<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, 1999
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)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Virginia
Common Stock, no par value
(State or other jurisdiction of incorporation or organization)
Name of each exchange on which registered
120 Tredegar Street Richmond, Virginia 23219
New York Stock Exchange (Address of principal executive offices) (Zip Code)
Securities registered pursuant to Section 12(g) of the Act: 54-1229715
None (I.R.S. Employer Identification No.)
(Registrant's telephone number, including area code) (804) 819-2000
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 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 voting stock held by nonaffiliates of the
registrant was over $8.6 billion based on the closing price of our Common Stock
on January 31, 2000, as reported on the composite tape by The Wall Street
Journal.
Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
Class Outstanding at March 1, 2000
<S> <C>
Common Stock, no par value 238,363,650
</TABLE>
DOCUMENTS INCORPORATED BY REFERENCE:
(a) Portions of the 1999 Annual Report to Shareholders for the fiscal year
ended December 31, 1999 are incorporated by reference in Parts I, II and IV
hereof.
(b) Portions of the 2000 Proxy Statement, dated March 16, 2000, are
incorporated by reference in Part III hereof.
<PAGE>
DOMINION RESOURCES, INC.
<TABLE>
<CAPTION>
Item Page
Number Number
------ ------
PART I
<C> <S> <C>
1. Business
The Company................................................... 1
Recent Developments.......................................... 1
Business Segments............................................ 2
Dominion Energy--Utility Operations and Dominion Delivery... 3
Competition................................................ 3
Regulation................................................. 4
Rates...................................................... 7
Sources of Power........................................... 10
Energy Output, Sources of Energy Used, Fuel Costs and
Operations..................................................... 11
Dominion Delivery--Interconnections......................... 13
Dominion Energy--Non-Utility Operations..................... 13
Dominion Exploration & Production........................... 13
Financial Information About Segments and Geographic Areas... 14
Dominion Capital............................................ 14
Capital Requirements and Financing Program--Dominion Energy,
Dominion Delivery and Dominion E&P....................... 14
CNG......................................................... 14
Government Regulation...................................... 14
Gas Competition............................................ 15
Gas Supply................................................. 18
Gas Sales, Supply, Transportation and Storage Statistics... 20
International Activities................................... 21
Rate Matters............................................... 21
Properties................................................. 21
2. Properties..................................................... 21
3. Legal Proceedings.............................................. 22
4. Submission of Matters to a Vote of Security Holders............ 23
Executive Officers of the Registrant........................... 24
PART II
Market for the Registrant's Common Equity and Related
5. Stockholder Matters............................................ 26
6. Selected Financial Data........................................ 26
Management's Discussion and Analysis of Financial Condition and
7. Results of Operations.......................................... 26
7A. Quantitative and Qualitative Disclosures About Market Risk..... 26
8. Financial Statements and Supplementary Data.................... 26
Changes in and Disagreements with Accountants on Accounting and
9. Financial Disclosure........................................... 26
PART III
10. Directors and Executive Officers of the Registrant............. 27
11. Executive Compensation......................................... 27
12. Security Ownership of Certain Beneficial Owners and Management. 27
13. Certain Relationships and Related Transactions................. 27
PART IV
Exhibits, Financial Statement Schedules, and Reports on Form 8-
14. K.............................................................. 28
</TABLE>
<PAGE>
PART I
ITEM 1. BUSINESS
THE COMPANY
Dominion Resources, Inc. (Dominion), a diversified utility holding company,
has its principal office at 120 Tredegar Street, Richmond, Virginia 23219,
telephone (804) 819-2000. Its principal 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.
Its other major subsidiaries are Dominion Energy, Inc. (DEI), its independent
power and natural gas subsidiary, and Dominion Capital, Inc. (Dominion
Capital), its diversified financial services company.
Dominion was incorporated in 1983 as a Virginia corporation. Dominion and
its subsidiaries (excluding CNG) had 11,035 full-time employees as of December
31, 1999.
Dominion also owns and operates a 365 Mw natural gas fired generating
facility in the United Kingdom.
Recent Developments
On January 28, 2000, Dominion and CNG completed the merger of CNG into a
subsidiary of Dominion. Shareholders of CNG received Dominion common stock
and/or cash in consideration of their CNG shares. 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 with selective energy businesses located abroad.
As a result of the merger, 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. The 1935 Act imposes a number of restrictions on the
operations of registered holding company systems. One such restriction limits
the ability of a registered holding company to engage in activities unrelated
to its utility operations or other energy related businesses. Consequently, as
part of the Securities and Exchange Commission (SEC) order approving the
merger under the 1935 Act, Dominion must divest itself of Dominion Capital,
its financial services subsidiary. Although a formal plan for divestiture has
not been adopted, the SEC allowed three years for this to be accomplished.
During the merger approval process, Dominion and CNG also agreed to divest
Virginia Natural Gas, Inc. (VNG), CNG's gas distribution subsidiary located in
Virginia Beach, Virginia. Dominion has one year after the merger is completed
to sell VNG to a third party. If the sale of VNG is not completed within one
year, VNG will be spun off as an independent company with the common stock
distributed to Dominion shareholders. Both deadlines are subject to reasonable
extensions, which may be granted by regulatory authorities.
As a result of Dominion's focus in the Midwest, Northeast and Mid-Atlantic
quadrant of the U.S., DEI reached an agreement in 1999 to sell its interests
in approximately 1,200 megawatts of gross generation capacity located in Latin
America. Duke Energy International is purchasing the interests for
approximately $405 million. The interests being sold are located in Argentina,
Belize, Bolivia and Peru and generate electricity from hydroelectric, natural
gas and diesel fuel sources. DEI completed the sale of its interests in Belize
and Peru on November 1, 1999 and expects to complete the sale of its interests
in Argentina and Bolivia in 2000, following receipt of certain regulatory
approvals. Similarly, Dominion has begun exploring the sale of CNG's
international operations.
1
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In conjunction with the merger, Dominion created a subsidiary service
company, Dominion Resources Services, Inc. (the Dominion Service Company),
which will provide certain services to Dominion's operating subsidiaries.
Employees of Dominion and Virginia Power who will perform those functions
became employees of the Dominion Service Company effective February 1, 2000.
CNG also has a service company. The operating subsidiaries may elect to
purchase services from either service company; however, service company
functions are expected to be combined in a single service company by March 31,
2001.
Dominion funded the merger with a $3.5 billion commercial paper program
backed by a short-term credit facility agented by the Bank of America and $1
billion of privately placed money market notes. The Company expects to replace
much of the short-term financing with long-term financing using a combination
of debt, preferred and/or convertible securities along with the proceeds of
any sales of non-core assets over the next several years, including VNG,
Dominion Capital, DEI's interests in Latin American power generation, as
discussed above, and CNG International, as discussed in CNG--International
Activities below.
For additional information, see FUTURE ISSUES-CNG Merger under MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(MD&A) on page 32 and Note X to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on
page 57 of the 1999 Annual Report to Shareholders.
Business Segments
In 1999, in preparation for the transition to competition for electric
generation in Virginia, Dominion began evaluating operating results and
financial information across Virginia Power's and DEI's current business
lines. Although the employees and assets involved remain with their respective
legal entities, Dominion currently evaluates the operations of DEI and
Virginia Power in the following business segments:
. generation-related operations of both Virginia Power and DEI (referred
to as Dominion Energy);
. regulated electric transmission and distribution services (referred to
as Dominion Delivery); and
. oil and gas operations of DEI (referred to as Dominion Exploration &
Production or Dominion E&P).
In addition to the business segments mentioned above, Dominion also
considers the following as business segments:
. the financial services businesses of Dominion Capital;
. East Midlands which was sold by Dominion in mid-1998; and
. Corporate Operations which include: corporate operations of Dominion's
holding company and U.K. operations.
Going forward, Dominion intends to manage the oil and gas exploration and
production operations and pipeline transmission operations of CNG and DEI on a
combined basis as Dominion E&P. Dominion also intends to manage CNG's
regulated local gas distribution companies and the related customer services
functions together with Virginia Power's regulated electric transmission and
distribution services as Dominion Delivery.
Dominion has generally structured this description of the Company to reflect
the business segments described above. However, for purposes of this report,
CNG's operations are separately discussed.
The Dominion Energy business segment includes the generation-related
operations of Virginia Power (the utility operations) and DEI (the non-utility
operations). Virginia Power is also where the electric operations of the
Dominion Delivery business segment are conducted. See Dominion Energy--Non-
Utility Operations for a discussion of that aspect of the Dominion Energy
business segment.
2
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As previously discussed, Dominion is in transition as it prepares for
deregulation. As a result, it is difficult to entirely segregate the
discussion of Virginia Power's Generation and Delivery businesses. However,
discussion below identifies, where practicable, the appropriate business
segment being described.
Dominion Energy--Utility Operations
and
Dominion Delivery (Virginia Power)
Virginia Electric and Power Company is a public utility engaged in the power
generation and electric service delivery business within a 30,000 square-mile
service territory in Virginia and northeastern North Carolina. Virginia Power
supplies energy at retail to approximately two million customers. In addition,
Virginia Power sells electricity at wholesale to rural electric cooperatives,
power marketers and certain municipalities. The term "Virginia Power" refers
to the entirety of Virginia Electric and Power Company, including its Virginia
and North Carolina operations and all of its subsidiaries.
In Virginia, Virginia Power trades under the name "Virginia Power." The
Virginia service area comprises about 65 percent of Virginia's total land
area, but accounts for over 80 percent of its population. In North Carolina,
Virginia Power trades under the name "North Carolina Power" and serves retail
customers located in the northeastern region of the state, excluding certain
municipalities. Virginia Power also engages in off-system wholesale purchases
and sales of electricity and purchases and sales of natural gas and is
developing trading relationships beyond the geographic limits of its retail
service territory. The Federal Energy Regulatory Commission (FERC), the State
Corporation Commission of Virginia (the Virginia Commission) and the North
Carolina Utilities Commission (the North Carolina Commission) are the
principal regulators of Virginia Power's electric operations.
Various factors are currently affecting the electric utility industry,
including increasing competition and related regulatory changes, costs to
comply with environmental regulations, and the potential for new business
opportunities outside of traditional rate-regulated operations. To meet the
challenges of this new competitive environment, Virginia Power continues to
consider new business opportunities, particularly those which allow it to use
the expertise and resources developed through its regulated utility
experience. Over the past several years Virginia Power has developed a broad
array of "non-traditional" products and services. Examples of non-traditional
services include wholesale power marketing and telecommunications. Virginia
Power also markets its services to other utilities in areas such as nuclear
consulting and management and power distribution (i.e., transmission,
distribution, engineering and metering services). Virginia Power is continuing
to focus on new and existing programs to enhance customer satisfaction and
energy efficiency.
The aspects of Virginia Power's business in the Dominion Energy segment
include its generation portfolio, trading and marketing activities, nuclear
consulting services and energy services activities.
Dominion Delivery includes Virginia Power's regulated electric transmission
and distribution services, bulk power transmission, distribution and metering
services and customer service. It continues to be subject to cost-based
regulation.
Competition
The structure of the electric industry in Virginia Power's service territory
and throughout the United States has been relatively stable for many years.
Recently, however, there have been both federal and state developments toward
less regulation and increased competition. Electric utilities have been
required to open up their transmission systems for non-discriminatory use by
potential wholesale competitors. In addition, non-utility power marketers now
compete with electric utilities in the wholesale generation market. At the
federal level, retail competition is under consideration. Some states,
including Virginia, have enacted legislation requiring retail competition.
3
<PAGE>
Currently, as in the past, there is no general retail competition in our
principal service area. Today Virginia Power's only competition for retail
sales arises when certain of its business customers move into another utility
service territory, use other energy sources instead of electric power, or
generate their own electricity. However, Virginia has adopted legislation
requiring retail competition beginning in 2002 and North Carolina is
considering retail competition. To the extent that competition is permitted,
Virginia Power's ability to sell power at prices that will allow it to recover
prudently incurred costs may be an issue. Additionally, Virginia Power is in
the process of developing a retail access pilot program for implementation by
the summer of 2000 in Virginia.
Virginia Power continues 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. Virginia Power has also
responded to the trends toward competition by cutting costs, re-engineering
its core business processes and pursuing innovative approaches to serving
traditional and future markets. In addition, Virginia Power is developing
certain "non-traditional" products and services as described above in an
effort to provide growth in future earnings.
For additional information on our changing industry environment see FUTURE
ISSUES--Dominion Delivery Business and Utility Operations of Dominion Energy
under MD&A on pages 33 through 35 of the 1999 Annual Report to Shareholders.
Regulation
General
Many aspects of Virginia Power's business are presently subject to
regulation by the Virginia Commission, the North Carolina Commission, FERC,
the Environmental Protection Agency (EPA), Department of Energy (DOE), Nuclear
Regulatory Commission (NRC), the Army Corps of Engineers and other federal,
state and local authorities. Furthermore, with Dominion becoming a registered
public utility holding company under the 1935 Act, both the Dominion Energy
and Dominion Delivery businesses are now subject to regulation by the SEC.
Virginia Power holds certificates of public convenience and necessity issued
by the Virginia Commission and the North Carolina Commission authorizing it to
construct and operate the electric facilities now in operation for which
certificates are required, and to sell electricity to retail customers.
However, Virginia Power may not construct, or incur financial commitments for
construction of, any substantial generating facilities or large capacity
transmission lines without the prior approval of various state and federal
governmental agencies.
The Virginia Commission and the North Carolina Commission regulate Virginia
Power's bundled rates for its Dominion Energy business and Dominion Delivery
business for retail electric sales and FERC approves Virginia Power's rates
for electric sales to wholesale customers.
The following sections discuss various regulatory proceedings in which
Virginia Power is or has recently been involved. Rate specific proceedings are
discussed separately in the section below entitled Rates. Environmental
matters are discussed separately in the section below entitled Environmental.
Virginia
Virginia Power is subject to the jurisdiction of the Virginia Commission,
which has broad powers of supervision and regulation over public utilities,
including rates, service regulations and sales of securities. The following is
a description of recent Virginia proceedings. The affected segments are
indicated parenthetically.
In March 1998, the Virginia Commission issued an Order Establishing
Investigation with regard to independent system operators (ISO's), regional
power exchanges (RPX's) and retail access pilot programs. The Order directed
all investor-owned electric utilities to begin, in conjunction with the
Virginia Commission Staff and other interested parties, to develop one or more
ISO's and RPX's to serve the public interest in Virginia.
4
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The Virginia Electric Utility Restructuring Act (Act), signed into law in
1999, requires that Virginia's incumbent electric utilities join or establish
a regional transmission entity (RTE) by January 1, 2001, and seek
authorization from the Virginia Commission to transfer operational control of
their transmission facilities to the RTE. In May 1999, the Virginia Commission
issued an Order Establishing Investigation and invited comments concerning the
development of the rules required by the Act. Virginia Power submitted
comments in June 1999 and reply comments in July 1999. In January 2000, the
Virginia Commission issued an Order giving notice of, and requesting comments
to, proposed rules and regulations establishing the elements of RTE structures
to be applied by the Virginia Commission in determining whether to authorize
the transfer of operational control of the transmission facilities to the RTE.
Virginia Power submitted comments on the proposed rules and regulations in
February 2000. Under the proposed rules, Virginia Power will be required to
seek authorization to transfer operational control of its transmission
facilities to a RTE on or before May 1, 2000. (Dominion Delivery)
In addition, the March 1998 Order instructed Virginia Power and American
Electric Power-Virginia (AEP), as the Commonwealth's two largest investor-
owned utilities, each to design and file a retail access pilot program. In
response, Virginia Power filed a report describing the details, objectives and
characteristics of its proposed retail access pilot program and a hearing was
held. Virginia Power is currently awaiting a Final Order. For more details on
the proposed retail access pilot program, see FUTURE ISSUES--Competition--
Regulatory Initiatives under MD&A on page 34 of the 1999 Annual Report to
Shareholders. (Dominion Energy and Dominion Delivery)
In December 1999, the Virginia Commission issued orders approving the
addition of two wholly-owned subsidiaries of Virginia Power Services, Inc.,
namely Evantage, Inc. (Evantage) and VP Property, Inc. (VP Property), to the
Affiliate Services Agreement approved by the Virginia Commission in its
September 1997 Order. In connection with the organization of Evantage and VP
Property, the Virginia Commission issued two related orders approving the
transfer of certain contracts and assets from Virginia Power to these
subsidiaries. (Dominion Energy)
In December 1999, in connection with the merger the Virginia Commission
issued an order approving service and support agreements which provide for
administrative management and other services for Dominion and its
subsidiaries.
In January 2000, Virginia Power 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. Virginia Power has
obtained the applicable zoning permits for the construction of the generators
and has applied for other required environmental permits. The Virginia
Commission set a hearing date of May 23, 2000 to consider the application.
(Dominion Energy)
North Carolina
The 1997 session of the North Carolina General Assembly created a study
commission on the future of electric service in North Carolina. In October
1999, Duke Energy Corp. and Carolina Power and Light Company submitted a
proposal to the study commission addressing certain municipal debt issues that
must be resolved before a comprehensive restructuring plan can be developed.
The North Carolina Commission continues to study the subject of deregulation
in anticipation that the 2000 session of the General Assembly will consider
the issue when it convenes in May of 2000. (Dominion Delivery and Dominion
Energy)
Federal
The Federal Power Act subjects Virginia Power to regulation by FERC as a
company engaged in the transmission or sale of wholesale electric energy in
interstate commerce. The Energy Policy Act of 1992 (EPACT) and FERC's
subsequent rulemaking activities allow FERC to order access for third parties
to transmission facilities owned by another entity. This authority is limited,
however, and does not permit FERC to issue orders requiring transmission
access to retail customers. FERC has issued orders for third-party
5
<PAGE>
transmission service. FERC has also issued a number of rules of general
applicability, including Orders 888, 889 and 2000. (Dominion Delivery)
Pursuant to FERC's final rules, Virginia Power established an open access
same-time information system (OASIS) which became operational January 1997. In
addition, in July 1997 Virginia Power filed amendments to its existing rate
tariff with FERC so that it could make wholesale power sales at market-based
rates. Under a FERC order conditionally accepting Virginia Power's market-
based rate schedule, Virginia Power began making market-based sales of
wholesale power in 1997. FERC set for hearing the issue of whether
transmission constraints limiting the transfer of power into Virginia Power's
service territory would provide it with generation dominance in local markets.
This issue was resolved through FERC's acceptance of an offer of settlement in
which Virginia Power agreed to refrain from making sales under its market-
based tariff to loads located within its service territory. This settlement
did not preclude Virginia Power from requesting FERC authorization of such
sales in the future, but until such authorization has been granted by FERC,
agreements by Virginia Power to sell wholesale power to loads located within
its service territory are to be at cost-based rates accepted by FERC. Virginia
Power filed in February 2000 an application with FERC to make sales under its
market based rate tariff to retail loads within its service territory to
accommodate a retail access pilot program. Also, in February 2000, Virginia
Power filed an application with FERC to amend its open access transmission
tariff to accommodate the retail access pilot program. (Dominion Energy)
In June 1999, Virginia Power, along with AEP, First Energy Corp., and
Consumers Energy Company and The Detroit Edison Company, on behalf of
themselves and their respective public utility operating company subsidiaries
filed with FERC applications under Sections 205 and 203 of the Federal Power
Act for approval of a proposed regional transmission organization. For more
detail on the application, see Dominion Delivery-- Interconnections section
below. (Dominion Delivery)
Environmental
The Dominion Energy 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 FUTURE ISSUES--Environmental
Matters, Environmental Protection and Monitoring Expenditures, Clean Air Act
Compliance, and Global Climate Change on pages 35 and 36 also see Virginia
Power--Capital Requirements and DEI--Capital Requirements under MD&A on pages
30 and 31, respectively, in the 1999 Annual Report to Shareholders.
From time to time Dominion may be identified as a potentially responsible
party (PRP) with respect to a superfund site. EPA (or a state) can either (a)
allow such a party to conduct and pay for a remedial investigation,
feasibility study and remedial action or (b) conduct the remedial
investigation and action and then seek reimbursement from the parties. Each
party can be held jointly, severally and strictly liable for all costs, but
the parties can then bring contribution actions against each other and seek
reimbursement from their insurance companies. As a result of the Superfund Act
or other laws or regulations regarding the remediation of waste, Dominion may
be required to expend amounts on remedial investigations and actions. Dominion
does not believe that any currently identified sites will result in
significant liabilities. For additional information regarding environmental
matters see Item 3. LEGAL PROCEEDINGS below, FUTURE ISSUES--Environmental
Matters on page 35 and Note Q to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on
page 51 of the 1999 Annual Report to Shareholders.
In accordance with applicable federal and state environmental laws, the
Dominion Energy business has applied for or obtained the necessary
environmental permits material to the operation of its generating stations.
Many of these permits are subject to reissuance and continuing review.
6
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Nuclear Generation
All aspects of the operation and maintenance of Virginia Power's nuclear
power stations, which are a part of the Dominion Energy business, 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 nuclear
generating units.
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
SNF. The federal government has not made such a repository available.
In July 1995, the Virginia Commission instituted an investigation regarding
SNF disposal. As directed, Virginia Power and others filed comments on legal
and public policy issues related to SNF storage and disposal. In February
1996, the Virginia Commission Staff filed its report recommending that
adoption of a definitive policy on SNF disposal issues be delayed pending the
outcome of litigation against DOE concerning SNF acceptance, the outcome of
proposed federal legislation concerning development of an interim storage
facility and development of a vision of the likely outcome of the electric
utility industry's restructuring efforts. The Virginia Commission consolidated
the proceeding with Virginia Power's pending fuel cost recovery proceeding in
October 1996. In March 1997, the Virginia Commission returned the SNF disposal
issue to a separate proceeding. No procedural order has been issued, but the
proceeding is pending.
In response to DOE's insufficient progress towards providing a permanent
repository for SNF, in January 1997, Virginia Power and numerous other
electric utilities requested the United States Court of Appeals for the
District of Columbia Circuit (the DC Circuit) to order DOE to begin accepting
the utilities' SNF for disposal by January 31, 1998. In November 1997, the DC
Circuit found that DOE's obligation to begin accepting SNF by the deadline is
"unconditional" and that DOE may not excuse its delay on the grounds that
delays were unavoidable. In February 1998, Virginia Power and other electric
utilities requested the DC Circuit to require DOE to begin moving SNF,
prohibit DOE from using the Nuclear Waste Fund (NWF) to pay damages and
relieve utilities of their obligation to pay NWF fees unless and until DOE
complies with its obligations. In May 1998, the DC Circuit refused to require
DOE to begin moving SNF and found that utilities should pursue their remedies
under their SNF contracts with DOE. In November 1998, the U.S. Supreme Court
denied DOE's request for review of the DC Circuit's decisions. Virginia Power
is considering whether to seek other remedies.
When Virginia Power nuclear units cease to operate, Virginia Power will be
obligated to decontaminate the facilities. This process is referred to as
decommissioning, and Virginia Power is required by the NRC to prepare for it
financially. For information on compliance with the NRC financial assurance
requirements, see Note F to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on page
44 of the 1999 Annual Report to Shareholders.
Virginia Power initiated the license renewal process for its nuclear power
plants in mid-1999 with expected submission to the NRC in late 2003. If
successful, NRC renewed licenses will extend the operation of Virginia Power's
four nuclear units to 2032, 2033, 2038 and 2040 for Surry Units 1 and 2 and
North Anna Units 1 and 2, respectively.
Rates
The majority of Virginia Power's revenue is provided through bundled rate
tariffs. Accordingly, the following discussion applies to both the Dominion
Energy business' utility operations and the Dominion
7
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Delivery business. 1999 electric service sales for Virginia Power included 70
million megawatt-hours of retail sales and 4.1 million megawatt-hours of sales
to wholesale requirements contract customers and were composed of the
following:
<TABLE>
<CAPTION>
1999
------------------
Percent of
Electric Service
------------------
Revenues Kwh Sales
<S> <C> <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 Virginia Power's electric service sales are currently
subject to recovery of changes in fuel costs either through fuel adjustment
factors or periodic adjustments to base rates, each of which requires prior
regulatory approval.
Where cost-based rates are in effect, each of these jurisdictions has the
authority to disallow recovery of costs it determines to be excessive or
imprudently incurred. Various cost items may be reviewed on occasion,
including costs of constructing or modifying facilities, on-going purchases of
capacity or providing replacement power during generating unit outages.
Virginia
Recent Virginia proceedings related to Virginia Power's rates include the
following:
. In June 1998, Virginia Power, the Staff of the Virginia Commission, the
office of the Virginia Attorney General, the Virginia Committee for Fair
Utility Rates and the Apartment and Office Building Association of
Metropolitan Washington agreed to settle its pending rate proceedings
before the Virginia Commission. In August 1998, the Virginia Commission
approved the settlement with only a minor redistribution of the agreed
rate reduction among customer classes. For provisions of the settlement,
see Note C to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on page 43 of
the 1999 Annual Report to Shareholders.
. In August 1998, Virginia Power filed an application with the Virginia
Commission to modify its cogeneration and small power production rates
under Schedule 19. An evidentiary hearing was held on this matter in
February 1999. The Hearing Examiner's report was issued in February 2000.
. In December 1999, Virginia Power filed an application with the Virginia
Commission for an increase in annual fuel revenues of approximately $104
million. A hearing was held in February 2000.
North Carolina
In support of Dominion's request for approval by the North Carolina
Commission of its merger with CNG, Virginia Power and Dominion reached an
agreement with the Public Staff of the North Carolina Commission whereby
Virginia Power agreed not to request an increase in North Carolina retail
electric base rates for both its Dominion Energy business and Dominion
Delivery business until after December 31, 2005, except for certain events
that would have a significant financial impact on Virginia Power. Such events
could include any governmental action or an occurrence that is beyond Virginia
Power's control and not attributable to its fault or negligence. However, fuel
rates are still subject to change under the annual fuel cost adjustment
procedures. The North Carolina Commission approved the merger subject to
conditions agreed to by Dominion and Virginia Power in October 1999.
8
<PAGE>
In September 1999, Virginia Power filed an application with the North
Carolina Commission for a $5.2 million increase in fuel rates for its Dominion
Energy business. In December 1999, the North Carolina Commission approved the
request. This increases the annual fuel rates and charges paid by the retail
customers of North Carolina Power effective on January 1, 2000.
9
<PAGE>
Sources of Power
Dominion Energy--Utility Operations Generating Units
<TABLE>
<CAPTION>
Type Summer
Years Of Capability
Installed Fuel (Mw)
--------- -------------- ----------
Name of Station, Units and Location
-----------------------------------
<S> <C> <C> <C>
Nuclear:
Surry Units 1 & 2, Surry, Va.............. 1972-73 Nuclear 1,602
North Anna Units 1 & 2, Mineral, Va....... 1978-80 Nuclear 1,790(a)
------
Total nuclear stations.................. 3,392
------
Fossil Fuel:
Steam:
Bremo Units 3 & 4, Bremo Bluff, Va...... 1950-58 Coal 227
Chesterfield Units 3-6, Chester, Va..... 1952-69 Coal 1,250
Clover Units 1 & 2, Clover, Va.......... 1995-96 Coal 882(b)
Mt. Storm Units 1-3, Mt. Storm, W. Va... 1965-73 Coal 1,587
Chesapeake Units 1-4, Chesapeake, Va.... 1953-62 Coal 595
Possum Point Units 3 & 4, Dumfries, Va.. 1955-62 Coal 322
Yorktown Units 1 & 2, Yorktown, Va...... 1957-59 Coal 326
Possum Point Units 1, 2, & 5, Dumfries,
Va..................................... 1948-75 Oil 929
Yorktown Unit 3, Yorktown, Va........... 1974 Oil & Gas 818
North Branch Unit 1, Bayard, W. Va...... 1994 Waste Coal 74(c)
Combustion Turbines:
33 units (7 locations).................... 1967-70 Oil & Gas 975
Combined Cycle:
Bellmeade, Richmond, Va................... 1991 Oil & Gas 230
Chesterfield Units 7 & 8, Chester, Va..... 1990-92 Oil & Gas 397
------
Total fossil stations................... 8,612
------
Hydroelectric:
Gaston Units 1-4, Roanoke Rapids, N.C..... 1963 Conventional 225
Roanoke Rapids Units 1-4, Roanoke Rapids,
N.C...................................... 1955 Conventional 99
Other..................................... 1930-87 Conventional 3
Bath County Units 1-6, Warm Springs, Va... 1985 Pumped Storage 1,260(d)
------
Total hydro stations.................... 1,587
------
Total generating unit capability........ 13,591
Net Purchases .............................. 1,245
Non-Utility Generation ..................... 3,273
------
Total Capability........................ 18,109
======
</TABLE>
- --------
(a) Includes an undivided interest of 11.6 percent (208 Mw) owned by Old
Dominion Electric Cooperative (ODEC).
(b) Includes an undivided interest of 50 percent (441 Mw) owned by ODEC.
(c) Returned to service in May 1999.
(d) Reflects Virginia Power's 60 percent undivided ownership interest in the
2,100 Mw station. A 40 percent undivided interest in the facility is owned
by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.
(AE).
Virginia Power's highest one-hour integrated service area summer 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.
10
<PAGE>
Energy Output, Sources of Energy Used, Fuel Costs and Operations
System energy output for Dominion Energy's utility operations by energy
source and the average fuel cost for each are shown below. Fuel cost is
presented in mills (one tenth of one cent) per kilowatt hour.
<TABLE>
<CAPTION>
1999 1998 1997
------------ ------------ ------------
Source Cost Source Cost Source Cost
------ ----- ------ ----- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Nuclear(*)............................... 35% 4.59 33% 4.71 34% 4.52
Coal(**)................................. 38 13.73 42 13.21 40 13.54
Oil...................................... 4 20.47 3 22.52 1 26.32
Purchased power, net..................... 19 23.95 19 21.85 23 21.54
Other.................................... 4 28.98 3 27.27 2 30.65
--- --- ---
Total.................................. 100% 100% 100%
=== === ===
Average fuel cost...................... 13.34 12.71 12.67
</TABLE>
- --------
(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power
Station.
(**) Excludes ODEC's 50 percent ownership interest in the Clover Power
Station.
Dominion Energy--Nuclear Operations and Fuel Supply
. In 1999, the Dominion Energy business' four nuclear units achieved a
combined capacity factor of 95.2 percent.
. Both long-term contracts and spot purchases are utilized to support
its needs for nuclear fuel. Dominion Energy continually evaluate
worldwide market conditions in order to ensure a range of supply
options at reasonable prices. Current agreements, inventories and
spot market availability will support current and planned fuel supply
needs for fuel cycles into the early 2000's. Beyond that period,
additional fuel will be purchased as required to ensure optimum cost
and inventory levels.
. In March 1999, Virginia Power, along with a consortium of companies,
was awarded a contract by DOE for mixed oxide (MOX) fuel fabrication
and reactor irradiation services. Virginia Power has 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 Virginia Power for all plant and site/facility
modifications as well as other MOX fuel implementation costs.
Virginia Power expects to provide irradiation services beginning
September 2007.
. DOE did not begin the acceptance of SNF in 1998 as specified in
Virginia Power's contract with DOE. However, on-site SNF pool and dry
container storage at the Surry and North Anna Power Stations is
expected to be adequate for its needs until DOE begins accepting SNF.
For details on the issues of decommissioning, see Note F on page 44 and for
nuclear insurance, see Note Q to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on
page 51 of the 1999 Annual Report to Shareholders.
Dominion Energy--Fossil Operations and Fuel Supply
The fuel mix utilized by the Dominion Energy business' utility fossil
operations consists of coal, oil and natural gas. During 1999, the fossil
operations burned approximately 12 million tons of coal and utilized both
long-term contracts and spot purchases to support their coal needs. Dominion
Energy presently anticipates sufficient supplies of coal will be available at
reasonable prices for the next 5 to 10 years. A sufficient supply of oil and
natural gas is expected over the same period with stable prices.
11
<PAGE>
Virginia Power uses natural gas as needed throughout the year primarily for
three combined-cycle units and combustion turbine units. For winter usage at
the combined-cycle sites, gas is purchased and stored during the summer and
fall and consumed during the colder months when gas supplies may not be
available. Virginia Power has firm transportation contracts for the delivery
of gas to its Chesterfield combined-cycle units.
