) ( 62.6)
Commodity contract assets and liabilities .................... 66.0 13.9
Other ......................................................... 55.3 22.9 ( 10.4)
--------- --------- ---------
Net Cash Flow From Operating Activities ......................... 1,094.1 1,090.8 1,115.3
Cash Flow From (Used in) Financing Activities:
Issuance of long-term debt .................................... 270.0 270.0 24.5
Issuance (repayment) of short-term debt ....................... ( 4.5) ( 86.2) 143.4
Repayment of long-term debt ................................... ( 333.5) ( 311.3) ( 284.1)
Common Stock dividend payments ................................ ( 377.7) ( 379.9) ( 385.8)
Preferred stock dividend payments ............................. ( 35.6) ( 35.8) ( 35.6)
Distribution-preferred securities of subsidiary trust ......... ( 10.9) ( 10.9) ( 10.9)
Other ......................................................... ( 6.4) ( 2.5) ( 2.3)
--------- --------- ---------
Net Cash Flow Used in Financing Activities ...................... ( 498.6) ( 556.6) ( 550.8)
--------- --------- ---------
Cash Flow Used in Investing Activities:
Plant and equipment expenditures (excluding
AFC -- other funds) .......................................... ( 450.8) ( 397.0) ( 393.8)
Nuclear fuel (excluding AFC -- other funds) ................... ( 80.9) ( 84.8) ( 90.2)
Nuclear decommissioning contributions ......................... ( 37.5) ( 36.2) ( 36.2)
Purchase of assets ............................................ ( 19.8) ( 13.7)
Other ......................................................... ( 12.7) ( 8.3) ( 12.5)
--------- --------- ---------
Net Cash Flow Used in Investing Activities ...................... ( 581.9) ( 546.1) ( 546.4)
--------- --------- ---------
Increase (decrease) in cash and cash equivalents ................ 13.6 ( 11.9) 18.1
Cash and cash equivalents at beginning of year .................. 36.0 47.9 29.8
--------- --------- ---------
Cash and cash equivalents at end of year ........................ $ 49.6 $ 36.0 $ 47.9
========= ========= =========
Cash paid during the year for:
Interest (reduced for the cost of borrowed funds
capitalized as AFC) .......................................... $ 309.3 $ 277.1 $ 295.4
Income taxes .................................................. 183.9 230.0 216.1
The accompanying notes are an integral part of the financial statements.
32
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 engages in off-system wholesale purchases and sales
of electricity and purchases and sales of natural gas, and is developing
trading relationships beyond the geographic limits of its 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 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 and include amounts yet to be billed to
customers. Revenues from trading activities include realized commodity contract
revenues, net of related cost of sales, amortization of option premiums and
unrealized gains and losses resulting from marking to market those commodity
contracts not yet settled.
FUEL, NET
Fuel, net includes the cost of fossil fuel, nuclear fuel and purchased
energy used to serve electric sales. It also includes the cost of purchased
energy associated with power marketing sales subject to cost of service rate
regulation.
Approximately 90% of the Company's rate regulated fuel costs are subject
to deferral accounting. Deferral accounting provides that the difference
between reasonably incurred actual expenses and the level of expenses included
in current rates is deferred and matched against future revenues. Fuel, net
includes the effect of this deferral accounting and may therefore show expenses
that are marginally higher or lower than the actual cost of fuel consumed
during the period.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment 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 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 1998, 1997 and 1996.
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.
33
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.
REGULATORY ASSETS
The Company's financial statements reflect assets and costs 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. Regulatory assets represent probable future revenue
associated with certain costs that will be recovered from customers through the
ratemaking process. See Note F and UTILITY RATE REGULATION, Note Q to
CONSOLIDATED FINANCIAL STATEMENTS for information on the Company's regulatory
assets and the potential impact of legislation on continued application of SFAS
71.
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.
AFC rates for 1998, 1997 and 1996 were 6.7 percent, 6.6 percent and 8.1
percent, respectively. No AFC is accrued for approximately 87 percent of the
Company's construction work in progress, which is instead included in rate
base. A cash return is collected on the portion of construction work in
progress included in rate base.
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, 1998 and 1997, the
Company's accounts payable included the net effect of checks outstanding but
not yet presented for payment of $48.6 million and $55.8 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
As part of Virginia Power's strategy to market energy from its generation
capacity and to manage the risks related thereto, the Company enters into
contracts for the purchase and sale of energy commodities. 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 and exchange-traded futures and options.
Options, exchange-for-physical contracts, basis swaps and futures 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. Exchange-traded futures
and options are marked to market based on closing exchange prices. No commodity
contracts were designated as hedges during 1998 and 1997.
Commodity contracts representing unrealized gain positions are reported as
Commodity contract assets; commodity contracts representing unrealized losses
are reported as Commodity contract liabilities. In addition, purchased options
and options sold are reported as Commodity contract assets and Commodity
contract liabilities, respectively, at estimated market value until exercise or
expiration. Realized commodity contract revenues, net of related cost of sales,
settlement of
34
futures contracts, amortization of option premiums and unrealized gains and
losses resulting from marking positions to market are included in Other
revenue. Cash flows from trading activities are reported in Net Cash Flow from
Operating Activities.
RECLASSIFICATION
Certain amounts in the 1997 and 1996 financial statements have been
reclassified to conform to the 1998 presentation. In addition, in the fourth
quarter of 1998, the Company changed the way it reports energy commodity
contracts. Thus, the reclassifications include netting the cost of commodities
purchased for trading purposes, not subject to cost of service rate regulation,
against commodity trading revenue in Other revenue. The gross amount of revenue
and expense generated from these contracts had previously been reported in
Other revenue and Fuel, net, respectively, within the Statements of Income.
B. INCOME TAXES:
Details of income tax expense are as follows:
YEARS
------------------------------------------
1998 1997 1996
------------ ------------ ------------
(MILLIONS)
Current expense:
Federal ................................................. $ 166.9 $ 222.1 $ 185.6
State ................................................... 12.7 8.6 2.4
--------- --------- ---------
179.6 230.7 188.0
Deferred expense:
Plant and equipment differences ......................... 28.6 41.3 65.4
Deferred fuel and capacity .............................. ( 4.5) 11.0 22.3
Debt issuance costs ..................................... ( 18.6) ( 2.1) ( 2.8)
Terminated construction project costs ................... ( 7.2) ( 5.8) ( 5.1)
Other ................................................... ( 3.7) ( 8.9) ( 10.7)
--------- --------- ---------
( 5.4) 35.5 69.1
--------- --------- ---------
Net deferred investment tax credits-amortization ......... ( 16.9) ( 16.9) ( 16.9)
--------- --------- ---------
Total income tax expense ................................. $ 157.3 $ 249.3 $ 240.2
========= ========= =========
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
------------------------------------------
1998 1997 1996
------------ ------------ ------------
(MILLIONS)
Federal income tax expense at statutory rate of 35 percent ......... $ 135.5 $ 251.4 $ 244.1
-------- -------- --------
Increases (decreases) resulting from:
Plant and equipment differences ................................... 25.9 7.7 5.7
Ratable amortization of investment tax credits .................... ( 16.9) ( 16.9) ( 16.9)
Terminated construction project costs ............................. 4.9 5.0 5.0
State income tax, net of federal tax benefit ...................... 6.8 4.9 2.4
Other, net ........................................................ 1.1 ( 2.8) ( 0.1)
--------- --------- ---------
21.8 ( 2.1) ( 3.9)
--------- --------- ---------
Total income tax expense ........................................... $ 157.3 $ 249.3 $ 240.2
========= ========= =========
Effective tax rate ................................................. 40.6% 34.7% 34.4%
35
The Company's net accumulated deferred income taxes consist of the following:
YEARS
-------------------------
1998 1997
----------- -----------
(MILLIONS)
Deferred income tax assets:
Investment tax credits ................................ $ 78.3 $ 84.4
--------- ---------
Deferred income tax liabilities:
Plant and equipment differences ....................... 1,475.0 1,479.8
Income taxes recoverable through future rates ......... 155.1 169.5
Other ................................................. 11.8 42.1
--------- ---------
Total deferred income tax liabilities ................. 1,641.9 1,691.4
--------- ---------
Total net accumulated deferred income taxes ........... $ 1,563.6 $ 1,607.0
========= =========
C. NUCLEAR OPERATIONS:
DECOMMISSIONING
When the Company's nuclear units cease operations, the Company is
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, amounts
are currently being collected from ratepayers that, when combined with
investment earnings, will be used to fund this future obligation. These dollars
are deposited into external trusts through which the funds are invested.
