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<SEC-DOCUMENT>0000916641-01-000361.txt : 20010321
<SEC-HEADER>0000916641-01-000361.hdr.sgml : 20010321
ACCESSION NUMBER: 0000916641-01-000361
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 7
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010320
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: DOMINION RESOURCES INC /VA/
CENTRAL INDEX KEY: 0000715957
STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911]
IRS NUMBER: 541229715
STATE OF INCORPORATION: VA
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-08489
FILM NUMBER: 1572390
BUSINESS ADDRESS:
STREET 1: 120 TREDEGAR STREET
STREET 2: P O BOX 26532
CITY: RICHMOND
STATE: VA
ZIP: 23219
BUSINESS PHONE: 8048192000
MAIL ADDRESS:
STREET 1: P O BOX 26532
STREET 2: 901 EAST BYRD STREET
CITY: RICHMOND
STATE: VA
ZIP: 23261
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>0001.txt
<DESCRIPTION>FORM 10-K405
<TEXT>
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------
FORM 10-K
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2000
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 1-8489
----------------
DOMINION RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Virginia 54-1229715
(I.R.S. Employer Identification Number)
(State or other jurisdictionof
incorporation or organization)
120 Tredegar Street 23219
Richmond, Virginia
(Address of principal executive (Zip Code)
offices)
(804) 819-2000
(Registrant's telephone number, including area code)
----------------
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
Name of Each Exchange
Title of Each Class on Which Registered
------------------- -----------------------
<S> <C>
Common Stock, no par value New York Stock Exchange
Corporate Premium Income Equity Securities New York Stock Exchange
8.4% Trust Preferred Securities New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
None
----------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of the
registrant was over $16.0 billion based on the closing price of our Common
Stock on March 2, 2001, as reported on the composite tape by the Wall Street
Journal.
Indicate the number of shares outstanding of each registrant's class of
common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
Outstanding at
Class March 2, 2001
----- --------------
<S> <C>
Common Stock, no par value 246,420,761
</TABLE>
DOCUMENTS INCORPORATED BY REFERENCE.
(a) Portions of the 2000 Annual Report to Shareholders for the fiscal year
ended December 31, 2000 are incorporated by reference in Parts I, II and IV
hereof.
(b) Portions of the 2001 Proxy Statement, dated March 16, 2001, are
incorporated by reference in Part III hereof.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
DOMINION RESOURCES, INC.
<TABLE>
<CAPTION>
Item Page
Number Number
- ------ ------
<S> <C> <C>
PART I
1. Business........................................................ 3
The Company...................................................... 3
Legal Structure and Principal Legal Subsidiaries............... 3
Organizational Changes......................................... 4
Competition...................................................... 4
Electric Industry.............................................. 4
Gas Industry................................................... 5
Regulations...................................................... 7
Separation of Electric Generation and Delivery Operations in
Virginia...................................................... 7
Regional Transmission Entities/Regional Transmission
Organizations................................................. 8
Retail Access Pilot Program.................................... 8
Wholesale Markets.............................................. 8
Environmental Matters.......................................... 9
Nuclear Generation............................................. 9
Rates............................................................ 10
Electric....................................................... 10
Gas............................................................ 11
Financial Information about Segments and Geographic Areas........ 11
Sources of Energy................................................ 11
Sources of Energy--Electricity................................. 11
Sources of Energy--Gas......................................... 14
Future Sources of Energy......................................... 15
Cautionary Factors That May Affect Future Results................ 16
2. Properties...................................................... 16
3. Legal Proceedings............................................... 19
4. Submission of Matters to a Vote of Security Holders............. 21
Executive Officers of the Registrant............................. 21
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................... 23
6. Selected Financial Data......................................... 23
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 23
7A. Quantitative and Qualitative Disclosures About Market Risk..... 23
8. Financial Statements and Supplementary Data..................... 23
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 23
PART III
10. Directors and Executive Officers of the Registrant............. 24
11. Executive Compensation......................................... 24
12. Security Ownership of Certain Beneficial Owners and
Management........................................................ 24
13. Certain Relationships and Related Transactions................. 24
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-
K................................................................. 25
</TABLE>
2
<PAGE>
PART I
ITEM 1. BUSINESS
THE COMPANY
Dominion Resources, Inc. (Dominion or the Company) is a fully integrated gas
and electric holding company headquartered in Richmond, Virginia. Our principal
assets are located in the Northeast quadrant of the United States, which is an
area we call MAIN to Maine. In the power industry, "MAIN" means the Middle
American Interconnected Network, which comprises the states of Missouri,
Illinois, Wisconsin, Michigan and Indiana. The MAIN to Maine region is home to
approximately 40% of the nation's demand for energy. It also has some of the
nation's highest energy prices and, as a result, is rapidly moving toward
industry deregulation and restructuring. Our acquisition of Consolidated
Natural Gas Company (CNG), completed in early 2000, substantially increased our
concentration of assets and customers in this region.
As a result of our acquisition of CNG, Dominion is a registered public
utility holding company subject to the provisions of the Public Utility Holding
Company Act of 1935 (the 1935 Act). CNG also continues to be a registered
holding company under the 1935 Act.
With the acquisition of CNG, Dominion began managing its business through
three principal segments that integrate its electric and gas services,
streamline operations, and position Dominion for long-term growth in the
competitive marketplace.
. Dominion Energy--Dominion Energy manages our 19,000-megawatt generation
portfolio, our 7,600 miles of gas transmission pipeline, and a 959
billion cubic foot natural gas storage network. It also guides our
generation growth strategy and our commodity trading, marketing, and risk
management activities. We currently operate generation facilities in
Virginia, West Virginia, North Carolina and Illinois. Dominion Energy
will also include the 1,954-megawatt Millstone Nuclear Power Station,
which we expect to acquire this year.
. Dominion Delivery--Dominion Delivery manages our local electric and gas
distribution systems serving nearly 3.8 million customers, our 6,000
miles of electric transmission lines and our customer service operations.
We currently operate transmission and distribution systems in Virginia,
West Virginia, North Carolina, Pennsylvania and Ohio. Dominion Delivery
also includes our interest in Dominion Telecom with its 3,600 route-mile
fiber optic network and related telecommunications and advanced data
services.
. Dominion Exploration & Production--Dominion Exploration & Production
(Dominion E&P) manages our onshore and offshore oil and gas exploration
and production activities. With approximately 2.8 trillion cubic feet of
natural gas equivalent reserves and an annual production capacity
exceeding 300 billion cubic feet, Dominion E&P is one of the nation's
largest independent oil and gas operators. We operate on the outer
continental shelf and deepwater areas of the Gulf of Mexico, western
Canada, the Appalachian Basin and other selected regions in the
continental United States.
While Dominion manages its daily operations as described above, its assets
remain wholly-owned by its legal subsidiaries, which are described below in
Legal Structure and Principal Legal Subsidiaries. For additional financial
information on business segments, see Note 27 to the Consolidated Financial
Statements on page 68 of the 2000 Annual Report.
Legal Structure and Principal Legal Subsidiaries
Dominion was incorporated in 1983 as a Virginia corporation. Dominion and
its subsidiaries had approximately 15,600 full-time employees as of December
31, 2000. Our principal office is located at 120 Tredegar Street, Richmond,
Virginia 23219, telephone (804) 819-2000. Dominion's principal direct legal
3
<PAGE>
subsidiaries are Virginia Electric and Power Company (Virginia Power) a
regulated public utility engaged in the generation, transmission, distribution
and sale of electric energy in Virginia and northeastern North Carolina and
Consolidated Natural Gas Company (CNG), a producer, transporter, distributor
and retail marketer of natural gas, serving customers in Pennsylvania, Ohio,
Virginia, West Virginia, New York and other cities focused in the Northeast and
Mid-Atlantic regions of the United States. Our other major subsidiaries are
Dominion Energy, Inc. (DEI), Dominion's independent power and natural gas
subsidiary, and Dominion Capital, Inc. (DCI), our diversified financial
services company.
Our legal structure is not currently the same as the operating segments we
use to manage our business. The functional separation of Virginia Power's
regulated and unregulated businesses described elsewhere in this report may,
with regulatory approval, provide us with the opportunity to realign our legal
structure with our operating segments.
Organizational Changes
On January 28, 2000, Dominion completed its acquisition of CNG. The
combination with CNG, based in Pittsburgh, Pennsylvania, creates a fully
integrated electric and natural gas utility in the Midwest, Northeast and Mid-
Atlantic regions of the United States.
As a result of the acquisition of CNG, we became a registered public utility
holding company under the 1935 Act. The 1935 Act imposes a number of
restrictions on the operations of registered holding company systems, one of
which limits our ability to engage in activities unrelated to our utility
operations or other energy related businesses. As part of the Securities and
Exchange Commission (SEC) order approving the acquisition under the 1935 Act,
Dominion must divest itself of DCI within three years. During the approval
process, Dominion and CNG also agreed to divest Virginia Natural Gas, Inc.
(VNG), CNG's gas distribution subsidiary located in Virginia Beach, Virginia.
In October 2000, Dominion completed the sale of VNG to AGL Resources Inc.
As we build our geographically focused business, we are also divesting our
assets outside of the targeted MAIN to Maine region. We have divested all of
our Latin American assets, including the Argentine assets of CNG. We completed
our exit from the United Kingdom during 2000 with the sale of our 80% interest
in the Corby Power Station, and we are actively exploring the sale of CNG's
remaining international operations in Australia.
As part of the acquisition of CNG, Dominion created a subsidiary service
company, Dominion Resources Services, Inc. (Services), which provides certain
services to Dominion's operating subsidiaries. During 2000, CNG also had a
service company, CNG Services, Inc. Effective January 1, 2001, the two service
companies were combined into one service company.
For additional information regarding the acquisition of CNG and our exit
strategy for certain DCI businesses, see Notes 5 and 6 to Consolidated
Financial Statements on pages 46 through 49 of the 2000 Annual Report.
COMPETITION
Our Dominion Energy and Dominion Delivery segments are each affected by the
increasing momentum towards deregulation in both the electric and gas
industries. In addition to the restructuring of the gas industry, the emerging
unbundling of services provided by electric utilities is leading toward the
convergence of the two industries to create one overall, highly competitive
marketplace for a customer's total energy needs.
Electric Industry
The structure of the electric industry in our service territory and
throughout the United States has been relatively stable for many years.
Recently, however, there have been both federal and state developments in
4
<PAGE>
restructuring regulation and increasing competition. Electric utilities are
required to open up their transmission systems for non-discriminatory use by
wholesale competitors. In addition, non-utility power marketers now compete
with electric utilities in the wholesale generation market. Although progress
varies, pro-competition electric legislation is under consideration in many
states. In Virginia, legislation was passed in 1999 which will phase in
customer choice between 2002 and 2004. In Ohio, legislation was enacted in 1999
which allowed consumers to choose their electric supplier beginning January 1,
2001. In Pennsylvania, all consumers may now choose their electric supplier.
Regulators and legislators in West Virginia and North Carolina are also
debating issues related to electric industry restructuring.
Because competition has not yet been fully phased-in and electric services
have not been unbundled in Virginia, competition issues affect both our
Dominion Energy and Dominion Delivery segments as a whole and do not lend
themselves to discussion on a segment basis. The following discussion relates
to competition as it affects our electricity operations in Virginia and North
Carolina.
Historically, our electric utility subsidiary has had the exclusive right to
provide electricity at retail within its assigned service territories in
Virginia and North Carolina. As a result, our Company's exposure to competition
for retail electric sales was limited to the extent our customers moved into
another utility service territory, used other energy sources instead of
electric power, or generated their own electricity. However, during 1998 and
1999, legislation was passed in Virginia that established plans to restructure
Virginia's electric utility industry and provided for a phased-in transition to
a fully competitive retail electric market during the period January 1, 2002
through January 1, 2004 (deregulation legislation). Complying with this
deregulation legislation, we established a retail choice pilot program that is
currently in place for sales of electricity within our Virginia service
territory.
We continue to participate actively in both the legislative and regulatory
processes relating to industry restructuring in an effort to ensure an orderly
transition from a regulated environment. We have also responded to the trends
toward competition by cutting costs, re-engineering our core business
processes, and pursuing innovative approaches to serving traditional and future
markets. In addition, we are developing certain "non-traditional" products and
services in an effort to provide growth in future earnings.
See Deregulation Legislation--Electric Industry under Management's
Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
on page 35 of the 2000 Annual Report.
Gas Industry
Dominion Delivery
Dominion has taken steps to offer choices to its gas customers in
Pennsylvania. As early as 1984, large industrial customers in Pennsylvania
began to buy natural gas supplies from third parties, rather than directly from
local utilities; the local distributors transported these third-party gas
supplies to the industrial facilities. Since that time, nearly all of our
Pennsylvania industrial and large commercial customers have changed from being
utility sales customers to transportation services customers, buying the
natural gas commodity from unregulated suppliers and transporting it on our gas
delivery network. In 1997, Dominion's Pennsylvania gas utility subsidiary
voluntarily launched an Energy Choice program for all of its retail consumers
in Pennsylvania--whether industrial, commercial, or residential. Subsequently,
in 1999, Pennsylvania enacted legislation to mandate supplier choice for
residential and small commercial customers. At December 31, 2000, approximately
106,000 customers had opted for Energy Choice in our Company's Pennsylvania
service area.
Large industrial customers in Ohio began to source their own natural gas
supplies in the mid-1980's, as interstate pipeline transportation services
became more widely available. However, to date, Ohio has not enacted
legislation to require supplier choice for residential and commercial natural
gas consumers. Dominion has made significant progress in offering Energy Choice
to customers on its own initiative, in cooperation with The Public Utilities
Commission of Ohio. In 1997, Dominion's Ohio gas utility subsidiary launched a
pilot
5
<PAGE>
program, designed to make gas transportation service available to residential
and small commercial customers, and to the suppliers that market gas to these
customer classes. In 2000, the Energy Choice program was expanded to all 1.2
million customers in Dominion's Ohio service area. At December 31, 2000,
approximately 175,000 of Dominion's Ohio customers were participating in this
open-access program.
At this time, West Virginia has not enacted legislation to require customer
choice in its retail natural gas markets. In this smaller, more rural market
area, Dominion has not voluntarily initiated an Energy Choice program. However,
the West Virginia Public Service Commission recently issued regulations to
govern pooling services; these services are one of the tools that natural gas
suppliers may utilize to provide retail customer choice in the future.
Dominion Energy
Dominion has taken advantage of selected market expansion opportunities,
concentrating its efforts primarily in the Northeast and along the East Coast.
Dominion's large underground storage capacity and the location of its gridlike
pipeline system as a link between the country's major gas pipelines and large
markets on the East Coast have been key factors in the success of these
expansion efforts. The Company's pipelines are part of an interconnected gas
transmission system which will continue to enable retail end users to take
advantage of the accessibility of supplies nationwide as gas utilities unbundle
services at the retail level.
Dominion competes with domestic as well as Canadian pipeline companies and
gas marketers seeking to provide or arrange transportation, storage and other
services for customers. Also, certain end users have the ability to switch to
fuel oil or coal if desired. Although competition is based primarily on price,
the array of services that can be provided to customers is also an important
factor. The combination of capacity rights held on certain longline pipelines,
a large storage capability and the availability of numerous receipt and
delivery points along its own pipeline system enables Dominion to tailor its
services to meet the individual needs of customers.
Dominion Exploration & Production
Exploration and production operations are conducted by the Company in
several major gas and oil producing basins in the United States, both onshore
and offshore, and Canada. In this highly competitive business, the Company
competes with a large number of entities ranging in size from large
international oil companies with extensive financial resources to small, cash
flow driven independent producers.
Dominion faces significant competition in the bidding for federal offshore
leases and in obtaining leases and drilling rights for onshore properties.
Since Dominion is the operator of a number of properties, it also faces
competition in securing drilling equipment and supplies for exploration and
development.
From the production perspective, the marketing of gas and oil is highly
competitive with price being the most significant factor. Gas producers
throughout the industry, including Dominion, face a diverse and active market
with purchasers seeking to balance the advantage of flexible spot market
supplies with the security of longer-term contracts. The growth of gas and
energy marketing firms has added to the competition for Dominion. When the
economics warrant, the Company attempts to sell its gas production under long-
term contracts to customers such as electric power generators and others that
require a secure source of supply. However, these arrangements represent only a
portion of the Company's gas production. Further, the deliverability of gas
produced is influenced by competition for downstream pipeline transportation
capacity. The Company continues to develop marketing strategies, contracts and
arrangements to address customer needs for intermediate and long-term gas
supplies as well as swing, peaking and other energy services. In addition, in
the ordinary course of business, Dominion participates in price risk management
activities to manage exposure to price risk in connection with the production
and sale of natural gas and oil.
6
<PAGE>
REGULATION
General
Many aspects of our business are presently subject to regulation by the SEC,
the Federal Energy Regulatory Commission (FERC), the Environmental Protection
Agency (EPA), Department of Energy (DOE), the Nuclear Regulatory Commission
(NRC), the Army Corps of Engineers, and other federal, state and local
authorities.
The Virginia State Corporation Commission (Virginia Commission) and the
North Carolina Utilities Commission (the North Carolina Commission) regulate
our bundled rates for retail electric sales in those states and FERC approves
our rates for electric sales to wholesale customers. While our electric utility
subsidiary holds certificates of public convenience and necessity authorizing
it to construct and operate its electric facilities now in operation and to
sell electricity to customers, it 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 government agencies.
As discussed above in COMPETITION--Electric Industry, deregulation
legislation has been enacted in Virginia. Under the deregulation legislation,
Dominion's electric utility subsidiary is required to join or establish a
regional transmission entity, establish a retail access pilot program and
submit to the Virginia Commission a plan for separating its generation and and
delivery operations.
Certain subsidiaries of CNG are subject to the Natural Gas Act of 1938, as
amended. Our interstate gas transportation and storage activities are regulated
under such Act and are conducted in accordance with certificates, tariffs and
service agreements on file with FERC. Other CNG subsidiaries are subject to
various provisions of the five statutes that are referred to as the National
Energy Act of 1978. One of these statutes, the National Energy Conservation
Policy Act, requires utilities to offer home energy audits and other assistance
to residential customers.
We are also subject to the Natural Gas Pipeline Safety Act of 1968, which
authorizes the establishment and enforcement of federal pipeline safety
standards and places jurisdiction of these standards with the Department of
Transportation. Intrastate facilities remain within the safety jurisdiction of
the state regulatory agencies, presuming compliance by such agencies with
certain prerequisites contained in such Act.
Our gas distribution business subsidiaries are subject to regulation of
rates and other aspects of their businesses by the states in which they
operate -- Pennsylvania, Ohio, and West Virginia. In 1999, Pennsylvania enacted
legislation which mandates supplier choice for residential and small commercial
customers. For additional information on deregulation in the gas industry, see
COMPETITION--Gas Industry.
The following sections discuss various regulatory proceedings in which the
Company is or has recently been involved. See COMPETITION and RATES for
information on additional proceedings.
Separation of Electric Generation and Delivery Operations in Virginia
In October 2000, the Virginia Commission issued its Final Order outlining
regulations governing the functional separation of incumbent electric
utilities' generation, transmission and distribution services. The Order
adopted rules for how Virginia's existing monopoly electric utilities should
organize themselves to participate in the competitive energy supply market,
which begins a phase-in in 2002. The rules govern how utilities can divide
themselves so that their generating plants can participate in the competitive
market without raising anti-competitive and other concerns. State law requires
the utilities to separate their various functions by January 1, 2002.
In November 2000, as required by electric deregulation legislation, the
Company's electric subsidiary filed with the Virginia Commission an application
for approval of a functional separation plan for its regulated utility
operations. The plan provides in part for the following:
. transfer of generation assets into a separate legal entity, Dominion
Generation Corporation;
7
<PAGE>
. transfer of rights and obligations under non-utility power purchase
contracts to Dominion Generation Corporation;
. retention of transmission and distribution assets and operations by
Virginia Power, to be known as Dominion Virginia Power;
. Dominion Generation Corporation to supply Dominion Virginia Power with
electric power during and after the capped rate period under a power
purchase agreement to ensure that adequate capacity and energy is
available to meet Dominion Virginia Power's capped rate service and
default supply obligations;
. planned allocation between Dominion Virginia Power and Dominion
Generation Corporation of payment responsibility for existing Virginia
Power debt with the objective that ratings on outstanding debt will
remain unchanged.
For additional details on functional separation, see Electric and Gas
Industry Issues--Separation of Electric Generation and Delivery Operations in
Virginia under MD&A on page 36 of the 2000 Annual Report.
Regional Transmission Entities/Regional Transmission Organizations
Deregulation legislation requires that Virginia's incumbent electric
utilities join or establish regional transmission entities (RTE) by January 1,
2001, and seek authorization from the Virginia Commission to transfer ownership
or operational control of their transmission facilities to such RTEs. In July
2000, the Virginia Commission issued regulations governing the transfer of
ownership or control of electric transmission assets to RTE. In October 2000,
Dominion's electric utility subsidiary filed an application with the Virginia
Commission seeking authorization to transfer control of its electric
transmission facilities to the Alliance Regional Transmission Organization
(Alliance RTO). As discussed below, the formation of the Alliance RTO began in
connection with FERC initiatives, and Dominion expects the RTO to satisfy the
requirements to establish the RTE under Virginia legislation.
In February 2000, FERC finalized regulations (Order No. 2000) to advance the
formation of Regional Transmission Organizations (RTO). The regulations require
that each public utility that owns, operates, or controls facilities for the
transmission of electric energy in interstate commerce make certain filings
with respect to forming and participating in an RTO. Dominion, together with
American Electric Power (AEP), Consumers Energy Company, The Detroit Edison
Company and First Energy Corporation, on behalf of themselves and their public
utility operating company subsidiaries (Alliance Companies), filed with FERC
applications under Sections 205 and 203 of the Federal Power Act for approval
of the proposed Alliance RTO. FERC approved most aspects of the RTO in January
2001. Dayton Power and Light Company, Commonwealth Edison Company, Commonwealth
Edison Company of Indiana, Illinois Power Company, Ameren UE and Ameren CIPS
have subsequently requested authority to join the Alliance RTO.
Retail Access Pilot Program
In 1998, the Virginia Commission issued an Order instructing the Company's
electric utility subsidiary and American Electric Power-Virginia, a subsidiary
of AEP, as Virginia's two largest investor-owned utilities, each to design and
file a retail access pilot program relating to electric distribution in
Virginia. In 2000, the Virginia Commission approved our retail access pilot
program and issued a final order on the interim rules governing pilot programs.
Our pilot program, Project Current Choice, began in September 2000. As of the
end of December 2000, over 81,000 customers have volunteered for the pilot
program and over 20,000 have switched to a competitive service provider. In
January 2001, the Virginia Commission established a proceeding to determine the
permanent rules for retail access.
Wholesale Markets
Dominion's electric utility subsidiary sells electricity in the wholesale
market under its market based-sales tariff authorized by FERC but has agreed
not to make wholesale power sales under this tariff to loads located
8
<PAGE>
within its service territory. During 2000, our electric utility subsidiary
filed applications with FERC to make sales under its market-based sales tariff
to loads within its service territory participating in its retail access pilot
program and to amend its open access transmission tariff to accommodate the
Virginia retail access pilot program. FERC has accepted both applications.
Until authorization is granted by FERC, any sales of wholesale power to loads
located within our electric service territory, other than sales to loads
participating in the electric retail access pilot program, are to be at cost-
based rates accepted by FERC.
Dominion's sales of oil and natural gas in wholesale markets are not
regulated by FERC. The deregulation of gas sales began through a multi-year
schedule established under the Natural Gas Policy Act (NGPA) of 1978 and was
completed under the Natural Gas Wellhead Decontrol Act of 1989.
Environmental Matters
Each segment of our business faces substantial regulation and compliance
costs with respect to environmental matters. For discussion of significant
aspects of these matters, including current and planned capital expenditures
relating to environmental compliance, see Electric and Gas Industry Issues--
Environmental Matters, Environmental Protection and Monitoring Expenditures,
Clean Air Act Compliance, and Global Climate Change under MD&A on pages 37 and
38 of the 2000 Annual Report.
From time to time we may be identified as a potentially responsible party
with respect to a superfund site. The EPA (or a state) can either (a) allow
such a party to conduct and pay for a remedial investigation, feasibility study
and remedial action or (b) conduct the remedial investigation and action and
then seek reimbursement from the parties. Each party can be held jointly,
severally and strictly liable for all costs, but the parties can then bring
contribution actions against each other and seek reimbursement from their
insurance companies. As a result, we may be responsible for the costs of
remedial investigation and actions under the Superfund Act or other laws or
regulations regarding the remediation of waste. We do not believe that any
currently identified sites will result in significant liabilities.
The Company has determined that it is associated with 20 former manufactured
gas plant sites, eight of which are currently owned by subsidiaries. Studies
conducted by other utilities at their former manufactured gas plants have
indicated that their sites contain coal tar and other potentially harmful
materials. None of the 20 former sites with which the Company is associated is
under investigation by any state or federal environmental agency, and no
investigation or action is currently anticipated. At this time it is not known
if, or to what degree, these sites may contain environmental contamination.
Therefore, the Company is not able to estimate the cost, if any, that may be
required for the possible remediation of these sites.
In accordance with applicable Federal and state environmental laws, we have
applied for or obtained the necessary environmental permits material to the
operation of our electric generating stations. Many of these permits are
subject to re-issuance and continuing review.
For additional information regarding environmental matters, see Item 3.
LEGAL PROCEEDINGS on page 20 and Electric and Gas Industry Issues--
Environmental Matters under MD&A on page 37 and Note 22 to the Consolidated
Financial Statements on page 60 of the 2000 Annual Report.
Nuclear Generation
All aspects of the operation and maintenance of our nuclear power stations,
which are a part of our Dominion Energy segment, are regulated by the NRC.
Operating licenses issued by the NRC are subject to revocation, suspension or
modification, and operation of a nuclear unit may be suspended if the NRC
determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and
maintenance of nuclear facilities. In many cases, these new regulations require
changes in the design, operation and maintenance of existing nuclear
facilities. If the NRC adopts such requirements in the future, it could result
in substantial increases in the cost of operating and maintaining our nuclear
generating units.
9
<PAGE>
One of the issues associated with the operation and decommissioning of
nuclear facilities is disposal of spent nuclear fuel (SNF). The Nuclear Waste
Policy Act of 1982 required the federal government to make available by January
31, 1998 a permanent repository for high-level radioactive waste and spent
nuclear fuel. Despite ongoing proceedings and investigations, the federal
government has not yet made such a repository available.
Most recently, we joined approximately 17 other electric utilities in a
petition for review in the U.S. Court of Appeals for the 11th Circuit,
challenging the DOE's action in allowing PECO Energy Company (PECO) to take
credits against payments PECO would otherwise make into the Nuclear Waste Fund
(NWF). The credits are part of a DOE settlement agreement with PECO for
potential claims arising out of DOE's breach of its 1998 obligation to begin
taking SNF for storage. The petition asserts that DOE violated the Nuclear
Waste Policy Act (NWPA) by improperly depleting the NWF and releasing PECO from
a portion of its NWF obligation. The petition seeks a declaration that credits
against NWF payments to offset on-site SNF storage costs violate the NWPA, an
injunction against DOE implementing the credit and fee reduction provisions of
the settlement agreement, and an injunction against DOE entering into similar
agreements.
We initiated the license renewal process for our nuclear power plants in
mid-1999 with expected submission to the NRC in 2001. If successful, NRC
renewed licenses will extend the operation of our four nuclear units to 2032,
2033, 2038 and 2040 for Surry Units 1 and 2 and North Anna Units 1 and 2,
respectively.
When our nuclear units cease to operate, we will be obligated to
decontaminate the facilities. This process is referred to as decommissioning,
and we are required by the NRC to prepare for it financially. For information
on our compliance with the NRC financial assurance requirements, see Note 14 to
Consolidated Financial Statements on page 53 of the 2000 Annual Report.
RATES
Electric
The majority of our electric revenue is provided through bundled rate
tariffs. In 2000, electric service sales by our electric utility subsidiary
included 73 million megawatt-hours of retail sales and 4.3 million megawatt-
hours of sales to wholesale requirements contract customers and were composed
of the following:
<TABLE>
<CAPTION>
2000
--------------------------------
Percent of Electric Service
--------------------------------
Revenues Kwh Sales
------------- --------------
<C> <S> <C> <C>
Virginia retail:
Non-Governmental customers........... Virginia Commission 81% 77%
Governmental customers............... Negotiated Agreements 10 13
North Carolina retail................... North Carolina Commission 5 4
Wholesale*.............................. FERC 4 6
------------- -------------
100% 100%
============= =============
</TABLE>
- --------
* Excludes power marketing sales which are also subject to FERC regulation.
Substantially all of the electric service sales made by our electric utility
subsidiary are currently subject to recovery of changes in fuel costs through
fuel adjustment factors. On November 27, 2000, an application was filed with
the Virginia Commission to propose an alternative fuel recovery method for the
period January 1, 2002--July 1, 2007. The proposed method would utilize a
portfolio of fuel indices, rather than actual incurred fuel costs, in the
development of the Virginia fuel factor.
10
<PAGE>
Recent Virginia proceedings related to our rates include the following:
The Virginia base (non-fuel) rates of our electric utility subsidiary are
currently capped until July 1, 2007, according to legislation passed in the
1998 session of the General Assembly.
In December 2000, our electric utility subsidiary filed an application with
the Virginia Commission for approval of unbundled tariffs that reflect
distribution rates and wires charges for the recovery of stranded costs. These
proposed rates are requested to become effective for usage on and after January
1, 2002.
Our electric utility subsidiary also filed an application with the Virginia
Commission to increase its Virginia fuel factor from 1.339c per kWh to 1.613c
per kWh or an estimated annual increase of $158 million. These new rates went
into effect on January 1, 2001, on an interim basis, for usage on and after
January 1, 2001 pending a hearing scheduled for March 1, 2001.
In July 2000, the Virginia Commission issued an order to modify our
cogeneration and small power production rates under Schedule 19. The order
sustained our proposed method to determine avoided costs, agreed with our
position that off system sales should be excluded from the calculation of
avoided costs, and that the cogeneration rate should be effective through 2001.
In September 2000, our electric utility subsidiary filed a revised Schedule 19
as required by the Virginia Commission's July 2000 Order, and in November 2000
the Virginia Commission accepted for filing our revised Schedule 19 Tariff.
In connection with the approval by the North Carolina Commission of its
acquisition of CNG, the Company agreed not to request an increase in North
Carolina retail electric base rates for both the Dominion Energy and Dominion
Delivery segments until after December 31, 2005, except for certain events that
would have a significant financial impact on the Company. Fuel rates are still
subject to change under the annual fuel cost adjustment proceedings.
Gas
Dominion's regulated gas subsidiaries continue to seek general rate
increases with regard to their regulated gathering, transmission, storage and
gas distribution services. Such rate changes are requested on a timely basis to
recover increased operating costs and to ensure that rates of return are
compatible with the cost of raising capital. In addition to general rate
increases, certain of our gas distribution subsidiaries make separate filings
with their respective regulatory commissions to reflect changes in the costs of
purchased gas. Dominion Transmission, Inc. (Dominion Transmission), an
interstate gas transmission subsidiary, has pending rate cases before FERC,
which are intended: (1) to unbundle gathering and products extraction rates
from those for interstate transportation, and (2) to recover the costs of
certain gas used as fuel for system operations. Otherwise, Dominion's regulated
gas subsidiaries filed no new general rate cases during 2000, nor were there
any outstanding cases requiring settlement.
In March 2001, Dominion's West Virginia gas utility subsidiary filed a rate
case with the Public Service Commission of West Virginia with a proposed
effective date for new rates as of January 1, 2002. No procedural schedule has
been established at this time. The proposed new rates are to provide for the
increased cost of gas supplies as well as increased operating costs.
FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHIC AREAS
See Note 27 to the Consolidated Financial Statements on page 68 of the 2000
Annual Report.
SOURCES OF ENERGY
Sources of Energy--Electricity
Dominion Energy provides electricity for use on a wholesale and a retail
level. We can supply electricity demand either through generation from our
generation facilities in Virginia, West Virginia, North Carolina and Illinois
or through power purchase contracts when needed. The following table outlines
our generating units and capability.
11
<PAGE>
Generating Units
<TABLE>
<CAPTION>
Summer
Years Capability
Name of Station, Units and Location Installed Type of Fuel Mw
----------------------------------- --------- -------------- ----------
<S> <C> <C> <C>
Nuclear:
Surry Units 1 & 2, Surry, Va............. 1972-73 Nuclear 1,625
North Anna Units 1 & 2, Mineral, Va...... 1978-80 Nuclear 1,842(a)
------
Total nuclear stations............... 3,467(e)
------
Fossil Fuel:
Steam:
Bremo Units 3 & 4, Bremo Bluff, Va..... 1950-58 Coal 227
Chesterfield Units 3-6, Chester, Va.... 1952-69 Coal 1,229
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
Combustion Turbines:
39 units (9 locations)................... 1967-70 Oil & Gas 1,595(c)
Combined Cycle:
Bellmeade, Richmond, Va.................. 1991 Oil & Gas 230
Chesterfield Units 7 & 8, Chester, Va.... 1990-92 Oil & Gas 397
------
Total fossil stations................ 9,211
------
Hydroelectric:
Gaston Units 1-4, Roanoke Rapids, N.C.... 1963 Conventional 225
Roanoke Rapids Units 1-4, Roanoke Rapids,
N.C..................................... 1955 Conventional 99
Other.................................... 1930-87 Conventional 3
Bath County Units 1-6, Warm Springs, Va.. 1985 Pumped Storage 1,260(d)
------
Total hydro stations................. 1,587
------
Total generating unit capability..... 14,265
------
Non-regulated Units:
Kincaid, Springfield, IL................. 1967-1968 Coal 1,158
Elwood, Elwood, IL....................... 1999 Gas 307
Morgantown, Morgantown, WV............... 1992 Waste Coal 33
Others................................... 1988-1990 Various 39
------
Total non-regulated generating
units............................... 1,537
------
Net Purchases.............................. 145
Non-Utility Generation (power purchase
contracts)................................ 3,973
------
Total Capability..................... 19,920
======
</TABLE>
- --------
(a) Includes an undivided interest of 11.6 percent (213.7 Mw) owned by Old
Dominion Electric Cooperative (ODEC).
(b) Includes an undivided interest of 50 percent (441 Mw) owned by ODEC.
(c) Includes the four new Remington combustion turbine units that began
operations in July 2000.
(d) Reflects Virginia Power's 60 percent undivided ownership interest in the
2,100 Mw station. A 40 percent undivided interest in the facility is owned
by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.
(AE).
(e) In 2000, our four nuclear units achieved a combined capacity factor of 95.1
percent.
12
<PAGE>
The Company's highest one-hour integrated service area summer and all- time
peak demand was 16,216 Mw on July 6, 1999, and an all-time high one-hour
integrated winter peak demand of 15,072 Mw was reached on January 28, 2000.
Power Purchase Contracts
Dominion Energy purchases electricity under contracts with other suppliers
to meet a portion of our own system capacity requirements. From the mid-1980's
until the start of the 1990's, we entered into a number of long-term purchase
contracts for electricity now associated with our Dominion Energy segment. At
the end of 1999, 900 Mw of these purchases from other utilities ended, and by
the end of the first quarter of 2000, an additional 200 Mw of diversity
exchange transactions was suspended. As of December 31, 2000, we have 54 power
purchase contracts with a combined dependable summer capacity of 3,973 Mw. For
information on the financial obligations under these agreements, see Note 22 to
Consolidated Financial Statements on page 60 of 2000 Annual Report.
The Company has reached an agreement, pending regulatory approvals, to
terminate three long-term power purchase agreements. Dominion expects the
transaction to be completed in the first quarter of 2001, resulting in a one-
time, non-operating charge of approximately $135 million, after taxes. The
transaction is part of an ongoing program which seeks to achieve competitive
cost structures at its power generating business.
Fuel for Electric Generation
We use a variety of fuels to power our electric generation. These include a
mix of both nuclear fuel and fossil fuel as described further below.
Nuclear Fuel Supply
We utilize both long-term contracts and spot purchases to support our needs
for nuclear fuel. We continually evaluate worldwide market conditions in order
to ensure a range of supply options at reasonable prices. Current agreements,
inventories and spot market availability are expected to support our current
and planned fuel supply needs for fuel cycles into the early 2000's. Beyond
that period, we expect to purchase additional fuel as required to ensure
optimum cost and inventory levels.
In March 1999, the Company, along with a consortium of companies, was
awarded a contract by DOE for mixed oxide (MOx) fuel fabrication and reactor
irradiation services. We have determined that MOx fuel can be used safely and
can potentially lower fuel costs. Furthermore, this program will improve
international security by reducing plutonium stockpiles. Certain plant and
site/facility modifications must be implemented to receive and utilize MOx
fuel. DOE will reimburse the Company for all plant and site/facility
modifications as well as other MOx fuel implementation costs. We expect to
provide irradiation services beginning September 2007.
The DOE did not begin the acceptance of SNF in 1998 as specified in our
contract with the DOE. However, on-site SNF pool and dry container storage at
the Surry and North Anna Power Stations are expected to be adequate for our
needs until the DOE begins accepting SNF. See REGULATION--Nuclear Generation
for additional information regarding SNF.
Fossil Fuel Supply
The fuel mix utilized by Dominion Energy's fossil operations consists of
coal, oil, and natural gas. During 2000, we burned approximately 14 million
tons of coal. We utilize both long-term contracts and spot purchases
13
<PAGE>
to support our coal needs. We presently anticipate sufficient supplies of coal
will continue to be available at reasonable prices but market prices and price
volatility will be higher. Coal producers, for the past two decades, have over-
supplied the market. As a result, market prices in the past have remained
relatively stable, even during periods when utility demand has spiked. Coal
markets have become more supply-demand balanced which will likely lead to more
price volatility in the future.
Oil and oil-fired generation are used primarily to support heavier system
generation loads during very cold or very hot weather periods. System
requirements are purchased under both short-term spot agreements and longer
term contracts. A sufficient supply of oil is expected to be available over the
next five to ten year period.
Dominion Energy uses natural gas as needed throughout the year for our
jurisdictional and non-jurisdictional facilities. The Company's gas supply is
obtained from various sources including: purchases from major and independent
producers in the Southwest and Midwest regions; purchases from local producers
in the Appalachian area; purchases from gas marketers; production from Company-
owned wells in the Appalachian area, the Southwest, Midwest and offshore; and
withdrawals from the Company's and third party underground storage fields.
Dominion has the capability to buy and store natural gas at summer prices,
which will then be consumed at the facilities during the winter.
Firm natural gas transportation contracts (capacity) exist that allow
delivery of gas to our facilities. Dominion has positioned its capacity
portfolio in such a way that allows flexible natural gas deliveries to our gas
turbine fleet, while minimizing costs. With natural gas being the preferred
source of new electric generation, competition for existing gas capacity has
increased. In order to ensure reliable delivery of natural gas, Dominion has
acquired more natural gas capacity and has a rolling seven-year capacity plan
in place that will protect its fleet from any perceived or real capacity
shortage in the market.
Sources of Energy--Gas
Gas Supply
Dominion Energy is also engaged in the sale and storage of natural gas
through its operating subsidiaries. Sources of gas supplies for sale to
customers are the same as those described in Fossil Fuel Supply above.
The Company has continued to purchase volumes from the array of accessible
producing basins using its firm capacity resources. These purchased supplies
include Appalachian resources in Ohio, Pennsylvania and West Virginia, and
production from the Gulf Coast, Mid-Continent and offshore areas. Upon FERC's
restructuring of the interstate pipeline business in 1992-93, pipelines no
longer sell the delivered natural gas commodity; rather, customers provide
their own gas supply for wholesale storage and/or delivery by the pipelines.
Much of the supply is purchased by local distributors, energy marketing
companies or end users, under seasonal or spot purchase agreements. While the
average term of the Company's gas purchase agreements has declined, the
reliability of supply has been adequate. The availability of supplies and
heightened competition has forged a viable market, which has proven capable of
satisfying the firm delivery requirement for supplies to the Company's markets
in a highly reliable manner. Purchased gas volumes were 422 billion cubic feet
(Bcf) or about 60% of the total 2000 supply. Spot market and short-term
purchases were 398 Bcf, or about 56% of the total 2000 supply.
Considering the Company's large storage capacity, the volumes obtainable
under its firm interstate pipeline capacity and gas supply contracts, Company-
owned gas reserves, and assuming the future availability of spot market gas,
the Company believes that supplies will be available to meet sales requirements
for at least the next several years.
Gas Storage--Transmission
The Company's underground storage facilities play an important part in
balancing gas supply with sales demand and are essential to servicing the
Company's large volume of space-heating business. In addition,
14
<PAGE>
storage capacity is an important element in the effective management of both
gas supply and pipeline transport capacity. The Company operates 26 underground
gas storage fields located in Ohio, Pennsylvania, West Virginia and New York.
