Prepared by R.R. Donnelley Financial -- FORM 10-K
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, 2001
OR
¨ |
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from
to
Commission File Number 1-2255
VIRGINIA ELECTRIC AND POWER COMPANY
(Exact name of registrant as specified in its charter)
| Virginia |
|
54-0418825 |
| (State or other jurisdiction of incorporation or
organization) |
|
(I.R.S. Employer Identification Number) |
| |
| 701 East Cary Street |
|
23219 |
| Richmond, Virginia |
|
(Zip Code) |
| (Address of principal executive offices) |
|
|
(804) 771-3000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class
|
|
Name of Each Exchange on Which Registered
|
| Peferred Stock (cumulative), $100 par value,$5.00 dividend |
|
New York Stock Exchange |
| Trust Preferred Securities (cumulative), $25 par value, 8.05% dividend |
|
New York Stock Exchange |
| 7.15% Senior Notes, due 2038 |
|
New York Stock Exchange |
| 6.70% Senior Notes, due 2009 |
|
New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s
knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
The aggregate market value of the voting stock held by non-affiliates of the registrant as of March 1, 2002, was zero.
As of March 1, 2002, there were issued and outstanding 171,484 shares of the registrant’s common stock, without par value, all of which were held,
beneficially and of record, by Dominion Resources, Inc.
DOCUMENTS INCORPORATED BY REFERENCE.
None
VIRGINIA ELECTRIC AND POWER COMPANY
| Item Number
|
|
|
|
Page Number
|
| |
| |
|
PART I |
|
|
| 1. |
|
|
|
3 |
| |
|
|
|
3 |
| |
|
|
|
3 |
| |
|
|
|
3 |
| |
|
|
|
4 |
| |
|
|
|
4 |
| |
|
|
|
7 |
| |
|
|
|
8 |
| |
|
|
|
9 |
| |
|
|
|
10 |
| |
|
|
|
10 |
| 2. |
|
|
|
10 |
| 3. |
|
|
|
10 |
| 4. |
|
|
|
11 |
| |
| |
|
PART II |
|
|
| 5. |
|
|
|
14 |
| 6. |
|
|
|
14 |
| 7. |
|
|
|
15 |
| 7A. |
|
|
|
34 |
| 8. |
|
|
|
34 |
| 9. |
|
|
|
71 |
| |
| |
|
PART III |
|
|
| 10. |
|
|
|
71 |
| 11. |
|
|
|
75 |
| 12. |
|
|
|
82 |
| 13. |
|
|
|
83 |
| |
| |
|
PART IV |
|
|
| 14. |
|
|
|
84 |
2
PART I
Virginia Electric and Power Company (the Company) is a regulated public utility that
generates, transmits and distributes power for sale in Virginia and northeastern North Carolina. In Virginia, the Company trades under the name ‘‘Dominion 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, the Company trades under the name ‘‘Dominion North Carolina Power’’ and serves retail customers located in the northeastern
region of the state, excluding certain municipalities. In addition, the Company sells electricity at wholesale to rural electric cooperatives, power marketers, municipalities and other utilities. Within this document, ‘‘the
Company’’ refers to the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and all of our subsidiaries.
Dominion Resources, Inc. (Dominion), our parent company, completed its
acquisition of Consolidated Natural Gas Company (CNG) in January 2000. As a result of the merger, Dominion became a registered public utility holding company under the Public Utility Holding Company Act of 1935 (the 1935 Act) when it completed the
CNG acquisition. The 1935 Act prohibits registered companies from owning businesses unrelated to our utility operations or other energy related businesses. In connection with the acquisition, a number of organizational changes were implemented
within the Company. Some of these changes were required as a result of Dominion’s new status as a 1935 Act company and some were based on business decisions relating to the integration of the merged companies.
As part of the acquisition of CNG, Dominion created a subsidiary service company, Dominion Resources Services, Inc. (Services), which provides certain
services to Dominion’s operating subsidiaries. During 2000, CNG also had a service company, Consolidated Natural Gas Service Company, Inc. Effective January 1, 2001, the two service companies were combined into one service company. The Company
provided certain administrative and support services to Services under the Virginia Electric and Power Company Support Agreement between the Company and Services effective January 1, 2000.
In July 2000, the Virginia State Corporation Commission (Virginia Commission) approved the Company’s transfer of all of its issued and outstanding common stock in VPS
Communications, Inc. (VPSC) to Dominion. In August 2000, VPSC became a direct subsidiary of Dominion and was renamed Dominion Telecom, Inc. (DTI). See Note 21 to the Consolidated Financial Statements for additional information on transactions with
DTI.
The Company manages its business through two principal segments: Energy and
Delivery.
| |
• |
|
Energy—Energy manages the Company’s portfolio of generating facilities and purchased power contracts, trading and marketing activities, hedging and arbitrage
activities. |
| |
• |
|
Delivery—Delivery manages the Company’s electric distribution and transmission systems, serving approximately 2 million customers, about 6,000 miles of
electric transmission lines and customer service operations. |
The majority of the Company’s revenue is
provided through bundled rate tariffs. This revenue is allocated between the Energy and Delivery segments for internal reporting purposes and discussion in this document. While the Company manages its daily operations as described above, its assets
remain wholly-owned and operated by the Company. For additional financial information on business segments, see Note 23 to the Consolidated Financial Statements.
3
As of December 31, 2001, the Company had approximately 7,900 full-time employees. Approximately
3,700 employees are subject to collective bargaining agreements. The contract of those employees represented by the International Brotherhood of Electrical Workers (IBEW) Local Union 50 expires at the end of the first quarter of 2002. Contract
negotiations between the Company and IBEW Local Union 50 have commenced.
Virginia Electric and Power Company was incorporated
in 1909 as a Virginia public service corporation. Its principal office is located at 701 East Cary Street, Richmond, Virginia 23219-3932. The telephone number is (804) 771-3000. All of the Company’s common stock is held by Dominion.
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, the Company continues to consider new business opportunities, particularly those which allow the Company to use its existing expertise and resources.
Prior to 2002, competition for retail electric sales in Virginia was limited to the extent customers moved into another utility service territory, used other energy sources instead of
electric power, generated their own electricity, or participated in a retail pilot program. The Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) provides for a phased-in transition to a fully competitive retail electric
market during the period January 1, 2002 through January 1, 2004. The Virginia Commission has ordered that retail choice be fully implemented in Virginia by January 1, 2003.
Under the Virginia Restructuring Act, the Company’s generation portion of its Virginia jurisdictional operations will no longer be subject to cost-based rate regulation effective
January 1, 2002. Base rates (excluding fuel costs and certain other allowable adjustments) are capped and will remain unchanged until July 2007 unless terminated sooner as provided by the Virginia Restructuring Act. Recovery of generation-related
costs will continue to be provided through capped rates and wires charges. A wires charge, where applicable, will be assessed to those customers opting for alternative suppliers. The Virginia Restructuring Act also requires the Company to join or
establish a regional transmission entity, phase in retail choice beginning January 1, 2002, and functionally separate its electric generation from its electric transmission and distribution operations. For additional information on electric
deregulation in Virginia, see Regulated Electric Operations in Future Issues and Outlook of Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).