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 $36.2 million per year for the
period 1996 through 1998. However, an additional $9.6 million was expensed in
1997 based on an expected increase in the decommissioning collections for 1997
as provided in the Company's rate case then pending before the Virginia
Commission. Since the Virginia rate case settlement did not include such an
increase, the 1998 expense provision was decreased by $9.6 million. Therefore,
the expense levels were $26.6 million, $45.8 million and $36.2 million in 1998,
1997 and 1996, respectively.
Net earnings of the trusts' investments are included in Other Income in
the Company's Consolidated Statements of Income. In 1998, 1997 and 1996, net
earnings were $17.5 million, $20.5 million and $16.0 million, respectively. The
accretion of the decommissioning obligation is equal to the trusts' net
earnings and is also recorded in Other Income.
The accumulated provision for decommissioning, which is included in
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, 1998, the net unrealized
gains were $230.5 million, which is an increase of $81.0 over the December 31,
1997, amount of $149.5 million. The accumulated provision for decommissioning
at December 31, 1998 and 1997, was $703.9 million and $578.7 million,
respectively.
The total estimated cost to decommission the Company's four nuclear units
is $1.6 billion based upon a site-specific study that was completed 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 (1998 dollars) ........... $ 410.6 $ 413.1 $ 400.5 $ 388.0 $ 1,612.2
Funds in external trusts at 12/31/98 ........... 194.1 189.1 165.5 156.4 705.1
1998 contributions to external trusts* ......... 10.6 10.8 7.6 7.2 36.2
- ---------
* Excludes an additional $1.3 million deposited into the trusts prior to the
settlement of the Virginia rate case, which will be considered as a partial
prepayment for calendar year 1999 contributions.
36
The Financial Accounting Standards Board (FASB) is reviewing the
accounting for nuclear plant decommissioning. In 1996, 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, the annual provisions for nuclear
decommissioning would also increase. During its deliberations, FASB expanded
the scope of the project to include similar unavoidable obligations to perform
closure and post-closure activities for other long-lived assets, including
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 $9.7 billion for a single nuclear incident. The
Price-Anderson Act Amendment 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 $90.7 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.
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 are 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
Electric Insurance Limited (NEIL), a mutual insurance company, and is subject
to retrospective premium assessments in any policy year in which losses exceed
the funds available to the insurance company. The maximum assessment for the
current policy period is $28.8 million. Based on the severity of the incident,
the board of directors of the Company's nuclear insurer has the discretion to
lower or eliminate the maximum retrospective premium assessment. 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 $6.8
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. PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, other than nuclear fuel, consists of the
following:
AT DECEMBER 31,
-----------------------------
1998 1997
------------- -------------
(MILLIONS)
Production ............................ $ 7,714.2 $ 7,684.2
Transmission .......................... 1,421.4 1,415.7
Distribution .......................... 4,682.3 4,559.2
Other ................................. 940.4 966.4
---------- ----------
14,758.3 14,625.5
Construction work in progress ......... 449.3 240.9
---------- ----------
Total ................................ $ 15,207.6 $ 14,866.4
========== ==========
37
E. JOINTLY OWNED PLANTS:
The following information relates to the Company's proportionate share of
jointly owned plants at December 31, 1998:
NORTH
BATH COUNTY ANNA CLOVER
PUMPED STORAGE POWER POWER
STATION STATION STATION
---------------- -------------- ----------
Ownership interest ............................... 60.0% 88.4% 50.0%
(MILLIONS)
Plant in service ................................. $ 1,073.1 $ 1,809.9 $ 535.6
Accumulated depreciation ......................... 249.4 852.1 39.6
Nuclear fuel ..................................... 402.7
Accumulated amortization of nuclear fuel ......... 334.4
Construction work in progress .................... .3 72.1 2.3
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
The Company's regulatory assets include the following:
AT DECEMBER 31,
-------------------------
1998 1997
----------- -----------
(MILLIONS)
Income taxes recoverable through future rates ..................... $ 438.8 $ 478.9
Cost of decommissioning DOE uranium enrichment facilities ......... 61.8 67.6
Deferred losses on reacquired debt, net ........................... 31.2 85.4
Nuclear design basis documentation cost ........................... 20.9 45.9
North Anna Unit 3 project termination costs ....................... 9.8 42.3
Other ............................................................. 57.5 102.4
Reserve for impairment of regulatory assets ....................... ( 65.1)
--------
Total ............................................................. $ 620.0 $ 757.4
======== ========
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. Such amounts are net of related regulatory liabilities and
$109 million associated with deferred income taxes which were established at
rates in excess of the current Federal rate and are subject to Internal Revenue
Code normalization requirements.
The cost of decommissioning the Department of Energy's (DOE) uranium
enrichment facilities represents 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 currently 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 cost of preparing detailed design documentation of the Company's
nuclear power stations required by the Nuclear Regulatory Commission has been
deferred and is currently being recovered through rates over the life of the
respective power stations.
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
recovery of these costs will be completed in 1999.
38
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. The Company does
not earn a return on $15.4 million of regulatory assets, effectively excluded
from rate base, to be recovered over various recovery periods up to 20 years,
depending on the nature of the deferred costs.
For information about the impairment of regulatory assets resulting from
the settlement of the Company's Virginia rate proceedings and the potential
impact on regulatory assets if certain legislation currently being considered
by the Virginia General Assembly is enacted, see Note P and UTILITY RATE
REGULATION, Note Q to CONSOLIDATED FINANCIAL STATEMENTS.
G. LEASES:
Property, plant and equipment under capital leases includes the following:
AT DECEMBER 31,
-------------------------
1998 1997
----------- -----------
(MILLIONS)
Office buildings(*) .................................... $ 34.4 $ 34.4
Data processing equipment .............................. 28.6 13.3
-------- --------
Total plant and property under capital leases ......... 63.0 47.7
Less accumulated amortization .......................... 27.7 17.8
-------- --------
Net plant and property under capital leases ............ $ 35.3 $ 29.9
======== ========
- ---------
(*) 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 $20 million and $22 million at
December 31, 1998 and 1997, respectively. The rental payment for this
lease was $3 million for each of the three years ended December 31, 1998,
1997 and 1996.
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, 1998, are as follows:
CAPITAL OPERATING
LEASES LEASES
----------- ----------
(MILLIONS)
1999 ................................................... $ 10.0 $ 24.5
2000 ................................................... 7.4 26.0
2001 ................................................... 3.9 10.0
2002 ................................................... 3.2 7.5
2003 ................................................... 2.9 6.3
After 2003 ............................................. 13.7 22.9
-------- -------
Total future minimum lease payments .................... $ 41.1 $ 97.2
======== =======
Less interest element included above ................... 5.8
--------
Present value of future minimum lease payments ......... $ 35.3
========
Rents on leases, which have been charged to operations expense, were $17.7
million, $17.6 million and $16.5 million for 1998, 1997 and 1996, respectively.