The Company owns 20 of these storage fields and has joint-ownership with other
companies in six of the fields. The total designed capacity of the storage
fields, including native gas, is approximately 959 Bcf. The Company's share of
the total capacity is about 717 Bcf. About one-half of the total capacity is
base gas which remains in the reservoirs at all times to provide the primary
pressure which enables the balance of the gas to be withdrawn as needed.
Dominion Transmission operates 756 Bcf of the total designed storage
capacity and owns 514 Bcf of the Company's capacity. Dominion Transmission
utilizes a large portion of its turnable capacity to provide approximately 275
Bcf of gas storage service for others. This service is provided principally to
local distributors, end users, and other customers serving the Northeast.
Two of Dominion's gas distribution subsidiaries, Dominion East Ohio and
Dominion Peoples, own and operate the remaining 203 Bcf of storage capacity. In
addition to owning their own storage, these companies, as well as several of
the other subsidiaries, have access to a portion of the storage capacity
operated by Dominion Transmission. The distribution subsidiaries also have
capacity available in storage fields owned by others. The Company controls
other acreage in the Appalachian area suitable for the development of
additional storage facilities which would enable further expansion of capacity
to meet possible future storage needs.
FUTURE SOURCES OF ENERGY
In January 2000, we filed an application with the Virginia Commission to
build and operate two 160 Mw combustion turbine units in Caroline County,
Virginia for additional peaking capacity. We have obtained the applicable
zoning permits for the construction of the generators and have applied for
other required environmental permits. The Virginia Commission approved the
project in October 2000. The units are expected to be operational by the summer
of 2001.
In June 2000, we filed an application with the Virginia Commission to make a
number of changes to the Possum Point Power Station designed to improve air
quality and to meet existing and proposed air emission limitations in Northern
Virginia. We have proposed the retirement of two coal-fired units, conversion
of two other coal-fired units to gas, and the addition of one combined cycle
unit to be operational by May 2003. The Virginia Commission held a hearing on
the matter in January 2001.
Dominion has reached an agreement to acquire the Millstone Nuclear Power
Station located in Waterford, Connecticut from subsidiaries of Northeast
Utilities and other owners for approximately $1.3 billion. The acquisition
includes 100% ownership in Unit 1 and Unit 2, and 93.47% ownership interest in
Unit 3, for a total of 1,954 Mw of generating capacity. See Note 5 of the
Consolidated Financial Statements on page 47 of the 2000 Annual Report for
additional information on the Millstone Nuclear Power Station acquisition.
Dominion has also sited four new generation plants with combined capacity of
approximately 2,000 Mw along Dominion's gas pipelines in Ohio, Pennsylvania and
West Virginia. Additional anticipated capacity expansion of 4,000 Mw is also
planned, including capacity expansions at our Elwood facility in Illinois.
The Company has planned a $400 million addition to its natural gas
transmission system to help meet demand growth. The 200-mile Greenbrier
Pipeline will extend from West Virginia to North Carolina.
During 2000, Dominion acquired 167 billion cubic feet equivalent of gas
reserves and additional acreage for exploratory and development drilling
through a number of purchase transactions. Significant acquisitions during the
year included the purchase of additional interests in two deepwater Gulf of
Mexico properties and various South Texas gas fields. In January 2000, Dominion
acquired an additional 12.5 percent interest in Popeye, a deepwater gas
producing property, increasing its interest to 50 percent. Dominion also
doubled its interest in the Devil's Tower deepwater discovery to 60 percent. In
August 2000, Dominion acquired the operating interests of Suemaur Exploration &
Production, LLC and several partners in three Texas Gulf Coast natural gas
fields.
15
<PAGE>
CAUTIONARY FACTORS THAT MAY AFFECT FUTURE RESULTS
(Cautionary statements under the Private Securities Litigation Reform Act of
1995)
Our disclosure and analysis in this report and in our 2000 Annual Report to
shareholders contain some "forward-looking statements." Forward-looking
statements give our current expectations or forecasts of future events. You can
identify these statements by the fact that they do not relate strictly to
historical or current facts. They use words such as "anticipate," "estimate,"
"expect," "project," "intend," "plan," "believe," and other words and terms of
similar meaning in connection with any discussion of future operating or
financial performance. In particular, these include statements relating to
future actions, a broad spectrum of regulatory approvals, future performance or
results of current and anticipated generation capacity, future performance or
results of the development and expansion of the telecommunications segment,
growth in customer base, financial results of asset divestitures, and the
outcome of contingencies such as legal proceedings. From time to time, we also
may provide oral or written forward-looking statements in other materials we
release to the public.
Any or all of our forward-looking statements in this report, in the 2000
Annual Report and in any other public statements that we make may turn out to
be wrong. They can be affected by inaccurate assumptions we might make or by
known or unknown risks and uncertainties. Many factors mentioned in the
discussion above--for example, government regulations, organizational and
operations restructuring, competition, weather, trading risks--will be
important in determining future results. Consequently, no forward-looking
statement can be guaranteed. Actual future results may vary materially.
We encourage you to read thoroughly Management's Discussion and Analysis of
Financial Condition and Results of Operations and its Forward-Looking
Statements.
We undertake no obligation to publicly update forward-looking statements,
whether as a result of new information, future events or otherwise. You are
advised, however, to consult any further disclosures we make on related
subjects in our 10-Q and 8-K reports to the SEC.
ITEM 2. PROPERTIES
Dominion's assets consist primarily of its investments in its subsidiaries,
the principal properties of which are described below.
Our Dominion Energy segment utilizes the electric generation facilities
listed under the heading Sources of Power--Generating Units in Item 1.
BUSINESS. Additionally, in connection with gas transmission and storage
operations, Dominion Energy's storage operation consists of 26 storage fields,
342,605 acres of operated leaseholds, 2,069 storage wells and 822 miles of
pipe. A significant portion of our investment in gas transmission facilities is
for 6,428 miles of pipe required to move large volumes of gas throughout the
Company's operating area.
Our Dominion Energy segment also includes 99 compressor stations with
492,040 installed compressor horsepower located in Ohio, West Virginia,
Pennsylvania and New York. Some of the stations are used interchangeably for
several functions.
Our Dominion Delivery segment utilizes 3,600 miles of electric transmission
lines. 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 our transmission lines
cross national parks and forests under permits entitling the federal government
to use, at specified charges, surplus capacity in the line if any exists.
Dominion Delivery's investment in its gas distribution network is located in
the states of Ohio, Pennsylvania and West Virginia. The gas distribution
network includes 27,060 miles of pipe, exclusive of service pipe.
16
<PAGE>
The Company's investment in its natural gas system is considered suitable to
do all things necessary to bring gas to the consumer. The Company's properties
provided the capacity to meet a record system peak day sendout, including
transportation service, of 11.4 Bcf on February 6, 1995. The system peak day
sendout in 2000 was 8.6 Bcf on January 27.
Information detailing Dominion Exploration & Production's oil and gas
investments is as follows:
Company-Owned Reserves
Estimated net quantities of proved gas and oil reserves at December 31 were
as follows:
<TABLE>
<CAPTION>
2000 1999 1998
---------------- ---------------- ----------------
Proved Total Proved Total Proved Total
Developed Proved Developed Proved Developed Proved
--------- ------ --------- ------ --------- ------
<S> <C> <C> <C> <C> <C> <C>
Gas reserves (Bcf)
United States.............. 1,593 1,858 600 600 473 473
Canada..................... 361 479 405 514 118 118
------ ------ ----- ------ ----- -----
Total gas reserves....... 1,954 2,337 1,005 1,114 591 591
====== ====== ===== ====== ===== =====
Oil reserves (000 Bbls)
United States.............. 21,709 51,072 659 659 2,661 2,661
Canada..................... 14,527 24,270 5,443 20,149 1,543 1,543
------ ------ ----- ------ ----- -----
Total oil reserves....... 36,236 75,342 6,102 20,808 4,204 4,204
====== ====== ===== ====== ===== =====
</TABLE>
Dominion E&P and Dominion Transmission file Form EIA-23 with the DOE. The
reserves reported on Form EIA-23 at December 31, 2000, as well as those which
will be reported at December 31, 2001, are not reconcilable with Company-owned
reserves because they are calculated on an operated basis and include working
interest reserves of all parties.
Quantities of Gas and Oil Produced
Quantities of gas and oil produced during each of the last three years
ending December 31 follow:
<TABLE>
<CAPTION>
2000 1999 1998
----- ----- -----
<S> <C> <C> <C>
Gas production (Bcf)
United States............................................... 222 60 50
Canada...................................................... 47 37 13
----- ----- -----
Total gas production...................................... 269 97 63
===== ===== =====
Oil production (000 Bbls)
United States............................................... 6,436 595 751
Canada...................................................... 1,258 1,462 274
----- ----- -----
Total oil production...................................... 7,694 2,057 1,025
===== ===== =====
</TABLE>
The average sales price (including transfers to other operations as
determined under Financial Accounting Standards Board rules) per Mcf of non-
cost-of-service gas produced during the years 2000, 1999 and 1998 was $3.10,
$2.06 and $2.07, respectively. The respective average sales prices for oil were
$22.88, $13.55 and $11.94 per barrel. The average production (lifting) cost per
Mcf equivalent of gas and oil produced during the years 2000, 1999 and 1998 was
$.49, $.71 and $.63, respectively.
17
<PAGE>
Productive Wells
The number of productive gas and oil wells in which the Company's
subsidiaries had an interest at December 31, 2000, follow:
<TABLE>
<CAPTION>
Gross Net
------ -----
<S> <C> <C>
Gas wells
United States.................................................... 11,048 8,864
Canada........................................................... 815 490
------ -----
Total gas wells................................................ 11,863 9,354
====== =====
Oil wells
United States.................................................... 342 247
Canada........................................................... 705 214
------ -----
Total oil wells................................................ 1,047 461
====== =====
</TABLE>
Includes 82 gross (23 net) multiple completion gas wells and 21 gross (8
net) multiple completion oil wells.
Net Wells Drilled in the Calendar Year
The number of net wells completed during each of the last three years
follows:
<TABLE>
<CAPTION>
Years Ended December 31
-------------------------
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Exploratory:
United States
Productive........................................ 5
Dry............................................... 9
------- ------- -------
Total exploratory............................... 14
------- ------- -------
Development:
United States
Productive........................................ 253 90 134
Dry............................................... 2
------- ------- -------
Total United States............................. 255 90 134
------- ------- -------
Canada
Productive........................................ 52 18 14
Dry............................................... 26 3 7
------- ------- -------
Total Canda..................................... 78 21 21
------- ------- -------
Total development............................... 333 111 155
------- ------- -------
Total wells drilled........................... 347 111 155
======= ======= =======
</TABLE>
As of December 31, 2000, 36 gross (21 net) wells were in process of
drilling, including wells temporarily suspended.
18
<PAGE>
Acreage
The following table sets forth the gross and net developed and undeveloped
acreage of the Company's subsidiaries at December 31, 2000:
<TABLE>
<CAPTION>
Developed Acreage Undeveloped Acreage
------------------- -------------------
Gross Net Gross Net*
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
United States*.......................... 2,453,889 1,784,475 1,034,933 611,114
Canada.................................. 1,281,477 716,673 1,130,216 732,678
--------- --------- --------- ---------
Total................................. 3,735,366 2,501,148 2,165,149 1,343,792
========= ========= ========= =========
</TABLE>
- --------
* Developed acreage includes 212,055 gross and net cost-of-service acres.
ITEM 3. LEGAL PROCEEDINGS
From time to time, Dominion and its subsidiaries are alleged to be in
violation or in default under orders, statutes, rules or regulations relating
to the environment, compliance plans imposed upon or agreed to by us, or
permits issued by various local, state and federal agencies for the
construction or operation of facilities. From time to time, there may be
administrative proceedings on these matters pending. In addition, in the normal
course of business, Dominion and its subsidiaries are 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.
See REGULATION and RATES under Item 1. BUSINESS for information on various
regulatory proceedings to which we are a party.
In April 1999, Virginia Power was notified by the Department of Justice of
alleged noncompliance with the EPA's oil spill prevention, control and
countermeasures (SPCC) plans and facility response plan (FRP) requirements at
one of our power stations. If, in a legal proceeding, such instances of
noncompliance are deemed to have occurred, Virginia Power may be required to
remedy any alleged deficiencies and pay civil penalties. Settlement of this
matter is currently in negotiation and is not expected to have a material
impact on our Company's financial condition or results of operations.
In August 1999, Virginia Power identified matters at certain other power
stations that the EPA might view as not in compliance with the SPCC and FRP
requirements. Virginia Power reported these matters to the EPA and our plan for
correcting them. The EPA has not assessed any penalties, pending its review of
the disclosure information. Future resolution of these matters is not expected
to have a material impact on the Company's financial condition or results of
operations.
In August 1990, Dominion Transmission entered into a Consent Order and
Agreement with the Commonwealth of Pennsylvania Department of Environmental
Protection (DEP) in which Dominion Transmission agreed with the DEP's
determination of certain violations of the Pennsylvania Solid Waste Management
Act, the Pennsylvania Clean Streams Law and the rules and regulations
promulgated thereunder. No civil penalties have been assessed. According to the
Order and Agreement, Dominion Transmission continues to perform sampling,
testing and analysis, and conducts a program of remediation at some of its
Pennsylvania facilities. Dominion Transmission has recognized an estimated
liability amounting to $6 million at December 31, 2000, for future costs
expected to be incurred to remediate or mitigate hazardous substances at these
sites and at facilities covered by the Order and Agreement.
During 2000, Dominion Transmission paid a total of $380,000 related to a
hydrocarbon spill in February 1998 at one of its facilities in Aliquippa,
Beaver County, Pennsylvania. Dominion Transmission settled the matter by
contributing $200,000 to the Penn's Corner Conservancy Charitable Trust and
$80,000 to the Beaver County Conservation District, and paying $100,000 to the
DEP for response costs.
19
<PAGE>
During 2000, Virginia Power received a Notice of Violation (NOV) from the
EPA alleging that we failed to obtain New Source Review permits under the Clean
Air Act prior to undertaking specified construction projects at our Mt. Storm
Power Station in West Virginia. EPA alleges that each of these projects
resulted in an increase in the emission of air pollutants beyond levels that
require a New Source Review permit specified under the Clean Air Act. Also in
2000, the Attorney General of New York filed a suit alleging similar violations
of the Clean Air Act at the Mt. Storm Power Station. Virginia Power also
received notices from the Attorneys General of Connecticut and New Jersey of
their intentions to file suit for similar violations. Virginia Power has
reached an agreement in principle with the federal government and the state of
New York to resolve this situation. The agreement in principle includes payment
of a $5 million civil penalty, a commitment of $14 million for major
environmental projects in Virginia, West Virginia, Connecticut, New Jersey and
New York, and a 12-year, $1.2 billion capital investment program for
environmental improvements at the Company's coal-fired generating stations in
Virginia and West Virginia. Although Virginia Power reached an agreement in
principle, the terms of a final binding settlement are still being negotiated.
See Note 22 to the Consolidated Financial Statements on page 61 of the 2000
Annual Report.
Following the announcement of the merger, in April 1999, CNG and its
directors were served with a Class Action Complaint, which sought, among other
things, to compel CNG to sell the company for the highest value to CNG
shareholders. Several additional Class Action Complaints, seeking essentially
the same relief, have been combined with this action. CNG moved to dismiss, and
on February 15, 2000, the plaintiffs took action for dismissal.
A qui tam action (one in which the plaintiff sues for the government as well
as for itself, and gets to keep part of the recovery) was brought by Jack
Grynberg, an oil and gas entrepreneur, against a major part of the gas
industry, including CNG and several of its subsidiaries. The complaint, which
was filed on July 2, 1997, was under seal pending Department of Justice review.
The Department of Justice declined to intervene and the seal was lifted in May
1999. CNG was served in the Western District of Louisiana on May 1, 1999. The
suit alleges fraudulent mismeasurement of gas volumes and underreporting of gas
royalties from gas production taken from federal leases. The cases have been
removed to the Eastern District of Wyoming, where a motion to dismiss will be
filed by the Company.
A class action was filed by Quinque Operating Co. and others against
approximately 300 defendants, including CNG and several of its subsidiaries, in
Stevens County, Kansas. The complaint, which was served on CNG and its
subsidiaries on September 24, 1999, alleged fraud, misrepresentation,
conversion and assorted other claims, in the measurement and payment of gas
royalties from privately held gas leases. The case has been remanded to Kansas
state court by the federal judge overseeing the Grynberg case. The plaintiffs
will seek class certification and expedited discovery in Kansas. The defendants
in the case have filed a motion to keep the case in federal court.
20
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
<TABLE>
<CAPTION>
Name and Age Business Experience Past Five Years
------------ -----------------------------------
<C> <S>
Thos. E. Capps (65)......... Chairman of the Board of Directors, President and
Chief Executive Officer of Dominion from August
1, 2000 to date; Vice Chairman of the Board of
Directors, President and Chief Executive Officer
of Dominion from January 28, 2000 to August 1,
2000; Chairman of the Board of Directors,
President and Chief Executive Officer from
September 1, 1995 to January 28, 2000; Chairman
of the Board of Directors and Chief Executive
Officer prior to September 1, 1995.
Thomas N. Chewning (55)..... Executive Vice President and Chief Financial
Officer of Dominion from May 1, 1999 to date;
Chief Executive Officer of Dominion Energy from
May 1, 1999 to January 28, 2000; Executive Vice
President and Chief Financial Officer of
Consolidated Natural Gas Company from January 28,
2000 to date; President and Chief Executive
Officer of Dominion Energy from October 1, 1994
to May 1, 1999; Senior Vice President of Dominion
prior to January 1, 1997.
Thomas F. Farrell, II (46).. Executive Vice President of Dominion from March
1, 1999 to date; Chief Executive Officer of
Virginia Electric and Power Company and Dominion
Energy, Inc. from May 1, 1999 to date; Executive
Vice President of Consolidated Natural Gas
Company from January 28, 2000 to date; Senior
Vice President-Corporate Affairs and General
Counsel of Dominion and Executive Vice President,
General Counsel and Corporate Secretary of
Virginia Electric and Power Company from July 1,
1998 to May 1, 1999; Executive Vice President and
General Counsel of Virginia Electric and Power
Company from April 17, 1998 to June 30, 1998;
Senior Vice President- Corporate and General
Counsel of Dominion from January 1, 1997 to March
1, 1999; Vice President and General Counsel of
Dominion from July 1, 1995 to January 1, 1997;
Partner in the law firm of McGuire, Woods, Battle
& Boothe LLP prior to July 1, 1995.
James P. O'Hanlon (57)...... Executive Vice President of Dominion and
President and Chief Operating Officer of Virginia
Electric and Power Company from May 1, 1999 to
date; Executive Vice President of Consolidated
Natural Gas Company from January 28, 2000 to
date; Chief Nuclear Officer of Virginia Electric
and Power Company from May 1, 1999 to April 28,
2000; Senior Vice President-Nuclear of Virginia
Electric and Power Company prior to May 1, 1999.
Robert E. Rigsby (51)....... President and Chief Operating Officer of Virginia
Electric and Power Company and Executive Vice
President of Dominion Resources, Inc. from May 1,
1999 to date; Executive Vice President of
Virginia Electric and Power Company from January
1, 1996 to April 30, 1999; Senior Vice
President--Finance and Controller of Virginia
Electric and Power Company prior to January 1,
1996.
</TABLE>
21
<PAGE>
<TABLE>
<CAPTION>
Name and Age Business Experience Past Five Years
------------ -----------------------------------
<C> <S>
H. Patrick Riley (63)..... Executive Vice President of Dominion from January
28, 2000 to date; Executive Vice President of
Consolidated Natural Gas Company from January 28,
2000 to date; President and Chief Executive Officer
of Dominion Exploration and Production, Inc. from
January 28, 2000 to date; President of CNG
Producing Company prior to January 28, 2000.
Edgar M. Roach, Jr. (52).. Executive Vice President of Dominion from September
15, 1997 to date and Chief Executive Officer of
Virginia Electric and Power Company from May 1,
1999 to date; Executive Vice President of
Consolidated Natural Gas Company from January 28,
2000 to date; Senior Vice President-Finance,
Regulation and General Counsel of Virginia Electric
and Power Company from January 1, 1996 to September
15, 1997; Vice President-Regulation and General
Counsel, prior to January 1, 1996.
James L. Trueheart (49)... Group Vice President and Chief Administrative
Officer of Dominion and Consolidated Natural Gas
Company from June 1, 2000 to date; Group Vice
President, Chief Administrative Officer, and
Controller from January 28, 2000 to June 1, 2000;
Senior Vice President and Controller from November
1, 1998 to January 28, 2000; Vice President and
Controller prior to November 1, 1998.
Eva Teig Hardy (56)....... Senior Vice President-External Affairs & Corporate
Communications of Dominion from May 1, 1999 to
date; Senior Vice President-External Affairs &
Corporate Communications of Virginia Electric and
Power Company, September 1, 1997 to April 28, 2000;
Vice President-External Affairs and Corporate
Communications, June 1, 1997 to September 1, 1997;
Vice President-Public Affairs of Virginia Electric
and Power Company prior to June 1, 1997.
G. Scott Hetzer (44)...... Senior Vice President and Treasurer of Dominion
from May 1, 1999 to date; Senior Vice President and
Treasurer of Virginia Electric and Power Company
from January 28, 2000 to date; Senior Vice
President and Treasurer of Consolidated Natural Gas
Company from January 28, 2000 to date; Vice
President and Treasurer of Dominion from October 1,
1997 to May 1, 1999; Managing Director of Wheat
First Butcher Singer prior to October 1, 1997.
James L. Sanderlin (59)... Senior Vice President-Law of Dominion from
September 15, 1999 to date; Senior Vice President-
Law of Consolidated Natural Gas Company from
January 28, 2000 to date. Partner in the law firm
of McGuire, Woods, Battle & Boothe LLP prior to
September 15, 1999.
Steven A. Rogers (39)..... Vice President, Controller and Principal Accounting
Officer of Dominion and Consolidated Natural Gas
Company and Vice President and Principal Accounting
Officer of Virginia Electric and Power Company from
June 1, 2000 to date; Controller of Virginia
Electric and Power Company from January 28, 2000 to
May 31, 2000. Controller of Dominion Energy, Inc.
from September 1, 1998 to June 1, 2000; Vice
President and Controller of Optacor Financial
Services Company from February 17, 1997 through
September 1, 1998; Manager--Internal Audit of
Dominion prior to February 17, 1997.
</TABLE>
22
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Dominion Resources common stock is listed on the New York Stock Exchange and
at December 31, 2000 there were 188,737 common shareholders of record.
Quarterly information concerning stock prices and dividends contained in Note
26 to the Consolidated Financial Statements on page 67 of the 2000 Annual
Report for the fiscal year ended December 31, 2000, filed herein as Exhibit 13,
is hereby incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA
This information contained under the caption "Selected Consolidated
Financial Data" on page 69 of the 2000 Annual Report for the fiscal year ended
December 31, 2000, filed herein as Exhibit 13, is hereby incorporated herein by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This information contained under the caption Management's Discussion and
Analysis of Financial Condition and Results of Operations on pages 30 through
40 of the 2000 Annual Report for the fiscal year ended December 31, 2000, filed
herein as Exhibit 13, is hereby incorporated herein by reference.
In addition, see Schedule I--Condensed Financial Information to Registrant
under Part IV, Item 14 for the separate, condensed financial statements and
related notes for Dominion Resources, Inc. which contain information on certain
restrictions in affect at December 31, 2000 on CNG's ability to make dividend
payments. These restrictions did not affect the Company's ability to meet its
cash obligations. Further as set out in Schedule I, this restriction has been
eliminated.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information contained under the following captions:
Market Rate Sensitive Instruments and Risk Management
Interest Rate Risk
Commodity Price Risk--Non-Trading Activities
Commodity Price Risk--Trading Activities
Equity Price Risk
Risk Management Policies
under Management's Discussion and Analysis of Financial Condition and Results
of Operations on pages 39 and 40 of the 2000 Annual Report for the fiscal year
ended December 31, 2000, filed herein as Exhibit 13, is hereby incorporated
herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This information contained in the Consolidated Financial Statements on pages
25 through 69 and related report thereon of Deloitte & Touche LLP, independent
auditors, appearing on page 70 of the 2000 Annual Report for the fiscal year
ended December 31, 2000, filed herein as Exhibit 13, is hereby incorporated
herein by reference.
In addition, see Schedule I--Condensed Financial Information of Registrant
under Part IV, Item 14 for the separate, condensed financial statements and
related notes, for Dominion Resources, Inc. which contain information on
certain restrictions in affect at December 31, 2000 on CNG's ability to make
dividend payments. These restrictions did not affect the Company's ability to
meet its cash obligations. Further as set out in Schedule I, this restriction
has been eliminated.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
23
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of Dominion contained in the 2001 Proxy
Statement, under the heading The Board, File No. 1-8489, dated March 16, 2001
(the 2001 Proxy Statement), is incorporated herein by reference. The
information concerning the executive officers of Dominion required by this item
is included in Part I of this Form 10-K under the caption EXECUTIVE OFFICERS OF
THE REGISTRANT.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation contained under the heading
Executive Compensation and the information regarding director compensation
contained under the heading The Board--Compensation and Other Programs in the
2001 Proxy Statement, is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information concerning stock ownership by directors and executive
officers is contained under the heading The Board--Share Ownership Table in the
2001 Proxy Statement, is hereby incorporated herein by reference. There is no
person known by Dominion to be the beneficial owner of more than five percent
of Dominion common stock.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information concerning certain transactions with executive officers
under the Stock Purchase and Loan Program contained under the heading Executive
Compensation in the 2001 Proxy Statement is incorporated herein by reference.
24
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Certain documents are filed as part of this Form 10-K and are
incorporated herein by reference and found on the pages noted.
1. Financial Statements
<TABLE>
<CAPTION>
2000 Annual
Report to
Shareholders
(Page)
------------
<S> <C>
Consolidated Statements of Income for the years ended
December 31, 2000, 1999 and 1998............................ 25
Consolidated Balance Sheets at December 31, 2000 and 1999.... 26-27
Consolidated Statements of Common Shareholders' Equity and
Consolidated Statements of Comprehensive Income for the
years ended December 31, 2000, 1999 and 1998................ 28
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998............................ 29
Notes to Consolidated Financial Statements................... 41-69
Independent Auditors' Report................................. 70
Report of Management's Responsibilities...................... 70
2. Financial Statement Schedules
<CAPTION>
Page
------------
<S> <C>
Independent Auditors' Report................................. 32
Schedule I--Condensed Financial Information of Registrant.... 33
Schedule II--Valuation and Qualifying Accounts............... 38
</TABLE>
All other schedules are omitted because they are not applicable, or the
required information is shown in the financial statements or the related notes.
3. Exhibits
<TABLE>
<C> <C> <S>
2(i) -- Agreement, dated June 26, 1998, relating to the sale and
purchase of East Midlands Electricity plc by PowerGen plc
(Exhibit 2, Form 10-Q for the quarter ended June 30, 1998, File
No. 1-8489, incorporated by reference).
2(ii) -- Amended and Restated Agreement and Plan of Merger, dated May
11, 1999 (Exhibit 2, Form S-4, Registration Statement, File No.
333-75699, as filed on May 20, 1999, incorporated by reference)
and the Joinder Agreement, dated January 28, 2000 (Exhibit 1.2,
Form 8-K, dated February 1, 2000, File No. 1-8489, incorporated
by reference).
3(i) -- Articles of Incorporation as in effect August 9, 1999 (Exhibit
3(i), Form 10-Q for the quarter ended June 30, 1999, File No.
1-8489, incorporated by reference).
3(ii) -- Articles of Amendment establishing Series A Preferred Stock,
effective March 12, 2001 (filed herewith).
3(iii) -- Bylaws as in effect on October 20, 2000 (Exhibit 3, Form 10-Q
for the quarter ended September 30, 2000, File No. 1-8489,
incorporated by reference).
4(i) -- See Exhibit 3(i) above.
</TABLE>
25
<PAGE>
<TABLE>
<C> <C> <S>
4(ii) -- Indenture of Mortgage of Virginia Electric and Power Company,
dated November 1, 1935, as supplemented and modified by fifty-
eight Supplemental Indentures (Exhibit 4(ii), Form 10-K for the
fiscal year ended December 31, 1985, File No. 1-2255,
incorporated by reference); Sixty-Seventh Supplemental
Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File
No. 1-2255, incorporated by reference); Seventieth Supplemental
Indenture, (Exhibit 4(iii), Form 8-K, dated February 25, 1992,
File No. 1-2255, incorporated by reference); Seventy-First
Supplemental Indenture (Exhibit 4(i)) and Seventy-Second
Supplemental Indenture, (Exhibit 4(ii), Form 8-K, dated July 7,
1992, File No. 1-2255, incorporated by reference); Seventy-
Third Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated
August 6, 1992, File No. 1-2255, incorporated by reference);
Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K,
dated February 10, 1993, File No. 1-2255, incorporated by
reference); Seventy-Fifth Supplemental Indenture, (Exhibit
4(i), Form 8-K, dated April 6, 1993, File No. 1-2255,
incorporated by reference);
Seventy-Sixth Supplemental Indenture, (Exhibit 4(i), Form 8-K,
dated April 21, 1993, File No. 1-2255, incorporated by
reference); Seventy-Seventh Supplemental Indenture,
(Exhibit 4(i), Form 8-K, dated June 8, 1993, File No. 1-2255,
incorporated by reference); Seventy-Eighth Supplemental
Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993,
File No. 1-2255, incorporated by reference); Seventy-Ninth
Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August
10, 1993, File No. 1-2255, incorporated by reference);
Eightieth Supplemental Indenture, (Exhibit 4(i), Form 8-K,
dated October 12, 1993, File No. 1-2255, incorporated by
reference); Eighty-First Supplemental Indenture,
(Exhibit 4(iii), Form 10-K for the fiscal year ended December
31, 1993, File No. 1-2255, incorporated by reference);
Eighty-Second Supplemental Indenture, (Exhibit 4(i), Form 8-K,
dated January 18, 1994, File No. 1-2255, incorporated by
reference); Eighty- Third Supplemental Indenture (Exhibit 4(i),
Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated
by reference); Eighty-Fourth Supplemental Indenture (Exhibit
4(i), Form 8-K, dated March 23, 1995, File No. 1-2255,
incorporated by reference, and Eighty-Fifth Supplemental
Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997,
File No. 1-2255, incorporated by reference).
4(iii) -- Indenture, dated as of June 1, 1986, between Virginia Electric
and Power Company and The Chase Manhattan Bank (formerly
Chemical Bank) (Exhibit 4(v), Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-2255, incorporated by
reference).
4(iv) -- Indenture, dated April 1, 1988, between Virginia Electric and
Power Company and The Chase Manhattan Bank (formerly Chemical
Bank), as supplemented and modified by a First Supplemental
Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for
the fiscal year ended December 31, 1993, File No. 1-2255,
incorporated by reference); Second Supplemental Indenture,
dated May 1, 1999 (Exhibit 4.2, Form S-3, Registration
Statement, File No. 333-7615, as filed on April 13, 1999,
incorporated by reference).
4(v) -- Subordinated Note Indenture, dated as of August 1, 1995 between
Virginia Electric and Power Company and The Chase Manhattan
Bank (formerly Chemical Bank), as Trustee, as supplemented
(Exhibit 4(a), Form S-3 Registration Statement File No. 333-
20561 as filed on January 28, 1997, incorporated by reference).
4(vi) -- Form of Senior Indenture, dated as of June 1, 1998, between
Virginia Electric and Power Company and The Chase Manhattan
Bank as supplemented by the First Supplemental Indenture
(Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255,
incorporated by reference); Second Supplemental Indenture
(Exhibit 4.2, Form 8-K, dated June 3, 1999, File No.1-2255,
incorporated by reference) and Third Supplemental Indenture
(Exhibit 4.2, Form 8-K, dated October 27, 1999, File No. 1-
2255, incorporated by reference).
</TABLE>
26
<PAGE>
<TABLE>
<C> <C> <S>
4(vii) -- Indenture, Junior Subordinated Debentures, dated December 1,
1997, between Dominion Resources, Inc. and The Chase Manhattan
Bank as supplemented by a First Supplemental Indenture, dated
December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4
Registration Statement, File No. 333-50653, as filed on April
21, 1998, incorporated by reference); Second and Third
Supplemental Indentures, dated January 1, 2001, (Exhibits 4.6
and 4.13, Form 8-K, dated January 9, 2001, incorporated by
reference).
4(viii) -- Consolidated Natural Gas Company Indentures, Supplemental
Indentures and Securities Resolutions are listed below and
incorporated by reference:
The Chase Manhattan Bank (formerly Manufacturers Hanover Trust
Company)
Indenture dated as of May 1, 1971 (Exhibit (5) to Certificate
of Notification at Commission File No. 70-5012)
Fifteenth Supplemental Indenture dated as of October 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File
No. 70-7651)
Seventeenth Supplemental Indenture dated as of August 1, 1993
(Exhibit (4) to Certificate of Notification at Commission File
No. 70-8167)
Eighteenth Supplemental Indenture dated as of December 1, 1993
(Exhibit (4) to Certificate of Notification at Commission File
No. 70-8167)
Nineteenth Supplemental Indenture dated as of January 28, 2000
(Exhibit (4A)(iii), Form 10-K for the fiscal year ended
December 31, 1999, File No. 1-3196, incorporated by
reference).
Twentieth Supplemental Indenture dated as of March 19, 2001
(filed herewith).
United States Trust Company of New York
Indenture dated as of April 1, 1995 (Exhibit (4) to
Certificate of Notification at Commission File No. 70-8107)
First Supplemental Indenture dated January 28, 2000 (Exhibit
(4 A)(ii), Form 10-K for the fiscal year ended December 31,
1999, File No. 1-3196, incorporated by reference).
Securities Resolution No. 1 effective as of April 12, 1995
(Exhibit 2 to Form 8-A filed April 21, 1995 under File No. 1-
3196 and relating to the 7 3/8% Debentures Due April 1, 2005)
Securities Resolution No. 2 effective as of October 16, 1996
(Exhibit 2 to Form 8-A filed October 18, 1996 under file No.
1-3196 and relating to the 6 7/8% Debentures Due October 15,
2026)
Securities Resolution No. 3 effective as of December 10, 1996
(Exhibit 2 to Form 8-A filed December 12, 1996 under file No.
1-3196 and relating to the 6 5/8% Debentures Due December 1,
2008)
Securities Resolution No. 4 effective as of December 9, 1997
(Exhibit 2 to Form 8-A filed December 12, 1997 under file No.
1-3196 and relating to the 6.80% Debentures Due December 15,
2027)
Securities Resolution No. 5 effective as of October 20, 1998
(Exhibit 2 to Form 8-A filed October 22, 1998 under file No.
1-3196 and relating to the 6% Debentures Due October 15, 2010)
Securities Resolution No. 6 effective as of September 21, 1999
(Exhibit 4A(iv), Form 10-K for the fiscal year ended December
31, 1999, File No. 1-3196, and relating to the 7 1/4% Notes
Due October 1, 2004).
</TABLE>
27
<PAGE>
<TABLE>
<C> <C> <S>
4(ix) -- Senior Indenture, dated June 1, 2000, between Dominion and The
Chase Manhattan Bank, as Trustee (Exhibit 4 (iii), Form S-3,
Registration Statement, File No. 333-93187, incorporated by
reference); First Supplemental Indenture, dated June 1, 2000
(Exhibit 4.2, Form 8-K, dated June 21, 2000, File No. 1-8489,
incorporated by reference); Second Supplemental Indenture,
dated July 1, 2000 (Exhibit 4.2, Form 8-K, dated July 11,
2000, File No. 1-8489, incorporated by reference); Third
Supplemental Indenture, dated July 1, 2000 (Exhibit 4.3, Form
8-K dated July 11, 2000, incorporated by reference); Fourth
Supplemental Indenture and Fifth Supplemental Indenture dated
September 1, 2000 (Exhibit 4.2, Form 8-K, dated September 8,
2000, incorporated by reference); Sixth Supplemental
Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K,
dated September 8, 2000, incorporated by reference); and
Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit
4.2, Form 8-K, dated October 11, 2000, incorporated by
reference). Eighth Supplemental Indenture, dated January 1,
2001 (Exhibit 4.2, Form 8-K, dated January 23, 2001,
incorporated by reference).
4(x) -- Dominion Resources agrees to furnish to the Commission upon
request any other instrument with respect to long-term debt as
to which the total amount of securities authorized thereunder
does not exceed 10% of Dominion Resources' total assets.
10(i) -- Amended and Restated Interconnection and Operating Agreement,
dated as of July 29, 1997 between Virginia Electric and Power
Company and Old Dominion Electric Cooperative (Exhibit 10(v),
Form 10-K for the fiscal year ended December 31, 1997,
File No. 1-8489, incorporated by reference).
10(ii) -- Credit Agreements, dated as of June 7, 1996, between The Chase
Manhattan Bank (formerly Chemical Bank) and Virginia Electric
and Power Company (Exhibit 10(i) and Exhibit 10(ii), Form 10-Q
for the period ended June 30, 1996. File No. 1-2255,
incorporated by reference) and as amended and restated as of
June 4, 1999 (Exhibit 10.2, Form 10-K for the fiscal year
ended December 31, 1999, File No. 1-2255, incorporated by
reference).
10(iii) -- Inter-Company Credit Agreement, dated December 20, 1985, as
modified on August 21, 1987, between Dominion Resources and
Dominion Capital, Inc. (Exhibit 10(vi), Form 10-K for the
fiscal year ended December 31, 1993, File No. 1-8489,
incorporated by reference).
10(iv) -- Inter-Company Credit Agreement, dated October 1, 1987 as
amended and restated as of May 1, 1988 between Dominion
Resources and Dominion Energy, Inc. (Exhibit 10(vii), Form 10-
K for the fiscal year ended December 31, 1993, File No. 1-
8489, incorporated by reference).
10(v) -- Form of Amended and Restated Articles of Partnership in
Commendam of Catalyst Old River Hydroelectric Limited
Partnership, by and between Catalyst Vidalia Corporation and
Dominion Capital, Inc. effective as of August 24, 1990
(Exhibit 10(xii) Form 10-K for the fiscal year ended December
31, 1990, File No. 1-8489, incorporated by reference).
10(vi) -- First Amendment of Trust Agreement of Dominion Resources Black
Warrior Trust, dated June 27, 1994, among Dominion Black
Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank
(DE) National Association and Nationsbank of Texas, N.A.
(Exhibit 10(ii), Form 10-Q for the quarter ended June 30,
1994, File No. 1-8489, incorporated by reference).
</TABLE>
28
<PAGE>
<TABLE>
<C> <C> <S>
10(vii) -- DRI Services Agreement, dated January 28, 2000, by and
between Dominion Resources, Inc., Dominion Resources
Services, Inc. and Consolidated Natural Gas Service
Company, Inc. (Exhibit 10(viii), Form 10-K for the fiscal
year ended December 31, 1999, File No. 1-8489, incorporated
by reference).
10(viii) -- Services Agreement between Dominion Resources Services,
Inc. and Virginia Electric and Power Company dated January
1, 2000 (Exhibit 10.19, Form 10-K for the fiscal year ended
December 31, 1999, File No. 1-2255, incorporated by
reference).
10(ix) -- Support Agreement between Dominion Resources Services, Inc.
and Virginia Electric and Power Company dated January 1,
2000 (Exhibit 10.20, Form 10-K for the fiscal year ended
December 31, 1999, File No. 1-2255, incorporated by
reference).
10(x) -- Alliance Agreement establishing the Alliance Independent
Transmission System Operator, Inc., Alliance Transmission
Company, Inc. and Alliance Transmission Company LLC dated
May 27, 1999 (Exhibit 10.21, Form 10-K for the fiscal year
ended December 31, 1999, File No. 1-2255, incorporated by
reference).
10(xi)* -- Dominion Resources, Inc. Executive Supplemental Retirement
Plan, effective January 1, 1981 as amended and restated
September 1, 1996 (Exhibit 10(iv), Form 10-Q for the
quarter ended June 30, 1997, File No. 1-8489, incorporated
by reference) and as amended June 20, 1997 and as amended
March 3, 1998 (Exhibit 10(xxi), Form 10-K for the fiscal
year ended December 31, 1997, File No. 1-8489, incorporated
by reference).
10(xii)* -- Arrangements with certain executive officers regarding
additional credited years of service for retirement and
retirement life insurance purposes (Exhibit 10(xxii),
Form 10-K for the fiscal year ended December 31, 1997, File
No. 1-8489, incorporated by reference).
10(xiii)* -- Dominion Resources, Inc.'s Cash Incentive Plan as adopted
December 20, 1991 (Exhibit 10(xxii), Form 10-K for the
fiscal year ended December 31, 1991, File No. 1-8489,
incorporated by reference).