In North Carolina, regulators and legislators continue to explore the issues related to electric industry restructuring, the development of a competitive wholesale market and retail
competition. However, there has been little recent activity.
The Company plans to continue to participate actively in both the
legislative and regulatory processes to ensure an orderly transition from a regulated environment. The Company has responded to the trends toward competition by cutting costs, re-engineering our core business processes, and pursuing innovative
approaches to serving traditional and future markets.
General
Many aspects of our business are presently subject to regulation by the Virginia Commission, the North Carolina Utilities Commission (North Carolina Commission), the Federal Energy Regulatory Commission (FERC), the
Environmental Protection Agency (EPA), the Department of Energy (DOE), the Nuclear Regulatory Commission (NRC), the Army Corps of Engineers, the Securities and Exchange Commission (SEC), and other federal, state and local authorities.
4
State Regulation
The Virginia Commission and the North Carolina Commission regulate the Company’s rates for retail electric sales in those states and FERC approves the rates for electric sales to wholesale customers. The current
Virginia fuel factor applied to the Company’s regulated generation is 1.613 cents per kWh, which will remain in effect through December 31, 2002. The North Carolina Commission has approved a fuel adjustment factor of 1.285 cents per kWh,
effective January 1, 2002.
Under the Virginia Restructuring Act, the generation portion of the Company’s Virginia
jurisdictional operations is no longer subject to cost-based rate regulation effective January 1, 2002. Base rates (excluding fuel costs and certain other allowable adjustments) will remain capped until July 2007 unless terminated sooner as provided
by the Virginia Restructuring Act. Recovery of generation-related costs will continue to be provided through capped rates and, where applicable, a wires charge assessed to those customers opting for alternative suppliers of electricity. The Virginia
Restructuring Act also requires the Company to join or establish a regional transmission entity, phase in retail choice beginning January 1, 2002, and functionally separate its electric generation from its electric transmission and distribution
operations.
In connection with the North Carolina Commission approval of the CNG acquisition, the Company agreed not to request
an increase in North Carolina retail electric base rates until 2006, except for certain events that would have a significant financial impact on the Company. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings.
The Company holds certificates of public convenience and necessity issued by the Virginia Commission and the North Carolina
Commission authorizing the construction and operation of electric facilities now in operation for which certificates are required, and to sell electricity to retail customers. However, the Company 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.
For additional information on deregulation in the electric industry and rate matters, see COMPETITION above and Regulated Electric Operations in Future Issues and Outlook of MD&A.
Public Utility Holding Company Act of 1935 (1935 Act)
When Dominion completed the acquisition of CNG in January 2000, it became a registered public utility holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern the activities of
Dominion and its subsidiaries, including the Company, with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates and other matters. In most cases, the Company's
activities in these areas are also regulated at the state level by the Virginia Commission. The SEC's rules under the 1935 Act generally provide that the obtaining of state approvals will suffice for the 1935 Act purposes also, subject to the
fulfillment of certain post-transaction reporting requirements.
Federal Energy Regulatory Commission (FERC)
Under the Federal Power Act, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce by public utilities.
The Company sells electricity in the wholesale market under its market based-sales tariff authorized by FERC but has agreed not to make wholesale power sales under this tariff to loads located within its service territory. In January 2002, the
Company filed for FERC approval of a tariff to sell wholesale power within or outside its service territory at capped rates based on the Company’s embedded cost of generation. For additional discussion on this matter, see Regulated Electric
Operations—Wholesale Competition in Future Issues and Outlook of MD&A.
FERC Order No. 2000 requires that each public
utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and
5
participating in an regional transmission organization (RTO). To meet the requirements of Order No. 2000, the Company and eight other member companies (Alliance Companies), filed with FERC for
approval of a proposed “Alliance RTO”. In December 2001, FERC concluded the Alliance Companies lack sufficient scope as an RTO and also ordered the Alliance Companies to determine how they could fit within the Midwest Independent System
Operator. The Company will examine the possibility of joining RTOs other than those representing Midwest utilities, as directed by FERC. For additional information, see Alliance RTO in Future Issues and Outlook of MD&A.
Environmental Matters
Each business segment
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 and Outlook—Environmental Matters under MD&A. Additional information can also be found in Item 3. LEGAL PROCEEDINGS and Note 19 to the Consolidated Financial Statements.
From time to time the Company may be identified as a potentially responsible party to a superfund site. The EPA (or a state) can either (a) allow such a party to conduct and pay for a
remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These
parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, the Company may be responsible for the costs of remedial investigation and actions under the Superfund Act or other
laws or regulations regarding the remediation of waste. The Company does not believe that any currently identified sites will result in significant liabilities.
In accordance with applicable federal and state environmental laws, the Company has applied for or obtained the necessary environmental permits material to the operation of the
Company’s generating stations. Many of these permits are subject to re-issuance and continuing review.
Nuclear Regulatory Commission (NRC)
All aspects of the operation and maintenance of the Company’s nuclear power stations, which are part of the Energy
segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so
requires.
The Company filed applications for 20 year life-extension for the North Anna and Surry units in May 2001. The NRC has
accepted and is reviewing the applications. For more information on this matter, see Nuclear Relicensing in Future Issues and Outlook of MD&A.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing
nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining the Company’s nuclear generating units.
Disposal of spent nuclear fuel (SNF) is a significant issue associated with the operation and decommissioning of nuclear power plants. The Nuclear Waste
Policy Act of 1982 (NWPA) requires the federal government to make available by January 31, 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel. In February 2002, the Secretary of Energy recommended that Yucca Mountain
located in the state of Nevada be developed as the permanent repository. The plan may be appealed by the state of Nevada and is subject to various congressional approvals and NRC licensing.
6
The Company and other utilities have petitioned for review in the U.S. Court of Appeals for the
11th Circuit, a matter involving the DOE and PECO Energy Company (PECO). The petitioners are challenging the DOE’s action in allowing PECO to take credits against payments PECO would have been making into the Nuclear Waste Fund (NWF). The
credits are part of a DOE settlement agreement with PECO for potential claims arising out of DOE’s breach of its SNF storage obligation. The petition asserts that DOE violated the NWPA by improperly depleting the NWF and releasing PECO from a
portion of its NWF obligation. The petition also seeks a declaration that credits against NWF payments violate the NWPA, an injunction against DOE implementing the credit and fee reduction provisions of the settlement agreement, and an injunction
against DOE entering into similar agreements. The case was argued in December 2001, and is pending before the court.
The NRC
also requires the Company to decontaminate its nuclear facilities once operations cease. This process is referred to as decommissioning, and the Company is required by the NRC to prepare for it financially. For information on compliance with NRC
financial assurance requirements, see Note 8 to the Consolidated Financial Statement.