39
H. LONG-TERM DEBT:
Long-term debt includes the following:
AT DECEMBER 31,
---------------------------
1998 1997
------------ ------------
(MILLIONS)
First and Refunding Mortgage Bonds (1):
1988 Series A, 9.375%, due 1998 .............................. $ 150.0
1992 Series F, 6.25%, due 1998 ............................... 75.0
1989 Series B, 8.875%, due 1999 .............................. $ 100.0 100.0
1993 Series C, 5.875%, due 2000 .............................. 135.0 135.0
1993 Series E, 6.000%, due 2001 .............................. 100.0 100.0
1992 Series E, 7.375%, due 2002 .............................. 155.0 155.0
1993 Series F, 6.000%, due 2002 .............................. 100.0 100.0
Various series, 6.625%-8%, due 2003-2007 ..................... 865.0 865.0
Various series, 5.45%-8.75%, due 2021-2025 ................... 1,144.5 1,144.5
--------- ---------
Total First and Refunding Mortgage Bonds .................. 2,599.5 2,824.5
--------- ---------
Other long-term debt:
Term notes:
Fixed interest rate, 5.73%-10.00%, due 1998-2008 ........... 562.6 551.1
1998 Series A, Senior Notes, 7.15%, due 2038 ............... 150.0
Tax exempt financings (2):
Money Market Municipal Securities due 2007-2027(3) ......... 488.6 488.6
Convertible interest rate bonds due 2022 ................... 10.0 10.0
--------- ---------
Total other long-term debt ................................ 1,211.2 1,049.7
--------- ---------
3,810.7 3,874.2
--------- ---------
Less amounts due within one year:
First and Refunding Mortgage Bonds ........................... 100.0 225.0
Term notes ................................................... 221.0 108.5
--------- ---------
Total amount due within one year .......................... 321.0 333.5
--------- ---------
Less unamortized discount, net of premium ..................... 25.0 26.1
--------- ---------
Total long-term debt ...................................... $ 3,464.7 $ 3,514.6
========= =========
- ---------
(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 1998
and 1997, the weighted average daily interest rates were 3.49 percent and
3.74 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): 1999 -- $321.0; 2000 -- $195.5; 2001 -- $160.7; 2002 -- $315.0; and
2003 -- $240.5.
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. 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
40
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, 1998:
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 the years 1996 through
1998.
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, 1998.
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 1998, 1997 and 1996, including fees for broker/dealer
agreements, were 4.60 percent, 4.71 percent, and 4.48 percent,
respectively.
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, 1998.
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 expires in June 2001. The other is a $200
million credit facility that originated in June 1996 and is subject to annual
renewal.
41
The total amount of commercial paper outstanding as of December 31, 1998,
was $221.7 million with a weighted average interest rate of 5.38 percent. This
represents a decrease of $4.5 million from the December 31, 1997, balance of
$226.2 million and a weighted average interest rate of 5.88 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 $20.5 million, $20.6 million and
$24.8 million for 1998, 1997 and 1996, respectively, and the amounts funded by
the Company were $20.5 million. $27.0 million and $28.4 million in 1998, 1997
and 1996, respectively.
OTHER POSTRETIREMENT BENEFITS
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees. Health care
benefits are provided to retirees who complete at least 10 years of service
after attaining age 45. These and similar benefits for active employees are
provided through insurance companies.
Net periodic postretirement benefit expense was as follows:
YEAR ENDED
DECEMBER 31,
------------------------------------
1998 1997 1996
---------- ---------- ----------
(MILLIONS)
Service cost ......................................... $ 11.9 $ 12.3 $ 12.1
Interest cost ........................................ 24.0 25.1 23.9
Expected return on plan assets ....................... (16.3) (11.9) ( 9.5)
Amortization of transition obligation ................ 12.1 12.1 12.1
Amortization of unrecognized net loss/(gain) ......... ( 1.2)
-------
Net periodic postretirement benefit cost ............. $ 30.5 $ 37.6 $ 38.6
======= ======= =======
42
The following table sets forth the funded status of the plan:
YEAR ENDED DECEMBER 31,
-------------------------
1998 1997
----------- -----------
(MILLIONS)
Change in plan assets:
Fair value of plan assets at beginning of year ........... $ 176.6 $ 133.0
Actual return on plan assets ............................. 24.0 25.3
Contributions ............................................ 11.2 18.3
Benefits paid from plan assets ...........................
Fair value of plan assets at end of year ................. 211.8 176.6
Change in benefit obligation:
Expected benefit obligation at beginning of year ......... 360.8 324.0
Expected actuarial gain during prior year ................ ( 41.9) ( 1.3)
-------- --------
Actual benefit obligation at beginning of year ........... 318.9 322.7
Service cost ............................................. 11.9 12.3
Interest cost ............................................ 24.0 25.1
Benefits paid from general funds ......................... ( 15.8) ( 15.8)
Actuarial loss during the year ........................... 32.6 16.5
-------- --------
Expected benefit obligation at end of year ............... 371.6 360.8
-------- --------
Reconciliation of funded status:
Funded status ............................................ (159.8) (184.2)
Unrecognized net actuarial gain .......................... ( 17.6) ( 1.8)
Unamortized prior service cost ...........................
Unrecognized net transition obligation ................... 168.7 180.8
-------- --------
Accrued benefit cost ..................................... $ (8.7) $ (5.2)
======== ========
Significant assumptions used in determining postretirement benefit
obligations were:
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997
---------- ----------
Discount rate ........................................... 7.00% 7.75%
Expected return on plan assets .......................... 9.00% 9.00%
Rate of increase for participants' compensation ......... 5.00% 5.00%
Medical cost trend rate:
First year ............................................. 5.00% 6.00%
Second year ............................................ 4.75% 5.00%
Years thereafter beginning 2000 ........................ 4.75% 4.75%
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects:
ONE PERCENTAGE ONE PERCENTAGE
POINT INCREASE POINT DECREASE
---------------- ---------------
(MILLIONS)
Effect on total of service and interest cost components for 1998 ......... $ 5.2 $ (3.2)
Effect on postretirement benefit obligation at December 31, 1998 ......... 41.5 (33.4)
The Company is recovering these costs in rates on an accrual basis in all
material respects, in all jurisdictions. However, see UTILITY RATE REGULATION,
Note Q to CONSOLIDATED FINANCIAL STATEMENTS for a discussion of legislation
that, if enacted, would provide the necessary details about the restructuring
of the electric utility industry in Virginia. The funds collected for other
postretirement benefits in rates, in excess of benefits actually paid during
the year, are contributed to external benefit trusts under the Company's
current funding policy.
43
O. RESTRUCTURING:
The Company announced a program in anticipation of industry restructuring
in March 1995. This program has resulted in outsourcing, decentralization,
reorganization and downsizing for portions of the Company's operations.
Restructuring charges of $18.4 million and $64.9 million were recorded in
1997 and 1996, respectively. These charges included severance costs, purchased
power contract restructuring and negotiated settlement costs and other costs.
The Company established a comprehensive involuntary severance package for
salaried employees who may no longer be employed as a result of these
initiatives. The package provides for severance to be paid over a period of
twenty months or less. The cost associated with employee terminations is being
recognized in accordance with Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)", as management identifies the positions to be eliminated. The
recognition of severance costs resulted in charges to operations of $1.8
million, $12.5 million and $49.2 million in 1998, 1997 and 1996, respectively.
At December 31, 1998, management had identified 1,932 positions to be
eliminated, of which 1,810 employees had been terminated and severance payments
totaling $89 million had been paid. The 1998 severance costs were charged to
operations and maintenance expense.
P. VIRGINIA RATE SETTLEMENT:
In 1998 Virginia Power, the Staff of the Virginia Commission, the office
of the Virginia Attorney General, the Virginia Committee for Fair Utility Rates
and the Apartment and Office Building Association of Metropolitan Washington
joined in a proposed agreement to settle the Company's outstanding base rate
proceedings. The Virginia Commission approved the settlement by Order dated
August 7, 1998.