Purchases and Sales of Energy
The Dominion Energy business' utility operations purchase electricity under
long-term contracts with other suppliers to meet a portion of its own system
capacity requirements, as well as for short-term sales transactions in the
eastern United States. In addition to wholesale electric power transactions,
Virginia Power also actively participates in the purchase and sale of natural
gas in the open market.
From the mid-1980's until the start of the 1990's, Virginia Power entered
into a number of long-term purchase contracts for electricity now associated
with the Dominion Energy business. 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 will be
suspended. However, Virginia Power continues to have contracts with 56 non-
utility generators with a combined dependable summer capacity of 3,273 Mw.
During 1998, Virginia Power entered into a long-term agreement to purchase 566
Mw of electricity for sale to the wholesale market from two of three
generating units at a plant constructed in Mississippi. For information on the
financial obligations under these agreements, see Purchased Power Contracts,
Note Q to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on page 51 of the 1999
Annual Report to Shareholders.
In a continuing effort to mitigate its exposure to above-market long-term
purchased power contracts, Virginia Power is evaluating its long-term
purchased power contracts and negotiating modifications to their terms,
including cancellations, where it is determined to be economically
advantageous to do so.
In 1997, Virginia Power executed three agreements now associated with both
its Dominion Energy business and its Dominion Delivery business with ODEC
which provide for the amendment of the parties' Interconnection and Operating
Agreement (I&O Agreement). The first agreement provides for the transition
from cost-based rates for capacity and energy purchases by ODEC to market-
based rates by 2002. The second two agreements are the Service and Operating
Agreements for Network Integration Transmission Service, which unbundled the
transmission services provided to ODEC under the I&O Agreement.
Dominion Energy--Future Sources of Power
Both the Hoosier 400 Mw long-term purchase contract and the AEP 500 Mw long-
term purchase contract expired on December 31, 1999. Virginia Power presently
anticipates adding peaking capacity beginning in the year 2000 to meet its
anticipated annual load growth of two percent. In addition, work was completed
and the North Branch unit was returned to service in May 1999.
In May 1999, the Virginia Commission approved the construction of four gas-
fired combustion turbine generator units in Fauquier County, Virginia. A
Petition to Appeal the approved units, filed by an opposing party in July
1999, was dismissed by the Virginia Supreme Court in December 1999; however,
the opposing party filed a request for rehearing in December 1999. The same
party appealed the air permit issued to Virginia Power by the Virginia
Department of Environmental Quality; however, such appeal was withdrawn on
January 18, 2000.
In January 2000, Virginia Power 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. Virginia Power has
obtained the applicable zoning permits for the construction of the generators
and has applied for other required environmental permits. The Virginia
Commission has set a hearing date in May 2000 to consider this request.
Commercial operation is planned to begin in June 2001.
12
<PAGE>
Dominion Delivery--Interconnections
The Dominion Delivery business maintains major interconnections with
Carolina Power and Light Company, AEP, AE and the utilities in the
Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission
network, it has arrangements with these utilities for coordinated planning,
operation, emergency assistance and exchanges of capacity and energy.
In June 1999, Virginia Power, 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 Regional Transmission
Organization (Alliance RTO).
In December 1999, FERC issued an Order under Section 203 of the Federal
Power Act granting the application, subject to certain conditions and
requirements discussed in the Order and directing the Alliance Companies to
submit a compliance filing as discussed in the Order. On January 19, 2000, the
Alliance Companies filed an application seeking rehearing of certain
conditions and requirements of the Order. In February 2000, the Alliance
Companies filed amendments to the Alliance RTO documents to comply with
certain conditions and requirements of the Order.
Also in December 1999, FERC issued Order 2000 which amended its regulations
to advance the formation of Regional Transmission Organizations (RTOs). The
regulations require that each public utility that owns, operates, or controls
transmission facilities make certain filings with respect to forming and
participating in an RTO. FERC also codified minimum characteristics and
functions that a transmission entity must satisfy in order to be considered an
RTO. In January 2000, the Alliance Companies filed an application seeking
rehearing of certain provisions of the Order.
Dominion Energy--Non-Utility Operations
DEI, the entity in which Dominion Energy's non-utility generation operations
are conducted, is active in the competitive electric power generation
business. Dominion Energy's non-utility operations are involved in power
projects in five states, including the Kincaid Power Station, a 1,108 Mw coal-
fired station and Elwood Energy; a 600 Mw gas fired peaking facility in
Illinois; two geothermal projects and one solar project in California; four
small hydroelectric projects in New York; a waste coal-fueled project in West
Virginia and a waste wood- and coal-fueled project in Maine.
For information on the sale of DEI's Latin American assets, see Recent
Developments on page 1 above.
For information regarding Dominion Energy's transition to a competitive
market for electric generation, see the Introduction to MD&A on page 26 and
FUTURE ISSUES--Dominion Energy on page 35 under MD&A of the 1999 Annual Report
to Shareholders.
For additional information concerning foreign operation risks, see MARKET
RATE SENSITIVE INSTRUMENTS AND RISK MANAGEMENT--Foreign Risks on page 38 under
MD&A of the 1999 Annual Report to Shareholders.
For information regarding environmental regulation and Dominion Energy, see
Regulation--Environmental above.
Dominion Exploration & Production
DEI, the entity in which the Dominion E&P business was conducted until the
completion of the CNG merger, is active in the development, exploration and
operation of oil and natural gas reserves. Dominion E&P
13
<PAGE>
is involved in oil and natural gas development and exploration in Canada, the
Appalachian Basin, the Michigan Basin, the Illinois Basin, the Black Warrior
Basin, the Uinta Basin, the San Juan Basin, the Gulf Coast and the Mid-
Continent, and owns net proved oil and natural gas reserves in key regions of
the United States and Canada.
For additional information concerning foreign operation risks, see MARKET
RATE SENSITIVE INSTRUMENTS AND RISK MANAGEMENT--Foreign Risks on page 38 under
MD&A of the 1999 Annual Report to Shareholders.
For additional information on industry structure and competitive factors
relevant to the Dominion E&P business, see CNG--Gas Competition--Exploration
and Production below.
FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHIC AREAS
See Note (R) to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on page 53 of the
1999 Annual Report to Shareholders.
Dominion Capital
Dominion Capital is a diversified financial services company with several
operating subsidiaries in the commercial lending, merchant banking and
residential lending business. Its principal subsidiaries are First Source
Financial, LLP, First Dominion Capital LLC and Saxon Mortgage, Inc. Dominion
Capital also owns a 46 percent interest in Cambrian Capital LLP.
First Source Financial provides cash-flow and asset-based financing to
middle-market companies seeking to expand, recapitalize or undertake buyouts.
First Dominion Capital is an integrated merchant banking and asset management
business located in New York. Saxon Mortgage and its affiliates originate and
securitize home equity and mortgage loans to individuals. Cambrian Capital
provides financing to small and mid-sized independent oil and natural gas
producers undertaking acquisitions, refinancings and expansions.
For additional information, see FUTURE ISSUES--Dominion Capital under MD&A
on page 36 of the 1999 Annual Report to Shareholders.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM--
DOMINION ENERGY, DOMINION DELIVERY AND DOMINION E&P
See LIQUIDITY AND CAPITAL RESOURCES under MD&A on pages 29 through 32 of the
1999 Annual Report to Shareholders.
CNG
CNG operates in all phases of the natural gas industry including exploration
for and production of oil and natural gas in the United States as well as
Canada. Its various retail gas subsidiaries serve approximately 1.9 million
residential, commercial, industrial and transportation customers in Ohio,
Pennsylvania, Virginia and West Virginia. Its interstate gas transmission
pipeline system services each of its distribution subsidiaries and non-
affiliated utilities and end use customers in the Midwest, the Mid-Atlantic
and the Northeast states. CNG has an equity ownership interest in a pipeline
extending from Canada to New York and New England.
Government Regulation
CNG remains subject to regulation under the 1935 Act. CNG Transmission and
Consolidated LNG are "natural-gas companies" subject to the Natural Gas Act of
1938, as amended. CNG Transmission's interstate
14
<PAGE>
transportation and storage activities are regulated under such Act and are
conducted in accordance with tariffs and service agreements on file with FERC.
CNG Power Services and CNG Retail, public utilities as defined by section 201
of the Federal Power Act, are also subject to limited FERC regulation. The
distribution subsidiaries are subject to regulation by the utility commissions
in the states within which they operate. Additionally, CNG Retail is
classified as a public utility in Pennsylvania for the limited purpose of its
participation in the Pennsylvania electric retail access programs.
Certain CNG subsidiaries are subject to various provisions of the five
statutes which 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.
The Natural Gas Pipeline Safety Act of 1968 (which, among other things,
authorizes the establishment and enforcement of federal pipeline safety
standards) subjects the interstate pipeline of CNG Transmission to the safety
jurisdiction of 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.
CNG is subject to the provisions of various federal laws dealing with the
protection of the environment. CNG Transmission and certain of the
distribution subsidiaries are subject to the Federal Clean Air Act and the
Federal Clean Air Act Amendments of 1990 which added significantly to the
existing requirements established by the Clean Air Act. In addition, the
subsidiary companies are subject to the environmental laws and regulations of
state and local governmental authorities in the areas within which the
subsidiaries have operations or facilities.
CNG has an interest in the following foreign utility and pipeline companies:
an electric utility company in Argentina, which is subject to regulation at
the federal and provincial level; Argentine gas utility companies, which are
regulated at the federal level; pipelines in Australia, which are currently
subject to state regulation, and will become subject to national regulation
being developed by the Commonwealth and state and territorial governments.
Gas Competition
Various regulatory and market trends have combined to increase competition
for CNG in recent years, and for the energy industry in general. These factors
include: federal and state regulatory efforts, such as FERC's various
initiatives to increase competition in both the gas and electric industries;
the overall availability of energy nationwide; competition from producers and
other sellers and brokers of gas for the retail and wholesale markets;
expansion of competition among distribution companies for industrial and
commercial customers; competition with existing and proposed pipelines and
projects to import gas from Canada and other foreign countries; and
competition with other energy forms, such as electricity, fuel oil and coal.
FERC Order No. 636 (Order 636) significantly increased competition in the
natural gas industry. In the restructured marketplace, local gas utilities and
large-volume end users, including former pipeline sales customers, bear all
the responsibilities and risks for arranging the procurement of their gas
supplies and contracting with pipelines to transport purchases. However, as
CNG distribution subsidiaries had been managing a part of their own gas
supplies for a number of years, the transition to a more competitive
environment under Order 636 did not have a significant impact on their
operations. Storage facilities owned and operated as part of CNG distribution
and transmission operations, as well as acquired storage capacity, have become
even more important factors in gas supply management.
Gas and Electric Industry Developments
Gas industry competition at the retail level is receiving increased
attention from both regulators and legislators. Governments in three of the
states in which CNG operates distribution subsidiaries have enacted or
considered legislation regarding deregulation of natural gas at the retail
level. In Ohio, a 1996 law established
15
<PAGE>
customer choice as a state policy in the supply of natural gas services.
Implementation of the law, which allows retail customers to obtain gas from an
array of suppliers, is under way. In Pennsylvania, legislation was enacted to
unbundle gas utility merchant functions and permit the Pennsylvania Public
Utility Commission to certify marketers, in addition to gas utilities, as
suppliers of last resort, creating competition in a traditional gas utility
function. Virginia is currently operating under a one-year unbundling pilot
program, enacted in 1999. The Virginia General Assembly is currently
considering legislation to make the program permanent.
In addition to 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. Regulators and legislators at the federal level
and in many states are considering, or are already implementing, initiatives
to promote increased competition in the electric industry. A major development
was the issuance in 1996 of FERC Orders 888 and 889. By requiring open access
to the national electric transmission grid, Order 888 fosters increased
competition in both the generation of electricity and the supply of bulk power
to major wholesale customers. The companion order, Order 889, addresses the
timing, information access and other administrative details associated with
FERC deregulation initiative. Congress also is considering legislation
intended to facilitate the move to competition in the electric industry.
Although progress status varies, pro-competition electric legislation is at
least under consideration in many states. In Ohio, legislation enacted in 1999
will allow all consumers to choose their electric supplier beginning January
1, 2001. In Pennsylvania, all consumers may now choose their supplier.
Competition is also forthcoming in Virginia, where in 1999 the General
Assembly passed the "Utility Restructuring Act" which will phase in customer
choice between 2002 and 2004. Regulators and legislators in West Virginia are
also debating issues related to electric industry restructuring.
Recent and pending regulatory actions may serve to further facilitate more
business combinations in the energy industry. FERC has streamlined its
regulatory review process regarding pending mergers.
Distribution
Distribution subsidiaries generally operate in long-established service
areas and have extensive facilities already in place. Growth in CNG's
traditional service areas in Ohio, Pennsylvania and West Virginia is limited
in that natural gas is already the fuel of choice for heating and for most
significant industrial applications. These areas have experienced minimal
population growth in recent years, and almost all customers have become more
energy efficient, resulting in lower gas usage per customer. In addition, the
economies of these areas, which were formerly based mainly on heavy industry,
have diversified with increased emphasis on high technology and service-
oriented firms. Growth in the retail sales market has largely been at VNG, due
to customer conversions from other energy sources and the past expansion of
its service territory (for additional information, see Recent Developments
above).
The Clean Air Act may also provide opportunities for increased throughput in
CNG's distribution markets. CNG is promoting the use of natural gas as a means
for industrial customers and electric generators to reduce emissions. The
Clean Air Act and the Energy Policy Act of 1992 contain a number of provisions
relating to the use of alternative fuel vehicles. CNG is participating in
various programs to demonstrate the advantages and environmental benefits of
natural gas powered vehicles.
Competition in the markets served by the distribution subsidiaries continues
to increase. As the gas industry has restructured and government regulations
have changed, a marketplace has evolved with new and traditional competitors--
the usual oil and electric companies, other gas companies, producers seeking
to gain direct access to CNG's customers, and gas brokers and dealers seeking
to supplant supplies with spot market gas. Natural gas faces price competition
with other energy forms, and certain of the distribution companies' industrial
customers have the ability to switch to fuel oil or coal if desired. In
addition, competition is increasing among local distribution companies to
provide gas sales and transportation services to commercial and residential
customers.
16
<PAGE>
Currently, local distribution companies operate in what are essentially dual
markets--a traditional utility market, where a utility has an obligation to
provide service and offers a "bundled" package of services to all customers;
and a "contract" market, where obligations are defined by contract terms. In
the latter market, large customers can elect individually or in various
combinations whatever gas supplies, storage and/or transportation services
they require. CNG has responded to this competitive environment by offering a
variety of firm and interruptible services, including gas transportation,
storage, supply pooling and balancing, and brokering, to industrial and
commercial customers. Also, residential customers in certain of CNG's service
territories can choose an alternative source of gas supply.
Transmission
CNG Transmission operates a regional interstate pipeline system with the
principal pipeline and storage facilities located in Ohio, Pennsylvania, West
Virginia and New York. CNG Transmission offers gas transportation, storage and
related services to its affiliates, as well as to utilities and end users in
the Northeast, Mid-Atlantic and Midwest regions of the country.
The changing regulatory environment has provided CNG Transmission and other
pipeline companies with a number of opportunities for expansion. CNG
Transmission has taken advantage of selected market expansion opportunities,
concentrating its efforts primarily in the Northeast and along the East Coast.
CNG Transmission'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. CNG'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 (see Gas and Electric Industry
Developments above).
CNG Transmission 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
CNG Transmission to tailor its services to meet the individual needs of
customers.
Exploration and Production
Exploration and production operations are conducted by CNG Producing in
several of the major gas and oil producing basins in the United States, both
onshore and offshore. In this highly competitive business, CNG 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.
CNG Producing faces significant competition in the bidding for federal
offshore leases and in obtaining leases and drilling rights for onshore
properties. Since CNG Producing is the operator of a number of properties, it
also faces competition in securing drilling equipment and supplies for
exploration and development.
The marketing of gas and oil is highly competitive with price being the most
significant factor. Gas producers throughout the industry, including CNG
Producing, face a diverse and active market with purchasers seeking to balance
the advantage of spot market supplies with the security of longer-term
contracts. The growth of gas and energy marketing firms has added to the
competition for CNG Producing. When the economics warrant, CNG 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 CNG's gas production.
Further, the deliverability of gas produced is influenced by competition for
downstream pipeline transportation capacity. CNG continues to develop
marketing strategies, contracts and arrangements to address customer needs for
intermediate and long-term gas supplies as well as swing, peaking
17
<PAGE>
and other energy services. In addition, in the ordinary course of business,
CNG Producing participates in price risk management activities to manage
exposure to price risk in connection with the production and sale of natural
gas and oil.
The exploration for and production of gas and oil is subject to various
federal and state laws and regulations which may, among other things, address
environmental matters and limit well drilling activity and volumes produced.
Changes in these laws and regulations can impact the exploration and
production operations.
Gas Supply
General
CNG'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 CNG's and third party
underground storage fields.
Regulatory actions, economic factors, and changes in customers and their
preferences continue to reshape CNG's gas sales markets. A significant number
of industrial and commercial customers and a growing number of residential
customers currently purchase a large portion of their gas supplies from
producers and marketers, and contract with the transmission and/or
distribution subsidiaries for transportation and other services. Since these
customers are less reliant on the distribution subsidiaries for sales service,
the volume of gas that these subsidiaries must obtain to meet sales
requirements has been reduced. This trend is likely to continue as the state
regulators continue unbundling services at the retail level. With the
exception of Hope Gas, the distribution subsidiaries continue to purchase gas
supplies for their remaining merchant customers and recover the costs through
their approved rates. CNG Retail and Hope Gas (under a negotiated rate
moratorium through December 31, 2001) have the responsibility and assume the
price risk for obtaining its own gas supplies to meet customer needs.
CNG's available gas supply in 1999 was again in a surplus position--where
available supplies exceeded sales requirements. Considering CNG's large
storage capacity, the volumes obtainable under its firm interstate pipeline
capacity and gas supply contracts, CNG-owned gas reserves, and assuming the
future availability of spot market gas, CNG believes that supplies will be
available to meet sales requirements for at least the next several years.
Gas Purchased
CNG has continued to purchase volumes from the 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. Gas purchase contract
terms have continued to undergo transformation initiated with the removal of
CNG Transmission and other gas pipelines from the merchant function. Much of
the supply is purchased under seasonal or spot purchase agreements. While the
average term of CNG's gas purchase agreements has declined, the reliability of
supply has been adequate. The availability of supplies and heightened
competition have forged a viable market which has proven capable of satisfying
the firm delivery requirement for supplies to CNG's markets in a highly
reliable manner.
At December 31, 1999, CNG's subsidiaries had 347.3 Bcf of firm annual
transport capacity on various pipelines to move supplies from purchase
locations to market, yielding deliveries of up to 0.9 Bcf of gas a day. These
pipelines include CNG Transmission, Tennessee Gas Pipeline Company, Panhandle
Eastern Pipe Line Company, Texas Eastern Transmission Corporation, ANR
Pipeline Company, Texas Gas Transmission Corporation, Transcontinental Gas
Pipe Line Corporation, Columbia Gas Transmission Corporation, Columbia Gulf
Transmission Company, Trunkline Gas Company, National Fuel Gas Supply
Corporation and Equitrans, Inc.
18
<PAGE>
Gas Storage
CNG's underground storage facilities play an important part in balancing gas
supply with sales demand and are essential to servicing CNG's large volume of
space-heating business. In addition, storage capacity is an important element
in the effective management of both gas supply and pipeline transport
capacity. CNG operates 26 underground gas storage fields located in Ohio,
Pennsylvania, West Virginia and New York. CNG owns 21 of these storage fields
and has joint-ownership with other companies in five of the fields. The total
designed capacity of the storage fields is approximately 885 Bcf. CNG's share
of the total capacity is about 669 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.
CNG Transmission operates 719 Bcf of the total designed storage capacity and
owns 503 Bcf of CNG's capacity. CNG Transmission utilizes a large portion of
its turnable capacity to provide approximately 265 Bcf of gas storage service
for others. This service is provided principally to affiliates, end users and
many of CNG Transmission's former wholesale gas sales customers who primarily
serve consumers in the Northeast.
Two of the distribution subsidiaries, East Ohio Gas and Peoples Natural Gas,
own and operate the remaining 166 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 CNG
Transmission. CNG's distribution subsidiaries also have capacity available in
storage fields owned by others. CNG 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.
Gas and Oil Producing Activities
CNG's total gas production in 1999 amounted to 181.6 Bcf, and oil production
was 10.3 million barrels.
CNG's gas wellhead prices in 1999 averaged $2.25 a thousand cubic feet
(Mcf). CNG's average gas wellhead prices are generally higher and less
volatile than industry spot prices since its average price reflects a mix of
longer-term contracts and the impact of price risk management activities.
However, due to market-based pricing mechanisms under many of the contracts,
CNG's gas prices generally follow industry trends. The average oil wellhead
price in 1999 was $13.19 a barrel, consistent with the general increase in
world oil prices. CNG's average oil wellhead prices also reflect the impact of
price risk management activities.
The following table sets forth 1999 drilling activity by region:
<TABLE>
<CAPTION>
Wells Drilled
-------------------------
Exploratory Development
------------ ------------
Gross Net Gross Net
------ ----- ------ -----
<S> <C> <C> <C> <C>
Onshore (Southwest and
West) 9 4 9 9
Gulf of Mexico 10 6 12 5
Appalachian Region 7 3 38 36
Canada -- -- 10 2
----- ----- ----- -----
Total 26 13 69 52
===== ===== ===== =====
</TABLE>
Of the total 95 wells drilled in 1999, 83 were successful. Of the 26
exploratory wells drilled, 16 were successful.
19
<PAGE>
Gas Sales, Supply, Transportation and Storage Statistics
(Continuing operations--excludes affiliated transactions)
<TABLE>
- -------------------------------------------------------------------------------
<CAPTION>
Years Ended December 31, 1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gas Sales Revenues
(Millions)
Regulated
Residential $1,109.3 $1,089.9 $ 1,449.1 $1,346.1 $1,214.2
Commercial 274.2 267.6 369.7 361.6 345.9
Industrial 12.5 13.4 22.8 30.6 32.6
Wholesale 1.2 2.8 9.4 15.4 4.7
Nonregulated 607.9 494.4 433.4 396.1 239.8
-------- -------- --------- -------- --------
Total(a) $2,005.1 $1,868.1 $ 2,284.4 $2,149.8 $1,837.2
======== ======== ========= ======== ========
Average Sales Rates per Mcf
Regulated
Residential $ 6.51 $ 6.82 $ 6.97 $ 6.15 $ 5.71
Commercial 5.71 6.04 6.19 5.41 4.95
Industrial 5.22 5.32 5.33 4.47 4.49
Wholesale (b) (b) (b) (b) (b)
Nonregulated 2.48 2.39 2.53 2.48 1.94
Weighted average $ 4.30 $ 4.51 $ 5.16 $ 4.74 $ 4.44
======== ======== ========= ======== ========
Gas Requirements (Bcf)
Regulated gas sales
Residential 170.4 159.9 207.8 218.7 212.5
Commercial 48.1 44.3 59.7 66.8 69.8
Industrial 2.4 2.5 4.3 6.9 7.3
Wholesale .2 .4 .2 1.8 .3
Nonregulated gas sales 244.9 207.1 171.0 159.7 123.5
-------- -------- --------- -------- --------
Total sales 466.0 414.2 443.0 453.9 413.4
Used and unaccounted for 59.4 37.7 29.0 23.3 37.8
-------- -------- --------- -------- --------
Total requirements 525.4 451.9 472.0 477.2 451.2
======== ======== ========= ======== ========
Gas Supply (Bcf)
Purchased gas 325.7 294.8 295.9 353.2 323.5
Storage (input) withdrawal 18.1 (.4) 18.0 (23.5) 20.5
Gas Produced
Gulf region 123.0 111.4 116.5 108.1 68.3
Appalachian area 28.1 26.6 25.8 26.0 27.2
Other areas 30.5 19.5 15.8 13.4 11.7
-------- -------- --------- -------- --------
Total produced 181.6 157.5 158.1 147.5 107.2
-------- -------- --------- -------- --------
Total supply 525.4 451.9 472.0 477.2 451.2
======== ======== ========= ======== ========
Purchased Gas Costs
(Millions)(c) $ 911.7 $ 900.4 $ 1,114.1 $ 963.2 $ 864.6
-------- -------- --------- -------- --------
Average Purchase Rates per
Mcf(c) $ 2.94 $ 2.95 $ 3.39 $ 3.37 $ 2.73
-------- -------- --------- -------- --------
Gas Transportation
Revenues (Millions) $ 442.5 $ 416.7 $ 369.1 $ 297.9 $ 345.2
-------- -------- --------- -------- --------
Gas Transported (Bcf) 660.1 641.2 736.0 754.0 743.3
======== ======== ========= ======== ========
Gas Stored at December 31
(Bcf) 377.0 397.2 407.2 426.2 406.4
======== ======== ========= ======== ========
</TABLE>
- --------
(a) Amount for 1999 includes total gas revenues of $190.2 million attributable
to VNG.
(b) Demand charges and low sales volumes produce an average rate which is not
meaningful.
(c) Includes transportation charges.
20
<PAGE>
International Activities
CNG International engages in energy-related activities outside of the United
States and holds equity investments in Australia and Latin America. During the
fourth quarter of 1999, CNG decided to focus on the United States oil and gas
markets and, accordingly, has now begun exploring the sale of CNG
International. CNG International's net assets totaled $251 million at December
31, 1999.
Rate Matters
The regulated subsidiaries continue to seek general rate increases 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 distribution companies make separate filings with
their respective regulatory commissions to reflect changes in the costs of
purchased gas. CNG's regulated subsidiaries filed no new general rate cases
during 1999, nor were there any outstanding cases requiring settlement.
CNG Properties
CNG's main properties and investments are located in Pennsylvania, Ohio,
Virginia, West Virginia, New York and from the Midwest, Mid-Atlantic and
Northeast states including Canada, Argentina and Australia.
CNG's total gross investment in property, plant and equipment was $9 billion
at December 31, 1999 (this total excludes $546.1 million of property, plant
and equipment attributable to VNG, the net assets of which were classified as
held for sale at December 31, 1999). The largest portion of this investment
(59%) is in facilities located in the Appalachian area. Another significant
portion (28%) is located in the Gulf of Mexico.
Of the $9 billion investment, $4.6 billion is in production and gathering
systems, of which 66% is invested in the Gulf of Mexico and the Gulf coast and
21% in the Appalachian area. CNG's production subsidiary, CNG Producing,
accounts for $4.1 billion of the $4.6 billion investment, and CNG Transmission
and the distribution subsidiaries account for the remaining $.5 billion. In
addition to wells (58 productive and 7 dry) and acres (1,993,340 gross and
1,562,493 net developed and 862,740 gross and 499,215 net undeveloped), this
investment includes 6,660 miles of gathering lines which are located almost
entirely within the Appalachian area.
CNG's investment in its gas distribution network includes 26,515 miles of
pipe, exclusive of service pipe, the cost of which represents 61% of the $1.7
billion invested in the total function.
CNG's storage operation consists of 26 storage fields, 334,050 acres of
operated leaseholds, 2,067 storage wells and 798 miles of pipe. The investment
in storage properties is $711 million, including $56 million of cushion gas
stored.
Of the $1.6 billion invested in transmission facilities, 66% represents the
cost of 6,814 miles of pipe required to move large volumes of gas throughout
CNG's operating area.
CNG has 94 compressor stations with 484,435 installed compressor horsepower.
Some of the stations are used interchangeably for several functions.
CNG's investment in its natural gas system is considered suitable to do all
things necessary to bring gas to the consumer. CNG's properties (including the
properties of VNG) provided the capacity to meet a record system peak day
sendout, including transportation service, of 11.4 Bcf (of which .4 Bcf was
attributable to VNG) on February 6, 1995. The system peak day sendout in 1999
was 8.0 Bcf (of which .3 Bcf was attributable to VNG) on January 5.
ITEM 2. PROPERTIES
Dominion leases its principal executive offices in Richmond, Virginia. It
owns the principal executive office building of Virginia Power in Richmond,
Virginia. CNG's principal executive office building in Pittsburgh,
Pennsylvania is leased. Dominion's assets consist primarily of its investments
in its subsidiaries, the principal properties of which are described in Item
1. BUSINESS above under the following headings:
21
<PAGE>
. Dominion Energy--Utility Operations and Dominion Delivery (Virginia
Power)--Sources of Power-- Dominion Energy--Utility Operations
Generating Units
. Dominion Energy--Non-Utility Operations
. Dominion E&P
. CNG--CNG Properties
Because our business segments include operations conducted in more than one
legal entity and some of our subsidiary legal entities operate in more that
one business segment, our segments share many of our facilities, particularly
office facilities.
In connection with a portion of the Dominion Delivery business that Virginia
Power operates, 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.
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 in 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 Virginia Power under Item 1. BUSINESS for
information on various regulatory proceedings.
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 its 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 Virginia Power'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 in December
1999 submitted revised FRP and SPCC plans. Presently, the EPA has not assessed
any penalties against Virginia Power pending its review of Virginia Power's
disclosure information. Future resolution of these matters is not expected to
have a material impact on Virginia Power's financial condition or results of
operations.
In November 1999 and September 1999, Virginia Power received notices from
the Attorney Generals of Connecticut and New York, respectively, of their
intention to file suit against Virginia Power for alleged violations of the
Clean Air Act. The notices question whether modifications at certain Virginia
Power generating facilities were properly permitted under the Clean Air Act
and allege that emissions from these facilities have damaged public health and
the environment in the Northeast. To date, no suits have been filed. Virginia
Power believes that it is one of a number of companies with fossil fuel power
generating stations in the southeast and central U.S. to have received such
notifications. Virginia Power believes that it has obtained the permits
necessary in connection with its generating facilities and that any suits
filed by the Attorney Generals will not have a material impact on its
financial condition or results of operations.
22
<PAGE>
On August 1990, CNG Transmission entered into a Consent Order and Agreement
with the Commonwealth of Pennsylvania Department of Environmental Protection
(DEP) in which CNG 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, CNG Transmission continues to perform sampling, testing and
analysis, and conducts a program of remediation at some of its Pennsylvania
facilities. Total remediation costs in connection with these sites and the
Order and Agreement are not expected to be material with respect to CNG's
financial position, results of operations or cash flows. CNG has recognized an
estimated liability amounting to $6.7 million at December 1999, 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.
The DEP has proposed a penalty of $380,000 related to a hydrocarbon spill in
February 1998 at a CNG Transmission facility in Aliquippa, Beaver County,
Pennsylvania. CNG Transmission has agreed to settle the matter by contributing
$280,000 to a Supplemental Environmental Program (SEP) and $100,000 directly
to the DEP. Under the SEP, several environmental programs will be undertaken
which are intended to benefit the Conversation District of Beaver County,
Pennsylvania.
In April 1999, CNG was served with a purported Class Action Complaint, Civil
Action No. 17114-NC, styled Gerold Garfinkel v. Raymond E. Galvin, Paul E.
Lego, Margaret A. McKenna, William S. Barrack, Jr., Steven A. Minter, J. W.
Connolly, George A. Davidson, Jr., Richard P. Simmons, and Consolidated
Natural Gas Company. The Complaint was filed in the Delaware Court of Chancery
in April 1999. The Complaint seeks injunctive relief in the form of an order
to the individual Board members to sell CNG for the highest value to the
shareholders, an accounting of any damages resulting from any failure to sell
it for the highest value, a determination with respect to the reasonableness
of the break-up fee in the agreement with Dominion and other miscellaneous
relief. The Complaint also seeks an award of costs and attorneys' fees.
Several additional purported Class Action Complaints against CNG and its
directors seeking essentially the same relief have been combined with this
action. CNG has moved to dismiss. In February 2000, the plaintiff filed a
status report indicating they will circulate a stipulation for dismissal
without prejudice.
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 in July 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 in May 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 CNG.
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 in September 1999, alleged fraud, misrepresentation, conversion
and assorted other claims, in the measurement and payment of gas royalties
from privately held gas leases. The cases have been moved to the U.S. District
Court of Kansas, pending consolidation with the Grynberg case.
