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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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Form 10-K
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(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-2255
VIRGINIA ELECTRIC AND POWER COMPANY
(Exact name of registrant as specified in its charter)
VIRGINIA 54-0418825
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification no.)
701 East Cary Street
23219-3932
Richmond, Virginia (Zip Code)
(Address of principal executive offices)
(804) 771-3000
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Preferred Stock (cumulative) New York Stock Exchange
$100 liquidation value:
$5.00 dividend
Trust Preferred Securities New York Stock Exchange
$25 liquidation value:
8.05% dividend
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Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of February 28, 1998, was zero.
As of February 28, 1998, there were issued and outstanding 171,484 shares
of the registrant's common stock, without par value, all of which were held,
beneficially and of record, by Dominion Resources, Inc.
DOCUMENTS INCORPORATED BY REFERENCE.
None
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VIRGINIA ELECTRIC AND POWER COMPANY
Page
Item Number Number
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PART I
1. Business .............................................................................. 1
The Company ........................................................................... 1
Company Management .................................................................... 1
Competition and Strategic Initiatives ................................................. 1
Regulation ............................................................................ 2
General .............................................................................. 2
Virginia ............................................................................. 2
FERC ................................................................................. 3
Environmental ........................................................................ 3
Nuclear .............................................................................. 3
Rates ................................................................................. 4
FERC ................................................................................. 4
Virginia ............................................................................. 5
North Carolina ....................................................................... 6
Capital Requirements and Financing Program ............................................ 6
Construction and Nuclear Fuel Expenditures ........................................... 6
Financing Program .................................................................... 6
Sources of Power ...................................................................... 7
Company Generating Units ............................................................. 7
Net Purchases ........................................................................ 7
Non-Utility Generation ............................................................... 7
Sources of Energy Used and Fuel Costs ................................................. 8
Nuclear Operations and Fuel Supply ................................................... 8
Fossil Operations and Fuel Supply .................................................... 8
Purchases and Sales of Energy ........................................................ 8
Future Sources of Power ............................................................... 9
Conservation and Load Management ...................................................... 9
Interconnections ...................................................................... 9
2. Properties ............................................................................ 10
3. Legal Proceedings ..................................................................... 11
4. Submission of Matters to a Vote of Security Holders ................................... 11
PART II
5. Market for the Registrant's Common Equity and Related Stockholder Matters ............. 12
6. Selected Financial Data ............................................................... 12
7. Management's Discussion and Analysis of Financial Condition and Results of Operations . 12
Liquidity and Capital Resources ....................................................... 13
Capital Requirements .................................................................. 14
Results of Operations ................................................................. 15
Future Issues ......................................................................... 17
Market Risk Sensitive Instruments and Risk Management ................................. 22
8. Financial Statements and Supplementary Data ........................................... 24
9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure .. 47
PART III
10. Directors and Executive Officers of the Registrant ................................... 48
11. Executive Compensation ............................................................... 51
12. Security Ownership of Certain Beneficial Owners and Management ....................... 55
13. Certain Relationships and Related Transactions ....................................... 55
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ..................... 56
PART I
ITEM 1. BUSINESS
THE COMPANY
Virginia Electric and Power Company is a Virginia Corporation. Our
principal office is at 701 East Cary Street, Richmond, Virginia 23219-3932,
telephone (804) 771-3000. We are a wholly owned subsidiary of Dominion
Resources, Inc. (Dominion Resources), a Virginia corporation. Dominion
Resources owns all of our common stock.
Virginia Electric and Power Company is a regulated public utility engaged
in the generation, transmission, distribution and sale of electric energy
within a 30,000 square-mile area in Virginia and northeastern North Carolina.
It transacts business under the name Virginia Power in Virginia and under the
name North Carolina Power in North Carolina. We have retail customers
(including governmental agencies) and wholesale customers such as rural
electric cooperatives, power marketers and municipalities. We serve more than
80 percent of Virginia's population. The Company has certificates of
convenience and necessity from the State Corporation Commission of Virginia
(the Virginia Commission) for service in all territories served at retail in
Virginia. The North Carolina Utilities Commission (the North Carolina
Commission) has assigned territory to the Company for substantially all of its
retail service outside certain municipalities in North Carolina.
The electric utility industry in the United States is undergoing an
evolutionary change toward less regulation and more competition. To meet the
challenges of this new competitive environment, Virginia Power has developed a
broad array of "non-traditional" product and service offerings from its
operating business units and subsidiaries:
o Energy Services -- offering electric energy and capacity in the emerging
wholesale market as well as natural gas and other energy-related products
and services;
o Fossil & Hydro -- targeting process type industries, such as chemical,
paper, plastics and petroleum to become a service provider of
instrumentation equipment;
o Nuclear Services -- offering management and operations services to other
electric utilities;
o Commercial Operations -- providing power distribution related services,
including transmission and distribution, engineering and metering services
to other gas, water and electric utilities; and
o Telecommunications -- offering telecommunications services through the
Company's existing fiber-optic network.
The Company and its subsidiaries had 9,043 full-time employees on December
31, 1997. A total of 3,452 of our employees are represented by the
International Brotherhood of Electrical Workers under a contract extending to
March 31, 1998. The Company and the union have tentatively agreed, subject to
ratification by the union membership, to a two year extension of the contract.
For a more thorough review of the changing utility industry and the
Company's strategy see COMPETITION AND STRATEGIC INITIATIVES below and Future
Issues -- Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (MD&A).
COMPANY MANAGEMENT
In April, Dr. James T. Rhodes, President and Chief Executive Officer since
1989, announced his retirement effective August 1, 1997. The Board of Directors
subsequently elected Mr. Norman Askew as the new President and Chief Executive
Officer, effective August 1, 1997. Mr. Askew was previously the Chief Executive
of East Midlands Electricity plc, a United Kingdom regional electricity company
acquired by Dominion Resources during the first quarter of 1997. Mr. Askew also
replaced Dr. Rhodes on the Board of Directors effective August 1, 1997.
COMPETITION AND STRATEGIC INITIATIVES
A number of developments in the United States are causing a trend toward
less regulation and more competition in the electric utility industry. This is
evidenced by legislative and regulatory action at both the federal and state
levels. To the extent that competition is either authorized or mandated and
regulation is eliminated or relaxed, electric utilities may no longer be
guaranteed an opportunity to recover all of their prudently incurred costs, and
utilities with costs that exceed the market prices established by the
competitive market will run the risk of suffering losses, which may be
substantial.
1
Virginia Power has responded to these trends by undertaking cost-cutting
measures, engaging in re-engineering efforts, restructuring its core business
processes, and pursuing a strategic planning initiative to encourage innovative
approaches to serving traditional markets. The Company has established separate
business units, as discussed above, to fully execute these strategies.
The Company also is vigorously participating in the state and federal
legislative actions currently underway to bring about competition in the
electric utility industry, in an effort to ensure an orderly transition from a
regulated environment.
The Company's non-traditional businesses face competition from a variety
of utility and non-utility entities.
For a full discussion of the regulatory and legislative issues related to
competition, carefully read the Future Issues section of MD&A.
REGULATION
General
In a wide variety of matters in addition to rates, Virginia Power is
presently subject to regulation by the Virginia Commission and the North
Carolina Commission, the Environmental Protection Agency (EPA), Department of
Energy (DOE), Nuclear Regulatory Commission (NRC), the Federal Energy
Regulatory Commission (FERC), the Army Corps of Engineers, and other federal,
state and local authorities. Compliance with numerous laws and regulations
increases the Company's operating and capital costs by requiring, among other
things, changes in the design and operation of existing facilities and changes
or delays in the location, design, construction and operation of new
facilities. The commissions regulating the Company's rates have historically
permitted recovery of such costs.
Virginia Power may not construct, or incur financial commitments for
construction of, any substantial generating facilities or large capacity
transmission lines without the prior approval of various state and federal
governmental agencies. Such approvals relate to, among other things, the
environmental impact of such activities, the relationship of such activities to
the need for providing adequate utility service and the design and operation of
proposed facilities.
Both federal and state legislative bodies have been studying competition
and restructuring in the electric utility industry. Please carefully read the
full discussion of this matter found in the Future Issues -- Competition --
Legislative Initiatives section of MD&A.
Virginia
In 1995, the Virginia Commission instituted an ongoing generic
investigation on electric industry restructuring, resulting in a number of
reports by its Staff covering such issues as retail wheeling experiments and
the status of wholesale power markets. The Staff also submitted a report to the
General Assembly calling for a cautious, two-phase, five-year period to address
restructuring issues. The report acknowledged the need for direction from the
Virginia legislature concerning policy issues surrounding competition in the
electric industry.
In November 1996, the Virginia Commission instituted a proceeding
concerning Virginia Power's cost of service and possible restructuring of the
electric utility industry as it might relate to Virginia Power. On March 24,
1997, Virginia Power filed in that proceeding a calculation of its cost of
service for 1996 and a proposed Alternative Regulatory Plan (ARP).
Subsequently, the Commission consolidated this proceeding with the proceeding
concerning the Company's 1995 Annual Informational Filing, in which the
Company's base rates were made interim and subject to refund as of March 1,
1997. Please carefully read the Future Issues -- Competition -- Legislative and
Regulatory Initiatives sections of MD&A and RATES-Virginia, below for details
concerning the ARP, its current status and related legislative developments.
In December 1995, Virginia Power applied to the Virginia Commission for
approval of arrangements with Chesapeake Paper Products Company (CPPC), under
which Virginia Power would facilitate the design, construction and financing of
a cogeneration plant to meet CPPC's energy requirements for its industrial
processes at its plant in West Point, Virginia. On August 13, 1997, the
Virginia Commission approved, in substantial part, the proposed transactions
between Virginia Power and CPPC's successor in ownership, St. Laurent Paper
Products Co. St. Laurent later determined that the current design of the
facility was no longer compatible with its long-term business strategies and
terminated its contractual arrangement with Virginia Power. The Virginia
Commission dismissed the proceeding on January 15, 1998.
In June 1997, the Virginia Commission granted the Company's request to
implement a monitoring program that requires certain non-utility generators to
provide certain information sufficient to determine continued compliance with
the "Qualifying Facility" (QF) requirements of the Public Utility Regulatory
Policies Act of 1978 (PURPA).