The settlement defines a new regulatory framework for the Company's
transition to electric competition. The major provisions of the settlement are
as follows:
o A two-phased base rate reduction: $100 million per annum beginning March
1, 1998 with one additional $50 million per annum reduction beginning
March 1, 1999;
o A base rate freeze through February 28, 2002 unless a change is necessary
to protect the legitimate interests of the Company, its shareholders or
ratepayers;
o An immediate, one-time refund of $150 million for the period March 1,
1997 through February 28, 1998;
o A discontinuation of deferral accounting for purchased power capacity
expenses effective February 28, 1998;
o A write-off of a minimum of $220 million of regulatory assets in addition
to normal amortization thereof during the base rate freeze period;
o An incentive mechanism until March 1, 2002 for earnings above the
following return on equity (ROE) benchmarks: 1998 -- 10.5%; after 1998 --
30-year Treasury bond rates plus 450 basis points. For rate incentive
mechanism purposes, all earnings up to the ROE benchmark would benefit the
Company's shareholder. Any earnings above the benchmark would be allocated
one-third to the Company's shareholder and two-thirds to the $220 million
write-off of regulatory assets; except that all earnings above the ROE
benchmark plus 270 basis points (initially 13.2%), would be allocated to
the write-off of regulatory assets.
Due to the required write-off of a minimum of $220 million of regulatory
assets in addition to normal amortization thereof during the rate freeze
period, the Company evaluated its regulatory assets for potential impairment
under SFAS 71. Based on the uncertainty of the Company's earnings potential
during the rate freeze period, management could no longer conclude that
recovery of the $220 million is probable, i.e., that earnings above its
authorized rate of return would be available to offset the $220 million
write-off of regulatory assets. The Company had previously identified
reductions in operating costs of $38.4 million in 1997 and $26.7 million in
1996, which were used to establish a reserve for potential impairment of
regulatory assets. Accordingly, the Company charged $158.6 million to second
quarter 1998 earnings, which when combined with the reserve for accelerated
cost recovery accrued in 1996 and 1997, provides for the impairment of
regulatory assets resulting from the settlement.
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
44
amounts. Except as described below under UTILITY RATE REGULATION, management
believes that the final disposition of these proceedings will not have a
material adverse effect on the operations or the financial position, liquidity
or results of operations of the Company.
UTILITY RATE REGULATION
The current session of the General Assembly of Virginia is scheduled to
end in late February 1999. The legislators are considering proposed legislation
that would establish a detailed plan to restructure the electric utility
industry in Virginia. The Senate approved restructuring legislation in Senate
Bill No. 1269 on February 9, 1999 (the Senate Bill). If enacted, it would
provide the necessary details to implement legislation passed in 1998 which
established a timeline for the transition to retail competition in Virginia.
Virginia Power is actively supporting the Senate Bill. Whether all of the
provisions of the Senate Bill will ultimately be included in enacted
legislation is uncertain. Virginia Power currently believes passage of Virginia
restructuring legislation is likely in 1999 but cannot predict what provisions
would be included, if restructuring legislation is ultimately enacted. Under
the Senate Bill, the Company's base rates would remain unchanged until July
2007.
If the Senate Bill is enacted, the generation portion of the Company's
Virginia jurisdictional operations would no longer be subject to cost-based
regulation beginning in 2002, although recovery of generation-related costs
would continue to be provided through the capped rates until July 2007. When
enacted legislation provides sufficient details about the transition to
deregulation of generation, the Company would discontinue the application of
SFAS 71 for the generation portion of its Virginia jurisdictional operations
and determine the amount of regulatory assets to be written off.
In order to measure the amount of regulatory assets to be written off,
Virginia Power must evaluate to what extent recovery of regulatory assets would
be provided through cost-based rates. Virginia Power would not be required to
write off regulatory assets for which recovery would be provided by either
cost-based rates or a separate, stranded cost recovery mechanism. Emerging
Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity
- -- Issues Related to the Application of FASB Statements No. 71, ACCOUNTING FOR
THE EFFECTS OF CERTAIN TYPES OF REGULATION, and No. 101, REGULATED ENTERPRISES
- -- ACCOUNTING FOR THE DISCONTINUANCE OF APPLICATION OF FASB STATEMENT NO. 71"
(EITF 97-4), provides guidance about writing off regulatory assets when SFAS 71
is discontinued for only a portion of a utility's operations. However, until
the final provisions of the Virginia legislation are known, Virginia Power
believes the measurement of regulatory assets to be written off under SFAS 71
and EITF 97-4 is uncertain. If a write-off of regulatory assets is required,
such write-off could materially affect Virginia Power's financial position and
results of operations. See Note F to CONSOLIDATED FINANCIAL STATEMENTS.
Management believes stable rates that would be provided until July 2007 by
the Senate Bill, coupled with the opportunity to pursue further reductions in
the Company's operating costs, would present a reasonable opportunity to
recover a substantial portion of the Company's potentially stranded costs.
However, as discussed above, if the application of SFAS 71 is discontinued for
any part of utility operations, Virginia Power would perform an impairment
evaluation with respect to property, plant and equipment as well as long-term
power purchase commitments. See Note D and PURCHASED POWER CONTRACTS, Note Q to
CONSOLIDATED FINANCIAL STATEMENTS. The impairment assessment may be required on
a disaggregated basis rather than as an aggregate portfolio. Thus, the
recognition of impairments, if any, could potentially not be mitigated by other
assets or contracts with estimated values in excess of respective carrying
amounts or contract payments. If the Company's evaluation concludes that an
impairment exists, an additional loss would be charged to earnings. Because the
impairment evaluation has not been completed, the Company cannot estimate the
amount of loss, if any, that would be recognized. However, such amount could
materially affect the Company's financial position and results of operations.
RETROSPECTIVE PREMIUM ASSESSMENTS
Under several of the Company's nuclear insurance policies, the Company is
subject to retrospective premium assessments in any policy year in which losses
exceed the funds available to these insurance companies. For additional
information, see Note C.
CONSTRUCTION PROGRAM
The Company has made substantial commitments in connection with its
construction program and nuclear fuel expenditures. Those expenditures are
estimated to total $802.5 million (excluding AFC) for 1999. The Company
presently estimates that 1999 construction expenditures, including nuclear
fuel, will be met through cash flow from operations and through a combination
of sales of securities and short-term borrowing.
45
PURCHASED POWER CONTRACTS
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 55 non-utility purchase contracts with a
combined dependable summer capacity of 3,285 MW.
The table below reflects the Company's minimum commitments as of December
31, 1998, for power purchases from utility and non-utility suppliers.
COMMITMENT
---------------------------
YEAR CAPACITY OTHER
- ------------------------------------ ------------- -----------
(MILLIONS)
1999 ............................... $ 836.7 $ 133.1
2000 ............................... 760.1 47.9
2001 ............................... 757.5 37.2
2002 ............................... 757.7 32.8
2003 ............................... 717.2 34.3
Later years ........................ 8,573.6 301.0
---------- --------
Total ............................. $ 12,402.8 $ 586.3
========== ========
Present value of the total ......... $ 5,389.7 $ 269.2
========== ========
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. Purchased power expenditures, subject to cost of service rate
regulation, (including economy, emergency, limited term, short-term and
long-term purchases) for the years 1998, 1997 and 1996 were $1,137 million,
$1,381 million and $1,183 million, respectively.
FUEL PURCHASE COMMITMENTS
The Company's estimated fuel purchase commitments for the next five years
for system generation are as follows (millions): 1999 -- $328; 2000 -- $248;
2001 -- $205; 2002 -- $115; and 2003 -- $118.