CNG believes the above complaints to be without merit and believes that the
ultimate resolution of the issues will not have a material adverse effect on
CNG's financial position, results of operations, or cash flows.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
23
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
<TABLE>
<CAPTION>
Name and Age Business Experience Past Five Years
------------ -----------------------------------
<C> <S>
George A. Davidson, Jr. (61) Chairman of the Board of Directors of Dominion and
Chairman and Chief Executive Officer of Consolidated
Natural Gas Company from January 28, 2000 to date;
Chairman and Chief Executive Officer of Consolidated
National Gas Company prior to January 28, 2000.
Thos. E. Capps (64) Vice Chairman of the Board of Directors, President and
Chief Executive Officer of Dominion from January 28,
2000 to date; 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 (54) 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; President and Chief Executive Officer of
Dominion Energy from October 1, 1994 to May 1, 1999;
Senior Vice President of Dominion Resources prior to
January 1, 1997.
Thomas F. Farrell, II (45) Executive Vice President of Dominion and Chief
Executive Officer of Virginia Electric and Power
Company Dominion Energy, Inc. and Dominion Generation,
Inc. from May 1, 1999 to date; Senior Vice President-
Corporate Affairs 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 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.
David L. Heavenridge (53) Executive Vice President of Dominion from January 1,
1997 to date and Chief Executive Officer of Dominion
Capital from February 1, 2000 to date; President and
Chief Executive Officer of Dominion Capital prior to
January 1, 1997.
James P. O'Hanlon (56) Executive Vice President of Dominion and President,
Chief Operating Officer and Chief Nuclear Officer of
Virginia Electric and Power Company, Dominion
Generation, Inc. from May 1, 1999 to date; Senior Vice
President-Nuclear of Virginia Electric and Power
Company prior to May 1, 1999.
Robert E. Rigsby (50) 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 Virginia Electric and Power Company,
January 1, 1996 to April 30, 1999; Senior Vice
President-Finance and Controller, prior to January 1,
1996.
H. Patrick Riley (62) Executive Vice President of Dominion from January 28,
2000 to date; President CNG Producing Company prior to
January 28, 2000.
Edgar M. Roach, Jr. (51) 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; 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.
</TABLE>
24
<PAGE>
<TABLE>
<CAPTION>
Name and Age Business Experience Past Five Years
------------ -----------------------------------
<C> <S>
James L. Trueheart (48) Group Vice President and Controller of Dominion from
January 28, 2000 to date; Senior Vice President and
Controller from November 1, 1998 to January 28, 2000; Vice
President and Controller prior to November 1, 1998.
G. Scott Hetzer (43) 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; Vice President and Treasurer from October 1, 1997
to May 1, 1999; Managing Director of Wheat First Butcher
Singer prior to October 1, 1997.
James L. Sanderlin (58) Senior Vice President-Law of Dominion from September 15,
1999 to date; Partner in the law firm of McGuire, Woods,
Battle & Boothe LLP prior to September 15, 1999.
Eva S. Teig (55) 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 May 1, 1999; Vice President-External Affairs and
Corporate Communications, June 1, 1997 to September 1,
1997; Vice President-Public Affairs prior to June 1, 1997.
</TABLE>
25
<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, 1999 there were 101,367 common shareholders of record.
Quarterly information concerning stock prices and dividends contained on page
56 of the 1999 Annual Report to Shareholders for the fiscal year ended
December 31, 1999 in Note W to NOTES TO CONSOLIDATED FINANCIAL STATEMENTS,
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 60 of the 1999 Annual Report to Shareholders for the
fiscal year ended December 31, 1999, 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 26 through
38 of the 1999 Annual Report to Shareholders for the fiscal year ended
December 31, 1999, filed herein as Exhibit 13, is hereby incorporated herein
by reference.
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 Non-Trading Activities
.Foreign Exchange Risk Activities
.Commodity Price Risk Non-Trading Activities
.Commodity Price Risk Trading Activities
.Equity Price Risk Activities
.Other
under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS on pages 37 and 38 of the 1999 Annual Report to
Shareholders for the fiscal year ended December 31, 1999, 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
21 through 25, NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on pages 39 through
57 and related report thereon of Deloitte & Touche LLP, independent auditors,
appearing on page 58 of the 1999 Annual Report to Shareholders for the fiscal
year ended December 31, 1999, filed herein as Exhibit 13, is hereby
incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
26
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of Dominion contained in the 2000 Proxy
Statement, under the heading The Board, File No. 1-8489, dated March 16, 2000
(the 2000 Proxy Statement), is hereby incorporated herein by reference. The
information concerning the executive officers of Dominion required by this
item is following 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
2000 Proxy Statement, is hereby 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 2000 Proxy Statement, is hereby incorporated herein by reference. There is
no person known by Dominion Resources to be the beneficial owner of more than
five percent of Dominion Resources common stock.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
27
<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>
1999
Annual Report
to Shareholders
(Page)
---------------
<S> <C>
Report of Independent Auditors................................. 58
Report of Management's Responsibilities........................ 58
Consolidated Statements of Income for the years ended December
31, 1999, 1998 and 1997....................................... 21
Consolidated Balance Sheets at December 31, 1999 and 1998...... 22-23
Consolidated Statements of Shareholders'
Equity and Consolidated Statements of Comprehensive Income
for the years ended December 31, 1999, 1998 and 1997.......... 24
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997.............................. 25
Notes to Consolidated Financial Statements..................... 39-57
</TABLE>
28
<PAGE>
2. 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) - Bylaws as in effect on October 15, 1999 (Exhibit 3, Form 10-Q
for the quarter ended September 30, 1999, File No. 1-8489,
incorporated by reference).
4(i) - See Exhibit 3(i) above.
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).
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).
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).
</TABLE>
29
<PAGE>
<TABLE>
<C> <C> <S>
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)
Eleventh Supplemental Indenture dated as of December 1, 1988
(Exhibit (5) to Certificate of Notification at Commission File
No. 70-7079)
Thirteenth Supplemental Indenture dated as of February 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File
No. 70-7336)
Fourteenth Supplemental Indenture dated as of June 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File
70-7336)
Fifteenth Supplemental Indenture dated as of October 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File
No. 70-7651)
Sixteenth Supplemental Indenture dated as of October 1, 1992
(Exhibit (4) 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 (4 A)(iii), Form 10-K for the fiscal year ended
December 31, 1999, File No. 1-3196, incorporated by
reference).
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)
4(ix) - 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).
</TABLE>
30
<PAGE>
<TABLE>
<C> <C> <S>
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).
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. (filed
herewith).
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 16, 1999 (Exhibit 10(i), Form 10-Q for the
quarter ended March 31, 1999, 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, 1997 (Exhibit 10 (xxvi), Form 10-K for the fiscal
year ended December 31, 1996, incorporated by reference).
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 and David L.
Heavenridge (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 and First Amendment
for David L. Heavenridge (Exhibit 10(iii) and Exhibit 10(ii),
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).
</TABLE>
31
<PAGE>
<TABLE>
<C> <C> <S>
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)* - Employment Agreement, dated May 26, 1989 between Virginia
Power and James P. O'Hanlon (Exhibit 10.22, Form 10-K for the
fiscal year ended December 31, 1999, File No. 1-2255,
incorporated by reference).
10(xxvii)* - Form of Reimbursement Agreement between certain executive
officers and Dominion Resources (filed herewith).
10(xxviii)* - Employment Agreement dated October 8, 1999 between Virginia
Power and James P. O'Hanlon (Exhibit 10.23, Form 10-K for the
fiscal year ended December 31, 1999, File No. 1-2255,
incorporated by reference).
11 - Computation of Earnings Per Share of Common Stock Assuming
Full Dilution (filed herewith).
13 - Portions of the 1999 Annual Report to Shareholders for the
fiscal year ended December 31, 1999(filed herewith).
21 - Subsidiaries of the Registrant (filed herewith).
23 - Consent of Deloitte & Touche LLP (filed herewith).
27 - Financial Data Schedule (filed herewith).
</TABLE>
- --------
* Indicates management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
Dominion filed a report on Form 8-K, dated January 3, 2000, relating to the
Virginia State Corporation Commission's final approval of the merger with
Consolidated Natural Gas Company.
Dominion filed a report on Form 8-K, dated February 1, 2000, relating to the
completion of the merger with Consolidated Natural Gas Company.
32
<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.
Thos E. Capps
By: _________________________________
(Thos E. Capps, Vice Chairman of
the Board of Directors,President,
Chief Executive Officer)
Date: March 7, 2000
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 7th day of March, 2000.
<TABLE>
<CAPTION>
Signature Title
--------- -----
<C> <S>
William S. Barrack, Jr. Director
______________________________________
William S. Barrack, Jr.
John B. Bernhardt Director
______________________________________
John B. Bernhardt
Thos E. Capps Vice Chairman of the Board of Directors, President,
______________________________________ Chief Executive Officer
Thos E. Capps
George A. Davidson, Jr. Chairman of the Board of Directors
______________________________________
George A. Davidson, Jr.
Raymond E. Galvin Director
______________________________________
Raymond E. Galvin
Ray J. Groves Director
______________________________________
Ray J. Groves
John W. Harris Director
______________________________________
John W. Harris
Benjamin J. Lambert, III Director
______________________________________
Benjamin J. Lambert, III
Richard L. Leatherwood Director
______________________________________
Richard L. Leatherwood
Paul E. Lego Director
______________________________________
Paul E. Lego
</TABLE>
33
<PAGE>
<TABLE>
<CAPTION>
Signature Title
--------- -----
<C> <S>
Margaret A. McKenna Director
______________________________________
Margaret A. McKenna
______________________________________ Director
Steven A. Minter
K. A. Randall Director
______________________________________
K. A. Randall
Frank S. Royal Director
______________________________________
Frank S. Royal
S. Dallas Simmons Director
______________________________________
S. Dallas Simmons
Robert H. Spilman Director
______________________________________
Robert H. Spilman
David A. Wollard Director
______________________________________
David A. Wollard
Thomas N. Chewning Executive Vice President
______________________________________ (Chief Financial Officer)
Thomas N. Chewning
J. L. Trueheart Group Vice President and Controller
______________________________________ (Principal Accounting Officer)
</TABLE> J.L. Trueheart
34
<PAGE>
DOMINION RESOURCES, INC.
PORTIONS
OF THE
1999
ANNUAL REPORT
TO
SHAREHOLDERS
(Incorporated by Reference)
<PAGE>
EXHIBIT 10 (vii)
DRI Services Agreement
This DRI Services Agreement (this "Agreement") is entered into as of the
28th day of January, 2000, by and between DOMINION RESOURCES, INC., a Virginia
corporation (the "Company"), DOMINION RESOURCES SERVICES, INC., a Virginia
corporation, ("DRI Services"), and CONSOLIDATED NATURAL GAS SERVICE COMPANY,
INC., a Delaware corporation ("CNG Services"). DRI Services and CNG Services are
sometimes referred to herein as a "Service Company" and, collectively, as the
"Service Companies".
WHEREAS, each of the Company, DRI Services and CNG Services is a direct or
indirect wholly owned subsidiary of Dominion Resources, Inc. ("DRI");
WHEREAS, each of the Service Companies has been formed for the purpose of
providing administrative, management and other services to DRI and its
subsidiaries ("System Companies"); and
WHEREAS, the Company believes that it is in the interest of the Company to
provide for an arrangement whereby the Company may, from time to time and at the
option of the Company, agree to purchase such administrative, management and
other services from either one or both of the Service Companies;
NOW, THEREFORE, in consideration of the mutual covenants contained herein
and other valuable consideration, the receipt and sufficiency of which are
hereby acknowledged, the parties hereto, intending to be legally bound, hereby
agree as follows:
I. SERVICES OFFERED. Exhibit I hereto lists and describes all of the
----------------
services that are available from either of the Service Companies. Each of the
Service Companies hereby offers to supply those services to Company and to other
subsidiaries of DRI. Such services are and will be provided to the Company only
at the request of the Company.
II. SERVICES SELECTED.
-----------------
A. Initial Selection of Services. Exhibit II lists the services Company
hereby agrees to receive from DRI Services. Exhibit III lists the services
Company hereby agrees to receive from CNG Services.
B. Annual Selection of Services. Each Service Company shall send an
annual service proposal form to the Company on or about December 1 listing
services proposed for the coming calendar year. By December 31, the Company
shall notify each Service Company of the services it has elected to receive from
that Service Company during the following calendar year.
1
<PAGE>
III. PERSONNEL. The Service Companies will provide services by utilizing
---------
the services of such executives, accountants, financial advisers, technical
advisers, attorneys, engineers, geologists and other persons as have the
necessary qualifications.
If necessary, the Service Companies, after consultation with the Company,
may also arrange for the services of nonaffiliated experts, consultants and
attorneys in connection with the performance of any of the services supplied
under this Agreement.
IV. COMPENSATION AND ALLOCATION. As and to the extent required by law,
---------------------------
the Service Companies will provide such services at cost. Exhibit IV hereof
contains rules for determining and allocating costs for DRI Services and CNG
Services.
V. TERMINATION AND MODIFICATION.
----------------------------
A. Modification of Services. The Company may modify its selection of
services at any time during the calendar year by giving the relevant Service
Company written notice of the additional services it wishes to receive, and/or
the services it no longer wishes to receive, from the Service Company. The
requested modification in services shall take effect on the first day of the
first calendar month beginning at least thirty (30) days after the Company sent
written notice to the Service Company.
B. Modification of Other Terms and Conditions. No other amendment, change
or modification of this Agreement shall be valid, unless made in writing and
signed by all parties hereto.
C. Termination of this Agreement. The Company may terminate this
Agreement as to either or both of the Service Companies by providing sixty (60)
days advance written notice of such termination to the applicable Service
Company or Companies. Either Service Company may terminate this Agreement as to
the Company by providing sixty (60) days advance written notice of such
termination to the Company. The parties expressly agree that termination of this
Agreement by the Company as to one of the Service Companies shall not constitute
a termination of this Agreement with respect to the other Service Company and
that termination of this Agreement by either Service Company shall not affect
the obligations of the other Service Company hereunder to the Company.
This Agreement is subject to termination or modification at any time to the
extent its performance may conflict with the provisions of the Public Utility
Holding Company Act of 1935, as amended ("1935 Act), or with any rule,
regulation or order of the Securities and Exchange Commission ("SEC") adopted
before or after the making of this Agreement. This Agreement shall be subject to
the approval of any state commission or other state regulatory body whose
approval is, by the laws of said state, a legal prerequisite to the execution
and delivery or the performance of this Agreement.
2
<PAGE>
VI. NOTICE. Where written notice is required by this Agreement, said
------
notice shall be deemed given when mailed by United States registered or
certified mail, postage prepaid, return receipt requested, addressed as follows:
a. To the Company:
120 Tredegar Street
Richmond, Virginia 23219
b. To DRI Services:
120 Tredegar Street
Richmond, Virginia 23219
c. To CNG Services:
CNG Tower
625 Liberty Avenue
Pittsburgh, Pennsylvania 15222-3199
VII. GOVERNING LAW. This Agreement shall be governed by and construed in
-------------
accordance with the laws of the respective states of incorporation of the
Service Companies, without regard to their respective conflict of laws
provisions.
VIII. ENTIRE AGREEMENT. This Agreement, together with its exhibits,
----------------
constitutes the entire understanding and agreement of the parties with respect
to its subject matter, and effective upon the execution of this Agreement by the
respective parties hereof and thereto, any and all prior agreements,
understandings or representations with respect to this subject matter (except
for completion of obligations of CNG Services and Consolidated Natural Gas
Company ("CNG") and its subsidiaries arising before the merger of DRI and CNG
became effective) are hereby terminated and canceled in their entirety and are
of no further force or effect.
IX. WAIVER. No waiver by any party hereto of a breach of any provision of
------
this Agreement shall constitute a waiver of any preceding or succeeding breach
of the same or any other provision hereof.
X. ASSIGNMENT. This Agreement shall inure to the benefit of and shall be
----------
binding upon the parties and their respective successors and assigns. No
assignment of this Agreement or any party's rights, interests or obligations
hereunder may be made without the other party's consent, which shall not be
unreasonably withheld, delayed or conditioned.
XI. SEVERABILITY. If any provision or provisions of this Agreement shall
------------
be held to be invalid, illegal, or unenforceable, the validity, legality, and
enforceability of the remaining provisions shall in no way be affected or
impaired thereby.
3
<PAGE>
XII. EFFECTIVE DATE. This Agreement is effective as of January 28, 2000.
--------------
IN WITNESS WHEREOF, the parties have caused this Agreement to be duly
executed as of the date first above mentioned.
Attest: By Company:
_____________________________ ____________________________________________
Name: G. Scott Hetzer
Title: Senior Vice President and Treasurer
Attest: By DRI Services:
_____________________________
____________________________________________
Name: Thomas N. Chewning
Title: Executive Vice President and CFO
Attest: By CNG Services:
_____________________________ ____________________________________________
Name:
Title:
4
<PAGE>
EXHIBIT I
DESCRIPTION OF SERVICES OFFERED BY EACH
SERVICE COMPANY UNDER THIS AND SIMILAR SERVICE CONTRACTS
1. Accounting. Provide advice and assistance to System Companies in
----------
accounting matters, including the development of accounting practices,
procedures and controls, the maintenance of the general ledger and related
subsidiary systems, the preparation and analysis of financial reports, and the
processing of certain accounts such as accounts payable, payroll, customer and
cash management.
2. Auditing. Periodically audit the accounting records and other
--------
records maintained by System Companies and coordinating their examination, where
applicable, with that of independent public accountants. The audit staff will
report on their examination and submit recommendations, as appropriate, on
improving methods of internal control and accounting procedures.
3. Legal and Regulatory. Provide advice and assistance with respect
--------------------
to legal and regulatory issues as well as regulatory compliance, including 1935
Act authorizations and compliance and regulatory matters under other Federal and
State laws.
4. Information Technology, Electronic Transmission and Computer
------------------------------------------------------------
Services. Provide the organization and resources for the operation of an
- --------
information technology function including the development, implementation and
operation of a centralized data processing facility and the management of a
telecommunications network. This function includes the central processing of
computerized applications and support of individual applications in System
Companies. Develop, implement, and process those computerized applications for
System Companies that can be economically best accomplished on a centralized
basis.
5. Software Pooling. Accept from System Companies ownership of and
----------------
rights to use, assign, license or sub-license all software owned, acquired or
developed by or for System Companies which System Companies can and do transfer
or assign to it. Preserve and protect the rights to all such software to the
extent reasonable and appropriate under the circumstances; license System
Companies, on a non-exclusive, no-charge or at-cost basis, to use all software
which the relevant Service Company has the right to sell, license or sub-
license; and, at the relevant System Companies' expense, permit System Companies
to enhance any such software and license others to use all such software and
enhancements to the extent that the relevant Service Companies shall have the
legal right to so permit.
<PAGE>
6. Employee Benefits/Pension Investment. Provide central accounting
------------------------------------
for employee benefit and pension plans of System Companies. Advise and assist
System Companies in the administration of such plans and prepare and maintain
records of employee and company accounts under the said plans, together with
such statistical data and reports as are pertinent to the plans.
7. Employee Relations. Advise and assist System Companies in the
------------------
formulation and administration of employee relations policies and programs
relating to the relevant System Companies' labor relations, personnel
administration, training, wage and salary administration and safety.
8. Operations. Advise and assist System Companies in the study,
----------
planning, engineering and construction of energy plant facilities of each System
Company and of the System as a whole, and advise, assist and manage the
planning, engineering (including maps and records) and construction operations
of System Companies. Develop long-range operational programs for all the System
Companies and advise and assist each such System Company in the coordination of
such programs with the programs of the other System Companies.
9. Executive and Administrative. Advise and assist System Companies
----------------------------
in the solution of major problems and in the formulation and execution of the
general plans and policies of System Companies. Advise and assist System
Companies as to operations, the issuance of securities, the preparation of
filings arising out of or required by the various Federal and State securities,
business, public utilities and corporation laws, the selection of executive and
administrative personnel, the representation of System Companies before
regulatory bodies, proposals for capital expenditures, budgets, financing,
acquisition and disposition of properties, expansion of business, rate
structures, public relationships and other related matters.
10. Business and Operations Services. Advise and assist System
--------------------------------
Companies in all matters relating to operational capacity and the preparation
and coordination of operating studies. Manage System Companies' purchase, sale,
movement, transfer and accounting of volumes to ensure continued recovery of all
prudently incurred energy purchase costs through local jurisdictional cost
recovery mechanisms. Compile and communicate information relevant to system
operation. Perform general business and operations support services, including
business, plant and facilities operation, maintenance and management, travel,
aviation, fleet and mail services.
11. Exploration and Development. Advise and assist System Companies
---------------------------
in all geological and exploration matters including the acquisition and
surrender of acreage and the development of underground storage facilities.
12. Risk Management. Advise and assist System Companies in securing
---------------
requisite insurance, in the purchase and administration of all property,
casualty and marine insurance, in the settlement of insured claims and in
providing risk prevention advice.
2
<PAGE>
13. Marketing. Plan, formulate and implement marketing programs, as
---------
well as provide associated marketing services to assist System Companies with
improving customer satisfaction, load retention and shaping, growth of energy
sales and deliveries, energy conservation and efficiency. Assist System
Companies in carrying out policies and programs for the development of plant
locations and of industrial, commercial and wholesale markets and assist with
community redevelopment and rehabilitation programs.
14. Medical. Direct and administer all medical and health activities
-------
of System Companies. Provide systems of physical examination for employment
and other purposes and direct and administer programs for the prevention of
sickness.
15. Corporate Planning. Advise and assist System Companies in
------------------
studying and planning in connection with operations, budgets, economic
forecasts, capital expenditures and special projects.
16. Procurement. Advise and assist System Companies in the
-----------
procurement of real and personal property, materials, supplies and services,
conduct purchase negotiations, prepare procurement agreements and administer
programs of material control.
17. Rates. Advise and assist System Companies in the analysis of
-----
their rate structure in the formulation of rate policies and in the negotiation
of large contracts. Advise and assist System Companies in proceedings before
regulatory bodies involving the rates and operations of System Companies and of
other competitors where such rates and operations directly or indirectly affect
System Companies.
18. Research. Investigate and conduct research into problems
--------
relating to production, utilization, testing, manufacture, transmission, storage
and distribution of energy. Keep abreast of and evaluate for System Companies
all research developments and programs of significance affecting System
Companies and the energy industry, conduct research and development in promising
areas and advise and assist in the solution of technical problems arising out of
System Companies' operations.
19. Tax. Advise and assist System Companies in the preparation of
---
Federal and other tax returns, and generally advise System Companies as to any
problems involving taxes including the provision of due diligence in connection
with acquisitions.
20. Corporate Secretary. Provide all necessary functions required of
-------------------
a publicly held corporation; coordinating information and activities among
shareholders, the transfer agent, and Board of Directors; providing direct
services to security holders; preparing and filing required annual and interim
reports to shareholders and the SEC; conducting the annual meeting of
shareholders and ensuring proper maintenance of corporate records.
21. Investor Relations. Provide fair and accurate analysis of DRI
------------------
and its operating subsidiaries and its outlook within the financial community,
enhancing DRI's
3
<PAGE>
position in the energy industry; balancing and diversifying shareholder
investment in DRI through a wide range of activities; providing feedback to DRI
and its operating subsidiaries regarding investor concerns, trading and
ownerships; holding periodic analysts meetings; and providing various operating
data as requested or required by investors.
22. Environmental Compliance. Provide consulting, cleanup, and other
------------------------
activities as required by System Companies to ensure full compliance with
applicable environmental statutes and regulations.
23. Customer Services. Provide services and systems dedicated to
-----------------
customer service, including billing, remittance, credit, collections, customer
relations, call centers, energy conservation support and metering.
24. Energy Marketing. Provide services and systems dedicated to
----------------
energy marketing, including marketing and trading of gas and electric power, and
energy price risk management and development of marketing and sales programs in
physical and financial markets.
25. Treasury/Finance. Provide services related to managing all
----------------
administrative activities associated with financing, including management of
capital structure; cash, credit and risk management activities; investment and
commercial banking relationships; oversight of decommissioning trust funds and
general financing activities.
26. External Affairs. Provide services in support of corporation
----------------
strategies for managing relationships with federal, state and local governments,
agencies and legislative bodies. Formulate and assist with public relations and
communications programs and administration of corporate contribution and
community affairs programs.
4
<PAGE>
EXHIBIT II
SERVICES THE COMPANY AGREES TO RECEIVE FROM DRI SERVICES
SERVICE YES NO
1. Accounting ____ ____
2. Auditing ____ ____
3. Legal and Regulatory ____ ____
4. Information Technology, Electronic Transmission
and Computer Services ____ ____
5. Software Pooling ____ ____
6. Employee Benefits/Pension Investment ____ ____
7. Employee Relations ____ ____
8. Operations ____ ____
9. Executive and Administrative ____ ____
10. Business and Operations Services ____ ____
11. Exploration and Development ____ ____
12. Risk Management ____ ____
13. Marketing ____ ____
14. Medical ____ ____
15. Corporate Planning ____ ____
16. Procurement ____ ____
17. Rates ____ ____
18. Research ____ ____
19. Tax ____ ____
20. Corporate Secretary ____ ____
21. Investor Relations ____ ____
22. Environmental Compliance ____ ____
23. Customer Services ____ ____
24. Energy Marketing ____ ____
25. Treasury/Finance ____ ____
26. External Affairs ____ ____
<PAGE>
EXHIBIT III
SERVICES THE COMPANY AGREES TO RECEIVE FROM CNG SERVICES
SERVICE YES NO
1. Accounting ____ ____
2. Auditing ____ ____
3. Legal and Regulatory ____ ____
4. Information Technology, Electronic Transmission
and Computer Services ____ ____
5. Software Pooling ____ ____
6. Employee Benefits/Pension Investment ____ ____
7. Employee Relations ____ ____
8. Operations ____ ____
9. Executive and Administrative ____ ____
10. Business and Operations Services ____ ____
11. Exploration and Development ____ ____
12. Risk Management ____ ____
13. Marketing ____ ____
14. Medical ____ ____
15. Corporate Planning ____ ____
16. Procurement ____ ____
17. Rates ____ ____
18. Research ____ ____
19. Tax ____ ____
20. Corporate Secretary ____ ____
21. Investor Relations ____ ____
22. Environmental Compliance ____ ____
23. Customer Services ____ ____
24. Energy Marketing ____ ____
25. Treasury/Finance ____ ____
26. External Affairs ____ ____
<PAGE>
EXHIBIT IV
METHODS OF ALLOCATION FOR CNG SERVICES AND DRI SERVICES
CNG Services and DRI Services shall allocate costs independently. Each Service
Company shall allocate costs among companies receiving service from it under
this and similar service contracts using the following methods:
I. The costs of rendering service by the Service Company will include all
costs of doing business including interest on debt but excluding a return
for the use of equity capital for which no charge will be made to System
Companies.
II. A. The Service Company will maintain a separate record of the expenses of
each department. The expenses of each department will include:
1. those expenses that are directly attributable to such department,
and
2. an appropriate portion of those office and housekeeping expenses
that are not directly attributable to a department but which are
necessary to the operation of such department.
B. Expenses of the department will include salaries and wages of
employees, rent and utilities, materials and supplies, depreciation,
and all other expenses attributable to the department. The expenses of
a department will not include:
1. those incremental out-of-pocket expenses that are incurred for
the direct benefit and convenience of an individual company or
group of companies,
2. Service Company overhead expenses, including expenses of the
corporate secretary's department that are attributable to
maintaining the corporate existence of the Service Company, and
all other incidental overhead expenses including those auditing
fees, internal auditing department expenses and accounting
department expenses attributable to the Service Company.
C. The Service Company will establish annual budgets for controlling the
expenses of each department and for determining estimated costs to be
included in interim monthly billing.
III. A. Employees in each department will be divided into two groups:
<PAGE>
1. Group A will include those employees rendering service to System
Companies, and
2. Group B will include those office and general service employees,
such as secretaries, file clerks and administrative assistants,
-----------------------------
who generally assist employees in Group A or render other
housekeeping services and who are not engaged directly in
rendering service to each Company or a group of companies.
B. Expenses set forth in Section II. above will be separated to show:
1. salaries and wages of Group A employees, and
2. all other expenses of the department.
C. There will be attributed to each dollar of a Group A employee's salary
or wage, that percentage of all other expenses of his department (as
defined in B above), that his salary or wage is to the total Group A
salaries and wages of that department.
D. Group A employees in each department will maintain a record of the
time they are employed in rendering service to each company or group
of companies. An hourly rate will be determined by dividing the total
expense attributable to a Group A employee as determined under
subsection C above by the productive hours reported by such employee.
IV. The charge to the Company for a particular service will be determined by
multiplying the hours reported by Group A employees in rendering such
service to each Company by the hourly rates applicable to such employees.
When such employees render service to a group of companies, the charge to
each Company will be determined by multiplying the hours attributable to
the Company under the allocation formulas set forth in Section IX of this
Exhibit by the hourly rates applicable to such employees.
V. To the extent appropriate and practical, the foregoing computations of
hourly rates and charges may be determined for groups of employees within
reasonable salary range limits.
VI. Those expenses of the Service Company that are not included in the annual
expense of a department under Section II. above will be charged to System
Companies receiving service as follows:
A. Incremental out-of-pocket costs incurred for the direct benefit and
convenience of a company or group of companies will be charged
directly to such company or group of companies. Such costs incurred
for a group of companies will be allocated on the basis of an
appropriate formula.
2
<PAGE>
B. Service Company overhead expenses referred to in Section II. above
will be charged to the Company in the proportion that the charges
made to the Company for costs, other than those set forth in this
Section VI., are to the total of such charges to all companies
receiving service.
VII. Notwithstanding the foregoing basis of determining cost allocations for
billing purposes, cost allocations for certain services involving machine
operations and production units will be determined on an appropriate basis
established by the Service Company relating to the direct use of machine
equipment or production units.
VIII. Monthly bills will be issued for the services rendered to the Company on
an actual or estimated basis. Estimates will normally be predicated on
service department budgets and estimated productive hours of employees for
the year. At the end of each year, estimated figures will be revised to
reflect actual experience during such year and adjustments will be made in
amounts billed to give effect to such revision.
IX. When Group A employees render services to a group of companies, the
following formulas shall be used to allocate the time of such employees to
the individual companies receiving such service:
A. The Service Department or Function formulas to be used when employees
render services to all companies participating in such service, for
the services indicated are set forth below. When necessary during the
period 1999-2002, the allocation formulas described below will be
calculated (in part or in whole) using data based on services
performed for System Companies Dominion Resources, Inc., prior to the
merger of Dominion Resources, Inc. and Consolidated Natural Gas
Company.
Service Department
or Function Basis of Allocation
----------- -------------------
Employee Benefits/ The number of employee and annuitant
Pension Investments accounts as of the preceding December 31st.
Human Resources The number of employees as of the preceding
December 31st.
Corporate Planning:
- Capital Budgets Total investment in plant recorded at
preceding December 31st.
- Operating &
Maintenance Budgets Total operating expenses, excluding
purchased gas expense, purchased power
expense (including fuel expenses), other
purchased products and royalties, for the
preceding year ended December 31st.
3
<PAGE>
Service Department
or Function Basis of Allocation
----------- -------------------
Business and Operations Energy sale and deliveries for the preceding
Services year ended December 31st.
Risk Management Insurance premiums for the preceding year
ended December 31st.
Rates Total regulated company operating expenses,
excluding purchased gas expense, purchased
power expense (including fuel expense),
other purchased products and royalties, for
the preceding year ended December 31st.
Research Gross revenues from the sale of natural gas
(including intercompany sales) and
electricity, recorded during the preceding
year ended December 31st.
Tax The sum of the total income and total
deductions as reported for Federal Income
Tax purposes on the last return filed.
Corporate Secretary/ The weighted average of the previous three
Investor Relations years of total Service Company billings for
the prior years ended December 31st.
Customer Services For metering, the number of gas or electric
meters for the preceding year ended December
31st; otherwise the number of customers for
the preceding year ended December 31st.
System Services Group:
Information Technology:
LDC/EDC Computer Applications Number of residential and commercial
customers at the end of the preceding year
ended December 31st.
Other Computer Applications Number of users or usage of specific
computer systems at the end of the preceding
year ended December 31st.
4
<PAGE>
Service Department
or Function Basis of Allocation
----------- -------------------
Network Computer Applications Number of network devices at the end of the
preceding year ended December 31st.