See Liquidity and Capital Resources of MD&A for details
about the Company’s capital requirements and financing program including material estimated capital expenditures for environmental control facilities.
7
| Plant
|
|
Location
|
|
Type of Fuel
|
|
Net Owned Summer Capability (Mw)
|
|
| Surry |
|
Surry, VA |
|
Nuclear |
|
1,625 |
|
| North Anna |
|
Mineral, VA |
|
Nuclear |
|
1,628 |
(a) |
| Bremo |
|
Bremo Bluff, VA |
|
Coal |
|
227 |
|
| Chesterfield |
|
Chester, VA |
|
Coal |
|
1,229 |
|
| Clover |
|
Clover, VA |
|
Coal |
|
441 |
(b) |
| Mt. Storm |
|
Mt. Storm, WV |
|
Coal |
|
1,587 |
|
| Chesapeake |
|
Chesapeake, VA |
|
Coal |
|
595 |
|
| Possum Point |
|
Dumfries, VA |
|
Coal |
|
322 |
|
| Yorktown |
|
Yorktown, VA |
|
Coal |
|
326 |
|
| Possum Point |
|
Dumfries, VA |
|
Oil |
|
929 |
|
| Yorktown |
|
Yorktown, VA |
|
Gas/Oil |
|
818 |
|
| North Branch |
|
Bayard, WV |
|
Waste Coal |
|
74 |
|
| Altavista |
|
Altavista, VA |
|
Coal |
|
63 |
|
| Hopewell |
|
Hopewell, VA |
|
Coal |
|
63 |
|
| Southampton |
|
Southampton, VA |
|
Coal |
|
63 |
|
| Remington (CT) |
|
Remington, VA |
|
Gas/Oil |
|
576 |
|
| Gravel Neck (CT) |
|
Surry, VA |
|
Gas/Oil |
|
329 |
|
| Darbytown (CT) |
|
Richmond, VA |
|
Gas/Oil |
|
288 |
|
| Ladysmith (CT) |
|
Ladysmith, VA |
|
Gas/Oil |
|
296 |
|
| Chesapeake (CT) |
|
Chesapeake, VA |
|
Gas/Oil |
|
144 |
|
| Possum Point (CT) |
|
Dumfries, VA |
|
Gas/Oil |
|
78 |
|
| Northern Neck (CT) |
|
Lively, VA |
|
Gas/Oil |
|
64 |
|
| Low Moor (CT) |
|
Covington, VA |
|
Gas/Oil |
|
60 |
|
| Kitty Hawk (CT) |
|
Kitty Hawk, NC |
|
Gas/Oil |
|
44 |
|
| Mt. Storm (CT) |
|
Mt. Storm, WV |
|
Gas/Oil |
|
12 |
|
| Bellmeade (CC) |
|
Richmond, VA |
|
Gas/Oil |
|
230 |
|
| Chesterfield (CC) |
|
Chester, VA |
|
Gas/Oil |
|
397 |
|
| Gaston |
|
Roanoke Rapids, NC |
|
Hydro |
|
225 |
|
| Roanoke Rapids |
|
Roanoke Rapids, NC |
|
Hydro |
|
99 |
|
| Bath County |
|
Warm Springs, VA |
|
Hydro |
|
1,260 |
(c) |
| Other |
|
Various |
|
Various |
|
2 |
|
| |
|
|
|
|
|
|
|
| |
|
|
|
|
|
14,094 |
|
| |
|
|
|
|
|
|
|
| Purchased Capacity |
|
|
|
|
|
3,770 |
|
| Net Purchases |
|
|
|
|
|
145 |
|
| |
|
|
|
|
|
|
|
| |
|
|
|
Total Capacity |
|
18,009 |
|
| |
|
|
|
|
|
|
|
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle
(a) |
|
Excludes 11.6 percent undivided interest owned by Old Dominion Electric Cooperative (ODEC). |
(b) |
|
Excludes 50 percent undivided interest owned by ODEC. |
(c) |
|
Excludes 40 percent undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc. |
8
SOURCES OF ENERGY USED AND FUEL SUPPLY COSTS
For information as to energy supply mix and the average
fuel cost of energy supply, see Discussion of Segments—Energy under MD&A.
Power Purchase Contracts
The Company’s Energy segment purchases electricity under contracts with other suppliers to meet a portion of our own system capacity requirements
and makes other wholesale electric power transactions. As of December 31, 2001, the Company has 43 power purchase contracts with a combined dependable summer capacity of 3,770 Mw. For information on the financial obligations under these agreements,
see Note 19 to the Consolidated Financial Statements.
In 2001, the Company completed the purchase of three generating
facilities and the termination of seven long-term power purchase contracts with non-utility generators. The Company recorded a charge of approximately $136 million, after taxes, in connection with these transactions.
Fuel for Electric Generation
The Company uses a
variety of fuels to power its electric generation. These include a mix of both nuclear fuel and fossil fuel as described further below.
Nuclear Fuel Supply
The Company’s Energy segment utilizes both long-term contracts and spot purchases to
support the Company’s nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices. Current agreements, inventories and spot market availability are expected to
support current and planned fuel supply needs. Additional fuel is purchased as required to achieve optimum cost and inventory levels.
The DOE did not begin accepting of SNF in 1998 as specified in the DOE contract. However, on-site SNF pool and dry container storage at the Surry and North Anna Power Stations are expected to be adequate for our needs until the DOE begins
accepting SNF. See REGULATION—Nuclear Regulatory Commission (NRC) for additional information regarding SNF.
Fossil Fuel
Supply
The Company’s Energy segment utilizes coal, oil, and natural gas in its fossil operations. Coal is obtained
through long-term contracts and spot purchases. The Company anticipates sufficient supplies of coal will continue to be available at reasonable prices.
Oil and oil-fired generation are used primarily to support heavier system generation loads during very cold or very hot weather periods. System requirements are purchased under both short-term spot agreements and
longer term contracts. A sufficient supply of oil is expected to be available over the next five to ten year period.
Firm
natural gas transportation contracts (capacity) exist that allow delivery of gas to generating facilities. The Company has positioned its capacity portfolio in such a way that allows flexible natural gas deliveries to its gas turbine fleet, while
minimizing costs. With natural gas being the preferred source of new electric generation, competition for existing gas capacity has increased. In order to ensure reliable delivery of natural gas, the Company has acquired more natural gas capacity
and has a capacity plan in place designed to protect its fleet from any perceived or real capacity shortage in the market.
9
In March 2001, the Virginia Commission issued an order approving the
Company’s application to make modifications to its Possum Point Power Station. The order approves the Company’s plan to remove two existing oil-fired units from service, convert two existing coal-fired units to natural gas, and construct a
new 540 Mw combined cycle unit to be operational by May 2003.
The Delivery segment maintains major interconnections with Carolina Power and Light
Company, American Electric Power Company, Inc., Allegheny Energy, Inc. and the utilities in the Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission network, the Company has arrangements with these utilities for coordinated
planning, operation, emergency assistance and exchanges of capacity and energy.