10(xiv)* -- Dominion Resources, Inc. Incentive Compensation Plan,
effective April 22, 1997 (Exhibit 99, Form S-8 Registration
Statement, File No 333-25587, incorporated by reference)
and as restated effective April 28, 2000 (Exhibit 99, Form
S-8, Registration Statement, File No. 333-38396,
incorporated by reference).
10(xv)* -- Form of Employment Continuity Agreement for certain
officers of Dominion Resources (Exhibit 10(i), Form 10-Q
for the quarter ended June 30, 1999, File No. 1-8489,
incorporated by reference).
10(xvi)* -- Dominion Resources, Inc. Retirement Benefit Funding Plan,
effective June 29, 1990 as amended and restated September
1, 1996 (Exhibit 10(iii), Form 10-Q for the quarter ended
June 30, 1997, File No. 1-8489, incorporated by reference).
10(xvii)* -- Dominion Resources, Inc. Retirement Benefit Restoration
Plan as adopted effective January 1, 1991 as amended and
restated September 1, 1996 (Exhibit 10(ii), Form 10-Q for
the quarter ended June 30, 1997, File No. 1-8489,
incorporated by reference).
10(xviii)* -- Dominion Resources, Inc. Executives' Deferred Compensation
Plan, effective January 1, 1994 and as amended and restated
January 1, 2001 (filed herewith).
</TABLE>
29
<PAGE>
<TABLE>
<C> <C> <S>
10(xix)* -- Employment Agreement dated April 16, 1999 between Dominion
Resources and Thos. E. Capps (Exhibit 10(ii), Form 10-Q for
the quarter ended March 31, 1999, File No. 1-8489,
incorporated by reference) and Form of Amendment (Exhibit
10(iii), Form 10-Q for the quarter ended June 30, 1999,
File No. 1-8489, incorporated by reference).
10(xx)* -- Form of Employment Agreement between Dominion Resources
certain executive officers including Thomas N. Chewning
(Exhibit 10 (xxx), Form 10-K for the fiscal year ended
December 31, 1997, File No. 1-8489, incorporated by
reference and Exhibit 10(ii), Form 10-Q for the quarter
ended March 31, 1998, File No. 1-8489, incorporated by
reference) and Form of Amendment for Thomas N. Chewning
(Exhibit 10(iii), Form 10-Q for the quarter ended June 30,
1999, File No. 1-8489, incorporated by reference).
10(xxi)* -- Dominion Resources, Inc. Stock Accumulation Plan for
Outside Directors, effective April 23, 1996 (Exhibit 10,
Form 10-Q for the quarter ended March 31, 1996,
File No. 1-8489, incorporated by reference).
10(xxii)* -- Dominion Resources, Inc. Directors Stock Compensation Plan,
effective April 9, 1998 (Exhibit 99, Form S-8 Registration
Statement, File No. 333-49725, incorporated by reference).
10(xxiii)* -- Dominion Resources, Inc. Directors Deferred Cash
Compensation Plan, effective December 21, 1998 (Exhibit 99,
Form S-8 Registration Statement, File No. 333-69305,
incorporated by reference).
10(xxiv)* -- Employment Agreement, dated September 12, 1997 between
Dominion Resources and Edgar M. Roach, Jr. (Exhibit
10(xxxiv), Form 10-K for the fiscal year ended December 31,
1997, File No. 1-8489, incorporated by reference).
10(xxv)* -- Employment Agreement dated September 12, 1997 between
Dominion Resources and Thomas F. Farrell, II (Exhibit
10(xxxiii), Form 10-K for the fiscal year ended December
31, 1998, File No. 1-8489, incorporated by reference) and
Form of Amendment (Exhibit 10 (iii), Form 10-Q for the
quarter ended June 30, 1999, File No. 1-8489, incorporated
by reference).
10(xxvi)* -- Form of Reimbursement Agreement between certain executive
officers and Dominion Resources (Exhibit 10(xxvii), Form
10-K for the fiscal year ended December 31, 1999, File No.
1-2255, incorporated by reference).
10(xxvii)* -- Dominion Resources, Inc. Leadership Stock Option Plan,
effective July 1, 2000 (Exhibit 10(ii), Form 10-Q for the
quarter ended June 30, 2000, File No. 1-8489, incorporated
by reference).
10(xxviii) -- Purchase and Sale Agreement, dated August 7, 2000, by and
among Northeast Nuclear Energy Company, et al and Dominion
Resources, Inc. (Exhibit 10(iii), Form 10-Q for the quarter
ended June 30, 2000, File No. 1-8489, incorporated by
reference).
10(xxix) -- Stock Purchase Agreement, dated May 8, 2000, By and Between
AGL Resources, Inc. as Buyer and Consolidated Natural Gas
Company, as Seller of Virginia Natural Gas, Inc. (Exhibit
10(iii), Form 10-Q for the quarter ended June 30, 2000,
File No. 1-8489, incorporated by reference).
</TABLE>
30
<PAGE>
<TABLE>
<C> <C> <S>
11 -- Computation of Earnings Per Share of Common Stock Assuming Full
Dilution (filed herewith).
13 -- Portions of the 2000 Annual Report to Shareholders for the fiscal
year ended December 31, 2000 (filed herewith).
18(i) -- Letter re: Change in Accounting Principles (Exhibit 18, Form 10-Q
for the quarter ended March 31, 2000, File No. 1-8489,
incorporated by reference).
18(ii) -- Letter re: Change in Accounting Principles (Exhibit 18, Form 10-Q
for the quarter ended September 30, 2000, File No. 1-8489,
incorporated by reference).
21 -- Subsidiaries of the Registrant (filed herewith).
23 -- Consent of Deloitte & Touche LLP (filed herewith).
</TABLE>
- --------
* Indicates management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
1. Dominion filed a report on Form 8-K, dated November 16, 2000, relating to
Dominion's agreement in principle with the Environmental Protection Agency
regarding environmental improvements at coal-fired generating stations in
Virginia and West Virginia.
2. Dominion filed a report on Form 8-K, dated November 22, 2000, relating to
the Dominion's Purchase Agreement with Merrill Lynch, Pierce, Fenner & Smith
Incorporated (Merrill Lynch and Co.) to sell 6,000,000 shares of common stock
to Merrill Lynch & Co.
3. Dominion filed a report on Form 8-K, dated January 9, 2001, relating to
(i) the Dominion and Dominion Resources Capital Trust III underwriting
agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan
Stanley & Co. for the sale of 250,000 8.4% Capital Securities and (ii) the
Dominion and Dominion Resources Capital Trust II underwriting agreement with
Merrill Lynch for the sale of 12,000,000 8.4% Trust Preferred Securities.
4. Dominion filed a report on Form 8-K, dated January 23, 2001, relating to
the Dominion's underwriting agreement with Lehman Brothers Inc. for the sale of
$1,000,000,000 2001 Series A 6% Senior Notes Due 2003.
31
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the consolidated financial statements of Dominion Resources,
Inc. and subsidiaries as of December 31, 2000 and 1999, and for each of the
three years in the period ended December 31, 2000, and have issued our report
thereon dated January 25, 2001; such consolidated financial statements and
report are included in your 2000 Annual Report to Shareholders and are
incorporated herein by reference. Our audits also included the consolidated
financial statement schedules of Dominion Resources, Inc. and subsidiaries,
listed in Item 14. These consolidated financial statement schedules are the
responsibility of the Company's management. Our responsibility is to express an
opinion based on our audits. In our opinion, such consolidated financial
statement schedules, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly in all material respects
the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Richmond, Virginia
January 25, 2001
32
<PAGE>
DOMINION RESOURCES, INC.
Schedule I--Condensed Financial Information of Registrant
Condensed Statements of Income
<TABLE>
<CAPTION>
Years Ended
December 31,
----------------
2000 1999 1998
---- ---- ----
(millions)
<S> <C> <C> <C>
Operating revenue and income.................................. $ 3 $ $
Operating expenses............................................ 31 37 36
---- ---- ----
Loss from operations.......................................... (28) (37) (36)
---- ---- ----
Other income.................................................. 47 47 35
---- ---- ----
Income (loss) before interest and income taxes................ 19 10 (1)
Interest charges.............................................. 350 44 35
---- ---- ----
Loss before income taxes...................................... (331) (34) (36)
Income tax benefit (expense).................................. 129 17 (16)
Equity in undistributed earnings of subsidiaries.............. 638 314 600
---- ---- ----
Net income $436 $297 $548
==== ==== ====
</TABLE>
The accompanying notes are an integral part of the Condensed Financial
Statements.
33
<PAGE>
DOMINION RESOURCES, INC.
Schedule I--Condensed Financial Information of Registrant
Condensed Balance Sheets
<TABLE>
<CAPTION>
At December 31, At December 31,
2000 1999
--------------- ---------------
(millions)
<S> <C> <C>
Assets
Current assets:
Cash and cash equivalents..................... $ 51 $ 28
Accounts receivable........................... 7 36
Other......................................... 33 15
------- ------
Total current assets.......................... 91 79
------- ------
Investments:
Investment in subsidiaries.................... 10,881 5,115
Advances to affiliates........................ 951 340
Other 3 17
------- ------
11,835 5,472
------- ------
Property, plant and equipment:
Nonutility property........................... 35 42
Accumulated depreciation and amortization..... (13) (16)
------- ------
22 26
------- ------
Deferred charges and other assets.............. 3 37
------- ------
Total assets.................................... $11,951 $5,614
======= ======
Liabilities and Stockholders' Equity
Current liabilities:
Short-term debt............................... $ 1,306 $ 197
Accounts payable.............................. 6 9
Accrued interest.............................. 63 2
Accrued taxes................................. 71 20
Other......................................... 27 24
------- ------
Total current liabilities..................... 1,473 252
------- ------
Long-term debt................................. 3,438 576
------- ------
Deferred credits and other liabilities......... 48 12
------- ------
Stockholders' equity:
Common stock.................................. 5,979 3,561
Other paid-in capital......................... 16 16
Accumulated other comprehensive income........ (31) (15)
Retained earnings............................. 1,028 1,212
------- ------
6,992 4,774
------- ------
Total liabilities and stockholders' equity..... $11,951 $5,614
======= ======
</TABLE>
The accompanying notes are an integral part of the Condensed Financial
Statements.
34
<PAGE>
DOMINION RESOURCES, INC.
Schedule I--Condensed Financial Information of Registrant
Condensed Statements of Cash Flows
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------
2000 1999 1998
--------- -------- --------
(millions)
<S> <C> <C> <C>
Net cash flows to operating activities........... $ (30) $ (66) $ (30)
Cash flows from(to) financing activities:
Issuance of common stock........................ 532 354
Repurchase of common stock...................... (1,641) (372) (99)
(Repayment) issuance of long-term debt.......... 2,863 493 (401)
(Repayment) issuance of short-term debt......... 1,108
Dividend payments............................... (615) (493) (503)
Other........................................... 1 4
--------- ------- --------
Net cash flows from(to) financing activities.... 2,247 (371) (645)
Cash flows from(to) investing activities:
Purchase of Consolidated Natural Gas Company.... (2,869)
Investment in affiliates........................ (71) (216) (413)
Inter-company advances.......................... (611) 107 (114)
Dividends received from subsidiaries............ 1,340 519 1,213
Other........................................... 17 (16) 38
--------- ------- --------
Net cash flows from(to) investing activities.... (2,194) 394 724
Increase (decrease) in cash and cash
equivalents..................................... 23 (43) 49
Cash and cash equivalents at beginning of year... 28 71 22
--------- ------- --------
Cash and cash equivalents at end of year......... $ 51 $ 28 $ 71
========= ======= ========
Supplemental cash flow information:
Non-cash transaction from investing and financing
activities:
Common stock issuance--acquisition of
Consolidated Natural Gas Company............... $ 3,527
</TABLE>
The accompanying notes are an integral part of the Condensed Financial
Statements.
35
<PAGE>
DOMINION RESOURCES, INC.
Schedule I--Condensed Financial Information of Registrant
Notes to Condensed Financial Statements
Note 1. Basis of Presentation
Pursuant to rules and regulations of the Securities and Exchange Commission,
the unconsolidated condensed financial statements of Dominion Resources, Inc.
(the Company) do not reflect all of the information and notes normally included
with financial statements prepared in accordance with generally accepted
accounting principles. Therefore these financial statements should be read in
conjunction with the consolidated financial statements and related notes
included in the fiscal 2000 Annual Report to Shareholders (2000 Annual Report)
as referenced in Form 10-K, Part II, Item 8.
Accounting for subsidiaries--The Company has accounted for the earnings of
its subsidiaries under the equity method in the unconsolidated condensed
financial statements.
Income Taxes--The unconsolidated income tax expense or benefit computed for
the Company in accordance with Statement of Financial Accounting Standards No.
109, Accounting for Income Taxes, reflects the tax assets and liabilities of
the Company on a stand alone basis and the effect of filing a consolidated U.S.
tax return with its subsidiaries.
Note 2. Long-term debt
<TABLE>
<CAPTION>
At December 31,
-----------------------------------------
2000 1999
-------------------- --------------------
Interest Interest
Balance Rate(/3/) Balance Rate(/3/)
---------- --------- ---------- ---------
(millions) (millions)
<S> <C> <C> <C> <C>
Senior notes:
2000 Series C, due 2003............ $ 400 7.6
2000 Series B, due 2005............ 700 7.6
2000 Various series, due 2010-
2014.............................. 1,400 7.2-8.1
Mandatory convertibles, convert
2004............................... 412 8.1
Commercial paper(/1/)............... 250 $300
Junior subordinated debentures, due
2027............................... 258 7.8 258 7.8
Bank loans, due 2004-2008(/2/)...... 18 7.3 18 5.8
------ ------- ---- ---
Total long-term debt................ $3,438 $576
====== ====
</TABLE>
- --------
(/1/)The weighted average interest rate for the years 2000 and 1999 were 6.5%
and 5.4%, respectively.
(/2/)Real estate at the Company is pledged as collateral.
(/3/)Interest rates are rounded to the nearest one-tenth of one-percent and
consist of weighted average interest rates for variable rate debt.
Maturities (including sinking fund obligations) through 2005 are as follows
(millions): 2003-$400; 2004-$431; 2005-$700.
In January 2001, the Company issued $1.0 billion of 2-year fixed rate 6%
notes, $309 million in aggregate principal of 8.4% junior subordinated
debentures due 2041 and $258 million in aggregate principal of 8.4% junior
subordinated debentures due 2031. See Notes 16 and 17 to the 2000 Annual
Report.
36
<PAGE>
Note 3. Guarantees
The Company has issued guarantees to various third parties in relation to
the payment of obligations by certain of its subsidiaries and officers. At
December 31, 2000, the Company had issued $1.8 billion of guarantees, and the
subsidiaries' debt subject to such guarantees totaled $1.2 billion.
Note 4. Dividends received from consolidated subsidiaries
The Company received dividends from its consolidated subsidiaries in the
amounts of $1.3 billion, $519 million and $1.2 billion for the years 2000,
1999, and 1998, respectively. Cash dividends in 2000 included approximately
$770 million reflecting proceeds from divestitures at certain of the Company's
subsidiaries (see Note 5 to the 2000 Annual Report). Cash dividends in 1998
included approximately $720 million reflecting a portion of the proceeds from
the sale of East Midlands Electricity plc by a subsidiary.
Consolidated Natural Gas Company (CNG), a consolidated subsidiary of the
Company, has indentures related to its long-term debt, one of which contained
restrictions on dividend payments at December 31, 2000. As of that date, $19
million of CNG's consolidated retained earnings were free from such
restriction. In March 2001, CNG requested and obtained the consent of debt
holders to amend the indenture to eliminate certain provisions of the
indenture, including such restriction. CNG received an order from the
Securities and Exchange Commission on March 19, 2001, approving the amendment
of the indenture.
37
<PAGE>
DOMINION RESOURCES, INC.
Schedule II--Valuation and Qualifying Accounts
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
-------- ---------- ------------------ ---------- ----------
Additions
------------------
Balance at Charged Charged Balance at
beginning to to other end of
Description of period expense accounts Deductions period
----------- ---------- ------- -------- ---------- ----------
(millions)
<S> <C> <C> <C> <C> <C> <C>
Valuation and qualifying
accounts which are
deducted in the balance
sheet from the assets
to which they apply:
Allowance for doubtful
accounts............... 1998 $ 2 $13 $10 (a) $ 5
1999 5 19 12 (a) 12
2000 36 (d) 71 $ 1 39 (a) 67
Allowance for loan
losses................. 1998 18 30 1 (a) 47
1999 47 11 11 (a) 47
2000 47 35 21 (a) 61
Valuation allowance for
commodity contracts.... 1998 13 13
1999 13 9 (b) 22
2000 22 (3)(b) 19
Reserves:
Liabilities for pre-2000
workforce reductions... 1998 30 2 16 (c) 16
1999 16 12 (c) 4
2000 12 (d) 9 (c) 3
Liabilities for
restructuring actvities
....................... 1998
1999
2000 92 55 (c) 37
</TABLE>
- --------
(a) Represents net amounts charged off as uncollectible.
(b) Amounts are net of adjustments to allowance reflecting changes in
estimates.
(c) Represents payments for workforce reductions and/or restructuring
liabilities.
(d) Includes balance of acquired company at date of acquisition.
38
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Dominion Resources, Inc.
/s/ Thomas E. Capps
By: _________________________________
(Thos E. Capps, Chairman of the
Board of Directors, President and
Chief Executive Officer)
Date: March 20, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated and on the 20th day of March, 2001.
<TABLE>
<CAPTION>
Signature Title
--------- -----
<S> <C>
/s/ Thos. E. Capps Chairman of the Board of Directors,
________________________________________________ President and Chief Executive
Thos. E. Capps Officer
/s/ William S. Barrack, Jr. Director
________________________________________________
William S. Barrack, Jr.
/s/ George A. Davidson, Jr. Director, Former Chairman of the
________________________________________________ Board of Directors
George A. Davidson, Jr.
/s/ Raymond E. Galvin Director
________________________________________________
Raymond E. Galvin
/s/ John W. Harris Director
________________________________________________
John W. Harris
/s/ Benjamin J. Lambert, III Director
________________________________________________
Benjamin J. Lambert, III
/s/ Richard L. Leatherwood Director
________________________________________________
Richard L. Leatherwood
/s/ Paul E. Lego Director
________________________________________________
Paul E. Lego
/s/ Margaret A. McKenna Director
________________________________________________
Margaret A. McKenna
</TABLE>
39
<PAGE>
<TABLE>
<CAPTION>
Signature Title
--------- -----
<S> <C>
/s/ Steven A. Minter Director
________________________________________________
Steven A. Minter
/s/ K. A. Randall Director
________________________________________________
K. A. Randall
/s/ Frank S. Royal Director
________________________________________________
Frank S. Royal
/s/ S. Dallas Simmons Director
________________________________________________
S. Dallas Simmons
/s/ Robert H. Spilman Director
________________________________________________
Robert H. Spilman
/s/ David A. Wollard Director
________________________________________________
David A. Wollard
/s/ Thomas N. Chewning Executive Vice President
________________________________________________ and Chief Financial
Thomas N. Chewning Officer
/s/ Steven A. Rogers Vice President, Controller
________________________________________________ and Principal Accounting
Steven A. Rogers Officer
</TABLE>
40
<PAGE>
DOMINION RESOURCES, INC.
PORTIONS
OF THE
2000
ANNUAL REPORT
TO
SHAREHOLDERS
(Incorporated by Reference)
41
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.8
<SEQUENCE>2
<FILENAME>0002.txt
<DESCRIPTION>TWENTIETH SUPPLEMENTAL INDENTURE
<TEXT>
<PAGE>
TWENTIETH SUPPLEMENTAL INDENTURE (the "Twentieth Supplemental Indenture"),
dated as of March 19, 2001 between Consolidated Natural Gas Company, a Delaware
corporation (including its predecessors by merger, the "Company"), and The Chase
Manhattan Bank, a New York banking corporation, formerly known as Chemical Bank,
successor by merger to Manufacturers Hanover Trust Company, as Trustee (the
"Trustee"), to the Indenture between the Company and the Trustee, dated as of
May 1, 1971, as amended or supplemented from time to time (the "Indenture").
WITNESSETH:
WHEREAS, the Company has requested the Trustee to enter into this Twentieth
Supplemental Indenture for the purpose of amending and modifying the Indenture
in accordance with Section 14.02 of the Indenture; and
WHEREAS, consents of the requisite holders of the Debentures to the
execution of this Twentieth Supplemental Indenture, together with an officers'
certificate and opinion of counsel, all in accordance with Section 14.03 of the
Indenture, have been delivered to the Trustee.
NOW, THEREFORE, intending to be legally bound hereby, the parties hereto
agree as follows:
ARTICLE I
AMENDMENTS TO THE INDENTURE
Section 1.1. Sections 6.05, 6.06, 6.07, 6.08, 6.09 and 6.10 of the
Indenture are deleted and shall have no further force and effect.
Section 1.2 Section 4.01 of each of the Seventeenth and Eighteenth
Supplemental Indentures is deleted and shall have no further force and effect.
Section 1.3. A new Section 6.15 is added to the Indenture, reading as
follows:
SECTION 6.15. The Company shall perform, observe and comply with all the
covenants and restrictions of the Indenture, dated as of April 1, 1995,
between the Company and United States Trust Company of New York, as
Trustee, as amended and supplemented from time to time (the "1995
Indenture"); provided, that no amendment requiring consent of the holders
of debt securities under the 1995 Indenture shall apply to the Indenture
unless such amendment shall have been approved and consented to in
accordance with the procedures set forth in Article Fourteen of this
Indenture.
Section 1.4. No additional Debentures may be issued under the Indenture.
<PAGE>
ARTICLE II
EFFECTIVE TIME
Section 2.1 This Twentieth Supplemental Indenture shall become effective
immediately upon its execution by the parties hereto and without any further
action by any person as of the date hereof.
ARTICLE III
MISCELLANEOUS PROVISIONS
Section 3.1 The Indenture, as amended and modified by this Twentieth
Supplemental Indenture, is in all respects ratified and confirmed; this
Twentieth Supplemental Indenture shall be deemed part of the Indenture in the
manner and to the extent herein and therein provided; and all the terms,
conditions, and provisions of the Indenture shall remain in full force and
effect, as amended and modified hereby.
Section 3.2 This Twentieth Supplemental Indenture shall be deemed to be a
contract made under the laws of the State of New York, and for all purposes
shall be construed in accordance therewith.
Section 3.3 The recitals herein contained are made by the Company and not
by the Trustee, and the Trustee assumes no responsibility for the correctness
thereof. The Trustee makes no representation as to the validity or sufficiency
of this Twentieth Supplemental Indenture.
Section 3.4 This Twentieth Supplemental Indenture may be executed in any
number of counterparts and by different parties thereto on separate
counterparts, each of which when so executed shall be deemed to be an original
and all of which taken together shall constitute but one and the same agreement.
Section 3.5 Capitalized terms used herein without definition have the
meanings assigned such terms in the Indenture.
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Twentieth
Supplemental Indenture to be duly executed and their respective corporate seals
to be hereunto affixed and attested, all as of the date hereof.
CONSOLIDATED NATURAL GAS COMPANY
By: /s/ G. Scott Hetzer
--------------------------------------------
Name: G. Scott Hetzer
Title: Senior Vice President and Treasurer
Attest:
By: /s/ J. P. Carney
--------------------------------
Name: J. P. Carney
Title: Assistant Treasurer
THE CHASE MANHATTAN BANK, as Trustee
By: /s/ Natalia Rodriguez
------------------------------------------
Name: Natalia Rodriguez
Title: Assistant Vice President
Attest:
By: /s/ Diane Darconte
---------------------
Name: Diane Darconte
Title: Trust Officer
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.18
<SEQUENCE>3
<FILENAME>0003.txt
<DESCRIPTION>EXECUTIVE DEFERRED COMPENSATION PLAN
<TEXT>
<PAGE>
Exhibit 10(xviii)
DOMINION RESOURCES, INC.
EXECUTIVES' DEFERRED COMPENSATION PLAN
AMENDED AND RESTATED
Effective January 1, 2001
For the Executives of:
Dominion Resources, Inc.
And Affiliates
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Section Page
- ------- ----
<S> <C>
1. DEFINITIONS............................................................ 1
2. PURPOSE................................................................ 4
3. PARTICIPATION.......................................................... 4
4. DEFERRAL ELECTION...................................................... 5
5. EFFECT OF NO ELECTION.................................................. 6
6. FORMER CNG PLANS....................................................... 6
7. DEFERRED STOCK OPTION BENEFIT.......................................... 7
8. MATCH CONTRIBUTIONS.................................................... 7
9. INVESTMENT FUNDS....................................................... 8
10. DISTRIBUTIONS.......................................................... 9
11. HARDSHIP DISTRIBUTIONS................................................. 10
12. COMPANY'S OBLIGATION................................................... 11
13. CONTROL BY PARTICIPANT................................................. 12
14. CLAIMS AGAINST PARTICIPANT'S BENEFIT................................... 12
15. AMENDMENT OR TERMINATION............................................... 12
16. ADMINISTRATION......................................................... 12
17. NOTICES................................................................ 13
18. WAIVER................................................................. 13
19. CONSTRUCTION........................................................... 13
</TABLE>
i
<PAGE>
DOMINION RESOURCES, INC.
EXECUTIVES' DEFERRED COMPENSATION PLAN
1. DEFINITIONS. The following definitions apply to this Plan and to any
-----------
related documents.
(a) Accounts means, collectively, a Participant's Deferral Account, Match
--------
Account, and Deferred Stock Option Account, if any.
(b) Administrator means Dominion Resources Services, Inc.
-------------
(c) Beneficiary or Beneficiaries means a person or persons or other entity that
----------- -------------
a Participant designates on a Beneficiary Designation Form to receive
Benefit payments pursuant to Plan Section 9(i). If a Participant does not
execute a valid Beneficiary Designation Form, or if the designated
Beneficiary or Beneficiaries fail to survive the Participant or otherwise
fail to take the Benefit, the Participant's Beneficiary or Beneficiaries
shall be the first of the following persons who survive the Participant: a
Participant's spouse (the person legally married to the Participant when
the Participant dies); the Participant's children in equal shares. If none
of these persons survive the Participant, the Beneficiary shall be the
Participant's estate.
(d) Beneficiary Designation Form means the form that a Participant uses to name
----------------------------
the Participant's Beneficiary or Beneficiaries.
(e) Benefit means collectively, a Participant's Deferred Benefit, Match
-------
Benefit, and Deferred Stock Option Benefit, if any.
(f) Board means the Board of Directors of DRI.
-----
(g) Change of Control means the occurrence of any of the following events:
-----------------
(i) any person, including a "group" as defined in Section 13(d)(3) of
Securities Exchange Act of 1934, as amended, becomes the owner or
beneficial owner of DRI securities having 20% or more of the combined
voting power of the then outstanding DRI securities that may be cast for
the election of DRI's directors (other than as a result of an issuance of
securities initiated by DRI, or open market purchases approved by the
Board, as long as the majority of the Board approving the purchases is also
the majority at the time the purchases are made);
(ii) as the direct or indirect result of, or in connection with, a cash
tender or exchange offer, a merger or other business combination, a sale of
assets, a contested election, or any combination of these transactions, the
persons who were directors of DRI before such transactions cease to
constitute a majority of
1
<PAGE>
the Board, or any successor's board, within two years of the last of such
transactions; or
(iii) with respect to a particular Participant, an event occurs with
respect to the Participant's employer such that, after the event, the
Participant's employer is no longer a Dominion Company.
(h) Code means the Internal Revenue Code of 1986, as amended.
----
(i) Committee means the Organization, Compensation and Nominating Committee of
---------
the Board.
(j) Company means DRI and any Dominion Company that is designated by the
-------
Administrator as covered by this Plan, and any successor business by
merger, purchase, or otherwise that maintains the Plan.
(k) Compensation means a Participant's base salary, cash incentive pay and
------------
other cash compensation from the Company, including annual bonuses, pre-
scheduled one-time performance-based payments, and gains from stock option
grants. Compensation does not include stock, stock options or spot awards.
The Administrator may determine whether to include or exclude an item of
income from Compensation.
(l) Deferral means the amount of Compensation that a Participant has elected to
--------
defer under a Deferral Election Form.
(m) Deferral Account means a bookkeeping record established for each
----------------
Participant who is eligible to receive a Deferred Benefit. A Deferral
Account shall be established only for purposes of measuring a Deferred
Benefit and not to segregate assets or to identify assets that may be used
to satisfy a Deferred Benefit. A Deferral Account shall be credited with
that amount of a Participant's Compensation deferred according to a
Participant's Deferral Election Form. A Deferral Account also shall be
credited periodically with deemed investment gain or loss under Plan
Section 8.
(n) Deferral Election Form means the form that a Participant uses to elect to
----------------------
defer Compensation pursuant to Plan Section 4.
(o) Deferred Benefit means the benefit available to a Participant who has
----------------
executed a valid Deferral Election Form.
(p) Deferred Stock Option Account means a bookkeeping record established for
-----------------------------
each Participant who has made an election to defer the DRI Stock to be
received under an exercise of a nonstatutory stock option granted under the
Dominion Resources, Inc. Incentive Compensation Plan and the Dominion
Resources, Inc. Leadership Stock Option Plan. The account shall be charged
or credited with net earnings, gains, losses and expenses, as well as any
appreciation or depreciation
2
<PAGE>
in market value during each Plan Year for the deemed investment in the DRI
Stock. The Administrator may charge or credit such earnings, gains, losses,
appreciation and depreciation based on the actual investment performance of
the DRI Stock that it has deposited into the trust.
(q) Deferred Stock Option Benefit means the portion of a Participant's Benefit
-----------------------------
from the Participant's Deferred Stock Option Account.
(r) Disability or Disabled means, with respect to a Participant, that the
---------- --------
Participant is entitled to benefits under the long-term disability plan of
the Company.
(s) Distribution Election Form means a form that a Participant uses to
--------------------------
establish the duration of the deferral of Compensation and the frequency of
payments of a Benefit. If a Participant does not execute a valid
Distribution Election Form, the distribution of a Benefit shall be governed
by Plan Section 9.
(t) Dominion Company means Consolidated Natural Gas, Inc., Virginia Power,
----------------
Dominion Capital, Inc., Dominion Energy, Inc., Dominion Resources Services,
Inc., or another corporation in which DRI owns stock possessing at least 50
% of the combined voting power of all classes of stock or which is in a
chain of corporations with DRI in which stock possessing at least 50% of
the combined voting power of all classes of stock is owned by one or more
other corporations in the chain.
(u) DRI means Dominion Resources, Inc.
---
(v) DRI Stock means the common stock, no par value, of DRI.
---------
(w) DRI Stock Fund means an Investment Fund in which the deemed investment is
--------------
DRI Stock.
(x) Election Date means the date by which an Executive must submit a valid
-------------
Deferral Election Form for regular Compensation. For each Plan Year, the
Election Date shall be January 1 unless the Administrator sets an earlier
Election Date or as provided in Plan Section 4(b) or 4(c).
(y) Executive means an individual who is employed by the Company and who (i) is
---------
an executive in salary grades A through G, (ii) has Compensation in excess
of the dollar limit for the Plan Year under Code section 401(a)(17), or
(iii) has reached the age of 50 and who has a base salary of at least
$100,000.
(z) Investment Fund means one or more deemed investment alternatives offered to
---------------
Participants from time to time. The Company may compute deemed investment
gain or loss under the Investment Funds based on the actual investment
performance of assets that it has deposited in a grantor trust (as
described in Plan Section 11). The DRI Stock Fund shall be one of the
Investment Funds.
3
<PAGE>
(aa) Match Account means an Account that holds the matching contributions made
-------------
by the Company under Plan Section 8.
(bb) Match Benefit means the portion of a Participant's Benefit from the
-------------
Participant's Match Account.
(cc) Participant means an individual presently or formerly employed by the
-----------
Company who meets one or more of the requirements of Plan Section 3(a).
(dd) Plan means the Dominion Resources, Inc. Executives' Deferred Compensation
----
Plan.
(ee) Plan Year means a calendar year.
---------
(ff) Terminate or Termination, with respect to a Participant, means the
--------- -----------
cessation of the Participant's employment with the Company on account of
death, Disability, severance or any other reason.
2. PURPOSE. The Plan is intended to benefit a "select group of management or
-------
highly compensated employees," as that term is used under Title I of the
Employee Retirement Income Security Act of 1974, as amended. The Plan is
intended to permit Executives to defer their Compensation, and for related
purposes.
3. PARTICIPATION.
-------------
(a) An individual presently or formerly employed by the Company is a
Participant if he or she is:
(i) With respect to any Plan Year, an Executive who executes a valid
Deferral Election Form for that Plan Year as provided in Plan Section
3(b);
(ii) An individual who has a Deferred Stock Option Account due to an
election to defer DRI Stock;
(iii) An individual who is eligible for a Match under Plan Section 8;
(iv) An individual who had a benefit entitlement under Section 4.1.(b) of
the CNG ERISA Excess Plan as of December 31, 2000; or
(v) An individual who had a benefit entitlement under Section 5 of the
Consolidated Natural Gas Company Executive Incentive Deferral Plan as
of December 31, 2000.
(b) An Executive may become a Participant for any Plan Year by filing a valid
Deferral Election Form according to Plan Section 4 on or before the
Election Date for that Plan Year, or by filing an election to defer DRI
Stock pursuant to the Dominion Resources, Inc. Incentive Compensation Plan,
the Dominion
4
<PAGE>
Resources, Inc. Leadership Stock Option Plan or any other plan designated
by the Administrator.
(c) An individual remains a Participant as long as the Participant is entitled
to a Benefit under the Plan. An individual who is a Participant under
Section 3(a)(iv) or (v) and who is not an Executive may direct deemed
investments pursuant to Section 9 but may not make a Deferral election
under Section 4.
4. DEFERRAL ELECTION. An Executive may elect on or before the Election Date to
-----------------
defer receipt of a portion of the Executive's Compensation for the Plan Year.
Except as provided in Plan Section 4(a), an Executive may elect a deferral for
any Plan Year only if he or she is an Executive on the Election Date for that
Plan Year. The following provisions apply to deferral elections:
(a) A Participant may defer up to 50% of the Participant's base salary and up
to 80% of the Participant's annual cash incentive award, long-term cash
incentive payments and pre-scheduled one-time cash payments. Compensation
for deferrals under the Dominion Resources, Inc. Employee Savings Plan
shall be based on a Participant's Compensation after any deferrals made
under this Plan.
(b) A Participant may defer up to 90% of the Participant's gains on stock
acquired by exercise of an option under the Dominion Resources, Inc.
Incentive Compensation Plan or the Dominion Resources, Inc. Leadership
Stock Option Plan. For purposes of deferral of stock option gains, the
Election Date shall be the date that is six months before the Participant
exercises the option. Procedures for deferring stock option gains shall be
established under the Dominion Resources, Inc. Incentive Compensation Plan
and the Dominion Resources, Inc. Leadership Stock Option Plan.
(c) Before each Plan Year's Election Date, each Executive shall be provided
with a Deferral Election Form. Except as provided below, a deferral
election shall be valid only when the Deferral Election Form is completed,
signed by the electing Executive, and received by the Administrator on or
before the Election Date for that Plan Year. In the year in which an
Executive is first promoted to a salary grade between A through G, the
Executive may make a deferral election by completing a Deferral Election
Form within 30 days of the promotion. The deferral election will be
effective for periods after the Administrator receives it.
(d) An Executive must complete an Investment Election Form for all amounts in
the Executive's Deferral Account. The Compensation deferred under a
Deferral Election Form shall be allocated among available Investment Funds
in percentages as specified on the investment election form.
(e) An Executive must complete a Distribution Election Form for the
distribution of the Executive's Deferral Account.
5
<PAGE>
(f) The Administrator may reject any Deferral Election Form or any Distribution
Election Form or both that does not conform to the provisions of the Plan.
The Administrator may modify any Distribution Election Form at any time to
the extent necessary to comply with any federal securities laws or
regulations. The Administrator's rejection or modification must be made on
a uniform basis with respect to similarly situated Executives. If the
Administrator rejects a Deferral Election Form, the Executive shall be paid
the amounts the Executive would have been entitled to receive if the
Executive had not submitted the rejected Deferral Election Form.
(g) An Executive may not revoke a Deferral Election Form after the Plan Year
begins, except that an Executive may revoke a Deferral Election Form within
30 days following a Change of Control. Any revocation before the beginning
of the Plan Year or within 30 days following a Change of Control has the
same effect as a failure to submit a Deferral Election Form. Any writing
signed by an Executive expressing an intention to revoke the Executive's
Deferral Election Form and delivered to the Administrator before the close
of business on the relevant Election Date shall be a revocation.
(h) Subject to the distribution restrictions of Plan Section 9, an Executive
may revoke an existing Distribution Election Form at any time by submitting
a new Distribution Election Form.
5. EFFECT OF NO ELECTION. Except as provided in Plan Section 4(c), an Executive
---------------------
who has not submitted a valid Deferral Election Form to the Administrator on or
before the relevant Election Date may not defer any part of the Executive's
Compensation for the Plan Year. The Deferred Benefit of an Executive who submits
a valid Deferral Election Form but fails to submit a valid Distribution Election
Form (either as to the form or commencement of payment) before the relevant
Election Date shall be distributed in a lump sum on or before the February 28
following the calendar year of the Executive's Termination.
6. FORMER CNG PLANS.
----------------
(a) The Plan has assumed a portion of the obligations and liabilities of the
Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural
Gas Company and its Participating Subsidiaries Who are Not Represented by a
Recognized Union ("CNG ERISA Excess Plan") with respect to Participants in
the Plan. The portion assumed by the Plan is the liabilities related to
"Matching Contributions" under the "Thrift Plan" (as those terms are
defined in the CNG ERISA Excess Plan) and related gains and losses as of
December 31, 2000. A Participant's Benefit as of January 1, 2001 shall
include the Participant's account under the CNG ERISA Excess Plan as of
December 31, 2000. The payment of a Participant's Benefit from this Plan
shall be in complete satisfaction of the Participant's benefits under
Section 4.1.(b) of the CNG ERISA Excess Plan. A Participant's Investment
Election Form, Distribution Election Form and
6
<PAGE>
Beneficiary Election Form shall apply to the portion of the Participant's
Benefit from the CNG ERISA Excess Plan.
(b) The Plan has assumed all of the obligations and liabilities of the
Consolidated Natural Gas Company Executive Incentive Deferral Plan ("CNG
Deferral Plan") with respect to Participants in the Plan. The liabilities
assumed by the Plan are the liabilities of the CNG Deferral Plan as of
December 31, 2000 equal to the sum of all Participants' balances as of
December 31, 2000 in the CNG Deferral Plan. The Participant's balance in
the CNG Deferral Plan shall be part of the Participant's Benefit as of
January 1, 2001. A Participant's Benefit as of January 1, 2001 shall
include the Participant's account under the CNG Deferral Plan as of
December 31, 2000. The payment of a Participant's Benefit from this Plan
shall be in complete satisfaction of the Participant's benefits under
Section 5 of the CNG Deferral Plan. A Participant's Investment Election
Form, Distribution Election Form and Beneficiary Election Form shall apply
to the portion of the Participant's Benefit from the CNG Deferral Plan.
7. DEFERRED STOCK OPTION BENEFIT. A Participant's Deferred Stock Option Benefit
-----------------------------
shall remain deemed invested in DRI Stock until distribution. Such Participant's
Distribution Election Form and Beneficiary Election Form shall apply to the
Participant's Deferred Stock Option Benefit. If the Company has delivered shares
of DRI Stock to a trust to satisfy the Deferred Stock Option Benefit, payment of
the Deferred Stock Option Benefit shall be tracked as stock and made in shares
of DRI Stock from the trust. If the Company has not delivered shares of DRI
Stock to a trust, the Company shall make payment of the Deferred Stock Option
Benefit in DRI Stock through the Dominion Resources, Inc. Incentive Compensation
Plan and the Dominion Resources, Inc. Leadership Stock Option Plan.
8. MATCH CONTRIBUTIONS.
-------------------
(a) With respect to each Plan Year, the Company shall credit a Match (as
defined below) to the Match Account of each eligible Participant. To be
eligible for a Match, a Participant must meet all of the following
criteria:
(i) be employed on December 31 or have Terminated during the Plan Year
due to retirement or early retirement (as defined by the Dominion
Savings Plan), death or Disability;
(ii) have made salary deferrals to the Dominion Savings Plan for the Plan
Year; and
(iii) have base salary for the Plan Year in excess of the dollar limit for
the Plan Year under Code section 401(a)(17).
(b) The amount of the Match will be determined under the following formula:
Excess Compensation times Deferral Percentage times Match Percentage. The
----- -----
terms in the formula have the following meanings.
7
<PAGE>
(i) Excess Compensation is the amount of the Participant's base salary
-------------------
for the Plan Year in excess of the dollar limit for the Plan Year
under Code section 401(a)(17).