SALES 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 3,000 MW to 15,000 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, see
UTILITY RATE REGULATION above for a discussion of legislation that, if enacted,
would restructure the electric utility industry in Virginia. If material costs
are incurred and not recovered through rates, the Company's results of
operations and financial position 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 $61.8 million to $69.5 million. The Company's proportionate
share of the cost is expected to be in the range of $1.6 million to $2.2
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 has had remedial action responsibilities remaining at several
coal tar sites. At December 31, the Company had expended $2 million on site
studies and investigation and remedial efforts at these sites. No material
expenditures
46
remain to be incurred by the Company. In addition, a civil suit, seeking
compensatory damages of $2 million and punitive damages of $1 million, was
filed against Virginia Power by a property owner who alleged that property was
contaminated by toxic pollutants originating from one of the coal tar sites.
This matter has been resolved through settlement by the parties.
The Company generally seeks to recover its costs associated with
environmental remediation from third party insurers. At December 31, 1998, any
pending or possible claims were not recognized as an asset or offset against
such 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.
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1998 1997
----------------------- -----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------- ---------- ---------- ----------
(MILLIONS)
Assets:
Cash and cash equivalents ............................... $ 49.6 $ 49.6 $ 36.0 $ 36.0
Nuclear decommissioning trust funds ..................... 705.1 705.1 569.1 569.1
Liabilities and capitalization:
Short-term debt ......................................... 221.7 221.7 226.2 226.2
Long-term debt:
First and Refunding Mortgage Bonds .................... 2,599.5 2,780.6 2,824.5 2,937.7
Medium-term Notes and Senior Unsecured Notes .......... 712.6 736.6 551.1 573.7
Money Market Municipal tax-exempt securities .......... 488.6 488.6 488.6 488.6
Convertible interest rate tax-exempt bonds ............ 10.0 10.4 10.0 10.4
Preferred stock subject to mandatory redemption ......... 180.0 186.2 180.0 186.6
Preferred securities of subsidiary trust ................ 135.0 138.0 135.0 137.7
Unrecognized financial instruments:
Forward treasury lock contracts ......................... 1.5
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.
Forward treasury lock contracts: Fair value is based on the difference
between the yield at December 31, 1998 on the current 30-year treasury note and
such rates specified in the contracts. On February 5, 1999, these contracts
were closed, resulting in a gain of $5.6 million.
47
S. BUSINESS SEGMENTS:
Effective December 31, 1998, Virginia Power implemented SFAS 131,
DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION. Virginia
Power's principal business segment is the regulated public utility business
serving Virginia and northeastern North Carolina and is reported as Utility
Operations. The All Other category includes the Company's wholesale power
group's trading and marketing activities, its telecommunications subsidiary,
its nuclear consulting services subsidiary and its energy services activities.
Management's review of the Company's operations focuses on earnings before
interest and income taxes. The Company purchases and sells power in regions
outside of its traditional service territory, including marketing available
generating capacity not required to serve native load customers. It also
markets natural gas. Revenues from wholesale power trading activities include
realized commodity contract revenues, net of related cost of sales, settlement
of futures contracts, amortization of option premiums and unrealized gains and
losses resulting from marking to market those commodity contracts not yet
settled.
UTILITY CONSOLIDATED
DESCRIPTION OPERATIONS ALL OTHER TOTAL
- -------------------------------------------- ------------- ----------- -------------
1998
Revenues ................................... $ 3,994.8 $ 289.8 $ 4,284.6
Depreciation and amortization .............. 535.6 .8 536.4
Earnings before interest and taxes ......... 735.1 ( 31.3) 703.8
Total assets ............................... 11,174.3 810.6 11,984.9
Capital expenditures ....................... 512.9 18.8 531.7
1997
Revenues ................................... $ 4,246.3 $ 417.6 $ 4,663.9
Depreciation and amortization .............. 583.8 .5 584.3
Earnings before interest and taxes ......... 1,054.3 ( 20.8) 1,033.5
Total assets ............................... 11,661.1 264.0 11,925.1
Capital expenditures ....................... 475.3 6.5 481.8
1996
Revenues ................................... $ 4,208.1 $ 173.9 $ 4,382.0
Depreciation and amortization .............. 533.0 3.4 536.4
Earnings before interest and taxes ......... 1,031.3 ( 14.5) 1,016.8
T. 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
management for a fair statement of the results for the interim periods.
INCOME/(LOSS) FROM NET BALANCE AVAILABLE
QUARTER REVENUES OPERATIONS INCOME (LOSS) FOR COMMON STOCK
- ------------- -------------- -------------------- --------------- ------------------
(MILLIONS)
1998
- ----
1st ......... $ 1,050.8 $ 233.6 $ 98.6 $ 89.9
2nd ......... 905.9 ( 90.1) ( 120.1) ( 129.0)
3rd ......... 1,352.7 398.9 205.9 197.0
4th ......... 975.2 143.4 45.5 36.2
1997
- ----
1st ......... $ 1,127.0 $ 248.4 $ 110.3 $ 101.5
2nd ......... 1,032.0 182.2 72.3 63.3
3rd ......... 1,444.1 383.5 201.1 192.1
4th ......... 1,060.8 200.6 85.4 76.5
Results for interim periods may fluctuate as a result of weather
conditions, changes in rates and other factors.
Certain accruals recorded in 1998 and 1997 were not ordinary, recurring
adjustments. These adjustments included (1) the impact resulting from the 1998
settlement of the Company's Virginia rate proceeding and (2) 1997 restructuring
costs.
48
RATE REFUND -- The Company recognized a $153.7 million provision for rate
refund and related interest expense of $10.7 million and other taxes of $3.9
million in the second quarter of 1998 as a result of the settlement of the
Company's rate proceeding in Virginia. See Note P to CONSOLIDATED FINANCIAL
STATEMENTS.
IMPAIRMENT OF REGULATORY ASSETS -- The Company charged $158.6 million to
second quarter 1998 earnings to provide for the impairment of regulatory assets
resulting from the settlement of the Company's rate proceeding in Virginia. The
Company accrued $2.8 million, $28.3 million and $7.3 million during the second,
third and fourth quarters of 1997, respectively, to provide for impairment of
regulatory assets. 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. See
Note O to CONSOLIDATED FINANCIAL STATEMENTS.
DEPRECIATION AND AMORTIZATION -- The Company recorded adjustments of $27.6
million in the second quarter of 1998 decreasing the year-to-date provision for
depreciation and decommissioning expenses to reflect terms of the Company's
settlement of its Virginia rate proceedings. See Note P to CONSOLIDATED
FINANCIAL STATEMENTS.
Charges for the rate refund and the impairment of regulatory assets,
offset by the adjustments to depreciation and decommissioning expenses, reduced
Balance Available for Common Stock by $201.0 million in the second quarter of
1998. Charges to provide for impairment of regulatory assets and for
restructuring expenses reduced Balance Available for Common Stock by $5.9
million, $19.3 million, and $11.7 million in the second, third, and fourth
quarters of 1997, respectively.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
NONE
49
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Information concerning directors of Virginia Electric and Power Company
is as follows:
YEAR FIRST
PRINCIPAL OCCUPATION FOR LAST 5 YEARS, ELECTED A TERM
NAME AND AGE DIRECTORSHIPS IN PUBLIC CORPORATIONS DIRECTOR EXPIRES
- ------------------------------- ---------------------------------------------------------------- ----------- --------
Thos. E. Capps (63) Chairman of the Board of Directors of Virginia Electric and 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
(prior to September 1, 1995, Chairman and Chief
Executive Officer). He is a Director of Bassett Furniture
Industries, Inc.
Norman Askew (56) President and Chief Executive Officer of Virginia Electric 1997 2001
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 prior
to February 21, 1997. He is Chairman of the Board of
Directors of Henlys Group plc., London, England.
John B. Adams, Jr. (54) President and Chief Executive Officer of Bowman 1987 2001
Companies, a manufacturer and bottler of alcohol
beverages, Fredericksburg, Virginia. He is a Director of
Pluma, Inc. and Dominion Resources.