2
On August 8, 1997, the Virginia Commission granted the Company's request
to provide interchange telecommunications services and approved the proposed
affiliate agreements between Virginia Power and our wholly-owned subsidiary,
VPS Communications, Inc. (VPSC). Under the authority granted, VPSC will provide
a range of telecommunications services, including private line and special
access services and high-capacity fiberoptic services.
On September 3, 1997, the Virginia Commission granted the Company's
request to provide services to our wholly-owned subsidiary, Virginia Power
Services, Inc. (VPS), which would enable Virginia Power Nuclear Services
Company (VPN), a VPS subsidiary, to furnish nuclear management and operation
services to electric utilities seeking assistance in the management and
operation of their nuclear generating facilities. VPN currently provides such
services to Northeast Utilities at its Millstone Unit 2 nuclear plant.
FERC
In April 1996, FERC issued final rules in Order Nos. 888 and 889
addressing open access transmission service, stranded costs, standards of
conduct and open access same-time information systems (OASIS). In July 1996,
Virginia Power filed an open access transmission service tariff in compliance
with FERC's Order No. 888. In compliance with FERC's directive, Virginia
Power's OASIS became operational on January 3, 1997. Also, on that date the
standards of conduct requiring separation of transmission
operations/reliability functions from wholesale merchant/marketing functions
became effective. The Company also made filings to comply with FERC's directive
that, effective January 1, 1997, utilities could no longer make bundled sales
of transmission and generation services in economy energy transactions. In
certain of those filings, Virginia Power canceled or committed not to use the
economy energy rate schedules contained in interconnection agreements with
neighboring utilities. On March 4, 1997, FERC issued Order Nos. 888-A and
889-A, which addressed requests for rehearing of Order Nos. 888 and 889. Orders
No. 888-A and 889-A essentially reaffirm the basic principles of 888 and 889
and clarify and make limited modifications to those orders. On December 17,
1997, FERC issued Order Nos. 888-B and 889-B. FERC rejected all requests for
rehearing filed with respect to Order Nos. 888-A and 889-A and clarified and
made limited modifications to those orders. Several parties have appealed the
888 orders to the United States Court of Appeals for the District of Columbia
Circuit.
For a discussion of the status of the Company's Open Access Transmission
Tariff filing, see RATES -- FERC below.
For additional discussion of open access issues see Future Issues --
Competition under MD&A.
LG&E Westmoreland Southampton owns a cogeneration facility in Franklin,
Virginia, and sells its output to Virginia Power. Southampton has sought a
waiver of FERC operating requirements for Qualifying Facilities (QF's) under
PURPA, however FERC refused to grant such a waiver. On March 31, 1997, the
United States Court of Appeals for the District of Columbia Circuit granted
FERC's motion to dismiss Southampton's Petition for Review.
Environmental
From time to time, Virginia Power may be designated by the EPA as a
potentially responsible party (PRP) with respect to a Superfund site. As a
result of that designation or other regulations regarding the remediation of
waste, we may become obligated to fund remedial investigations or actions. We
do not believe that any currently identified sites will result in significant
liabilities. For a discussion of the Company's site remediation efforts, see
Note Q to the CONSOLIDATED FINANCIAL STATEMENTS.
Permits under the Clean Water Act and state laws have been issued for all
of the Company's steam generating stations now in operation. These permits are
subject to reissuance and continuing review. The Clean Air Act, as amended in
1990, requires the Company to reduce its emissions of sulfur dioxide (SO2) and
nitrogen oxides (NOx). Beginning in 1995, the SO2 reduction program is based on
the issuance of a limited number of SO2 emission allowances, each of which may
be used as a permit to emit one ton of SO2 into the atmosphere or may be sold
to someone else. The program is administered by the EPA.
For additional information on Environmental Matters, Clean Air Act
compliance and related issues see the Future Issues section of MD&A.
Nuclear
All aspects of the operation and maintenance of the Company's nuclear
power stations are regulated by the NRC. Operating licenses issued by the NRC
are subject to revocation, suspension or modification, and operation of a
nuclear unit may be suspended if the NRC determines that the public interest,
health or safety so requires.
3
From time to time, the NRC adopts new requirements for the operation and
maintenance of nuclear facilities. In many cases, these new regulations require
changes in the design, operation and maintenance of existing nuclear
facilities. If the NRC adopts such requirements in the future, it could result
in substantial increases in the cost of operating and maintaining the Company's
nuclear generating units.
In July 1995, the Virginia Commission instituted an investigation
regarding spent nuclear fuel disposal. As directed, Virginia Power and others
filed comments on legal and public policy issues related to spent nuclear fuel
storage and disposal. In February 1996, the Commission Staff filed its Report
recommending that adoption of a definitive policy on spent nuclear fuel
disposal issues be delayed pending the outcome of litigation against the
Department of Energy concerning spent nuclear fuel acceptance, the outcome of
proposed federal legislation concerning development of an interim storage
facility, and development of a vision of the likely outcome of the electric
utility industry's restructuring efforts. The Virginia Commission consolidated
the proceeding with Virginia Power's pending fuel cost recovery proceeding in
October 1996. On March 20, 1997, the Virginia Commission returned the spent
nuclear fuel disposal issue to a separate proceeding.
On January 31, 1997, Virginia Power joined thirty-five other electric
utilities in filing a petition in the United States Court of Appeals for the
District of Columbia Circuit, seeking to compel DOE to comply with its
obligation to begin accepting the utilities' spent nuclear fuel for disposal by
January 31, 1998, the date imposed by the Nuclear Waste Policy Act. Additional
utilities have joined since the original filing. On November 14, 1997, the
Court issued an Order finding that DOE's obligation to begin accepting spent
nuclear fuel by the deadline is unconditional, and that DOE may not excuse its
delay on the grounds that it has not prepared a permanent repository or interim
storage facility. The Court found that DOE's spent fuel disposal contracts with
the utilities offer a potentially adequate remedy for DOE's failure to meet its
obligation. DOE filed a petition for rehearing on December 29, 1997.
RATES
The Company's electric services sales were subject to rate regulation in
1997 as follows:
1997
-----------------------
Percent Percent
of of
Revenues Kwh Sales
---------- ----------
Virginia retail:
Non-Governmental customers ........... Virginia Commission 81% 76%
Governmental customers ............... Negotiated Agreements 10 12
North Carolina retail ................. North Carolina Commission 5 5
Wholesale --Sales for Resale* ......... FERC 4 7
-- --
100% 100%
=== ===
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* Excludes wholesale power marketing sales subject to FERC regulation.
Substantially all of the Company's electric service sales are subject to
recovery of changes in fuel costs either through fuel adjustment factors or
periodic adjustments to base rates, each of which requires prior regulatory
approval.
Each of these jurisdictions has the authority to disallow recovery of
costs it determines to be excessive or imprudently incurred. Various cost items
may be reviewed on occasion, including costs of constructing or modifying
facilities, on-going purchases of capacity or providing replacement power
during generating unit outages.
FERC
In compliance with FERC's Order No. 888, Virginia Power filed an open
access transmission service tariff, which became effective on July 9, 1996. In
October 1996, FERC issued a procedural order, scheduling a hearing for April
28, 1997. The Company and all parties reached a settlement of issues raised in
the proceeding, and on March 20, 1997, those parties jointly filed with FERC
the Settlement Agreement and Motion to Certify the Settlement Agreement. On
April 23, 1997 the presiding Administrative Law Judge certified the Settlement
Agreement to the FERC and on June 11, 1997, the FERC approved the settlement.
In compliance with FERC's Order No. 889, on January 3, 1997, the Company
filed its Procedures For Standards of Conduct for Unbundled Transmissions and
Wholesale Merchant Function (Standards of Conduct) effective on that date. On
July 1, 1997, the Company filed an amendment to the Standards of Conduct in
Compliance with FERC's Order No. 889-A.
4
On July 16, 1997, the Company filed another amendment in response to a FERC
Staff request. The Company is awaiting FERC action on the filing.
On September 11, 1997, FERC authorized the Company to sell power at
market-based rates but set for hearing the issue of the impact of any
transmission constraints on Virginia Power's ability to exercise generation
market power in localized areas within its service territory. If FERC finds
that transmission constraints give Virginia Power generation dominance, it
could either revoke or limit the scope of the market-based rate authority. The
hearing is scheduled to commence June 2, 1998.
On October 31, 1997, Virginia Power filed at FERC three agreements with
Old Dominion Electric Cooperative (ODEC) to amend the parties' Interconnection
and Operating Agreement (I&O Agreement) and to unbundle transmission services
provided to ODEC under the I&O Agreement. On December 22, 1997, FERC issued a
deficiency letter with respect to the filing directing the Company to provide
additional information. On January 21, 1998, the Company provided the requested
information. FERC accepted the agreements on March 12, 1998.
Virginia
In March 1997, the Virginia Commission issued an order that Virginia
Power's base rates be made interim and subject to refund as of March 1, 1997.
This order was the result of the Commission Staff's report on its review of
Virginia Power's 1995 Annual Informational Filing, which concluded that
Virginia Power's present rates would cause Virginia Power to earn in excess of
its authorized return on equity. The Staff found that, for purposes of
establishing rates prospectively, a rate reduction of $95.6 million (including
a one-time adjustment of $29.7 million to Virginia Power's deferred capacity
balance at December 31, 1996) may be necessary in order to realign rates to the
authorized level. Virginia Power filed its Alternative Regulatory Plan in March
1997, based on 1996 financial information. Subsequently, the Commission
consolidated the proceeding concerned with the 1995 Annual Informational Filing
with the proceeding that includes the ARP proposed by the Company.
In December 1997, Virginia Power sought to withdraw its ARP, having
concluded that resolution of the cost recovery issues raised by the ARP was
unlikely without General Assembly action. The Commission has agreed that the
Company may withdraw its support of the ARP but has reserved the right to
continue consideration of the ARP as well as other regulatory alternatives. In
addition, the Commission will continue to consider the issues arising out of
the 1995 Annual Informational Filing. The Commission's Staff is scheduled to
file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed
by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A
public hearing is scheduled to commence on May 19, 1998.