(ii) Deferral Percentage is the total of the Participant's salary
-------------------
deferrals to the Dominion Savings Plan for the Plan Year divided by
the lesser of (i) the dollar limit for the Plan Year under Code
section 401(a)(17), or (ii) the Participant's base salary for the
Plan Year reduced by deferrals under this Plan and the Dominion
Savings Plan. The Deferral Percentage may not exceed the maximum
percentage of compensation on which the Participant would be eligible
to receive a match by making a deferral under the Dominion Savings
Plan for the Plan Year.
(iii) Match Percentage is the percentage of company match made with respect
----------------
to the Participant's salary deferral to the Dominion Savings Plan.
(c) A Participant's Match Account will be vested to the same extent that the
Participant's match account in the Dominion Savings Plan is vested. If a
Participant Terminates employment when the Match Account is not vested, the
Match Account will be forfeited.
(d) A Participant will not be required to invest any portion of the Match
Account in the DRI Stock Fund. The Administrator may establish further
procedures for the administration of the Match Account.
9. INVESTMENT FUNDS.
----------------
(a) Each Participant shall have the right to direct the deemed investment of
the Participant's Deferral Account and the Match Account among the
Investment Funds. The Administrator shall determine the number and type of
Investment Funds that will be available for investment in any Plan Year.
(b) Deferrals shall be credited to an Investment Fund as of the date on which
the deferred Compensation would have been paid to the Participant. A
separate bookkeeping account shall be established for each Participant who
has directed a deemed investment in an Investment Fund. Deemed transfers
between Investment Funds in the Participant's Deferral Account and Match
Account shall be charged and credited as the case may be to each Investment
Fund account. The Investment Fund account shall be charged or credited with
net earnings, gains, losses and expenses, as well as any appreciation or
depreciation in market value during each Plan Year for the deemed
investment in the Investment Fund. The Administrator may charge or credit
such earnings, gains, losses, appreciation and depreciation based on the
actual investment performance of assets that it has deposited in a grantor
trust (as described in Plan Section 11).
8
<PAGE>
(c) Pursuant to procedures established by the Administrator uniformly applied,
Participants may direct the transfer of deemed investments among Investment
Funds at least once in each Plan Year.
10. DISTRIBUTIONS.
-------------
(a) All Benefits, less withholding for applicable income and employment taxes,
shall be paid in cash by the Company or its designee, except that payment
from a Participant's Deferred Stock Option Account shall be made in the
form of DRI Stock. A Participant may elect to receive a distribution of all
or a portion of the Participant's Benefits subject to the provisions of
this Section. Payment of each distribution of Benefits shall be made in one
lump sum or in installments as provided in this Section. Except in the
event of Termination for reasons other than death, retirement or
Disability, or as provided in subsection 10(f), a Participant may receive a
distribution from the Participant's Deferral Account only on a date that is
at least six months after the date on which the Participant's most recent
Deferral Election Form is effective.
(i) Unless otherwise provided herein or specified in a Participant's
Distribution Election Form, any lump sum payment shall be paid, or
installment payments shall begin, on or before February 28 of the calendar
year after the Participant's Termination. The Participant may elect on the
Participant's Distribution Election Form to begin payments (A) on or before
the February 28 of the calendar year following the calendar year of the
Participant's Termination; (B) on or before the February 28 of the calendar
year following the calendar year of the Participant's Termination but no
sooner than February 28 of a specified calendar year; or (C) even if the
Participant does not Terminate, on or before the February 28 of a specified
calendar year.
(ii) Installment payments will be made in approximately equal amounts
during each year of the installment period. For a Benefit payable in
installments, the unpaid balance of a Participant's Deferral Account and
Match Account, if any, shall continue to be maintained in Investment Funds.
The unpaid balance of a Participant's Deferred Stock Option Account shall
remain invested in DRI Stock.
(b) Benefits paid on account of Termination for retirement shall be paid in a
lump sum unless the Participant's Distribution Election Form specifies
annual installment payments over a period of up to five (5) years.
(c) Benefits paid on account of a Participant's death shall be paid in a lump
sum in accordance with the provisions of Plan Section 9(i).
(d) Benefits paid on account of Termination due to Disability shall begin to be
paid as soon as administratively practicable following the Participant's
Termination. The Benefits shall be paid in the method designated on the
Participant's Distribution Election Form, or in annual installment payments
over a period of five (5) years if the Participant made no election on the
Participant's Distribution Election Form.
9
<PAGE>
If a Disabled Participant begins to receive Benefits and thereafter
recovers and returns to employment before the balance of the Participant's
Accounts is fully paid, distributions shall cease and any remaining
Benefits under the Plan shall be governed by this Plan Section 9 and the
Participant's Distribution Election Form.
(e) Benefits paid on account of Termination due to other than death, Disability
or retirement shall be paid in a lump sum as soon as practicable following
the Termination.
(f) A Participant may elect to receive payment of Benefits prior to
Termination. If payment is made pursuant to a Distribution Election Form
that was effective less than six months before the date of such payment,
the Participant's Deferred Benefit shall be reduced by 10%. Such payment
shall be paid in a lump sum.
(g) Notwithstanding any other provision of this Plan or a Participant's
Distribution Election Form, the Committee in its sole discretion may
postpone the distribution of all or part of a Benefit to the extent that
the payment would not be deductible under Section 162(m) of the Internal
Revenue Code of 1986, as amended (the Code) or any successor thereto. A
Benefit distribution that is postponed pursuant to the preceding sentence
shall be paid as soon as it is possible to do so within the deduction
limitations of Section 162(m) of the Code.
(h) A Participant or Beneficiary may not assign Benefits. A Participant may use
only one Beneficiary Designation Form to designate one or more
Beneficiaries for all of the Participant's Benefits under the Plan. Such
designations are revocable. Each Beneficiary shall receive the
Beneficiary's portion of the Participant's Accounts on or before February
28 of the year following the Participant's death. However, the
Administrator, in its discretion, may approve a Beneficiary's request for
accelerated payment under Plan Section 10. The Administrator may require
that multiple Beneficiaries agree upon a single distribution method.
11. HARDSHIP DISTRIBUTIONS.
----------------------
(a) At its sole discretion and at the request of a Participant before or after
the Participant's Termination, or at the request of any of the
Participant's Beneficiaries after the Participant's death, the
Administrator may accelerate and pay all or part of any amount attributable
to a Participant's Benefits. The Administrator may accelerate distributions
only in the event of Hardship as defined in subsection (b). An accelerated
distribution under this Section shall be limited to the amount necessary to
satisfy the Hardship.
(b) Hardship is a severe financial hardship to the Participant resulting from a
sudden and unexpected illness or accident of the Participant or of a
dependent of the Participant, loss of the Participant's property due to
casualty, or other similar extraordinary and unforeseeable circumstances
arising as a result of events beyond the control of the Participant. The
circumstances that will constitute a Hardship will depend upon the facts of
each case, but, in any case, payment will
10
<PAGE>
not be made to the extent that the Hardship is or may be relieved: (i)
through reimbursement or compensation by insurance or otherwise, (ii) by
liquidation of the Participant's assets, to the extent that the liquidation
of such assets would not itself cause severe financial hardship, or (iii)
by cessation of deferrals under the Plan.
(c) Distributions under this Section 10 shall be made in one lump sum payment
in cash except that in the case of a Participant's Deferred Stock Option
Benefit, distributions shall be made in DRI Stock. Distributions shall be
made proportionately from all of the Investment Funds in the Participant's
Accounts first, and, with respect to Deferred Benefits, shall be limited to
amounts attributable to Compensation deferred under a Deferral Election
Form that was effective at least six months before the distribution. The
Investment Funds in the Participant's Accounts shall be valued as of the
last business day prior to the distribution, or as of such other date as
may be determined in the discretion of the Administrator.
(d) A distribution under this Section 10 shall be in lieu of that portion of a
Participant's Benefit that would have been paid otherwise. A Benefit shall
be adjusted by reducing the balance of the Participant's Accounts by the
amount of the distribution.
12. COMPANY'S OBLIGATION.
--------------------
(a) The Plan shall be unfunded. DRI shall not be required to segregate any
assets that at any time may represent a Benefit. DRI shall establish a grantor
trust (within the meaning of Sections 671 through 679 of the Code) for
Participants and Beneficiaries and shall deposit Participants' Match Benefits
with the trustee of such trust. DRI may deposit funds with the trustee of such
trust to provide the Deferred Benefits or Deferred Stock Option Benefits to
which Participants and Beneficiaries may be entitled under the Plan. The funds
deposited with the trustee or trustees of such trust, and the earnings thereon,
will be dedicated to the payment of Benefits under the Plan but shall remain
subject to the claims of the general creditors of the Company. Any liability of
DRI to a Participant or Beneficiary under this Plan shall be based solely on any
contractual obligations that may be created pursuant to this Plan. No such
obligation of DRI shall be deemed to be secured by any pledge of, or other
encumbrance on, any property of DRI.
(b) Notwithstanding the foregoing, in the event of a Change of Control, DRI
shall, immediately prior to a Change of Control, make an irrevocable
contribution to the trust so that the amount held in trust is equal to 105% of
the amount that is sufficient to pay each Participant or Beneficiary the Benefit
to which they would be entitled, and for which DRI and each other Dominion
Company is liable, pursuant to the terms of the Plan as in effect on the date on
which the Change of Control occurred. The amount of such contribution exceeding
the amount required to pay Benefits under the Plan shall be used to pay
administrative costs of the trust and reimburse any Participant who incurs legal
fees as a result of an attempt to enforce the terms of the Plan against an
acquirer of DRI.
11
<PAGE>
Additionally, the trustee of the trust as of the date of the Change of Control
may not be removed as trustee of the trust before the fifth anniversary of the
date of the Change of Control.
13. CONTROL BY PARTICIPANT. A Participant shall have no control over the
----------------------
Participant's Benefit except according to the Participant's Deferral Election
Forms, Distribution Election Forms, Investment Election Form and Beneficiary
Designation Form.
14. CLAIMS AGAINST PARTICIPANT'S BENEFIT. An Account shall not be subject in any
------------------------------------
manner to anticipation, alienation, sale, transfer, assignment, pledge,
encumbrance, or charge, and any attempt to do so shall be void. A Benefit shall
not be subject to attachment or legal process for a Participant's debts or other
obligations. Nothing contained in this Plan shall give any Participant any
interest, lien, or claim against any specific asset of the Company. A
Participant or the Participant's Beneficiary shall have no rights other than as
a general creditor of DRI.
15. AMENDMENT OR TERMINATION. Except as otherwise provided, this Plan may be
------------------------
altered, amended, suspended, or terminated at any time by the Committee. The
Committee may not alter, amend, suspend, or terminate this Plan without the
consent of that Participant if such action would result in (i) a distribution of
the Participant's Benefit in any manner not provided in the Plan or (ii)
immediate taxation of a Benefit to a Participant.
16. ADMINISTRATION.
--------------
(a) This Plan shall be administered by the Administrator. The Administrator
shall interpret the Plan, establish regulations to further the purposes of
the Plan and take any other action necessary to the proper operation of the
Plan. Prior to paying a Benefit under the Plan, the Administrator may
require the Participant, former Participant or Beneficiary to provide such
information or material as the Administrator, in its sole discretion, shall
deem necessary to make any determination it may be required to make under
the Plan. The Administrator may withhold payment of a Benefit under the
Plan until it receives all such information and material and is reasonably
satisfied of its correctness and genuineness. The Administrator may
delegate all or any of its responsibilities and powers to any persons
selected by it, including designated officers of employees of the Company.
(b) If for any reason a Benefit payable under this Plan is not paid when due,
the Participant or Beneficiary may file a written claim with a committee
appointed by the Administrator to review claims for benefits under the Plan
(the "Claims Committee"). If the claim is denied or no response is received
within forty-five (45) days after the date on which the claim was filed
with the Claims Committee (in which case the claim will be to have been
denied), the Participant or Beneficiary may appeal the denial to the
Committee within sixty (60) days of receipt of written notification of the
denial or the end of the forty-five day period,
12
<PAGE>
whichever occurs first. In pursuing an appeal, the Participant or
Beneficiary may request that the Committee review the denial, may review
pertinent documents, and may submit issues and documents in writing to the
Committee. A decision on appeal will be made within sixty (60) days after
the appeal is made, unless special circumstances require the Committee to
extend the period for another sixty (60) days.
17. NOTICES. All notices or election required under the Plan must be in
-------
writing. A notice or election shall be deemed delivered if it is delivered
personally or sent registered or certified mail to the person at the person's
last known business address.
18. WAIVER. The waiver of a breach of any provision in this Plan does not
------
operate as and may not be construed as a waiver of any later breach.
19. CONSTRUCTION. This Plan shall be adopted and maintained according to the
------------
laws of the Commonwealth of Virginia (except its choice-of-law rules and except
to the extent that such laws are preempted by applicable federal law). Headings
and captions are only for convenience; they do not have substantive meaning. If
a provision of this Plan is not valid or enforceable, the validity or
enforceability of any other provision shall not be affected. Use of one gender
includes all, and the singular and plural include each other.
IN WITNESS WHEREOF, this instrument has been executed this ____ day of
_____________, 2000.
DOMINION RESOURCES, INC.
By__________________________________
James L. Trueheart
Group Vice President and
Chief Administrative Officer
13
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-11
<SEQUENCE>4
<FILENAME>0004.txt
<DESCRIPTION>COMPUTATION OF EARNINGS PER SHARE
<TEXT>
<PAGE>
EXHIBIT 11
DOMINION RESOURCES, INC.
COMPUTATION OF EARNINGS PER SHARE OF COMMON STOCK
ASSUMING FULL DILUTION
<TABLE>
<CAPTION>
(Million, Except Per Share Amounts)
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Basic earnings per common share:
Consolidated net income (1) $ 436 $ 297 $ 548
====== ====== ======
Adjustment to average common shares:
Shares of common stock - average
shares outstanding 235.2 191.4 194.9
Plus: Additional shares assuming conversion
of installments received on stock purchase plan
at average market value (2) 0.0 0.0 0.0
------ ------ ------
Adjusted average common shares 235.2 191.4 194.9
====== ====== ======
Basic earnings per common share $ 1.85 $ 1.55 $ 2.81
====== ====== ======
Diluted earnings per common share:
Consolidated net income $ 436 $ 285 $ 548
====== ====== ======
Adjustment to average common shares:
Shares of common stock - average
shares outstanding 235.9 191.4 194.9
Plus: Additional shares assuming conversion
of installments received on stock purchase plan
at average market value (2) 0.0 0.0 0.0
------ ------ ------
Adjusted average common shares 235.9 191.4 194.9
====== ====== ======
Diluted earnings per common share $ 1.85 $ 1.48 $ 2.81
====== ====== ======
Notes: (1) See the Consolidated Statements of Income.
(2) Based on the following data:
<CAPTION>
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Installments received on stock purchase plan
at year-end $ 0.3 $ 0.2 $ 0.4
Average market per common share $48.53 $43.46 $43.38
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>5
<FILENAME>0005.txt
<DESCRIPTION>SELECTED FINANCIALS
<TEXT>
<PAGE>
| Consolidated Statements of Income
<TABLE>
<CAPTION>
For The Year Ended December 31,
-------------------------------
(millions, except per share amounts) 2000 1999 1998
================================================================================================================================
<S> <C> <C> <C>
Operating revenue and income:
Regulated sales
Electric $ 4,492 $ 4,227 $ 3,979
Gas 1,374
Nonregulated sales
Electric 97 180 190
Gas 593
Gas transportation and storage 486
Oil and gas production 856 218 141
East Midlands 1,010
Other 1,362 895 761
- --------------------------------------------------------------------------------------------------------------------------------
Total 9,260 5,520 6,081
- --------------------------------------------------------------------------------------------------------------------------------
Expenses:
Fuel, net 1,106 996 961
Purchased power capacity, net 741 809 806
Purchased gas, net 1,453
Liquids, capacity and other products purchased 299
Supply and distribution-- East Midlands 655
Restructuring and other acquisition-related costs 460
Impairment of regulatory assets 159
Other operation and maintenance 2,011 1,376 1,357
Depreciation, depletion and amortization 1,176 707 733
Other taxes 485 304 306
- --------------------------------------------------------------------------------------------------------------------------------
Total 7,731 4,192 4,977
- --------------------------------------------------------------------------------------------------------------------------------
Income from operations 1,529 1,328 1,104
- --------------------------------------------------------------------------------------------------------------------------------
Other income:
Gain on sale-- East Midlands 332
Other 95 75 99
- --------------------------------------------------------------------------------------------------------------------------------
Total 95 75 431
- --------------------------------------------------------------------------------------------------------------------------------
Income before interest and income taxes 1,624 1,403 1,535
- --------------------------------------------------------------------------------------------------------------------------------
Interest and related charges:
Interest charges 958 507 583
Preferred dividends and distributions of subsidiary trusts 66 67 65
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,024 574 648
- --------------------------------------------------------------------------------------------------------------------------------
Income before income taxes, minority interests, extraordinary item
and cumulative effect of a change in accounting principle 600 829 887
Income taxes 183 259 312
Minority interests 2 18 27
- --------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and cumulative effect of a change in accounting principle 415 552 548
- --------------------------------------------------------------------------------------------------------------------------------
Extraordinary item (net of income taxes of $197) (255)
Cumulative effect of a change in accounting principle (net of income taxes of $11) 21
- --------------------------------------------------------------------------------------------------------------------------------
Net income $ 436 $ 297 $ 548
================================================================================================================================
Average shares of common stock-- basic 235.2 191.4 194.9
- --------------------------------------------------------------------------------------------------------------------------------
Basic earnings per common share:
Income before extraordinary item and cumulative effect of a change in accounting principle $ 1.76 $ 2.88 $ 2.81
Extraordinary item (1.33)
Cumulative effect of a change in accounting principle 0.09
- --------------------------------------------------------------------------------------------------------------------------------
Net income $ 1.85 $ 1.55 $ 2.81
================================================================================================================================
Average shares of common stock-- diluted 235.9 191.4 194.9
- --------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share:
Income before extraordinary item and cumulative effect of a change in accounting principle $ 1.76 $ 2.81 $ 2.81
Extraordinary item (1.33)
Cumulative effect of a change in accounting principle 0.09
- --------------------------------------------------------------------------------------------------------------------------------
Net income $ 1.85 $ 1.48 $ 2.81
================================================================================================================================
Dividends paid per common share $ 2.58 $ 2.58 $ 2.58
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of the Consolidated Financial
Statements.
___
25
<PAGE>
| Consolidated Balance Sheets
| Assets
<TABLE>
<CAPTION>
At December 31,
---------------------------
(millions) 2000 1999
===========================================================================================================================
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 360 $ 280
Accounts receivable:
Customers (less allowance for doubtful accounts of $67 in 2000 and $12 in 1999) 1,872 664
Other 486 269
Inventories:
Materials and supplies (average cost method) 150 143
Fossil fuel (average cost method) 102 111
Gas stored-- current portion 75
Investment securities -- trading 275 2
Mortgage loans held for sale 104 119
Commodity contract assets 1,058 363
Unrecovered gas costs 263
Broker margin deposits 267 36
Prepayments 173 154
Net assets held for sale 73
Other 608 37
- -----------------------------------------------------------------------------------------------------------------------------
Total current assets 5,866 2,178
- -----------------------------------------------------------------------------------------------------------------------------
Investments:
Loans receivable, net 676 2,049
Investments in affiliates 392 433
Available for sale securities 292 512
Nuclear decommissioning trust funds 851 818
Investments in real estate 65 86
Other 326 334
- -----------------------------------------------------------------------------------------------------------------------------
Total net investments 2,602 4,232
- -----------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment 28,011 18,703
Less accumulated depreciation, depletion and amortization 13,162 7,906
- -----------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net 14,849 10,797
- -----------------------------------------------------------------------------------------------------------------------------
Deferred charges and other assets:
Goodwill, net 3,502 132
Regulatory assets, net 516 221
Prepaid pension costs 1,455 22
Other, net 558 200
- -----------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 6,031 575
- -----------------------------------------------------------------------------------------------------------------------------
Total assets $ 29,348 $17,782
=============================================================================================================================
</TABLE>
___
26
<PAGE>
| Liabilities and Shareholders' Equity
<TABLE>
<CAPTION>
At December 31,
------------------
(millions) 2000 1999
===================================================================================================
<S> <C> <C>
Current liabilities:
Securities due within one year $ 336 $ 536
Short-term debt 3,237 870
Accounts payable, trade 1,736 711
Accrued interest 195 121
Accrued payroll 127 93
Accrued taxes 316 89
Commodity contract liabilities 1,021 348
Other 624 232
- ---------------------------------------------------------------------------------------------------
Total current liabilities 7,592 3,000
- ---------------------------------------------------------------------------------------------------
Long-term debt 10,101 6,936
- ---------------------------------------------------------------------------------------------------
Deferred credits and other liabilities:
Deferred income taxes 2,820 1,710
Deferred investment tax credits 147 146
Other 801 223
- ---------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,768 2,079
- ---------------------------------------------------------------------------------------------------
Total liabilities 21,461 12,015
- ---------------------------------------------------------------------------------------------------
Minority interest 1 99
- ---------------------------------------------------------------------------------------------------
Commitments and contingencies (see Note 22)
Obligated mandatorily redeemable preferred securities of subsidiary trusts* 385 385
- ---------------------------------------------------------------------------------------------------
Preferred stock not subject to mandatory redemption 509 509
- ---------------------------------------------------------------------------------------------------
Common shareholders' equity:
Common stock -- no par; authorized -- 500.0 shares;
outstanding -- 245.8 shares at 2000 and
186.3 shares at 1999 5,979 3,561
Other paid-in capital 16 16
Accumulated other comprehensive income (31) (15)
Retained earnings 1,028 1,212
- ---------------------------------------------------------------------------------------------------
Total common shareholders' equity 6,992 4,774
- ---------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 29,348 $ 17,782
===================================================================================================
</TABLE>
* As described in Note 17, the 7.83% and 8.05% Junior Subordinated Notes
totaling $258 million and $139 million principal amounts, respectively,
constitute 100% of the trusts' assets. The accompanying notes are an integral
part of the Consolidated Financial Statements.
___
27
<PAGE>
Consolidated Statements of Common Shareholders' Equity
<TABLE>
<CAPTION>
Accumulated
Common Stock Other Other
------------------ Retained Comprehensive Paid-In
(millions) Shares Amount Earnings Income Capital Total
=================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1998 188 $ 3,674 $ 1,363 $ (3) $ 16 $ 5,050
Issuance of stock through public offering 7 268 268
Issuance of stock through employee and
direct stock purchase plans 2 86 86
Stock repurchase and retirement (2) (99) (99)
Other common stock activity 4 4
Comprehensive income 548 (17) 531
Dividends and other adjustments (503) (503)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 195 3,933 1,408 (20) 16 5,337
Stock repurchase and retirement (9) (372) (372)
Comprehensive income 297 5 302
Dividends and other adjustments (493) (493)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 186 3,561 1,212 (15) 16 4,774
Issuance of stock--CNG acquisition 87 3,527 3,527
Issuance of stock through public offering 6 354 354
Issuance of stock through employee, executive
loan and direct stock purchase plans 4 195 195
Stock repurchase and retirement (37) (1,641) (1,641)
Premium income equity securities (21) (21)
Other common stock activity 4 4
Comprehensive income 436 (16) 420
Dividends and other adjustments (620) (620)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 246 $ 5,979 $ 1,028 $ (31) $ 16 $ 6,992
=================================================================================================================================
</TABLE>
Consolidated Statements of Comprehensive Income
<TABLE>
<CAPTION>
For The Year Ended December 31,
-----------------------------------------
(millions) 2000 1999 1998
=================================================================================================================================
<S> <C> <C> <C>
Net income $ 436 $ 297 $ 548
Other comprehensive income, net of tax:
Unrealized holding gains (losses) on investment securities 9 (14) (3)
Less: reclassification adjustment for gains (losses) realized in net income (3) 3 3
- ---------------------------------------------------------------------------------------------------------------------------------
Unrealized gains (losses) on investment securities 12 (17) (6)
Foreign currency translation adjustment (4) 22 (11)
Minimum pension liability adjustment (24)
- ---------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss) (16) 5 (17)
- ---------------------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 420 $ 302 $ 531
=================================================================================================================================
</TABLE>
The accompanying notes are an integral part of the Consolidated Financial
Statements.
__
28
<PAGE>
| Consolidated Statements of Comprehensive Income
<TABLE>
<CAPTION>
For The Year Ended December 31,
-------------------------------------
(millions) 2000 1999 1998
================================================================================================================================
<S> <C> <C> <C>
Cash flows from (used in) operating activities:
Net income $ 436 $ 297 $ 548
Adjustments to reconcile net income to net cash from operating activities:
Cumulative effect of a change in accounting principle (21)
Restructuring and other acquisition related costs 124
DCI impairment losses 292
Extraordinary item, net of income taxes 255
Impairment of regulatory assets 159
Gains on sales of subsidiaries (23) (332)
Depreciation and amortization 1,268 798 814
Deferred income taxes 22 64 22
Deferred fuel expense (33) (35) (34)
Changes in current assets and liabilities:
Accounts receivable (842) 81 (90)
Inventories (62) (6) (24)
Unrecovered gas costs (217)
Purchase and origination of mortgages (4,281) (2,575) (2,503)
Proceeds from sale and principal collections of mortgages 4,295 2,597 2,450
Accounts payable, trade 674 (24) 65
Accrued interest and taxes 139 (48) 100
Commodity contract assets and liabilities (32) (92) 66
Net assets held for sale (24)
Other (372) (57) (16)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows from operating activities 1,343 1,255 1,225
- --------------------------------------------------------------------------------------------------------------------------------
Cash flow from (used in) investing activities:
Plant construction and other property additions (1,385) (871) (739)
Acquisition of exploration and production assets (353) (90) (96)
Loan originations (2,911) (2,581) (2,580)
Repayments of loan originations 4,255 2,238 1,778
Sale of businesses, including East Midlands 836 180 1,462
Sale of marketable securities 137 35 70
Purchase of debt securities (235) (53) (120)
Acquisitions of businesses (2,779) (167) (338)
Other investments (140) (152) (75)
Other (22) (81) (30)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flow used in investing activities (2,597) (1,542) (668)
- --------------------------------------------------------------------------------------------------------------------------------
Cash flow from (used in) financing activities:
Issuance of common stock 532 354
Repurchase of common stock (1,641) (372) (99)
Issuance (repayment) of short-term debt 1,820 394 65
Issuance of long-term debt 8,108 6,446 4,027
Repayment of long-term debt (6,813) (5,790) (4,207)
Common dividend payments (615) (493) (503)
Other (57) (44) (90)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flow from (used in) financing activities 1,334 141 (453)
- --------------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 80 (146) 104
Cash and cash equivalents at beginning of the year 280 426 322
- --------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of the year $ 360 $ 280 $ 426
================================================================================================================================
Supplemental cash flow information:
Cash paid during the year for:
Interest, excluding capitalized amounts $ 988 $ 522 $ 474
Income taxes 240 199 202
Non-cash transactions from investing and financing activities:
Common stock issuance-- CNG acquisition 3,527
Note received in sale of business 260 26
Exchange of securities 57
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of the Consolidated Financial
Statements.
29
<PAGE>
[LOGO] Management's Discussion and Analysis of Financial Condition and Results
of Operations (unaudited)
Forward-Looking Information
This annual report includes certain information which contains "forward-looking
statements" as defined by the Private Securities Litigation Reform Act of 1995,
including (without limitation) discussions as to expectations, beliefs, plans,
objectives and future financial performance, or assumptions underlying or
concerning matters discussed in this document. These discussions, and any other
discussions, including certain contingency matters (and their respective
cautionary statements) discussed elsewhere in this report, that are not
historical facts, are forward-looking and, accordingly, involve estimates,
projections, goals, forecasts, assumptions and uncertainties that could cause
actual results or outcomes to differ materially from those expressed in the
forward-looking statements.
The business and financial condition of Dominion Resources, Inc. and its
subsidiaries (Dominion or the Company) are influenced by a number of factors
including political and economic risks, market demand for energy, inflation,
capital market conditions, and other general and specific economic conditions in
the Company's service areas, governmental policies, legislative and regulatory
actions (including those of the Federal Energy Regulatory Commission [FERC],
the Securities and Exchange Commission [SEC], the Environmental Protection
Agency [EPA], the Department of Energy, the Nuclear Regulatory Commission [NRC]
and various state regulatory commissions), industry and rate structure, and
legal and administrative proceedings. Some other important factors that could
cause actual results or outcomes to differ materially from those discussed in
the forward-looking statements include changes in and compliance with
environmental laws and policies, weather conditions and catastrophic weather-
related damage, present or prospective wholesale and retail competition,
electric and gas deregulation, the restructuring of the organization, operations
and financing of Dominion's electric power business to separate generation,
transmission and distribution, competition for new energy development
opportunities, pricing and transportation of commodities, operation of nuclear
power facilities, competition in the telecommunications industry, successful
implementation of the Company's telecommunications strategy, effects and risks
associated with the Company's acquisition, generation growth and divestiture
strategies, recovery of potentially stranded costs, including nuclear
decommissioning costs, exposure to risks associated with Dominion's portfolio
of derivative commodity contracts, counter-party credit risk and unanticipated
changes in operating expenses and capital expenditures. All such factors are
difficult to predict, contain uncertainties that may materially affect actual
results, and may be beyond the control of Dominion. 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 Dominion.
Any forward-looking statement speaks only as of the date on which such
statement is made, and Dominion undertakes no obligation to update any forward-
looking statement to reflect events or circumstances after the date on which
such statement is made.
Introduction
Management's Discussion and Analysis of Financial Condition and Results of
Operations explain the general financial condition and the results of operations
for Dominion. "Dominion" or the "Company" is used throughout this report and,
depending on the context of its use, may represent any of the following: the
legal entity, Dominion Resources, Inc., one of Dominion's consolidated
subsidiaries, or the entirety of Dominion Resources, Inc. and its consolidated
subsidiaries.
Dominion is a holding company headquartered in Richmond, Virginia. Its
principal subsidiaries are Virginia Electric and Power Company (Virginia Power)
and Consolidated Natural Gas Company (CNG), which was acquired on January 28,
2000. Dominion is subject to the Public Utility Holding Company Act of 1935
(1935 Act).
Virginia Power 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. Virginia Power
sells electricity to approximately 2.1 million retail customers (including
governmental agencies) and to wholesale customers such as rural electric
cooperatives, municipalities, power marketers and other utilities. Virginia
Power also engages in off-system wholesale purchases and sales of electricity
and purchases and sales of natural gas beyond the geographic limits of its
retail service territory.
CNG operates in all phases of the natural gas industry in the United
States, including exploration for and production of oil and natural gas and
natural gas transmission, storage and distribution. Its regulated retail gas
distribution subsidiaries serve approximately 1.7 million residential,
commercial and industrial gas sales and transportation customers in Ohio,
Pennsylvania and West Virginia. Its interstate gas transmission pipeline
system services each of its distribution subsidiaries, non-affiliated utilities
and end use customers in the Midwest, the Mid-Atlantic and the Northeast states.
CNG's exploration and production operations are conducted in several of the
major gas and oil producing basins in the United States, both onshore and
offshore, and in Canada.
The Company's other major subsidiaries are Dominion Energy, Inc. (DEI) and
Dominion Capital, Inc. (DCI). DEI is engaged in independent power production
and the acquisition and production of natural gas and oil reserves. In Canada,
DEI is engaged in natural gas exploration, production and storage. DCI is
Dominion's financial services subsidiary. DCI's primary business is financial
services which includes commercial lending and residential mortgage lending.
See Note 6 to the Consolidated Financial Statements for a discussion of
management's strategy to exit and windup DCI's businesses as ordered by the SEC
under the 1935 Act.
Under the 1935 Act, Dominion created a subsidiary service company,
Dominion Resources Services, Inc. (Services), which provides certain services to
Dominion's operating subsidiaries. During 2000, CNG also had a service company.
Effective January 1, 2001, the two service companies were combined into one
service company.
30
<PAGE>
On March 3, 2000, Dominion announced a new business structure that
integrates CNG's businesses, streamlines operations, and positions Dominion for
long-term growth in the competitive marketplace. Under the structure,
Dominion operates three principal business segments -- Dominion Energy, Dominion
Delivery and Dominion Exploration & Production. In addition, Dominion reviews
the financial services business of DCI and Corporate Operations as segments.
Items for which the operating segments are not held accountable, as well as
inter-segment eliminations, are included in Corporate Operations. See Note 27 to
the Consolidated Financial Statements. While Dominion manages its daily
operations as described above, assets remain wholly owned by its legal
subsidiaries. For more information on business segments, see Note 27 to the
Consolidated Financial Statements.
Results of Operations
Overview
Dominion achieved net income of $436 million in 2000, or $1.85 per diluted
share, compared with net income of $297 million in 1999, or $1.48 per share.
Since its acquisition, CNG's various businesses have had a significant impact on
Dominion's current year operations. Consequently, the primary reason for the
increase in operating results when comparing 2000 to 1999 is the contributions
of CNG's operations. CNG's various businesses contributed $157 million, or
$0.67 per share, to Dominion's net income in 2000. Net income for the
comparative periods was impacted by an extraordinary item for the write-off of
certain generation-related assets and liabilities in 1999 and the following
factors in 2000:
. a change in the method of accounting for pensions (see Note 3 to the
Consolidated Financial Statements);
. the increased earnings contributions by Dominion Energy, Dominion Delivery
and Dominion Exploration & Production;
. the gain on the sale of Dominion's interest in Corby Power Station (see Note
5 to the Consolidated Financial Statements);
. the charges for restructuring and other acquisition-related costs and the
charges resulting from the impairment and revaluation of DCI's assets (see
Note 6 to the Consolidated Financial Statements);
. the amortization of the goodwill associated with the purchase of CNG (see
Note 5 to the Consolidated Financial Statements);
. an increase in interest charges primarily due to debt incurred to finance the
acquisition of CNG and the interest expense of DCI;
. a decrease in income tax expense primarily due to restructuring and other
acquisition-related charges and the impairment and revaluation of DCI's
assets.
Net income decreased $251 million in 1999 as compared to 1998 and was
impacted by the following:
. the write-off of generation-related assets and liabilities in 1999, resulting
in an after-tax charge to earnings of $255 million (see Note 7 to the
Consolidated Financial Statements);
. the loss recorded by Dominion Energy in 1999 related to its interests in
Latin American power generation;
. the sale of East Midlands which resulted in a gain in 1998 and the absence of
East Midlands' contribution to earnings in 1999;
. the increased contribution from Dominion Energy's energy marketing business
during 1999;
. the impairment of regulatory assets and one-time base rate refund resulting
from the settlement of 1998 Virginia jurisdictional rate proceedings;
. lower interest charges primarily due to the retirement of debt upon the sale
of East Midlands, the capitalization of interest on utility generation
construction beginning in 1999 and the interest portion of the 1998
Virginia jurisdictional rate refund. These factors were offset, in part, by
interest charges from debt issued to fund the acquisition of Kincaid Power
Station and Dominion Energy Canada, Ltd. in 1998 and increased funding for
loan originations at Dominion's financial services businesses; and
. a decrease in income tax expense due to taxes on the gain on the East
Midlands sale recorded in 1998.
A comparison of net income and earnings per share contributions by segment
follows:
<TABLE>
<CAPTION>
Year ended December 31, 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(millions, except per Net Net Net
share amounts) Income EPS Income EPS Income EPS
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Dominion Delivery $ 339 $ 1.44 $ 175 $ 0.91 $ 168 $ 0.86
Dominion Energy 478 2.03 271 1.42 262 1.35
Dominion E&P 270 1.14 44 0.23 34 0.17
DCI 11 0.05 78 0.41 59 0.30
East Midlands 26 0.14
- ---------------------------------------------------------------------------------------------------------------------
1,098 4.66 568 2.97 549 2.82
Corporate Operations (662) (2.81) (271) (1.42) (1) (0.01)
- ---------------------------------------------------------------------------------------------------------------------
Consolidated $ 436 $ 1.85 $ 297 $ 1.48/(1)/ $ 548 $ 2.81
- ---------------------------------------------------------------------------------------------------------------------
Average shares -- diluted 235.9 191.4 $194.9
=====================================================================================================================
</TABLE>
(1) Diluted earnings per share calculation includes the effect of the total
return equity swap. For more information, see Note 19 to the Consolidated
Financial Statements.
Regulated Sales Revenue
Regulated sales -- electric consist primarily of sales to retail customers in
Dominion's electric service territory at rates authorized by the Virginia and
North Carolina regulatory commissions and sales to cooperatives and
municipalities at wholesale rates authorized by FERC. Also, included in this
revenue are amounts received from others for use of Dominion's transmission
system to transport electric energy under tariffs authorized by FERC.
Regulated sales -- electric for fiscal years 2000, 1999 and 1998 were
allocated to the electric utility operations of the Dominion Energy and Dominion
Delivery businesses as follows:
(millions) Year ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------
Revenue:
Dominion Energy $ 3,341 $ 3,122 $ 3,069
Dominion Delivery 1,151 1,109 1,063
Corporate Operations (4) (153)
- -----------------------------------------------------------------------------
Total revenue $ 4,492 $ 4,227 $ 3,979
=============================================================================
31
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations (continued)
Weather typically has a significant impact on retail electric sales revenue.
However, for the comparative periods presented, weather did not have a
significant impact.
The primary factors affecting the increase in regulated sales -- electric
in both fiscal years 2000 and 1999 were customer growth and changes in rates.
Dominion's electric retail customer base increased, on average, approximately
39,000 in both 2000 and 1999 over the respective prior year periods. These
additional customers increased electric regulated sales by an estimated $76
million in 2000 compared to 1999 and an estimated $68 million in 1999 compared
to 1998. Fuel revenue increased $117 million in 2000 as compared to 1999
reflecting higher fuel rates approved in the first quarter of 2000. In addition,
regulated sales -- electric in 1999 were higher as a result of a one-time $150
million base rate refund in 1998, the effect of which is reported in Corporate
Operations along with other intersegment eliminations.
For the period January 28, 2000 through December 31, 2000, regulated
sales--gas were $ 1.4 billion. The revenue in 2000 reflects the cold weather
experienced in the Company's retail gas service areas in the fourth quarter of
2000. Average sales rates for all customer groups increased sharply during the
year, reflecting the pass through of higher purchased gas costs.
Dominion Energy
Dominion Energy includes Dominion's 19,000-megawatt generation portfolio,
consisting of generating units and power purchase agreements. It also manages
the Company's generation growth strategy; energy trading, marketing, hedging and
arbitrage activities; and gas pipeline and storage operations. Selected
financial information relevant to Dominion Energy is as follows:
Year ended December 31, 2000 1999 1998
- ---------------------------------------------------------------------------
All
(millions) Total CNG Other
- ---------------------------------------------------------------------------
Regulated sales revenue:
Electric $3,341 $3,341 $3,122 $3,069
Nonregulated sales revenue:
Electric 97 97 180 190
Gas 518 $494 24
Gas transportation and storage 291 291
Other revenue 517 287 230 291 251
Operating expenses 3,830 857 2,973 2,970 2,895
Operating income 934 215 719 623 615
===========================================================================
2000 Compared to 1999; 1999 Compared to 1998
Regulated sales-- electric increased, reflecting growth in the number of retail
customers and an increase in Virginia jurisdictional fuel rates.
The decrease in nonregulated electric sales is primarily attributable to
the sale of Dominion Energy's interests in its Latin American power generation
in 1999 and early 2000.
Nonregulated gas sales to marketers and end users were $518 million.
Nonregulated gas sales to other Dominion segments, included in Other revenue,
were $122 million.
Gas transportation volumes in 2000 were 425 Bcf, reflecting the cold
weather experienced late in the year.
Operating expenses in 2000 included purchased gas costs of $602 million
associated with nonregulated gas sales.
There were no significant variations in revenue, operating expenses or
operating income for 1999 as compared to 1998.
Dominion Delivery
Dominion Delivery consists primarily of Dominion's electric transmission and
distribution system and local gas distribution systems. Selected financial
information relevant to Dominion Delivery is as follows:
Year ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------
All
(millions) Total CNG Other
- -------------------------------------------------------------------------
Regulated sales revenue:
Electric $1,151 $1,151 $1,109 $1,063
Gas 1,374 $1,374
Gas transportation and
storage 197 197
Operating expenses 2,117 1,398 719 735 687
Operating income 707 205 502 431 424
=========================================================================
2000 Compared to 1999; 1999 Compared to 1998
Regulated sales -- electric increased, reflecting growth in the number of retail
customers.
Regulated sales -- gas reflects the cold weather experienced in the
Company's retail service areas during the fourth quarter of 2000. Gas sales and
transportation volumes were 187 Bcf.