John B. Bernhardt (69) Managing Director, Bernhardt/Gibson Financial 1986 2000
Opportunities, financial services, Newport News, Virginia.
He is a Director of Resource Bank Shares Corporation
and Dominion Resources.
James F. Betts (66) 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 (54) President and owner of Century 21 Clary and Associates, 1996 2000
Inc., South Hill, Virginia. She is a Director of Sherwood
Brands, LLC.
John W. Harris (51) President, Lincoln Harris, LLC, a real estate consulting firm, 1997 2001
Charlotte, North Carolina. He is a Director of Piedmont
Natural Gas Company, Inc. and US Airways Group, Inc.
Benjamin J. Lambert, III (62) Optometrist, Richmond, Virginia. He is a Director of 1992 2001
Consolidated Bank and Trust Company, Student Loan
Marketing Association (SallieMae) and Dominion
Resources.
Richard L. Leatherwood (59) Retired, Baltimore, Maryland. Former President and Chief 1994 2001
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. (69) Chairman and Chief Executive Officer of Harvey Lindsay 1986 1999
Commercial Real Estate, LLC, Norfolk, Virginia, a
commercial real estate firm. He is a Director of Dominion
Resources.
Kenneth A. Randall (71) 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.
William T. Roos (70) Retired, Hampton, Virginia (prior to December 31, 1993, 1975 1999
President of Penn Luggage, Inc., retail specialty stores).
He is a Director of Dominion Resources.
Frank S. Royal (59) Physician, Richmond, Virginia. He is a Director of 1997 2001
Columbia/HCA Healthcare Corporation, SunTrust Banks,
Inc., Chesapeake Corporation, CSX Corporation and
Dominion Resources.
50
President of Virginia Union University, Richmond, Virginia.
S. Dallas Simmons (59) He is a Director of Dominion Resources. 1997 2000
Robert H. Spilman (71) President, Spilman Properties, Inc., Bassett, Virginia (prior to 1994 2000
August 1, 1997 Chairman and Chief Executive Officer of
Bassett Furniture Industries, Inc., Bassett, Virginia). He is
a Director of Dominion Resources, Jefferson-Pilot
Corporation, The Pittston Company, and the International
Home Furnishing Center.
William G. Thomas (59) President of Hazel & Thomas, Alexandria, Virginia, a law 1987 1999
firm.
Judith B. Warrick (50) Senior Advisor, Morgan Stanley & Co., Inc., an investment 1997 1999
banking firm, New York, New York, from September 1,
1995 (prior to September 1, 1995, Advisor). She is a
Director of Dominion Resources.
David A. Wollard (61) Chairman of the Board, Exempla Healthcare, Denver, 1997 1999
Colorado January 1, 1996 to date; President, Bank One
Colorado, N.A., Denver, Colorado prior to January 1,
1996.
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 their individual class term expires, or until their successors are 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 (56) 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 prior to February 21, 1997.
Thomas F. Farrell, II (44) Executive Vice President, General Counsel and Corporate Secretary of Virginia
Electric and Power Company from July 1, 1998 to date; Executive Vice President of
Virginia Electric and Power Company and Senior Vice President -- Corporate
Affairs of Dominion Resources, September 1, 1997 to July 1, 1998; Senior Vice
President -- Corporate and 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 (49) 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 (56) Senior Vice President -- Fossil and Hydro, July 1, 1995 to date; Vice President Fossil
and Hydro prior to July 1, 1995.
Larry M. Girvin (55) 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 (55) Senior Vice President -- Nuclear, June 1, 1994 to date.
John A. Shaw (51) Senior Vice President, Chief Financial Officer and Treasurer, July 1, 1998 to date;
Senior Vice President -- Finance, March 16, 1998 to July 1, 1998; Vice President
Financial Services for ARCO Chemical Company, Philadelphia, Pennsylvania, prior
to March 16, 1998. Prior to March 16, 1998 he has also served as Vice
President -- Treasurer and Vice President -- Controller of ARCO Chemical.
51
Eva S. Teig (54) 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.
James A. White (55) Senior Vice President -- Human Resources, July 1, 1998 to date; Senior Vice
President -- Human Resources, Cigna Investment Management, prior to July 1,
1998.
Said Ziai (45) Senior Vice President -- Corporate Strategy, October 1, 1997 to date; Corporate
Planning Director, East Midlands Electricity plc, Nottingham, England, prior to
October 1, 1997.
M. Stuart Bolton, Jr. (45) Vice President and Controller, January 1, 1999 to date; Controller, prior to January 1,
1999.
David A. Christian (44) Vice President -- Nuclear Operations, July 1, 1998 to date; Site Vice
President -- Surry, March 1, 1998 to July 1, 1998; Station Manager -- Surry Power
Station, September 1, 1994 to March 1, 1998; Assistant Station Manager -- Surry,
prior to September 1, 1994.
James T. Earwood, Jr. (55) 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.
Eugene S. Grecheck (45) Site Vice President -- Surry, July 1, 1998 to date; Manager, Station Operation and
Maintenance -- North Anna, March 1, 1998 to July 1, 1998. Assistant Station
Manager -- North Anna, April 1, 1996 to March 1, 1998, Manager Design
Engineering and Support prior to April 1, 1996.
Leslie N. Hartz (41) Vice President -- Nuclear Engineering and Services May 1, 1998 to date; Manager,
Nuclear Engineering prior to May 1, 1998.
E. Paul Hilton (55) 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. (47) 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.
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 prior to May 1, 1996.
Margaret E. McDermid (50) Vice President -- Information Technology and Chief Information Officer, October 1,
1998 to date; Manager, Information Technology prior to October 1, 1998.
Mark F. McGettrick (41) Vice President -- Customer Service and Marketing, 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 (51) Vice President -- Procurement, October 1, 1998 to date and Vice President of
Dominion Resources, February 20, 1997 to date; Vice President -- Information
Technology, January 1, 1996 to October 1, 1998; Vice President and Treasurer,
Dominion Resources prior to October 1, 1998.
Edward J. Rivas (54) 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.
Johnny V. Shenal (53) 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 (49) 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.
52
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Our directors and executive officers report their ownership of and
transactions in 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:
M. Stuart Bolton, Jr., Eugene S. Grecheck, Leslie N. Hartz. The required
filings have now been made.
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 had any reportable transactions in the preferred stock which
have not been timely reported.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The Summary Table below includes compensation paid by the Company for
services rendered in 1998, 1997 and 1996 for the Chief Executive Officer and
the four other most highly compensated executive officers (as of December 31,
1998) as determined under the SEC executive compensation disclosure rules.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION
------------------------------------------------
OTHER ANNUAL
NAME & PRINCIPAL POSITION YEAR SALARY(1) BONUS COMPENSATION(2)
- --------------------------- ------ ----------- ----------- -----------------
Norman Askew 1998 $475,000 $308,223 $ 0
President and CEO 1997 $177,084 $ 85,833 $14,560
James P. O'Hanlon 1998 $334,667 $180,232 $ 0
Senior Vice 1997 $270,250 $110,240 $ 0
President -- Nuclear 1996 $220,815 $128,511 $ 0
Robert E. Rigsby 1998 $279,414 $226,553 $ 0
Executive Vice President 1997 $254,850 $129,920 $ 0
1996 $226,469 $143,892 $ 0
Thomas F. Farrell, II 1998 $236,971 $161,951 $ 0
Executive Vice President,
General Counsel and
Corporate Secretary
Larry M. Girvin 1998 $201,667 $138,104 $ 0
Senior Vice President 1997 $187,050 $ 85,520 $ 0
Commercial Operations 1996 $164,600 $ 89,200 $ 0
LONG TERM
COMPENSATION AWARDS
------------------------
SECURITIES PAYOUTS
RESTRICTED UNDERLYING -----------------------------
STOCK OPTIONS/ LTIP ALL OTHER
NAME & PRINCIPAL POSITION AWARDS(3) SAR GRANTS PAY OUT(4) COMPENSATION(5)
- --------------------------- ------------ ----------- ------------ ----------------
Norman Askew $0 $0 $177,040 $ 0
President and CEO $0 $0 $ 18,791 $120,000
James P. O'Hanlon $0 $0 $ 86,512 $ 4,679
Senior Vice $0 $0 $ 80,140 $ 4,800
President -- Nuclear $0 $0 $ 56,152 $ 4,500
Robert E. Rigsby $0 $0 $133,691 $ 4,769
Executive Vice President $0 $0 $ 83,171 $ 4,800
$0 $0 $ 43,157 $ 4,500
Thomas F. Farrell, II $0 $0 $ 33,444 $ 4,800
Executive Vice President,
General Counsel and
Corporate Secretary
Larry M. Girvin $0 $0 $ 70,687 $ 4,800
Senior Vice President $0 $0 $ 52,935 $ 4,800
Commercial Operations $0 $0 $ 30,717 $ 4,500
- ---------
(1) Amounts shown may include vacation sold back to the Company.