Virginia Power's previous filings in this proceeding support maintaining
the Company's rates at current levels; however, opposing parties have made
filings recommending rate reductions in excess of $200 million. At this time,
management cannot predict the ultimate outcome of the proceeding and its impact
on the Company's results of operations, cash flows or financial position.
In July 1996, Virginia Power proposed to substantially reduce the rates
paid under Schedule 19 to cogenerators and small power producers of 100 kW or
less. The rates became effective on an interim basis on January 1, 1997. On
January 21, 1998, the Virginia Commission approved revised Schedule 19 rates.
The approved rates do not differ in any significant way from the rates
originally proposed by the Company.
In October 1996, Virginia Power filed an application with the Virginia
Commission to increase its fuel factor from 1.299 cents per kWh to 1.322 cents
per kWh, reflecting a fuel factor annual revenue increase of approximately
$48.2 million. The increase became effective on an interim basis on December 1,
1996. On June 11, 1997, the Commission entered an Order Establishing Fuel
Factor approving the requested increase.
On October 31, 1997, Virginia Power filed with the Virginia Commission its
application for a reduction of $45.6 million in its fuel cost recovery factor
for the period December 1, 1997 through November 30, 1998. The reduction became
effective on an interim basis on December 1, 1997. Subsequently, as a result of
amendments to two non-utility power purchase contracts, the Company proposed
two additional reductions of approximately $30.2 million and $18 million for
the same period, bringing the total proposed fuel factor reduction to $93.8
million. Both additional reductions were approved on an interim basis,
effective March 1, 1998. A hearing is scheduled for April 9, 1998.
5
North Carolina
On November 4, 1996, the Company filed for approval of a new Schedule 19
which governs purchases from cogenerators and small power producers. The
Company proposed rates substantially lower than those previously specified. It
also proposed to reduce the applicability threshold to 100 kW and shorten the
maximum term of contracts under Schedule 19 to five years. On June 19, 1997,
the North Carolina Commission issued an Order requiring the Company to offer
long-term (5-,10- and 15-year) levelized capacity payments to hydroelectric and
certain landfill and waste facilities contracting for up to 5 MW; a 5-year
levelized rate option to other QFs contracting for up to 100 kW; and optional
long-term levelized energy payments for QFs rated at 100 kW or less capacity.
On October 10, 1997 the Company filed an application with the North
Carolina Commission for a $728,000 increase in fuel revenues. On December 29,
1997, the North Carolina Commission entered an Order Approving Fuel Charge
Adjustment. The Order approved an approximate $600,000 increase in the annual
rates and charges paid by the retail customers of North Carolina Power
effective on January 1, 1998.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Construction and Nuclear Fuel Expenditures
Virginia Power's estimated construction and nuclear fuel expenditures for
the three-year period 1998-2000, total $1.5 billion. It has adopted a 1998
budget for construction and nuclear fuel expenditures as set forth below:
Estimated 1998
Expenditures
(millions)
---------------
Production .................................................... $ 60
Technology .................................................... 150
General Support Facilities .................................... 19
Transmission .................................................. 37
Distribution .................................................. 213
Nuclear Fuel .................................................. 86
----
Total Construction Requirements and Nuclear Fuel Expenditures $565
====
In addition, the Company expects to incur approximately $23 million of
expenditures in 1998 in connection with the development of energy management
projects for customers. Contracts with such customers provide for the recovery
of these costs in future years.
Financing Program
The Company currently has three shelf registrations on file with the
Securities Exchange Commission (SEC) providing the Company with $915 million of
debt capital resources. The Company also has a Preferred Stock shelf registered
with the SEC for $100 million in aggregate principal amount, which has not been
utilized.
The Company intends to issue securities from time to time to meet its
capital requirements, which include $333.5 million of long-term debt maturities
in 1998.
Please see the Liquidity and Capital Resources section of MD&A for details
about our Financing Program.
6
SOURCES OF POWER
Company Generating Units
Type Summer
Years of Capability
Name of Station, Units and Location Installed Fuel MW
- ---------------------------------------------------------- ----------- ---------------- ------------
Nuclear:
Surry Units 1 & 2, Surry, Va ........................... 1972-73 Nuclear 1,602
North Anna Units 1 & 2, Mineral, Va .................... 1978-80 Nuclear 1,790 (a)
Total nuclear stations ................................ 3,392
--------
Fossil Fuel:
Steam:
Bremo Units 3 & 4, Bremo Bluff, Va. ................... 1950-58 Coal 227
Chesterfield Units 3-6, Chester, Va. .................. 1952-69 Coal 1,250
Clover Units 1 & 2, Clover, Va. ....................... 1995-96 Coal 882 (b)
Mt. Storm Units 1-3, Mt. Storm, W. Va. ................ 1965-73 Coal 1,587
Chesapeake Units 1-4, Chesapeake, Va. ................. 1953-62 Coal 595
Possum Point Units 3 & 4, Dumfries, Va. ............... 1955-62 Coal 322
Yorktown Units 1 & 2, Yorktown, Va. ................... 1957-59 Coal 326
Possum Point Units 1, 2, & 5, Dumfries, Va. ........... 1948-75 Oil 929
Yorktown Unit 3, Yorktown, Va. ........................ 1974 Oil & Gas 818
North Branch Unit 1, Bayard, W. Va. ................... 1994 Waste Coal 74 (c)
Combustion Turbines:
35 units (8 locations) ................................. 1967-90 Oil & Gas 1,019
Combined Cycle:
Bellmeade, Richmond, Va. ............................... 1991 Oil & Gas 230
Chesterfield Units 7 & 8, Chester, Va. ................. 1990-92 Oil & Gas 397
Total fossil stations ................................. 8,656
--------
Hydroelectric:
Gaston Units 1-4, Roanoke Rapids, N.C. ................. 1963 Conventional 225
Roanoke Rapids Units 1-4, Roanoke Rapids, N.C. ......... 1955 Conventional 99
Other .................................................. 1930-87 Conventional 3
Bath County Units 1-6, Warm Springs, Va. ............... 1985 Pumped Storage 1,260 (d)
--------
Total hydro stations .................................. 1,587
--------
Total Company generating unit capability .............. 13,635
Net Purchases ........................................... 1,480
Non-Utility Generation .................................. 3,277
--------
Total Capability ...................................... 18,392
========
- ---------
(a) Includes an undivided interest of 11.6 percent (208 MW) owned by ODEC.
(b) Includes an undivided interest of 50 percent (441 MW) owned by ODEC.
(c) Effective January 25, 1996, this unit was placed in a cold reserve
status.
(d) Reflects the Company's 60 percent undivided ownership interest in the
2,100 MW station. A 40 percent undivided interest in the facility is owned
by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc
(AE).
The Company's highest one-hour integrated service area summer peak demand
was 14,537 MW on July 28, 1997, and an all-time high one-hour integrated winter
peak demand of 14,910 MW was reached on February 5, 1996.
7
SOURCES OF ENERGY USED AND FUEL COSTS
For information as to energy supply mix and the average fuel cost of
energy supply, see Results of Operations under MD&A.
Nuclear Operations and Fuel Supply
In 1997, the Company's four nuclear units achieved a combined capacity
factor of 91.1 percent.
The Company utilizes both long-term contracts and spot purchases to
support its needs for nuclear fuel. The Company continually evaluates worldwide
market conditions in order to ensure a range of supply options at reasonable
prices. Current agreements, inventories and spot market availability will
support the Company's current and planned fuel supply needs for fuel cycles
throughout the remainder of the 1990's and into the early 2000's. Beyond that
period, additional fuel will be purchased as required to ensure optimum cost
and inventory levels.
The DOE is not expected to begin the acceptance of spent fuel in 1998 as
specified in the Company's contract with the DOE. However, on-site spent
nuclear fuel storage at the Surry Power Station (spent fuel pool and dry cask
storage) is expected to be adequate for the Company's needs until the DOE
begins accepting spent fuel. The North Anna Power Station will require
additional spent fuel storage capacity in 1998. The Company submitted a license
application to the NRC in May 1995 for a dry cask facility at North Anna. The
Company anticipates that this application will be approved in mid-1998.
For details on the issues of decommissioning and nuclear insurance, see
Note C to the CONSOLIDATED FINANCIAL STATEMENTS.
Fossil Operations and Fuel Supply
The Company's fossil fuel mix consists of coal, oil and natural gas. In
1997, Virginia Power consumed approximately 13 million tons of coal. As with
nuclear fuel, the Company utilizes both long-term contracts and spot purchases
to support its needs. The Company presently anticipates that sufficient coal
supplies at reasonable prices will be available for the remainder of the
1990's. Current projections for an adequate supply of oil remain favorable,
barring unusual international events or extreme weather conditions which could
affect both price and supply.
The Company uses natural gas as needed throughout the year for two
combined cycle units and at several combustion turbine units. For winter usage
at the combined cycle sites, gas is purchased and stored during the summer and
fall and consumed during the colder months when gas supplies are not available
at favorable prices. The Company has firm transportation contracts for the
delivery of gas to the combined cycle units. Current projections indicate gas
supplies will be available for the next several years.
Purchases and Sales of Energy
Virginia Power relies on purchases of power to meet a portion of its
capacity requirements. The Company also makes economy purchases of power from
other utility systems when it is available at a cost lower than the Company's
own generation costs.
Under contracts effective January 1, 1985, Virginia Power agreed to
purchase 400 MW of electricity annually through 1999 from Hoosier Energy Rural
Electric Cooperative, Inc. (Hoosier), and agreed to purchase 500 MW of
electricity annually during 1987-99 from certain operating units of American
Electric Power Company, Inc. (AEP).
The Company has a diversity exchange agreement with AE under which AE
delivers 200 MW to Virginia Power in the summer and Virginia Power delivers 200
MW to AE in the winter.
Virginia Power also has 57 non-utility power purchase contracts with a
combined dependable summer capacity of 3,277 MW (for information on the
financial obligations under these agreements see Note Q to the CONSOLIDATED
FINANCIAL STATEMENTS). In a continuing effort to mitigate its exposure to
above-market long-term purchased power contracts, the Company is evaluating its
long-term purchased power contracts and negotiating modifications to their
terms, including cancellations, where it is determined to be economically
advantageous to do so.