Operating expenses increased due to the inclusion of CNG's other operations
and maintenance expenses. The increase was mitigated by lower electric
service restoration costs associated with storm damage, pension credits (see
Note 3 to the Consolidated Financial Statements) and the effect of staffing
reductions attributable to restructuring initiatives.
There were no significant variations in revenue, operating expenses or
operating income for 1999 as compared to 1998.
Dominion Exploration & Production
Dominion Exploration & Production consists of the gas and oil exploration,
development and production operations of DEI and CNG. The CNG acquisition added
1.5 trillion cubic feet equivalent (Tcfe) of gas reserves located primarily in
the Gulf of Mexico, Gulf Coast and Appalachian and Rocky Mountain regions of the
United States. Production from these reserves added nearly 475 million cubic
feet of gas and 20,000 barrels of oil per day to Dominion's existing production.
Dominion now owns 2.8 Tcfe reserves. Acquisition activity in early 2000
included the purchase of additional interests in two deepwater Gulf of Mexico
fields and various South
32
<PAGE>
Texas gas fields. Selected financial information relevant to Dominion
Exploration & Production is as follows:
Year ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------
All
(millions) Total CNG Other
- -------------------------------------------------------------------------
Operating revenue $1,369 $998 $371 $256 $164
Operating expenses 931 670 261 212 135
Operating income 438 328 110 44 29
=========================================================================
2000 Compared to 1999
Operating revenue and income were higher as a result of increased production and
higher oil and gas prices. The 2000 results of operations reflect the addition
of CNG's operations and new property acquisitions, as well as increased
production from existing properties . CNG's exploration and production
operations acquired in early 2000 contributed $998 million to the segment's
total Operating revenue and income, including brokered gas and oil sales of $306
million.
Natural gas production from operations other than CNG rose to 115 Bcfe in
2000, compared to 109 Bcfe in 1999. The increase was primarily due to a full
year of operations from properties acquired by Dominion during 1999. Property
additions in 1999 included the purchase of Remington Energy Ltd. (Remington), a
natural gas exploration and production company headquartered in Calgary,
Alberta, Canada and gas producing properties in the San Juan Basin of New
Mexico.
Operating expenses increased primarily due to the addition of CNG's
operations and a full year of Remington's operations. Operating expenses
attributable to CNG's operations also included $296 million for the cost of gas
and oil purchased for brokered sales.
1999 Compared to 1998
Oil and gas production revenues increased primarily due to increased
natural gas production. Natural gas production rose to 109 Bcfe in 1999,
compared to 69 Bcfe in 1998. At December 31, 1999, proved reserves totaled 1,234
Bcfe, an increase of 618 Bcfe over 1998. The 1999 increase in production and
reserves resulted primarily from the development of existing acreage, a full
year's operations at Dominion Energy Canada, Ltd. and the acquisition of
Remington and gas producing properties in the San Juan Basin of New Mexico.
Operating expenses increased primarily due to increased natural gas
operations.
Dominion Capital
Selected financial information relevant to DCI is as follows:
(millions) Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------
Other revenue $433 $473 $409
Operating expenses 218 208 199
Operating income 215 265 210
==================================================================
2000 Compared to 1999
Operating income decreased primarily due to decreased contributions from
financial services businesses. Mortgage volumes were $2.1 billion in 2000, down
from $2.4 billion in 1999. As a result of the sale and restructuring of loans,
the commercial finance operations portfolio decreased to $676 million at the end
of 2000 compared to $2.0 billion at the end of 1999. For additional information,
see Note 6 to the Consolidated Financial Statements.
1999 Compared to 1998
Operating income increased primarily due to increased contributions from
financial services businesses. Mortgage lending volumes were $2.4 billion, up
from $2.1 billion in 1998. The commercial finance operations portfolio increased
to $2.0 billion compared to $1.7 billion at the end of 1998.
Liquidity and Capital Resources
Internal Sources of Liquidity
Cash flow from operating activities provided approximately $ 1.3 billion during
2000 and $1.2 billion in 1999 and 1998. Cash requirements not met by the timing
or amount of cash flow from operations are generally satisfied with proceeds
from the short-term borrowings, sales of securities in the case of major
acquisitions and additional long-term debt financings.
External Sources of Liquidity
During 2000, Dominion issued a combination of common stock and short-term and
long-term debt, totaling $10.5 billion. As discussed below, these issuances were
used primarily to finance the acquisition of CNG and the pending acquisition of
Millstone Nuclear Power Station (Millstone), support financial services
operations and for other general corporate purposes including the repayment of
approximately $7.0 billion of long-term debt and preferred securities. See Notes
15 and 16 to the Consolidated Financial Statements for information on Dominion's
short-term borrowings and long-term debt as of December 31, 2000.
CNG Acquisition and Related Financing
On January 28, 2000, Dominion acquired the outstanding shares of CNG's common
stock for $6.4 billion, consisting of approximately 87 million shares of
Dominion common stock and approximately $2.9 billion in cash. In addition, in
connection with the acquisition, Dominion shareholders exchanged approximately
33 million shares of Dominion common stock for $1.4 billion. Dominion initially
financed the CNG acquisition with bridge financing consisting of a $3.5 billion
commercial paper program backed by a short-term credit facility and $1 billion
of short-term, privately placed money market notes.
During 2000, Dominion issued the following securities whose proceeds were
used primarily to refinance a portion of the bridge financing:
. $700 million of 10-year fixed rate 8.125% notes;
. $700 million of 5-year fixed rate 7.625% notes;
33
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Management's Discussion and Analysis of Financial Condition and Results of
Operations (continued)
. $400 million of 3-year fixed rate 7.60% notes;
. $200 million of 12-years fixed rate 7.40% remarketable notes;
. $250 million of 14-year fixed rate 7.82% remarketable notes;
. $250 million of 12-year variable rate remarketable notes; and
. $413 million of Premium Income Equity Securities (registered trademark of
Lehman Brothers, Inc.).
Also during 2000, Dominion used net proceeds from the sales of non-core
assets to pay down a portion of the bridge financing.
In January 2001, Dominion issued $250 million of 8.4% Capital Securities due
in January 2031 and $1 billion of 2-year fixed rate 6% notes to refinance the
remaining bridge financing. For additional information on the capital
securities, see Note 17 to the Consolidated Financial Statements.
Millstone Nuclear Power Station Acquisition and Related Financing
Dominion has reached an agreement to acquire Millstone, located in Waterford,
Connecticut, for a total purchase price of approximately $1.3 billion. The
acquisition is expected to close by the end of April 2001, following regulatory
approvals. See Note 5 to the Consolidated Financial Statements. During 2000,
Dominion issued 6 million shares of common stock generating proceeds of $354
million to pre-finance a portion of the Millstone acquisition. Also in January
2001, Dominion issued $300 million of 8.4% Trust Preferred Securities due in
January 2041 in anticipation of the Millstone purchase. For additional
information on the preferred securities, see Note 17 to the Consolidated
Financial Statements. Dominion plans to finance the remainder of the Millstone
acquisition with bridge financing or through the issuance of long-term debt.
Short-Term Borrowings
In addition to the bridge financing discussed above, Dominion has three separate
commercial paper programs with an aggregate limit of $2.85 billion supported by
various credit facilities. One facility is a $1.75 billion 364-day revolving
credit facility that matures May 31, 2001. Two of the facilities, aggregating
$500 million, are accessible by CNG only and will terminate by March 31, 2001.
The other facilities are multi-year, one of which matures in June 2001.
Net borrowings under the commercial paper program were $2.7 billion at
December 31, 2000, an increase of $1.5 billion from amounts outstanding at
December 31, 1999. Commercial paper borrowings are used primarily to fund
working capital requirements and bridge financing of acquisitions, and therefore
may vary significantly during the course of the year depending upon the timing
and amount of cash requirements not satisfied by cash provided by operations.
In addition to commercial paper, Dominion may also issue extendible
commercial notes (ECNs) to meet working capital requirements. This program
became effective in July 2000 and will allow Dominion to issue up to $200
million aggregate outstanding principal of ECNs. ECNs are unsecured notes
expected to be sold in private placements. Any ECNs Dominion issues would have a
stated maturity of 390 days from issuance and may be redeemed, at Dominion's
option, within 90 days or less from issuance.
Equity Plans
In 2000, Dominion raised $195 million from the sale of common stock through
Dominion Direct (a dividend reinvestment open enrollment direct stock purchase
plan) and employee savings plans. Beginning in August 2000, Dominion began using
newly issued shares rather than shares purchased on the open market for these
plans.
Other Securities Issuances and Repayments
In 2000, Dominion issued the following securities:
. $220 million of variable-rate medium-term notes maturing in 2002; and
. $30 million of Tax-Exempt Pollution Control Revenue Bonds due September 1,
2030.
The proceeds from the issuances were used for general corporate purposes,
including the scheduled retirement of outstanding debt and preferred stock.
In 2000, Dominion repaid approximately $867 million of scheduled maturities
of its long-term debt and preferred stock, excluding debt repaid in connection
with financial services operations, and retired $45 million of debt securities
through sinking fund provisions and open market purchases.
In February 2001, Dominion issued through the Industrial Development
Authority of the Town of Louisa, Virginia, $50 million in aggregate principal
amount of Tax-Exempt Pollution Control Revenue Bonds due 2031. The net proceeds
of the bonds were used to finance qualifying expenditures made during the
construction of facilities at the North Anna Power Station.
Dominion Capital Financing Activities
In connection with purchases and originations of loans and sales and collections
of loans during 2000, the Company repaid $237 million of short-term commercial
paper and issued and repaid long-term debt of $5.0 billion and $6.1 billion,
respectively.
Amounts Available under Shelf Registrations
As of December 31, 2000, Dominion had available $5.0 billion of remaining
principal amount under currently effective shelf registrations with the SEC to
meet capital requirements. Financing activities in January 2001 reduced this
amount by $1.55 billion.
Investing Activities
In 2000, investing activities resulted in a net cash outflow of $2.6 billion
reflecting the following primary investing activities:
. Dominion's cash payment of approximately $2.9 billion in connection with the
CNG acquisition;
. plant and nuclear fuel expenditures of $1.4 billion that included
construction and expansion of generation facilities, environmental upgrades,
purchase of nuclear-fuel, and construction and improvements of gas and
electric transmission and distribution assets;
34
<PAGE>
. exploration and production expenditures of $353 million that included the
purchase of gas and oil producing properties, drilling and equipment costs
and undeveloped lease acquisitions;
. proceeds from the sales of non-core businesses of $836 million; and
. repayments of loans (net of new originations) associated with DCI of $1.3
billion.
Capital Requirements
Capital Expenditures
Dominion's planned capital expenditures during 2001, 2002 and 2003 are expected
to total $2.0 billion, $3.0 billion and $2.8 billion, respectively. These
expenditures include construction and expansion of generation facilities,
environmental upgrades, purchase of nuclear fuel, construction improvements of
gas and electric transmission and distribution assets, and expenditures for
natural gas and oil producing properties.
Maturities
Dominion will require $336 million to meet current maturities of long-term
securities in 2001.
Dominion expects to fund its capital requirements and debt maturities with
cash flow from operations and a combination of sales of securities and short-
term borrowings.
Electric and Gas Industry Issues
Deregulation Legislation -- Electric Industry
Virginia
Historically, Dominion has had the exclusive right to provide electricity at
retail within its assigned service areas in Virginia and North Carolina.
However, during 1998 and 1999, deregulation legislation was enacted in
Virginia that established a plan to restructure Virginia's electric utility
industry and provided for a phased-in transition to a fully competitive retail
electric market during the period January 1, 2002 through January 1, 2004. In
connection with the implementation of the phase-in of retail electric
competition, the Virginia Commission Staff recommended transition schedules for
each of Virginia's electric utilities. For Dominion, the Virginia Commission
Staff's plan recommended the phase-in of retail choice for all customers by
January 1, 2003. Dominion filed comments on the Commission Staff's recommended
plan in February 2001.
Under the deregulation legislation, the generation portion of Dominion's
Virginia jurisdictional operations will no longer be subject to cost-based rate
regulation beginning in 2002. Base rates will remain unchanged until July 2007
and recovery of generation related costs will continue to be provided through
capped rates and a wires charge assessed to those customers opting for alternate
suppliers. In addition, under the deregulation legislation, Dominion may
petition the Virginia Commission to terminate the capped rates after January 1,
2004. The capped rates may be terminated if the Virginia Commission finds that a
competitive market for generation services exists within Dominion's service
area.
As discussed further in sections below, the deregulation legislation
addressed divestiture, functional separation, regional transmission entities and
other corporate relationships. It also established a task force to work with the
Virginia Commission during the phase-in of competition. The task force's
specific assignments include the monitoring of possible over or under-recovery
of stranded costs by incumbent utilities. Technical amendments to the
deregulation legislation were approved by the 2001 General Assembly.
North Carolina
The North Carolina General Assembly is exploring the future of electric service
in North Carolina, including retail competition.
Federal
The United States Congress may consider federal legislation in the near future
authorizing or requiring retail competition or repealing the 1935 Act and the
Public Utility Regulatory Policy Act of 1978.
Deregulation Legislation -- Gas Industry
Each of the three states in which Dominion has gas distribution operations has
enacted or considered legislation regarding deregulation of natural gas sales at
the retail level.
Pennsylvania
As early as 1984, large industrial customers in Pennsylvania began to buy
natural gas supplies from third parties, rather than directly from local
utilities. Local distributors transported these third-party gas supplies to the
industrial facilities. Since that time, nearly all Pennsylvania industrial and
large commercial customers have started buying natural gas from unregulated
suppliers.
In 1997, Dominion's Pennsylvania gas utility voluntarily launched an Energy
Choice program for all of its retail consumers in Pennsylvania. Subsequently, in
1999, Pennsylvania enacted legislation mandating supplier choice for residential
and small commercial customers. At December 31, 2000, approximately 106,000
customers had opted for Energy Choice in the Company's Pennsylvania service
area.
Ohio
Large industrial customers in Ohio also began to source their own natural gas
supplies in the mid-1980s, as interstate pipeline transportation services became
more widely available. However, to date Ohio has not enacted legislation
requiring supplier choice for residential and commercial natural gas consumers.
Dominion has made significant progress in offering Energy Choice to customers on
its own initiative, in cooperation with the Public Utilities Commission of Ohio.
In 1997, Dominion's Ohio gas utility launched a pilot program, designed to make
gas transportation service available to residential and small commercial
customers, and to the suppliers that market gas to these customer classes. In
2000, the Energy Choice program was expanded to all 1.2 million customers in
Dominion's Ohio service area. At December 31, 2000, approximately
35
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations (continued)
175,000 of Dominion's Ohio customers were participating in this open-access
program.
West Virginia
At this time, West Virginia has not enacted legislation to require customer
choice in its retail natural gas markets. The West Virginia Public Service
Commission recently issued regulations to govern pooling services; these
services are one of the tools that natural gas suppliers may utilize to provide
retail customer choice in the future.
Virginia Retail Access Pilot Program
In 1998, the Virginia Commission issued an order instructing Dominion and AEP-
Virginia, Virginia's two largest investor-owned utilities, each to design and
file a retail access pilot program relating to electric distribution in
Virginia. During 1998 and 1999, Dominion worked with the Virginia Commission
Staff to develop the plans for the size and scope of the program and the market
price methodology. In 2000, the Virginia Commission approved Dominion's retail
access pilot program and issued a final order on the interim rules governing
pilot programs. Dominion began its pilot program in September 2000. In January
2001, the Virginia Commission established a proceeding to determine the
permanent rules for retail access.
Separation of Electric Generation and
Delivery Operations in Virginia
The deregulation legislation requires functional separation of electric
generation and delivery utility operations by January 1, 2002. In November 2000,
Dominion filed with the Virginia Commission an application for approval of a
functional separation plan for its regulated electric utility operations. The
plan provides for the following:
. transfer of generation assets into a separate legal entity, Dominion
Generation Corporation;
. transfer of rights and obligations under non-utility power purchase contracts
to Dominion Generation Corporation;
. retention of Dominion's electric transmission and distribution assets and
operations, to be known as Dominion Virginia Power;
. collection of nuclear decommissioning funding costs and wires charges from
retail customers by Dominion Virginia Power on behalf of Dominion Generation
Corporation;
. Dominion Virginia Power to be responsible for providing capped rate service
until July 1, 2007 and default service obligations, if any;
. Dominion Generation Corporation to supply Dominion Virginia Power with
electric power during and after the capped rate period under a power purchase
agreement to ensure that adequate capacity and energy is available to meet
Dominion's capped rate service and default supply obligations;
. upon expiration of the capped rate period, any power purchases by Dominion
Virginia Power from Dominion Generation Corporation to be at prevailing
market prices;
. an index-based fuel cost recovery mechanism based on the forecasted
generation by fuel type and projected fuel price indices after January 1,
2002;
. unbundled rates to reflect the separation and deregulation of generation;
. a wires charge, effective January 1, 2002, and subject to annual adjustment,
to be paid by retail customers choosing an alternative generation supplier
during the capped rate period;
. proposed internal controls to prevent cross-subsidies between regulated and
unregulated entities and to ensure that the regulated company does not give
undue advantages to unregulated affiliated generation companies; and
planned allocation between Dominion Virginia Power and Dominion Generation
Corporation of payment responsibility for existing Virginia Power debt with
the objective that ratings on outstanding debt will remain unchanged.
In October 2000, the Virginia Commission issued its final order promulgating
regulations governing the functional separation of incumbent electric utilities'
generation, transmission, and distribution services. The order adopted rules for
how Virginia's existing electric utilities should organize themselves to
participate in the competitive energy supply market, which begins a two-year
phase in period in 2002. The rules govern how utilities which generate, transmit
and distribute electricity can separate operations so their generating plants
can participate in the competitive market without raising anti-competitive and
other concerns.
Regional Transmission Entities/
Regional Transmission Organizations
The deregulation legislation required that Virginia's incumbent electric
utilities join or establish regional transmission entities (RTE) by
January 1, 2001, and seek authorization from the Virginia Commission to transfer
ownership or operational control of their transmission facilities to such RTEs.
In July 2000, the Virginia Commission issued regulations governing the transfer
of ownership or control of electric transmission assets to a RTE. In October
2000, Dominion filed its application with the Virginia Commission pursuant to
the RTE regulations seeking authorization to transfer control of its electric
transmission facilities to the Alliance Regional Transmission Organization
(Alliance RTO). As discussed below, the formation of the Alliance RTO began
according to FERC initiatives, but Dominion expects it to satisfy the RTE
requirements under the Virginia deregulation legislation.
In 1999, FERC issued regulations (Order No. 2000) to advance the formation of
Regional Transmission Organizations (RTO). The regulations require that each
public utility that owns, operates, or controls facilities for the transmission
of electric energy in interstate commerce make certain filings with respect to
operating and participating in a RTO. Dominion, together with AEP, Consumers
Energy Company, The Detroit Edison Company and First Energy Corporation, on
behalf of themselves and their public utility operating company subsidiaries
(Alliance Companies), filed with FERC applications under Sections 205 and 203 of
the Federal Power Act for approval of the proposed Alliance RTO. FERC approved
most aspects of the Alliance RTO in January 2001. Dayton Power and Light
Company, Illinois Power, Commonwealth Edison Company of
36
<PAGE>
Indiana, Commonwealth Edison Company, Ameren UE and Ameren
CIPS subsequently requested FERC approval to join the Alliance RTO.
Competition -- Wholesale Market
Dominion sells electricity in the wholesale market under its market based sales
tariff authorized by FERC but has agreed not to make wholesale power sales under
this tariff to loads located within its service territory. During 2000, Dominion
filed applications with FERC to make sales under its market-based sales tariff
to loads within its Virginia service territory participating in its retail
access pilot program and to amend its open access transmission tariff to
accommodate the Virginia retail access pilot program. FERC has accepted both
applications. Until authorization is granted by FERC, any sales of wholesale
power to loads located within Dominion's Virginia service territory, other than
sales to loads participating in the retail access pilot program, are to be at
cost-based rates accepted by FERC.
Dominion's sales of oil and natural gas in wholesale markets are not
regulated by the FERC. The deregulation of gas sales began through a multi-year
schedule established under the Natural Gas Policy Act (NGPA) of 1978 and was
completed under the Natural Gas Wellhead Decontrol Act of 1989.
Exposure to Potentially Stranded Costs
The most significant potential impact of transitioning from a regulated to a
competitive environment is stranded costs. Stranded costs are those costs
incurred or commitments made by utilities under cost-based regulation that may
not be reasonably expected to be recovered in a competitive market. If no
recovery mechanism is provided during the transition, the financial position of
a utility could be materially adversely affected. At December 31, 2000,
Dominion's exposure to potentially stranded costs was comprised of: long-term
purchased power contracts that could ultimately be determined to be above
market; generating plants that could possibly become uneconomic in a deregulated
environment; and unfunded obligations for nuclear plant decommissioning and
postretirement benefits not yet recognized in the financial statements.
Dominion believes capped electric retail rates provided under the Virginia
deregulation legislation present a reasonable opportunity to recover a
substantial portion of its potentially stranded costs. In the absence of capped
rates, at March 31, 1999, Dominion would have otherwise been exposed, on a pre-
tax basis, to an estimated $3.2 billion of potential losses related to long-
term power purchase commitments. Recovery of Dominion's potentially stranded
costs is subject to numerous risks including, among others, exposure to long-
term power purchase commitment losses, future environmental compliance
requirements, changes in tax laws, nuclear decommissioning costs, inflation,
increased capital costs, and recovery of certain other items. See Notes 14, 21
and 22 to the Consolidated Financial Statements.
Environmental Matters
Dominion 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 and can result in increased capital, operating and other
costs as a result of compliance, remediation, containment and monitoring
obligations. To the extent environmental costs are incurred through June 30,
2007, in excess of the level currently included in electric retail Virginia
jurisdictional rates, the amounts will be reflected in Dominion's results of
operations. After that date, recovery through regulated rates may be sought for
only those environmental costs related to regulated electric transmission and
distribution operations. Dominion may seek recovery through regulated rates for
environmental expenditures related to regulated gas transmission and
distribution operations.
Environmental Protection and Monitoring Expenditures
Dominion incurred approximately $94 million, $78 million, and $72 million of
expenses (including depreciation) during 2000, 1999, and 1998, respectively, in
connection with the use of environmental protection and monitoring activities,
and expects these expenses to be approximately $91 million in 2001. In
addition, capital expenditures related to environmental controls were $214
million, $84 million, and $22 million for 2000, 1999, and 1998, respectively.
The amount estimated for 2001 for these expenditures is $200 million.
Clean Air Act Compliance
The Clean Air Act requires Dominion to reduce its emissions of SO\\2\\ and
NO\\X\\, which are gaseous by-products of fossil fuel combustion. The Clean Air
Act also requires Dominion to obtain operating permits for all major emissions-
emitting facilities. Permit applications have been submitted for Dominion's
power stations. The Clean Air Act's SO\\2\\ reduction program is based on the
issuance of a limited number of SO\\2\\ emission allowances, each of which may
be used as a permit to emit one ton of SO\\2\\ into the atmosphere or may be
sold to a third party.
In September 1998, the EPA adopted a rule requiring 22 states, including
Virginia, West Virginia, Illinois and North Carolina, to reduce and cap ozone-
season NO\\X\\ emissions beginning in May 2003. A recent court ruling has
extended the compliance date to May 31, 2004. In response to these requirements,
Dominion plans to install NO\\X\\ reduction equipment at its coal-fired
generating facilities at an estimated capital cost of approximately $635 million
over the next several years. Whether these costs are actually incurred is
dependent on the outcome of pending litigation of these rules, the
implementation plans adopted by the states in which Dominion operates and
Dominion's agreement in principle with the federal government as discussed
below.
Evaluation and planning of future projects to comply with SO\\2\\ and NO\\X\\
reduction requirements are ongoing and will be influenced by changes in the
regulatory environment, availability of SO\\2\\ allowances, and emission control
technology.
37
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations (continued)
During 2000, Dominion received a Notice of Violation from the EPA alleging
that it failed to obtain New Source Review permits under the Clean Air Act prior
to undertaking specified construction projects at the Mt. Storm Power Station in
West Virginia. Management believes that Dominion has obtained the permits
necessary in connection with its generating facilities. Dominion has reached an
agreement in principle with the federal government and the state of New York
concerning the implementation of certain additional environmental controls at
its coal-fired generating stations in connection with the resolution of various
Clean Air Act matters. The agreement in principle includes payment of a $5
million civil penalty, a commitment of $14 million for environmental projects in
Virginia, West Virginia, Connecticut, New Jersey and New York, and a 12-year,
$1.2 billion capital investment program for environmental improvements at
Dominion's coal-fired generating stations in Virginia and West Virginia.
Dominion had already committed to a substantial portion of the $1.2 billion
expenditures for SO\2\ and NO\X\ emissions controls as discussed above. Although
Dominion has reached an agreement in principle, the terms of a final binding
settlement are still under negotiation. See Note 22 to the Consolidated
Financial Statements.
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 in December 1997 in Kyoto, Japan. This
Protocol calls for the United States to reduce greenhouse emissions by 7 percent
from 1990 baseline levels by the period 2008-2012. The Protocol has been signed
by the United States but will not constitute a binding commitment unless
submitted to and approved by the United States Senate. Emission reductions of
the magnitude included in the Protocol, if adopted, would likely result in a
substantial financial impact on companies that consume or produce fossil fuel-
derived electric power, including Dominion.
Recently Issued Accounting Standards
In June 2000, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 138, Accounting for Certain
Derivative Instruments and Certain Hedging Activities, which amends SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133
requires that all derivative instruments be recorded on the Company's balance
sheet at their fair value effective January 1, 2001.
Dominion has determined that certain contracts used in its operations will be
subject to fair value accounting under SFAS No. 133. A substantial portion of
these contracts is used by Dominion in its production and delivery of energy to
its customers and the contracts involve various hedging strategies. In addition
to these commodity contracts, Dominion uses interest rate swaps to manage its
cost of capital.
The Company will record one-time, non-operating after-tax charges to net
income of approximately $1 million and other comprehensive income of
approximately $180 million in the first quarter of 2001 for the initial adoption
of SFAS No. 133. These adjustments will be recognized as of January 1, 2001 as
the cumulative effect of a change in accounting principle. The ongoing effects
will depend on future market conditions, the Company's hedging activities, and
further interpretations of the standard. The Derivatives Implementation Group
(DIG), a group sponsored by the FASB, continues to develop interpretive
guidance. The DIG has not yet resolved certain issues that could ultimately
impact the application of the standard.
Restructuring and Other Acquisition-Related Charges
Subsequent to its acquisition of CNG, Dominion developed and began the
implementation of a plan to restructure the operations of the combined
companies. Restructuring activities include workforce reductions and the
consolidation of post-merger operations and information technology systems. For
the year ended December 31, 2000, the Company recognized $460 million of
restructuring costs and other acquisition-related costs. See Note 6 to the
Consolidated Financial Statements.
The 2000 workforce reductions and other restructuring actions should reduce
future annualized operating costs by approximately $102 million that would
otherwise have been incurred.
Business Opportunities and Other Operations
Because Dominion's industry is rapidly changing, there are many opportunities
for acquisitions of assets and business combinations. Dominion investigates any
opportunity that may increase shareholder value and build on existing
businesses. Dominion has participated in the past, and its security holders may
assume that at any time Dominion may be participating, in bidding or other
negotiating processes for such transactions. Such participation may or may not
result in a transaction for Dominion. However, any such transaction that does
take place may involve consideration in the form of cash, debt or equity
securities and may involve payment of a premium over book or market values. Such
transactions or payments could affect the market prices and rates for Dominion's
securities.
Exploration and Production Operations
Dominion continues to focus on maintaining and increasing earnings from oil and
gas properties primarily through development and acquisition activities and
operating efficiencies. Dominion will continue to seek opportunities to optimize
the value of its reserves through the convergence of its gas and electric
products and maximization of its gas storage facilities. In addition, sharing
past experiences and sound business practices developed over time in oil and gas
operations should help improve operational efficiencies and minimize finding,
developing and lifting costs. Additional efficiencies are being achieved by
elimination of duplicate administrative functions.
38
<PAGE>
Due to unprecedented supply and demand factors, natural gas prices are now at
levels not seen in years. While increased prices can benefit Dominion, where
over 80 percent of reserves are natural gas, higher prices also will impact the
future cost of acquiring, finding, developing and producing reserves. Higher oil
and gas prices have impacted both the availability and cost of oilfield
equipment and materials, such as rigs, boats and drill pipe.
Independent Power Production Operations
Dominion's future focus in its power generation business is to acquire and
develop additional power generation in the MAIN to Maine region. The region
begins at the Mid-America Interconnected Network (MAIN) and extends
northeastward through Maine. MAIN includes electric service territories of the
upper Midwest. Dominion is benefiting from the CNG acquisition as it plans to
develop natural gas-fired power generation facilities along its natural gas
pipeline system. Dominion has identified a number of potential development sites
in Ohio, Pennsylvania, New York, West Virginia and Virginia.
Telecommunications Operations
The Company plans to expand its telecommunications operations as a competitive
provider of telecommunications service, including the development of a
facilities-based high-bandwidth capacity telecommunications network throughout
the eastern United States. Initially, Dominion will build its network through
the acquisition of dark fiber capacity on existing third-party networks. It
expects future growth of its network to occur through joint development projects
on third-party rights of way. The Company anticipates financing these expansion
plans through a financing structure that will allow Dominion to deconsolidate
its telecommunications business, while maintaining management flexibility for
future growth. Dominion expects to close the approximately $700 million
financing plan in early 2001 and will use the proceeds to fund
telecommunications expansion.
Divestitures
Under the SEC's order approving the CNG acquisition, Dominion must divest itself
of DCI within three years. No formal plan of divestiture has been adopted.
However, Dominion has sold certain portions of its financial services
businesses. Until DCI is sold, Dominion will continue to operate these financial
service activities and be subject to their risks.
Restructuring of Contracts with Non-Utility
Generating Facilities
The Company has reached an agreement, pending regulatory approvals, to terminate
three long-term power purchase agreements. Dominion expects the transaction to
be completed in the first quarter of 2001, resulting in a one-time, non-
operating charge of approximately $135 million, after taxes. The transaction is
part of an ongoing program which seeks to achieve competitive cost structures at
its power generating business.
Nuclear Relicensing
In June 2001, Dominion plans to file applications with the NRC to renew the
operating licenses for its Surry and North Anna nuclear stations. The technical
work required to support a license renewal application was completed in 2000.
The renewal of the license will extend the plants' useful lives by 20 years. See
Note 14 to the Consolidated Financial Statements.
Effect of Changes in Natural Gas and Oil Prices
Dominion's operations are impacted by changes in energy commodity prices. To the
extent energy commodities are sold by one of Dominion's cost-of-service rate
regulated utilities, the cost of such commodities are generally recovered
through rates. For sales of Dominion's production of natural gas and oil and for
sales of energy commodities through nonregulated subsidiaries, price changes
impact Dominion's sales revenue. However, Dominion has established an enterprise
risk management function to manage such price risk exposures.
Market Rate Sensitive Instruments and Risk Management
Dominion is exposed to market risk because it utilizes financial instruments,
derivative financial instruments and derivative commodity instruments. The
market risks inherent in these instruments are represented by the potential loss
due to adverse changes in interest rates, commodity prices and equity security
prices as described below. Interest rate risk generally is related to Dominion's
outstanding debt as well as its commercial, consumer, and mortgage lending
activities. Commodity price risk is experienced in Dominion's electric
operations, gas production and procurement operations, and energy marketing and
trading operations due to the exposure to market shifts for prices received and
paid for natural gas and electricity. Dominion uses derivative commodity
instruments to hedge price exposures for these operations. Dominion is exposed
to equity price risk through various portfolios of equity securities.
Dominion uses the sensitivity analysis methodology to disclose the
quantitative information for interest rate and commodity price risks. The
sensitivity analysis estimates the potential loss of future earnings or fair
value from market risk sensitive instruments over a selected time period due to
a 10% unfavorable change in interest rates and commodity prices.
39
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations (continued)
Interest Rate Risk
Dominion manages its interest rate risk exposure by maintaining a mix of fixed
and variable rate debt. In addition, Dominion enters into interest rate
sensitive derivatives. Examples of these derivatives are swaps, forwards and
futures contracts. In addition, Dominion, through subsidiaries, retains
ownership in mortgage investments, including subordinated bonds and interest-
only residual assets retained at securitization of mortgage loans originated and
purchased. For financial instruments outstanding at December 31, 2000, a
hypothetical 10% increase in market interest rates would decrease annual
earnings by approximately $40 million. A hypothetical 10% increase in market
interest rates, as determined at December 31, 1999, would have resulted in a
decrease in annual earnings of $31 million.
Commodity Price Risk -- Non-Trading Activities
Dominion manages the price risk associated with purchases and sales of natural
gas and oil by selecting derivative commodity instruments including futures,
forwards, options, swaps, and collars.
For sensitivity analysis purposes, the fair value of Dominion's oil and
natural gas derivative financial contracts are determined from models which take
into account the market prices of oil and natural gas in future periods, the
volatility of the market prices in each period, as well as the time value
factors of the underlying commitments. In most instances, market prices and
volatility are determined from quoted prices on the futures exchange.
Dominion has determined a hypothetical change in fair value for its oil and
natural gas derivative financial contracts assuming a 10% unfavorable change in
market prices. This hypothetical 10% change in market prices would have resulted
in a decrease in fair value of approximately $56 million and $20 million as of
December 31, 2000 and December 31, 1999, respectively.
The impact of a change in oil and natural gas commodity prices on
Dominion's oil and natural gas derivative financial contracts at a point in time
is not necessarily representative of the results that will be realized when such
contracts are ultimately settled. Net losses from oil and natural gas financial
derivative contracts used for hedging purposes, to the extent realized, should
generally be offset by recognition of the hedged transaction.
Commodity Price Risk -- Trading Activities
As part of its strategy to market energy from its generation capacity and to
manage related risks, Dominion manages a portfolio of derivative commodity
contracts held for trading purposes. These contracts are sensitive to changes in
the prices of natural gas and electricity. Dominion employs established policies
and procedures to manage the risks associated with these price fluctuations and
uses various commodity instruments, such as futures, swaps and options, to
reduce risk by creating offsetting market positions. In addition, Dominion seeks
to use its generation capacity, when not needed to serve customers in its
service territory, to satisfy commitments to sell energy.
A hypothetical 10% change in commodity prices would have resulted in a
hypothetical loss of approximately $3 million and $5 million in the fair value
of its commodity contracts, held for trading purposes, as of December 31, 2000
and 1999, respectively.
Equity Price Risk
Dominion is subject to equity price risk due to marketable securities held as
investments and in trust funds. In accordance with current accounting standards,
the marketable securities are reported on the balance sheet at fair value. The
following table presents descriptions of the equity securities held by Dominion
at December 31, 2000 and 1999.
<TABLE>
<CAPTION>
2000 1999
- ----------------------------------------------------------------------------------
Fair Fair
(millions) Cost Value Cost Value
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Trading:
Short-term marketable
securities $275 $275 $ 1 $ 2
Other than trading:
Marketable securities 134 118 134 126
Nuclear decommissioning
trust investments 279 549 274 565
==================================================================================
</TABLE>
Risk Management Policies
Dominion has operating procedures in place that are administered by experienced
management to help ensure that proper internal controls are maintained. In
addition, Dominion has established an independent function at the corporate
level to monitor compliance with the price risk management policies of all
subsidiaries. Dominion maintains credit policies that include the evaluation of
a prospective counterparty's financial condition, collateral requirements where
deemed necessary, and the use of standardized agreements which facilitate the
netting of cash flows associated with a single counterparty. In addition,
Dominion also monitors the financial condition of existing counterparties on an
ongoing basis. Dominion believes it unlikely that a material adverse effect on
its financial position, results of operations or cash flows would occur as a
result of counterparty nonperformance.
40
<PAGE>
[LOGO] Notes to Consolidated Financial Statements
Note 1 | Nature of Operations
General Organization and Legal Description
Dominion Resources, Inc. (Dominion or the Company) is a holding company
headquartered in Richmond, Virginia. Its principal subsidiaries are Virginia
Electric and Power Company (Virginia Power) and, with the completion of the
acquisition on January 28, 2000, Consolidated Natural Gas Company (CNG).
Dominion is subject to the Public Utility Holding Company Act of 1935 (1935
Act).
Virginia Power 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. Virginia Power
sells electricity to approximately 2.1 million retail customers (including
governmental agencies) and to wholesale customers such as rural electric
cooperatives, municipalities, power marketers and other utilities. Virginia
Power engages in off-system wholesale purchases and sales of electricity and
purchases and sales of natural gas beyond the geographic limits of its retail
service territory.
CNG operates in all phases of the natural gas industry, including
exploration for and production of oil and natural gas in the United States. Its
regulated retail gas distribution subsidiaries serve approximately 1.7 million
residential, commercial and industrial gas sales and transportation customers in
Ohio, Pennsylvania and West Virginia. Its interstate gas transmission pipeline
system services each of its distribution subsidiaries, non-affiliated utilities
and end use customers in the Midwest, the Mid-Atlantic and the Northeast states.
CNG's exploration and production operations are conducted in several of the
major gas and oil producing basins in the United States, both onshore and
offshore. CNG also holds equity investments in energy activities in Australia,
which are held for sale.
The Company's other major subsidiaries are Dominion Energy, Inc. (DEI) and
Dominion Capital, Inc. (DCI). DEI is engaged in independent power production and
the acquisition and production of natural gas and oil reserves. In Canada, DEI
is engaged in natural gas exploration, production and storage. DCI is Dominion's
financial services subsidiary. DCI's primary business is financial services
which includes commercial lending and residential mortgage lending. See Note 6
for a discussion of management's strategy to exit and windup DCI's businesses as
ordered by the Securities and Exchange Commission (SEC) under the 1935 Act.
In mid-1998 Dominion sold East Midlands Electricity, plc (East Midlands),
an electricity distribution and supply company in the United Kingdom.
Dominion created a subsidiary service company under the 1935 Act, Dominion
Resources Services, Inc. (Services), which provided certain services to
Dominion's operating subsidiaries. During 2000, CNG also had a service company.
Effective January 1, 2001, the two service companies were combined into one
service company.
Dominion manages its operations based on the following operating segments:
Dominion Energy, Dominion Delivery and Dominion Exploration & Production. In
addition, Dominion also reviews the financial services business of DCI and
Corporate Operations as segments.
While Dominion manages its daily operations as described above, assets
remain wholly owned by its legal subsidiaries. For more information on business
segments, see Note 27.
"Dominion" or the "Company" is used throughout this report and, depending
on the context of its use, may represent any of the following: the legal entity,
Dominion Resources, Inc., one of Dominion's consolidated subsidiaries or the
entirety of Dominion Resources, Inc. and its consolidated subsidiaries.
Note 2 | Significant Accounting Policies
General
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent liabilities at the date of the financial statements and the reported
amounts of revenue and expenses during the reporting period. Actual results
could differ from those estimates.
The consolidated financial statements represent the accounts of the Company
after the elimination of intercompany transactions. The Company follows the
equity method of accounting for investments in partnerships and corporate
joint ventures when the company is able to influence the financial and
operating policies of the investee. For all other investments, the cost method
is applied.
Accounting for the utility businesses conforms with generally accepted
accounting principles as applied to regulated public utilities and as
prescribed by federal agencies and the commissions of the states in which the
utility business operates.
Revenue
Revenue is recorded on the basis of services rendered, commodities delivered or
contracts settled and include amounts yet to be billed to customers. Revenue
from trading activities include realized commodity contract revenue, net of
related cost of sales, amortization of option premiums, and unrealized gains and
losses resulting from marking to market those commodity contracts not yet
settled. Dividend income on securities owned is recognized on the ex-dividend
date.
41
<PAGE>
Notes to Consolidated Financial Statements (continued)
Fuel, Net
Fuel, net includes the cost of fossil fuel and nuclear fuel used in electric
generation and purchased energy used to serve electric sales. It also includes
the cost of purchased energy associated with power marketing sales subject to
cost of service rate regulation.
Practically all of Dominion's electric service regulated fuel costs are
subject to deferral accounting. Deferral accounting provides that the difference
between reasonably incurred actual expenses and the level of expenses included
in current rates is deferred and matched against future revenues. Fuel, net
includes the effect of this deferral accounting and may therefore show expenses
that are marginally higher or lower than the actual cost of fuel consumed during
the period.
Unrecovered Gas Costs
Where permitted by regulatory authorities, the Company defers the difference
between the cost of gas (including certain related costs) and the amount of such
costs included in current customer rates. The differences are accounted for as
either unrecovered gas costs or amounts payable to customers. Unrecovered
amounts are recognized as purchased gas expenses in future periods when the
costs are recovered through adjusted rates.
Goodwill, Net
Goodwill is the excess of the cost of net identifiable assets acquired in
business combinations over their fair value. It is amortized on a straight-line
basis over periods up to 40 years.