In June 1999, the Company and eight other
member companies (Alliance Companies) filed with FERC for the approval of an RTO. In December 2001, FERC concluded the Alliance Companies lack sufficient scope as an RTO and also ordered the Alliance Companies to determine how they can fit within
the Midwest Independent System Operator. The Company will examine the possibility of joining RTOs other than those representing Midwest utilities, as directed by FERC. See REGULATION—State Regulations and Federal Regulations and Alliance RTO
under MD&A for a discussion of state and federal laws and proceedings relating to the establishment of regional transmission entities and RTO’s.
The Company owns its principal properties in fee (except as
indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of the Company’s property is subject to the lien of a mortgage securing its First and Refunding Mortgage Bonds.
The Delivery segment has obtained right-of-way grants from the apparent owners of real estate for most of the Company’s
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, where permission to operate can be revoked. Portions of transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line if
any exists.
The Company leases its headquarters facility from Dominion. In addition, the Energy and Delivery segments share
certain leased buildings and equipment.
See Virginia Electric and Power Company’s Power Generation under Item 1. BUSINESS
for a list of the principal facilities utilized by the Energy segment.
From time to time, the Company is alleged to be in
violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans, or permits issued by various local, state and federal agencies for the construction or operation of facilities. From time to time,
there may be pending administrative proceedings on these matters. In addition, in the normal course of business, the Company is involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not
have a material adverse effect on the Company’s financial position, liquidity or results of operations.
See REGULATION
under Item 1. BUSINESS, Future Issues and Outlook of MD&A, and Note 19 to the Consolidated Financial Statements for additional information on various regulatory proceedings to which the Company is a party.
10
In April 1999, the Department of Justice (DOJ) notified the Company of alleged noncompliance
with the EPA’s oil spill prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of our power stations. In December 2001, the Company reached a settlement agreement with the DOJ and EPA covering
all alleged noncompliance issues. The settlement will not have a material impact on the Company’s financial condition or results of operations. The Company also identified matters at other power stations that the EPA might view as not in
compliance with the SPCC and FRP requirements and reported these matters to the EPA. The Company also reported its plans for correcting the issues. The Company does not believe that the settlement of these self-reported matters, if any, will be
material to its results of operations or financial conditions.
During 2000, the Company received a Notice of Violation from the
EPA alleging that the company failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at the Mt. Storm Power Station in West Virginia. The Attorney General of New York filed a suit
against the Company alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. The Company also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations.
Management believes that the Company has obtained the necessary permits for its generating facilities. The Company has reached an agreement in principle with the federal government and the state of New York to resolve this situation. The agreement
in principle includes payment of a $5 million civil penalty, a commitment of $14 million for environmental projects in Virginia, West Virginia, Connecticut, New Jersey and New York, and a 12-year, $1.2 billion capital investment program for
environmental improvements at the Company's coal-fired generating stations in Virginia and West Virginia. The Company had already committed to a substantial portion of the $1.2 billion expenditures for SO2 and NOx emissions controls. The negotiations over the terms of a binding settlement have expanded beyond the basic agreement in
principle and are ongoing.
A special meeting
of the Company’s shareholders was held on December 12, 2001 and was reconvened on December 18, 2001. On December 12, 2001 shareholders voted on matters (A),(B) and (D) below, and on December 18, 2001 shareholders voted on (C).
(A) |
|
To amend the Articles to increase the percentages in the definition of “AA” Rate Multiple set forth in the Articles of Amendment relating to the October 1988
Series Money Market Cumulative Preferred Stock. |
The results of the vote taken was as follows:
| Security
|
|
FOR
|
|
AGAINST
|
|
ABSTAIN
|
| Common Stock |
|
171,484 |
|
0 |
|
0 |
| All Preferred Stock |
|
2,505,603 |
|
3,678 |
|
33,409 |
| $5 Dividend Preferred Stock |
|
35,953 |
|
620 |
|
2,020 |
| $4.04 Dividend Preferred Stock |
|
3,221 |
|
310 |
|
220 |
| $4.20 Dividend Preferred Stock |
|
2,852 |
|
200 |
|
142 |
| $4.12 Dividend Preferred Stock |
|
24,841 |
|
474 |
|
10 |
| $4.80 Dividend Preferred Stock |
|
28,287 |
|
2,074 |
|
717 |
| $7.05 Dividend Preferred Stock |
|
76,499 |
|
0 |
|
1,000 |
| $6.98 Dividend Preferred Stock |
|
2,950 |
|
0 |
|
29,300 |
| January 1987 Series Money Mkt |
|
20,000 |
|
0 |
|
0 |
| June 1987 Series Money Mkt |
|
706,000 |
|
0 |
|
0 |
| October 1988 Series Money Mkt |
|
396,000 |
|
0 |
|
0 |
| June 1989 Series Money Mkt |
|
509,000 |
|
0 |
|
0 |
| September 1992A Series MM |
|
295,000 |
|
0 |
|
0 |
| September 1992AB Series MM |
|
405,000 |
|
0 |
|
0 |
11
(B) |
|
To amend the Articles to increase the percentages in the definition of “AA” Rate Multiple set forth in the Articles of Amendment relating to the June 1989 Series
Money Market Cumulative Preferred Stock. |
The results of the vote taken was as follows:
| Security
|
|
FOR
|
|
AGAINST
|
|
ABSTAIN
|
| Common Stock |
|
171,484 |
|
0 |
|
0 |
| All Preferred Stock |
|
2,505,723 |
|
3,680 |
|
33,287 |
| $5 Dividend Preferred Stock |
|
35,953 |
|
622 |
|
2,018 |
| $4.04 Dividend Preferred Stock |
|
3,221 |
|
310 |
|
220 |
| $4.20 Dividend Preferred Stock |