The Company's wholesale power group actively participates in the purchase
and sale of wholesale electric power and natural gas in the open market. The
wholesale power group has expanded the Company's trading range beyond the
geographic limits of the Virginia Power service territory, and has developed
trading relationships with energy buyers and sellers on a nationwide basis.
8
In July 1997, the Company executed three agreements with Old Dominion
Electric Cooperative (ODEC) which provide for the amendment of the parties'
Interconnection and Operating Agreement (I&O Agreement). The first agreement
provides for the transition from cost-based rates for capacity and energy
purchases by ODEC to market-based rates by 2002. The second two agreements are
the Service and Operating Agreements for Network Integration Transmission
Service, which unbundled the transmission services provided to ODEC under the
I&O Agreement.
FUTURE SOURCES OF POWER
As reported earlier, both the Hoosier 400 MW long-term purchase and the
AEP 500 MW long-term purchase will expire on December 31, 1999. The Company
presently anticipates adding peaking capacity beginning in the year 2000 to
meet its anticipated load growth. The Company has and will pursue capacity
acquisition plans to provide that capacity and maintain a high degree of
service reliability. This capacity may be owned and operated by others and sold
to the Company or may be built by the Company if it determines it can build
capacity at a lower overall cost. The Company also pursues conservation and
demand-side management (see CONSERVATION AND LOAD MANAGEMENT below). No
Company-owned generation is currently in the planning or construction stages.
For additional information, see Note Q to the CONSOLIDATED FINANCIAL
STATEMENTS.
CONSERVATION AND LOAD MANAGEMENT
The Company is committed to evaluating and selecting demand-side and
supply-side options on a consistent basis in order to provide reliable,
low-cost service to its customers. Conservation and load management programs
are evaluated annually at Virginia Power through a resource planning process
that directly compares the stream of costs and benefits from supply-side and
demand-side options. This process supports a conservation and load management
portfolio which contributes both to the selection of low-cost resources to meet
the future electricity needs of the Company's customers, as well as the
efficient use of current resources.
Events in the evolving electric power marketplace and its regulatory and
legislative environment continue to impact utility-sponsored conservation and
load management programs. In the future, the Company anticipates a greater
reliance on the use of price signals to convey information to our customers
regarding energy-related costs, resulting in more efficient purchase decisions.
INTERCONNECTIONS
The Company maintains major interconnections with Carolina Power and Light
Company, AEP, AE and the utilities in the Pennsylvania-New Jersey-Maryland
Power Pool. Through this major transmission network, the Company has
arrangements with these utilities for coordinated planning, operation,
emergency assistance and exchanges of capacity and energy.
In December 1996, the Company joined with Allegheny Power Service
Corporation, Cleveland Electric Illuminating Company, Toledo Edison Company,
Ohio Edison Company, Pennsylvania Power Company and Southern Company Services,
Inc. (the Transmission Alliance) to file a contract with the FERC entitled the
GAPP Experiment Participation Agreement (GAPP Agreement). The Transmission
Alliance and the GAPP Agreement were established to promote fair and equitable
use of the transmission systems based on the General Agreement on Parallel
Paths (GAPP) model for coordinating the flow of bulk supplies of electricity
among utilities. GAPP principles allow electric companies to determine where
electricity actually flows in bulk power transactions, as opposed to the
"contract" paths that are based on power purchase and transmission agreements
among buying, selling and transmitting utilities.
Compensation for transmission services has historically been based on
contract paths. The GAPP Agreement was designed to determine the physical path
electricity actually takes through the system and allocate open access
transmission revenues among the parties. The GAPP Agreement was designed as an
experiment to test the GAPP methods and procedures for a period of two years.
The FERC accepted the contract on March 25, 1997. The Company and the
Transmission Alliance implemented the GAPP Agreement on April 2, 1997.
On November 14, 1997, in accordance with the FERC order accepting the GAPP
Agreement, the Transmission Alliance issued a report detailing the results of
the first six months of the experiment. The preliminary results of the
experiment indicate that it is technically possible to monitor and predict the
physical flow of electricity over multiple systems and that transmission
revenues reallocated according to actual use of the system differ significantly
from collections under a contract
9
path approach. In October 1997, Virginia Power gave notice to the Transmission
Alliance that, effective January 1, 1998, it was exercising its option under
the GAPP Agreement to terminate its involvement in the experiment.
On December 9, 1997, the Company, the Transmission Alliance and other
utilities agreed to study the creation of an independent regional transmission
entity. The memorandum of understanding to initiate this study was signed by
eleven investor-owned electric companies, including Virginia Power, Consumers
Energy, Detroit Edison, Duquesne Light Company, The Illuminating Company, Ohio
Edison Company, Pennsylvania Power Company, Toledo Edison Company, and the
Allegheny Energy Companies (Monongahela Power Company, The Potomac Edison
Company, and West Penn Power Company). This group is an outgrowth of the GAPP
Agreement and its key goals are to maintain the long-term reliability and
security of the utilities' interconnected transmission systems; ensure the most
efficient use of resources; eliminate pancaking of rates within and between
transmission entities; avoid duplication of costs and achieve transmission cost
savings; and, strike an appropriate balance among the diverse interests of
energy suppliers, customers, and shareholders. The group will also explore
cooperative agreements designed to achieve these goals while ensuring
nondiscriminatory and comparable access to all users of the group's
transmission system. The companies intend to be responsive to industry changes,
especially with the introduction of retail competition in some of the areas
served by the signatories and as some other industry participants consider
creation of independent transmission operating companies or separate
transmission companies. Further, the companies will have the flexibility to
continue to investigate and pursue other opportunities and arrangements that
could develop regarding independent system operators or independent
transmission companies.
Virginia Power and Appalachian Power Company (AEP-Virginia), an operating
unit of AEP, each sought approval from the SCC in 1991 to construct certain
interconnecting transmission facilities. These applications resulted from a
joint planning effort of Virginia Power and AEP to meet the requirements of
their customers. At the time of Virginia Power's application, particularly
during the summer of 1992, constraints were being experienced on transfers of
power into the Virginia Power service territory from the west. On November 7,
1997, the SCC issued an Order directing the Company to report to the Commission
on the continued need for certain new interconnected transmission facilities,
on the relationship between the Company's application to build the new
facilities and certain other pending proceedings, and on the Company's
construction plans, if the SCC grants the Company's application.
On December 15, 1997, the Company filed a report in compliance with the
SCC Order stating that since the filing of the Company's application, the
constraints have been less frequent, due in part to less severe summer weather,
and actual power requirements have been less than originally forecasted. In
addition, generating resources within the Virginia Power service area have been
increased by the higher performance level of the nuclear units, as well as the
completion of the Clover Station. Completion of the AEP project is a
prerequisite for the Virginia Power project to go forward. The proposed
Virginia Power project would not fulfill its intended purpose without the AEP
line being built. AEP has withdrawn its original application and has instituted
a new proceeding before the Commission in which different routing is proposed.
Virginia Power continues to monitor closely the progress of AEP in this
proceeding with respect to its new proposal, but until more is known about
these proceedings, Virginia Power cannot predict what its construction plans
will be.
ITEM 2. PROPERTIES
The Company owns its principal properties in fee (except as indicated
below), subject to defects and encumbrances that do not interfere materially
with their use. Substantially all of its property is subject to the lien of a
mortgage securing its First and Refunding Mortgage Bonds. Right-of-way grants
from the apparent owners of real estate have been obtained for most electric
lines, but underlying titles have not been examined except for transmission
lines of 69 Kv or more. Where rights of way have not been obtained, they could
be acquired from private owners by condemnation if necessary. Many electric
lines are on publicly owned property, as to which permission for use is
generally revocable. Portions of the Company's transmission lines cross
national parks and forests under permits entitling the federal government to
use, at specified charges, surplus capacity in the line if any exists.
The Company leases certain buildings and equipment. See Note G to the
CONSOLIDATED FINANCIAL STATEMENTS.
See Company Generating Units under SOURCES OF POWER under Item 1.
BUSINESS.
10
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is alleged to be in violation or in default
under orders, statutes, rules or regulations relating to the environment,
compliance plans imposed upon or agreed to by the Company, or permits issued by
various local, state and federal agencies for the construction or operation of
facilities. From time to time, there may be administrative proceedings on these
matters pending. In addition, in the normal course of business, the Company is
involved in various legal proceedings. Management believes that the ultimate
resolution of these proceedings will not have a material adverse effect on the
Company's financial position, liquidity or results of operations.
In December 1995, two civil actions were filed in the Virginia Circuit
Court of the City of Norfolk against the City of Norfolk and Virginia Power,
one for $15 million and one for $3 million, by property owners who each alleged
contamination of their respective properties by hazardous substances
originating on nearby property now owned by the city and formerly owned by the
Company. In reference to the $15 million action, the parties reached a
settlement prior to the scheduled August 18, 1997, trial date. The related
action by the other property owner seeking $3 million is still pending, but has
not yet been scheduled for trial.
On April 2, 1997, Doswell Limited Partnership (Doswell) filed a motion for
judgment against Virginia Power in the Circuit Court of the City of Richmond.
Doswell is an independent power producer that has entered into two power
purchase agreements with Virginia Power and claims the Company breached one of
those agreements. On the same date, Doswell also filed a complaint against
Virginia Power in the United States District Court for the Eastern District of
Virginia alleging certain claims relating to the two power purchase agreements.
In March 1998, the parties agreed that both proceedings should be stayed in
order to give the parties an opportunity to negotiate amendments to the power
purchase agreements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On October 17, 1997, by Consent of the Sole Shareholder, Dominion
Resources, Inc., the number of Virginia Power Directors was expanded to a
maximum of eighteen (18) and the following Directors were elected to serve for
terms expiring at the annual shareholder meetings for the years indicated
below:
John B. Bernhardt 2000
John W. Harris 1998
Kenneth A. Randall 1999
Frank S. Royal 1998
Judith B. Sack 1999
S. Dallas Simmons 2000
David A. Wollard 1999
11
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
All of the Company's Common Stock is owned by Dominion Resources.