Utility and Other Plant
Property, plant and equipment are stated at cost. Additions and betterments are
charged to the property accounts at cost. Maintenance, repairs and related costs
are charged principally to expense as incurred.
Impairment of Long-Lived Assets
Whenever events or changes in circumstances indicate that the carrying amount of
long-lived assets or intangible assets, including goodwill, may not be
recoverable, an evaluation for impairment is performed. Such evaluations may
consider various analyses, including undiscounted future cash flows attributable
to the assets.
Exploration and Production Properties
Effective with the acquisition of CNG on January 28, 2000, Dominion changed its
method of accounting for its oil and gas exploration and production activities
to the full cost method of accounting. Previously, the Company had accounted for
these activities, which were primarily directed toward development and
extraction rather than exploration, using the successful efforts method of
accounting. Prior periods have been restated. The effect of restatement on 1999
and 1998 was not material. For more information on the accounting change, see
Note 3.
Under the full cost method, all costs directly associated with property
acquisition, exploration, and development activities are capitalized, with the
principal limitation that such amounts not exceed the present value of estimated
future net revenues to be derived from the production of proved gas and oil
reserves (the "ceiling test"). If net capitalized costs exceed the ceiling test
at the end of any quarterly period, then a permanent write-down of the assets
must be recognized in that period. The ceiling test is performed separately for
each cost center, with cost centers established on a country-by-country basis.
Depreciation, Depletion and Amortization
Depreciation and amortization are recorded over the estimated service lives of
plant assets by application of the straight-line method or, in the case of gas
and oil producing properties, the unit-of-production method. The cost of
depreciable gas utility and electric transmission and distribution property
retired and related cost of removal, less salvage, are charged to accumulated
depreciation. For generation-related property, cost of removal is charged to
expense as incurred. The Company records gains and losses upon retirement of
generation-related property based upon the difference between proceeds received,
if any, and the property's undepreciated basis at the retirement date. Owned
nuclear fuel is amortized on a unit-of-production basis sufficient to amortize
fully, over the estimated service life, the cost of the fuel plus permanent
storage and disposal costs.
Estimated useful lives of the Company's property, plant and equipment are
as follows: production 10-66 years, transmission 10-77 years, distribution 10-66
years, storage 10-69 years, and other 5-50 years.
Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil reserves,
and on estimated dismantlement and abandonment costs net of projected salvage
values. However, the costs of investments in unproved properties and major
development projects are excluded from amortization until it is determined
whether or not proved reserves are attributable to such properties.
Capitalized Interest
Interest is capitalized in connection with the construction of major facilities.
The capitalized interest is recorded as part of the asset and is depreciated
over the asset's estimated useful life. In 2000, 1999 and 1998, $22 million, $30
million and $10 million of interest cost was capitalized, respectively.
Income Taxes
Dominion and its subsidiaries file a consolidated federal income tax return.
Deferred income taxes are provided for all significant temporary differences
between the financial and tax basis of assets and liabilities. The regulatory
treatment of temporary differences can differ from the requirements of Statement
of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes.
Accordingly, a regulatory asset has been recognized if it is probable
42
<PAGE>
that future revenues will be provided for the payment of deferred tax
liabilities.
Dominion accounts for investment tax credits related to utility plant
subject to cost-based regulation under the "deferral method," which provides for
the amortization of these credits over the service lives of the property giving
rise to the credits.
Regulatory Assets and Liabilities
Generally, Dominion uses the same accounting policies and practices used by
nonregulated companies for financial reporting under generally accepted
accounting principles. However, regulatory authorities may order an accounting
treatment different from that used by nonregulated companies to determine the
rates charged to customers. When this occurs, certain utility income and
expenses are deferred as regulatory assets and liabilities. See Notes 7 and 12
for additional information on regulatory assets and liabilities and the impact
of legislation on continued application of SFAS No. 71, Accounting for the
Effects of Certain Types of Regulation.
Foreign Currency Translation
Dominion translates foreign currency financial statements by adjusting balance
sheet accounts using the exchange rate at the balance sheet date and income
statement accounts using the average exchange rate for the year. Translation
gains and losses are recorded in shareholders' equity as a component of
accumulated other comprehensive income. Gains and losses resulting from the
settlement of transactions in a currency other than the functional currency are
reflected in income.
Amortization of Debt Issuance Costs
Dominion defers and amortizes the expenses incurred in the issuance of long-term
debt, together with premiums and discounts associated with such debt, over the
lives of the respective issues. Any gains or losses resulting from the
refinancing of debt allocable to utility operations that are subject to cost-
based regulation are also deferred and amortized over the lives of the new
issues of long-term debt as permitted by regulatory commissions. In addition,
gains or losses resulting from the redemption of debt allocable to utility
operations that are subject to cost-based regulation without refinancing are
amortized over the remaining lives of the redeemed issues.
Investment Securities
Dominion accounts for and classifies investments in equity securities that have
readily determinable fair values and for all investments in debt securities
based on management's intent. The investments are classified into three
categories. Debt securities which are intended to be held to maturity are
classified as held-to-maturity securities and reported at amortized cost. Debt
and equity securities purchased and held with the intent of selling them in the
current period are classified as trading securities and are reported at fair
value with unrealized gains and losses included in earnings. Debt and equity
securities that are neither held-to-maturity nor trading are classified as
available-for-sale securities. These are reported at fair value with unrealized
gains and losses reported in shareholders' equity, as a component of accumulated
other comprehensive income, net of tax. For a discussion of the treatment for
securities held in nuclear decommissioning trusts and classified as available-
for-sale, see Note 14.
Mortgage Loans Held for Sale
Mortgage loans held for sale consist of mortgage loans secured by single family
residential properties. Any price premiums or discounts on mortgage loans,
including any capitalized costs or deferred fees on originated loans, are
deferred as an adjustment to the cost of the loans and are therefore included in
the determination of any gains or losses on sales of the related loans. Mortgage
loans held for sale are carried at the lower of cost or market value.
Loans Receivable, Net and Finance Receivables
Held for Sale
Loans receivable and finance receivables held for sale are stated at their
outstanding principal balance, net of the allowance for credit losses and any
deferred fees or costs. Origination fees, net of certain direct origination
costs, are deferred and recognized as an adjustment of the yield of the related
loans receivable.
The allowance for credit losses is established through provisions for
credit losses charged against income. Loans and finance receivables deemed to
be uncollectible are charged against the allowance for credit losses, and
subsequent recoveries, if any, are credited to the allowance. At December 31,
2000 and 1999, the allowance for credit losses for loans receivable, net was $61
million and $47 million, respectively.
Gain on Sale of Loans
Gain on sale of loans represents the present value of amounts based on the
difference between the interest rate to be received on the mortgage loans sold
and the interest rate to be paid to investors participating in securitizations,
after considering estimated prepayments, credit losses, servicing costs, and
non-refundable fees and premiums. Securitizations involve selling mortgage loans
to an unconsolidated special purpose trust in exchange for cash proceeds and an
interest in the loans securitized (residual assets). Gains on the sale of loans
are recognized on the settlement date. Residual assets may include interest-only
strips and servicing rights. Interest-only residual assets are recorded based on
the net present value of the projected cash flows, using management's best
estimates of the key assumptions, including credit losses, prepayment speeds,
forward yield curves, and discount rates commensurate with the risks involved.
Loan Servicing Rights
Dominion recognizes as separate assets its rights to service mortgage loans.
Mortgage servicing rights are recorded when purchased or when mortgage loans are
originated and subsequently sold or securitized with the servicing rights
retained. Servicing rights are recorded based on the relative fair value of the
mortgage loans and the servicing rights. The fair value of the servicing rights
43
<PAGE>
Notes to Consolidated Financial Statements (continued)
is determined based on market prices under comparable servicing sales contracts
or the present value of estimated future cash flows. Dominion assesses the
impairment of mortgage servicing rights based on the fair value of those rights,
and any impairment is recognized through a valuation allowance.
Mortgage loans serviced require regular monthly payments from borrowers.
Income on loan servicing is generally recorded as payments are collected and is
based on a percentage of the principal balance of loans serviced. Loan servicing
expenses are charged to operations when incurred.
Mortgage Investments
Mortgage investments consist of subordinated bonds and interest-only residual
assets retained at securitization of mortgage loans. Mortgage investments are
classified as trading securities. Interest-only strip residual assets are
amortized in proportion to the estimated income received but are analyzed
quarterly to determine whether prepayment experience, losses and changes in the
interest rate environment have had an impact on the valuation. Expected cash
flows of the underlying loans sold are reviewed based upon current economic
conditions and the type of loans originated and are revised as necessary.
Derivatives -- Other Than Trading
Dominion utilizes futures and forward contracts and derivative financial
instruments, including swaps, caps and collars, to manage exposure to
fluctuations in interest rates, lease payments, and natural gas and electricity
prices.
These futures, forwards and derivative financial instruments are deemed
effective hedges when the item being hedged and the underlying financial or
commodity instrument show strong historical correlation. Dominion uses deferral
accounting to account for futures, forwards and derivative instruments which are
designated as hedges. Under this method, gains and losses (including the payment
of any premium) related to effective hedges of existing assets and liabilities
are recognized in earnings in conjunction with earnings of the designated asset
or liability. Gains and losses related to effective hedges of firm commitments
and anticipated transactions are included in the measurement of the subsequent
transaction. Cash flow from derivatives designed as hedges are reported in net
cash flow from operating activities.
Derivatives -- Trading
The fair value method, which is used for those derivative transactions which do
not qualify for settlement or deferral accounting, requires that derivatives are
carried on the balance sheet at fair value, with changes in that value
recognized in earnings or common shareholders' equity. As part of Dominion's
strategy to market energy from its generation capacity and to manage the risks
related thereto, it enters into contracts for the purchase and sale of energy
commodities. Dominion uses the fair value method for its trading activities.
Options, swaps and future contracts are marked to market with resulting
gains and losses reported in earnings. Forward contracts, initiated for trading
purposes, are also marked to market with resulting gains and losses reported in
earnings. For swaps, forward contracts, and options, market value reflects
management's best estimates considering over-the-counter quotations, time value
and volatility factors of the underlying commitments. Exchange-traded futures
and options are marked to market based on exchange closing prices.
Commodity contracts representing unrealized gain positions are reported as
Commodity contract assets; commodity contracts representing unrealized losses
are reported as Commodity contract liabilities. In addition, purchased options
and options sold are reported as Commodity contract assets and Commodity
contract liabilities, respectively, at estimated market value until exercise or
expiration. Realized commodity contract revenues, net of related cost of sales,
settlement of futures contracts, amortization of option premiums, and unrealized
gains and losses resulting from marking positions to market are included in
Operating revenue. Cash flow from trading activities is reported in net cash
flow from operating activities.
Other Derivatives
Dominion uses total return swaps to accumulate loans and securities for future
sale as collateralized debt obligation securities. Gains and losses from the
settlements and sale of total return swaps are recorded as Operating revenue and
income -- Other. Total return swaps are marked to market with the corresponding
unrealized gains and losses also recorded in Operating revenue and income --
Other. Cash flow from total return swaps are reported in net cash flow from
operating activities. As of December 31, 2000, all total return swaps relating
to the above have been terminated.
Dominion has used total return equity swaps to reacquire shares of its
outstanding common stock. Dominion has recorded all amounts received or paid in
2000 under such arrangements as either increases or decreases to equity.
The net of amounts paid and amounts received under interest rate swaps is
reported as interest expense in the Consolidated Statement of Income.
See Note 4 for discussion of recently issued accounting standards and their
impact on the Company's accounting for derivatives in 2001.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until
actually presented for payment. At December 31, 2000 and 1999, accounts payable
included the net effect of checks outstanding but not yet presented for payment
of $171 million and $61 million, respectively.
For purposes of the Consolidated Statements of Cash Flows, Dominion
considers cash and cash equivalents to include cash on hand and temporary
investments purchased with a maturity of three months or less.
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<PAGE>
Reclassification
Certain amounts in the 1999 and 1998 Consolidated Financial Statements have been
reclassified to conform to the 2000 presentation.
Note 3 | Accounting Changes
Accounting for Net Periodic Pension Cost
Effective January 1, 2000, Dominion adopted a company-wide method of calculating
the market related value of pension plan assets used to determine the expected
return on pension plan assets, a component of net periodic pension cost. Under
the new method, the market related value of pension plan assets reflects the
difference between actual investment returns and expected investment returns
evenly over a four-year period. Prior to Dominion's acquisition of CNG, each
company used different methods to determine the "calculated value" of the market
related value of pension plan assets. The previous Dominion method recognized
interest, dividends and realized gains immediately and deferred unrealized gains
and losses evenly over a five-year period. The former CNG method calculated the
market related value of pension plan assets as the average of market values at
the end of each of the preceding four years, with appropriate adjustments for
receipts, disbursements, and investment income during the period. Dominion
believes that the new method is preferable to continuing to use either or both
of the former methods as the new method enhances the predictability of expected
return on pension plan assets, provides consistent treatment of all investment
gains and losses, and results in calculated market related pension plan asset
values that are closer to market value as compared to values calculated under
the previous methods.
The $21 million cumulative effect of the change on prior years (net of
income taxes of $11 million) is included in income for the year ended December
31, 2000. The effect of the change on 2000 was to increase income before
extraordinary item and cumulative effect of a change in accounting principle by
$11 million ($0.05 per share-basic and diluted) and net income by $32 million
($0.14 per share-basic and diluted).
Retroactive application of the new method, on a pro forma basis, would not
have materially changed Dominion's net income for 1999 or 1998.
Accounting for Oil and Gas Activities
Effective upon the acquisition of CNG on January 28, 2000, Dominion changed its
method of accounting for oil and gas exploration and production activities to
the full cost method of accounting. Previously, Dominion accounted for these
activities, which were primarily directed toward development and extraction
rather than exploration, using the successful efforts method of accounting.
While the Company's previous method of accounting was in accordance with
generally accepted accounting principles, the Company believes that the full
cost method of accounting is preferable for its merged exploration and
production operations. CNG's exploration and production business is historically
larger than Dominion's and consists of substantial investments in exploration
activities. CNG uses the full cost method of accounting for its exploration and
production activities which management believes better reflects the economics
associated with the discovery and development of oil and gas reserves. It is
anticipated that the strategic direction of the combined exploration and
production operations will be consistent with CNG's past operations, thus
supporting the adoption of the full cost method of accounting.
Prior year financial statements have been restated to reflect this change
on a retroactive basis. The effect of the accounting change on income in 2000,
and on income as previously reported for 1999 and 1998 is not significant.
The balances of retained earnings for 1999 and 1998 have been restated for
the effect (net of income taxes) of applying retroactively the new method of
accounting.
Note 4 | Recently Issued Accounting Standards
In June 2000, the Financial Accounting Standards Board (FASB) issued SFAS No.
138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, which amends SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities. SFAS No. 133 requires that all derivative instruments be
recorded on the Company's balance sheet at their fair value effective January 1,
2001.
The Company holds certain commodity contracts for trading purposes that are
currently subject to fair value accounting under Emerging Issues Task Force
Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The Company determined that certain additional contracts
will be subject to fair value accounting under SFAS No. 133. A substantial
portion of these contracts is used by Dominion in its production and delivery of
energy to its customers and involves various hedging strategies. In addition to
these commodity contracts, Dominion uses interest rate swaps to manage its cost
of capital.
Under SFAS No. 133, changes in the fair value of derivatives are recorded
each period in current earnings or other comprehensive income, depending on
whether a derivative is designated and effective as part of a hedge strategy,
and, if it is, whether such strategy represents a fair value or cash flow hedge.
For fair value hedge strategies, where Dominion is hedging the changes in the
fair value of assets, liabilities or firm commitments, changes in the fair value
of the derivative instruments will generally be offset in the income statement
by changes in the fair value of the hedged items. For cash flow hedge
strategies, where Dominion is hedging the variability of cash flows related to
variable-priced assets, liabilities or forecasted transactions, including
anticipated production, purchases or sales, changes in the fair value of the
derivative instruments will be reported in other comprehensive income. Amounts
recorded in other comprehensive income will be adjusted for changes in fair
value until reclassified to earnings. Such reclassification will generally occur
when earnings are affected by the hedged transactions (e.g., anticipated sales).
As amounts
45
<PAGE>
Notes to Consolidated Financial Statements (continued)
are reclassified from other comprehensive income, the impact on earnings should
generally be offset by the recognition of the hedged transactions.
The Company will record after-tax charges to net income of approximately $1
million and other comprehensive income of approximately $180 million in the
first quarter of 2001 for the initial adoption of SFAS No. 133. These
adjustments will be recognized as of January 1, 2001 as the cumulative effect of
a change in accounting principle.
The Derivatives Implementation Group (DIG), a group sponsored by the FASB,
continues to develop interpretive guidance. The DIG has not yet concluded on
certain issues that could ultimately impact the application of the standard.
Note 5 | Acquisitions and Divestitures
Consolidated Natural Gas Company
On January 28, 2000, Dominion acquired all of the outstanding shares of CNG
common stock for a purchase price of $6.4 billion, consisting of approximately
87 million shares of Dominion common stock valued at $3.5 billion and
approximately $2.9 billion in cash . Dominion has accounted for the acquisition
of CNG's operations that are not subject to cost-based rate regulation,
primarily its oil and gas exploration and production operations, using the
purchase method of accounting. For CNG's interstate pipeline and local gas
distribution businesses that are subject to cost-based rate regulation, Dominion
has accounted for the acquisition in accordance with SFAS No. 71.
The purchase price has been allocated to assets acquired and liabilities
assumed based on the estimated fair value of those assets and liabilities as of
the date of the acquisition. Such allocation was based on the Company's
evaluations. The excess of the purchase price over the fair value of CNG's
operations not subject to cost-based rate regulation and the historical carrying
value of CNG's operations subject to cost of service rate regulation resulted in
goodwill of $3.5 billion. The goodwill is being amortized on a straight-line
basis over the weighted average useful lives of CNG's gas utility plant and
equipment, a period approximating 40 years. As of December 31, 2000, $77 million
of amortization associated with the goodwill had been recognized. The results of
operations of CNG for the period January 28, 2000 through December 31, 2000 are
included in the accompanying consolidated financial statements .
Initially, the allocation of the purchase price included estimated values
for amounts expected to be realized from the sale of Virginia Natural Gas (VNG)
and CNG International, which were classified as Net assets held for sale. In
addition, the allocation of the purchase price provided for recognition of
liabilities associated with change of control payments triggered by the
acquisition of CNG under certain employment contracts ($31 million) and seismic
licensing agreements ($26 million).
The Company has made adjustments during 2000 to the allocation of the
purchase price for changes in preliminary assumptions and analyses based on
receipt of additional information, to reflect the following:
. actuarial valuations of CNG's pension and other postretirement benefit plan
obligations and related plan assets; and
. actual proceeds realized from the disposition of VNG and CNG International's
Argentine investments.
Net assets held for sale at December 31, 2000 included the unsold portion of
CNG International, which is primarily its equity investment in Australian energy
activities. The December 31, 2000 consolidated balance sheet includes $ 73
million representing the carrying amount of CNG International, which includes
the effects of $12 million of interest and $4 million of operating losses
capitalized during the post-acquisition period.
The following unaudited pro forma combined results of operations for the
years ended December 31, 2000 and 1999 have been prepared assuming the
acquisition of CNG had occurred at the beginning of each period. The pro forma
results are provided for information only. The results are not necessarily
indicative of the actual results that would have been realized had the
acquisition occurred on the indicated date, nor are they necessarily indicative
of future results of operations of the combined companies.
<TABLE>
<CAPTION>
Year ended December 31, 2000 1999
- ----------------------------------------------------------------------------------------------------------------------
(millions, except per share amounts) As Reported Pro Forma As Reported Pro Forma
- ---------------------------------------------------------------------------------------------------------------
Consolidated Results
<S> <C> <C> <C> <C>
Revenue $9,260 $9,627 $5,520 $8,390
Income before
extraordinary item and
cumulative effect of a change
in accounting principle $ 415 $ 475 $ 552 $ 546
Net income $ 436 $ 496 $ 297 $ 291
Earnings per share--basic:
Income before
extraordinary item and
cumulative effect of a change
in accounting principle $ 1.76 $ 1.99 $ 2.88 $ 2.29
Net income $ 1.85 $ 2.08 $ 1.55 $ 1.22
Average shares--basic 235.2 238.9 191.4 238.4
Earnings per share--diluted:
Income before extraordinary item
and cumulative effect of a change
in accounting principle $ 1.76 $ 1.98 $ 2.81 $ 2.22
Net income $ 1.85 $ 2.07 $ 1.48 $ 1.15
Average shares--diluted 235.9 240.0 191.4 238.4
==============================================================================================================
</TABLE>
46
<PAGE>
Millstone Nuclear Power Station
Dominion has reached an agreement to acquire the Millstone Nuclear Power Station
located in Waterford, Connecticut. Dominion is acquiring the three-unit station
from subsidiaries of Northeast Utilities and other owners for a total purchase
price of approximately $1.3 billion, including approximately $1.19 billion
for plant assets and $105 million for fuel. The acquisition will include 100%
ownership interest in Unit 1 and Unit 2, and a 93.47% ownership interest in Unit
3, for a total of 1,954 Mw of generating capacity. Unit 1 is being
decommissioned and is no longer in service. Dominion will assume the
decommissioning trusts for the three units and expects the trusts to be fully
funded to the regulatory minimum at the time of the closing.
Divestitures
In October 2000, Dominion completed the sale of VNG to AGL Resources Inc. Cash
proceeds from the sale were $533 million.
After Dominion acquired CNG in the first quarter of 2000, CNG committed to a
plan to sell CNG International as part of its desire to focus on the United
States oil and gas markets. In October 2000, CNG International completed the
sale of its Argentine assets to Sempra Energy International for $145 million.
In September 2000, Dominion completed the sale of its 80 percent interest in
Corby Power Limited (Corby) to PowerGen plc. for 52.5 million pounds sterling
($78 million at December 31, 2000). Corby is the owner of a 350-megawatt natural
gas-fired facility about 90 miles north of London, England. The sale of Corby
resulted in an after-tax gain of $13 million ($0.05 per share).
In 1999, Dominion reached an agreement to sell its interests in
approximately 1,200 megawatts of gross generation capacity located in Latin
America. Duke Energy International purchased the interests for approximately
$405 million. The Company completed the sale of its interests in Belize and Peru
in November 1999. In 2000, Dominion completed the sale of its interests in the
generation capacity located in Argentina and Bolivia.
Note 6 | Restructuring and Acquisition-Related Activities
General
As a result of the CNG acquisition and Dominion's desire to focus its businesses
in the MAIN to Maine area of the United States, Dominion is divesting certain
businesses. The region begins at the Mid-America Interconnected Network (MAIN)
and extends north-eastward through Maine. MAIN includes electric service
territories of the upper Midwest. In addition, Dominion and its subsidiaries
developed and began the implementation of a plan to restructure the operations
of the combined companies. The restructuring plan included an involuntary
severance program, a voluntary early retirement program (ERP) and a transition
plan to consolidate operations after the CNG acquisition.
For the year ended December 31, 2000, Dominion recognized $460 million of
restructuring and other acquisition-related costs as follows:
<TABLE>
<CAPTION>
(millions)
- ----------------------------------------------------------------------------
<S> <C>
Severance liability accrued $ 70
Commodity contract losses 55
Information technology related costs 35
Lease termination and restructuring 14
DCI exit strategies 172
ERP benefit costs 114
Curtailment gains (see Note 21) (26)
Other, net 26
- ----------------------------------------------------------------------------
Total restructuring costs $460
- ----------------------------------------------------------------------------
Severance paid $ 41
- ----------------------------------------------------------------------------
Ending severance liability $ 29
- ----------------------------------------------------------------------------
Positions eliminated at December 31, 2000 679
Estimated positions yet to be eliminated 89
ERP participants 860
============================================================================
</TABLE>
Employee Severance Programs
Dominion established a comprehensive involuntary severance package for salaried
employees impacted by workforce reductions. Severance payments are based on the
individual's base salary and years-of-service at the time of termination. In
addition, severance payments are being provided to employees at DCI (and certain
subsidiaries of DCI) who are terminated as part of Dominion's implementation of
its strategy to exit certain businesses of DCI.
Change in Risk Management Strategy
During the first quarter of 2000, Dominion implemented a new hedging strategy
for its combined operations. Under its new strategy, Dominion created an
enterprise risk management group with responsibility for managing Dominion's
aggregate energy portfolio, including the related commodity price risk, across
its consolidated operations. Previously, individual business segments managed
their respective energy portfolios and related price risk exposure on a stand-
alone basis. Dominion management believes this new structure should result in
more effective risk management with the objective of maximizing the value of
Dominion's diversified energy portfolio and market opportunities.
As part of the implementation of the new strategy, management evaluated CNG's
hedging strategy associated with its oil and gas operations in relation to
Dominion's combined operations. As a result of the evaluation, CNG designated
its portfolio of derivative contracts that existed at January 28, 2000 as held
for purposes other than hedging for accounting purposes. This action required a
change to mark-to-market accounting where derivative contracts are carried at
fair value in the balance sheet with any future unrealized gains and losses
included in the determination of net income. In addition, CNG entered into
offsetting contracts for those contracts in the January 28, 2000 portfolio that
would not be
47
<PAGE>
Notes to Consolidated Financial Statements (continued)
settled during the first quarter of 2000. Due to these offsetting contracts,
absent any not yet identified future losses from credit risk exposure, no
additional material losses are expected to be realized as these derivative
contracts mature through 2003.
Early Retirement Program
On January 28, 2000, Dominion announced an early retirement program. This
program was a voluntary program for all salaried employees of Dominion,
excluding officers and employees of DCI, VNG and CNG International. The early
retirement option provides up to three additional years of age and three
additional years of employee service for benefit formula purposes, subject to
age and service maximums under the Company's postretirement medical and pension
plans. Qualifying salaried employees and employees covered by several collective
bargaining agreements of CNG and its participating subsidiaries who had attained
age 52 and completed at least 12 years of service as of July 1, 2000 were
eligible under the ERP. For Dominion's other participating subsidiaries,
qualifying employees who had attained age 52 and completed at least 5 years of
service as of July 1, 2000 were eligible under the ERP.
Certain ERP participants will also receive benefits under the involuntary
severance package, which are subject to reduction as a result of coordination
with additional benefits provided by the ERP.
Dominion Capital
DCI is a diversified financial services company. Its principal subsidiaries are:
. First Source Financial, LLP (First Source), a provider of financial services
to middle market companies;
. First Dominion Capital LLC, (First Dominion Capital) an integrated merchant
banking and asset management business;
. Saxon Mortgage, Inc. and its affiliates (Saxon), are involved in the
origination, purchase and servicing of single-family residential mortgage
loans; and
. Dominion Lands, a developer of real estate projects.
With the acquisition of CNG, Dominion became a registered public utility
holding company subject to the requirements of the 1935 Act. One such
requirement restricts investment in non-regulated businesses which are not
functionally related to the public utility business. As a result, the SEC order
authorizing the CNG acquisition required divestiture of DCI's financial services
businesses within three years. As of December 31, 2000, Dominion had implemented
exit strategies for certain DCI businesses.
During the second quarter of 2000, management adopted a strategy to exit
certain businesses of DCI and to de-emphasize the remaining components of the
businesses that are expected to be retained or possibly held only as long as
necessary to wind up affairs. At this time, the Company does not have a formal
plan of disposal for substantive portions of the DCI segment and does not expect
to dispose of all such portions of the business within one year. Management has
continued to monitor and evaluate its investments in its financial services and
real estate businesses.
In 2000, Dominion recognized impairment losses of $291 million, of which $172
million was determined to be attributable to Dominion's exit strategy rather
than other factors and are included in Restructuring and other acquisition-
related costs. The remaining $119 million of impairment charges are related to
normal operations of DCI. These charges, net of related income taxes of $105
million, reduced net income by $186 million for 2000. These amounts were
recorded and derived from:
. a $106 million impairment at Saxon concerning its interest-only residual
assets and servicing assets;
. additional provisions of $36 million for loan losses applicable to the loans
receivable at First Source and First Dominion Capital;
. a $46 million loss in value in venture capital equity and other equity
investments at First Source and First Dominion Capital;
. a $49 million impairment loss related to its investment in First Source; and
. a $54 million impairment recorded with respect to certain real estate
projects managed and held by Dominion Lands.
As the planned exit strategies at DCI are implemented, additional charges may
be incurred to reflect updated information.
In September 2000, Dominion sold First Dominion Capital's asset management
division. Dominion received approximately $10 million in cash after certain fees
were paid.
Also in October 2000, Dominion sold $823 million in principal amount of
commercial loans held in First Source's loan portfolio.
The transaction settled in a series of closings which began in mid-October and
was completed in the fourth quarter of 2000. Dominion received proceeds of $600
million.
In October 2000, Dominion securitized $716 million in principal amount of
commercial loans held by First Source and First Dominion Capital in a
collateralized loan obligation (CLO) transaction. In the securitization, the
loans were sold to an unconsolidated special purpose loan securitization trust,
First Source Loan Obligations Trust, in exchange for cash proceeds of $570
million. In addition, Dominion holds a $76 million investment in the
subordinated debt of the CLO. First Source will manage the financial assets of
the CLO.
Dominion closed on another CLO in the first quarter of 2001.
It included $461 million of the remaining First Source and First Dominion
Capital commercial loans. Dominion retained a $196 million investment in the
subordinated debt of the CLO.
Dominion's exit strategy for Dominion Lands, DCI's real estate development
and management business, is to minimize resources committed to the winding down
and exiting of these projects. In addition, Dominion is seeking offers that
would expedite its exit from these projects. In August 2000, Dominion realized
$8 million from the sale of its interests in certain real estate.
Dominion continues to evaluate exit strategies for Saxon.
Other
Restructuring and other acquisition-related costs also include amounts paid to
employees to retain their services during the post-merger transition period,
amounts payable under certain employee contracts and information technology
systems and operations integration costs. The information technology costs
include excess
48
<PAGE>
amortization expense attributable to shortening the useful lives of capitalized
software being impacted by systems integration.
Note 7 | Extraordinary Item and 1998 Rate Settlement
Extraordinary Item--Discontinuance of SFAS No. 71
In 1999, legislation was enacted that established a detailed plan to restructure
the electric utility industry in Virginia. The legislation's deregulation of
generation is an event that required discontinuation of SFAS No. 71 for
Dominion's utility generation operations in 1999. Dominion's electric
transmission and distribution operations con- tinue to meet the criteria for
recognition of regulatory assets and liabilities as defined by SFAS No. 71. In
addition, fuel continues to be subject to deferral accounting.
In order to measure the amount of regulatory assets to be written off upon
discontinuance of SFAS No. 71, Dominion evaluated the estimated recovery of
regulatory assets through capped rates during the transition period ending July
2007. Generation-related assets and liabilities that will not be recovered
through capped rates were written off in 1999, resulting in an after-tax charge
to earnings of $255 million. See Note 12 for discussion of regulatory assets at
December 31, 2000. The $255 million charge also included the write-off of
approximately $38 million, after-tax, of deferred investment tax credits and
approximately $18 million, after- tax, of other generation-related assets. A
corresponding regulatory asset of $23 million was established representing the
amount expected to be recovered during the transition period related to these
assets.
The events that caused the discontinuance of SFAS No . 71 for generation-
related assets and liabilities also required a review of generation assets for
impairment. This review was based on estimates of possible future market prices,
load growth, competition and many other assumptions and included the effects of
nuclear decommissioning and other currently identified environmental
expenditures. Based on those analyses, no plant write-downs were appropriate at
that time.
Dominion also reviewed its long-term power purchase contracts for potential
loss in accordance with SFAS No. 5, Accounting for Contingencies, and Accounting
Research Bulletin No. 43, Chapter 4, Inventory Pricing. Based on projections of
possible future market prices for wholesale electricity, the results of the
analyses indicated no loss recognition was appropriate at that time. Other pro-
jections of possible future market prices indicated a possible loss of $500
million. In the absence of capped rates as provided by the legislation, the
potential loss exposure would have been approximately $3.2 billion at March 31,
1999.
Significant estimates were required in recording the effect of the
deregulation legislation, including the resulting impact on the fair value
determination of generating facilities and estimated purchases under long-term
power purchase contracts. Such projections are highly dependent on future
customer load projections, generating unit availability, the timing and type of
future capacity additions in Dominion's market area and future market prices for
fuel and electricity.
Virginia Rate Settlement
Dominion's 1998 settlement of its outstanding Virginia jurisdictional electric
base rate proceedings defined a new regulatory framework for the Company's
transition to electric competition. The impact of the settlement provisions was
largely recognized in 1998 and 1999 and included: a $150 million base rate
reduction phased-in over 1998 and 1999; a $150 million one-time refund in 1998;
and the accrual of a $159 million impairment charge which, when coupled with
$65 million previously recorded in earlier years, provided for the write-off of
$220 million of regulatory assets.
Note 8 | Income Taxes
Income before provision for income taxes, classified by source of income, before
minority interests, was as follows:
<TABLE>
<CAPTION>
(millions) Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------------
<S> <C> <C> <C>
U.S. $552 $797 $420
Non-U.S 48 32 467
- ------------------------------------------------------------------------
Total $600 $829 $887
========================================================================
</TABLE>
The provision for income taxes, classified by the timing and location of
payment, was as follows:
<TABLE>
<CAPTION>
(millions) Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------------
<S> <C> <C> <C>
Current:
U.S. $255 $187 $153
State 20 18 25
Non-U.S 4 101
- ------------------------------------------------------------------------
Total current 275 209 279
- ------------------------------------------------------------------------
Deferred:
U.S. (111) 66 32
State 16 (3)
Non-U.S 22 (1) 21
- ------------------------------------------------------------------------
Total deferred (73) 65 50
- ------------------------------------------------------------------------
Amortization of deferred
investment tax credits--net (19) (15) (17)
- ------------------------------------------------------------------------
Total provision $183 $259 $312
========================================================================
</TABLE>
49
<PAGE>
Notes to Consolidated Financial Statements (continued)
The statutory U.S. federal income tax rate reconciles to the effective income
tax rates as follows:
<TABLE>
<CAPTION>
Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
U.S. statutory rate 35.0% 35.0% 35.0%
Utility plant differences 0.8 0.3 3.0
Preferred dividends 2.1 1.6 1.4
Amortization of investment
tax credits (2.3) (1.8) (1.9)
Nonconventional fuel credit (7.1) (4.4) (2.8)
Other -- benefits and taxes related
to foreign operations (2.7) (0.2) (0.1)
State taxes, net of federal benefit 4.3 1.5 1.5
Goodwill amortization 4.4
Employee pension and other benefits (1.4)
Other, net (2.6) (0.8) (0.9)
- ------------------------------------------------------------------------------------------------------
Effective tax rate 30.5% 31.2% 35.2%
======================================================================================================
</TABLE>
The tax benefit associated with dispositions of employee stock plans reduced
taxes currently payable for 2000.
In 1998, the United Kingdom reduced its corporate income tax rate,
effective April 1, 1999, by one percent to 30 percent.
Accordingly, deferred tax liabilities and 1998 income tax expense were reduced
by $8.3 million.
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amount of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes.
Dominion's net deferred tax liability is attributable to:
<TABLE>
<CAPTION>
(millions) At December 31, 2000 1999
- -----------------------------------------------------------------------
<S> <C> <C>
Assets:
Deferred investment tax credits $ 55 $ 52
Other 4
- -----------------------------------------------------------------------
Total deferred income tax asset 59 52
- -----------------------------------------------------------------------
Liabilities:
Depreciation method and plant
basis differences 1,994 1,493
Income taxes recoverable
through future rates 20 20
Partnership basis differences 141 159
Postretirement and pension benefits 481 (6)
Intangible drilling costs 269 44
Other (26) 52
- -----------------------------------------------------------------------
Total deferred income tax liability 2,879 1,762
- -----------------------------------------------------------------------
Net deferred income tax liability $ 2,820 $ 1,710
=======================================================================
</TABLE>
Note 9 Transfers and Servicing of Financial Assets
During 2000 Dominion sold commercial loans in a securitization transaction. In
that securitization, Dominion retained servicing responsibilities and
subordinated interests. Dominion receives annual servicing fees approximating 38
basis points of the outstanding balance and rights to future cash flows
arising after the investors in the securitization trust have received the return
for which they contracted. The investors and the securitization trusts have no
recourse to Dominion's other assets for failure of debtors to pay when due.
Dominion's retained interests are subordinate to investors' interests. Their
value is subject to credit and general economic risks on the transferred
financial assets. All of the loans in the securitization are variable rate
loans, consequentially changes in interest rates will not cause a material
change in the performance of the portfolio of loans.
Dominion also securitizes receivables of residential mortgage loans.
When Dominion sells receivables in securitizations of residential
mortgage loans, it retains interest-only strips, one or more subordinated
tranches, servicing rights and future rights to prepayment penalties, all of
which are retained interests in the securitized receivables. Gain on sale of the
receivables depends in part on the previous carrying amount of the financial
assets involved in the transfer. Dominion generally estimates fair value based
on the present value of future expected cash flows using management's best
estimates of the key assumptions--credit losses, prepayment speeds, forward
yield curves and discount rates commensurate with the risks involved.
During 2000 and 1999, Dominion sold residential mortgage loans through
securitization transactions. In each of those securitizations, Dominion retained
servicing responsibilities and subordinated interests. Dominion receives annual
servicing fees approximating 50 basis points of the outstanding balance and
rights to future cash flows arising after the investors in the securitization
trust have received the return for which they contracted . In addition, Dominion
receives future cash flows from prepayment penalties on mortgage loans that
prepay during the contractual penalty period. The investors and the
securitization trusts have no recourse to Dominion's other assets for failure of
debtors to pay when due. Dominion's retained interests are sub-ordinate to the
investors' interests. The retained interests' value is subject to credit,
prepayment and interest rate risks on the transferred financial assets.
In 2000 and 1999, Dominion recognized pretax gains of $85 million and $107
million, respectively, on the securitization of residential mortgage loans.
50
<PAGE>
The weighted-average rates (per annum) for key economic assumptions used in
measuring the retained interests from securitizations completed during 2000 were
as follows:
<TABLE>
<CAPTION>
Residential
Mortgage Loans Servicing Rights
<S> <C> <C>
- --------------------------------------------------------------------------------------------------------
Prepayment speed * *
Weighted-average life (in years) 6.05/2.44 3.63
Expected credit losses 2.26% 2.26%
Residual cash flows discounted at 15.07% 14.09%
=======================================================================================================
</TABLE>
* Fixed rate loans ramp up to 24 Constant Prepayment Rate (CPR) over 13 months
and thereafter.
Adjustable rate loans ramp up to 40 CPR over 13 months; ramping down to 24
CPR over 32 months and thereafter.
Two-year hybrid loans ramp up to 29 CPR over 13 months; ramping up to 57 CPR
in month 21 ramping down to 29 CPR over 18 months and thereafter.
Three-year hybrid loans ramp up to 29 CPR over 13 months; ramping up to 57
CPR in month 34 ramping down to 29 CPR over 18 months and thereafter.
As a result of changes in the market conditions during the first half of
2000, the discount rate used to value interest-only residual assets was
increased from 12% to 17%, and a loss of $106 million was recognized. In
addition, due to the events described in Note 6, these assets were transferred
from available-for-sale to trading. Accordingly, these assets are recorded at
fair value.
Activity for the interest-only residual assets and servicing rights is
summarized as follows:
<TABLE>
<CAPTION>
(millions) Residual Assets* Servicing Rights Total
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at January 1, 1998 $ 213 $ 18 $ 231
Retained from securitization 157 24 181
Amortization (3) (7) (10)
Cash received (57) (57)
Fair value adjustment (28) (28)
- -------------------------------------------------------------------------------------------
Balance at December 31, 1998 282 35 317
Retained from securitization 169 16 185
Amortization (7) (12) (19)
Cash received (79) (79)
Fair value adjustment (18) (18)
- -------------------------------------------------------------------------------------------
Balance at December 31, 1999 347 39 386
Retained from securitization 99 18 117
Amortization (16) (7) (23)
Cash received (51) (51)
Gain on trading securities 25 25
Fair value adjustment (102) (5) (107)
- -------------------------------------------------------------------------------------------
Balance at December 31, 2000 $ 302 $ 45 $ 347
===========================================================================================
</TABLE>
*Includes prepayment penalties
At December 31, 2000, key economic assumptions and the sensitivity of the
current fair value of residual cash flows to immediate 10 percent and 20 percent
adverse changes in those assumptions are as follows:
<TABLE>
<CAPTION>
Residential
(millions, except percentages) Mortgage Loans Servicing Rights
- ---------------------------------------------------------------------------------------------
<S> <C> <C>
Carrying amount/fair value of retained interests $ 301 $ 46
Weighted-average life (in years) 5.23/1.74 3.64
- ---------------------------------------------------------------------------------------------
Prepayment speed assumption (annual rate) /(1)/ /(1)/
Impact on fair value of 10% adverse change $ (20) $ (4)
Impact on fair value of 20% adverse change $ (37) $ (6)
- ---------------------------------------------------------------------------------------------
Expected credit losses (annual rate) 2.28% 2.28%
Impact on fair value of 10% adverse change $ (10) N/A
Impact on fair value of 20% adverse change $ (20) N/A
- ---------------------------------------------------------------------------------------------
Residual cash flows discount rate (annual) 17% 15%
Impact on fair value of 10% adverse change $ (9) $ (1)
Impact on fair value of 20% adverse change $ (20) $ (3)
- ---------------------------------------------------------------------------------------------
Interest rates on variable and
adjustable contracts /(2)/ /(2)/
Impact on fair value of 10% adverse change $ (7) N/A
Impact on fair value of 20% adverse change $ (18) N/A
=============================================================================================
</TABLE>
(1) Fixed rate loans ramp up to 24 CPR over 13 months and thereafter for
series 96-1, 96-2, 97-1, 99-3, 99-4, 99-5 and 00-1; ramp up to 22 CPR
over 13 months and thereafter for series 98-1 and 99-2; ramp up to 27 CPR
over 13 months and thereafter for series 97-2 and 97-3. Adjustable rate
loans ramp up to 40 CPR over 13 months; ramping down to 24 CPR over
32 months and thereafter.