|
2,972 |
|
200 |
|
22 |
| $4.12 Dividend Preferred Stock |
|
24,841 |
|
474 |
|
10 |
| $4.80 Dividend Preferred Stock |
|
28,287 |
|
2,074 |
|
717 |
| $7.05 Dividend Preferred Stock |
|
76,499 |
|
0 |
|
1,000 |
| $6.98 Dividend Preferred Stock |
|
2,950 |
|
0 |
|
29,300 |
| January 1987 Series Money Mkt |
|
20,000 |
|
0 |
|
0 |
| June 1987 Series Money Mkt |
|
706,000 |
|
0 |
|
0 |
| October 1988 Series Money Mkt |
|
396,000 |
|
0 |
|
0 |
| June 1989 Series Money Mkt |
|
509,000 |
|
0 |
|
0 |
| September 1992A Series MM |
|
295,000 |
|
0 |
|
0 |
| September 1992AB Series MM |
|
405,000 |
|
0 |
|
0 |
(C) |
|
To amend the Articles to make certain conforming technical changes and to increase the percentages in the definition of “AA” Rate Multiple set forth in the
Articles of Amendment relating to the September 1992A Series Auction Market Preferred Stock. |
The results
of the vote taken was as follows:
| Security
|
|
FOR
|
|
AGAINST
|
|
ABSTAIN
|
| Common Stock |
|
171,484 |
|
0 |
|
0 |
| All Preferred Stock |
|
2,505,597 |
|
3,678 |
|
33,415 |
| $5 Dividend Preferred Stock |
|
35,947 |
|
620 |
|
2,026 |
| $4.04 Dividend Preferred Stock |
|
3,221 |
|
310 |
|
220 |
| $4.20 Dividend Preferred Stock |
|
2,852 |
|
200 |
|
142 |
| $4.12 Dividend Preferred Stock |
|
24,841 |
|
474 |
|
10 |
| $4.80 Dividend Preferred Stock |
|
28,287 |
|
2,074 |
|
717 |
| $7.05 Dividend Preferred Stock |
|
76,499 |
|
0 |
|
1,000 |
| $6.98 Dividend Preferred Stock |
|
2,950 |
|
0 |
|
29,300 |
| January 1987 Series Money Mkt |
|
20,000 |
|
0 |
|
0 |
| June 1987 Series Money Mkt |
|
706,000 |
|
0 |
|
0 |
| October 1988 Series Money Mkt |
|
396,000 |
|
0 |
|
0 |
| June 1989 Series Money Mkt |
|
509,000 |
|
0 |
|
0 |
| September 1992A Series MM |
|
295,000 |
|
0 |
|
0 |
| September 1992AB Series MM |
|
405,000 |
|
0 |
|
0 |
12
(D) |
|
To amend the Articles to make certain conforming technical changes and to increase the percentages in the definition of “AA” Rate Multiple set forth in the
Articles of Amendment relating to the September 1992B Series Auction Market Preferred Stock. |
The results
of the vote taken was as follows:
| Security
|
|
FOR
|
|
AGAINST
|
|
ABSTAIN
|
| Common Stock |
|
171,484 |
|
0 |
|
0 |
| All Preferred Stock |
|
2,505,597 |
|
3,676 |
|
33,417 |
| $5 Dividend Preferred Stock |
|
35,947 |
|
618 |
|
2,028 |
| $4.04 Dividend Preferred Stock |
|
3,221 |
|
310 |
|
220 |
| $4.20 Dividend Preferred Stock |
|
2,852 |
|
200 |
|
142 |
| $4.12 Dividend Preferred Stock |
|
24,841 |
|
474 |
|
10 |
| $4.80 Dividend Preferred Stock |
|
28,287 |
|
2,074 |
|
717 |
| $7.05 Dividend Preferred Stock |
|
76,499 |
|
0 |
|
1,000 |
| $6.98 Dividend Preferred Stock |
|
2,950 |
|
0 |
|
29,300 |
| January 1987 Series Money Mkt |
|
20,000 |
|
0 |
|
0 |
| June 1987 Series Money Mkt |
|
706,000 |
|
0 |
|
0 |
| October 1988 Series Money Mkt |
|
396,000 |
|
0 |
|
0 |
| June 1989 Series Money Mkt |
|
509,000 |
|
0 |
|
0 |
| September 1992A Series MM |
|
295,000 |
|
0 |
|
0 |
| September 1992AB Series MM |
|
405,000 |
|
0 |
|
0 |
13
PART II
Dominion Resources, Inc. (Dominion) owns all of the Company’s common stock.
The Company paid quarterly cash
dividends on its common stock as follows:
| |
|
1st
|
|
2nd
|
|
3rd
|
|
4th
|
| |
|
(Millions) |
| 2001 |
|
$ |
81 |
|
$ |
73 |
|
$ |
178 |
|
$ |
60 |
| 2000 |
|
$ |
93 |
|
$ |
94 |
|
$ |
160 |
|
$ |
61 |
| |
|
2001
|
|
2000
|
|
1999(3)
|
|
1998(2)
|
|
1997(1)
|
| |
|
(Millions) |
| Operating revenue |
|
$ |
4,944 |
|
$ |
4,791 |
|
$ |
4,591 |
|
$ |
4,280 |
|
$ |
4,664 |
| Income from operations |
|
|
999 |
|
|
1,086 |
|
|
1,007 |
|
|
681 |
|
|
1,015 |
| Income before extraordinary item and cumulative effect of a change in accounting principle |
|
|
446 |
|
|
558 |
|
|
485 |
|
|
230 |
|
|
469 |
| Extraordinary item (net of income taxes of $197) |
|
|
|
|
|
|
|
|
255 |
|
|
|
|
|
|
| Cumulative effect of a change in accounting principle (net of income taxes of $11) |
|
|
|
|
|
21 |
|
|
|
|
|
|
|
|
|
| Net income |
|
|
446 |
|
|
579 |
|
|
230 |
|
|
230 |
|
|
469 |
| Balance available for common stock |
|
|
423 |
|
|
543 |
|
|
193 |
|
|
194 |
|
|
433 |
| Total assets |
|
|
13,784 |
|
|
13,331 |
|
|
11,765 |
|
|
11,985 |
|
|
11,925 |
| Long-term debt, noncurrent capital lease obligations, preferred stock subject to mandatory redemption and preferred securities of
subsidiary trust |
|
|
3,864 |
|
|
3,722 |
|
|
3,716 |
|
|
3,805 |
|
|
3,854 |
(1) |
|
Revenue for the first eight months of 1997 includes revenue associated with power marketing and gas sales with related cost of sales of such operations recorded
as a component of fuel, net. The Company experienced significant growth in its power marketing operations in 1997. Beginning in September 1997, the Company recorded the results of its power marketing and gas sales operations, not subject to
cost-based rate regulation, as a component of other revenue, net of related cost of sales. |
(2) |
|
Revenue for 1998 reflects the Company’s settlement of base rate proceedings which included a one-time rate refund of $150 million and a base rate reduction
of $100 million beginning in March 1998. Net income for 1998 reflects the aforementioned base rate refund and rate reduction as well as an impairment charge of $159 million to write-off net regulatory assets no longer considered recoverable as a
result of the rate settlement. |
(3) |
|
In 1999, the Company discontinued the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types
of Regulation, to its generation operations in connection with the deregulation of these operations in Virginia. The discontinuance of SFAS No. 71 for generation resulted in a $255 million after-tax charge. See Note 6 to the Consolidated
Financial Statements. |
14
Introduction
MD&A explains the results of operations and general financial condition of Virginia Electric
and Power Company (Virginia Power). MD&A should be read in conjunction with the Consolidated Financial Statements. “The Company” is used throughout MD&A and, depending on the context of its use, may represent any of the following:
the legal entity, Virginia Electric and Power Company, one of Virginia Power’s consolidated subsidiaries, or the entirety of Virginia Power and its consolidated subsidiaries. The Company is a wholly-owned subsidiary of Dominion Resources, Inc.