The Company paid quarterly cash dividends on its Common Stock as follows:
1st 2nd 3rd 4th
---------- ---------- ---------- ----------
(Millions)
1997 ............. $ 95.9 $ 93.4 $ 94.7 $ 95.9
1996 ............. $ 95.3 $ 96.5 $ 96.1 $ 97.9
ITEM 6. SELECTED FINANCIAL DATA
1997 1996
------------- -------------
(Millions, except
percentages)
Revenues .................................................... $ 5,079.0 $ 4,420.9
Income from operations ...................................... 1,019.3 1,010.0
Net income .................................................. 469.1 457.3
Balance available for Common Stock .......................... 433.4 421.8
Total assets ................................................ 11,953.4 11,828.0
Total net utility plant ..................................... 9,219.2 9,433.8
Long-term debt, noncurrent capital lease obligations,
preferred stock subject to mandatory redemption and
preferred securities of subsidiary trust ................... 3,854.4 3,916.2
Utility plant expenditures (including nuclear fuel) ......... 481.8 484.0
Capitalization ratios (percent):
Debt ....................................................... 45.4 46.4
Preferred stock ............................................ 7.6 7.5
Preferred securities ....................................... 1.5 1.5
Common equity .............................................. 45.5 44.6
Embedded cost (percent):
Long-term debt ............................................. 7.60 7.68
Preferred stock ............................................ 5.25 5.14
Preferred securities ....................................... 8.72 8.72
Weighted average ........................................... 7.29 7.34
1995 1994 1993
------------- ------------- -------------
(Millions, except percentages)
Revenues .................................................... $ 4,351.9 $ 4,170.8 $ 4,187.3
Income from operations ...................................... 971.9 957.1 1,070.6
Net income .................................................. 432.8 447.1 509.0
Balance available for Common Stock .......................... 388.7 404.9 466.9
Total assets ................................................ 11,827.7 11,647.9 11,520.5
Total net utility plant ..................................... 9,573.1 9,623.4 9,459.7
Long-term debt, noncurrent capital lease obligations,
preferred stock subject to mandatory redemption and
preferred securities of subsidiary trust ................... 4,228.0 4,157.5 4,151.1
Utility plant expenditures (including nuclear fuel) ......... 577.5 660.9 712.8
Capitalization ratios (percent):
Debt ....................................................... 47.2 46.7 46.4
Preferred stock ............................................ 7.5 9.0 9.2
Preferred securities ....................................... 1.5
Common equity .............................................. 43.8 44.3 44.4
Embedded cost (percent):
Long-term debt ............................................. 7.73 7.65 7.67
Preferred stock ............................................ 5.29 5.47 4.88
Preferred securities ....................................... 8.72
Weighted average ........................................... 7.41 7.29 7.18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This Management's Discussion and Analysis of Financial Condition and
Results of Operations contains "forward-looking statements" as defined by the
Private Securities Litigation Reform Act of 1995, including (without
limitation) discussions as to expectations, beliefs, plans, objectives and
future financial performance, or assumptions underlying or concerning matters
discussed in this document. These discussions, and any other discussions,
including certain contingency matters (and their respective cautionary
statements) discussed elsewhere in this report, that are not historical facts,
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions and uncertainties that could cause actual results or
outcomes to differ materially from those expressed in the forward-looking
statements.
Some important factors that could cause actual results or outcomes to
differ materially from those discussed in the forward-looking statements
include current governmental policies and regulatory actions (including those
of FERC, the EPA, the DOE, the NRC, the Virginia Commission and the North
Carolina Commission), industry and rate structure, operation of nuclear power
facilities, acquisition and disposal of assets and facilities, operation and
storage facilities, recovery of the cost
12
of purchased power, nuclear decommissioning costs, and present or prospective
wholesale and retail competition. The business and profitability of Virginia
Power also are influenced by economic and geographic factors including
political and economic risks, changes in and compliance with environmental laws
and policies, weather conditions and catastrophic weather-related damage,
competition for retail and wholesale customers, pricing and transportation of
commodities, market demand for energy, inflation, capital market conditions,
unanticipated changes in operating expenses and capital expenditures,
competition for new energy development opportunities and legal and
administrative proceedings. All such factors are difficult to predict, contain
uncertainties that may materially affect actual results, and may be beyond the
control of Virginia Power. New factors emerge from time to time and it is not
possible for management to predict all such factors, nor can it assess the
impact of each such factor on the business of the Company.
Any forward-looking statement speaks only as of the date on which such
statement is made, and Virginia Power undertakes no obligation to update any
forward-looking statement or statements to reflect events or circumstances
after the date on which such statement is made.
Liquidity and Capital Resources
Operating activities continue to be a strong source of cash flow,
providing $1,091 million in 1997 compared to $1,115 million in 1996. The
decrease of $24 million (or 2 percent) from the previous year is attributable
to normal business fluctuations. Over the past three years, cash flow from
operating activities has, on average, covered 134 percent of our total
construction requirements and provided 81 percent of our total cash
requirements. Our remaining cash needs are met generally with proceeds from the
sale of securities and short-term borrowings.
Financing activities have represented a net outflow of cash in recent
years as strong cash flow from operations and the absence of major construction
programs have reduced the Company's reliance on debt financing.
Cash from (used in) financing activities was as follows:
1997 1996 1995
----------- ------------ -----------
(Millions)
Issuance of long-term debt ................................... $ 270.0 $ 24.5 $ 240.0
Issuance of preferred securities of subsidiary trust ......... 135.0
Issuance (Repayment) of short-term debt ...................... ( 86.2) 143.4 169.0
Repayment of long-term debt and preferred stock .............. (311.3) (284.1) (439.0)
Dividend payments ............................................ (415.6) (421.4) (438.6)
Other ........................................................ ( 13.5) ( 13.2) ( 13.7)
-------- -------- --------
Total ....................................................... $ (556.6) $ (550.8) $ (347.3)
======== ======== ========
We have taken advantage of declining interest rates by issuing new debt at
lower rates as higher-rate debt has matured. For example, in 1997, $311.3
million of the Company's long-term debt securities matured with an average
effective rate of 8.08 percent. As a partial replacement for this maturing
debt, we issued $270 million of long-term debt securities during the year with
an average effective rate of 6.84 percent.
We currently have three shelf registration statements effective with the
Securities and Exchange Commission from which we can obtain additional debt
capital: $400 million of Junior Subordinated Debentures; $375 million of Debt
Securities, including First and Refunding Mortgage Bonds, Senior Notes and
Senior Subordinated Notes filed in February 1998; and $200 million of
Medium-Term Notes, Series F. The remaining principal amount of debt that can be
issued under these registrations totals $915 million. An additional capital
resource of $100 million in preferred stock also is registered with the
Securities and Exchange Commission.
The Company has a commercial paper program that is supported by two credit
facilities totaling $500 million. Proceeds from the sale of commercial paper
are primarily used to provide working capital. Net borrowings under the program
were $226.2 million at December 31, 1997.
Investing activities in 1997 resulted in a net cash outflow of $546.1
million, primarily due to $397.0 million of construction expenditures and $84.8
million of nuclear fuel expenditures. The construction expenditures included
approximately $252.4 million for transmission and distribution projects, $52.1
million for production projects, $49.7 million for information technology
projects and $42.8 million for other projects.
13
Cash used in investing activities was as follows:
1997 1996 1995
------------ ------------ ------------
(Millions)
Utility plant expenditures (excluding AFC -- other funds) ......... $ (397.0) $ (393.8) $ (519.9)
Nuclear fuel (excluding AFC -- other funds) ....................... ( 84.8) ( 90.2) ( 57.6)
Nuclear decommissioning contributions ............................. ( 36.2) ( 36.2) ( 28.5)
Sale of accounts receivable, net .................................. (160.0)
Purchase of assets ................................................ ( 19.8) ( 13.7)
Other ............................................................. ( 8.3) ( 12.5) ( 11.1)
-------- -------- --------
Total ............................................................ $ (546.1) $ (546.4) $ (777.1)
======== ======== ========
Capital Requirements
Capacity -- The Company anticipates that kilowatt-hour sales will grow
approximately 2.36 percent a year through 2000. We will continue to pursue
capacity acquisition plans to meet the anticipated load growth and maintain a
high degree of service reliability. The additional capacity may be purchased
from others or built by the Company if we can build capacity at a lower overall
cost. We have long-term purchase agreements with Hoosier (400 MW) and AEP (500
MW) which will expire on December 31, 1999. We presently anticipate adding
peaking capacity beginning in the year 2000 to meet future load growth.
Fixed Assets -- The Company's construction and nuclear fuel expenditures
(excluding AFC), during 1998, 1999 and 2000 are expected to total $588.1
million, $476.2 million and $395.1 million, respectively. The Company presently
estimates that all of its 1998 construction and nuclear fuel expenditures will
be met through cash flow from operations.
Long-term Debt -- The Company will require $333.5 million to meet
maturities of long-term debt in 1998, which we expect to meet with cash flow
from operations and issuance of replacement debt securities. Other capital
requirements will be met through a combination of sales of securities and
short-term borrowings.
Customer Service -- The Company has adopted a plan to improve customer
service, requiring an investment in excess of $100 million. Our plan includes:
o installing automated electric meters in metropolitan and inaccessible
rural and urban locations,
o installing a new work management system,
o making technological changes to enhance the Company's ability to handle
customer calls during power outages,
o installing mobile data dispatch technology in the Company's service
fleet, accompanied by digitized mapping of our service territory, and
o initiating both local and regional distribution line improvement
projects.
Expenditures in 1997 for these projects were approximately $23 million; future
expenditures are expected to be approximately $68 million in 1998 and $15
million in 1999. We anticipate funding these projects with cash flow from
operations.
14
Results of Operations
The following is a discussion of results of operations for the years ended
1997 as compared to 1996, and 1996 as compared to 1995.