(2) None of the executive officers above received perquisites or other personal
benefits in excess of either $50,000 or 10% of total cash compensation.
(3) During 1998, with the agreement Virginia Power cancelled all shares of
restricted Dominion Resources stock previously issued under existing
incentive plans in order to convert to the new incentive compensation plan
described in footnote 4 below. Consequently, as of December 31, 1998, none
of the executives shown in this table held any restricted stock issued
under Virginia Power compensation programs. Messrs. Askew and Farrell held
restricted stock issued under Dominion Resources programs.
(4) Amounts in this column for 1998 represent payouts under the Incentive
Compensation Plan for the three-year period 1996-1998. These amounts
include both the cash award and the value of the restricted Dominion
Resources shares as of the issue date February 19, 1999 ($42.25 per
share). The performance measure used was economic value added for the same
three-year period. Based on their accomplishment level, each executive
received their award in the form of 50% cash as 50% restricted stock.
Awards were made following goal confirmation by the Organization,
Compensation
53
and Nominating Committee of the Board of Directors. They cannot be sold and
will be forfeited if the executive terminates employment during the
restricted period. Awards were paid as follows:
RESTRICTED
OFFICER STOCK AWARD CASH AWARD
- ----------------------------- ------------- -----------
Norman Askew .............. 1,989 $93,005
James P. O'Hanlon ......... 972 $45,445
Robert E. Rigsby .......... 1,502 $70,231
Thomas F. Farrell, II ..... 376 $17,558
Larry M. Girvin ........... 794 $37,140
(5) For 1998, employer matching contribution on Employee Savings Plan
contributions.
LONG-TERM INCENTIVE COMPENSATION
AWARDS IN THE LAST FISCAL YEAR
1998-2000 LONG-TERM INCENTIVE PLAN
ESTIMATED FUTURE PAYOUTS
UNDER NON-STOCK PRICE
BASED
PERFORMANCE OR PLANS
NUMBER OF OTHER PERIOD -------------------------
SHARES, UNITS UNTIL MATURATION THRESHOLD TARGET
NAME OR OTHER RIGHTS(#) OR PAYOUT ($ OR #) ($ OR #)
- -------------------------- -------------------- ----------------- ----------- -----------
N. Askew ................. $237,500 3 years $118,750 $237,500
J. P. O'Hanlon ........... $207,000 3 years $103,500 $207,000
R. E. Rigsby ............. $296,000 3 years $148,000 $296,000
T. F. Farrell,II ......... $296,000 3 years $148,000 $296,000
L. M. Girvin ............. $157,000 3 years $ 78,500 $157,000
The above table reflects the target awards that will be paid to these
executives for the 1998-2000 performance cycle of the long-term incentive
program if specified goals are achieved. The established goals for executives
consist of two specific financial targets (Operating Profit and Net Cash Flow)
for Virginia Power (50%) and consolidated net income for DRI (50%). Awards will
be paid 50% in cash and 50% in restricted shares of Dominion Resources common
stock. The stock will be restricted for two years. During this time it cannot
be transferred and will be forfeited if the executive terminates employment.
For the 1998-2000 performance period, a threshold award will be earned if
minimum performance goals are achieved. The target award will be earned if the
specified goals are fully achieved. A higher award is available for higher
levels of achievement.
54
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 $ 51,390 $ 68,520 $ 85,650 $102,779
200,000 55,957 74,610 93,262 111,914
225,000 63,570 84,760 105,950 127,139
250,000 71,182 94,910 118,637 142,364
300,000 86,407 115,210 144,012 172,814
350,000 101,632 135,510 169,387 203,264
400,000 116,857 155,810 194,762 233,714
450,000 132,082 176,110 220,137 264,164
500,000 147,307 196,410 245,512 294,614
550,000 162,532 216,710 270,887 325,064
600,000 177,757 237,010 296,262 355,514
650,000 192,982 257,310 321,637 385,964
750,000 223,432 297,910 372,387 446,864
800,000 238,657 318,210 397,762 477,314
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.
In addition, certain officers, if they reach a specified age while still
employed, will be credited with additional years of service. For the executives
named in the Summary Compensation Table, credited years of service at age 60,
including any additional years earned in connection with the retirement
agreements, would be 30.
Virginia Power's executive compensation program places significant
emphasis on incentive compensation opportunities linked to financial and
operating performance. The Retirement Plan benefit formula recognizes base
salary, but not incentive compensation payments. Therefore, each year the
Organization, Compensation and Nominating 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 1998, 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 Restoration Plan.
EXECUTIVE SUPPLEMENTAL RETIREMENT PLAN
The Supplemental Plan provides an annual retirement benefit equal to 25
percent of a participant's final cash compensation (base pay plus target 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 1998 compensation, the estimated annual benefit
under this plan for each of the executives named in the Summary Compensation
Table are: Mr. Askew: $189,515; Mr. O'Hanlon: $127,989; Mr. Rigsby: $119,328;
Mr. Farrell, II: $93,778; Mr. Girvin: $83,387.
55
EXECUTIVE DEFERRED COMPENSATION PLAN
Under this plan, executives may defer any portion of their base salary,
annual incentive cash award and/or long term incentive cash award. Deferrals
are credited at the executive's discretion, for bookkeeping purposes, with
earnings and losses as if they were invested in any of several mutual fund
options, or Dominion Resources common stock. Distributions are made at the
direction of the executive.
EMPLOYMENT AGREEMENTS
The Company has entered into employment continuity agreements (the
Agreements) with its key management executives, including, Mr. Askew, Mr.
O'Hanlon, Mr. E. Rigsby, Mr. Farrell, II, and Mr. Girvin, which provide
benefits in the event of a change in control. Each Agreement has a three-year
term and is automatically extended each year on its anniversary date for an
additional year unless the Company decides not to extend it. 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 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 annual incentive payments 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 incentive or other 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
FEES
During 1998, non-employee directors were paid an annual retainer of
$19,000 in cash plus $19,000 in stock. Individuals who are directors of both
Virginia Power and Dominion Resources receive one Annual Retainer Fee. They
also received $900 in cash per Board or committee meeting attended.
DEFERRED CASH COMPENSATION PLAN
Directors may elect to defer their cash fees under this plan until they
reach retirement or a specified age. The deferred fees are credited to either
an interest bearing account or a Dominion Resources common stock equivalent
account. Interest or dividend equivalents accrue until distributions are made.
A director will be paid in cash or stock according to the election made.
STOCK COMPENSATION PLAN
The stock portion of the directors' retainer is paid under this plan.