Telecommunications Applications Number of telecommunications units at the
end of the preceding year ended December
31st.
Facility Services:
Building Services Square footage of office space as of the
preceding year ended December 31st.
Processing Services:
Payroll Number of employees on the previous December
31st or the number of payroll payments
generated during the previous year ending
December 31st.
Cash Management & Number of customer payments processed during
Customer Payment Processing the preceding year ended December 31st.
Accounts Payable Processing Number of accounts payable documents
processed during the preceding year ended
December 31st.
Fleet Administration Number of vehicles at December 31st.
Purchasing Dollar value of contract purchases for the
preceding year ended December 31st.
Regulated Business Support Group:
Engineering Services:
General Services Gas pipeline and/or electric supply line
footage as of the preceding year ended
December 31st.
Transmission and Storage Total investment in storage and transmission
Services plant as of the preceding year ended
December 31st.
Gas Supply: Gas volumes purchased for each affiliate for
the preceding year ended December 31st.
Electricity Supply: Electricity load purchased for each
affiliate for the preceding year ended
December 31st.
5
<PAGE>
Service Department
or Function Basis of Allocation
----------- -------------------
Marketing
Shared Projects Annual marketing plan budget for the current
year of allocation.
Other Indirect Costs Total marketing direct and shared project
costs billed to each System Company for the
preceding year ended December 31st.
Material Management Material inventory assets as of the
preceding year ended December 31st.
System Accounting:
Financial Accounting and Reporting Number of financial related transactions,
records and reports generated, and account
code combinations for the preceding year
ended December 31st.
Regulated Fixed Assets Regulated companies fixed assets added,
retired or transferred during the preceding
year ended December 31st.
B. Company Group Formulas to be used in the absence of a service
department or function formula or when service rendered by employees
is for a different group of companies than those companies regularly
participating in such service:
Company Group Basis of Allocation
All companies (includes all Total operating expenses, excluding
System Companies except Service purchased gas expense, purchased power
Company) expense (including fuel expense), other
purchased products and royalties, for the
preceding year ended December 31st.
All retail companies Volume of gas and quantity of electricity
sold at retail during the preceding year
ended December 31st (converted to dollar
value).
All wholesale companies Gross revenues from sales for resale
recorded during the preceding year ended
December 31st.
6
<PAGE>
All companies having Gross investment in transmission plant
transmission lines recorded at preceding December 31st.
All production companies Production plant budget for the current year
of allocation.
Appalachian production Gross investment in Appalachian production
companies plant recorded at preceding December 31st.
All storage companies Gross investment in storage plant, excluding
non-current inventory, recorded at preceding
December 31st.
All Companies/ The weighted average of the previous three
Shareholder Activities years of Service Company billings.
All unregulated companies Total unregulated companies' operating
expenses, excluding purchased gas expense,
purchased power expense (including fuel
expense), other purchased products and
royalties, for the preceding year ending
December 31st.
All regulated companies Total regulated companies' operating
expenses, excluding purchased gas expense,
purchased power expense (including fuel
expense), other purchased products and
royalties, for the preceding year ended
December 31st.
C. If the use of a basis of allocation would result in an inequity
because of a change in operations or organization, then the Service
Company may adjust the basis to effect an equitable distribution.
7
<PAGE>
Exhibit 10 (xxvii)
FORM OF REIMBURSEMENT AGREEMENT
This Reimbursement Agreement is made as of _______________, 2000 by
__________________________________________________, residing at
_______________________, _______________________ (the "Employee") and Dominion
Resources, Inc., (the "Company").
Preliminary Statements
A. The Board of Directors of the Company has established the 2000
Executive Stock Purchase and Loan Program under the Dominion Resources, Inc.
Incentive Compensation Plan (the "Stock Purchase Program"). Under the Stock
Purchase Program, eligible employees of the Company and its parents or
Subsidiaries may borrow money to exercise options to acquire common stock of the
Company ("Common Stock") and receive financing from various lenders for which
Bank One, NA is acting as administrative agent (collectively, the "Lender").
B. The Employee wishes to obtain a loan or loans (collectively, the
"Loan") from the Lender in an aggregate principal amount not in excess of ten
(10) times the Employee's annual salary for the purpose of acquiring Common
Stock under the Stock Purchase Program, paying any income taxes from the
restricted share match under the Stock Purchase Program, and paying any income
taxes from the exercise of related stock options. The promissory note
evidencing the Loan is referred to as the "Note".
C. To induce the Lender to make loans to employees participating in the
Stock Purchase Program, the Company has entered a Facility and Guaranty
Agreement (the "Facility Agreement") dated as of ____________, 1999 among the
Company, the Lender and Bank One, NA, as Agent for the Lender. Under the
Facility Agreement, the Company has guaranteed all loans made to employees by
the Lender pursuant to the Facility Agreement as well as the payment by the
employees of certain related amounts (the "Guaranty"). Each term used and not
otherwise defined shall have the same meaning as in the Facility Agreement, a
copy of which has been provided to the Employee.
D. The Employee wishes to induce the Company to designate Employee as a
loan recipient under the Facility Agreement and thereby facilitate the making of
the Loan (which will be guaranteed by the Company pursuant to the Guaranty).
Accordingly, the Employee has agreed to execute and deliver this Agreement in
favor of the Company under which the Employee will reimburse the Company on
demand for all amounts paid by the Company to the Lender under the Guaranty with
respect to the Loan.
Therefore, the Employee and the Company agree as follows:
Section 1. Absolute and Unconditional Reimbursement Obligation. The
Employee absolutely and unconditionally agrees to reimburse the Company fully
and promptly, upon demand, for all amounts paid by the Company to the Lender
pursuant to the Guaranty with respect to the Loan. The Employee shall also
reimburse the Company for any interest on all such
<PAGE>
amounts from the date paid by the Company until repayment by the Employee at
the rate of 8% per annum. However, the Employee shall have no obligation to
reimburse the Company for any Early Payment Fee that becomes due as a result of
the occurrence of a Program Event of Default or other circumstance in which the
Participant is not obligated to pay the Early Payment Fee under the Stock
Purchase Program, or for the Company's payment of interest on behalf of the
Employee under the Stock Purchase Program prior to an Event of Default. This
Agreement shall be a continuing agreement. The liability of the Employee shall
be absolute and unconditional, shall be performed strictly in accordance with
the terms of this Agreement and shall not be affected by reason of: (i) any
assignment, renewal, modification or extension of the Loan or of the Guaranty;
(ii) any modification or waiver of or change in any of the terms, covenants,
conditions or provisions of the Loan or of the Guaranty; (iii) any dealings or
transactions occurring between the Lender and the Company (including without
limitation any amendment of the Facility Agreement) whether or not notice is
given to the Employee; (iv) any default or failure of the Employee fully to
perform any of its obligations, covenants or agreements with respect to the
Loan or as set forth in this Agreement; (v) the invalidity or lack of
enforceability of the Loan or the Guaranty or any provision of them; or
(vi) any other circumstance which might otherwise constitute a defense available
to, or a discharge of, the Employee in respect of the Loan or the Employee in
respect of this Agreement.
Section 2. Right of Setoff. Upon the occurrence and during the
continuance of any Event of Default (as defined below), the Company is
authorized at any time from time to time, without notice to the Employee (any
such notice being expressly waived by the Employee) to set off and apply any and
all amounts owing by the Company to the Employee or any property of the Employee
in the possession of the Company against any and all of the obligations of the
Employee under this Agreement, whether or not the Company shall have made any
demand under this Agreement. This right of setoff includes, without limitation,
base salary (to the extent permitted by law) and bonuses, but excludes any
"margin stock" (as defined in Regulation U of the Board of Governors of the
Federal Reserve System). The Company agrees promptly to notify the Employee
after any setoff and application, but the failure to give notice shall not
affect the validity of the setoff and application. The rights of the Company
under this Section are in addition to the other rights and remedies which the
Company may have. The following events shall constitute an "Event of Default"
under this Agreement: (a) any breach by the Employee of or default by the
Employee under this Agreement; (b) any representation or warranty made, or any
financial or other information provided by, the Employee to the Company, in
connection with this Agreement, shall prove to have been incorrect in any
material respect when made or provided; and (c) the occurrence of any Borrower
Event of Repayment (as defined in the Note).
Section 3. Representations and Warranties. The Employee represents and
warrants to the Company as follows:
(a) The Employee has all right and power to enter into this Agreement,
perform its obligations hereunder and consummate the contemplated
transactions.
(b) This Agreement constitutes a legal, valid and binding obligation of
the Employee, enforceable against the Employee in accordance with its
terms.
-2-
<PAGE>
(c) Neither the execution and delivery of this Agreement, nor compliance
by the Employee with the terms hereof, will violate any statute,
regulation or ordinance of any governmental authority or conflict
with, or result in the breach of any term, condition or provision of,
any agreement, contract, order or instrument to which the Employee is
a party or by which his/her assets or properties are bound or
constitute a default (or an event which, with the lapse of time or the
giving of notice or both, would constitute a default) thereunder.
(d) There is not pending or, to the best of the Employee's knowledge,
threatened any suit, claim, action, litigation or proceeding,
administrative or judicial, or any governmental investigation against
the Employee or involving any of his/her properties or assets which
may reasonably be expected to have a material adverse effect on the
Employee's ability to meet his/her obligations under this Agreement.
(e) No representation or warranty of the Employee in or pursuant to this
Agreement, including any financial or other information provided by
the Employee to the Company in connection with the Stock Purchase
Program, contains or will contain any untrue statement of a material
fact, or omits to state, or will omit to state, any material fact
necessary in order to make the statements, in the light of the
circumstances under which they are made, not misleading.
Section 4. Covenants of the Employee. The Employee agrees that:
(a) so long as all or any portion of the Loan remains outstanding and
unpaid, or the Guaranty remains in effect, or any amount is owing to
the Company hereunder:
(i) the ratio of the liquidation value of the Liquid Assets (as
defined below) of the Employee to the aggregate amount of
the indebtedness for money borrowed of the Employee (other
than residential mortgage indebtedness) and the credit card
or similar indebtedness of the Employee shall be greater
than or equal to 1.0 to 1.0;
(ii) the Employee shall promptly provide to the Company such information
with respect to the Employee as the Company may from time to time
reasonably request to confirm compliance with (i) and (ii) above
(which information the Company shall keep confidential and make
available only to employees of the Company responsible for
administering the Stock Purchase Program); and
(iii) the Employee shall not voluntarily pre-pay any portion of the Loan
except in the case of (a) the Employee's death; (b) the Employee's
retirement on or after the Employee's early retirement date or
normal retirement date as defined in the Dominion Resources, Inc.
Retirement Plan; (c) the Employee's hardship as defined in the
Stock Purchase Program; (d) the approval of the Company's Chief
Executive Officer or the Company's Organization, Compensation
and Nominating Committee; or (e) the Company's change of control
as defined in the Stock Purchase Program.
-3-
<PAGE>
(b) The Employee shall use the proceeds of the Loan solely for the
purposes described in the Note.
For purposes of this Agreement, "Liquid Assets" shall mean all cash,
marketable securities, Common Stock (whether or not purchased with the
proceeds of the Loan), unexercised and vested options of the Employee to
buy Common Stock valued at the excess of market value over the exercise
price, money market funds, other assets of the Employee which can be
readily liquidated within 30 days and net owner-occupied residential real
estate equity if such residential real estate is owned entirely by the
Employee or by the Employee and his/her spouse.
Section 5. Indemnification. The Employee agrees to indemnify, defend and
hold the Company harmless from and against all demands, claims, actions or
causes of action, assessments, losses, damages, liabilities, cost and expenses,
including without limitation, interest, penalties and reasonable attorneys' fees
and expenses asserted against, resulting to, imposed upon or incurred directly
by the Company by reason of or resulting from a breach of any representation,
warranty or covenant of the Employee contained in or made pursuant to this
Agreement.
Section 6. Agreement of the Company. The Company agrees to pay to the
Agent for the account of the Employee any Early Payment Fee payable by the
Employee pursuant to the Note that becomes due as a result of an acceleration of
the Loan as a result of the occurrence of a Program Event of Default. To the
extent that at any time the Employee pays any such Early Payment Fee to the
Agent, the Company shall reimburse the Employee for the amount upon demand.
Section 7. Amendments, Etc. No amendment or waiver of any provision of
this Agreement shall be effective unless it is in writing and signed by the
Company, and any waiver shall be effective only in the specific instance and for
the specific purpose for which given.
Section 8. Waiver of Notice, Etc. The Employee waives promptness,
diligence, notice of acceptance and any other notice with respect to this
Agreement and any requirement that the Company protect, secure, perfect or
insure any security interest or lien or any property subject thereto or exhaust
any right or take any action against any person or entity.
Section 9. Governing Law. This Agreement and the rights and remedies of
the Company and the Employee shall be governed by and construed in accordance
with the laws of the Commonwealth of Virginia.
Section 10. Binding Effect. This Agreement shall inure to the benefit of
the Company and its successors and assigns and shall be fully binding upon the
Employee, its heirs, executors and legal or personal representatives.
Section 11. Expenses. The Employee will, upon demand, pay to the Company
the amount of any and all reasonable expenses, including the reasonable fees and
expenses of its counsel, which the Company may incur in connection with the
exercise or enforcement of any of the rights of the Company. The Employee shall
also be solely responsible for his/her own cost for accounting, tax, legal and
investment banking advice and other similar services that he/she
-4-
<PAGE>
may receive from his/her respective advisors with respect to this Agreement and
the matters contemplated in the Agreement.
Section 12. Taxes. The Employee shall be solely responsible and agrees to
pay any and all taxes applicable with respect to shares purchased or options
exercised pursuant to or in connection with the Stock Purchase Program and
subsequently sold, including but not limited to income taxes, capital gains
taxes or any other tax levied by any relevant taxing authority.
Section 13. Term. This Agreement shall remain in full force and effect
until all obligations of the Employee under the Note and under this Agreement
have been fully performed and the Company has no further actual or contingent
liability to the Lender under the Guaranty with regard to the Loan.
Section 14. Notices. All notices and other communications permitted or
required pursuant to this Agreement shall be in writing and shall be deemed
given when delivered in person, or when deposited in the United States mail,
postage prepaid, as certified mail, return receipt requested, properly addressed
to the party for whom intended at the addresses set forth below, or to such
other address as either party hereto may designate for itself by notice in
accordance herewith to the other:
The Company Treasurer
Dominion Resources, Inc.
120 Tredegar Street
Richmond, VA 23219
The Employee: ____________________________________
____________________________________
____________________________________
Section 15. Remedies; No Waiver. All of the Company's rights and remedies
under this Agreement are intended to be distinct, separate and cumulative and no
such right or remedy is intended to be to the exclusion of or be a waiver of any
other right or remedy. No delay or omission of the Company to exercise any
right, remedy or power shall impair the same or be construed to be a waiver of
any Event of Default. A waiver of any Event of Default shall not extend to or
affect any subsequent Event of Default, nor shall it impair any right, remedy or
power available to the Company. No single or partial exercise of any right,
remedy or power shall preclude any other or further exercise by the Company;
Section 16. Severability. Any provision of this Agreement that is legally
determined to be unenforceable in any jurisdiction shall, as to that
jurisdiction, be ineffective to the extent of the unenforceability without
invalidating the remaining provisions, but no unenforceability in any
jurisdiction shall invalidate or render unenforceable the same or any other
provision in any other jurisdiction.
-5-
<PAGE>
Section 17. Entire Agreement. This Agreement constitutes the entire
agreement of the parties with respect to the subject matter and supersedes any
and all other understandings, negotiations, or agreements between the Employee
and the Company about these matters.
IN WITNESS WHEREOF, the parties have signed this Agreement as of the date
written above.
<TABLE>
<CAPTION>
<S><C>
DOMINION RESOURCES, INC. [EMPLOYEE]
By:_______________________________ By:__________________________
Its:______________________________
</TABLE>
-6-
<PAGE>
Exhibit 11
DOMINION RESOURCES, INC.
COMPUTATION OF EARNINGS PER SHARE OF COMMON STOCK
ASSUMING FULL DILUTION
(Million, Except Per Share Amounts)
1999 1998 1997
---- ---- ----
Basic earnings per common share:
Consolidated net income (1) $296 $536 $399
---- ---- ----
Adjustment to average common shares:
Shares of common stock - average
shares outstanding 191.4 194.9 185.2
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 191.4 194.9 185.2
----- ----- -----
Basic earnings per common share $1.55 $2.75 $2.15
----- ----- -----
Diluted earnings per common share:
Consolidated net income $284 $536 $399
---- ---- ----
Adjustment to average common shares:
Shares of common stock - average
shares outstanding 191.4 194.9 185.2
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 191.4 194.9 185.2
----- ----- -----
Diluted earnings per common share $1.48 $2.75 $2.15
----- ----- -----
Notes: (1) See the Consolidated
Statements of Income.
(2) Based on the following
data:
1999 1998 1997
---- ---- ----
Installments received on stock purchase
plan at year-end $0.2 $0.4 $0.7
Average market per common share $43.46 $43.38 $38.06
<PAGE>
Exhibit 13
Consolidated Statements of Income
<TABLE>
<CAPTION>
-----------------------------------
For The Years Ended December 31, 1999 1998 1997
(millions, except per share amounts)
Operating revenue and income:
<S> <C> <C> <C>
Domestic electric utility service $ 4,274 $ 4,013 $ 4,230
East Midlands-electric utility service 1,010 1,970
Other 1,246 1,058 1,063
-----------------------------------
Total 5,520 6,081 7,263
-----------------------------------
Expenses:
Fuel, net 996 961 1,222
Purchased power capacity, net 809 806 718
Supply and distribution n East Midlands 655 1,466
Impairment of regulatory assets 159 38
Other operation and maintenance 1,384 1,374 1,226
Depreciation, depletion and amortization 716 734 819
Other taxes 304 306 302
-----------------------------------
Total 4,209 4,995 5,791
-----------------------------------
Income from operations 1,311 1,086 1,472
-----------------------------------
Other income and expense:
Gain on sale (windfall profits tax) n East Midlands 332 (157)
Other 91 99 39
-----------------------------------
Total other income and expense 91 431 (118)
-----------------------------------
Income before fixed charges and income taxes 1,402 1,517 1,354
-----------------------------------
Fixed charges:
Interest charges 507 583 627
Distributions n preferred securities and preferred stock 67 65 48
-----------------------------------
Total fixed charges 574 648 675
-----------------------------------
Income before provision for income taxes, minority interests and extraordinary item 828 869 679
Provision for income taxes 259 306 233
Minority interests 18 27 47
-----------------------------------
Income before extraordinary item 551 536 399
-----------------------------------
Extraordinary item (net of income taxes of $197) 255
-----------------------------------
Net income $ 296 $ 536 $ 399
===================================
Basic earnings per common share:
Income before extraordinary item $ 2.88 $ 2.75 $ 2.15
Extraordinary item $ (1.33)
-----------------------------------
Net income $ 1.55 $ 2.75 $ 2.15
===================================
Diluted earnings per common share:
Income before extraordinary item $ 2.81 $ 2.75 $ 2.15
Extraordinary item $ (1.33)
-----------------------------------
Net income $ 1.48 $ 2.75 $ 2.15
===================================
Dividends paid per common share $ 2.58 $ 2.58 $ 2.58
===================================
Average common shares outstanding 191.4 194.9 185.2
===================================
</TABLE>
The accompanying notes are an integral part of the Consolidated Financial
Statements.
21
<PAGE>
Consolidated Balance Sheets
Assets
<TABLE>
<CAPTION>
-----------------------
At December 31, 1999 1998
(millions)
Current assets:
<S> <C> <C>
Cash and cash equivalents $ 280 $ 426
Accounts receivable:
Customers (less allowance for doubtful accounts of $12 in 1999 and $5 in 1998) 664 778
Other 269 256
Materials and supplies at average cost or less:
Plant and general 143 158
Fossil fuel 111 95
Mortgage loans in warehouse 119 140
Commodity contract assets 362 180
Finance receivables held for sale 15 174
Other 229 252
-----------------------
Total current assets 2,192 2,459
-----------------------
Investments:
Loans receivable, net 2,034 1,513
Investments in affiliates 433 382
Available for sale securities 512 500
Nuclear decommissioning trust funds 818 705
Investments in real estate 86 94
Other 334 263
-----------------------
Total net investments 4,217 3,457
-----------------------
Property, plant and equipment 18,646 18,106
Less accumulated depreciation, depletion and amortization 7,882 7,469
-----------------------
Net property, plant and equipment 10,764 10,637
-----------------------
Deferred charges and other assets:
Goodwill, net 132 150
Regulatory assets, net 221 620
Other, net 221 194
-----------------------
Total deferred charges and other assets 574 964
-----------------------
Total assets $17,747 $17,517
=======================
</TABLE>
The accompanying notes are an integral part of the Consolidated Financial
Statements.
22
<PAGE>
Liabilities and Shareholders' Equity
<TABLE>
<CAPTION>
---------------------------
At December 31, 1999 1998
(millions)
Current liabilities:
<S> <C> <C>
Securities due within one year $ 536 $ 443
Short-term debt 870 301
Accounts payable, trade 711 699
Accrued interest 121 109
Accrued payroll 93 86
Accrued taxes 89 175
Commodity contract liabilities 347 266
Other 232 259
---------------------------
Total current liabilities 2,999 2,338
---------------------------
Long-term debt 6,936 6,252
---------------------------
Deferred credits and other liabilities:
Deferred income taxes 1,699 1,793
Investment tax credits 146 221
Other 222 212
---------------------------
Total deferred credits and other liabilities 2,067 2,226
---------------------------
Total liabilities 12,002 10,816
---------------------------
Minority interest 99 311
---------------------------
Commitments and contingencies (See Note Q)
Obligated mandatorily redeemable preferred securities of subsidiary trusts* 385 385
---------------------------
Preferred stock:
Preferred stock subject to mandatory redemption 180
---------------------------
Preferred stock not subject to mandatory redemption 509 509
---------------------------
Common shareholders' equity:
Common stock -- no par; authorized -- 500.0 shares;
outstanding -- 186.3 shares at 1999 and
194.5 shares at 1998 3,561 3,933
Retained earnings 1,190 1,387
Accumulated other comprehensive income (15) (20)
Other paid-in capital 16 16
---------------------------
Total common shareholders' equity 4,752 5,316
---------------------------
Total liabilities and shareholders' equity $ 17,747 $ 17,517
===========================
</TABLE>
* As described in Note M, 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.
23
<PAGE>
Consolidated Statements of Shareholders' Equity
<TABLE>
<CAPTION>
----------------------------------------------------------------------------
Accumulated Other Other
Common Stock Retained Comprehensive Paid-In
Shares Amount Earnings Income Capital Total
(millions)
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1997 181 $ 3,472 $ 1,438 $ (10) $ 16 $ 4,916
Issuance of stock through employee and
direct stock purchase plans 5 176 176
Other common stock activity 2 26 26
Comprehensive income 399 7 406
Dividends and other adjustments (483) (483)
----- ------- ------- ------- ------- -------
Balance at December 31, 1997 188 $ 3,674 $ 1,354 $ (3) $ 16 $ 5,041
----------------------------------------------------------------------------
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 536 (17) 519
Dividends and other adjustments (503) (503)
----- ------- ------- ------- ------- -------
Balance at December 31, 1998 195 $ 3,933 $ 1,387 $ (20) $ 16 $ 5,316
----------------------------------------------------------------------------
Stock repurchase and retirement (9) (372) (372)
Comprehensive income 296 5 301
Dividends and other adjustments (493) (493)
----- ------- ------- ------- ------- -------
Balance at December 31, 1999 186 $ 3,561 $ 1,190 $ (15) $ 16 $ 4,752
============================================================================
</TABLE>
Consolidated Statements of Comprehensive Income
<TABLE>
<CAPTION>
-----------------------------------
For The Years Ended December 31, 1999 1998 1997
(millions) -----------------------------------
<S> <C> <C> <C>
Net income $ 296 $ 536 $ 399
Other comprehensive income, net of tax:
Unrealized holding gains (losses) arising during a period (14) (3) 9
Less: reclassification adjustment for gains realized in net income 3 3 --
(millions) -----------------------------------
Unrealized gains (losses) on investment securities* (17) (6) 9
Foreign currency translation adjustment 22 (11) (2)
(millions) -----------------------------------
Other comprehensive income 5 (17) 7
(millions) -----------------------------------
Comprehensive income $ 301 $ 519 $ 406
(millions) ===================================
</TABLE>
* Reclassification adjustments for gains (losses) realized in net income were
not material in any of the periods presented.
The accompanying notes are an integral part of the Consolidated Financial
Statements.
24
<PAGE>
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
-------------------------------------
For The Years Ended December 31, 1999 1998 1997
(millions)
Cash flow from (used in) operating activities:
<S> <C> <C> <C>
Net income $ 296 $ 536 $ 399
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization 798 814 905
Gain on sale of East Midlands (332)
Deferred income taxes 64 22 13
Deferred fuel expense (35) (34) 10
Extraordinary item, net of income taxes 255
Impairment of regulatory assets 159 38
Changes in current assets and liabilities:
Accounts receivable 81 (90) (176)
Materials and supplies (6) (24) 16
Purchase and origination of mortgages (2,575) (2,503) (1,695)
Proceeds from sale and principal collections of mortgages 2,597 2,450 1,672
Accounts payable, trade (24) 65 113
Accrued interest and taxes (48) 100 119
Commodity contract assets and liabilities (92) 66 14
Other (56) (4) (116)
-------------------------------------
Net cash flow from operating activities 1,255 1,225 1,312
-------------------------------------
Cash flow from (used in) financing activities:
Issuance of common stock 354 176
Repurchase of common stock (372) (99)
Issuance of preferred securities of subsidiary trust 250
Issuance (repayment) of short-term debt 394 65 (100)
Issuance of long-term debt 6,446 4,027 6,316
Repayment of long-term debt (5,790) (4,207) (4,376)
Common dividend payments (493) (503) (478)
Other (44) (90) 42
-------------------------------------
Net cash flow from (used in) financing activities 141 (453) 1,830
-------------------------------------
Cash flow from (used in) investing activities:
Utility capital expenditures (737) (624) (649)
Acquisition of natural gas and independent power properties (157) (131) (53)
Loan originations (2,581) (2,580) (1,147)
Repayments of loan originations 2,238 1,778 1,065
Purchase of East Midlands (1,902)
Sale of businesses, including East Midlands 180 1,462 123
Purchase of property, plant and equipment (67) (80) (124)
Sale of marketable securities 35 70 117
Purchase of debt securities (53) (120) (138)
Acquisitions of businesses (167) (338) (145)
Other investments (152) (75) (50)
Other (81) (30) (28)
-------------------------------------
Net cash flow used in investing activities (1,542) (668) (2,931)
-------------------------------------
(Decrease) increase in cash and cash equivalents (146) 104 211
Cash and cash equivalents at beginning of the year 426 322 111
-------------------------------------
Cash and cash equivalents at end of the year $ 280 $ 426 $ 322
=====================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, excluding capitalized amounts $ 522 $ 474 $ 440
Income taxes 199 202 190
Non-cash transactions from investing and financing activities:
Assumption or issuance of debt as part of acquisitions 260 26 18
Note issued in sale of business 57
Exchange of securities 12 52
Equity contribution for Wolverine acquisition 21
</TABLE>
The accompanying notes are an integral part of the Consolidated Financial
Statements.
25
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations
(unaudited)
Forward-Looking Information
We have included certain information in this annual report 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) is influenced by a number of factors
including political and economic risks, market demand for energy, inflation,
capital market conditions, governmental policies, legislative and regulatory
actions (including those of 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, the Virginia
State Corporation Commission [Virginia Commission], and the North Carolina
Utilities Commission [North Carolina Commission]), industry and rate structure,
and legal and administrative proceedings. Some other important factors that
could cause actual results or outcomes to differ materially from those discussed
in the forward-looking statements include changes in and compliance with
environmental laws and policies, weather conditions and catastrophic
weather-related damage, present or prospective wholesale and retail competition,
competition for new energy development opportunities, pricing and transportation
of commodities, operation of nuclear power facilities, acquisition and
disposition of assets and facilities, effects of the merger with Consolidated
Natural Gas (CNG), nuclear decommissioning costs, exposure to changes in the
fair value of commodity contracts, counter-party credit risk and unanticipated
changes in operating expenses and capital expenditures. All such factors are
difficult to predict, contain uncertainties that may materially affect actual
results, and may be beyond the control of 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
In Management's Discussion and Analysis of Financial Condition and Results of
Operations, we explain the general financial condition and the results of
operations for Dominion. As you read this section, it will be helpful to refer
to our consolidated financial statements and notes.
At December 31, 1999, Dominion's principal subsidiaries were Virginia
Electric and Power Company (Virginia Power), Dominion Energy, Inc. (DEI), and
Dominion Capital, Inc. (Dominion Capital). Virginia Power, a regulated public
utility, is 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 is also engaged in off-system wholesale purchases
and sales of electricity and purchases and sales of natural gas beyond the
geographic limits of its service territory. DEI is engaged in independent power
production and oil and gas exploration, development and production. Dominion
Capital's primary business is financial services which includes commercial
lending, merchant banking, asset management and residential mortgage lending.
In preparation for the transition to competition for electric generation in
Virginia, Dominion is evaluating operating results and financial information
across Virginia Power's and DEI's current business lines. Although the employees
and assets involved remain with their respective legal entities, Dominion
currently evaluates the operations of DEI and Virginia Power in the following
business segments:
. generation-related operations of both Virginia Power and DEI (referred to
as Dominion Energy);
. regulated electric transmission and distribution services (referred to as
Dominion Delivery); and
. oil and gas operations of DEI (referred to as Dominion E&P).
In addition to the business segments mentioned above, Dominion also reviews
the following as business segments:
. the financial services of Dominion Capital;
. East Midlands which was sold by Dominion in mid-1998; and
. Corporate Operations which include: corporate costs of Dominion's holding
company; Corby Power (Corby) operations; intercompany eliminations; the
impact of the impairment of regulatory assets and one-time refund recorded
as a result of Virginia Power's 1998 rate settlement; and the extraordinary
item recorded in 1999.
Dominion has structured its Management's Discussion and Analysis of
Operations to reflect these business segments. Certain activities are currently
evaluated based on existing legal entities rather than operating segments. In
those cases, discussion is provided on a legal entity basis.
Three major events occurred in 1999 which will have a significant effect on
Dominion's future operations and business segments. These events are more fully
described in Future Issues and include:
. the announcement of Dominion's merger with CNG which closed on January 28,
2000;
. the enactment of law which established a detailed plan to restructure the
electric industry in Virginia; and
. the sale of Dominion Energy's interests in Latin American power generation.
RESULTS OF
OPERATIONS
Overview
Dominion achieved earnings of $296 million in 1999 or $1.55 per average common
share, compared with earnings of $536 million in 1998 or $2.75 per share. Absent
the extraordinary item, earnings would have been $551 million in 1999, or $2.88
per share. Significant factors impacting earnings in 1999 and 1998 include:
. the write-off of generation-related assets and liabilities at Virginia
Power in 1999;
. the loss recorded by Dominion Energy in 1999 related to its interests in
Latin American power generation;
. the increased contribution from Dominion Energy's energy marketing business
during 1999;
. the sale of East Midlands which resulted in a gain in 1998 and the absence
of East Midlands' contribution to earnings in 1999; 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.
26
<PAGE>
Earnings increased $137 million in 1998 as compared to 1997 primarily due
to the gain on the sale of East Midlands in mid-1998 offset by the impact of
Virginia Power's 1998 rate case settlement and the recognition of the windfall
profits tax by East Midlands in 1997.