1997 Compared to 1996
Revenue changed from the prior year primarily due to the following:
1997 1996
---------- ----------
(Millions)
Revenue -- Electric Service
Customer growth ...................... $ 55.8 $ 45.1
Weather .............................. (111.1) 4.4
Base rate variance ................... ( 18.7) (35.5)
Fuel rate variance ................... 44.1 (89.6)
Other retail, net .................... 47.7 41.5
-------- -------
Total retail ....................... 17.8 (34.1)
Other electric service ............... 11.0 (49.8)
-------- -------
Total electric service ............. 28.8 (83.9)
-------- -------
Revenue -- Other
Wholesale -- power marketing ......... 363.4 96.6
Natural gas .......................... 232.6 33.2
Other, net ........................... 33.3 23.1
-------- -------
Total revenue -- other ............. 629.3 152.9
-------- -------
Total revenue ..................... $ 658.1 $ 69.0
======== =======
Electric service revenue consists of sales to retail customers in our
service territory at rates authorized by the Virginia and North Carolina
Commissions and sales to cooperatives and municipalities at wholesale rates
authorized by FERC. The primary factors affecting this revenue in 1997 were
customer growth, weather, and fuel rates.
Customer growth -- There were 50,899 new customer connections to our system
in 1997, the largest number of new connections in any year since 1990. This
had the effect of increasing our sales by $55.8 million in 1997 over 1996.
Weather -- The mild weather in 1997 caused customers to use less
electricity for heating and cooling, which reduced revenue by approximately
$111.1 million from the previous year. Heating and cooling degree days were
as follows:
1997 1996 Normal
------------ ------------- -------
Cooling degree days ............................... 1,349 1,365 1,530
Percentage change compared to prior year .......... (1.2)% (18.1)%
Heating degree days ............................... 3,787 4,131 3,726
Percentage change compared to prior year .......... (8.3)% 9.0%
Fuel rates -- The increase in fuel rate revenues is primarily attributable
to higher fuel rates which went into effect December 1, 1996, increasing
recovery of fuel costs by approximately $48.2 million. The regulatory
commissions having jurisdiction over the Company allow us to charge
customers for the cost of fuel used in generating electricity.
Other revenue includes sales of electricity beyond our service territory,
natural gas, nuclear consulting services, energy management services and other
revenue. The growth in power marketing and natural gas sales revenue is
primarily due to our success at marketing electricity and natural gas beyond
our service territory. The Company began pursuing these new lines of business
in 1996. We expect that revenue from such non-traditional business activities
will continue to grow in the near future.
15
Kilowatt-hour sales changed as follows:
Increase
(Decrease) From
Prior Year
------------------------
1997 1996
------------ ---------
Residential ............................ ( 1.8)% 2.3%
Commercial ............................. 0.6 2.3
Industrial ............................. 2.1 2.3
Public authorities ..................... ( 4.7) 2.6
Total retail sales ..................... ( 0.5) 2.4
Wholesale -- system .................... 2.5 (24.3)
Wholesale -- power marketing ........... 196.0 200.3
Total sales ............................ 17.2 6.3
The decrease in retail kilowatt-hour sales in 1997 as compared to 1996 reflects
the impact of weather on our traditional electricity service business, despite
continued customer growth. The increase in wholesale kilowatt-hour sales was
primarily due to the Company's power marketing efforts.
Fuel, net increased as compared to 1996, primarily due to the cost of the
power marketing and natural gas sales which reflects increased purchases of
energy from other wholesale power suppliers and purchases of natural gas.
System energy output by energy source and the average fuel cost for each are
shown below. Fuel cost is presented in mills (one tenth of one cent) per
kilowatt hour.
1997 1996 1995
-------------------- -------------------- --------------------
Source Cost Source Cost Source Cost
-------- --------- -------- --------- -------- ---------
Nuclear (*) .................. 34% 4.52 32% 4.48 32% 4.92
Coal (**) .................... 40 13.54 38 14.32 39 14.44
Oil .......................... 1 26.32 1 27.75 1 25.11
Purchased power, net ......... 23 21.54 27 21.99 25 22.50
Other ........................ 2 30.65 2 26.98 3 23.82
-- -- --
Total ...................... 100% 100% 100%
=== === ===
Average fuel cost .......... 12.67 13.47 13.73
- ---------
(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power
Station.
(**) Excludes ODEC's 50 percent ownership interest in the Clover Power Station.
Other operations and maintenance increased as compared to 1996 as a result
of costs associated with the growth in sales by the Company's energy services
business unit. These higher costs were offset partially by a reduction in
expenses attributable to the Company's strategic initiatives. Expenses in 1996
include high storm damage costs resulting from destructive summer storms,
including Hurricane Fran.
Depreciation and amortization increased as compared to 1996 due to the
recognition of additional depreciation and nuclear decommissioning expense to
reflect adjustments in the Company's filing currently pending before the
Virginia Commission and higher depreciation expense related to Clover Unit 2,
which began operations in March 1996. See Future Issues -- Utility Rate
Regulation for additional information on current rate proceedings.
Restructuring expenses decreased as compared to 1996 as the Company nears
completion of its Vision 2000 strategic initiative. Charges for restructuring
primarily include employee severance costs, costs to restructure agreements to
purchase power from third parties and, when necessary, to negotiate settlement
and termination of these contracts, and other costs. The Company estimates that
staffing reductions will result in annual savings, in the range of $80 million
to $90 million. However, these savings are being offset by salary increases,
outsourcing costs and increased payroll costs associated with staffing for
growth opportunities. See also Note O to the CONSOLIDATED FINANCIAL STATEMENTS.
Accelerated cost recovery represents a reserve for potential adjustments
to regulatory assets. In this increasingly competitive environment, the Company
has concluded that it is appropriate to utilize available cost reductions, such
as those generated by the Vision 2000 program, to accelerate the write-off of
unamortized regulatory assets and potentially stranded costs (see Future Issues
- -- Competition).
16
1996 Compared to 1995
Electric service revenues decreased as compared to 1995 due to the effect
of mild weather on the Company's summer retail rates, which are designed to
reflect normal weather conditions. These revenues also were affected by reduced
sales to Old Dominion Electric Cooperative (ODEC) due to the completion of
Clover Units 1 and 2, of which ODEC owns a fifty percent interest.
Other revenues increased as compared to 1995 due to growth in our power
marketing and energy services business, which was organized as a distinct
business unit in 1996.
Fuel, net increased as compared to 1995, primarily as a result of
increased energy purchases associated with our power marketing sales, offset in
part by a higher recovery of fuel expenses subject to deferral accounting in
1995.
Operations and maintenance decreased slightly as compared to 1995,
primarily as a result of a reduction in expenses attributable to the Company's
strategic initiatives, offset partly by the high storm damage costs incurred in
1996 from destructive summer storms, including Hurricane Fran.
Depreciation and amortization increased as compared to 1995, primarily as
a result of greater nuclear decommissioning expense and depreciation related to
Clover Units 1 and 2, which were placed in service in October 1995 and March
1996, respectively.
Restructuring decreased as compared to 1995 as the implementation phase of
the Vision 2000 initiative continued. Restructuring charges in 1996 included
severance costs, costs to restructure or settle certain contracts to purchase
power and other costs. In addition, 1995 restructuring costs included one-time
charges to cancel specific capital projects and adjustments to inventory and
certain real estate to reflect adoption of changes in business strategies and
processes.
Accelerated cost recovery represents a provision for management's estimate
of a reserve that may ultimately be used to accelerate the write-off of
unamortized regulatory assets and potentially stranded costs (see Future Issues
- -- Competition).
Future Issues
Competition in the Electric Industry -- General
For most of this century, the structure of the electric industry in
Virginia and throughout the United States has been relatively stable. We have
recently seen, however, federal and state developments toward increased
competition. Electric utilities have been required to open up their
transmission systems for use by potential wholesale competitors. In addition,
non-utility power producers now compete with electric utilities in the
wholesale generation market. At the federal level, retail competition is under
consideration. Some states have enacted legislation requiring retail
competition.
Today, Virginia Power faces competition in the wholesale market.
Currently, there is no general retail competition in Virginia Power's principal
service area. To the extent that competition is permitted, Virginia Power's
ability to sell power at prices that allow it to recover its prudently incurred
costs may be an issue. See Future Issues -- Competition -- Exposure to
Potentially Stranded Costs.
In response to competition, Virginia Power has successfully renegotiated
long term contracts with wholesale and large federal government customers. In
addition, the Company has obtained regulatory approval of innovative pricing
proposals for large industrial customers. Rate concessions resulting from these
contract negotiations and innovative pricing proposals are expected to reduce
the Company's 1998 revenue by approximately $40 million. To date, the Company
has not experienced any material loss of load.
Virginia Power is actively participating in the legislative and regulatory
processes relating to industry restructuring. The Company has also responded to
these trends toward competition by cutting its costs, re-engineering its core
business processes, and pursuing innovative approaches to serving traditional
markets and future markets. In addition, a significant part of the Company's
strategy relies on developing "non-traditional" businesses within the Company's
business units and subsidiaries designed to provide growth in future earnings,
including:
o Energy Services -- offering electric energy and capacity in the emerging
wholesale market as well as natural gas, and other energy related products
and services;
o Fossil & Hydro -- targeting process type industries, such as chemical,
paper, plastics and petroleum to become a service provider of
instrumentation equipment;
o Nuclear Services -- offering management and operations services to other
electric utilities;
17
o Commercial Operations -- providing power distribution related services,
including transmission and distribution, engineering and metering services
to other gas, water and electric utilities; and
o Telecommunications -- offering telecommunications services through the
Company's existing fiber-optic network.
The Company's non-traditional businesses face competition from a variety
of utility and non-utility entities. In addition, Virginia Power may from time
to time identify and investigate opportunities to expand its markets through
strategic alliances with partners whose strengths, market position and
strategies complement those of the Company.
Competition -- Wholesale
During 1997, sales to wholesale customers represented approximately 17
percent of the Company's total revenues from electric sales. Approximately 73
percent of wholesale revenues resulted from the Company's power marketing
efforts.
In July 1997, Virginia Power filed amendments to its existing rate tariffs
with FERC so it could make wholesale sales at market-based rates. Under a FERC
order conditionally accepting the Company rates for filing, Virginia Power
began making market-based sales in 1997. FERC set for hearing in June 1998 the
issue of whether transmission constraints limiting the transfer of power into
the Company's service territory provide Virginia Power with generation
dominance in localized markets. If FERC finds transmission constraints give
Virginia Power generation dominance, it could revoke or limit the scope of the
Company's market-based rate authority.