Two-year hybrid loans ramp up to 30 CPR over 13 months; ramping up to 60
CPR in month 21 ramping down to 30 CPR over 18 months and thereafter.
Three-year hybrid loans ramp up to 30 CPR over 13 months; ramping up to
60 CPR in month 33 ramping down to 30 CPR over 18 months and
thereafter.
(2) Based on the full forward 1-month LIBOR, 6-month LIBOR or 1 year CMT
through 1/1/2004 based on the variable component of the variable rate
contracts.
These sensitivities are hypothetical and should be used with caution. As
the figures indicate, changes in fair value based on a 10 percent variation in
assumptions generally cannot be extrapolated because the relationship of the
change in assumption to the change in fair value may not be linear. Also, in
this table, the effect of a variation in a particular assumption on the fair
value of the retained interest is calculated without changing any other
assumption; in reality, changes in one factor may result in changes in another
(for example, increases in market interest rates may result in lower prepayments
and increased credit losses), which might magnify or counteract the
sensitivities.
__
51
<PAGE>
Notes to Consolidated Financial Statements (continued)
Note 10 | Collateralized Debt Obligation Investments
Until September 20, 2000, Dominion managed financial assets held in three
collateralized debt obligations (CDO). That business was sold as part of
Dominion's strategy to divest its non-core operations. Dominion continues to
hold an investment in the subordinated debt of each CDO. The total investment
in the CDOs was $ 159 million and $58 million at December 31, 2000 and 1999,
respectively.
Note 11 | Investment Securities
Securities classified as available-for-sale as of December 31 follow:
<TABLE>
<CAPTION>
Gross Gross
Unrealized Unrealized Aggregate
(millions) Security Type Cost Gains Losses Fair Value
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
2000
Equity $ 132 $ 1 $ 15 $ 118
Debt 175 1 174
- ---------------------------------------------------------------------------------------------------
Total $ 307 $ 1 $ 16 $ 292
- ---------------------------------------------------------------------------------------------------
1999
Equity $ 134 $ 2 $ 10 $ 126
Debt 396 10 386
- ---------------------------------------------------------------------------------------------------
Total $ 530 $ 2 $ 20 $ 512
===================================================================================================
</TABLE>
Debt securities held at December 31, 2000 do not have stated contractual
maturities because borrowers have the right to call or repay obligations with or
without call or prepayment penalties.
For the years ended December 31, 2000 and 1999, the proceeds from the sales
of available-for-sale securities were $3 million and $35 million, respectively.
The gross realized gains were $1 million and $5 million for 2000 and 1999,
respectively. The gross realized loss for 1998 was $1 million. The basis on
which the cost of these securities was determined is specific identification.
The changes in net unrealized holding gains and losses on available-for-sale
securities have resulted in an increase of $7 million, net of tax, in
accumulated other comprehensive income during the year ended December 31, 2000.
During the twelve months ended December 31, 1999, the changes in net unrealized
holding gains and losses resulted in a decrease of $ 17 million, net of tax, in
accumulated other comprehensive income. The changes in net unrealized holding
gains and losses on trading securities increased earnings during the year 2000
by $6 million. Included in the $6 million increase was a $14 million loss
relating to the reclassification of certain available-for-sale securities to
the trading category. In 1999, the change in net unrealized holding gains and
losses on trading securities increased earnings by $1 million.
For a discussion of investment securities held in nuclear decommissioning
trusts, see Note 14.
Note 12 | Regulatory Assets and Liabilities
Regulatory assets and liabilities included the following:
<TABLE>
<CAPTION>
(millions) At December 31, 2000 1999
- -----------------------------------------------------------------------
<S> <C> <C>
Regulatory assets:
Other postretirement benefit costs $ 126
Income taxes recoverable through future rates 182 $ 57
Deferred fuel costs 98 63
Cost of decommissioning DOE uranium
enrichment facilities 49 55
Other 61 46
- -----------------------------------------------------------------------
516 221
- -----------------------------------------------------------------------
Unrecovered gas costs (See Note 2) 263
- -----------------------------------------------------------------------
Total $ 779 $ 221
- -----------------------------------------------------------------------
Regulatory liabilities:
Estimated rate contingencies and refunds $ 41
Income taxes refundable through future rates 18
- -----------------------------------------------------------------------
Total $ 59
=======================================================================
</TABLE>
The incurred costs underlying these regulatory assets and regulatory
liabilities may represent expenditures by Dominion's rate regulated electric
and gas operations or may represent the recognition of liabilities that
ultimately will be settled at some time in the future. See Note 7 for
information about the write-off of regulatory assets that resulted from 1999
deregulation legislation and the settlement of Dominion's 1998 Virginia rate
proceeding.
Other postretirement benefit costs consist of the difference between
recognized costs and the amounts included in rates charged by Dominion's local
gas distribution subsidiaries, pending the expected recovery through future
rates.
Unrecovered gas costs and deferred fuel costs represent the difference
between the actual cost of purchased gas or fuel used in electric generation and
amounts recovered for such costs through current rates.
Income taxes recoverable or refundable through future rates resulted from
the recognition of additional deferred income taxes, not previously recorded
because of past rate-making practices, as part of the implementation of SFAS No.
109.
The costs of decommissioning the Department of Energy's (DOE) uranium
enrichment facilities represents the unamortized portion of Dominion's required
contributions to a fund for decommissioning and decontaminating DOE's uranium
enrichment facilities. Dominion began making contributions in 1992 and will
continue over a 15-year period with escalation for inflation. These costs are
currently being recovered in fuel rates.
52
<PAGE>
Estimated rate contingencies and refunds are associated with certain
increases in prices by Dominion's rate regulated utilities and other rate-making
issues that are subject to final modification in regulatory proceedings.
Note 13 Gas Stored
At December 31, 2000, stored gas inventory used in local gas distribution
operations was valued at $41 million under the LIFO method. Based upon the
average price of gas purchased during 2000, the current cost of replacing the
inventory of "Gas stored-current portion" exceeded the amount stated on a LIFO
basis by approximately $283 million. At December 31, 2000, the stored gas
inventory of certain non-regulated gas operations of Dominion was valued at $34
million using the weighted average cost method.
A portion of gas in underground storage used as a pressure base and for
operational balancing is included in Property, plant and equipment in the amount
of $126 million at December 31, 2000.
Note 14 Property, Plant and Equipment
Major classes of property, plant and equipment and their respective balances
are:
(millions) At December 31, 2000 1999
- ------------------------------------------------------------------
Utility:
Production $ 8,103 $ 7,758
Transmission 3,085 1,517
Distribution 6,764 4,835
Storage 573
Plant under construction 562 677
Nuclear fuel 755 801
Other electric and gas 1,574 901
- ------------------------------------------------------------------
Total utility 21,416 16,489
- ------------------------------------------------------------------
Nonutility:
Exploration and production properties:
Proved 5,210 1,116
Unproved 550 69
Independent power properties 358 811
Other 477 218
- ------------------------------------------------------------------
Total nonutility 6,595 2,214
- ------------------------------------------------------------------
Total property, plant and equipment $28,011 $18,703
==================================================================
Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 2000, and the
years in which such excluded costs were incurred, follow:
(millions) Incurred in Year Ended December 31,
- -----------------------------------------------------------------------------
Total 2000 1999 1998
- -----------------------------------------------------------------------------
Property acquisition costs $ 112 $ 69 $ 25 $ 18
Exploration costs 46 46
Capitalized interest 2 2
- -----------------------------------------------------------------------------
Total $ 160 $ 117 $ 25 $ 18
=============================================================================
Amortization of capitalized costs under the full cost method of accounting for
Dominion's United States and Canadian cost centers were as follows:
(Per Mcf Equivalent)
Year ended December 31, 2000 1999 1998
- ----------------------------------------------------------------------------
United States cost center $1.13 $0.75 $0.82
Canadian cost center 0.92 0.80 0.97
============================================================================
When Dominion's nuclear units cease operations, it is obligated to decontaminate
or remove radioactive contaminants so that the property will not require Nuclear
Regulatory Commission (NRC) oversight. This phase of a nuclear power plant's
life cycle is termed decommissioning. While the units are operating, amounts are
currently being collected from ratepayers that, when combined with investment
earnings, will be used to fund this future obligation. These dollars are
deposited into external trusts through which the funds are invested.
The total estimated cost to decommission the four nuclear units is currently
estimated at $1.6 billion based on a site-specific study that was completed in
1998. The cost estimate assumes that the method of completing decommissioning
activities is prompt dismantlement. This method assumes that dismantlement and
other decommissioning activities will begin shortly after cessation of
operations, which under current operating unit licenses will begin in 2012,
2013, 2018 and 2020. The balance in the external trusts available for
decommissioning was $851 million at December 31, 2000. The Company intends to
file relicensing applications in 2001 to extend the life of each unit by 20
years.
53
<PAGE>
Notes to Consolidated Financial Statements (continued)
The amount being accrued for decommissioning is equal to the amount being
collected from ratepayers and is included in depreciation, depletion and
amortization expense. The decommissioning collections were $36 million per year
for the period 1998 through 2000. The expense provisions were $36 million, $36
million and $26 million in 2000, 1999 and 1998, respectively. Net earnings of
the trusts' investments are included in Other income. In 2000, 1999 and 1998,
net earnings were $20 million, $17 million and $18 million, respectively. The
accretion of the decommissioning obligation is equal to the trusts' net earnings
and is also recorded in Other income.
The accumulated provision for decommissioning, which is included in
Accumulated depreciation, depletion and amortization in the Consolidated Balance
Sheets, includes the accrued expense and accretion described above and any
a gains and losses on the trusts' investments. At December 31, 2000,
the net unrealized gains were $268 million, which is a decrease of $ 23 million
over the December 31, 1999 amount of $ 291 million. The accumulated provision
for decommissioning at December 31, 2000 was $851 million. It was $818 million
at December 31, 1999.
The NRC requires nuclear power plant owners to annually update minimum
financial assurance amounts for the future decommissioning of the nuclear
facilities. Dominion's 2000 NRC minimum financial assurance amount, aggregated
for the four nuclear units, was $1.0 billion. Financial assurance is provided by
a combination of surety bonds and the funds being collected and funded in the
external trusts.
FASB is reviewing the accounting for nuclear plant decommissioning. FASB
has tentatively determined that the estimated cost of decommissioning should be
reported as a liability rather than as accumulated depreciation and that a
substantial portion of the decommissioning obligation should be recognized
earlier in the operating life of the nuclear unit.
Dominion's proportionate share of jointly-owned utility plants at December
31, 2000 follows:
Bath
County North
Pumped Anna Clover
Storage Power Power
(millions, except percentages) Station Station Station
- ----------------------------------------------------------------------------
Ownership interest 60.0% 88.4% 50.0%
Plant in service $ 1,067 $ 1,875 $ 538
Accumulated depreciation 294 1,135 69
Nuclear fuel 350
Accumulated amortization of nuclear fuel 335
Construction work in progress 2 33 3
============================================================================
The co-owners are obligated to pay their share of all future construction
expenditures and operating costs of the jointly-owned facilities in the same
proportions as their respective ownership interest. Such operating costs are
classified in the appropriate expense category in the Consolidated Statements of
Income.
Note 15 | Short-Term Debt and Credit Agreements
Dominion and its subsidiaries have credit agreements with various expiration
dates and pay fees in lieu of compensating balances in connection with these
agreements. These agreements provided for maximum borrowings of $4.4 billion and
$5.1 billion at December 31, 2000 and 1999, respectively. At December 31, 2000
and 1999, $295 million and $2.3 billion, respectively, was borrowed under such
agreements.
Dominion and its subsidiaries' credit agreements also supported $2.7 billion and
$1.2 billion of commercial paper at December 31, 2000 and 1999, respectively. A
significant portion of the commercial paper is supported by credit agreements
that have expiration dates extending beyond one year. Therefore, a total of $250
million and $364 million of the commercial paper was classified as long-term in
2000 and 1999, respectively. These borrowings were used primarily to fund the
interim financing of the CNG acquisition and operational needs at Dominion and
its subsidiaries.
In June 2000, Dominion established a $1.75 billion credit facility that
supports its combined commercial paper programs. Subject to the maximum
aggregate limit of $1.75 billion, Virginia Power and CNG may borrow up to the
full commitment and Dominion may borrow up to $750 million.
A summary of the amounts that are classified as short-term debt at December
31 follows:
<TABLE>
<CAPTION>
(millions, except percentages) 2000 1999
- ------------------------------------------------------------------------------------------------------
Weighted Weighted
Amount Average Amount Average
Outstanding Interest Rate Outstanding Interest Rate
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Commercial paper $ 2,414 6.5% $ 813 5.3%
Term-notes 823 7.0% 57 9.7%
Total $ 3,237 $ 870
======================================================================================================
</TABLE>
54
<PAGE>
Note 16 | Long-Term Debt
<TABLE>
<CAPTION>
(millions) At December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
Balance Interest Rate/(6)/ Balance Interest Rate/(6)/
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First and Refunding Mortgage Bonds/(1/):
1992 Series E, due 2002 $ 155 7.4% $ 155 7.4%
1993 Various Series, 2001-2003 400 6.0-6.6 535 5.9-6.6
Various Series, 2004-2007 665 6.8-8.0 665 7.6-8.0
Various series, due 2021-2025 1,101 6.8-8.8 1,101 5.4-8.8
- -------------------------------------------------------------------------------------------------------------------------------
Total First and Refunding Mortgage Bonds 2,321 2,456
- -------------------------------------------------------------------------------------------------------------------------------
Other Long-Term Debt:
Notes:
Due 2004 400 7.3
Debentures:
Due 2003-2027 1,334 5.8-8.8
Senior notes:
2000 Series C, due 2003 400 7.6
2000 Series B, due 2005 700 7.6
2000 Various series, due 2010-2014 1,400 7.2-8.1
Mandatory Convertibles, convert 2004 413 8.1
Commercial paper/(2)/ 250 300
Term notes, fixed interest rate, due 2000-2008 581 5.7-10.0 422 5.7-10.0
Various series, due 2004-2038 375 6.7-7.2 375 6.7-7.1
Tax exempt financings/(3)/:
Money market municipals, due 2007-2027 489 3.3 489 3.3
Other, due 2022-2030 59 4.9-5.5 29 5.4
Variable rate debt, 2000-2007 54 5.8
Secured revolving lines of credit, variable rates, due 2002-2005 237 6.3-7.0 303 5.6-6.0
- -------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 6,638 1,972
- -------------------------------------------------------------------------------------------------------------------------------
Nonrecourse debt:
Bank loans, due 2004-2008/(4)/ 18 7.3 18 5.8
Revolving credit agreements, due 2001 129 6.3-7.0 363 5.7-6.7
Bank loans, due 2000-2024 39 4.5-6.6
Senior secured bonds, fixed rate, due 2020 259 7.3 265 7.3
Other 19 6.9 3 5.4
Senior notes/(5)/:
Fixed rate, due 2003 46 7.6 96 6.1-7.6
Term notes, fixed rate, due 2000-2012 959 6.5-9.0 159 6.5-12.1
Line of credit, variable rate, due 2000 76 6.9 48 6.2
Line of credit, fixed rate, due 2000-2001 3 6.3 44 6.2
Notes payable, due 2006 23 6.9 298 6.5
Commercial paper 64 5.6
Revolving credit agreements 1,492 5.9
- -------------------------------------------------------------------------------------------------------------------------------
Total nonrecourse debt 1,532 2,889
- -------------------------------------------------------------------------------------------------------------------------------
Total debt 10,491 7,317
- -------------------------------------------------------------------------------------------------------------------------------
Less amounts due within one year:
First and refunding mortgage bonds 100 135
Other long-term debt 141 60
Nonrecourse debt 95 161
- -------------------------------------------------------------------------------------------------------------------------------
Total amount due within one year 336 356
- -------------------------------------------------------------------------------------------------------------------------------
Less unamortized discount, net of premium 54 25
- -------------------------------------------------------------------------------------------------------------------------------
Total long-term debt $10,101 $6,936
===============================================================================================================================
</TABLE>
Notes:
/(1)/ Substantially all of Virginia Power's property is subject to the lien of
the mortgage, securing its First and Refunding Mortgage Bonds.
/(2)/ See Note 15.
/(3)/ Certain pollution control equipment at Virginia Power's generating
facilities has been pledged or conveyed to secure these financings.
/(4)/ Real estate at Dominion is pledged as collateral.
/(5)/ Certain common stock owned by DCI is pledged as collateral to secure the
loan.
/(6)/ Interest rates are rounded to the nearest one-tenth of one-percent and
consist of weighted average interest rates for variable rate debt.
55
<PAGE>
Notes to Consolidated Financial Statements (continued)
At December 31, 2000 and 1999, the Company had aggregate notional principal
amounts of interest rate swaps on outstanding debt of $1.5 billion and $600
million, respectively, maturing between March 2002 and October 2023. The impact
of the interest rate swaps on interest expense and on the Company's effective
borrowing rates in 2000, 1999 and 1998 was not significant.
Maturities (including sinking fund obligations) through 2005 are as follows
(in millions): 2001-$336; 2002-$1,658; 2003-$843; 2004-$1,314 and 2005-$858.
In January 2001, Dominion issued $1.0 billion of 2-year fixed rate 6%
notes. In addition, in February 2001, Dominion issued $50 million in aggregate
principal amount of Tax-Exempt Pollution Control Revenue Bonds due 2031.
Note 17 | Obligated Mandatorily Redeemable Preferred Securities of
| Subsidiary Trusts
In December 1997, Dominion established Dominion Resources Capital Trust I (DR
Capital Trust). DR Capital Trust sold 250,000 Capital Securities for $250
million, representing preferred beneficial interests and 97% beneficial
ownership in the assets held by DR Capital Trust. Dominion issued $258 million
of 7.83% Junior Subordinated Debentures (Debentures) in exchange for the $250
million realized from the sale of the Capital Securities and $8 million of
common securities of DR Capital Trust. The common securities represent the
remaining 3% beneficial ownership interest in the assets held by DR Capital
Trust. The Debentures constitute 100% of DR Capital Trust's assets.
In 1995, Virginia Power established Virginia Power Capital Trust I (VP
Capital Trust). VP Capital Trust sold 5 million preferred securities for $135
million, representing preferred beneficial interests and 97% beneficial
ownership in the assets held by VP Capital Trust. Virginia Power issued $139
million of its 1995 Series A, 8.05% Junior Subordinated Notes (the Notes) in
exchange for the $135 million realized from the sale of the preferred
securities and $4 million of common securities of VP Capital Trust. The
common securities represent the remaining 3% beneficial ownership interest in
the assets held by VP Capital Trust. The Notes constitute 100% of VP Capital
Trust's assets.
In January 2001, Dominion established Dominion Resources Capital Trust
II (DR Capital Trust II) and Dominion Resources Capital Trust III (DR Capital
Trust III). DR Capital Trust II sold 12 million Trust Preferred Securities for
$300 million, representing preferred beneficial interests and 97% beneficial
ownership in the assets held by DR Capital Trust II. Dominion issued
approximately $309 million of 8.4% Junior Subordinated Debentures due 2041 in
exchange for the $300 million realized from the sale of the preferred securities
and approximately $9 million of common securities of DR Capital Trust II. The
Debentures constitute 100% of DR Capital Trust II's assets. DR Capital Trust III
sold 250,000 Capital Securities for approximately $247 million, representing
preferred beneficial interests and 97% beneficial ownership in the assets held
by DR Capital Trust III. Dominion issued approximately $258 million of 8.4%
Junior Subordinated Debentures due 2031 in exchange for the $247 million
realized from the sale of the capital securities and approximately $8 million
of common securities of DR Capital Trust III. The common securities represent
the remaining 3% beneficial ownership in the assets held by DR Capital Trust
III. The Debentures constitute 100% of DR Capital Trust III's assets.
Note 18 | Preferred Stock
Dominion is authorized to issue up to 20 million shares of preferred stock;
however, no such shares are issued and outstanding.
Virginia Power is authorized to issue 10 million shares of preferred
stock, $100 liquidation preference. Upon involuntary liquidation, dissolution
or winding-up of Virginia Power, each share is entitled to receive $100 per
share plus accrued dividends. Dividends are cumulative. During 2000, the
following series of preferred stock subject to mandatory redemption matured:
. 400,000 shares of the $5.58 Series of Preferred Stock matured on March 1,
2000; and
. 1,400,000 shares of the $6.35 Series of Preferred Stock matured on
September 1, 2000.
There were no redemptions of preferred stock in 1999.
At December 31, 2000, preferred stock not subject to mandatory redemption,
$100 liquidation preference, included:
Issued and Entitled Per
Outstanding Share Upon
Dividend Shares Redemption
- -----------------------------------------------------------------------
$5.00 106,677 $ 112.50
4.04 12,926 102.27
4.20 14,797 102.50
4.12 32,534 103.73
4.80 73,206 101.00
7.05 500,000 105.00/(1)/
6.98 600,000 105.00/(2)/
MMP 1/87/(3)/ 500,000 100.00
MMP 6/87/(3)/ 750,000 100.00
MMP 10/88/(3)/ 750,000 100.00
MMP 6/89/(3)/ 750,000 100.00
MMP 9/92 Series A/(3)/ 500,000 100.00
MMP 9/92 Series B/(3)/ 500,000 100.00
- -----------------------------------------------------------------------
Total 5,090,140
=======================================================================
Notes:
/(1)/ Through 7/31/03 and thereafter to amounts declining in steps to $100.00
after 7/31/13.
/(2)/ Through 8/31/03 and thereafter to amounts declining in steps to $100.00
after 8/31/13.
/(3)/ Money Market Preferred (MMP) dividend rates are variable and are set every
49 days via an auction. The weighted average rates for these series in
2000, 1999, and 1998, including fees for broker/dealer agreements, were
5.71%, 4.82%, and 4.49%, respectively.
Note 19 | Common Stock
On July 20, 1998, Dominion's Board of Directors authorized the repurchase of
up to $650 million of Dominion common stock outstanding. As of December 31,
1999, Dominion had repurchased approximately 11 million shares valued at
approximately $471 million.
In addition, Dominion repurchased approximately 3.2 million shares of stock
in 2000 through the implementation of a total return
56
<PAGE>
swap facility. These shares were repurchased at a cost of approximately $145
million. For additional information on the total return swap, see Note 24.
Immediately before the CNG acquisition, Dominion concluded a first step
transaction in which 33 million shares of Dominion common stock were exchanged
for approximately $1.4 billion.
Basic earnings per common share are calculated by dividing net income by
the average number of common shares outstanding during the year. Diluted
earnings per share are computed similar to basic earnings per share except that
the weighted average shares outstanding are increased to include additional
shares from the assumed exercise of stock options, if dilutive. The number of
additional shares is calculated by assuming that outstanding stock options were
exercised and that the proceeds from such exercises were used to acquire shares
of common stock at the average market price during the reporting period. In
1999, diluted earnings per share includes an adjustment to reflect the cost
incurred under a total return equity swap associated with Dominion's repurchase
of common stock. A reconciliation of income before extraordinary item and
cumulative effect of a change in accounting principle and basic to diluted share
amounts follows:
<TABLE>
<CAPTION>
2000 EPS 1999 EPS 1998 EPS
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Numerator:
Income before extraordinary item and cumulative effect
of a change in accounting principle-- basic $ 415 $ 552 $ 548
Income effect of total return equity swap, net of taxes (12)
- ---------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and cumulative effect
of a change in accounting principle-- dilutive $ 415 $ 540 $ 548
- ---------------------------------------------------------------------------------------------------------------------------------
Denominator:
Weighted average shares-- basic 235.2 $ 1.76 191.4 $ 2.88 194.9 $ 2.81
Effect of dilutive securities-- stock options .7 (0.07)
- ---------------------------------------------------------------------------------------------------------------------------------
Weighted average shares-- dilutive 235.9 $ 1.76 191.4 $ 2.81 194.9 $ 2.81
=================================================================================================================================
</TABLE>
Note 20 | Stock Compensation Plans
The Dominion Resources Incentive Compensation Plan (Incentive Plan) provides for
the granting of stock options, restricted stock and performance shares to
employees of Dominion and its affiliates. The aggregate number of shares of
common stock that may be issued under the Incentive Plan is 30 million. The
Dominion Resources Leadership Stock Option Plan (Leadership Stock Option Plan),
adopted by the Board of Directors in 2000, provides for the granting of non-
statutory stock options to salaried employees of Dominion. The aggregate number
of common shares that may be issued under the Leadership Stock Option Plan is 10
million.
The changes in restricted share incentives and option awards under the combined
plans were as follows:
<TABLE>
<CAPTION>
Restricted Weighted Stock Weighted Options
Shares Average Price Options Average Price Exercisable
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1997 105,264 $ 38.88 4,826 $ 29.38 4,826
- -------------------------------------------------------------------------------------------------------------------------------
Awards granted-- 1998 75,866 $ 39.78
Exercised/distributed/forfeited (83,162) $ 38.37 (2,700) $ 29.29
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 97,968 $ 40.02 2,126 $ 29.49 2,126
- -------------------------------------------------------------------------------------------------------------------------------
Awards granted-- 1999 24,758 $ 43.51 7,146,383 $ 41.38
Exercised/distributed/forfeited (94,113) $ 40.71 (1,113) $ 29.37
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 28,613 $ 42.29 7,147,396 $ 41.37 7,147,396
- -------------------------------------------------------------------------------------------------------------------------------
Awards granted-- 2000 169,886 $ 41.88 5,388,822 $ 43.87
Exercised/distributed/forfeited (108,077) $ 42.25 (2,204,765) $ 40.07
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 90,422 $ 41.56 10,331,453 $ 41.77 6,966,695
===============================================================================================================================
</TABLE>
Under SFAS No. 123, Accounting for Stock Based Compensation, compensation cost
is measured at the grant date based on the fair value of the award and is
recognized over the service (or vesting) period. However, as permitted under
SFAS No. 123, the Company instead measures compensation cost in accordance with
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees, and related interpretations. Under this standard, compensation cost
is measured as the difference between the market price of the Company's common
stock and the exercise price of the option at the grant date. Accordingly, no
compensation expense has been recognized for the stock option grants.
Had compensation cost associated with the stock options been determined
under SFAS No. 123 based on the fair market value of the options at the grant
date, such cost, net of related income taxes, would have been approximately $6
million for the year ended December 31, 2000. Basic and diluted earnings per
share for the
57
<PAGE>
Notes to Consolidated Financial Statements (continued)
year would have decreased by $0.03, due to the issuance of the stock options. In
1999, had compensation costs associated with the stock options been determined
under SFAS No. 123, compensation cost, net of tax, would have been approximately
$20 million for the year ended December 31, 1999. Both basic and diluted
earnings per share for the year would have decreased by $0.10.
The fair value of the options was estimated on the date of grant using the
Black-Scholes option pricing model. The following assumptions were used:
expected dividend yield of 5.22 percent; expected volatility of 21.54 percent;
contractual life of 10 years; riskfree interest rate of 5.18 percent; and
expected lives of six years.
The weighted-average fair value of options granted during 2000 and 1999 was
$6.86 and $ 4.35, respectively.
In 2000, Dominion instituted a third-party loan program whereby Dominion
officers may borrow funds to increase their investment in the common stock of
Dominion. Under certain phases of this program, approximately 1.7 million
options were issued under the Incentive Plan, which were then immediately
exercised. Certain of the officers who met their target ownership level under
the loan program received bonus restricted shares equal to five percent of the
number of shares they purchased under the program. The number of bonus shares
totaled 101,666 in the aggregate. Dominion officers are responsible for the
payment of such loans.
Note 21 | Employee Benefit Plans
In 2000 and 1999, Dominion and its subsidiaries maintained qualified
noncontributory defined benefit retirement plans covering virtually all
employees of Dominion. The benefits of the retirement plans are based on years
of service, age, and the employee's compensation. Dominion's funding policy is
to contribute annually an amount that is in accordance with the provisions of
the Employment Retirement Income Security Act of 1974. For the year 1998, non-
U.S. activity refers to the pension plan of East Midlands, which was sold in
July 1998. The pension program also includes the payment of benefits to certain
retired executives under company-sponsored nonqualified employee benefit plans.
Certain of these nonqualified plans are funded through contributions to a
grantor trust.
Dominion and its subsidiaries provide retiree health care and life
insurance benefits with annual premiums based on several factors such as age,
retirement date, and years of service. From time to time in the past, Dominion
and its subsidiaries have changed benefits. Some of these changes have reduced
benefits. Under the terms of their benefit plans, the companies reserve the
right to change, modify or terminate the plans.
On January 28, 2000, Dominion offered an early retirement program (ERP).
The ERP provided up to three additional years of age and three additional years
of employee service for benefit formula purposes, subject to age and service
maximums under the companies' postretirement medical and pension plans. Certain
employees who satisfied certain minimum age and years of service requirements
were eligible under the ERP. The effect of the ERP on the Company's pension plan
and post retirement benefit expenses was $81 million and $33 million,
respectively. These expenses were offset, in part, by curtailment gains of
approximately $20 million and $6 million from pension plans and other
postretirement benefit plans, respectively, attributable to reductions in
expected future years of service as a result of ERP participation and
involuntary employee terminations.
In addition, effective January 1, 2000, Dominion adopted a change in the
method of calculating the market-related value of pension plan assets. The
change is reported as a change in accounting principle. See Note 3.
The components of the provision for net periodic benefit cost were as follows:
<TABLE>
<CAPTION>
(millions) Pension Benefits Other Benefits
- -------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000 1999 1998 1998 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
U.S. U.S. U.S. Non-U.S.
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Service cost $ 65 $ 40 $ 32 $ 10 $ 30 $ 17 $ 12
Interest cost 161 76 71 44 52 28 24
Expected return on plan assets (298) (93) (80) (49) (31) (20) (16)
Recognized gain 6
Amortization of prior service cost 3
Amortization of transition obligation (4) 13 12 12
Curtailment gains (20) (6)
ERP benefit costs 81 33
Net amortization and deferral (1) (2) (1)
- -------------------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost $ (6) $ 23 $ 22 $ 5 $ 89 $ 37 $ 31
===============================================================================================================================
</TABLE>
58
<PAGE>
<TABLE>
<CAPTION>
(millions) Pension Benefits Other Benefits
- -----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000 1999 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Change in plan assets:
Fair value of plan assets at beginning of year $1,305 $1,094 $ 272 $ 212
Acquisition of CNG 2,332 128
Actual return on plan assets 64 232 3 45
Contributions 34 22 45 16
Benefits paid from plan assets (141) (43) (20) (1)
Sale of VNG (37) (11)
- -----------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 3,557 1,305 417 272
- -----------------------------------------------------------------------------------------------------------------------------------
Expected benefit obligation at beginning of year 1,097 1,126 401 377
Acquisition of CNG 1,002 297
Actuarial (gain) loss during prior period (13) 26
- -----------------------------------------------------------------------------------------------------------------------------------
Actual benefit obligation at beginning of year 2,099 1,113 698 403
Extraordinary accounting charge 10
Service cost 65 40 30 17
Interest cost 161 76 52 28
Benefits paid (141) (43) (43) (18)
Actuarial (gain) loss during the year 112 (89) 82 (29)
ERP benefit costs 81 33
Sale of VNG (45) (20)
Change in APBO due to curtailment (20) (6)
Plan amendments (18) (27)
- -----------------------------------------------------------------------------------------------------------------------------------
Expected benefit obligation at end of year 2,304 1,097 799 401
- -----------------------------------------------------------------------------------------------------------------------------------
Funded status 1,253 208 (382) (129)
Unrecognized net actuarial (gain) loss 177 (177) 13 (45)
Unamortized prior service cost (1) 3 (7)
Unrecognized net transition (asset) obligation (9) (12) 125 158
- -----------------------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit costs $1,420 $ 22 $(251) $ (16)
- -----------------------------------------------------------------------------------------------------------------------------------
Amounts recognized in the Consolidated Balance Sheets at December 31 consist
of the following:
Prepaid benefit costs $1,455 $ 22
Accrued benefit costs (77) $(251) $ (16)
Intangible asset 14
Accumulated other comprehensive income 28
- -----------------------------------------------------------------------------------------------------------------------------------
Net amount recognized $1,420 $ 22 $(251) $ (16)
===================================================================================================================================
</TABLE>
The Company has nonqualified pension plans which are reflected in the table
above. The projected benefit obligation for these plans was $93 million at
December 31, 2000. In addition, Dominion had recognized a minimum liability
associated with these plans of $42 million at December 31, 2000.
Significant assumptions used in determining net periodic pension cost, the
projected benefit obligation, and postretirement benefit obligations were:
Pension Benefits Other Benefits
- -----------------------------------------------------------------------------
2000 1999 2000 1999
- -----------------------------------------------------------------------------
Discount rates 7.50% 7.50% 7.50% 7.50%
Expected return on plan assets 9.50% 9.50% 6.50% 9.00%
Rate of increase for compensation 5.00% 5.00% 5.00% 5.00%
Medical cost trend rate 9.00% 4.75%
Decreasing to
4.75% in 2005
and years
thereafter
================================================================================
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A one-percentage-point change in assumed
health care cost trend rates would have the following effects:
Other Postretirement Benefits
1-Percentage 1-Percentage
(millions) Point Increase Point Decrease
- ------------------------------------------------------------------------------
Effect on total of service and interest
cost components for 2000 $10 $ (8)
Effect on postretirement benefit
obligation at 12/31/00 $86 $(71)
==============================================================================
59
<PAGE>
Notes to Consolidated Financial Statements (continued)
In addition, Dominion sponsors defined contribution thrift-type savings plans.
During 2000, 1999 and 1998, Dominion's recognized $30 million, $29 million and
$28 million, respectively, as contributions to these plans.
The funds collected for other postretirement benefits in regulated utility
rates, in excess of other postretirement benefits actually paid during the year,
are contributed to external benefit trusts.
Note 22 | Commitments and Contingencies
As the result of issues generated in the course of daily business, Dominion and
its subsidiaries are involved in legal, tax and regulatory proceedings before
various courts, regulatory commissions and governmental agencies, some of which
involve substantial amounts of money. Management believes that the final
disposition of these proceedings will not have an adverse material effect on its
operations or the financial position, liquidity or results of operations.
Utility Rate Regulation
The acquisition of CNG has expanded the Company's exposure to utility rate
regulation. Dominion's retail gas distribution companies are subject to price
regulation in the states of Ohio, Pennsylvania and West Virginia. In addition,
Dominion's gas transmission business is subject to rate regulation.
Dominion currently faces competition as a result of utility industry
deregulation. Under Virginia's electric utility industry deregulation
legislation, the Company's base rates will remain unchanged until July 2007 and
recovery of certain generation-related costs will be provided through these
capped rates. The Company remains exposed to numerous risks, including, among
others, exposure to potentially stranded costs, future environmental compliance
requirements, changes in tax laws, inflation and increased capital costs. At
December 31, 2000, Dominion's exposure to potentially stranded costs was
comprised of the following:
. long-term purchased power contracts that could ultimately be determined to
be above market--See Purchased Power Contracts below;
. generating plants that could possibly become uneconomic in a deregulated
environment; and
. unfunded obligations for nuclear plant decommissioning and postretirement
benefits not yet recognized in the financial statements--See Notes 14 and
21.
Purchased Power Contracts
Dominion has contracts for the long-term purchase of capacity and energy from
other utilities, qualifying facilities and independent power producers. Dominion
has 54 power purchase contracts with a combined dependable summer capacity of
3,973 megawatts.
The following table reflects the Company's minimum commitments as of
December 31, 2000, for power purchases from utility and nonutility suppliers.
(millions) Commitment
- --------------------------------------------------------------------------------
Year Capacity Other
- --------------------------------------------------------------------------------
2001 $ 727 $ 43
2002 724 43
2003 674 31
2004 672 29
2005 665 25
Later years 6,683 169
- --------------------------------------------------------------------------------
Total $ 10,145 $ 340
- --------------------------------------------------------------------------------
Present value of the total $ 5,580 $ 193
================================================================================
In addition to the minimum purchase commitments in the table above, under some
of these contracts Dominion may purchase, at its option, additional power as
needed. Purchased power expenditures, subject to cost of service rate
regulation, (including economy, emergency, limited term, short-term and long-
term purchases) for the years 2000, 1999 and 1998 were $1.1 billion, $1.2
billion and $1.1 billion, respectively.
See Note 7 for an evaluation of Dominion's potential exposure under its
long-term purchased power commitments.
Fuel Purchase Commitments
Estimated fuel purchase commitments for the next five years for system
generation are as follows: 2001--$379 million; 2002--$193 million; 2003--$166
million; 2004--$153 million; and 2005--$133 million.
Leases
Future minimum lease payments under the Company's noncancellable capital leases
and operating leases that have initial or remaining lease terms in excess of one
year as of December 31, 2000 are: 2001-$115 million; 2002-$58 million; 2003-$51
million; 2004-$40 million; 2005-$29 million; and years after 2005-$92 million.
Rental expense included in other operation and maintenance expense was $107
million, $31 million and $27 million for 2000, 1999 and 1998, respectively.
Sales of Power
Subsidiaries of Dominion enter into agreements with other utilities and with
other parties to purchase and sell electric capacity and energy. These
agreements may cover current and future periods. The volume of these
transactions varies from day to day, based on the market conditions, Dominion's
current and anticipated load, and other factors. The combined amounts of sales
and purchases range from 3,000 megawatts to 15,000 megawatts at various times
during a given year. These operations are closely monitored from a risk-
management perspective.
Environmental Matters
Dominion is subject to rising costs resulting from a steadily increasing number
of federal, state and local laws and regulations designed to protect human
health and the environment. These laws and regulations affect future planning
and existing operations. These laws and regulations can result in increased
capital,
60
<PAGE>
operating and other costs as a result of compliance, remediation, containment
and monitoring obligations of Dominion.
Dominion currently recovers environmental-related costs from electric
service customers through regulated utility rates. However, to the extent
environmental costs are incurred during the period ending June 30, 2007, in
excess of the level currently included in Virginia jurisdictional rates,
Dominion's results of operations will decrease. After that date, Dominion may
seek recovery from customers through utility rates of only those environmental
costs related to transmission and distribution operations.
In 1987, the U.S. Environmental Protection Agency (EPA) identified Dominion
and several other entities as Potentially Responsible Parties (PRPs) at two
Superfund sites located in Kentucky and Pennsylvania. Current cost studies
estimate total remediation costs for the sites to range from $98 million to $156
million. Dominion's proportionate share of the total cost is expected to be in
the range of $2 million to $3 million, based upon allocation formulas and the
volume of waste shipped to the sites. Dominion has accrued a reserve of $2
million to meet its obligations at these two sites. Based on a financial
assessment of PRPs involved at these sites, Dominion has determined that it is
probable that the PRPs will fully pay the costs apportioned to them. Dominion
generally seeks to recover its costs associated with environmental remediaton
from third-party insurers. Any pending or possible claims were not recognized as
an asset or offset against such obligations.
In 1999, Dominion was notified by the Department of Justice of alleged
noncompliance with EPA's oil spill prevention, control and counter-measures
(SPCC) plans and facility response plan (FRP) requirements at one of Dominion's
power stations. If, in a legal proceeding, such instances of noncompliance are
deemed to have occurred, Dominion may be required to remedy any alleged
deficiencies and pay civil penalties. Settlement of this matter is currently in
negotiation and is not expected to have a material impact on Dominion's
financial condition or results of operations. Dominion identified matters at
certain other power stations that EPA might view as not in compliance with the
SPCC and FRP requirements. Dominion reported these matters to the EPA and in
December 1999 submitted revised FRP and SPCC plans. Presently, the EPA has not
assessed any penalties against Dominion, pending its review of Dominion's
disclosure information. Future resolution of these matters is not expected to
have a material impact on Dominion's financial condition or results of
operations.