Below we have provided a comparison of net income and earnings per share
contributions by segment:
<TABLE>
<CAPTION>
--------------------------------------------------------------------
Year ended December 31, 1999 1998 1997
Net Net Net
Income EPS Income EPS Income EPS
(millions, except per
share amounts)
<S> <C> <C> <C> <C> <C> <C>
Dominion Delivery $ 175 $ 0.91 $ 168 $ 0.86 $ 193 $ 1.04
Dominion Energy 271 1.42 262 1.35 275 1.48
Dominion E&P 43 0.22 22 0.11 35 0.19
Dominion Capital 78 0.41 59 0.30 45 0.24
East Midlands 26 0.14 47 0.25
Corporate:
Operations (16) (0.08) (1) (0.01) (15) (0.08)
Rate case settlement (201) (1.03)
Extraordinary item (255) (1.33)
Impairment --
regulatory assets (24) (0.12)
East Midlands
Gain on sale/
(windfall profits tax) 201 1.03 (157) (0.85)
--------------------------------------------------------------------
Consolidated $ 296 $ 1.55 $ 536 $ 2.75 $ 399 $ 2.15
====================================================================
Average Shares 191.4 194.9 185.2
====================================================================
</TABLE>
Domestic Electric Utility Service
As mentioned above, Dominion is evaluating the operating results of its domestic
utility operations as two separate businesses. Although distinct discussions are
presented for these businesses below, this section provides a general discussion
of factors that affect both the utility operations of Dominion Energy and the
regulated transmission and distribution business of Dominion Delivery.
Revenue
Domestic electric utility service revenue for fiscal years 1999, 1998, and 1997
were allocated to the utility operations of Dominion Energy and Dominion
Delivery businesses as follows:
---------------------------------------
Year ended December 31, 1999 1998 1997
(millions)
Revenue:
Dominion Energy $3,129 $3,075 $3,150
Dominion Delivery 1,148 1,092 1,080
Corporate Operations (3) (154)
---------------------------------------
Total revenue $4,274 $4,013 $4,230
=======================================
See Note R for discussion of the nature of items in this caption.
The following factors contributed to the increase in domestic electric
utility service revenue in 1999 as compared to 1998 and the decrease in 1998 as
compared to 1997:
--------------------------------
(millions) 1999 vs. 1998 1998 vs. 1997
Increase (decrease) due to:
Customer growth $ 68 $ 60
Weather 2 (7)
Base rate refund 154 (154)
Base rate variance (57) (88)
Fuel rate variance 24 (121)
Other retail, net 31 99
--------------------------------
Total retail 222 (211)
Other electric service revenue 39 (6)
--------------------------------
Total increase (decrease) in domestic
electric service revenue $261 $(217)
================================
Domestic electric utility service revenue consists primarily of sales to retail
customers in Virginia Power's service territory at rates authorized by the
Virginia and North Carolina 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 our transmission system to
transport electric energy under tariffs authorized by FERC. The primary factors
affecting this revenue in both fiscal years 1999 and 1998 were customer growth
and changes in rates.
Retail Customer Growth
Virginia Power's retail customer base increased by approximately 39,000 in 1999
and 35,000 in 1998 over the respective prior year periods. These additional
customers increased our electric utility service revenue by an estimated $68
million in 1999 compared to 1998 and an estimated $60 million in 1998 compared
to 1997.
Weather
Weather typically has a significant impact on the Company's revenue. However,
for the comparative periods presented, weather did not have a significant
impact.
Base Rate Reduction
Electric utility service revenue in 1998 was less than revenue in both 1999 and
1997 as a result of a one-time $150 million base rate refund. Further, a
two-phased rate reduction in Virginia ($100 million effective March 1, 1998 and
an additional $50 million effective March 1, 1999), reduced 1999 electric
service revenue by $57 million compared to 1998 and 1998 revenue by $88 million
compared to 1997. As a result of Virginia law enacted in 1999, Virginia Power's
jurisdictional base rates will remain unchanged until mid-2007. See Note (C) to
Consolidated Financial Statements.
Fuel Rates
Currently, Virginia Power is permitted to recover the cost of fuel used in
generating electricity through fuel rates approved by regulatory authorities.
The decrease in 1998 fuel rate revenue of $121 million, as compared to 1997, is
primarily attributable to lower fuel rates. The reduction recognized savings
from negotiated changes to power supply contracts. In December 1998, Virginia
Power's annual fuel case resulted in an increase in fuel rates and increased
electric utility service revenue in 1999 by $24 million as compared to 1998.
27
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations, continued
Dominion Delivery
The business segment Dominion Delivery includes customer service, bulk power
transmission, distribution and metering services that continue to be subject to
cost-based regulation.
Overall Dominion Delivery's operating income increased in 1999, as compared
to 1998, primarily due to an increase in revenue for electric transmission
services and from retail electric service customer growth, offset in part by
increased expenses associated with storm damage. The decrease in Dominion
Delivery's operating income in 1998, as compared to 1997, reflects primarily the
excess of increased storm damage costs and other routine operational expenses
over the increase in revenue for electric transmission services. Selected
financial information relevant to Dominion Delivery is as follows:
----------------------------------
Year ended December 31, 1999 1998 1997
(millions)
Domestic electric utility
service revenue $1,148 $1,092 $1,080
Operation and maintenance 313 286 266
Operating income 431 424 442
==================================
Operation and maintenance
Operation and maintenance increased in 1999 and 1998 as compared to respective
prior years, primarily due to increased service restoration costs associated
with storm damage.
Dominion Energy
The business segment Dominion Energy consists of the independent power
generation operations of DEI and the utility generation operations of Virginia
Power. Dominion Energy's 1999 operating income increased when compared to 1998
primarily due to the performance of the energy marketing business. The
performance was attributable to changes in the composition and the fair value of
its portfolio of commodity contracts as well as the settlement of commodity
contract liabilities using Dominion Energy resources rather than market
purchases. Selected financial information relevant to Dominion Energy is as
follows:
-----------------------------
Year ended December 31, 1999 1998 1997
(millions)
Domestic electric utility
service revenue $3,129 $3,075 $3,150
Other revenue 464 435 599
Fuel, net 996 961 1,222
Purchased power capacity, net 809 806 718
Other operation and maintenance 690 605 624
Operating income 624 615 645
=============================
Other revenue includes sales of electricity beyond Virginia Power's retail
service territory, including trading revenues, and sales of natural gas, nuclear
consulting services and energy management services. The increase in other
revenue in 1999 over 1998 reflects primarily changes in the composition and fair
value of our portfolio of commodity contracts.
Other revenue decreased in 1998 as compared to 1997 due to electricity
trading revenue being reported net of purchased energy for the entirety of 1998
and only for the last four months of 1997. Such revenue was reported gross for
the first eight months of 1997 as a result of being subject to cost of service
rate regulation during that time.
Fuel, net increased in 1999, as compared to 1998, primarily due to
increased fuel costs resulting from higher production from our generating units
and increased energy purchases.
Fuel, net decreased in 1998, as compared to 1997, primarily due to the
inclusion of the cost of power marketing purchases for the first eight months of
1997. However, the cost of power marketing purchases since September 1997 is
being reported net of related revenue in Other revenue. Prior to September 1997,
this activity was subject to cost of service rate regulation.
Purchased power capacity, net increased in 1998 as compared to 1997
primarily due to (1) increased expenses associated with the restructuring of
certain contracts and (2) the discontinuance of deferral accounting for such
expenses. See Note (C) to the Consolidated Financial Statements.
The increase in Operation and maintenance in 1999 as compared to 1998,
includes the following:
. increased maintenance activities performed during planned outages at fossil
plants;
. adjustments to inventories related to the planned disposal of identified
obsolete and excess materials and supplies;
. certain accounting policy changes, including the recognition of losses on
retirement of equipment and related removal costs; and
. the recognition of a loss related to the sale of the Latin American power
generation businesses.
See Note (B) to the Consolidated Financial Statements for discussion of
accounting policy changes made in connection with the discontinuance of
Statement of Financial Accounting Standards No. 71, Accounting for the Effects
of Certain Types of Regulation (SFAS No. 71), to utility generation operations.
Dominion E&P
In 1999, DEI acquired interests in certain gas producing properties located in
the San Juan Basin of New Mexico for approximately $115 million. In addition,
DEI completed its purchase of all of the issued and outstanding shares of
Remington Energy Ltd. (Remington), a publicly traded natural gas exploration
and production company headquartered in Calgary, Alberta, Canada. DEI paid $33
million and assumed $260 million of Remington's debt and liabilities.
Selected financial information relevant to Dominion E&P is as follows:
----------------------------------
Year ended December 31, 1999 1998 1997
(millions)
Revenue $256 $164 $158
Operating income:
Oil and gas* 73 44 53
Adjustments* (46) (32) (25)
Total operating income 27 12 28
==================================
*Oil and gas Operating income includes Nonconventional Fuels Tax Credits. Such
credits are reversed on the Adjustments line as they are not ordinarily reported
as a component of Operating income.
Operating income increased in 1999 primarily due to increased natural gas
production. Natural gas production rose to 109 billion cubic feet equivalent
(Bcfe) in 1999, compared to 69 Bcfe in 1998, a 58 percent increase. At December
31, 1999, proved gas 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 production at Dominion Energy
Canada, Ltd., and the acquisition of interests discussed above.
28
<PAGE>
Natural gas production rose to 69 Bcfe in 1998, compared to 59 Bcfe in
1997, a 17 percent increase. At December 31, 1998, proved gas reserves totaled
616 Bcfe, an increase of 157 Bcfe over 1997. The 1998 increase resulted
primarily from the development of existing acreage and the acquisition of
Dominion Energy Canada, Ltd. The increased production for 1998 was offset by a
$0.38 reduction in average sales price per Mcfe, from $2.44 in 1997 to $2.06 in
1998. The 1998 decreases in gas prices resulted from a combination of shifting
geographic production mix and lower overall market price.
Dominion Capital
Dominion Capital's 1999 results of operations increased as compared to 1998
primarily due to a higher earnings contribution from the commercial lending,
merchant banking, asset management and residential mortgage lending operations
in 1999, partially offset by a decrease in net investment gains.
Dominion Capital's 1998 operating income increased over 1997 primarily due
to earnings contribution from its commercial finance, merchant banking and asset
management operations.
Selected financial information relevant to Dominion Capital is as follows:
----------------------------------
Year ended December 31, 1999 1998 1997
(millions)
Revenue $473 $409 $296
Operating income:
Financial services 267 212 143
Other (2) (2) 14
----------------------------------
Total operating income 265 210 157
==================================
Operating income increased in 1999 and 1998 primarily due to increased
contributions from our financial services businesses. Our mortgage lending
volumes were $2.4 billion in 1999, up from $2.1 billion in 1998. Our commercial
finance operations portfolio has grown to $2.0 billion at the end of 1999,
compared to $1.7 billion at the end of 1998. In addition, assets under
management were $4.8 billion and $3.5 billion at December 31, 1999 and 1998,
respectively.
Income from investments decreased in 1998 over 1997 primarily due
to a valuation adjustment to other investments and higher real estate operating
costs.
Corporate
Corporate earnings include transactions for which the segments are not held
accountable for internal reporting purposes and other miscellaneous items.
Corporate earnings include the effects of the utility operations' write-off of
generation-related assets and liabilities as an extraordinary item in 1999 and
the impairment of regulatory assets and one-time refund recorded as a result of
the settlement of Virginia Power's 1998 Virginia jurisdictional rate
proceedings. See Note (C) to the Consolidated Financial Statements.
Other Income and Expense
In 1999, Other income and expense decreased as compared to 1998 because of the
gain on the sale of East Midlands in 1998. Other income and expense increased in
1998 as compared to 1997 primarily due to the gain on the sale of East Midlands
in 1998 and the recognition of the windfall profits tax by East Midlands in
1997.
Fixed Charges
Interest charges decreased in 1999 as compared to 1998, primarily due to:
. cancellation of the debt associated with East Midlands which was
sold in mid-1998;
. interest paid in 1998 in connection with the settlement of Virginia
Power's Virginia jurisdictional rate proceeding; and
. the utility generation operations starting to capitalize interest on
construction projects.
These reductions were offset by:
. the issuance of debt to fund DEI's acquisitions of Kincaid Power
Station and Dominion Energy Canada, Ltd. in 1998 and
. the increase in funding needs for loan originations at Dominion
Capital's financial services businesses.
Interest charges decreased in 1998 as compared to 1997 because of the
cancellation of the debt associated with East Midlands which was sold in 1998.
The debt cancellation for East Midlands was offset by the issuance of debt to
fund DEI's acquisitions.
Provision For Income Taxes
The taxes on the gain on the sale of East Midlands recorded in 1998 were the
primary reasons for the decrease in taxes in 1999 as compared to 1998 and the
increase in taxes in 1998 as compared to 1997. In 1998, the taxes related to the
sale of East Midlands were partially off-set by the income tax provisions
associated with the effects of Virginia Power's Virginia rate proceeding
settlement.
Extraordinary Item, Net of Tax
This extraordinary item was recorded in connection with the passage of new
legislation in 1999 establishing a detailed plan to restructure the electric
utility industry in Virginia. The legislation's deregulation of generation was
an event that required discontinuation of SFAS No. 71 for our utility generation
operations. Generation-related assets and liabilities not expected to be
recovered through cost-based rates were written off in March 1999, resulting in
an after-tax charge to earnings of $255 million. See Note (C) to Consolidated
Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
Certain activities discussed under Liquidity and Capital Resources are currently
evaluated based on existing legal entities rather than the operating segments
defined by the new organizational structure. References are made to specific
operating segments as appropriate.
Dominion funds its operations and supports the financing needs of its
subsidiaries primarily through the issuance of commercial paper, backed by lines
of credit and the issuance of debt, preferred or common securities, which is
facilitated by the equity plans described below and a $950 million dollar shelf
registration, $675 million of which was still available to Dominion as of
December 31, 1999.
The proceeds of Dominion's financing activities are provided to its
subsidiaries as needed under inter-company agreements.
29
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations, continued
CNG Merger Financing
In 2000, Dominion initially financed the cash used in the CNG merger with 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. Dominion expects to
refinance these amounts with a combination of debt, preferred and convertible
securities along with the proceeds from sales of non-core assets, including
DEI's interests in Latin American power generation, CNG's foreign investments,
Virginia Natural Gas, and Dominion Capital. See Future Issues -- CNG Merger.
A $4.5 billion shelf registration was filed with the SEC and it became
effective on January 6, 2000. The shelf is expected to be used to facilitate the
refinancing of the CNG merger.
Immediately before the CNG merger, we concluded a first step transaction in
which 33 million shares of Dominion common stock were exchanged for
approximately $1.4 billion.
Commercial Paper
Dominion's nonutility subsidiaries may finance their working capital for
operations with the proceeds of Dominion commercial paper sales. Dominion sells
its commercial paper in regional and national markets and provides the proceeds
to the nonutility subsidiaries under the terms of intercompany credit
agreements. At the end of 1999, Dominion Resources, Inc. supported these
borrowings through bank lines of credit totaling $601 million. The nonutility
subsidiaries repay Dominion through cash flow from operations and proceeds from
permanent financings. Virginia Power and Dominion Capital also have commercial
paper programs as discussed below
Equity Plans
In 1998 and 1997, Dominion raised $87 million and $176 million, respectively,
from the sale of common stock through the Dominion Direct Investment and
Employee Savings plans. In 1998, management made the decision that purchases of
shares required by the Company's equity plans would be purchased on the open
market instead of issuing new shares. However, Dominion continues to have access
to capital through the Dominion Direct Investment and the Employee Savings plans
in the future.
Virginia Power
Operating activities continue to be a strong source of cash flow, providing $1.1
billion in each of the years 1999, 1998, and 1997. Over the past three years,
cash flow from operating activities, after dividend payments, has, on average,
covered 120% of Virginia Power's total construction requirements and provided
77% of its total cash requirements. Virginia Power's cash requirements not met
by the timing or amount of cash flow from operations are generally satisfied
with proceeds from the sale of securities and short-term borrowings.
Cash from (used in) financing activities was as follows:
---------------------------------
1999 1998 1997
(millions)
Issuance of long-term debt $ 305 $ 270 $ 270
Repayment of long-term debt (345) (334) (311)
Issuance (repayment) of
short-term debt 156 (4) (86)
Common dividend payments (383) (378) (380)
Other (53) (53) (50)
---------------------------------
Total $(320) $(499) $(557)
=================================
Financing activities have represented a net outflow of cash in recent years as
strong cash flow from operations has reduced Virginia Power's reliance on debt
financing.
During 1999, Virginia Power issued $305 million in aggregate principal of
unsecured debt securities. In 1999, Virginia Power issued $150 million in
aggregate principal of unsecured Senior Notes, Series 1999-A, with an annual
coupon rate of 6.7%, due 2009; and $80 million of Medium-Term Notes, Series G,
with an annual coupon rate of 6.3%, due 2001. Virginia Power also issued $75
million in aggregate principal of unsecured Senior Notes, Series 1999-B, with an
annual coupon rate of 7.2%, due 2004.
During 1999, Virginia Power retired $321 million in aggregate principal
amount of mandatory debt maturities. In 1999, Virginia Power repurchased $24
million in aggregate principal amount of First and Refunding Mortgage Bonds that
were made available through the open market.
As of December 31, 1999, Virginia Power has $740 million under effective
shelf registration statements with the SEC available for its use to meet capital
requirements. Virginia Power also has a commercial paper program that is
supported by two revolving credit facilities totaling $500 million. Proceeds
from the sale of commercial paper are primarily used to provide working capital.
Net borrowings under the program were $378 million at December 31, 1999.
Cash used in investing activities was as follows:
----------------------------------
1999 1998 1997
(millions)
Plant and equipment $(673) $(451) $(397)
Nuclear fuel (64) (81) (85)
Nuclear decommissioning
contributions (35) (37) (36)
Other (3) (13) (28)
----------------------------------
Total $(775) $(582) $(546)
==================================
Plant and equipment expenditures for generation-related projects were
approximately $327 million in 1999 and included significant expenditures for
additional capacity and environmental upgrades -- See Capital Requirements
below. Transmission and distribution-related projects accounted for
approximately $282 million of our total plant and equipment expenditures. These
projects included routine capital improvements and expenditures associated with
new connections. Remaining plant and equipment expenditures of $64 million
reflect general projects and information technology enhancements. These
information technology projects include development of remote metering and
dispatch technology, and continued implementation of new financial systems.
Capital Requirements
Capacity Virginia Power anticipates that peak demand will grow approximately 2%
per year through 2002. Virginia Power will complete construction of four
150-megawatt combustion turbines in Fauquier County, Virginia by mid-2000.
Virginia Power will spend an estimated
30
<PAGE>
$190 million on the project of which approximately $145 million has been
incurred through December 31, 1999. In January 2000, Virginia Power filed for
approval from the Virginia Commission for the construction of two additional
combustion turbines. The Virginia Commission has set a hearing date in May 2000
to consider this request. Commercial operation is planned to begin in June 2001.
Virginia Power expects that any future additional capacity and energy
requirements will be met through a combination of market purchases and company-
constructed generation.
Plant and Equipment Virginia Power's construction and nuclear fuel expenditures
during 2000, 2001 and 2002 are expected to total $856 million, $822 million and
$760 million, respectively. Virginia Power expects these construction and
nuclear fuel expenditures to be met through cash flow from operations, sales of
securities and short-term borrowings. These projected expenditures include the
effects of environmental costs discussed below.
Virginia Power is installing sulfur dioxide (SO2) emission control
equipment at two coal-fired generating units. The total cost for this project is
estimated to be $126 million of which $33 million has been incurred as of
December 31, 1999. Management believes the installation of scrubbers on these
two units will provide the most cost-effective means of complying with the Clean
Air Act.
In response to a rule adopted by the EPA in September 1998, Virginia Power
plans to install nitrogen oxide (NOx) reduction equipment on a portion of its
generating units at an estimated capital cost of $454 million over the next five
years. Whether these costs are actually incurred is dependent on the
implementation plans adopted by the states in which Virginia Power operates. No
significant costs have been incurred as of December 31, 1999. See Future Issues
- -- Clean Air Act Compliance.
Maturities Virginia Power will require $375 million to meet maturities of
securities in 2000.
Funding Capital Requirements
Virginia Power expects to meet its capital funding requirements with cash flow
from operations and issuance of replacement debt or preferred securities.
DEI
Net cash flow from operating activities was $151 million, $148 million and $162
million in 1999, 1998 and 1997, respectively. During 1999, cash flow from
operating activities increased as compared to 1998 primarily due to normal
business operations.
Net cash flow provided by operating activities decreased in 1998, as
compared to 1997, primarily due to a reduction in ownership of a subsidiary that
occurred during the third quarter of 1997.
DEI funds its capital requirements through cash flow from operations,
equity contributions by Dominion, an intercompany credit agreement with
Dominion, and bank revolving credit agreements. Cash flow from (used in)
financing activities was as follows:
----------------------------------
1999 1998 1997
(millions)
Contribution from parent $ 115
Issuance of long-term debt 14 $455 $ 108
Repayment of debt (213)
Common dividend payments (62) (48) (48)
Issuance (repayment) of
intercompany debt (10) 1 22
Other (27) 4
---------------------------------
Total $ 30 $412 $(131)
=================================
During 1999, cash flow from financing activities was $30 million primarily due
to an equity contribution from Dominion, net of dividends. Proceeds were used
primarily to fund acquisitions which expanded DEI's natural gas exploration,
development and production operations. Also, in 1998, DEI borrowed funds to
expand and upgrade its independent power plants.
Cash from (used in) investing activities was as follows:
---------------------------------
1999 1998 1997
(millions)
Purchase of fixed assets $ (57) $ (73) $(12)
Purchase of natural gas
properties (65) (35) (53)
Purchase of electric plant (92) (96)
Sale of business 180 53 123
Acquisition of businesses (167) (338) (28)
Other (36) (26) (20)
---------------------------------
Total $(237) $(515) $ 10
=================================
During 1999, cash flow was used in investing activities for the following:
. the acquisitions of Remington and interests in certain gas producing
properties located in the San Juan Basin of New Mexico and
. expansion and upgrade activities at certain independent power plants,
offset by
. proceeds from the sale of DEI's interest in its Latin American subsidiaries
in Peru and Belize.
Capital Requirements
DEI and Peoples Energy Corporation plan to expand the capacity at their
jointly-owned electric generating peaking facility near Elwood, Illinois. The
expansion is expected to be completed in 2001 and will add a combined 600
megawatts of natural gas-fired electric power to the facility's capacity for a
total of 1,200 megawatts. The cost of the expansion is estimated at $280
million. DEI and Peoples Energy Corporation will share equally in the
construction costs.
In response to a rule adopted by the EPA in 1998, DEI expects to install
NOx reduction equipment at its Kincaid plant at an estimated capital cost of
approximately $100 million over the next five years. Whether these costs are
actually incurred is dependent on the implementation plans adopted by Illinois
and the outcome of litigation regarding this rule. The power purchase agreement
with Commonwealth Edison Company provides that DEI will recover a portion of
these capital expenditures through monthly reimbursement over the term of the
agreement. The agreement also provides that DEI will be reimbursed for
operations, maintenance and fuel costs that may be incurred as a result of NOx
emission reduction regulations. For more information, see Future Issues -- Clean
Air Act Compliance. The capital requirements will be funded by cash flow from
operations and existing sources of financing.
Dominion Capital
Dominion Capital's net cash flow provided by operations for 1999 increased by
$76 million as compared to 1998 due to an increase in mortgage sales and
principal collections, net of originations, plus normal operations. Cash flow
provided by operations for 1998 increased by $61 million as compared to 1997
primarily due to higher operating income from financial services and liquidation
of marketable equity securities.
31
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations, continued
Dominion Capital funds its capital requirements through cash flow from
operations, an intercompany credit agreement with Dominion, equity contributions
from Dominion, bank revolving credit agreements, term loans and commercial paper
programs. Cash flow from (used in) financing activities was as follows:
------------------------------------
1999 1998 1997
(millions)
Contribution from parent $ 100 $ 118 $ 162
Issuance of long-term debt 5,331 3,212 3,911
Repayment of long-term debt (5,446) (2,992) (3,865)
Common dividend payments (71) (55) (43)
Issuance of commercial
paper, net 541 492 33
Issuance (repayment) of
intercompany debt (96) 114 28
------------------------------------
Total $ 359 $ 889 $ 226
====================================
During 1999, cash flow from financing activities was $359 million and was used
primarily to fund loan originations.
Dominion Capital has a senior unsecured 364-day $400 million revolving
credit agreement. The credit agreement is used by Dominion Capital for general
corporate purposes including providing liquidity to support a $400 million
commercial paper program which was established in February 1999. Net borrowings
under the agreement were $275 million at December 31, 1999.
Cash used in investing activities was as follows:
-------------------------------------
1999 1998 1997
(millions)
Loan originations, net $(343) $(802) $ (82)
Purchase of securities (156) (125) (139)
Other (24) (4) (22)
-------------------------------------
Total $(523) $(931) $(243)
=====================================
During 1999, cash flow used in investing activities decreased chiefly because of
an increase in commercial loan syndications, sales and repayments. In addition,
Dominion Capital also has an interest in a hydroelectric facility, real estate
and other investments. In mid 1999, Dominion Capital sold one half of its
interest in its hydroelectric facility for $45 million.
Capital Requirements
Until its divestiture, Dominion Capital will continue to fund the operations
of its financial services activities through net cash flows from operations,
sales of existing real estate and other assets and borrowings through the
intercompany credit agreement and various third party credit sources.
FUTURE ISSUES
This section discusses information that may have an impact on future operating
results. The SEC encourages companies to provide forward-looking information
because it provides investors with an insight into management's outlook for the
future. It should be noted that any forward-looking information is expressly
covered by the safe harbor rule for projections. For a more detailed description
of some of the uncertainties associated with forward-looking information, please
refer to the Forward-Looking Information section on page 26.
Three major events occurred in 1999 which will have a significant effect
on Dominion's future operations. These events were:
. the announcement of the CNG merger;
. the enactment of law which established a detailed plan to restructure the
electric industry in Virginia; and
. the sale of Dominion Energy's interests in Latin American power generation.
CNG Merger
On January 28, 2000, Dominion and CNG closed the merger of CNG into a subsidiary
of Dominion. The aggregate purchase price was $6.4 billion. Shareholders of CNG
received either Dominion common stock or cash in consideration of their CNG
shares. The combination with CNG, based in Pittsburgh, Pa., creates a fully
integrated electric and natural gas utility in the Midwest, Northeast and
Mid-Atlantic regions of the United States with selective energy businesses
located abroad. Immediately before the CNG Merger, we concluded a first step
transaction in which 33 million shares of Dominion common stock were exchanged
for approximately $1.4 billion.
With the CNG Merger, Dominion has an energy portfolio of almost 20,000
megawatts of domestic power generation and 2.8 trillion cubic feet equivalent in
natural gas and oil reserves, producing more than 300 billion cubic feet
equivalent annually. Dominion now operates a major interstate gas pipeline
system and the largest natural gas storage system in North America and has
approximately 6,000 miles of electric transmission lines. Dominion is the
eleventh largest independent oil and gas producer in the United States, measured
by reserves, and provides integrated energy services to approximately four
million retail customers.
As a result of the merger, Dominion is a registered public utility holding
company subject to the provisions of the Public Utility Holding Company Act of
1935 (1935 Act). The 1935 Act imposes a number of restrictions on the operations
of registered holding company systems. One such restriction limits the ability
of a registered holding company to engage in activities unrelated to its utility
operations. Consequently, as part of the SEC order approving the merger,
Dominion must divest itself of Dominion Capital, its financial services
subsidiary. Although a formal plan for divestiture has not been adopted, the SEC
allowed three years for this to be accomplished.
During the merger approval process, Dominion and CNG also agreed to divest
Virginia Natural Gas, Inc. (VNG), CNG's gas distribution subsidiary located in
Virginia Beach, Va. Dominion has one year after the merger is completed to sell
VNG to a third party. If the sale of VNG is not completed within one year, VNG
will be spun off as an independent company with the common stock distributed to
Dominion shareholders. Both deadlines are subject to reasonable extensions,
which may be granted by regulatory authorities. For more information on the CNG
merger, see Note (X) to the Consolidated Financial Statements.
As part of the merger, Dominion created a subsidiary service company,
Dominion Resources Services, Inc. (Services), which will provide certain
services to Dominion's operating subsidiaries. Employees of Dominion Resources
and Virginia Power who will perform those functions became employees of
Services, effective February 1, 2000. CNG also has a service company. The
operating subsidiaries may elect to purchase services from either service
company; however, service company functions are expected to be centralized into
a single service company in 2001.
In addition, our business operations are being reviewed in conjunction with
the merger to identify opportunities for operational efficiencies. As a result
of the formation of the service company and this operational review,
restructuring charges for items such as employee severance and other special
termination benefits and the elimination of duplicate facilities are likely to
be incurred during 2000 and 2001.
32
<PAGE>
Dominion intends to manage the oil and gas exploration and production
operations of CNG and DEI on a combined basis. Dominion also intends to review
CNG's local gas distribution companies, Virginia Power's transmission and
distribution operations and the related customer services functions on a
combined basis.
Virginia Legislation
On March 25, 1999, the Governor of Virginia signed into law legislation
establishing a detailed plan to restructure the electric utility industry in
Virginia. The legislation will deregulate generation by 2002 with the phase-in
of retail customer choice beginning at that time. When customer choice begins,
customers will have the right to choose their energy supplier. However, we will
continue to transport all energy to customers within Virginia Power's service
territory. Under this legislation, Virginia Power's base rates will remain
generally unchanged until July 2007 and recovery of generation-related costs
will continue to be provided through capped rates. For more information, see
Note (C) to the Consolidated Financial Statements and Competition--Legislative
Initiatives below.
Sale of Interests in Latin American Power Generation
In 1999, DEI reached an agreement to sell its interests in approximately 1,200
megawatts of gross generation capacity located in Latin America. Duke Energy
International is purchasing the interests for approximately $405 million.
Dominion Energy completed the sale of its interests in Belize and Peru in
November 1999 and expects to complete the sale of its interests in Argentina and
Bolivia in 2000, following receipt of certain regulatory approvals.
During 1999, DEI recorded a one-time after-tax charge of $21 million
related to the sale. For additional information, see Note (V) to the
Consolidated Financial Statements and Future Issues--Dominion Energy.
Recently Issued Accounting Standards
The Financial Accounting Standards Board (FASB) recently issued SFAS No. 137,
Accounting for Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133, which defers the effective date of
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a
result, Dominion must adopt SFAS No. 133 no later than January 1, 2001. SFAS
No. 133 requires that derivative instruments (including certain derivative
instru-ments embedded in other contracts) be recorded in the balance sheet as
either an asset or liability measured at fair value. The statement requires that
changes in a derivative's fair value be recognized currently in earnings unless
specific hedge-accounting criteria are met.
The FASB-sponsored Derivatives Implementation Group is addressing
implementation issues related to SFAS No. 133. Dominion does not believe that
its long-term purchased power contracts would be subject to SFAS No. 133.
Dominion's portfolio of commodity contracts held for trading purposes is
currently marked to fair value and would not be affected by this statement.
Dominion is in the process of assessing the impact of SFAS No. 133. To the
extent that contracts are subject to SFAS No. 133 fair value accounting,
implementing appropriate hedging strategies could possibly mitigate the
potential impact on earnings volatility.
However, Dominion has not yet quantified the impacts of adopting SFAS
No. 133.
Year 2000 Compliance
Dominion experienced a successful transition to the Year 2000. Immediately after
the rollover and throughout the rollover weekend, Dominion's transmission and
distribution systems and its generating units continued to operate smoothly. Our
customers did not lose power as a result of a Year 2000 problem.
We are continuing to monitor systems for any Year 2000 issues, and we will
be especially alert to any problems caused by the transition through
February 29, 2000. However, as with the rollover to January 1, 2000, no
significant problems are expected.
We expect total Year 2000 costs to be approximately $32 million. Actual
Year 2000 costs of $30 million had been expended as of December 31, 1999.
We cannot estimate or predict the potential adverse consequences, if any,
that could result from a third party's failure to effectively address remaining
Year 2000 issues, if any, but believe that any impact would be short-term in
nature and would not have a material adverse impact on results of operations.
Dominion Delivery Business and Utility Operations of
Dominion Energy
The following discussion is about Virginia Power, Dominion's principal
subsidiary, and the environment in which it operates. As previously discussed,
Dominion evaluates the operations of Virginia Power in two of its operating
segments, Dominion Delivery (regulated electric distribution and transmission
operations) and Dominion Energy (utility generation operations).
Competition -- General
Dominion has recently seen federal and state developments toward increased
competition. Electric utilities have been required to open up their transmission
systems for use by potential wholesale competitors. In addition, non-utility
power producers now compete with electric utilities in the wholesale generation
market. At the federal level, retail competition is under consideration. Some
states, including Virginia, Ohio and Pennsylvania, have already enacted
legislation requiring the introduction of retail competition.