Virginia Power has successfully negotiated a new power supply arrangement
with its largest wholesale customer. The new arrangement provides for a
transition from cost-based rates to market-based rates, subject to FERC
approval. Virginia Power estimates the reduced rates, offset in part by other
revenues which may be earned under the agreement, will decrease income before
taxes by approximately $38 million through 2005. Virginia Power anticipates
that additional contract negotiations with other wholesale customers will take
place in the future.
Competition -- Retail
Currently, Virginia Power has the exclusive right to provide electricity
at retail within its assigned service territories in Virginia and North
Carolina. As a result, Virginia Power now only faces competition for retail
sales if certain of its business customers move into another utility service
territory, use other energy sources instead of electric power, or generate
their own electricity. However, both Virginia and North Carolina are
considering implementing retail competition.
Competition -- Legislative Initiatives
Virginia: In the 1998 Session, the Virginia General Assembly passed House
Bill No. 1172 (HB1172) to establish a schedule for Virginia's transition to
retail competition in the electric utility industry. The Company actively
supported HB1172, which passed both houses of the General Assembly in amended
form and now awaits action by the Governor. HB1172 requires the following:
o establishment of one or more independent system operators (ISO) and one
or more regional power exchanges (RPX) for Virginia by January 1, 2001;
o deregulation of generating facilities beginning January 1, 2002;
o transition to retail competition to begin on January 1, 2002, with
retail competition to begin on January 1, 2004;
o recovery of just and reasonable net stranded costs; and
o appropriate consumer safeguards related to stranded costs and
consideration of stranded benefits.
If HB1172 becomes law, it will become effective July 1, 1998. While the
bill establishes a timeline for the transition to competition in Virginia, a
detailed plan to implement that transition must be developed through future
legislative and regulatory action. The Company is unable at this time to
predict its timing or details.
Federal: The U.S. Congress is expected to consider federal legislation in
the near future authorizing or requiring retail competition. Virginia Power
cannot predict what, if any, definitive actions the Congress may take.
North Carolina: The 1997 Session of the North Carolina General Assembly
created a Study Commission on the Future of Electric Service in North Carolina.
An interim report is expected in 1998 with final recommendations made to the
1999 session of the North Carolina General Assembly.
18
Competition -- Regulatory Initiatives
The Virginia Commission also has been actively interested in industry
restructuring and competition, as shown in the following generic and
utility-specific proceedings.
In 1995, the Commission instituted an ongoing generic investigation on
restructuring, resulting in a number of reports by its Staff covering such
issues as retail wheeling experiments and the status of wholesale power
markets.
In November 1996, the Commission ordered Virginia Power to file studies
and reports on possible restructuring of the electric industry in Virginia. The
Commission also invited Virginia Power to submit a proposed alternative
regulation plan with its filing. A two-phase alternative regulatory plan (ARP)
was filed March 1997. During Phase I (1997 to December 2002), Virginia Power
proposed implementing a freeze of its current base rates and devoting a portion
of earnings above a 11.5% return-on-equity to accelerate the write-off of
generation-related regulatory assets and to mitigate the costs associated with
payments under power purchase contracts with non-utility generators that may be
above market if competition is authorized in Virginia. During Phase II (beyond
December 31, 2002), Virginia Power would seek Commission approval of stranded
cost recovery if retail competition is implemented in Virginia and a transition
cost charge mechanism by which stranded costs would be recovered. Virginia
Power presented illustrative estimates of stranded costs based on hypothetical
market prices as part of its Phase II filing. When the Company filed its ARP,
the Commission consolidated its consideration of the ARP with its consideration
of the Company's 1995 Annual Information Filing. For a discussion of the 1995
Annual Information Filing, See Future Issues -- Utility Rate Regulation.
In November 1997, the Commission Staff issued its report to the General
Assembly calling for a cautious, two-phase, five-year period to address
restructuring issues. The report acknowledged the need for direction from the
Virginia legislature concerning policy issues surrounding competition in the
electric industry. Virginia Power sought to withdraw its ARP in December 1997,
having concluded that resolution of the cost recovery issues raised by the ARP
was unlikely without General Assembly action. The Commission has agreed that
the Company may withdraw its support of the ARP, but has reserved the right to
continue consideration of the ARP as well as other regulatory alternatives. In
addition, the Commission will continue to consider the issues arising out of
the 1995 Annual Informational Filing (See Future Issues -- Utility Rate
Regulation).
Competition -- SFAS 71
Virginia Power's regulated rates are designed to recover its prudently
incurred costs of providing service, including the opportunity to earn a
reasonable return on its shareholder's investment. The Company's financial
statements reflect assets and costs under this cost-based rate regulation in
accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71),
"Accounting for the Effects of Certain Types of Regulation." SFAS 71 provides
that certain expenses normally reflected in income are deferred on the balance
sheet as regulatory assets and are recognized as the related amounts are
included in rates and recovered from customers. Continued accounting under SFAS
71 requires that rates designed to recover the utility's specific costs of
providing service, are, and will continue to be, established by regulators. The
presence of increasing competition that limits the utility's ability to charge
rates that recover its costs, or a change in the method of regulation with the
same effect, could result in the discontinued applicability of SFAS 71.
Rate-regulated companies are required to write off regulatory assets
against earnings whenever those assets no longer meet the criteria for
recognition as defined by SFAS 71. In addition, SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
requires a review of long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Thus, events or changes in circumstances that cause the
discontinuance of SFAS 71, and write off of regulatory assets, may also require
a review of utility plant assets for possible impairment. If such review
indicates utility plant assets are impaired, the carrying amount of the
affected assets would be written down. This would result in a loss being
charged to earnings, unless recovery of the loss is provided through operations
that remain regulated.
Virginia Power's regulated operations currently satisfy the SFAS 71
criteria. However, if events or circumstances should change so that those
criteria are no longer satisfied, management believes that a material adverse
effect on the Company's results of operations and financial position may
result. The form of cost-based rate regulation under which Virginia Power
operates is likely to evolve as a result of various legislative or regulatory
initiatives. At this time, management can predict neither the ultimate outcome
of regulatory reform in the electric utility industry nor the impact such
changes would have on Virginia Power.
19
Competition -- Exposure to Potentially Stranded Costs
Under traditional cost-based regulation, utilities have generally had an
obligation to serve supported by an implicit promise of the opportunity to
recover prudently incurred costs. The most significant potential adverse effect
of competition is "stranded costs." Stranded costs are those costs incurred or
commitments made by utilities under cost-based regulation that may not be
reasonably expected to be recovered in a competitive market.
The Company's potential exposure to stranded costs is comprised of the
following:
o long-term purchased power contracts that may be above market (see Note Q
to the CONSOLIDATED FINANCIAL STATEMENTS);
o costs pertaining to certain generating plants that may become uneconomic
in a deregulated environment;
o regulatory assets for items such as income tax benefits previously
flowed-through to customers, deferred losses on reacquired debt and other
costs; (see Note F to the CONSOLIDATED FINANCIAL STATEMENTS); and
o unfunded obligations for nuclear plant decommissioning and postretirement
benefits not yet recognized in the financial statements (see Notes C and N
to the CONSOLIDATED FINANCIAL STATEMENTS).
Any forecast of potentially stranded costs is extremely sensitive to the
various assumptions made. Such assumptions include:
o the timing and extent of customer choice in the market for electric
service;
o estimates of future competitive market prices;
o sales and load growth forecasts;
o power stations' future operating performance;
o rate revenues permitted during the transition;
o estimated costs of utility operations over time;
o mitigation opportunities;
o stranded cost recovery mechanisms and other factors.
Certain combinations of these assumptions as applied to Virginia Power
would produce little to no stranded costs; under other scenarios Virginia
Power's exposure to potentially stranded costs could be substantial.
Virginia Power has assessed the reasonableness of various possible
assumptions, but has not been able to settle on any particular combination
thereof. Thus, the Company's maximum exposure to potentially stranded costs is
uncertain. Management believes that recovery of any potentially stranded costs
is appropriate and will vigorously pursue such recovery with the regulatory
commissions having jurisdiction over its operations. However, Virginia Power
cannot predict the extent to which such costs, if any, will be recoverable from
customers. Also, in an effort to mitigate the amount at risk, the Company will
continue to implement cost reduction measures.
Utility Rate Regulation
In March 1997, the Virginia Commission issued an order that Virginia
Power's base rates be made interim and subject to refund as of March 1, 1997.
This order was the result of the Commission Staff's report on its review of
Virginia Power's 1995 Annual Informational Filing, which concluded that
Virginia Power's present rates would cause Virginia Power to earn in excess of
its authorized return on equity. The Staff found that, for purposes of
establishing rates prospectively, a rate reduction of $95.6 million (including
a one-time adjustment of $29.7 million to Virginia Power's deferred capacity
balance at December 31, 1996) may be necessary in order to realign rates to the
authorized level. Virginia Power filed its ARP in March 1997, based on 1996
financial information. Subsequently, the Commission consolidated the proceeding
concerned with the 1995 Annual Informational Filing with the proceeding that
includes the ARP proposed by the Company.
In December 1997, Virginia Power sought to withdraw its ARP, having
concluded that resolution of the cost recovery issues raised by the ARP was
unlikely without General Assembly action. The Commission has agreed that the
Company may withdraw its support of the ARP but has reserved the right to
continue consideration of the ARP as well as other regulatory alternatives. In
addition, the Commission will continue to consider the issues arising out of
the 1995 Annual Informational Filing. The Commission's Staff is scheduled to
file its testimony on March 24, 1998; Virginia Power's rebuttal is to be filed
by April 27, 1998; and the reply testimony is to be filed by May 11, 1998. A
public hearing is scheduled to commence on May 19, 1998.
Virginia Power's previous filings in this proceeding support maintaining
the Company's rates at current levels; however, opposing parties have made
filings recommending rate reductions in excess of $200 million. At this time,
management cannot predict the ultimate outcome of the proceeding and its impact
on the Company's results of operations, cash flows or financial position.