Cautionary Statements Regarding Forward-Looking Information
From time to time the Company makes statements concerning its expectations, plans, objectives, future financial performance and other statements that are not historical facts. These
statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In some cases the reader can identify these forward-looking statements by words such as “anticipate”,
“estimate”, “expect”, “forecast”, “believe”, “should”, “could”, “plan”, “may” or other similar words.
Forward-looking statements are made by the Company with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from the results
predicted. Factors that could cause actual results to differ materially are often presented with the forward-looking statements themselves. In addition, other factors could cause actual results to differ materially from those indicated in any
forward-looking statement. These factors include, but are not limited to:
| |
• |
|
Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
| |
• |
|
Extreme weather events that could disrupt or cause catastrophic damage to the Company’s electric distribution and transmission systems; |
| |
• |
|
Exposure to unanticipated changes in prices for energy commodities purchased or sold; |
| |
• |
|
State and federal legislative and regulatory developments, including deregulation and restructuring of the electric utility industry and changes in environmental and other laws
and regulations to which the Company is subject; |
| |
• |
|
The timing and implementation of the Company’s business separation plan; |
| |
• |
|
The effects of competition, including the extent and timing of the entry of additional competitors in the electric market; |
| |
• |
|
The Company’s pursuit of potential business strategies, including acquisitions or dispositions of assets; |
| |
• |
|
Regulatory factors such as changes in the policies or procedures that set rates, changes in the Company’s ability to recover investments made under traditional regulation
through rates, and changes to the frequency and timing of rate increases; |
| |
• |
|
Financial or regulatory accounting principles or policies imposed by governing bodies; |
| |
• |
|
Political, legal, and economic conditions and developments in the U.S. This would include the threat of domestic terrorism, inflation rates and monetary fluctuations;
|
| |
• |
|
Changing market conditions and other factors related to physical and financial energy trading activities, including energy commodity price, basis, counterparty credit risk,
liquidity, volatility, capacity, transmission, currency exchange rates, interest rates and warranty risks; |
| |
• |
|
Financial market conditions, including availability and cost of capital, and the Company’s ability to obtain financing on favorable terms; |
15
| |
• |
|
The performance of the Company’s projects and the success of efforts to invest in and develop new opportunities, including development of power generation facilities;
|
| |
• |
|
The cost of replacement electric energy in the event of unscheduled generation outages; and |
| |
• |
|
Employee workforce factors, including collective bargaining agreements with union employees. |
The Company has based its forward-looking statements on management’s beliefs and assumptions using information available at the time the statements were made. The Company cautions
the reader not to place undue reliance on its forward-looking statements because the assumptions, beliefs, expectations and projections about future events may and often do materially differ from actual results. The Company undertakes no obligation
to update any forward-looking statements to reflect developments occurring after the statements are made. Interested parties should also consider other risks identified from time to time in the Company’s reports and registration statements
filed with the Securities and Exchange Commission.
Operating Segments
In general, management’s discussion of the Company’s results of operations focuses on the contributions of its operating segments. However, the discussion of the Company’s
financial condition under Liquidity and Capital Resources is for the entire company. The Company’s two primary operating segments are:
Energy manages the Company’s portfolio of generating facilities and power purchase contracts and its energy trading, marketing, hedging and arbitrage
activities. Energy’s operating results reflect: the impact of weather on demand for electricity; customer growth as influenced by overall economic conditions; and changes in prices of commodities, primarily electricity and natural gas, that the
segment actively markets and trades, uses for hedging purposes and consumes in generation activities. The cost of fuel used in generation operations and electric energy purchases incurred by the Company to serve Virginia and North Carolina retail
customers is generally recoverable through rates charged to customers.
Delivery manages the
Company’s electric distribution and transmission systems as well as customer service. Delivery’s operating results reflect the impact of weather on demand for electricity and customer growth as influenced by overall economic conditions.
The segment is subject to cost-of-service rate regulation and base rates are currently capped in Virginia and North Carolina.
In addition, the Company also reports Corporate and Other as a segment. The Company includes certain expenses which are not allocated to the Energy and Delivery segments in Corporate and Other.
For more information on the Company’s operating segments, see Note 23 to the Consolidated Financial Statements.
Critical Accounting Policies
The Company has
identified the following accounting policies that, as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition
or results of operations under different conditions or using different assumptions.
Accounting for risk management and
energy trading contracts at fair value—The Company uses derivatives to manage its commodity, financial market and currency exchange risks. In addition, the Company purchases and sells commodity-based contracts in the natural gas,
electricity and oil markets for trading purposes. The accounting requirements for derivatives and hedging activities are complex and interpretation of these requirements by standard-setting bodies is ongoing. All derivatives, other than specific
exceptions, are reported on the Consolidated Balance Sheet at fair value, beginning in 2001. Energy trading contracts are also reported on the Consolidated Balance Sheet at fair value. Changes in fair value, except those related to derivative
instruments
16
designated as cash flow hedges, are generally included in the determination of the Company’s net income at each financial reporting date until the contracts are ultimately settled. The
measurement of fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry
publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies deemed appropriate by the Company’s management. For individual
contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value. In addition, for hedges of forecasted transactions, the Company must estimate the expected future cash flows of forecasted
transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition of changes in fair value of certain hedging
derivatives. See Selected Information—Energy Trading Activities and Market Rate Sensitive Instruments and Risk Management in MD&A and Notes 2, 9, and 20 to the Consolidated Financial Statements.
Accounting for regulated operations—Methods of allocating costs to accounting periods for operations subject to
federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. When the timing of cost recovery prescribed by regulatory authorities differs from the timing of expense recognition
used for accounting purposes, the Company’s consolidated financial statements may recognize a regulatory asset for expenditures that otherwise would be expensed. Regulatory assets represent probable future revenue associated with certain costs
that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. See Notes 2,
6, and 10 to the Consolidated Financial Statements.
Results of Operations
The Company’s discussion of its results of operations includes an overview of its operating revenue and operating results for 2001 and 2000, on a consolidated basis. These sections
are followed by a more detailed discussion of the results of operations of the operating segments. For additional information about the Company’s operating segments, see Note 23 to the Consolidated Financial Statements.
Overview of Results
| |
|
Year Ended December 31,
|
|
| |
|
Net Income Contribution
|
|
|
Operating Revenue
|
|
Operating Expenses
|
|
| |
|
2001
|
|
|
2000
|
|
|
1999
|
|
|
2001
|
|
2000
|
|
1999
|
|
2001
|
|
2000
|
|
1999
|
|
| |
|
(Millions) |
|
| Energy |
|
$ |
380 |
|
|
$ |
369 |
|
|
$ |
292 |
|
|
$ |
3,722 |
|
$ |
3,577 |
|
$ |
3,423 |
|
$ |
2,953 |
|
$ |
2,900 |
|
$ |
2,846 |
|
| Delivery |
|
|
230 |
|
|
|
246 |
|
|
|
193 |
|
|
|
1,212 |
|
|
1,210 |
|
|
1,160 |
|
|
713 |
|
|
718 |
|
|
740 |
|
| Corporate and Other |
|
|
(164 |
) |
|
|
(36 |
) |
|
|
(255 |
) |
|
|
10 |
|
|
4 |
|
|
8 |
|
|
279 |
|
|
87 |
|
|
(2 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
$ |
446 |
|
|
$ |
579 |
|
|
$ |
230 |
|
|
$ |
4,944 |
|
$ |
4,791 |
|
$ |
4,591 |
|
$ |
3,945 |
|
$ |
3,705 |
|
$ |
3,584 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overview of Operating Revenue—Consolidated
The following is a general discussion of factors that affect operating revenue for both the Energy and Delivery segments.