Today, Dominion faces competition in the wholesale market. There is no
general retail competition in Virginia Power's principal service area at this
time. However, Virginia enacted a law in 1999 establishing a detailed plan to
restructure the electric utility industry in Virginia. Dominion actively
supported this restructuring legislation. See Competition -- Retail and
Competition -- Legislative Initiatives below and Note (C) to the Consolidated
Financial Statements.
Dominion has responded to the trend toward competition by cutting costs,
re-engineering core business processes, and pursuing innovative approaches to
serving traditional markets and future markets. Dominion's strategy also
includes the development of non-traditional products and services with an
objective of providing growth in future earnings. These products and services
include electric energy and capacity in the emerging wholesale market; natural
gas and other energy-related products and services; nuclear management and
consulting services; power distribution and transmission related services,
including engineering and metering; and telecommunication services. In addition,
Dominion may from time to time identify and investigate opportunities to expand
its markets through strategic alliances with partners whose strengths, market
position and strategies complement those of Dominion.
Competition -- Wholesale
Virginia Power 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 Virginia Power's service
territory. However, Virginia Power expects to file in the first quarter 2000 an
application with FERC to make sales under its market-based sales tariff to loads
within its service territory to facilitate the retail access pilot program.
Also, Virginia Power expects to file in the first
33
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations, continued
quarter 2000 an application with FERC to amend its open access transmission
tariff to accommodate the retail access pilot program. Until such authorization
has been granted by FERC, any agreements which allow Virginia Power to sell
wholesale power to loads located within its service territory are to be at
cost-based rates accepted by FERC.
During 1999, sales to wholesale customers under requirements contracts
represented approximately 4 percent of Virginia Power's total revenues from
electric sales. Since FERC issued its Order 888 requiring open access to
transmission service, Virginia Power has faced increased competitive pressures
on sales to wholesale customers served under requirements contracts. In
response, Virginia Power has renegotiated long-term contracts with wholesale
customers. Virginia Power has also implemented a new arrangement with its
largest wholesale customer that provides for a transition from cost-based rates
to market-based rates.
Competition -- Retail
Currently, Virginia Power has the exclusive right to provide electricity at
retail within its assigned service territories in Virginia and North Carolina.
As a result, Virginia Power now faces competition for retail sales only if
certain of its business customers move into another utility service territory,
use other energy sources instead of electric power, or generate their own
electricity.
However, in 1998, the Virginia General Assembly passed legislation that
established a timeline for deregulation of retail electric service but left the
details regarding implementation to future enabling legislation. In March 1999,
the Governor of Virginia signed into law new legislation establishing a detailed
plan to restructure the electric utility industry in Virginia which will provide
for customer choice beginning in 2002. For a discussion of Virginia Power's
pilot program for customer choice beginning in 2000, see Competition --
Regulatory Initiatives below. Under this legislation, Virginia Power's 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. See Note (C) to
the Consolidated Financial Statements.
Competition--Legislative Initiatives
Virginia As discussed above, the Governor of Virginia signed into law
legislation establishing a detailed plan to restructure the electric utility
industry. Under the legislation, the generation portion of Virginia Power's
Virginia jurisdictional operations will no longer be subject to cost-based rate
regulation beginning in 2002.
A legislative transition task force is charged with specific assignments
including the monitoring of possible over- or under-recovery of stranded costs
by incumbent utilities. This monitoring begins at the onset of customer choice
and the task force will submit annual reports to the Governor and the General
Assembly offering recommendations as it deems necessary.
The legislation also addressed divestiture, functional separation and other
corporate relationships. Although mandatory divestiture is prohibited by the
law, functional separation is required and must be completed by January 1, 2002.
Utilities must submit their plans to the Virginia Commission by January 1, 2001,
outlining steps to be taken to functionally separate generation, transmission
and distribution.
Dominion is currently supporting certain technical amendments to the
restructuring legislation being considered by the 2000 General Assembly.
North Carolina The 1997 session of the North Carolina General Assembly created a
study commission on the future of electric service in North Carolina. In October
1999, Duke Energy Corp. and Carolina Power and Light Company submitted a
proposal to the study commission addressing certain municipal debt issues that
must be resolved before a comprehensive restructuring plan can be developed. The
North Carolina Commission continues to study the subject of deregulation in
anticipation that the 2000 session of the General Assembly may consider the
issue when it convenes in May.
Federal The U.S. Congress is expected to consider federal legislation in the
near future authorizing or requiring retail competition. Dominion cannot predict
what, if any, definitive actions the Congress may take.
Competition -- Regulatory Initiatives
Virginia In 1998, the Virginia State Corporation Commission issued an order
instructing Virginia Power and American Electric Power (AEP)- Virginia, as the
Commonwealth's two largest investor-owned utilities, to design and file retail
access pilot programs. Virginia Power filed a report in November 1998 describing
the details, objectives and characteristics of its proposed retail access pilot
program. In August 1999, the Commission's Hearing Examiner issued a report on
interim rules for the introduction of electric and natural gas retail
competition in Virginia. In September 1999, Virginia Power, the Virginia
Commission Staff and two other parties entered into a stipulated agreement which
resolved the size and scope of the proposed pilot program and the methodology
for determining the market price of electricity used in calculating the wires
charge assessed to those customers opting for alternate suppliers. The pilot
program will initially give approximately 35,000 customers the ability to
choose their electricity supplier. The scope of the program will be expanded to
include approximately 70,000 customers by year end 2000. A Hearing was held in
September 1999. The Hearing Examiner's Report was issued in November 1999,
recommending certain changes to Virginia Power's pilot plan and a modification
of the stipulated market price methodology. Virginia Power filed comments and
exceptions in December 1999. A Final Order from the Virginia Commission is
anticipated in early 2000.
In March 1998, the Virginia Commission issued an Order Establishing
Investigation with regard to independent system operators (ISOs), regional power
exchanges (RPXs) and retail access pilot programs. The Order directed all
investor-owned electric utilities to begin work, in conjunction with the
Virginia Commission Staff and other interested parties, to develop one or more
ISOs and RPXs to serve the public interest in Virginia. The Virginia Electric
Utility Restructuring Act (Act), signed into law in 1999, requires that
Virginia's incumbent electric utilities join or establish regional transmission
entities (RTEs) by January 2001, and seek authorization from the Virginia
Commission to transfer ownership or operational control of their transmission
facilities to such RTE's. In May 1999, the Virginia Commission issued an Order
Establishing an Investigation and inviting comments concerning the development
of the rules required by the Act. Virginia Power submitted comments in June 1999
and reply comments in July 1999, urging the Virginia Commission to adopt rules
and regulations that are identical to FERC's regulations concerning ISOs. In
January 2000, the Virginia Commission issued an Order giving notice of, and
requesting comments to, the proposed rules and regulations establishing the
elements of RTE structures. Under the proposed rules, Virginia Power would be
required to seek authorization to transfer operational control of its trans-
mission facilities on or before May 1, 2000. Virginia Power submitted comments
on the proposed rules and regulations in February 2000.
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<PAGE>
Federal Virginia Power maintains major interconnections with Carolina Power and
Light Company, AEP, Allegheny Energy (AE) and the utilities in the
Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission
network, Virginia Power has arrangements with these utilities for coordinated
planning, operation, emergency assistance, and exchanges of capacity and energy.
In June 1999, Virginia Power, together with American Electric Power
Services Corporation, 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 Regional Transmission Organization (Alliance RTO).
In December 1999, FERC issued an Order under Section 203 of the Federal
Power Act granting the application, subject to certain conditions and
requirements discussed in the Order, and directing the Alliance Companies to
submit a compliance filing as discussed in the Order. In January 2000, the
Alliance Companies filed an application seeking a rehearing of certain
conditions and requirements of the Order. In February 2000, the Alliance
Companies filed amendments to the Alliance RTO documents to comply with certain
conditions and requirements of the Order.
In December 1999, FERC issued Order 2000 which amended its regulations to
advance the formation of Regional Transmission Organizations (RTOs). The
regulations require that each public utility that owns, operates, or controls
transmission facilities make certain filings with respect to forming and
participating in an RTO. FERC also codified minimum characteristics and
functions that a transmission entity must satisfy in order to be considered an
RTO. In January 2000, the Alliance Companies filed an application seeking a
rehearing of such order.
Competition -- Exposure To Potentially Stranded Costs
Under traditional cost-based regulation, utilities have generally had an
obligation to serve, supported by an implicit promise of the opportunity to
recover prudently incurred costs. The most significant potential impact of
transitioning from a regulated to a competitive environment is "stranded costs."
Stranded costs are those costs incurred or commitments made 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, 1999, Virginia Power'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, Note (Q) to the
Consolidated Financial Statements);
. 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 (F) and
(O) to the Consolidated Financial Statements).
Dominion believes the capped rates provided by the 1999 legislation present
a reasonable opportunity to recover a substantial portion of our potentially
stranded costs. In the absence of capped rates, Virginia Power would otherwise
have been exposed, on a pre-tax basis, to an estimated $3.2 billion of potential
losses related to long-term power purchase commitments. See Note (C) to the
Consolidated Financial Statements. Recovery of potentially stranded costs
remains subject to numerous risks including, among others, exposure to long-term
power purchase commitment losses, future environmental compliance requirements,
changes in tax laws, decommissioning costs, inflation, increased capital costs,
and recovery of certain other items.
Rate Matters
In obtaining approval for the CNG Merger in North Carolina, Virginia Power
agreed not to request an increase in its North Carolina retail electric base
rates until after December 31, 2005, except for certain events that would have a
significant financial impact on Dominion.
Virginia Power's fuel rates are still subject to change under the annual
fuel cost adjustment proceedings in both Virginia and North Carolina.
Competition -- Retail Gas
Gas industry competition at the retail level is receiving increased attention
from both regulators and legislators. Governments in three of the states in
which Dominion, subsequent to the CNG Merger, operates distribution subsidiaries
have enacted or considered legislation regarding deregulation of natural gas at
the retail level. In Ohio, a 1996 law established customer choice as a state
policy in the supply of natural gas services. Implementation of the law, which
allows retail customers to obtain gas from an array of suppliers, is under way.
In Pennsylvania, legislation was enacted to unbundle gas utility merchant
functions and permit the Pennsylvania Public Utility Commission to certify
marketers, in addition to gas utilities, as suppliers of last resort, creating
competition in a traditional gas utility function. Virginia is currently
operating under a one-year unbundling pilot program, enacted in 1999. The
Virginia General Assembly is currently considering legislation to make the
program permanent.
Dominion Energy
Dominion Energy's future focus in its domestic power generation business is to
acquire and develop additional power generation in the MAIN to Maine region. The
MAIN region consists of the Mid-America Interconnected Network. This network
includes the range of electric utility service territories that begins in the
upper Midwest and covers an area northeastward through Maine. Dominion Energy
will benefit from the merger with CNG as it plans to develop natural gas-fired
power generation facilities along CNG's natural gas pipeline system. Dominion
has identified a number of potential development sites along CNG's natural gas
pipeline network in Ohio, Pennsylvania, New York, West Virginia and Virginia.
As indicated above, Dominion Energy's business is increasingly competitive,
particularly given the deregulation and consolidation activity the industry is
experiencing. In its existing independent power investments, Dominion Energy
intends to counter competition by focusing on cost structure, operating
efficiencies and actively exercising management control.
Environmental Matters
Dominion Energy is subject to rising costs resulting from a steadily increasing
number of federal, state and local laws and regulations designed to protect
human health and the environment. These laws and regulations affect future
planning and existing operations. They can result in increased capital,
operating and other costs as a result of compliance, remediation, containment
and monitoring obligations. Historically, these costs for utility operations
could be recovered from customers through 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, recovery may be
sought for only those environmental costs related to transmission and
distribution operations through regulated utility rates.
35
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Management's Discussion and Analysis of Financial Condition and Results of
Operations, continued
Environmental Protection and Monitoring Expenditures
Dominion Energy incurred $78 million, $72 million, and $71 million (including
depreciation) during 1999, 1998 and 1997, respectively, in connection with the
use of environmental protection facilities. Dominion Energy expects these
expenses to be $79 million in 2000. In addition, capital expenditures to limit
or monitor hazardous substances were $84 million, $22 million, and $25 million
for 1999, 1998 and 1997, respectively. The amount estimated for 2000 for these
expenditures is $148 million.
Clean Air Act Compliance
The Clean Air Act, as amended in 1990, requires Dominion Energy to reduce its
emissions of SO2 and NOx which are gaseous by-products of fossil fuel
combustion. The Clean Air Act also requires Dominion Energy to obtain operating
permits for all major emissions-emitting facilities. Permit applications have
been submitted for Dominion Energy's power stations.
The Clean Air Act's SO2 reduction program is based on the issuance of a
limited number of SO2 emission allowances, each of which may be used as a permit
to emit one ton of SO2 into the atmosphere or may be sold to someone else. The
EPA administers the program. Dominion Energy's compliance plans are reviewed
periodically and may include switching to lower sulfur coal, purchase of
emission allowances, and installation of SO2 control equipment. In December
1998, Dominion Energy initiated a capital project to install SO2 control
equipment on two units at the Mt. Storm power station at an estimated cost of
$126 million. These SO2 controls are expected to be operational by January 2002.
In July 1999, Dominion Energy's Kincaid plant converted to low-sulfur Powder
River Basin coal, further reducing SO2 emissions.
Dominion Energy began complying with Clean Air Act Phase I NOx limits at
eight of its units in Virginia in 1997, three years earlier than otherwise
required. As a result, the units will not be subject to more stringent Phase II
limits until 2008. Dominion Energy has established a plan to comply with the
Phase II limits at remaining coal-fired units subject to the Phase II limits.
In September 1998, EPA adopted a rule requiring 22 states, including states
within which we operate, to reduce and cap ozone season (May-September) NOx
emissions beginning in May 2003. The affected states were to submit a compliance
plan to EPA by September 1999, but a May 1999 ruling by the U.S. District Court
of Appeals in the DC Circuit has granted an indefinite stay of the states'
submittal requirements. However, in December 1999, EPA issued a finding in
support of petitions filed by several Northeastern states seeking relief from
long-range pollutant transport from utility and large industrial sources that
essentially enforces the same NOx emission caps beginning in May 2003. In
response to these requirements, Dominion Energy plans to install NOx reduction
equipment at its coal-fired generating facilities at an estimated capital cost
of approximately $554 million over the next five years. Whether these costs are
actually incurred and the timing of such expenditures are dependent on both the
outcome of pending litigation of these rules and on the implementation plans
adopted by the states in which Dominion Energy operates.
Evaluation and planning of future projects to comply with SO2 and NOx
reduction requirements are ongoing and will be influenced by changes in the
regulatory environment, availability of SO2 and NOx allowances, and emission
control technology.
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.
Dominion E&P
One of Dominion E&P's primary goals in its oil and gas business is to sustain
and increase earnings from non-tax credit oil and gas properties. Dominion E&P's
operating focus is on cost structure and operating efficiencies. Dominion E&P
expects to compete in regional markets by expanding its reserve base through
drilling and the acquisition of oil and gas properties.
Dominion E&P will benefit from the merger with CNG through the optimization
of the value of the Company's reserve portfolio. This optimization will be
achieved through the convergence of the Company's gas and electric products and
maximization of gas storage facilities, to achieve the most favorable market
conditions when selling energy. In addition, Dominion E&P's oil and gas
operations should realize the benefits of sharing past experiences and sound
business practices developed over time. This should help improve operational
efficiencies and minimize finding, developing, and lifting costs. Additional
efficiencies will be achieved by elimination of duplicate administrative
functions.
Dominion Capital
Under the SEC's order approving the CNG merger, Dominion must divest itself of
Dominion Capital within three years. No formal plan of divestiture has been
adopted. However, Dominion has begun identifying suitable buyers. Until Dominion
Capital is sold, Dominion will continue to operate these financial services
businesses and be subject to their risks.
The financial performance of Dominion Capital's diversified financial
services businesses depends to a certain degree on the movement of interest
rates, overall economic conditions, and increasing competition. Dominion Capital
intends to manage the effect of these issues by maintaining a balanced
diversified business approach, maintaining underwriting, credit quality and
service, and focusing on specialized markets. Dominion Capital expects continued
growth in its existing financial service business units through increased market
share, developing new products and services and entering new financial markets.
Business Opportunities
Because Dominion's industry is rapidly changing, especially in the U.S., there
are many opportunities for acquisitions of assets and business combinations. We
investigate any opportunity we learn about that may increase shareholder value
and build on our existing businesses. We have participated in the past and our
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.
36
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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 commodity prices, equity security prices,
interest rates, and foreign currency exchange rates as described below. Interest
rate risk generally is related to Dominion and its subsidiaries' outstanding
debt as well as their commercial, consumer, and mortgage lending activities.
Currency risk exists principally through Dominion E&P's investment in Canada
and some debt denominated in European currencies associated with Dominion
Energy's investment in Latin America. Dominion is exposed to equity price risk
through various portfolios of equity securities. Commodity price risk is
experienced in Dominion's power generation and oil and gas businesses, Dominion
Energy and Dominion E&P. They are exposed to effects of market shifts in the
sales prices they receive and pay for natural gas and electricity.
Dominion has utilized the sensitivity analysis methodology to disclose the
quantitative information for the interest rate, commodity price and foreign
exchange risks. Sensitivity analysis provides a presentation of the potential
loss of future earnings, fair values, or cash flows from market risk-sensitive
instruments over a selected time period due to one or more hypothetical changes
in interest rates, foreign currency exchange rates, commodity prices, or other
similar price changes. The tabular presentation methodology continues to be used
to disclose equity price market risk.
Interest Rate Risk Non-Trading Activities
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.
Dominion's sensitivity analysis estimates the impact of a hypothetical
change in interest rates on its variable-rate long-term and short-term financial
instruments and interest rate-sensitive derivatives. For financial instruments
outstanding at December 31, 1999, a hypothetical 10% increase in market interest
rates would decrease annual earnings by approximately $31 million. A similar
hypothetical increase in market interest rates, as determined at December 31,
1998, would have resulted in a decrease in annual earnings of $12 million.
Dominion Capital, through subsidiaries, retains ownership in the residual
classes of the asset-backed securities utilized to sell home equity loans
originated and purchased. At December 31, 1999, these assets are classified as
available for sale securities on the balance sheet and total $307 million.
The residual securities represent the net present value of the excess of
interest payable on the underlying mortgage collateral, net of interest payments
to outstanding bond holders, servicing costs, over-collateralization
requirements, and credit losses. Fair value of the residual is analyzed
quarterly by Dominion Capital 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.
Foreign Exchange Risk Activities
Dominion's exposure to foreign currency exchange rates results from debt which
is denominated in a currency different from the company's functional currency,
the U.S. dollar. In this situation, the company is subject to gains and losses
due to the relative change in the foreign currency rate of the debt versus the
U.S. dollar. This risk is mitigated by entering into contracts which are
denominated or indexed to the U.S. dollar. In the past, Dominion has also used
currency swaps to minimize this exposure. As of December 31, 1999, no currency
swaps were outstanding.
Dominion has performed sensitivity analyses to estimate its exposure to
foreign-exchange market risk. If the U.S. dollar declines in value by 10% as
compared to its value at December 31, 1999, the impact on the fair value of the
foreign denominated debt would be insignificant. Comparatively, the same
percentage decline of the U.S. dollar at December 31, 1998 would have resulted
in an insignificant increase in the fair value of the foreign denominated debt.
Commodity Price Risk Non-Trading Activities
Dominion E&P is exposed to the impact of market fluctuations in the sales price
it receives for its produced natural gas and oil. To reduce price risk caused by
market fluctuations, Dominion E&P generally follows a policy of hedging a
portion of its natural gas and oil sales commitments by selecting derivative
commodity instruments whose historical price fluctuations correlate strongly
with those of the production being hedged. Dominion E&P enters into options,
swaps, and collars to mitigate a loss in revenues, should natural gas or oil
prices decline in future production periods. Dominion E&P also mitigates price
risk by entering into fixed price sale agreements with physical purchasers of
natural gas.
When conducting sensitivity analysis of the change in the fair value of
Dominion E&P's oil and gas portfolio which would result from a hypothetical
change in the future market price of oil and natural gas, the fair value of the
contracts are determined from models which take into account estimated future
market prices of oil and natural gas, 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 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 $20 million and $8 million as of December 31, 1999
and December 31, 1998, respectively.
The impact of a change in oil and natural gas commodity prices on Dominion
E&P's oil and natural gas contracts at a point in time is not necessarily
representative of the results that will be realized when such contracts are
ultimately settled.
Commodity Price Risk Trading Activities
As part of its strategy to market energy from owned generation capacity and to
manage related risks, Dominion Energy 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 Energy 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 Energy seeks to use its generation capacity,
37
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations, continued
when not needed to serve electric utility service customers, to satisfy
commitments to sell energy.
Under sensitivity analysis, the fair value of the portfolio is a function
of the underlying commodity, contract prices and market prices represented by
each derivative commodity contract. For swaps, forward contracts and options,
market value reflects our best estimates considering over-the-counter
quotations, time value and volatility factors of the underlying commitments.
Exchange-traded futures and options are marked to market based on closing
exchange prices.
Dominion Energy has determined a hypothetical loss by calculating a
hypothetical fair value for each contract assuming a 10% unfavorable change in
the market prices of the related commodity and comparing it to the fair value of
the contracts based on market prices at December 31, 1999 and 1998. This
hypothetical 10% change in commodity prices would have resulted in a
hypothetical loss of approximately $5 million and $13 million in the fair value
of Dominion Energy's commodity contracts as of December 31, 1999 and 1998,
respectively. The commodity contracts' sensitivity to unfavorable price changes
decreased in 1999 primarily due to reduced price exposure from options included
in the portfolio at December 31, 1999, as compared to December 31, 1998.
The sensitivity analysis does not include the price risks associated with
utility operations, including those underlying utility fuel requirements. In the
normal course of business, Dominion Energy also faces risks that are either
nonfinancial or nonquantifiable. Such risks principally include credit risk,
which is not reflected in the sensitivity analysis above.
Equity Price Risk Activities
Dominion is subject to equity price risk due to marketable securities held as
investments and in trust funds. Trust funds are maintained by Virginia Power in
order to fund certain nuclear decommissioning costs.
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, other than trading, held by Dominion at
December 31, 1999 and 1998.
1999 1998
--------------------------------------------
Fair Fair
Cost Value Cost Value
(millions)
Trading:
Short-term marketable
securities $ 1 $ 2 $ 1 $ 1
Other than trading:
Marketable securities $134 $126 $165 $169
Nuclear decommissioning
trust investments $274 $565 $252 $470
============================================
Other Risk Management Factors and Matters
Foreign Risks
Dominion's investment in Corby, a generation project in the United Kingdom, and
a significant portion of DEI's operations are located in foreign countries.
DEI's foreign operations include interests in Latin American power production
included in Dominion Energy and certain Canadian activities included in Dominion
E&P. These investments represent primarily investments in affiliates which own
energy-related production, generation and transmission facilities. Dominion is
exposed to foreign currency risk and sovereignty risk with respect to these
investments. Sovereignty risk relates to losses due to actions initiated by
foreign governments that preclude actions by Dominion to mitigate such losses.
Dominion seeks to manage this risk by limiting its exposure in any single
country and by limiting its investments to those countries and regions where it
believes these risks are less significant.
The sale of DEI's interests in Belize and Peru in November 1999 and the
pending completion of the sale of its interests in Argentina and Bolivia in 2000
will reduce Dominion's exposure to foreign currency and sovereignty risk.
Financial Service Business Risk
Dominion Capital manages a number of risks in its operations in addition to
interest rate risk as discussed above. Its lending groups are concerned with
credit risks, loan loss reserves, prepayments, and oil and natural gas market
fluctuations.
Credit risks are managed by:
. experienced management and effective underwriting policies and procedures;
. controlling the average loan size;
. geographic diversification of the portfolio;
. compensating for risk grade by lowering loan to values and higher interest
rates; and
. servicing and quality control efforts.
Commercial credit risks are managed by:
. diversification of clients by industry classification;
. primarily maintaining first position in collateralized assets;
. underwriting by experienced professionals and effective underwriting
policies and procedures; and
. portfolio monitoring and credit collection.
Dominion Capital's mortgage investments are adversely impacted by increases
in the rate at which home equity loans prepay. Accordingly, Dominion Capital
actively manages this risk by:
. including prepayment penalties, when possible, as part of loan structure;
. aggressively enforcing premium recapture provisions with sellers of
mortgage loans;
. limiting the acquisition of below market (teaser) start rates on adjustable
rate mortgages to those covered by prepayment penalties; and
. constructing prudent valuation assumptions based on historical prepayment
rates globally and within the company.
The market price of natural gas assets are monitored and coverages are
maintained in the underwriting structures of Dominion Capital's loan assets as
well as oil and gas hedges.
38
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Notes to Consolidated Financial Statements
NOTE A: Nature of Operations
General Organization and Legal Description Dominion Resources, Inc. (Dominion or
the Company) is a holding company headquartered in Richmond, Va. Its principal
subsidiary is Virginia Electric and Power Company (Virginia Power), which is a
regulated public utility. Virginia Power is engaged in the generation,
transmission, distribution and sale of electric energy within a 30,000 square
mile area in Virginia and northeastern North Carolina. It sells electricity to
retail customers (including government agencies) and to wholesale customers such
as rural electric cooperatives, power marketers and municipalities. The Virginia
service area comprises about 65 percent of Virginia's total land area, but
accounts for 80 percent of its population. 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 service territory.
Dominion's subsidiary, Dominion Energy, Inc. (DEI), is engaged in
independent power production and oil and gas exploration, development and
production. Some of the independent power and natural gas and oil businesses are
located in foreign countries. In Latin America, DEI is engaged in power
generation. See Note (V) for information about the sale of such interests. In
Canada, DEI is engaged in natural gas exploration, production and storage.
Including the Latin American power generation assets being sold in 2000, DEI's
net investment in foreign operations was approximately $277 million at December
31, 1999.
Dominion Capital, Inc. (Dominion Capital) is Dominion's financial services
subsidiary. Dominion Capital's primary business includes commercial lending,
merchant banking, asset management and residential mortgage lending.
Dominion's United Kingdom subsidiary, Dominion U.K. Holding, Inc., owns an
80% interest in Corby Power Station (Corby), a 350-megawatt natural gas-fired
power station located in Northamptonshire, about 90 miles north of London. Until
mid-1998, this subsidiary also owned East Midlands Electricity, plc (East
Midlands), an electricity distribution and supply company in the United
Kingdom.
Dominion evaluates its businesses along functional lines rather than legal
entities. The functional segments include Dominion Delivery (representing the
regulated transmission and distribution operations of Virginia Power); Dominion
Energy (including the generation-related operations of Virginia Power and DEI);
Dominion E&P (representing oil and gas exploration and production activities);
Dominion Capital (consistent with legal entity described above); and Corporate
Operations (including general corporate items as well as Corby).
In 1999, Dominion announced its merger with Consolidated Natural Gas
Company (CNG) which closed on January 28, 2000. As a result, Dominion became a
registered holding company under the Public Utility Holding Company Act of 1935
(the 1935 Act). See Note (X) for further discussion.
NOTE B: 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 revenues and expenses during the reporting period.
Actual results could differ from those estimates.
The Consolidated Financial Statements include the accounts of Dominion and
its subsidiaries. In consolidation, all significant intercompany transactions
and accounts have been eliminated.
Accounting for the utility business 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.
As discussed in Dominion's Form 8-K, filed March 29, 1999, Virginia Power
discontinued the application of Statement of Financial Accounting Standards No.
71 (SFAS No. 71), Accounting for the Effects of Certain Types of Regulation, to
its generation operations. The effect thereof was an after-tax charge of $255
million. See Note (C).
In connection with the discontinuance of SFAS No. 71, for its utility
generation operations, Dominion prospectively changed certain of its accounting
policies to those used by nonregulated entities. These policy changes primarily
relate to the capitalization of interest on and depreciation of
generation-related property. Dominion also reevaluated the economic useful life
estimates of its generation-related property in light of the scheduled
deregulation of the generation business in Virginia. In addition, Dominion no
longer provides for the cost of removal in its provision for depreciation of
generation-related utility property, as prescribed by regulatory accounting
practices. Effective April 1999, such costs are expensed as incurred. Also,
Dominion no longer records retirements of generation-related utility property by
charging accumulated depreciation. Rather, Dominion records gains and losses
upon retirement of such property based upon the difference between proceeds
received, if any, and the property's undepreciated basis at the retirement date.
The overall impact of these changes was not material to Dominion's results of
operations and financial condition.
Earnings per share Basic earnings per common share are calculated by dividing
net income by the average number of common shares outstanding during the year.
Under Statement of Financial Accounting Standards No. 128, Earnings Per Share,
and Emerging Issues Task Force (EITF) Topic No. D-72, Effect of Contracts That
May Be Settled in Stock or Cash on the Computation of Diluted Earnings Per
Share, diluted earnings per share includes an adjustment to reflect the cost
incurred under a total return equity swap associated with Dominion's repurchase
of Dominion common stock. The adjustment reduced basic earnings per share by
$0.07. For more information on the transaction, see Note (P).
Revenue Revenue is recorded on the basis of services rendered, commodities
delivered or contracts settled and include amounts yet to be billed to
customers. Revenues from trading activities include realized commodity contract
revenues, net of related cost of sales, amortization of option premiums, and
unrealized gains and losses resulting from marking to market those commodity
contracts not yet settled. Dividend income on securities owned is recognized on
the ex-dividend date. Interest income is accrued on the unpaid principal
balance.
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.
Approximately 95% of Virginia Power's rate regulated fuel costs are subject
to deferral accounting. Deferral accounting provides that the difference between
reasonably incurred actual expenses and the level of expenses included in
current rates is deferred and matched against future revenues. Fuel, net
includes the effect of this deferral accounting and may therefore show expenses
that are marginally higher or lower than the actual cost of fuel consumed during
the period.
Investments in Affiliates Investments in common stocks of affiliates
representing 20% to 50% ownership, and joint ventures and partnerships
representing generally 50% or less ownership interests, are accounted for under
the equity method.
39
<PAGE>
Notes to Consolidated Financial Statements, continued
Dominion also uses the equity method when accounting for its 80% investment
in Corby, as the Company believes that Corby's governing agreements give
substantive participating rights to the minority shareholder. Corby owns and
operates a 350-megawatt gas-fired power station in England. At December 31,
1999, Corby's assets and liabilities were as follows: current assets of $40
million, current liabilities of $31 million, non-current assets of $263 million,
and non-current liabilities of $232 million. Corby had total revenues of $137
million and total expenses (including interest and taxes) of $122 million in
1999.
Goodwill Goodwill is the excess of the cost of net assets acquired in business
combinations over their fair value. It is amortized on a straight-line basis
over periods ranging from 20 to 40 years. Goodwill is evaluated for impairment
at least annually.
Property, Plant and Equipment Property, plant and equipment is recorded at
original cost, which includes labor, materials, services, and other indirect
costs.
The cost of acquisition, exploration and development of natural resource
properties is accounted for under the successful efforts method.
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 1999, 1998 and 1997, $30
million, $10 million and $4 million of interest cost was capitalized,
respectively.
Depreciation, Depletion and Amortization Depreciation of power generation plant
(other than nuclear fuel) is computed using the straight-line method based on
projected useful service lives. For Virginia Power's transmission and
distribution assets, which remain subject to SFAS No. 71, the cost of
depreciable utility plant retired and the cost of removal, less salvage, are
charged to accumulated depreciation. The provision for depreciation applicable
to utility operations resulted in a weighted average rate of 3.2% for 1999, 1998
and 1997.
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.
Natural gas properties are depleted using the units-of-production method.
Federal 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 using
presently enacted tax rates in accordance with SFAS No. 109, Accounting for
Income Taxes. Temporary differences occur when events and transactions
recognized for financial reporting result in taxable or tax-deductible amounts
in future periods. The regulatory treatment of temporary differences can differ
from the requirements of SFAS No. 109. Accordingly, a regulatory asset has been
recognized if it is probable 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 The financial statements reflect assets and costs in
accordance with SFAS No. 71 and related literature. SFAS No. 71 provides that
certain expenses normally reflected in income are deferred on the balance sheet
as regulatory assets. Regulatory assets represent probable future revenue
associated with certain costs that will be recovered from customers through the
ratemaking process. See Notes (C) and (E) for information on regulatory assets
and the impact of legislation on continued application of SFAS No. 71.