During 2000, the Company received a Notice of Violation (NOV) from the EPA
alleging that Dominion is operating its Mt. Storm Power Station in West Virginia
in violation of the Clean Air Act. The NOV alleges that Dominion failed to
obtain New Source Review permits prior to undertaking specified construction
projects at the station. Violations of the Clean Air Act may result in the
imposition of substantial civil penalties and injunctive relief. Also in 2000,
the Attorney General of New York filed a suit against Dominion alleging similar
violations of the Clean Air Act at the Mt. Storm Power Station. Dominion has
also received notices from the Attorneys General of Connecticut and New Jersey
of their intentions to file suit against Dominion for similar violations.
Currently, Dominion has reached an agreement in principle with the federal
government and the state of New York about the resolution of various Clean Air
Act matters. The agreement in principle includes payment of a $5 million civil
penalty, a commitment of $14 million for major environmental projects in
Virginia, West Virginia, Connecticut, New Jersey and New York, and a 12-year,
$1.2 billion capital investment program for environmental improvements at
Dominion's coal-fired generating stations in Virginia and West Virginia.
Dominion has already committed to a substantial portion of the $1.2 billion
expeditures for SO2 and NOX emissions controls in response to other Clean Air
Act requirements. Although Dominion and EPA have reached an agreement in
principle, the terms of a final binding settlement are still being negotiated.
As of December 31, 2000, Dominion has recorded, on a discounted basis, $17
million for the civil penalty and environmental projects.
In 1990, Dominion Transmission entered into a Consent Order and Agreement
with the Commonwealth of Pennsylvania Department of Environmental Protection
(DEP) in which Dominion Transmission has agreed with the DEP's determination of
certain violations of the Pennsylvania Solid Waste Management Act, the
Pennsylvania Clean Streams Law and the rules and regulations promulgated
thereunder. No civil penalties have been assessed. Pursuant to the Order and
Agreement, Dominion Transmission continues to perform sampling, testing and
analysis, and conducts remediation at some of its affected Pennsylvania
facilities. Total remediation costs in connection with these sites and the Order
and Agreement are not expected to be material with respect to the Company's
financial position, results of operations or cash flows.
The Company has recognized an estimated liability amounting to $6 million
at December 31, 2000, for future costs expected to be incurred to remediate or
mitigate hazardous substances at these sites and at facilities covered by the
Order and Agreement.
Nuclear Insurance
The Price-Anderson Act limits the public liability of an owner of a nuclear
power plant to $9.5 billion for a single nuclear incident. The Price-Anderson
Act Amendment of 1988 allows for an inflationary provision adjustment every five
years. Dominion has purchased $200 million of coverage from the commercial
insurance pools, with the remainder provided through a mandatory industry risk
sharing program. In the event of a nuclear incident at any licensed nuclear
reactor in the United States, Dominion could be assessed up to $88 million for
each of its four licensed reactors not to exceed $10 million per year per
reactor. There is no limit to the number of incidents for which this
retrospective premium can be assessed.
Dominion's current level of property insurance coverage ($2.55 billion for
North Anna and $2.55 billion for Surry) exceeds the NRC's minimum requirement
for nuclear power plant licensees of $1.06 billion per reactor site and includes
coverage for premature decommissioning and functional total loss. The NRC
requires that the proceeds from this insurance be used first to return the
reactor to
61
<PAGE>
Notes to Consolidated Financial Statements (continued)
and maintain it in a safe and stable condition, then to decontaminate the
reactor and station site in accordance with a plan approved by the NRC.
Dominion's nuclear property insurance is provided by Nuclear Electric Insurance
Limited (NEIL), a mutual insurance company, and is subject to retrospective
premium assessments in any policy year in which losses exceed the funds
available to the insurance company. The maximum assessment for the current
policy period is $21 million. Based on the severity of the incident, the board
of directors of Dominion's nuclear insurer has the discretion to lower or
eliminate the maximum retrospective premium assessment. For any losses that
exceed the limits or for which insurance proceeds are not available because they
must first be used for stabilization and decontamination, Dominion has the
financial responsibility for these losses.
Dominion purchases insurance from NEIL to cover the cost of replacement
power during the prolonged outage of a nuclear unit due to direct physical
damage of the unit. Under this program, Dominion is subject to a retrospective
premium assessment for any policy year in which losses exceed funds available to
NEIL. The current policy period's maximum assessment is $7 million.
As part owner of the North Anna Power Station, Old Dominion Electric
Cooperative is responsible for its share of the nuclear decommissioning
obligation and insurance premiums applicable to that station, including any
retrospective premium assessments and any losses not covered by insurance.
Guarantees
Dominion has issued guarantees to various third parties in relation to the
payment obligations by certain of its subsidiaries and officers. At December 31,
2000, Dominion had issued $1.8 billion of guarantees, and the subsidiaries'
debt subject to such guarantees totaled $1.2 billion.
DEI
Subsidiaries of DEI have general partnership interests in certain of its energy
ventures. These subsidiaries may be required to fund future operations of these
investments, if operating cash flow is insufficient.
DCI
At December 31, 2000, DCI had commitments to fund loans of approximately $230
million.
Note 23 | Fair Value of Financial Instruments
The fair value amounts of Dominion's financial instruments have been determined
using available market information and valuation methodologies deemed
appropriate in the opinion of management. However, considerable judgment is
required to interpret market data to develop the estimates of fair value.
Accordingly, the estimates presented herein are not necessarily indicative of
the amounts that could be realized in a current market exchange. The use of
different market estimation assumptions may have a material effect on the
estimated fair value amounts.
(millions) At December 31, Carrying Amount Estimated Fair Value
- -------------------------------------------------------------------------------
2000 1999 2000 1999
- -------------------------------------------------------------------------------
Assets:
Cash and cash equivalents/(1)/ $ 360 $ 280 $ 360 $ 280
Investment securities, trading/(2)/ 275 2 275 2
Mortgage loans held for sale/(3)/ 104 119 104 119
Commodity-based swaps,
trading/(4)/ 281 25 281 25
Commodity-based options,
trading/(4)/ 29 6 29 6
Available-for-sale securities/(2)/ 292 512 292 512
Loans and notes receivable
and finance receivables
held for sale/(5)/ 676 2,131 676 2,131
Nuclear decommissioning
trust funds/(2)/ 851 818 851 818
- -------------------------------------------------------------------------------
Liabilities:
Short-term debt/(6)/ 3,237 870 3,237 870
Commodity-based swaps,
trading/(4)/ 325 24 325 24
Commodity-based options,
trading/(4)/ 56 6 56 6
Long-term debt/(6)/ 10,491 7,317 10,555 7,185
Preferred securities of
subsidiary trusts/(7)/ 385 385 383 359
Preferred stock/(8)/ 180 181
Loan commitments/(9)/ 230 937
- -------------------------------------------------------------------------------
Unrecognized financial
instruments:
Interest rate-swaps/(10)/ 17 (15)
Total return equity swap/(11)/ (19)
Swaps, collars and options,
hedging/(4)/ (277) 5
===============================================================================
Notes:
(1) The carrying amount of these items is a reasonable estimate of their fair
value.
(2) The estimated fair value is based on quoted market prices, dealer quotes,
and prices obtained from independent pricing sources.
(3) The fair value is based on outstanding commitments from investors.
(4) Fair value reflects the Company's best estimates considering over-the-
counter quotations, time value and volatility factors of the underlying
commitments.
(5) The carrying value approximates fair value due to the variable rate or term
structure.
(6) Market values are used to determine the fair value for debt securities for
which a market exists. For debt issues that are not quoted on an exchange,
interest rates currently available to the Company for issuance of debt with
similar terms and remaining maturities are used to estimate fair value. The
carrying amount of debt issues with short-term maturities and variable
rates refinanced at current market rates is a reasonable estimate of their
fair value.
(7) The fair value is based on market quotations.
(8) Preferred stock matured in 2000. See Note 18.
(9) The fair value of commitments is estimated using the fees currently charged
to enter into similar agreements, taking into account the remaining terms
of the agreements and the present credit-worthiness of the counterparties.
(10) The fair value is based upon the present value of all estimated net future
cash flows, taking into account current interest rates and the
creditworthiness of the swap counterparties.
(11) The fair value of the total return equity swap is estimated by obtaining
quotes from brokers.
62
<PAGE>
Note 24 | Derivative Transactions
Dominion uses derivative financial instruments for the purposes of managing
commodity price and interest rate risks.
Commodity-Based Instruments -- Non-Trading
Dominion manages the price risk associated with purchases and sales of natural
gas and oil by selecting derivative commodity instruments whose historical price
fluctuations correlate strongly with those of the transactions being hedged.
These commodity-based financial derivatives include swaps, options, and collars
which require settlement in cash. As these instruments qualify and have been
designated as hedges, any gains or losses resulting from market price changes
are expected to be generally offset by the related physical transaction.
At December 31, 2000, Dominion held swaps with notional quantities of
approximately 267 Bcf of natural gas maturing through 2001-2005 with an
aggregate unrealized gain of $158 million. Net notional quantities do not
represent the quantities exchanged by the parties and are not a measure of
Dominion's exposure through the use of swaps but are used in the determination
of cash settlements under the swap agreements.
At December 31, 2000, Dominion held options and collars covering
approximately 202 Bcf of natural gas and 11 million barrels of crude oil
maturing through 2001 with an aggregate unrealized loss of $435 million.
At December 31, 1999, Dominion held swaps, options and collars covering
approximately 42 Bcf of natural gas maturing through 2002 with an aggregate
unrealized gain of $5 million.
Commodity-based Instruments -- Trading
As part of Dominion's strategy to market energy from its generation capacity and
to manage related risks, the Company manages a portfolio of commodity contracts
held for trading purposes. These contracts are reported at fair value on the
Consolidated Balance Sheet. Commodity contract assets (including long-term)
totaled $1.1 billion and $367 million at December 31, 2000 and 1999,
respectively. Commodity contract liabilities (including long-term) totaled $1.1
billion and $354 million at December 31, 2000 and 1999, respectively. As
disclosed in Note 23, included in these amounts was a net commodity-based
derivative liability consisting of swaps and options totaling $71 million and a
net commodity-based derivative asset of $1 million at December 31, 2000 and
1999, respectively. Net gains and losses associated with Dominion's commodity
trading activities are reported net of related cost of sales in Operating
revenue and income -- other and totaled $95 million and $65 million for 2000
and 1999, respectively.
Interest Rate Contracts
Dominion enters into interest rate sensitive financial derivative instruments,
including swaps and futures, in order to manage exposure to the effects of
interest rate changes on outstanding debt and mortgage loans that the Company
has funded or has committed to fund, as well as residual interests retained.
Net notional quantities or amounts do not represent the quantities or amounts
exchanged by the parties, and are not a measure of Dominion's exposure through
the use of swaps and futures but are used in the determination of cash
settlements under the agreements.
At December 31, 2000, Dominion held swaps used to synthetically convert
approximately $450 million of variable-rate debt to fixed rates, and
approximately $1.0 billion of fixed-rate debt to variable-rate debt.
Also, at December 31, 2000, Dominion recorded its interest rate swaps and
futures held for trading purposes at fair value, a net liability of $13
million. These contracts had notional quantities of $5.0 billion and resulted
in net trading losses of $14 million for 2000.
At December 31, 1999, all interest rate swaps and futures were held for
purposes other than trading with notional quantities of $3.7 billion. The net
deferred hedging losses were not material.
Risk Management Policies
Dominion has operating procedures in place that are administered by experienced
management to help ensure that proper internal controls regarding the use of
derivatives are maintained. In addition, Dominion has established an
independent function to monitor compliance with the price risk management
policies of all subsidiaries. In addition, Dominion maintains credit policies
with respect to its counterparties that management believes minimize overall
credit risk. Such policies include the evaluation of a prospective
counterparty's financial condition, collateral requirements where deemed
necessary, and the use of standardized agreements which facilitate the netting
of cash flows associated with a single counterparty. Dominion also monitors the
financial condition of existing counterparties on an ongoing basis. Considering
the system of internal controls in place and credit reserve levels at December
31, 2000, management believes it unlikely that a material adverse effect on its
financial position, results of operations or cash flows would occur as a result
of counterparty nonperformance.
In addition to the financial derivatives disclosed above, Dominion held
futures and forwards that may be settled through the purchase or delivery of
commodities. As of December 31, 2000, these instruments were not considered
financial derivatives. However, effective January 1, 2001, Dominion adopted SFAS
No. 133 which changed the scope and method of accounting for derivatives. See
Note 4 for a discussion of impact of adoption of this standard.
Other Derivatives
In 1998, Dominion entered into total return swap agreements with swap
counterparties. The notional amount of the swaps is based on the purchase price
of the securities to be acquired by the swap counterparties. As a result of the
winding down of the financial services business, the total return swap
agreement was terminated in 2000. At December 31, 1999, the notional amount was
$249 million. The gains or losses from the sale, settlement or mark to market
of the total return swaps are recorded in Other revenue. Earnings due to swap
transactions were $2 million and $18 million in 2000 and
63
<PAGE>
Notes to Consolidated Financial Statements (continued)
1999, respectively. Total return swap transactions require additional funding of
or return of cash collateral resulting from decreases or increases in the fair
market value of the swap position. Total return swap cash collateral is included
in cash and cash equivalents. Such cash collateral was $59 million at December
31, 1999.
During the fourth quarter of 1999, Dominion entered into a total return
equity swap facility agreement (Agreement). The Agreement gave Dominion the
right to direct the counterparty to purchase shares of Dominion common stock
during the term of the Agreement. In addition, Dominion paid the counterparty a
carrying cost equal to a LIBOR-based rate on the counterparty's cost of
acquiring the shares from the date of such acquisitions until the date of
settlement. Due to Dominion's ability to issue shares to settle periodic price
fluctuations and fees under the Agreement, Dominion recorded all amounts
received and paid as equity. As of December 31, 1999, the counterparty had
acquired 3.2 million shares of Dominion common stock under this Agreement at an
aggregate cost that was approximately $19 million more than the fair market
value of the shares at December 31, 1999. On February 3, 2000, Dominion settled
all transactions under the Agreement and received the 3.2 million shares at a
cost of $145 million.
Note 25 | Gas and Oil Producing Activities
(unaudited)
Capitalized Costs
The aggregate amounts of costs capitalized for gas and oil producing activities,
and related aggregate amounts of accumulated depreciation and amortization,
follow:
<TABLE>
<CAPTION>
(millions) At December 31,
- ------------------------------------------------------------------------------------------
2000 1999
- ------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalized costs of:
Proved properties $5,210 $1,116
Unproved properties 550 69
- ------------------------------------------------------------------------------------------
5,760 1,185
- ------------------------------------------------------------------------------------------
Accumulated depreciation of:
Proved properties 2,959 245
Unproved properties 233 6
- ------------------------------------------------------------------------------------------
3,192 251
- ------------------------------------------------------------------------------------------
Net capitalized costs $2,568 $ 934
==========================================================================================
</TABLE>
Total Costs Incurred
The following costs were incurred in gas and oil producing activities during the
years 1998 through 2000:
<TABLE>
<CAPTION>
(millions)
- ------------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Total United States Canada Total United States Canada Total United States Canada
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Property acquisition costs:
Proved properties $1,475 $1,459 $ 16 $ 280 $ 121 $ 159 $ 165 $ 165
Unproved properties 125 125 33 3 30
- ------------------------------------------------------------------------------------------------------------------------------------
1,600 1,584 16 313 124 189 165 165
Exploration costs 159 115 44 4 2 2 20 $ 16 4
Development costs 261 236 25 85 34 51 28 25 3
- ------------------------------------------------------------------------------------------------------------------------------------
Total $2,020 $1,935 $ 85 $ 402 $ 160 $ 242 $ 213 $ 41 $ 172
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Results of Operations
The Company cautions that the following standardized disclosures required by the
FASB do not represent the results of operations based on its historical
financial statements. In addition to requiring different determinations of
revenue and costs, the disclosures exclude the impact of interest expense and
corporate overheads.
<TABLE>
<CAPTION>
(millions) Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Total United States Canada Total United States Canada Total United States Canada
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues (net of royalties)
from:
Sales to nonaffiliated
companies $ 861 $ 691 $ 170 $ 229 $ 142 $ 87 $ 141 $ 119 $ 22
Transfers to other
operations 93 93
- ------------------------------------------------------------------------------------------------------------------------------------
Total 954 784 170 229 142 87 141 119 22
- ------------------------------------------------------------------------------------------------------------------------------------
Less:
Production (lifting)
costs 158 133 25 77 47 30 43 37 6
Depreciation and
amortization 345 294 51 84 47 37 59 45 14
Income tax expense 134 93 41 (10) (19) 9 (10) (11) 1
- ------------------------------------------------------------------------------------------------------------------------------------
Results of operations $ 317 $ 264 $ 53 $ 78 $ 67 $ 11 $ 49 $ 48 $ 1
====================================================================================================================================
</TABLE>
64
<PAGE>
Company-Owned Reserves
<TABLE>
<CAPTION>
Estimated net quantities of proved gas and oil (including condensate) reserves
in the United States and Canada at December 31,
1998 through 2000, and changes in the reserves during those years, are shown in
the two schedules which follow.
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
(billion cubic feet) Total United States Canada Total United States Canada Total United States Canada
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped
reserves--Gas
At January 1 1,114 600 514 591 473 118 447 447
Changes in reserves:
Extensions, discoveries and
other additions 274 232 42 156 94 62 66 57 9
Revisions of previous estimates (89) (59) (30) (18) 25 (43) 17 17
Production (269) (222) (47) (97) (60) (37) (63) (50) (13)
Purchases of gas in place 1,322 1,322 512 98 414 129 6 123
Sales of gas in place (15) (15) (30) (30) (5) (4) (1)
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31 2,337 1,858 479 1,114 600 514 591 473 118
===================================================================================================================================
Proved developed reserves -- Gas
At January 1 1,005 600 405 591 473 118 447 447
At December 31 1,954 1,593 361 1,005 600 405 591 473 118
===================================================================================================================================
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
(thousands of barrels) Total United States Canada Total United States Canada Total United States Canada
- -----------------------------------------------------------------------------------------------------------------------------------
Proved developed and undeveloped
reserves -- Oil
At January 1
Changes in reserves: 20,808 659 20,149 4,204 2,661 1,543 2,349 2,349
Extensions, discoveries and
other additions 14,213 12,813 1,400 2,051 118 1,933 966 925 41
Revisions of previous estimates (5,082) (2,443) (2,639) 8,339 (552) 8,891 140 140
Production (7,694) (6,436) (1,258) (2,057) (595) (1,462) (1,025) (751) (274)
Purchases of oil in place 54,977 48,359 6,618 9,244 9,244 1,897 1,897
Sales of oil in place (1,880) (1,880) (973) (973) (123) (2) (121)
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31 75,342 51,072 24,270 20,808 659 20,149 4,204 2,661 1,543
===================================================================================================================================
Proved developed reserves -- Oil
At January 1 6,102 659 5,443 4,204 2,661 1,543 2,349 2,349
At December 31 36,236 21,709 14,527 6,102 659 5,443 4,204 2,661 1,543
===================================================================================================================================
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
The following tabulation has been prepared in accordance with the FASB's rules
for disclosure of a standardized measure of discounted future net cash flows
relating to Company-owned proved gas and oil reserve quantities.
<TABLE>
<CAPTION>
(millions) Year ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
Total United States Canada Total United States Canada Total United States Canada
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Future cash inflows $22,762 $18,277 $ 4,485 $ 2,401 $1,282 $ 1,119 $ 1,311 $1,102 $ 209
Less:
Future development and production
costs 2,558 1,945 613 1,097 497 600 485 381 104
Future income tax expense 7,145 5,591 1,554 209 125 84 120 137 (17)
- -----------------------------------------------------------------------------------------------------------------------------------
Future cash flows 13,059 10,741 2,318 1,095 660 435 706 584 122
Less annual discount (10% a year) 5,721 4,620 1,101 546 310 236 324 280 44
- -----------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows $ 7,338 $ 6,121 $ 1,217 $ 549 $ 350 $ 199 $ 382 $ 304 $ 78
===================================================================================================================================
</TABLE>
65
<PAGE>
Notes to Consolidated Financial Statements (continued)
In the foregoing determination of future cash inflows, sales prices for gas were
based on contractual arrangements or market prices at each year-end. Prices for
oil were based on average prices received from sales in the month of December
each year. Future cash inflows also reflect the effects of hedging activities.
Future costs of developing and producing the proved gas and oil reserves
reported at the end of each year shown were based on costs determined at each
such year end, assuming the continuation of existing economic conditions. Future
income taxes were computed by applying the appropriate year-end or future
statutory tax rate to future pretax net cash flows, less the tax basis of the
properties involved, and giving effect to tax deductions, or permanent
differences and tax credits.
It is not intended that the FASB's standardized measure of discounted
future net cash flows represent the fair market value of the Company's proved
reserves. The Company cautions that the disclosures shown are based on estimates
of proved reserve quantities and future production schedules which are
inherently imprecise and subject to revision, and the 10% discount rate is
arbitrary . In addition, present costs and prices are used in the determinations
and no value may be assigned to probable or possible reserves.
The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.
<TABLE>
<CAPTION>
(millions) Year ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Standardized measure of discounted
future net cash flows at January 1 $ 549 $ 382 $ 329
Changes in the year resulting from:
Sales and transfers of gas and oil produced
during the year, less production costs (796) (152) (98)
Prices and production and development
costs related to future production 8,706 (110) (114)
Extensions, discoveries and other additions,
less production and development costs 1,602 103 61
Previously estimated development costs
incurred during the year 82 57 71
Revisions of previous quantity estimates (778) 34 8
Accretion of discount 259 44 40
Income taxes (3,309) (44) 8
Acquisition of CNG 1,322
Other purchases and sales of proved reserves
in place 994 245 83
Other (principally timing of production) (1,293) (10) (6)
- -----------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at December 31 $ 7,338 $ 549 $ 382
===============================================================================================
</TABLE>
Note 26 | Quarterly Financial and Common Stock Data (unaudited)
The following amounts reflect all adjustments, consisting of only normal
recurring accruals (except as disclosed below), necessary in the opinion of
Dominion's management for a fair statement of the results for the interim
periods.
(millions, except per share amounts) 2000 1999
- --------------------------------------------------------------------------
Operating revenue and income
First Quarter $ 2,072 $ 1,293
Second Quarter 2,056 1,315
Third Quarter 2,351 1,663
Fourth Quarter 2,781 1,249
- --------------------------------------------------------------------------
Year $ 9,260 $ 5,520
==========================================================================
Income from operations
First Quarter $ 415 $ 322
Second Quarter 71 300
Third Quarter 658 492
Fourth Quarter 385 214
- --------------------------------------------------------------------------
Year $ 1,529 $ 1,328
==========================================================================
Income (loss) before extraordinary
item and cumulative effect of a change
in accounting principle
First Quarter $ 143 $ 138
Second Quarter (103) 120
Third Quarter 255 235
Fourth Quarter 120 59
- --------------------------------------------------------------------------
Year $ 415 $ 552
==========================================================================
Net income (loss)
First Quarter $ 143 $ (117)
Second Quarter (103) 120
Third Quarter 255 235
Fourth Quarter 141 59
- --------------------------------------------------------------------------
Year $ 436 $ 297
==========================================================================
Earnings (loss) per share before extraordinary item and cumulative effect
of a change in accounting principle
Basic Diluted
- --------------------------------------------------------------------------
2000 1999 2000 1999
- --------------------------------------------------------------------------
First Quarter $ 0.64 $ 0.71 $ 0.64 $ 0.71
Second Quarter (0.44) 0.63 (0.44) 0.63
Third Quarter 1.07 1.23 1.07 1.23
Fourth Quarter 0.49 0.31 0.49 0.24
- --------------------------------------------------------------------------
Year $ 1.76 $ 2.88 $ 1.76 $ 2.81
==========================================================================
Earnings (loss) per share
Basic Diluted
- --------------------------------------------------------------------------
2000 1999 2000 1999
- --------------------------------------------------------------------------
First Quarter $ 0.64 $ (0.61) $ 0.64 $ (0.61)
Second Quarter (0.44) 0.63 (0.44) 0.63
Third Quarter 1.07 1.23 1.07 1.23
Fourth Quarter 0.58 0.30 0.58 0.23
- --------------------------------------------------------------------------
Year $ 1.85 $ 1.55 $ 1.85 $ 1.48
==========================================================================
66
<PAGE>
Quarterly Financial and Common Stock Data--Unaudited, (continued)
- -----------------------------------------------------------------------
2000 1999
- -----------------------------------------------------------------------
Dividends per share
First Quarter $ 0.645 $ 0.645
Second Quarter 0.645 0.645
Third Quarter 0.645 0.645
Fourth Quarter 0.645 0.645
- -----------------------------------------------------------------------
Year $ 2.58 $ 2.58
=======================================================================
Stock price range
First Quarter 43 1/8 - 34 13/16 47 1/16 - 36 7/8
Second Quarter 47 1/2 - 38 1/16 44 13/16 - 36 9/16
Third Quarter 59 13/16 - 42 13/16 47 3/16 - 43
Fourth Quarter 67 15/16 - 50 3/4 49 3/8 - 39 1/4
- -----------------------------------------------------------------------
Year 67 15/16 - 34 13/16 49 3/8 - 36 9/16
=======================================================================
Certain amounts recorded in 2000 and 1999 were not ordinary, recurring
adjustments.
For the year ended December 31, 2000, Dominion recognized $460 million of
restructuring and other acquisition-related costs. See Note 6.
During the second quarter of 2000, management adopted a strategy to exit
certain businesses of DCI and to de-emphasize the remaining components of the
businesses that are expected to be retained or possibly held only as long as
necessary to wind up affairs. Under this strategy, DCI reevaluated certain
assets and businesses and impairment losses were recognized. During 2000,
Dominion has recognized impairment losses of $291 million, of which $172
million was determined to be attributable to Dominion's exit strategy rather
than other factors and are included in Restructuring and other acquisition-
related costs.
During the quarter ended September 30, 2000, Dominion adopted a company-
wide method of calculating the market related value of plan assets used to
determine the expected return on pension plan assets, a component of net
periodic pension cost. Dominion recorded $21 million, net of income taxes of
$11 million, as a cumulative effect of the change on prior years' income. The
effect of the change for the year 2000 was to increase income before
extraordinary item and cumulative effect of a change in accounting principle by
$11 million, or $0.05 per share, and net income by $32 million, or $0.14 per
share.
Extraordinary Item
In the first quarter of 1999, Dominion recorded an after-tax charge of $255
million, or $1.33 per share, to reflect the write-off of assets and liabilities
that will not be recovered through base rates capped by Virginia legislation
enacted into law on March 25, 1999. This legislation establishes a detailed plan
to restructure the electric utility industry in Virginia. The after-tax charge
was recorded as an extraordinary item on Dominion's Consolidated Statements of
Income.
67
<PAGE>
Notes to Consolidated Financial Statements (continued)
Note 27 Business Segments
Business segment financial information follows for each of the three years in
the period ended December 31, 2000. Corporate includes intersegment
eliminations.
<TABLE>
<CAPTION>
Dominion Dominion Dominion Dominion Dominion Corporate Total
(millions, except total assets) Delivery Capital Energy UK E&P Operations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2000
Revenue $2,824 $ 433 $ 4,764 $ 1,369 $ (130) $ 9,260
Interest income 8 8
Interest expense 198 192 207 83 278 958
Operating income 707 215 934 438 (765) 1,529
Depreciation and amortization 318 34 340 352 132 1,176
Unusual items 351 351
Equity income 6 23 12 6 47
Income tax expense (benefit) 187 12 262 97 (375) 183
Net income 339 11 478 270 (662) 436
Equity investments 111 223 71 68 473
Capital expenditures 457 5 330 751 22 1,565
Total assets (billions) 7.9 2.0 10.6 3.6 5.2 29.3
1999
Revenue 1,166 473 3,593 256 32 5,520
Interest income 12 4 7 23
Interest expense 141 152 173 39 2 507
Operating income 431 265 623 44 (35) 1,328
Depreciation and amortization 246 32 313 84 32 707
Extraordinary item (255) (255)
Equity income 4 14 5 10 33
Income tax expense (benefit) 109 35 161 (29) (17) 259
Net income 175 78 271 44 (271) 297
Equity investments 166 186 23 31 406
Capital expenditures 317 9 461 86 21 894
Total assets (billions) 4.6 3.6 7.5 1.2 0.9 17.8
1998
Revenue 1,111 409 3,510 $1,009 164 (122) 6,081
Interest income 12 2 15 29
Interest expense 145 121 179 102 19 17 583
Operating income 424 210 615 142 29 (316) 1,104
Depreciation and amortization 237 25 337 75 59 733
Unusual items 332 332
Equity income 21 14 4 2 41
Income tax expense (benefit) 104 31 157 133 (20) (93) 312
Net income 168 59 262 227 34 (202) 548
Equity investments 203 122 18 39 382
Capital expenditures 282 6 260 92 50 65 755
Total assets (billions) 4.6 3.1 7.5 0.8 1.5 17.5
================================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Geographic Areas
Revenue International
---------------------------------------------------
(millions) United Latin Total
Year Domestic Kingdom America Canada International Consolidated
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2000 $ 9,068 $ 13 $ 179 $ 192 $ 9,260
1999 5,392 106 22 128 5,520
1998 4,913 $ 1,009 133 26 1,168 6,081
Long-Lived Assets International
---------------------------------------------------
(billions) United Latin Total
Year Domestic Kingdom America Canada International Consolidated
- --------------------------------------------------------------------------------------------------------------------------------
2000 $ 21.5 $ 0.5 $ 0.5 $ 22.0
1999 10.7 $ 0.1 $ 0.4 0.5 1.0 11.7
================================================================================================================================
</TABLE>
68
<PAGE>
Notes to Consolidated Financial Statements (concluded)
Under SFAS No. 131, Disclosures About Segments of an Enterprise and Related
Informations, Dominion has defined segments based on product, geographic
location and regulatory environment.
On March 3, 2000, Dominion announced a new business structure that
integrates CNG's businesses, streamlines operations, and positions Dominion for
long-term growth in the competitive marketplace. Under the structure, Dominion
operates three principal business units:
. Dominion Energy manages Dominion's 19,000-megawatt generation portfolio,
consisting of generating units and power purchase agreements. It also
manages the Company's generation growth strategy; energy trading,
marketing, hedging and arbitrage activities; and gas pipeline and storage
operations.
. Dominion Delivery manages Dominion's electric and gas distribution systems,
as well as customer service and electric transmission. The Company's
telecommunications business is also included in the Dominion Delivery
segment.
. Dominion Exploration & Production manages Dominion's onshore and offshore
oil and gas exploration, development and production operations. Operations
are located on the outer continental shelf and deep water areas of the Gulf
of Mexico and in selected regions in the lower 48 states and Canada.
In addition, Dominion also reviews the following as business segments:
. the financial services businesses of DCI; and
. Corporate Operations.
The Corporate Operations category includes:
. corporate costs of Dominion's and CNG's holding companies;
. Corby Power (UK) operations, prior to its sale on September 29, 2000;
. intercompany eliminations;
. restructuring and acquisition related costs (see Note 6);
. cumulative effect of a change in the method of accounting for pensions (see
Note 3);
. impairment and re-valuation of DCI's assets (see Note 6);
. the write-off of generation-related assets and liabilities at Dominion in
1999 (see Note 7); and
. the impairment of regulatory assets and one-time base rate refund resulting
from the settlement of Virginia Power's 1998 Virginia jurisdictional rate
proceedings (see Note 7).
While Dominion manages its daily operations as described above, assets
remain wholly owned by its legal subsidiaries.
Selected Consolidated Financial Data
<TABLE>
<CAPTION>
(millions, except per share amounts) 2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenue and income $ 9,260 $ 5,520 $ 6,081 $ 7,263 $ 4,815
Income before extraordinary item and cumulative
effect of a change in accounting principle $ 415 $ 552 $ 548 $ 412 $ 482
Extraordinary item (net of income taxes of $197) $ (255)
Cumulative effect of change in accounting principle
(net of income taxes of $11) $ 21
Net income $ 436 $ 297 $ 548 $ 412 $ 482
Total assets $ 29,348 $ 17,782 $ 17,549 $ 20,184 $ 14,911
Long-term debt, preferred stock subject to
mandatory redemption and preferred
securities of a subsidiary trust/(1)/ $ 10,486 $ 7,321 $ 6,817 $ 7,761 $ 5,362
Common stock data:
Earnings per share--basic $ 1.85 $ 1.55 $ 2.81 $ 2.22 $ 2.70
Dividends paid per share $ 2.58 $ 2.58 $ 2.58 $ 2.58 $ 2.58
===========================================================================================================
</TABLE>
Note:
/(1)/ In 1999, preferred stock subject to mandatory redemption is included in
Securities due within one year and is excluded from this amount.
69
<PAGE>
Report of Management's Responsibilities
The management of Dominion Resources, Inc. is responsible for all information
and representations contained in the Consolidated Financial Statements and other
sections of the annual report. The Consolidated Financial Statements, which
include amounts based on estimates and judgments of management, have been
prepared in conformity with generally accepted accounting principles. Other
financial information in the annual report is consistent with that in the
Consolidated Financial Statements.
Management maintains a system of internal accounting controls designed to
provide reasonable assurance, at a reasonable cost, that Dominion's and its
subsidiaries' assets are safeguarded against loss from unauthorized use or
disposition and that transactions are executed and recorded in accordance with
established procedures. Management recognizes the inherent limitations of any
system of internal accounting control, and therefore cannot provide absolute
assurance that the objectives of the established internal accounting controls
will be met.
This system includes written policies, an organizational structure designed
to ensure appropriate segregation of responsibilities, careful selection and
training of qualified personnel, and internal audits. Management believes that
during 2000 the system of internal control was adequate to accomplish the
intended objectives.
The Consolidated Financial Statements have been audited by Deloitte &
Touche LLP, independent auditors, who were designated by the Board. Their audits
were conducted in accordance with auditing standards generally accepted in the
United States of America and include a review of Dominion's and its
subsidiaries' accounting systems, procedures and internal controls, and the
performance of tests and other auditing procedures sufficient to provide
reasonable assurance that the Consolidated Financial Statements are not
materially misleading and do not contain material errors.
The Audit Committee of the Board of Directors of Dominion Resources, Inc.,
composed entirely of directors who are not officers or employees of Dominion
Resources, Inc. or its subsidiaries, meets periodically with the independent
auditors, the internal auditors and management to discuss auditing, internal
accounting control and financial reporting matters of the Company and to ensure
that each is properly discharging its responsibilities. Both independent
auditors and the internal auditors periodically meet alone with the Audit
Committee and have free access to the Committee at any time.
Management recognizes its responsibility for fostering a strong ethical
climate so that the Company's affairs are conducted according to the highest
standards of personal corporate conduct. This responsibility is characterized
and reflected in Dominion's Code of Ethics, which addresses potential conflicts
of interest, compliance with all domestic and foreign laws, the confidentiality
of proprietary information, and full disclosure of public information.
Dominion Resources, Inc.
/s/ Thos. E. Capps /s/ Steven A. Rogers
Chairman, President and Vice President, Controller and
Chief Executive Officer Principal Accounting Officer
Independent Auditors' Report
To the Shareholders and Board of Directors of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion
Resources, Inc. and subsidiaries as of December 31, 2000 and 1999, and the
related consolidated statements of income, comprehensive income, common
shareholders' equity, and cash flows for each of the three years in the period
ended December 31, 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Dominion Resources, Inc. and
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the
Company changed its method of accounting used to develop the market-related
value of pension plan assets in 2000. Also, as discussed in Note 3 to the
consolidated financial statements, in 2000 the Company changed its method of
accounting for its oil and gas exploration and production activities to the full
cost method of accounting and, retroactively, restated the 1999 and 1998
consolidated financial statements for the change to the full cost method.
Deloitte & Touche LLP
Richmond, Virginia
January 25, 2001
70
<PAGE>
Directors and Officers
Dominion Resources, Inc.
Directors
Thos. E. Capps, 65
Chairman, President and Chief Executive Officer
William S. Barrack, Jr., 71
Former Senior Vice President, Texaco, Inc.
New Canaan, Connecticut
George A. Davidson, Jr., 62
Former Chairman, Dominion Resources, Inc.
Pittsburgh, Pennsylvannia
Raymond E. Galvin, 69
Former President, Chevron USA Production Company
Houston, Texas
John W. Harris, 53
President, Lincoln Harris, LLC, Charlotte, North Carolina
Benjamin J. Lambert, III, 64
Optometrist, Richmond, Virginia
Richard L. Leatherwood, 61
Former President and Chief Executive Officer,
CSX Equipment, Baltimore, Maryland
Paul E. Lego, 70
Former Chairman and Chief Executive Officer,
Westinghouse Electric Corporation
Pittsburgh, Pennsylvania
Margaret A. McKenna, 55
President, Lesley University, Cambridge, Massachusetts
Steven A. Minter, 62
President and Executive Director,
The Cleveland Foundation, Cleveland, Ohio
Kenneth A. Randall, 73
Corporate director of various companies,
Williamsburg, Virginia
Frank S. Royal, M.D., 61
Physician, Richmond, Virginia
S. Dallas Simmons, 61
Chairman, President and Chief Executive Officer,
Dallas Simmons & Associates, Inc., Richmond, Virginia
Robert H. Spilman, 73
President, Spilman Properties, Bassett, Virginia
David A. Wollard, 63
Chairman of the Board, Exempla Healthcare, Denver, Colorado
Officers
Thomas F. Farrell, II, 46
Executive Vice President
(Chief Executive Officer of Dominion Energy)
H. Patrick Riley, 63
Executive Vice President
(Chief Executive Officer and President of Dominion Exploration & Production)
Edgar M. Roach, Jr., 52
Executive Vice President
(Chief Executive Officer of Dominion Delivery)
Thomas N. Chewning, 55
Executive Vice President and Chief Financial Officer
James P. O'Hanlon, 57
Executive Vice President
(President and Chief Operating Officer of Dominion Energy)
Robert E. Rigsby, 51
Executive Vice President
(President and Chief Operating Officer of Dominion Delivery)
James L. Trueheart, 49
Group Vice President and Chief Administrative Officer
Eva Tieg Hardy, 56
Senior Vice President -- External Affairs & Corporate Communications
G. Scott Hetzer, 44
Senior Vice President and Treasurer
James L. Sanderlin, 59
Senior Vice President -- Law
William C. Hall, Jr., 47
Vice President -- External Affairs & Corporate Communications
Simon C. Hodges, 39
Vice President -- Financial Planning
Karen E. Hunter, 46
Vice President -- Tax
Steven A. Rogers, 39
Vice President, Controller and Principal Accounting Officer
James F. Stutts, 56
Vice President and General Counsel
Patricia A. Wilkerson, 45
Vice President and Corporate Secretary
71
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>6
<FILENAME>0006.txt
<DESCRIPTION>SUBSIDIARIES OF THE REGISTRANT
<TEXT>
<PAGE>
Exhibit 21
DOMINION RESOURCES, INC.
SUBSIDIARIES OF THE REGISTRANT
<TABLE>
<CAPTION>
JURISDICTION OF NAME UNDER WHICH
NAME INCORPORATION BUSINESS IS CONDUCTED
<S> <C> <C>
Consolidated Natural Gas Company Delaware Consolidated Natural Gas Company
Dominion Capital, Inc. Virginia Dominion Capital, Inc.
Dominion Energy, Inc. Virginia Dominion Energy, Inc.
Dominion Exploration & Production, Inc. Delaware Dominion Exploration & Production, Inc.
Dominion Transmission, Inc. Delaware Dominion Transmission, Inc.
The East Ohio Gas Company Ohio Dominion East Ohio
The Peoples Natural Gas Company Pennsylvania Dominion Peoples
Dominion Virginia Power in Virginia
and Dominion North Carolina Power
Virginia Electric and Power Company Virginia in North Carolina
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>7
<FILENAME>0007.txt
<DESCRIPTION>CONSENT OF DELOITTE AND TOUCHE
<TEXT>
<PAGE>
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
333-55904, 333-36082, 333-93187, 333-46043, and 333-35501 of Dominion Resources,
Inc. on Form S-3 and Registration Statement Nos. 333-38398, 333-38398,
333-95795, 333-95567, 333-87529, 333-78173, 333-69305, 333-49725, 333-25587,
333-18391, 333-02733, and 33-62705 of Dominion Resources, Inc. on form S-8 of
our reports dated January 25, 2001, appearing in and incorporated by reference
in this Annual Report on Form 10-K of Dominion Resources, Inc. for the year
ended December 31, 2000.
DELLOITTE & TOUCHE LLP
Richmond, Virginia
March 16, 2001
</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
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