The majority of the Company’s operating revenue is provided through bundled rate tariffs. Regulated electric sales consist primarily of sales to
retail customers at rates authorized by the State Corporation Commission of Virginia (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission), and sales to cooperatives and municipalities at wholesale rates
authorized by the Federal Energy Regulatory Commission (FERC). Also included in regulated electric sales are amounts received from others for use of the Company’s transmission system to transport electric energy under tariffs authorized by
FERC.
17
Electric sales vary seasonally and in response to weather. The resulting impact may be
significant on regulated electric sales. The impact of weather on electric sales is measured in terms of heating degree-days and cooling degree-days. A mild summer or winter can have a significant impact on revenue. Electric sales are also impacted
by the number of customers that the Company serves, which continues to increase. Regulated electric sales also include recovery of the cost of fuel used in generating electricity for customers served under regulated tariffs through fuel rates
approved by regulatory authorities. Fluctuations in amounts recovered will affect amounts reported as regulated electric sales.
Overview of
2001 Results
Operating Revenue
Operating revenue increased $153 million to $4.9 billion for 2001 as compared to 2000. The increase was due primarily to higher fuel rate recoveries, growth in the numbers of retail customers and increased wholesale
sales to cooperatives and municipalities under requirements contracts. These factors were offset by milder weather conditions in 2001. While there were 6 percent more cooling degree-days in 2001 as compared to 2000, the 10 percent decline in heating
degree-days more than offset the benefit experienced in the summer. The Company served, on average, 40,000 more retail customers during 2001.
The results of the Company’s trading and marketing operations, which are recorded as other revenue, net of cost sales, also contributed slightly to the overall increase in operating revenue.
Operating Expenses
Operating expenses
increased $240 million to $3.9 billion for 2001 as compared to 2000. Higher prices for commodities consumed contributed to increased electric fuel and energy purchases, net. Purchased electric capacity expense decreased as the
Company terminated certain contracts in early 2001. See Note 19 to the Consolidated Financial Statements. Depreciation and amortization decreased primarily due to a change in the estimated useful lives of the Company’s nuclear plants in
connection with the expected re-licensing of those plants offset by additional expense related to other recent capital expenditures. The Company incurred restructuring costs in both 2001 and 2000 primarily associated with Dominion’s
acquisition of CNG and subsequent integration of the combined companies’ operations. Other operations and maintenance expenses increased primarily due to costs associated with the termination of certain long-term power purchase
contracts. Other taxes decreased, reflecting the change in Virginia whereby the Company became subject to state income taxes rather than gross receipts taxes effective January 2001.
Other Factors Affecting Net Income
The Company’s effective income tax
rate increased in 2001 due to its utility operations in Virginia becoming subject to state income taxes in lieu of gross receipts taxes.
18
Overview of 2000 Results
Operating Revenue
Total operating revenue increased $200 million to $4.8 billion for 2000 as compared to 1999.
Regulated electric sales increased as a result of customer growth, higher fuel rates, and a charge for rate refunds taken in 1999. Regulated electric sales revenue also increased in 2000, as compared to 1999, reflecting higher customer usage in
response to colder fall and winter weather, offset somewhat by lower customer usage resulting from milder summer weather. For 2000, as compared to 1999, the 12% increase in heating degree-days was largely offset by the 12% decrease in cooling
degree-days. Revenue from electric transmission services did not change significantly.
Other revenue decreased in 2000,
as compared to 1999, reflecting lower off-system electric sales resulting primarily from the expiration of two major long-term power purchase contracts in late 1999.
Operating Expenses
Operating expenses increased $121 million to $3.7 billion in 2000, as
compared to 1999. Electric fuel and energy purchases, net increased in 2000 due to increased generation activity and higher costs for fossil fuels consumed and energy purchases. Other operations and maintenance expenses were
approximately the same in 2000 and 1999, with higher corporate and administrative costs being offset by lower service restoration costs. Purchased electric capacity expense decreased due to the expiration of two major long-term power purchase
contracts in late 1999. The Company incurred restructuring charges in 2000 primarily associated with Dominion’s integration of CNG into its consolidated operations.
Other Factors Affecting Net Income
Interest expense and related charges increased $7
million to $296 million reflecting additional borrowings in 2000. Also in 2000, the cumulative effect of a change in the method of accounting for certain components of pension cost increased the Company’s net income by $21 million (net of
income taxes of $11 million). See Note 3 to the Consolidated Financial Statements. In 1999, the Company recorded an extraordinary item of $255 million (net of income taxes of $197 million) reflecting primarily the write-off of certain
regulatory assets. See Note 6 to the Consolidated Financial Statements.
Segment Results
Energy Segment
| |
|
2001
|
|
2000
|
|
1999
|
| |
|
(millions) |
| Operating revenue |
|
$ |
3,722 |
|
$ |
3,577 |
|
$ |
3,423 |
| Operating expense |
|
|
2,953 |
|
|
2,900 |
|
|
2,846 |
| Net income contribution |
|
|
380 |
|
|
369 |
|
|
292 |
| |
|
|
|
|
|
|
|
|
|
| Electricity supplied (mmwhr) |
|
|
72 |
|
|
74 |
|
|
71 |
19
The Company provides electricity primarily from the following fuel sources: nuclear, coal, oil
and purchased power. System energy output by energy source and the average fuel cost for each are shown below. Fuel cost is presented in mills (one tenth of one cent) per kilowatt-hour.
| |
|
2001
|
|
2000
|
|
1999
|
| |
|
Source
|
|
|
Cost
|
|
Source
|
|
|
Cost
|
|
Source
|
|
|
Cost
|
| Nuclear(1) |
|
31 |
% |
|
$ |
4.64 |
|
33 |
% |
|
$ |
4.48 |
|
35 |
% |
|
$ |
4.59 |
| Coal(2) |
|
40 |
|
|
|
16.55 |
|
42 |
|
|
|
14.04 |
|
38 |
|
|
|
13.73 |
| Oil |
|
5 |
|
|
|
36.41 |
|
3 |
|
|
|
35.89 |
|
4 |
|
|
|
20.47 |
| Purchased power, net |
|
21 |
|
|
|
24.38 |
|
20 |
|
|
|
23.97 |
|
19 |
|
|
|
23.95 |
| Other |
|
3 |
|
|
|
42.37 |
|
2 |
|
|
|
44.58 |
|
4 |
|
|
|
28.98 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
100 |
% |
|
|
|
|
100 |
% |
|
|
|
|
100 |
% |
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average fuel cost |
|
|
|
|
|
16.35 |
|
|
|
|
|
14.20 |
|
|
|
|
|
13.34 |
(1) |
|
Excludes Old Dominion Electric Cooperative’s (ODEC) 11.6 percent ownership interest in the North Anna Power Station. |
(2) |
|
Excludes ODEC’s 50 percent ownership interest in the Clover Power Station. |
2001 Results
Operating Revenue
See Overview of Operating Revenue—Consolidated.