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 any expenses
incurred in the issuance of long-term debt, including premiums and discounts
associated with such debt, over the lives of the respective issues. Any gains or
losses resulting from the refinancing of debt 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 and accounted for in the following manner: 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 or 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. However, for a discussion of the treatment for securities held in
nuclear decommissioning trusts and classified as available for sale, see
Note (H).
Mortgage Investments Mortgage investments at December 31, 1999 consist of
subordinated bonds and interest-only strips retained at securitization of the
mortgage loans. In accordance with SFAS No. 134, Accounting for Mortgage-Backed
Securities Retained after the Securitization of Mortgage Loans Held for Sale by
a Mortgage Banking Enterprise, mortgage investments are classified as available
for sale as defined by SFAS No. 115, Accounting for Certain Investments in Debt
and Equity Securities. Changes in the fair value of the mortgage investments are
reported in accumulated other comprehensive income. Fair value of the residual
is analyzed quarterly on a security level stratum, further disaggregated between
the fixed rate and adjustable rate pieces of interest-only strips 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.
Mortgage Loans in Warehouse Mortgage loans in warehouse 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 in warehouse are carried at the lower of cost or
market value.
40
<PAGE>
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,
1999 and 1998, the allowance for credit losses for loans receivable, net was $47
million.
Gain on Sale of Loans Gain on sale of loans represents the present value of
amounts based on the difference between the interest rate received on the
mortgage loans and the interest rate received by the investor in the securities
after considering the effects of estimated prepayments, credit losses, costs to
service the mortgage loans, and non-refundable fees and premiums on loans sold.
Gains on the sale of loans are recognized on the settlement date and are based
on the relative fair market value of the portion sold and retained. Concurrently
with recognizing such gain on sale, a corresponding asset representing interest-
only strips retained at securitization is recorded based on the net present
value of the projected cash flows. The asset, which is classified as available
for sale, is amortized in proportion to the estimated income received.
Loan Servicing Rights SFAS No. 125, Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities, (SFAS No. 125) requires
that a mortgage banking enterprise recognize as separate assets 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. The total cost of the mortgage loans is allocated to
the mortgage servicing rights and the loans (without the mortgage servicing
rights) based on their relative fair values. The cost of servicing rights is
capitalized and amortized in proportion to, and over the period of, estimated
future net servicing income.
In order to determine the fair value of the servicing rights, the company
uses market prices under comparable servicing sales contracts, or alternatively,
it uses a valuation model that calculates the present value of future cash
flows.
In accordance with SFAS No. 125, the company assesses the impairment of the
capitalized mortgage servicing portfolio 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.
Derivatives -- Other Than Trading Dominion utilizes futures and forward
contracts and derivative instruments, including swaps, caps and collars, to
manage exposure to fluctuations in interest rates, foreign currency exchange
rates, lease payments, and natural gas and electricity prices.
These futures, forwards and derivative 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
recorded on the balance sheet and 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 stock-holder's 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 closing
exchange 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 and income -- Other. 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.
Dominion has used total return equity swaps to reacquire shares of its
outstanding common stock. Dominion has the option to settle any price
fluctuation settlement requirements and fees with the third party counterparty
in either cash or shares of common stock. Due to Dominion's ability to issue
shares to resolve settlement issues with respect to the swap, Dominion records
all amounts received or paid under this arrangement 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.
41
<PAGE>
Notes to Consolidated Financial Statements, continued
Cash Current banking arrangements generally do not require checks to be funded
until actually presented for payment. At December 31, 1999 and 1998, accounts
payable included the net effect of checks outstanding but not yet presented for
payment of $61 million and $58 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.
Reclassification Certain amounts in the 1998 and 1997 Consolidated Financial
Statements have been reclassified to conform to the 1999 presentation.
NOTE C: Extraordinary Item and 1998 Rate Settlement
Extraordinary Item -- Discontinuance of SFAS No. 71 During its 1998 session, the
Virginia legislature passed a law that required a transition to retail
competition between January 1, 2002 and January 1, 2004, but left the details as
to how that would be accomplished to future enabling legislation.
In March 1999, the Governor of Virginia signed into law legislation
establishing a detailed plan to restructure the electric utility industry in
Virginia. The major elements of the bill included:
. Phase-in of retail customer choice beginning in 2002 with full retail
customer choice by 2004; the schedule is to be determined by the Virginia
Commission, which has the authority to accelerate or delay implementation
under certain conditions; however, the phase-in of retail customer choice
may not be delayed beyond January 1, 2005;
. No mandatory divestiture of generating assets;
. Deregulation of generation in 2002;
. Capped base rates from January 1, 2001 to July 1, 2007;
. Recovery of net stranded costs through capped rates or a wires charge paid
by those customers opting, while capped rates are in effect, to purchase
energy from a competitive supplier;
. Cost-based recovery of fuel expenses until July 2007;
. Consumer protection safeguards;
. Establishment of default service beginning January 1, 2004; and
. Creation of a Legislative Transition Task Force to oversee the
implementation of the statute.
Under this legislation, Virginia Power's base rates will remain unchanged
until July 2007 and recovery of generation-related costs will continue to be
provided through the capped rates. In addition, under companion legislation
enacted by Virginia in 1999, providers of electric service will be subject to
corporate income taxes in lieu of gross receipts taxes, effective in 2001.
As discussed in Note (B), Dominion's financial statements reflect
regulatory assets and liabilities under cost-based rate regulation in accordance
with SFAS No. 71. Rate-regulated companies are required to write off regulatory
assets against current earnings whenever changes in facts and circumstances
result in those assets no longer satisfying criteria for recognition as defined
by SFAS No. 71. The legislation's deregulation of generation was an event that
required discontinuation of SFAS No. 71 for utility generation operations.
Virginia Power's transmission and distribution operations continue 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,
Virginia Power evaluated to what extent recovery of regulatory assets would be
provided through the capped rates during the transition period. EITF Issue No.
97-4, "Deregulation of the Pricing of Electricity Issues Related to the
Application of FASB Statements No. 71, Accounting for the Effects of Certain
Types of Regulation, and No. 101, Regulated Enterprises -- Accounting for the
Discontinuance of Application of FASB Statement No. 71" (EITF Issue 97-4),
provides guidance about writing off regulatory assets when SFAS No. 71 is
discontinued for only a portion of a utility's operations. The provisions of the
Virginia legislation provide an opportunity to recover generation-related
costs, including certain regulatory assets, through capped rates prior to July
2007. Under EITF Issue 97-4, such generation-related regulatory assets will
continue to be recognized until they are recovered through capped rates.
Generation-related assets and liabilities that will not be recovered through the
capped rates were written off in the first quarter of 1999, resulting in an
after-tax charge to earnings of $255 million. This amount also included the
write-off of regulatory assets previously assigned to wholesale requirements
customers. See Note (E) for further discussion of net regulatory assets at
December 31, 1999.
In addition to the write-off of generation-related net regulatory assets,
the $255 million charge included a write-off of approximately $18 million,
after-tax, of other generation-related assets. Pursuant to EITF Issue 97-4, a
corresponding regulatory asset of $23 million, representing the amount expected
to be recovered during the transition period related to these assets, was
established. The extraordinary item also included the write-off of approximately
$38 million, after-tax, of deferred investment tax credits.
The events or changes in circumstances that cause discontinuance of SFAS
No. 71, and write-off of regulatory assets, also require a review of utility
plant assets and long-term power purchase contracts for possible impairment.
This review was based on estimates of possible future market prices, load
growth, competition and many other assumptions. Virginia Power evaluated its
generation assets in accordance with the provisions of SFAS No. 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of. Those evaluations included the effects of nuclear decommissioning and other
currently identified environmental expenditures. Based on those analyses which
were highly dependent on the underlying assumptions, no plant write-downs were
appropriate at that time.
Virginia Power reviewed its long-term power purchase commitments 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 of the Company's long-term power purchase contracts
indicated no loss recognition is appropriate at this time. Other projections 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 exposure
related to Virginia Power's power purchase contracts would have otherwise been
approximately $3.2 billion.
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
customer load projections, generating unit availability, the timing and type of
future capacity additions in Virginia Power's market area, and market prices for
fuel and electricity. The projections are subject to re-evaluation.
42
<PAGE>
Virginia 1998 Rate Settlement
In 1998, Virginia Power reached a settlement with the Virginia Commission to
resolve then outstanding rate proceedings. The settlement provided for the
following:
. A two-phased base rate reduction: $100 million per annum beginning March 1,
1998 with one additional $50 million per annum reduction beginning March 1,
1999;
. A base rate freeze through February 28, 2002 unless a change is necessary
to protect the legitimate interests of the Company, its shareholder or
ratepayers;
. An immediate, one-time refund of approximately $150 million for the period
March 1, 1997 through February 28, 1998;
. A discontinuation of deferral accounting for purchased power capacity
expenses effective February 28, 1998;
. A write-off of a minimum of $220 million of regulatory assets in addition
to normal amortization by February 28, 2002.
Due to the required write-off of a minimum of $220 million of regulatory
assets in addition to normal amortization thereof during the rate freeze period,
Dominion evaluated regulatory assets for potential impairment under SFAS No. 71.
Based on the uncertainty of Virginia Power's earnings potential for regulatory
purposes during the rate freeze period, management could no longer conclude that
recovery of the $220 million was probable. Previously identified reductions in
operating costs of $38 million in 1997 and $27 million in 1996 were used to
establish a reserve for potential impairment of regulatory assets. Accordingly,
Dominion charged $159 million to second quarter 1998 earnings, which when
combined with the reserve for accelerated cost recovery accrued in 1996 and
1997, provided for the impairment of regulatory assets resulting from the
settlement.
NOTE D: Taxes
Income before provision for income taxes was as follows:
---------------------------------------
Year ended December 31, 1999 1998 1997
(millions)
U.S. $792 $397 $713
Non-U.S. 36 472 (34)
---------------------------------------
Total $828 $869 $679
=======================================
The provision for income taxes, classified by the timing and location of
payment, was as follows:
---------------------------------------
At December 31, 1999 1998 1997
(millions)
Current:
U.S. $187 $153 $222
State 18 25 9
Non-U.S 4 101 25
---------------------------------------
Total Current 209 279 256
---------------------------------------
Deferred:
U.S. 64 24 22
State (3)
Non-U.S 1 23 (28)
---------------------------------------
Total Deferred 65 44 (6)
---------------------------------------
Amortization of deferred
investment tax credits--net (15) (17) (17)
---------------------------------------
Total Provision $259 $306 $233
=======================================
The statutory U.S. federal income tax rate reconciles to the effective income
tax rates as follows:
---------------------------------------
Year ended December 31, 1999 1998 1997
U.S. statutory rate 35.0% 35.0% 35.0%
Utility plant differences 0.3 3.0 0.9
Preferred dividends of
Virginia Power 1.6 1.4 1.5
Amortization of investment
tax credits (1.8) (1.9) (2.0)
Nonconventional fuel credit (4.4) (2.8) (3.0)
UK windfall profits tax 0.0 0.0 12.1
Other--benefits and taxes related
to foreign operations (0.2) (0.1) 3.6
State taxes net of federal benefit 1.5 1.5 0.7
Other, net (0.7) (0.9) (2.2)
---------------------------------------
Effective tax rate 31.3% 35.2% 46.6%
=======================================
The effective income tax rate includes state and foreign income taxes. The
effective income tax rate was higher in 1997 due to the one-time windfall
profits tax at East Midlands.
The 1999 United Kingdom corporate income tax rate was 30%, compared to 31%
and 33% in 1998 and 1997, respectively. Income tax expense from continuing
operations for 1998 has been reduced by $8 million to reflect the decrease in
deferred tax liabilities resulting from the 1% decrease in the corporate tax
rate. Income tax expense from continuing operations in 1997 has been reduced by
$16 million to reflect the decrease in deferred tax liabilities resulting from
the 2% decrease in the corporate tax rate.
Dominion's net noncurrent deferred tax liability is attributable to:
-----------------------
At December 31, 1999 1998
(millions)
Assets:
Deferred investment tax credits $ 52 $ 78
-----------------------
Total deferred income tax asset 52 78
=======================
Liabilities:
Depreciation method and plant
basis differences 1,485 1,498
Income taxes recoverable
through future rates 20 155
Partnership basis differences 159 168
Other 87 50
-----------------------
Total deferred income tax liability 1,751 1,871
-----------------------
Net deferred income tax liability $1,699 $1,793
=======================
43
<PAGE>
Notes to Consolidated Financial Statements, continued
NOTE E: Regulatory Assets
Regulatory assets included the following:
---------------
At December 31, 1999 1998
(millions)
Income taxes recoverable through future rates $ 57 $439
Cost of decommissioning DOE uranium
enrichment facilities 55 62
Deferred losses on reacquired debt, net 15 31
Deferred fuel 63 28
Other 31 60
---------------
Total $221 $620
===============
The incurred costs underlying these regulatory assets may represent expenditures
by Virginia Power or may represent the recognition of liabilities that
ultimately will be settled at some time in the future. See Note (C) for
information about the write-off of regulatory assets that resulted from 1999
deregulation legislation and the settlement of Virginia Power's 1998 Virginia
rate proceeding.
Income taxes recoverable through future rates represent principally the tax
effect of depreciation differences not normalized in earlier years for
rate-making purposes. These amounts are amortized as the related temporary
differences reverse. Such amounts are net of related regulatory liabilities and
$43 million associated with deferred income taxes which were established at
rates in excess of the current federal rate and are subject to Internal Revenue
Code normalization requirements.
The costs of decommissioning the Department of Energy's (DOE) uranium
enrichment facilities represents the unamortized portion of Virginia Power's
required contributions to a fund for decommissioning and decontaminating DOE's
uranium enrichment facilities. Virginia Power is making such contributions over
a 15-year period with escalation for inflation. These costs are currently being
recovered in fuel rates.
Where permitted by appropriate regulatory jurisdictions for the portion of
Virginia Power's operations that remain subject to cost-based regulation, losses
on reacquired debt are deferred and amortized over the lives of the new issues
of long-term debt. Gains or losses resulting from the redemption of debt without
refinancing are amortized over the remaining lives of the redeemed issues.
Deferred fuel accounting provides that the difference between reasonably
incurred actual expenses and the recovery for such costs included in current
rates is deferred and matched against future revenue.
NOTE F: Property, Plant and Equipment
Major classes of property, plant and equipment and their respective balances
are:
---------------------
At December 31, 1999 1998
(millions)
Utility:
Production $ 7,758 $ 7,714
Transmission 1,517 1,422
Distribution 4,835 4,682
Other electric 901 941
Plant under construction 677 449
Nuclear fuel 801 816
---------------------
Total utility 16,489 16,024
---------------------
Nonutility:
Natural gas properties 1,127 710
Independent power properties 811 1,190
Other 219 182
---------------------
Total nonutility 2,157 2,082
---------------------
Total property, plant and equipment $18,646 $18,106
=====================
When Virginia Power'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 $818 million at December 31, 1999.
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 1997 through 1999. However, an additional $10 million was
expensed in 1997 based on an expected increase in the decommissioning
collections for 1997 as provided in Virginia Power's rate case then pending
before the Virginia Commission. Since the Virginia rate case settlement did not
include such an increase, the 1998 expense provision was decreased by $10
million. Therefore, the expense levels were $36 million, $26 million and $46
million in 1999, 1998 and 1997, respectively.
Net earnings of the trusts' investments are included in Other income. In
1999, 1998 and 1997, net earnings were $17 million, $18 million and $21 million,
respectively. The accretion of the decommissioning obligation is equal to the
trusts' net earnings and is also recorded in Other income.
44
<PAGE>
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
unrealized gains and losses on the trusts' investments. At December 31, 1999,
the net unrealized gains were $291 million, which is an increase of $60 million
over the December 31, 1998 amount of $231 million. The accumulated provision for
decommissioning at December 31, 1999 was $818 million. It was $705 million at
December 31, 1998.
The NRC requires nuclear power plant owners to annually update minimum
financial assurance amounts for the future decommissioning of the nuclear
facilities. Virginia Power's 1999 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.
The Financial Accounting Standards Board (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. During its deliberations, FASB expanded the scope of the
project to include similar unavoidable obligations to perform closure and
post-closure activities for other long-lived assets, possibly including
non-nuclear power plants. Any forthcoming standard may also impact regulated
utility plant depreciation practices, the impact of which cannot be determined
at this time.
The following information relates to Virginia Power's proportionate share
of jointly owned utility plants at December 31, 1999.
----------------------------------------
Bath
County North
Pumped Anna Clover
Storage Power Power
Station Station Station
Ownership interest 60.0% 88.4% 50.0%
(millions)
Plant in service $1,069 $1,824 $536
Accumulated depreciation 274 1,066 56
Nuclear fuel 361
Accumulated amortization of
nuclear fuel 334
Construction work in progress 61 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 G: Short-Term Debt and Credit Agreements
Dominion and its subsidiaries have credit agreements with various expiration
dates. Dominion and its subsidiaries pay fees in lieu of compensating balances
in connection with these credit agreements. These agreements provided for
maximum borrowings of $5.1 billion and $4.6 billion at December 31, 1999 and
1998, respectively. At December 31, 1999 and 1998, $2.3 billion and $1.2
billion, respectively, was borrowed under such agreements.
Dominion and its subsidiaries' credit agreements supported $1.2 billion and
$297 million of commercial paper at December 31, 1999 and 1998, respectively. A
total of $813 million and $222 million of the commercial paper was classified as
short-term in 1999 and 1998, 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 $364 million and $75 million of
the commercial paper was classified as long-term in 1999 and 1998, respectively.
These borrowings are used primarily to fund operational needs at Dominion and
its subsidiaries. For discussion of interim financing associated with the CNG
merger, see Note (X).
A summary of the amounts that are classified as short-term debt at
December 31 follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------
1999 1998
Weighted Weighted
Amount Average Amount Average
Outstanding Interest Rate Outstanding Interest Rate
(millions, except percentages)
<S> <C> <C> <C> <C>
Commercial paper $813 5.3% $222 5.4%
Term-notes 57 9.7% 79 7.8%
-----------------------------------------------------------
Total $870 $301
===========================================================
</TABLE>
NOTE H: Investment Securities
Securities classified as available-for-sale as of December 31 follow:
<TABLE>
<CAPTION>
-----------------------------------------------------------
Gross Gross
Unrealized Unrealized Aggregate
Security Type Cost Gains Losses Fair Value
(millions)
<S> <C> <C> <C> <C>
1999
Equity $134 $ 2 $10 $126
Debt $396 $10 $386
1998
Equity $165 $11 $ 7 $169
Debt $333 $ 2 $331
===========================================================
</TABLE>
Debt securities held at December 31, 1999 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, 1999 and 1998, the proceeds from the sales
of available-for-sale securities were $35 million and $40 million, respectively.
The gross realized gains were $5 million and $3 million for 1999 and 1998,
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 a decrease in the separate component of
shareholders' equity during the years ended December 31, 1999 and 1998 of $17
million, net of tax, and $6 million, net of tax, respectively. The changes in
net unrealized holding gains and losses on trading securities increased earnings
during the years ended December 31, 1999 and 1998 by $1 million and $9 million,
respectively.
For a discussion of investment securities held in nuclear decommissioning
trusts, see Note (F).
45
<PAGE>
Notes to Consolidated Financial Statements, continued
NOTE I: 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.
Cash and Cash Equivalents The carrying amount of these items is a reasonable
estimate of their fair value.
------------------------------------------
Carrying Amount Estimated Fair Value
------------------ ----------------------
At December 31, 1999 1998 1999 1998
(millions)
Assets:
Cash and cash equivalents $ 280 $ 426 $ 280 $ 426
Trading securities 2 1 2 1
Mortgage loans in warehouse 119 140 119 146
Commodity-based swaps
and options, trading 6 6 10 10
Available-for-sale securities 512 500 512 500
Loans and notes receivable
and finance receivables
held for sale 2,131 1,722 2,131 1,768
Nuclear decommissioning
trust funds 818 705 818 705
------------------------------------------
Liabilities:
Short-term debt 870 301 870 301
Commodity-based swaps
and options, trading 5 9 5 9
Long-term debt 7,317 6,719 7,185 6,971
Preferred securities of
subsidiary trusts 385 385 359 430
Preferred stock 180 180 181 186
Loan commitments 937 762
------------------------------------------
Unrecognized financial
instruments:
Forward treasury locks 2
Interest rate-swaps (15) (6)
Equity -- total return swap (19)
Swaps, collars and futures
contracts 5 23
==========================================
Investment Securities and Nuclear Decommissioning Trust Funds The estimated fair
value is based on quoted market prices, dealer quotes, and prices obtained from
independent pricing sources.
Mortgage Loans in Warehouse The fair value of mortgage loans in warehouse is
based on outstanding commitments from investors.
Commodity-Based Swaps and Options, Trading Fair value reflects the Company's
best estimates considering over-the-counter quotations, time value and
volatility factors of the underlying commitments.
Loans and Notes Receivable and Finance Receivables The carrying value
approximates fair value due to the variable rate or term structure.
Short-Term Debt and Long-Term Debt 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.
Preferred Securities of Subsidiary Trusts The fair value is based on market
quotations.
Preferred Stock The fair value of the fixed-rate preferred stock subject to
mandatory redemption was estimated by discounting the dividend and principal
payments for a representative issue of each series over the average remaining
life of the series.
Loan Commitments 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.
Total Return and Interest Rate Swaps 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.
Forward Treasury Lock Contracts Fair value is based on the difference between
the yield at December 31, 1998 on the 30-year treasury note and such rates
specified in the contracts.
Total Return Equity Swaps The fair value of the total return equity swap is
estimated by obtaining quotes from brokers.
Swaps, Collars, and Futures Contracts Derivatives used by the Company to hedge
its exposure to interest rate fluctuations and mitigate its exposure to future
gas price fluctutations. These instruments are marked to market with any
unrealized gains or losses deferred until the hedged item is sold.
46
<PAGE>
NOTE J: Long-Term Debt
<TABLE>
<CAPTION>
-----------------------------------------------------
At December 31, 1999 1998
Balance Interest Rate(6) Balance Interest Rate(6)
(millions)
Virginia Power First and
Refunding Mortgage Bonds(1):
<S> <C> <C> <C> <C>
1989 Series B, due 1999 $ 100 8.9%
1993 Series C, due 2000 $ 135 5.9% 135 5.9
1993 Series E, due 2001 100 6.0 100 6.0
1992 Series E, due 2002 155 7.4 155 7.4
1993 Series F, due 2002 100 6.0 100 6.0
1993 Series B, due 2003 200 6.6 200 6.6
Various series, due 2004-2007 665 7.6-8.0 665 7.6-8.0
Various series, due 2021-2025 1,101 5.4-8.8 1,125 5.4-8.8
-----------------------------------------------------
Total First and Refunding Mortgage Bonds 2,456 2,580
-----------------------------------------------------
Other long-term debt:
Dominion:
Commercial paper(2) 300 3
Virginia Power:
Term notes, fixed interest rate, due 1998-2008 422 5.7-10.0 563 5.7-10.0
Various series, due 2004-2038 375 6.7-7.1 150 7.1
Tax exempt financings(3):
Money market municipals, due 2007-2027 489 3.3 489 3.5
Other, due 2022-2024 29 5.4 29 5.4
Dominion UK:
Variable rate debt, due 1998-2007 54 5.8 55 7.6
DEI:
Secured revolving lines of credit, variable rates, due 2002, 2005 303 5.6-6.0
-----------------------------------------------------
Total other long-term debt 1,972 1,289
-----------------------------------------------------
Nonrecourse nonutility:
Dominion:
Bank loans, due 2005-2008(5) 18 5.8 19 9.25
DEI:
Revolving credit agreements, due 2001 363 5.7-6.7 432 5.4-6.0
Bank loans, due 1998-2024 39 4.5-6.6 45 4.5-6.6
Senior secured bonds, fixed rate, due 2020 265 7.3 265 7.3
Bonds, due 2001-2003 60 7.7-8.8
Other 3 5.4 19 9.7-9.9
Dominion Capital:
Senior notes(4):
Fixed rate, due 2000-2003 96 6.1-7.6 96 6.1-7.6
Term notes, fixed rate, due 1998-2012 159 6.5-12.1 175 6.5-12.1
Line of credit, variable rate, due 1998-2000 48 6.2 118 6.2
Line of credit, fixed rate, due 2000 44 6.2
Notes payable, due 2002-2006 298 6.5 350 6.0
Commercial paper 64 5.6 72 5.2
Revolving credit agreements 1,492 5.9 1,200 5.5-6.2
-----------------------------------------------------
Total nonrecourse -- nonutility debt 2,889 2,851
-----------------------------------------------------
Total debt 7,317 6,720
-----------------------------------------------------
Less amounts due within one year:
First and Refunding Mortgage Bonds 135 100
Term notes and Loans 60 221
Nonrecourse -- nonutility 161 122
-----------------------------------------------------
Total amount due within one year 356 443
-----------------------------------------------------
Less unamortized discount, net of premium 25 25
-----------------------------------------------------
Total long-term debt $6,936 $6,252
=====================================================
</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 (G).
(3) Certain pollution control equipment at Virginia Power's generating
facilities has been pledged or conveyed to secure these financings.
(4) Certain common stock owned by Dominion Capital is pledged as collateral to
secure the loan.
(5) Real estate at Dominion is pledged as collateral.
(6) 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 2004 are as follows (in
millions): 2000-$356; 2001-$623; 2002-$753; 2003-$319; and 2004-$486.
47
<PAGE>
Notes to Consolidated Financial Statements, continued
NOTE K: 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
$503 million. In 2000, Dominion has repurchased approximately 5 million shares
of stock through the implementation of a total return swap and accelerated stock
repurchase facilities. These shares were repurchased at a cost of approximately
$209 million. For additional information on the total return swap, see Note (P).
Immediately before the CNG merger, Dominion concluded a first step
transaction in which 33 million shares of Dominion common stock were exchanged
for approximately $1.4 billion.
NOTE L: Long-Term Incentive Plan
In 1997, Dominion's Long-Term Incentive Plan (LTIP) expired and was replaced
with the Dominion Resources Incentive Compensation Plan (Incentive Plan). At
December 31, 1999, 1,113 options remained outstanding under the LTIP. No further
awards will be made under the LTIP. The 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 11 million. The changes in restricted
share incentives and option awards under the combined plans were as follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
Restricted Weighted Stock Weighted Shares
Shares Average Price Options Average Price Exercisable
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1996 95,779 $ 41.18 9,626 $ 29.32 9,626
-----------------------------------------------------------------------------------------
Awards granted -- 1997 53,884 $ 35.24
Exercised/distributed/forfeited (44,399) $ 39.42 (4,800) $ 29.25
-----------------------------------------------------------------------------------------
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
=========================================================================================
</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 $20
million for the year ended December 31, 1999. Basic and diluted earnings per
share for the year would have decreased by $0.11 and $0.12, respectively, due to
the issuance of the stock options.
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 6.25%;
. expected volatility of 15.137%;
. contractual life of 10 years;
. risk-free interest rate of 6.52%; and
. expected lives of six years.
The fair values of each option at the dates of the grants were as follows:
. May 17, 1999 $4.34
. July 12, 1999 $4.59
. September 15, 1999 $4.88
. September 20, 1999 $4.90
The weighted-average fair value of options granted during 1999 was $4.35.
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. The first subscription in this program involved approximately 1.7
million shares of common stock at a price of $41.22 per share. Dominion officers
are responsible for the payment of such loans.
48
<PAGE>
NOTE M: 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.
NOTE N: 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 has authorized 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. Virginia Power preferred stock subject to
mandatory redemption, which is non-callable prior to redemption, at December 31,
1999 was as follows:
-----------------------------
Shares Redemption
Series Outstanding Date
$5.58 400,000 3/1/00
$6.35 1,400,000 9/1/00
-----------------------------
Total 1,800,000
=============================
Dominion has classified the $180 million of preferred stock subject to mandatory
redemption in Securities Due Within One Year.
There were no redemptions of preferred stock during 1997 through 1999.
As noted above, the 400,000 shares of the $5.58 Series of Preferred Stock
matured on March 1, 2000.
At December 31, 1999, Virginia Power preferred stock not subject to
mandatory redemption, $100 liquidation preference, is listed in the table below.
-----------------------------------------
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
=========================================
(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
1999, 1998, and 1997, including fees for broker/dealer agreements, were
4.82%, 4.49%, and 4.48%,respectively.
NOTE O: Retirement Plan, Postretirement Benefits and Other Benefits
In 1999 and 1998, Dominion Resources' Retirement Plan covered virtually all
employees of Dominion except the majority of the employees of Dominion's
U.K.-based subsidiary, East Midlands Electricity, who were covered by a separate
multi-employer plan administered on behalf of the U.K. electricity industry. The
Retirement Plan benefits are based on years of service 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 years 1998 and 1997, non-U.S. activity refers to
the pension plan of East Midlands. East Midlands was sold in July 1998. Dominion
and its subsidiaries, except for U.K.-based subsidiaries, provide retiree health
care and life insurance benefits through insurance companies with annual
premiums based on benefits paid during the year. Retiree health benefits in the
United Kingdom are generally provided by the state. 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.
49
<PAGE>
Notes to Consolidated Financial Statements, continued
The components of the provision for net periodic benefit cost were as follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------
Pension Benefits Other Benefits
-------------------------------------------------- ----------------------
1999 1998 1997 1999 1998 1997
Year ending December 31, U.S. U.S. Non-U.S. U.S. Non-U.S.
(millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Service cost $ 40 $ 32 $ 10 $ 28 $ 23 $ 17 $ 12 $ 13
Interest cost 76 71 44 64 83 28 24 25
Expected return on plan assets (93) (80) (49) (69) (95) (20) (16) (12)
Amortization of transition obligation 12 12 12
Net amortization and deferral (1) (1) (1)
-----------------------------------------------------------------------------
Net periodic benefit cost $ 23 $ 22 $ 5 $ 22 $ 11 $ 37 $ 31 $ 38
=============================================================================
</TABLE>
<TABLE>
<CAPTION>
--------------------------------------------------
Pension Benefits Other Benefits
---------------------- ----------------------
1999 1998 1999 1998
Change in plan assets:
<S> <C> <C> <C> <C>
Fair value of plan assets at beginning of year $1,094 $ 966 $ 212 $ 177
Actual return on plan assets 232 149 45 24
Contributions 22 22 16 11
Benefits paid from plan assets (43) (43) (1)
--------------------------------------------------
Fair value of plan assets at end of year 1,305 1,094 272 212
--------------------------------------------------
Expected benefit obligation at beginning of year 1,126 945 377 365
Actuarial (gain)/loss during prior period (13) (4) 26 (42)
--------------------------------------------------
Actual benefit obligation at beginning of year 1,113 941 403 323
Service cost 40 32 17 12
Interest cost 76 71 28 24
Benefits paid (43) (43) (18) (16)
Actuarial (gain)/loss during the year (89) 125 (29) 34
--------------------------------------------------
Expected benefit obligation at end of year 1,097 1,126 401 377
--------------------------------------------------
Funded status 208 (32) (129) (165)
Unrecognized net actuarial (gain)/loss (177) 66 (45) (17)
Unamortized prior service cost 3 3
Unrecognized net transition (asset)/obligation (12) (15) 158 170
--------------------------------------------------
Prepaid (accrued) benefit costs $ 22 $ 22 $ (16) $ (12)
==================================================
</TABLE>
Significant assumptions used in determining net periodic pension cost, the
projected benefit obligation, and postretirement benefit obligations were:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------
Pension Benefits Other Benefits
--------------------------------- --------------------------------------
1999 1998 1999 1998
U.S. U.S. Non-U.S
<S> <C> <C> <C> <C> <C>
Discount rates 7.50% 7.00% 6.75% 7.50% 7.00%
Expected return on plan assets 9.50% 9.50% 7.00% 9.00% 9.00%
Rate of increase for compensation income 5.00% 5.00% 4.75% 5.00% 5.00%
Medical cost trend rate 4.75% 5% for first year
4.75% second year
4.75% thereafter
============================================================================
</TABLE>
50
<PAGE>
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
-------------------------------
(millions) 1-Percentage 1-Percentage
Point Increase Point Decrease
Effect on total of service and interest cost
components for 1999 $ 6 $ (5)
Effect on postretirement benefit obligation
at 12/31/99 $40 $(33)
==============================
The funds collected for other postretirement benefits in Virginia Power's
regulated utility rates, in excess of other postretirement benefits actually
paid during the year, are contributed to external benefit trusts. See Note (C)
for a discussion of legislation that provides for the restructuring of the
electric utility industry in Virginia.