Directors have the option to defer receipt of the stock. If a director elects
this option, the shares are held in trust until the director's retirement and
the dividends on those shares are reinvested. However, the director retains all
voting and other rights as a shareholder.
STOCK ACCUMULATION PLAN
Upon election to the Board, a non-employee director receives a one-time
award under this plan. The award is in Stock Units, which are equivalent in
value to Dominion Resources common stock. The award amount is determined by
multiplying the director's annual cash retainer by 17, then dividing the result
by the average price of Dominion Resources common stock on the last trading
days of the three months before the director's election to the Board. The Stock
Units awarded to a director are credited to a book account. A separate account
is credited with additional Stock Units equal in value to dividends on all
Stock Units held in the director's account. A director must have 17 years of
service to receive all of the Stock Units awarded and accumulated under this
plan. Reduced distributions may be made where a director has at least 10 years
of service.
CHARITABLE CONTRIBUTION PROGRAM
As part of its overall program of charitable giving, the Company offers
the directors participation in a Directors' Charitable Contribution Program.
The Program is funded by life insurance policies purchased by the Company on
the directors.
56
The directors derive no financial or tax benefits from the Program, because all
insurance proceeds and charitable tax deductions accrue solely to the Company.
However, upon the death of a director, the Company will donate an aggregate of
$50,000 per year for ten years to one or more qualifying charitable
organizations recommended by that director.
MATCHING GIFTS PROGRAM
Directors may give up to $1,000 per year to 501(c)3 organizations of their
choice and the Company will match their donations on a 1-to-1 basis. If they
volunteer more than 50 hours of work to any organization during a year, the
Company will match the donation on a 2-to-1 basis.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The table below sets forth as of February 19, 1999, except as noted, the
number of shares of Common Stock of Dominion Resources owned by Directors and
the executive officers named on the Summary Compensation Table.
SHARES OF COMMON STOCK DIRECTOR PLAN
NAME BENEFICIALLY OWNED ACCOUNTS(1)
- ----------------------------------------- ------------------------ --------------
John B. Adams, Jr. ...................... 3,997 9,647
John B. Bernhardt ....................... 2,000(4) 9,647
James F. Betts .......................... 7,979 9,647
Thos. E. Capps .......................... 65,231(2)
Jean E. Clary ........................... 148 9,723
John W. Harris .......................... 5,000 9,647
Benjamin J. Lambert, III ................ 590(4) 11,086
Richard L. Leatherwood .................. 1,500(4) 19,886
Harvey L. Lindsay ....................... 879 9,647
Kenneth A. Randall ...................... 3,713 9,647
William T. Roos ......................... 11,262(4) 9,647
Frank S. Royal .......................... 500(4) 11,067
S. Dallas Simmons ....................... 3,332 11,983
Robert H. Spilman ....................... 1,666 9,647
William G. Thomas ....................... 1,500(4) 14,068
Judith B. Warrick ....................... 1,500(4) 15,460
David A. Wollard ........................ 1,315 9,647
Norman Askew ............................ 3,425(2)
Thomas F. Farrell, II ................... 17,113(3)
Larry M. Girvin ......................... 2,966
James P. O'Hanlon ....................... 5,215
Robert E. Rigsby ........................ 15,036
All Directors and Executive Officers as a
group -- 41 persons (5) ................ 384,310(2)(6)
- ---------
(1) Amounts in this column represent share equivalents accumulated under the
non-employee director Stock Accumulation Plan. Balances of 9,647 shares
are the amounts accumulated 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 9,647 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 -- 33,153 shares;
Mr. Askew -- 2,057; Mr. Farrell -- 14,467; Mr. Rigsby -- 1502; Mr. Girvin
-- 794; Mr. O'Hanlon -- 972; and all directors and executive officers as a
group -- 58,512.
(3) Mr. Farrell disclaims beneficial ownership of 399 shares held by his
spouse.
(4) Includes 500 shares held in trust under the Directors Stock Compensation
Plan.
(5) All current directors and executive officers as a group own less than one
percent of the number of shares outstanding as of February 19, 1999.
57
(6) Beneficial ownership is disclaimed for a total of 622 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.
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.
58
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).
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 -- Form of Senior Indenture, dated as of June 1, 1998 as supplemented by the First
Supplemental Indenture to the Senior Indenture dated as of June 1, 1998 (Exhibit 4.2 to
Form 8-K dated June 12, 1998, regarding the sale of $150 million of Senior Notes,
incorporated by reference).
4.8 -- 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.
59
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
(Exhibit 10.3, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255
incorporated by reference).
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* -- Description of arrangements with certain officers regarding additional credited years of
service for retirement purposes (Exhibit 10(xii), Form 10-K for the fiscal year ended
December 31, 1992, File No. 1-2255, incorporated by reference).
10.11* -- 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 (Exhibit 10.14, Form 10-K for the fiscal
year ended December 31, 1997, File No. 1-2255, incorporated by reference). .
10.12* -- 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).
10.13* -- Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as
amended and restated September 1, 1996 (Exhibit 10.16, Form 10-K for the fiscal year
ended December 31, 1997, File No. 1-2255, incorporated by reference).
10.14* -- Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective
January 1, 1991 as amended and restated September 1, 1996 (Exhibit 10.17, Form 10-K for
the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference).
10.15* -- 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).
10.16* -- Form of an Employment Agreement dated June 23, 1994 between Virginia Power and
certain executive officers, including Larry M. Girvin and James P. O'Hanlon (Exhibit
10(xxi), Form 10-K for the fiscal year ended December 31, 1996, File No. 1-2255,
incorporated by reference). [The only material respect in which the particular employment
agreements differ is the base salary set forth therein.]
10.17* -- 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).
10.18* -- Employment Agreement dated February 1, 1997 between Dominion Resources and Norman
Askew (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 1997, File No.
1-2255, incorporated by reference).
60
10.19* -- 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).
10.20* -- Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997 (Exhibit
10.23 Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255,
incorporated by reference).
10.21* -- Form of an Employment Agreement dated March 16, 1998 between Virginia Power and
certain executive officers (Exhibit 10.1, Form 10-Q for the period ended March 31, 1998,
File No. 1-2255, incorporated by reference). [The only material respect in which the
particular employment agreements differ is the base salary set forth therein.]
10.22* -- Dominion Resources, Inc. Directors' Stock Compensation Plan, effective April 9, 1998
(filed herewith).
10.23* -- Dominion Resources, Inc. Directors' Deferred Cash Compensation Plan effective December
21, 1998 (filed herewith).
10.24* -- Employment Agreement dated September 12, 1997 between Dominion Resources and
Thomas F. Farrell, II (filed herewith).
23.1 -- Consent of McGuire Woods Battle & Boothe LLP (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
61
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:
By THOS.
(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 .
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.
KENNETH A. RANDALL Director
- ----------------------------------
KENNETH A. RANDALL
62
SIGNATURE TITLE
- ----------------------------------- -----------------------------------------
WILLIAM T. ROOS Director
- ----------------------------------
WILLIAM T. ROOS
FRANK S. ROYAL Director
- ----------------------------------
FRANK S. ROYAL
S. DALLAS SIMMONS Director
- ----------------------------------
S. DALLAS SIMMONS
ROBERT H. SPILMAN Director
- ----------------------------------
ROBERT H. SPILMAN
WILLIAM G. THOMAS Director
- ----------------------------------
WILLIAM G. THOMAS
JUDITH B. WARRICK Director
- ----------------------------------
JUDITH B. WARRICK
DAVID A. WOLLARD Director
- ----------------------------------
DAVID A. WOLLARD
JOHN A. SHAW Senior Vice President,
- ----------------------------------
JOHN A. SHAW Chief Financial Officer and Treasurer
M. S. BOLTON, JR. Vice President and Controller (Principal
- ----------------------------------
M. S. BOLTON, JR. Accounting Officer)
63