20
Utility Operations
The Company strives to operate its generating facilities in accordance
with prudent utility industry practices and in conformity with applicable
statutes, rules and regulations. Like other electric utilities, the Company's
generating facilities are subject to unanticipated or extended outages for
repairs, replacements or modification of equipment or otherwise to comply with
regulatory requirements. Such outages may involve significant expenditures not
previously budgeted, including replacement energy costs.
On September 10, 1997, the NRC published a proposed rule for financial
assurance requirements related to nuclear decommissioning. If the NRC's
proposed rule were implemented without further clarification or modification,
the Company may have to either pre-fund or provide acceptable security for a
portion of its nuclear decommissioning obligation. See Note C to the
CONSOLIDATED FINANCIAL STATEMENTS.
Environmental Matters
The Company is subject to rising costs resulting from a steadily
increasing number of federal, state and local laws and regulations designed to
protect human health and the environment. These laws and regulations affect
future planning and existing operations. They can result in increased capital,
operating and other costs as a result of compliance, remediation, containment
and monitoring obligations of the Company. These costs have been historically
recovered from customers through utility rates. However, to the extent that the
regulatory environment departs from cost-based rates, the Company's results of
operations and financial condition could be adversely impacted.
Environmental Protection and Monitoring Expenditures
The Company incurred $70.4 million, $71.1 million and $68.3 million
(including depreciation) during 1997, 1996 and 1995, respectively, in
connection with the use of environmental protection facilities and expects
these expenses to be approximately $69.1 million in 1998. In addition, capital
expenditures to limit or monitor hazardous substances were $24.6 million, $22.4
million and $23.4 million for 1997, 1996 and 1995, respectively. The amount
estimated for 1998 for these expenditures is $10.0 million.
Clean Air Act Compliance
The Clean Air Act, as amended in 1990, requires the Company to reduce its
emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx). The Clean Air Act
also requires the Company to obtain operating permits for all major emissions-
emitting facilities. Permit applications have been submitted for the Company's
power stations located in North Carolina and West Virginia. Applications for
the Company's power stations located in Virginia will be filed in 1998.
The Clean Air Act's SO2 reduction program is based on the issuance of a
limited number of SO2 emission allowances, each of which may be used as a
permit to emit one ton of SO2 into the atmosphere or may be sold to someone
else. The program is administered by the EPA. The Company's compliance plans
may include switching to lower sulfur coal, purchase of emission allowances and
installation of SO2 control equipment. Maximum flexibility and least-cost
compliance will be maintained through annual studies.
The Company began complying with Clean Air Act Phase I NOx limits at eight
of its units in Virginia in 1997, three years earlier than otherwise required.
As a result, the units will not be subject to more stringent Phase II limits
until 2008. Furthermore, in order to avoid the necessity of more stringent
regulations, the Company made voluntary commitments in 1996 to cap NOx
emissions at its Chesterfield and Yorktown Power Stations and the Chesapeake
Energy Center during the ozone season beginning in 2000.
From 1994 through 1997, the Company invested more than $160 million to
install and upgrade SO2 and NOx emission control equipment at its Mt. Storm and
Possum Point power stations. Capital expenditures related to Clean Air Act
compliance over the next five years are projected to be approximately $40
million. Changes in the regulatory environment, availability of allowances, and
emissions control technology could substantially impact the timing and
magnitude of compliance expenditures.
In November 1997, the EPA proposed new requirements for 22 states,
including North Carolina, Virginia and West Virginia, to reduce and cap
emissions of NOx. The EPA will issue a final rule by September 1998. Although
the proposal allows each state to determine how to achieve the required
reduction in emissions, the caps were calculated based on emission limits for
utility boilers. If the states in which Virginia Power operates choose to
impose this limit, major additional emission control equipment, with attendant
significant capital and operating costs, could be required.
21
Global Climate Change
In 1993, the United Nation's Global Warming Treaty became effective. The
objective of the treaty is the stabilization of greenhouse gas concentrations
at a level that would prevent man-made emissions from interfering with the
climate system.
As a continuation of the effort to limit man-made greenhouse emissions, an
international Protocol was formulated on December 10, 1997, in Kyoto, Japan.
This Protocol calls for the United States to reduce greenhouse emissions by 7
percent from 1990 baseline levels by the period 2008-2012. The Protocol will
not constitute a binding commitment unless submitted to and approved by the
United States Senate. Emission reductions of the magnitude included in the
Protocol, if adopted, would likely result in a substantial financial impact on
companies that consume or produce fossil fuel-derived electric power, including
Virginia Power.
Recently Issued Accounting Standards
During 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income," and SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." Each of these statements is effective for
fiscal years beginning after December 15, 1997. At this time, the Company does
not expect the implementation of these standards to have a material impact on
its results of operations or financial position.
Year 2000 Compliance
Virginia Power is taking an aggressive approach regarding computer issues
associated with the onset of the new millenium -- specifically, the impact of
the possible failure of computer systems and computer-driven equipment due to
the rollover to the year 2000. The year 2000 problem is pervasive and complex
as virtually every computer operation could be affected in some way by the
rollover of the two-digit year value from 99 to 00. The issue is whether
computer systems will properly recognize date-sensitive information when the
year changes to 2000. Systems that do not properly recognize such information
could generate erroneous data or fail.
If not properly addressed, the year 2000 computer problem could result in
failures in computer systems in the Company and the computer systems of third
parties with which the Company transacts business. Such failures of the
Company's or third parties' computer systems could have a material impact on
the Company's ability to conduct business.
Since January 1997, the Company has organized a formal year 2000 project
team to identify, correct or reprogram and test its systems for year 2000
compliance. At this time, the project team has completed its preliminary
assessment. Based on the team's evaluation, the costs of testing and conversion
of system applications are projected to be within the range of $30 million to
$50 million. The range is a function of our ongoing evaluation as to whether
certain systems and equipment will be corrected or replaced, which is dependent
on information yet to be obtained from suppliers and other external sources.
Maintenance or modification costs will be expensed as incurred, while the costs
of new software and hardware will be capitalized and amortized over the asset's
useful life.
At this time, Virginia Power is actively pursuing solutions to its year
2000-related computer problems in order to ensure that foreseeable situations
related to Company computer systems are effectively addressed. The Company
cannot estimate or predict the potential adverse consequences, if any, that
could result from a third party's failure to effectively address this issue.
Market Rate Sensitive Instruments and Risk Management
Virginia Power is subject to market risk as a result of its use of various
financial instruments and derivative commodity instruments. Interest rate risk
generally is associated with the Company's outstanding debt, preferred stock
and trust-issued securities. The Company also is exposed to interest rate risk
as well as equity price risk as a result of its nuclear decommissioning trust
investments in debt and equity securities.
The Company's wholesale power group is involved in trading activities
which use derivative commodity instruments. However, the fair value of such
instruments at December 31, 1997, is not material to the Company's financial
position. Also, the potential near term losses in future earnings, fair values,
or cash flows, resulting from reasonably possible near term changes in market
prices for such instruments are not anticipated to be material to the Company's
results of operations, financial position or cash flows.
22
The following analysis does not include the price risks associated with
the nonfinancial assets and liabilities of utility operations, including
underlying fuel requirements.
Interest-rate risk
Virginia Power uses both fixed rate and variable rate debt and preferred
securities as sources of capital. The following table presents the financial
instruments that are held or issued by the Company at December 31, 1997, and
are sensitive to interest rate changes in some way. Weighted average variable
rates are based on implied forward rates derived from appropriate annual spot
rate observations as of December 31, 1997.
Expected Maturity Date
--------------------------------------------------------------- Fair
1998 1999 2000 2001 2002 Thereafter Total Value
---------- --------- --------- --------- --------- ------------ ----------- -----------
(Millions of Dollars, Except Percentages)
ASSETS
Nuclear decommissioning
trust investments ............. $ 17.7 $ 5.3 $ 2.1 $ 7.1 $ 3.1 $ 165.0 $ 200.3 $ 190.7
Average interest rate (1) ..... 5.5% 5.5% 5.5% 5.5% 5.5% 5.5%
LIABILITIES -- Fixed rate
Mortgage bonds .................. 225.0 100.0 135.0 100.0 255.0 2,009.5 2,824.5 2,937.7
Average interest rate ......... 6.7% 8.9% 5.9% 6.0% 4.5% 7.6%
Medium term notes ............... 108.5 221.0 60.5 60.6 60.0 40.5 551.1 573.7
Average interest rate ......... 7.6% 8.5% 9.7% 8.4% 7.6% 9.0%
Tax-exempt financing ............ 10.0 10.0 10.4
Average interest rate ......... 5.2%
Short-term debt ................. 226.2 226.2 226.2
Average interest rate ......... 5.9%
Preferred stock, subject to
mandatory redemption ............ 180.0 180.0 186.6
Average dividend rate ......... 6.2%
Mandatorily redeemable
trust-issued preferred
securities ...................... 135.0 135.0 137.7
Average dividend rate ......... 8.1%
LIABILITIES -- Variable rate
Tax-exempt financing (2) ........ 488.6 488.6 488.6
Average interest rate ......... 4.1%
- ---------
(1) Rates are based on average yield for entire portfolio at December 31, 1997.
(2) Interest rates on the tax-exempt bonds are based on short-term, tax-exempt
market rates and are reset for periods of one to 270 days in length. The
Company has the option to convert these bonds to fixed rate securities
upon 40 days written notice. See Note H to the CONSOLIDATED FINANCIAL
STATEMENTS.
Equity price risk
The following table presents a description of marketable equity securities
held by the Company at December 31, 1997. As prescribed by Statement of
Financial Accounting Standards No. 115, "Accounting for Certain Investments in
Debt and Equity Securities," these securities are reported on the balance sheet
at fair value.
Fair
Cost Value
------------ ------------
(Millions of Dollars)
Nuclear decommissioning trust investments ......... $ 219.4 $ 360.4
23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Page
No.
-----
Report of Management ......................................................... 25
Report of Independent Auditors ............................................... 26
Consolidated Statements of Income for the years ended
December 31, 1997, 1996 and 1995 ............................................ 27
Consolidated Balance Sheets at December 31, 1997 and 1996 .................... 28
Consolidated Statements of Earnings Reinvested in Business for the years ended
December 31, 1997, 1996 and 1995 ....................................