NOTE P: Derivative Transactions
Dominion uses derivative financial instruments for the purposes of managing
interest rate, natural gas price and foreign currency risks.
Interest Rate Risk Dominion Capital's mortgage business enters into forward
delivery contracts, financial futures, options contracts, and interest rate swap
agreements for the purpose of reducing exposure to the effects of changes in
interest rates on mortgage loans which the company has funded or has committed
to fund as well as residual interests retained. Gains and losses on such
contracts relating to mortgage loans are recognized when the loans are sold. If
the counterparties to the hedging transactions are unable to perform according
to the terms of the contracts, Dominion Capital may incur losses upon selling
the mortgage loans at prevailing prices. As of December 31, 1999 and 1998,
Dominion Capital's mortgage business has outstanding liabilities related to its
hedging positions with certain counterparties based on notional amounts of $3.7
billion and $1.3 billion, respectively. The deferred hedging losses, net, at
December 31, 1999, 1998 and 1997 were immaterial.
Commodity Price Risk DEI enters into natural gas options, collars, and swaps as
hedges against fluctuations in natural gas prices for future production periods.
DEI addresses market risk by selecting natural gas-based financial instruments
with historical value fluctuations that correlate strongly with those of the
item being hedged. Revenues received from such contracts held until expiration
are recognized in the corresponding production month for the contract. DEI has
some risk, since the price received for the underlying production may exceed the
reference price included in the hedging transaction. As of December 31, 1999,
DEI has entered into various natural gas put options, collars, and swap
contracts as hedges expiring on various dates until October 2002 on
approximately 42 Bcf of natural gas. The weighted average put price per MMBTU of
natural gas was $2.40. At December 31, 1998, DEI had entered into natural gas
put option contracts as hedges extending through October 1999 on approximately
18 Bcf of natural gas. The weighted average put price per MMBTU of natural gas
was $2.08.
In addition, as part of Dominion's strategy to market energy and to manage
related risks, it manages a portfolio of derivative commodity contracts held for
trading purposes. During 1999 and 1998, the portfolio included some derivative
financial instruments in the form of commodity-based swaps and options. Such
contracts were not material at December 31, 1999 and 1998.
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. At
December 31, 1999 and 1998, the notional amounts were $249 million and $756
million, respectively. The gains or losses from the sale, settlement or mark to
market of the total return swaps are recorded in Operating revenue and income --
Other in the income statement. Earnings due to swap transactions were $18
million and $8 million in 1999 and 1998, 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 on the balance sheet. Such cash collateral was $59 million at
December 31, 1999, and $71 million at December 31, 1998.
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 3,236,805 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 3,236,805 shares at a cost
of $146 million.
NOTE Q: 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 from operations.
Utility Rate Regulation As discussed in Note (C), the Governor of Virginia
signed into law legislation establishing a detailed plan to restructure the
electric utility industry in Virginia. Under this legislation, Virginia Power's
base rates will remain unchanged until July 2007 and recovery of
generation-related costs will continue to be provided through capped rates. The
legislation's deregulation of generation was an event that required
discontinuation of SFAS No. 71 for Virginia Power's generation operations in the
first quarter of 1999.
51
<PAGE>
Notes to Consolidated Financial Statements, continued
Virginia Power 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, 1999, Virginia Power'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 (F)
and (O).
Construction Program Virginia Power has made substantial commitments in
connection with its construction program and nuclear fuel expenditures. Those
expenditures are estimated to total approximately $856 million (excluding
capitalized interest) for 2000. Virginia Power presently estimates that 2000
construction expenditures, including nuclear fuel, will be met through cash flow
from operations and through a combination of sales of securities and short-term
borrowing.
Purchased Power Contracts Virginia Power has entered into contracts for the
long-term purchase of capacity and energy from other utilities, qualifying
facilities and independent power producers. Virginia Power has 56 non-utility
purchase contracts with a combined dependable summer capacity of 3,273
megawatts.
The table below reflects Virginia Power's minimum commitments as of
December 31, 1999, for power purchases from utility and non-utility suppliers.
-------------------------
Commitment
Year Capacity Other
(millions)
2000 $ 765 $ 45
2001 770 36
2002 771 32
2003 731 33
2004 731 31
Later years 7,890 227
-------------------------
Total $11,658 $404
=========================
Present value of the total $ 6,218 $215
=========================
In addition to the minimum purchase commitments in the table above, under some
of these contracts Virginia Power 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 1999, 1998 and 1997 were $1.2 billion, $1.1
billion and $1.4 billion, respectively.
See Note (C) for an evaluation of the company's potential exposure under
its long-term purchased power commitments.
Fuel Purchase Commitments Virginia Power's estimated fuel purchase commitments
for the next five years for system generation are as follows: 2000 -- $334
million; 2001 -- $277 million; 2002 -- $156 million; 2003 -- $145 million; and
2004 -- $143 million.
Sales of Power Virginia Power enters into agreements with other utilities and
with other parties to purchase and sell capacity and energy. These agreements
may cover current and future periods. The volume of these transactions varies
from day to day, based on the market conditions, Virginia Power'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, operating and other costs as a result of
compliance, remediation, containment and monitoring obligations of Dominion.
Historically, Dominion recovered such costs from customers through 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, Virginia Power may seek recovery from customers through utility rates of
only those environmental costs related to transmission and distribution
operations. At December 31, 1999, the environmental matters discussed below are
related to the operations of Virginia Power.
In 1987, the Environmental Protection Agency (EPA) identified Virginia
Power 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 $106 million to
$156 million. Virginia Power'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. Virginia Power 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, Virginia Power has deter-
mined that it is probable that the PRPs will fully pay the costs apportioned
to them.
Virginia Power generally seeks to recover its costs associated with
environmental remediation from third-party insurers. Any pending or possible
claims were not recognized as an asset or offset against such obligations of
Virginia Power.
In 1999, Virginia Power 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
Virginia Power's 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 Virginia Power's financial condition or results of operations.
In 1999, Virginia Power identified matters at certain other power stations
that EPA might view as not in compliance with the SPCC and FRP requirements.
Virginia Power reported these matters to the EPA
52
<PAGE>
and in December 1999 submitted revised FRP and SPCC plans. Presently, the EPA
has not assessed any penalties against Virginia Power, pending its review of
Virginia Power's disclosure information. Future resolution of these matters is
not expected to have a material impact on Virginia Power's financial condition
or results of operations.
On November 8, 1999 and September 21, 1999, Virginia Power received notices
from the Attorneys General of Connecticut and New York, respectively, of their
intention to file suit against Virginia Power for alleged violations of the
Clean Air Act. The notices question whether modifications at certain Virginia
Power generating facilities were properly permitted under the Clean Air Act and
allege that emissions from these facilities have contributed to damage to public
health and the environment in the Northeast. To date, no suits have been filed.
Dominion believes that it is one of a number of companies with fossil fuel power
generating stations in the southeast and central U.S. to have received such
notifications. Virginia Power believes that it has obtained the permits
necessary in connection with its generating facilities and that the outcome of
the suits, if any, filed by the Attorney Generals would not have a material
adverse effect on Dominion's financial condition or results of operations.
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. Virginia Power 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, Virginia Power
could be assessed up to $91 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.
Virginia Power's current level of property insurance coverage ($2.55
billion for North Anna and $2.4 billion for Surry) exceeds the NRC's minimum
requirement for nuclear power plant licensees of $1.06 billion per reactor site
and includes coverage for premature decommissioning and functional total loss.
The NRC requires that the proceeds from this insurance be used first to return
the reactor to and maintain it in a safe and stable condition, then to
decontaminate the reactor and station site in accordance with a plan approved by
the NRC. Virginia Power'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 $29 million. Based on the severity of the incident, the board
of directors of Virginia Power'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, Virginia Power has the
financial responsibility for these losses.
Virginia Power purchases insurance from NEIL to cover the cost
of replacement power during the prolonged outage of a nuclear unit due to direct
physical damage of the unit. Under this program, Virginia Power is subject to a
retrospective premium assessment for any policy year in which losses exceed
funds available to NEIL. The current policy period's maximum assessment is $7
million.
Under several of Virginia Power's nuclear insurance policies, it is subject
to retrospective premium assessments in any policy year in which losses exceed
the funds available to these insurance companies.
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.
Dominion
Dominion has issued guarantees to various third party creditors in relation to
the repayment of debt by certain of its subsidiaries. At December 31, 1999,
Dominion had issued $751 million of guarantees, and the subsidiaries' debt
subject to such guarantees totaled $406 million.
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.
Dominion Capital
At December 31, 1999, Dominion Capital had commitments to fund loans of
approximately $937 million.
NOTE R: Business Segments
Under SFAS No. 131, Disclosure About Segments of an Enterprise and Related
Information, Dominion has defined segments based on product, geographic location
and regulatory environment.
In preparation for the transition to competition for electric generation in
Virginia, Dominion is evaluating the operating results across Virginia Power's
and DEI's current business lines. Although the employees and assets involved
remain with their respective legal entities, Dominion currently evaluates the
operations of DEI and Virginia Power in the following business segments:
. generation-related operations of both Virginia Power and DEI
(referred to as Dominion Energy);
. regulated electric transmission and distribution services (referred to
as Dominion Delivery); and
. oil and gas operations of DEI (referred to as Dominion E&P).
In addition to the business segments mentioned above, Dominion
reviews the following as business segments:
. the financial services of Dominion Capital;
. Dominion UK (East Midlands) which was sold by Dominion in 1998;
and
. Corporate Operations:
-- corporate costs of Dominion's holding company;
-- Corby operations;
-- intercompany eliminations;
-- impact of the impairment of regulatory assets and one-time refund
recorded as a result of the settlement of the 1998 Virginia
jurisdictional rate proceedings; and
-- extraordinary item recorded in the first quarter of 1999.
53
<PAGE>
Notes to Consolidated Financial Statements, continued
Business segment financial information follows for each of the three years
in the period ended December 31, 1999. Corporate includes intersegment
eliminations.
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
Dominion Dominion Dominion Dominion Dominion Corporate Total
Delivery Capital Energy UK E&P Operations Consolidated
(millions, except total assets)
1999
<S> <C> <C> <C> <C> <C> <C> <C>
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 431 265 624 27 (36) 1,311
Depreciation 246 32 313 93 32 716
Unusual items (255) (255)
Equity income 4 14 5 10 33
Income tax expense (benefit) 109 35 161 (29) (17) 259
Net income 175 78 271 43 (271) 296
Equity investments 166 186 23 31 406
Capital expenditures 317 9 461 86 21 894
Total assets (billions) 4.6 3.6 7.4 1.2 0.9 17.7
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 12 (317) 1,086
Depreciation 237 25 337 75 60 734
Unusual items 332 332
Equity income 21 14 4 2 41
Income tax expense (benefit) 104 31 157 133 (26) (93) 306
Net income 168 59 262 227 22 (202) 536
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
1997
Revenue 1,098 296 3,749 1,970 158 (8) 7,263
Interest income 9 8 1 1 19
Interest expense 134 92 192 189 13 7 627
Operating income 442 157 645 246 28 (46) 1,472
Depreciation 237 18 374 131 58 1 819
Unusual items (157) (157)
Equity income 16 13 1 30
Income tax expense (benefit) 111 20 119 21 (18) (20) 233
Net income 193 45 275 (110) 35 (39) 399
</TABLE>
<TABLE>
<CAPTION>
Geographic Areas
- ----------------------------------------------------------------------------------------------------------------------------------
Revenue
---------------------------------------------------------------
(millions) International
---------------------------------------------------------------
United Latin Total
Year Domestic Kingdom America Other International Consolidated
<S> <C> <C> <C> <C> <C> <C>
1999 $5,295 $106 $119 $ 225 $5,520
1998 4,913 $1,009 133 26 1,168 6,081
1997 5,130 1,970 163 2,133 7,263
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------------
Long-Lived Assets
---------------------------------------------------------------
(billions) International
---------------------------------------------------------------
United Latin Total
Year Domestic Kingdom America Other International Consolidated
<S> <C> <C> <C> <C> <C> <C>
1999 $10.6 $0.1 $0.4 $0.6 $1.1 $11.7
1998 10.6 0.1 0.7 0.2 1.0 11.6
</TABLE>
54
<PAGE>
NOTE S: Loan Servicing Portfolio
As of December 31, 1999 and 1998 Dominion Capital serviced a portfolio
consisting of loans in all 50 states. In addition to servicing loans of its
mortgage lending subsidiary, Saxon Mortgage, Inc. (SMI), Dominion Capital's
customers are Government National Mortgage Association (GNMA), Federal National
Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and
Dynex Capital, Inc. (Dynex). The loan-servicing portfolios as of December 31,
1999 and 1998 are summarized below:
----------------------------------------------------
1999 1998
Number Principal Number Principal
Of Loans Balance Of Loans Balance
(millions, except
number of loans)
SMI 42,071 $4,136 26,760 $2,773
GNMA 1,491 48 1,758 60
FNMA 634 16 798 20
FHLMC 124 6 155 8
Dynex 2,586 308 3,707 470
Other 150 47 1,265 58
----------------------------------------------------
47,056 $4,561 34,443 $3,389
===================================================
Activity related to capitalized loan servicing rights during 1999 and 1998 was
as follows:
--------------------------
For the Years Ended December 31, 1999 1998
(millions)
Balance, beginning of year $52 $ 23
Loan servicing rights purchased 48 39
Amortization (20) (10)
--------------------------
Balance, end of year $80 $ 52
==========================
NOTE T: Collateralized Debt Obligation Investments
Dominion manages financial assets held in three collateralized debt obligations
(CDO). In addition to the management of the debt, Dominion holds an investment
in the subordinated debt of each CDO. The total investment in the CDOs were $58
million and $24 million at December 31, 1999 and 1998, respectively. The total
assets under management in the CDOs were approximately $2.3 billion and $1.0
billion at December 31, 1999 and 1998, respectively.
NOTE U: Leases
Future minimum lease payments under operating leases that have initial or
remaining lease terms in excess of one year as of December 31, 1999 are 2000-$25
million, 2001-$20 million, 2002-$18 million, 2003-$15 million, 2004-$11 million
and years after 2004-$46 million. Rent on leases, which have been charged to
operations expense, were $31 million, $27 million, and $20 million for 1999,
1998 and 1997, respectively.
NOTE V: Acquisitions and Divestitures
Acquisitions
In 1999, DEI acquired interests in certain gas producing properties located in
the San Juan Basin of New Mexico for approximately $115 million. In addition,
DEI completed its purchase of all of the issued and outstanding shares of
Remington Energy Ltd., (Remington), a publicly traded natural gas exploration
and production company headquartered in Calgary, Alberta, Canada. DEI paid $33
million and assumed $260 million of Remington's debt and liabilities.
In April 1998, DEI purchased Dominion Energy Canada, Ltd., a natural gas
and oil exploration and production company. DEI paid $119 million and assumed
debt of $26 million. The transaction has been recorded using the purchase method
of accounting.
Divestitures
In 1999, DEI reached an agreement to sell its interests in approximately 1,200
megawatts of gross generation capacity located in Latin America. Duke Energy
International is purchasing the interests for approximately $405 million. DEI
completed the sale of its interests in Belize and Peru in November 1999 and
expects to complete the sale of its interests in Argentina and Bolivia in 2000,
following receipt of certain regulatory approvals.
The assets and liabilities of the unsold interests amounts to $446 million
and $178 million, respectively, and continues to be reflected in Dominion's
Consolidated Balance Sheets.
During 1999, DEI adjusted the carrying amount of the Latin American
interests to be sold and recognized an impairment loss of $21 million, including
the effect of applicable income taxes. The pretax loss of $17 million was
recorded in Other operation and maintenance and the income tax effect of $4
million was recorded in Provision for income taxes in Dominion's Consolidated
Statements of Income.
In 1998, Dominion sold East Midlands to PowerGen, an electricity generator
and supplier in the United Kingdom. East Midlands is principally an electricity
supply and distribution company serving 2.3 million homes and businesses in the
East Midlands region of the United Kingdom. PowerGen acquired 100% of DR
Investments in a transaction valued at $3.2 billion. DR Investments is the
holding company for DR Investments (UK) PLC and East Midlands. Dominion recorded
an aftertax gain of $201 million or $1.03 per share.
55
<PAGE>
Notes to Consolidated Financial Statements, continued
NOTE W: 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 Resources' management for a fair statement of the results for the
interim periods.
Quarterly Financial and Common Stock Data -- Unaudited
-----------------------
1999 1998
(millions, except per share amounts)
Operating revenue and income
First Quarter $1,293 $1,774
Second Quarter 1,315 1,585
Third Quarter 1,663 1,549
Fourth Quarter 1,249 1,173
-----------------------
Year $5,520 $6,081
=======================
Income from operations
First Quarter $ 313 $ 381
Second Quarter 296 67
Third Quarter 487 436
Fourth Quarter 215 202
-----------------------
Year $1,311 $1,086
=======================
Income (loss) before provision for
income taxes, minority interests and
extraordinary item
First Quarter $ 211 $ 217
Second Quarter 175 (108)
Third Quarter 357 666
Fourth Quarter 85 94
-----------------------
Year $ 828 $ 869
=======================
Net income (loss)
First Quarter $ (116) $ 140
Second Quarter 117 (83)
Third Quarter 232 425
Fourth Quarter 63 54
-----------------------
Year $ 296 $ 536
=======================
Earnings (loss) per share
First Quarter $(0.60) $ 0.72
Second Quarter 0.61 (0.42)
Third Quarter 1.21 2.17
Fourth Quarter 0.33 0.28
-----------------------
Year $ 1.55 $ 2.75
=======================
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 47 1/16 -36 7/8 42 15/16-39 3/8
Second Quarter 44 13/16-36 9/16 42 1/16 -37 13/16
Third Quarter 47 3/16 -43 44 15/16-39 5/16
Fourth Quarter 49 3/8 -39 1/4 48 15/16-44 3/8
------------------------------------
Year 49 3/8 -36 9/16 48 15/16-37 13/16
====================================
Certain accruals recorded in 1999 and 1998 were not ordinary, recurring
adjustments.
Extraordinary Item In the first quarter of 1999, Dominion recorded an after-tax
charge to net income of $255 million or $1.33 per share. The charge reflects 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 Resources' Consolidated Statements of Income.
Sale of Interests in Latin American Power Generation In 1999, Dominion recorded
a one-time after-tax charge of $21 million, or $0.11 per share, related to the
sale of its interests in its Latin American power generation.
Rate Refund Dominion recognized a provision for rate refund of $154 million or
$0.79 per share and related interest expense of $11 million and other taxes of
$4 million in the second quarter of 1998 as a result of the settlement of its
rate proceeding in Virginia.
Impairment of Regulatory Assets Dominion charged $159 million to second quarter
1998 earnings or $0.82 per share as a provision for the impairment of regulatory
assets resulting from the settlement of Virginia Power's rate proceeding in
Virginia.
Depreciation and Amortization Dominion recorded adjustments of $27 million in
the second quarter of 1998 decreasing the year-to-date provision for
depreciation and decommissioning expenses to reflect terms of the settlement of
Virginia Power's Virginia rate proceedings. For more information, see Note (C).
Sale of East Midlands In the third quarter of 1998, Dominion Resources recorded
an after-tax gain of $201 million or $1.03 per share to reflect the sale of East
Midlands to PowerGen.
56
<PAGE>
NOTE X: Subsequent Event
Merger
On January 28, 2000, Dominion acquired the outstanding shares of CNG's common
stock. The aggregate purchase price was $6.4 billion. The purchase price was
paid in a combination of cash and Dominion stock. The acquisition was
accomplished in a two-step transaction. In the first step, a wholly owned
subsidiary of Dominion merged (First Merger) with and into Dominion, the
surviving corporation. The second step involved the merger (Second Merger) of
CNG and a subsidiary of Dominion in which the Dominion subsidiary is the
surviving corporation.
In the first merger, Dominion shareholders exchanged approximately 33
million shares of Dominion common stock for approximately $1.4 billion. In the
second merger, CNG shareholders received approximately 87 million shares of
Dominion common stock and approximately $2.9 billion in exchange for all of the
outstanding shares of CNG common stock.
In 2000, Dominion initially financed the cash used in the CNG merger with 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. Dominion expects
to refinance these amounts with a combination of debt, preferred and convertible
securities, and proceeds from sales of non-core assets, including DEI's
interests in Latin American power generation, CNG's foreign investments,
Virginia Natural Gas and Dominion Capital.
For accounting purposes, the First Merger is treated as a reorganization
with no changes in the recorded amount of Dominion's assets and liabilities. The
Second Merger will be accounted for under the purchase method of accounting.
In the Second Merger, Dominion has registered as a holding company under
the 1935 Act. The 1935 Act imposes a number of restrictions on the operations of
registered holding company systems. One such restriction is it limits the
ability of registered holding companies to engage in activities unrelated to
their utility operations. Consequently, as part of the SEC order approving the
merger, Dominion must divest itself of Dominion Capital, its financial services
subsidiary. Although a formal plan for divestiture has not been adopted, the SEC
allowed three years for this to be accomplished.
During the merger approval process, Dominion and CNG also agreed to divest
Virginia Natural Gas, Inc. (VNG), CNG's gas distribution subsidiary located in
Virginia Beach, Va., under an agreement with the Virginia Commission. The
companies have also agreed with the Federal Trade Commission (FTC) to divest
VNG. Dominion has one year after the merger is completed to sell VNG to a third
party. If the sale of VNG is not completed within the timeframe of one year, VNG
will be spun off as an independent company with the common stock distributed to
Dominion shareholders. Both deadlines are subject to reasonable extensions,
which may be granted by the regulatory authorities.
After the CNG Merger, Dominion has an energy portfolio of almost 20,000
megawatts of domestic power generation and 2.8 trillion cubic feet equivalent in
natural gas and oil reserves producing more than 300billion cubic feet
equivalent annually. Dominion now operates a major interstate gas pipeline
system and the largest natural gas storage system in North America and has
approximately 6,000 miles of electric transmission lines. Dominion is the
eleventh largest independent oil and gas producer in the United States, measured
by reserves, and provides integrated energy services to approximately four
million retail customers.
57
<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 1999 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 generally accepted auditing standards 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 Committees of the Boards, composed entirely of directors who are
not officers or employees of Dominion or its subsidiaries, meet periodically
with independent auditors, the internal auditors and management to discuss
auditing, internal accounting control and financial reporting matters and to
ensure that each is properly discharged. Both independent auditors and the
internal auditors periodically meet alone with the Audit Committees and have
free access to the Committees at any time.
Management recognizes its responsibility for fostering a strong ethical
climate so that Dominion's affairs are conducted according to the highest
standards of personal corporate conduct. This responsibility is characterized
and reflected in Dominion Resources' 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/ James L. Trueheart
Thos. E. Capps James L. Trueheart
President and Group Vice President and
Chief Executive Officer Controller
Report of Independent Auditors
To the Shareholders and Board of Directors of
Dominion Resources, Inc.
We have audited the accompanying consolidated balance sheets of Dominion
Resources, Inc. and subsidiaries as of December 31, 1999 and 1998 and the
related consolidated statements of income, comprehensive income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1999. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of Dominion
Resources, Inc. and subsidiaries as of December 31, 1999 and 1998 and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999, in conformity with generally accepted
accounting principles.
/s/ Deloitte & Touche LLP
Richmond, Virginia
January 28, 2000
58
<PAGE>
Directors and Officers
Dominion Resources, Inc.
Directors
George A. Davidson, Jr., 61
Chairman of the Board of Directors
Thos. E. Capps, 64
Vice Chairman, President and Chief Executive Officer
William S. Barrack, Jr., 70
Former Senior Vice President, Texaco, Inc., New Canaan, Connecticut
John B. Bernhardt, 70
Managing Director, Bernhardt/Gibson Financial Opportunities,
Newport News, Virginia
Raymond E. Galvin, 68
Former President, Chevron USA Production Company, Houston, Texas
Ray J. Groves, 64
Chairman, Legg Mason Merchant Banking, Inc., New York, New York
John W. Harris, 52
President, Lincoln Harris, LLC, Charlotte, North Carolina
Benjamin J. Lambert, III, 63
Optometrist, Richmond, Virginia
Richard L. Leatherwood, 60
Former President and Chief Executive Officer, CSX Equipment,
Baltimore, Maryland
Paul E. Lego, 69
Former Chairman and Chief Executive Officer,
Westinghouse Electric Corporation, Pittsburgh, Pennsylvania
Margaret A. McKenna, 54
President, Lesley College, Cambridge, Massachusetts
Steven A. Minter, 61
President and Executive Director, The Cleveland Foundation, Cleveland, Ohio
Kenneth A. Randall, 72
Corporate director of various companies, Williamsburg, Virginia
Frank S. Royal, M.D., 60
Physician, Richmond, Virginia
S. Dallas Simmons, 60
Chairman, President and Chief Executive Officer,
Dallas Simmons & Associates, Inc., Richmond, Virginia
Robert H. Spilman, 72
President, Spilman Properties, Bassett, Virginia
David A. Wollard, 62
Chairman of the Board, Exempla Healthcare, Denver, Colorado
Officers
Thomas F. Farrell, II, 45
Executive Vice President (Chief Executive Officer of Dominion Energy)
David L. Heavenridge, 53
Executive Vice President (Chief Executive Officer of Dominion Capital)
H. Patrick Riley, 62
Executive Vice President (Chief Executive Officer and President of Dominion
Exploration & Production)
Edgar M. Roach, Jr., 51
Executive Vice President (Chief Executive Officer of Dominion Delivery)
Thomas N. Chewning, 54
Executive Vice President and Chief Financial Officer
James P. O'Hanlon, 56
Executive Vice President (President and Chief Operating Officer of
Dominion Energy)
Robert E. Rigsby, 50
Executive Vice President (President and Chief Operating Officer of
Dominion Delivery)
James L. Trueheart, 48
Group Vice President, Controller and Principal Accounting Officer
G. Scott Hetzer, 43
Senior Vice President and Treasurer
James L. Sanderlin, 58
Senior Vice President -- Law
Eva S. Teig, 55
Senior Vice President -- External Affairs & Corporate Communications
William C. Hall, Jr., 46
Vice President -- External Affairs & Corporate Communications
Simon C. Hodges, 38
Vice President -- Financial Planning
Karen E. Hunter, 45
Vice President -- Tax
James F. Stutts, 55
Vice President and General Counsel
Patricia A. Wilkerson, 44
Vice President and Corporate Secretary
Virginia Electric and Power Company
Nonemployee Directors
Jean E. Clary, 56
President, Century 21 Clary and Associates, Inc., South Hill, Virginia
William G. Thomas, 60
Partner, Reed Smith Hazel & Thomas, LLP, Falls Church, Virginia
<PAGE>
Selected Consolidated Financial Data
<TABLE>
<CAPTION>
-----------------------------------------------------
1999 1998 1997
(dollars in millions, except per share amounts)
<S> <C> <C> <C>
Operating revenue and income $ 5,520 $ 6,081 $ 7,263
Net income $ 296 $ 536 $ 399
Total assets $17,747 $17,517 $20,165
Long-term debt, preferred stock
subject to mandatory redemption
and preferred securities of
a subsidiary trust (1) $ 7,321 $ 6,817 $ 7,761
Common stock data:
Earnings per share $ 1.55 $ 2.75 $ 2.15
Dividends paid per share $ 2.58 $ 2.58 $ 2.58
Common stock price range (dollars) 49 3/8 - 36 9/16 48 15/16 - 37 13/16 42 7/8 - 33 1/4
Market value per share (year-end) $ 39.25 $ 46.75 $ 42.56
Book value per share (year-end) $ 25.50 $ 27.33 $ 26.84
Market to book value (year-end) 153.9% 171.1% 158.6%
Return on average common equity 5.9% 10.1% 8.0%
Payout ratio 166.5% 93.8% 120.0%
Price/earnings ratio (year-end) 25.3 17.0 19.8
Outstanding shares of common
stock (millions)
-- average 191.4 194.9 185.2
-- actual (year-end) 186.3 194.5 187.8
Capitalization:
Debt and capital
lease obligations $ 8,193 $ 7,012 $ 9,194
Preferred securities 385 385 385
Preferred stock 689 689 689
Common equity 4,752 5,316 5,041
-----------------------------------------------------
Total capitalization $14,019 $13,402 $15,309
-----------------------------------------------------
Capitalization ratios
Debt and capital
lease obligations 58% 52% 60%
Preferred securities of
subsidiary trust 3% 3% 3%
Preferred stock 5% 5% 4%
Common equity 34% 40% 33%
</TABLE>
<TABLE>
<CAPTION>
-----------------------------------------------------
1996 1995 1994
(dollars in millions, except per share amounts)
<S> <C> <C> <C>
Operating revenue and income $ 4,815 $ 4,633 $ 4,491
Net income $ 472 $ 425 $ 478
Total assets $14,896 $13,903 $13,562
Long-term debt, preferred stock
subject to mandatory redemption
and preferred securities of
a subsidiary trust (1) $ 5,362 $ 4,927 $ 4,934
Common stock data:
Earnings per share $ 2.65 $ 2.45 $ 2.81
Dividends paid per share $ 2.58 $ 2.58 $ 2.55
Common stock price range (dollars) 44 3/8 - 36 7/8 41 5/8 - 34 7/8 45 3/8 - 34 7/8
Market value per share (year-end) $ 38.50 $ 41.25 $ 36.00
Book value per share (year-end) $ 27.13 $ 26.88 $ 26.60
Market to book value (year-end) 141.9% 153.5% 135.3%
Return on average common equity 9.8% 9.2% 10.6%
Payout ratio 97.4% 105.3% 90.7%
Price/earnings ratio (year-end) 14.5 16.8 12.8
Outstanding shares of common
stock (millions)
-- average 178.3 173.8 170.3
-- actual (year-end) 181.2 176.4 172.4
Capitalization:
Debt and capital
lease obligations $ 5,857 $ 5,271 $ 5,257
Preferred securities 135 135
Preferred stock 689 689 816
Common equity 4,915 4,742 4,586
-----------------------------------------------------
Total capitalization $11,596 $10,837 $10,659
-----------------------------------------------------
Capitalization ratios
Debt and capital
lease obligations 51% 49% 49%
Preferred securities of
subsidiary trust 1% 1%
Preferred stock 6% 6% 8%
Common equity 42% 44% 43%
</TABLE>
(1) In 1999, preferred stock subject to mandatory redemption is included in
Securities due within one year and is excluded from this amount.
<PAGE>
DOMINION RESOURCES, INC.
SUBSIDIARIES OF THE REGISTRANT
<TABLE>
<CAPTION>
JURISDICTION OF NAME UNDER WHICH
NAME INCORPORATION BUSINESS IS CONDUCTED
<S> <C> <C>
Virginia Power in Virginia
Virginia Electric and and North Carolina Power
Power Company Virginia in North Carolina
Consolidated Natural Gas Company Virginia Consolidated Natural Gas Company
Dominion Energy, Inc. Virginia Dominion Energy, Inc.
Dominion Capital, Inc. Virginia Dominion Capital, Inc.
</TABLE>
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statements
File No. 333-35501, 333-46043 and 333-93187 of Dominion Resources, Inc. on
Forms S-3 and Registration Statements File No. 33-62705, File No. 333-02733,
File No. 333-25587, File No. 333-18391, File No. 333-49725, File No. 333-69305,
File No. 333-78173, File No. 333-87529, File No. 333-95567 and File No.
333-95795 of Dominion Resources, Inc. on Forms S-8 of our report dated
January 28, 2000, appearing in and incorporated by reference in the Annual
Report on Form 10-K of Dominion Resources, Inc. for the year ended
December 31, 1999.
/s/ Deloitte & Touche LLP
- -------------------------
DELOITTE & TOUCHE LLP
Richmond, Virginia
March 7, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
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<TOTAL-CURRENT-ASSETS> 2,192
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<TOTAL-ASSETS> 17,747
<COMMON> 3,561
<CAPITAL-SURPLUS-PAID-IN> 16
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<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,752
0
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<LONG-TERM-DEBT-NET> 6,936
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