Operating Expenses
Operating expenses increased $53 million for 2001, as compared to 2000. Electric fuel and energy purchases, net were
higher in 2001, reflecting higher fuel prices in coal and oil consumed as well as higher levels of recovery of previously deferred fuel costs. The effect of such expenses on net income was mitigated by increased fuel rate revenue. Purchased
electric capacity costs decreased as a result of the termination of long-term power purchase agreements in the first quarter of 2001. The decrease in depreciation and amortization expense primarily reflects a change in the estimated
useful lives of the Company’s nuclear plants which resulted in a $72 million decrease in depreciation expense. This change is based on the Company’s expectation that 20-year extensions of the operating licenses for its nuclear facilities
will be granted. The application was filed with the Nuclear Regulatory Commission in May 2001. The decrease in depreciation was partially offset by additional depreciation expense related to other recent generation-related capital expenditures.
Other operations and maintenance increased due to scheduled outages at both nuclear and fossil plants. Other taxes decreased reflecting the change in Virginia whereby the Company became subject to state income taxes rather than gross
receipts taxes effective January 2001.
2000 Results
Operating Revenue
See Overview of Operating Revenue—Consolidated.
Operating Expenses
Operating expenses increased
$54 million to $2.9 billion for 2000, as compared to 1999. Electric fuel and energy purchases, net increased in 2000 due to higher overall production from the Company’s generation units, increased costs of fossil fuels consumed and
increased energy purchases. Purchased electric capacity costs decreased due to the expiration of two major long-term power purchase contracts late in 1999. Other operations and maintenance expenses increased, reflecting
primarily higher overall corporate and administrative costs. Other taxes decreased due to the recognition of a tax refund in 2000.
20
Selected Information—Energy Trading Activities
Energy manages the Company’s energy trading, hedging and arbitrage activities through the Dominion Energy Clearinghouse (the Clearinghouse). The Company believes these operations
complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including natural gas, electricity
and oil. Settlement of a contract may require physical delivery of the underlying commodity or, in some cases, an exchange of cash. These contracts are classified as energy trading contracts for financial accounting purposes, and are included in the
Consolidated Balance Sheets as components of current and non-current derivative and energy trading assets and liabilities.
In
accordance with generally accepted accounting principles, the Company reports energy trading contracts in its financial statements at fair value. Both realized and unrealized changes in these contracts’ fair value are included in net income.
For a discussion of how the Company determines fair value for its energy trading contracts, see Critical Accounting Policies presented earlier in MD&A. Arbitrage activities constitute a substantial portion of the Clearinghouse’s
activities. Accordingly, when the Clearinghouse enters into a contract to purchase a commodity, it typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or
very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (a realized gain),
or sometimes will pay a net cash margin (a realized loss). Until the contracts are settled, however, the Company must record the monthly changes in the fair value of both contracts. These changes in fair value represent unrealized gains and losses.
To the extent purchase and sales contracts with identical or similar terms are held by the Clearinghouse, the changes in their fair values will generally offset one another. Although the Clearinghouse may hold purchase or sales contracts for
delivery of commodities at particular locations and times that have not been offset, such exposures are monitored and actively managed on a daily basis. Dominion’s risk management policy and procedures are designed to ensure that the
Company’s exposure to commodity price changes is limited. For additional discussion of trading activities, see Market Rate Sensitive Instruments and Risk Management and Notes 2, 9, and 20 to the Consolidated Financial Statements.
A summary of the changes in the unrealized gains and losses in the Company’s portfolio of energy contracts held for
trading purposes during 2001 follows:
| |
|
Energy Trading Contracts
|
|
| |
|
(millions) |
|
| Net unrealized gain at December 31, 2000 |
|
$ |
25 |
|
| Contracts realized or otherwise settled during the period |
|
|
(12 |
) |
| Net unrealized gain at inception of contracts initiated during the period |
|
|
17 |
|
| Change in unrealized gains and losses attributable to net arbitrage gains and changes in market prices |
|
|
107 |
|
| Changes in unrealized gains and losses attributable to changes in valuation techniques |
|
|
17 |
|
| |
|
|
|
|
| Net unrealized gain at December 31, 2001 |
|
$ |
154 |
|
| |
|
|
|
|
21
Unrealized gains and losses in the Company’s portfolio of energy trading contracts at
December 31, 2001 are summarized in the following table based on the approach used to determine fair value and the contract settlement or delivery dates:
| (millions) |
|
Maturity Based on Contract Settlement or Delivery Date(s)
|
| Source of Fair Value
|
|
Less than 1 year
|
|
1-2 years
|
|
2-3 years
|
|
3-5 years
|
|
Greater than 5 years
|
|
Total
|
| Prices actively quoted |
|
$ |
46 |
|
46 |
|
4 |
|
— |
|
— |
|
$ |
96 |
| Prices provided by other external sources |
|
|
— |
|
3 |
|
4 |
|
— |
|
— |
|
|
7 |
| Prices based on models and other valuation methods |
|
|
17 |
|
10 |
|
6 |
|
6 |
|
12 |
|
|
51 |
Delivery Segment
| |
|
2001
|
|
2000
|
|
1999
|
| |
|
(millions) |
| Operating revenue |
|
$ |
1,212 |
|
$ |
1,210 |
|
$ |
1,160 |
| Operating expense |
|
|
713 |
|
|
718 |
|
|
740 |
| Net income contribution |
|
|
230 |
|
|
246 |
|
|
193 |
| |
|
|
|
|
|
|
|
|
|
| Electricity delivered (mmwhr) |
|
|
72 |
|
|
74 |
|
|
71 |
2001 Results
Operating Revenue
See Overview of Operating Revenue—Consolidated.
Operating Expenses
Operating expenses were $713 million in 2001, as compared to $718 million in 2000. In addition to the effect of weather on sales, Delivery’s operating expenses can also be significantly impacted by severe weather. Hurricanes, major
thunderstorms and ice storms can cause damage to the Company’s distribution and transmission systems. During 2001 and 2000, there were no unusual levels of storm restoration activities. Depreciation and amortization increased
slightly as a result of routine property additions. Other operations and maintenance expenses included a moderate increase in provisions for uncollectible customer accounts. Other taxes decreased, reflecting the change in Virginia
whereby the Company became subject to state income taxes rather than gross receipts taxes effective January 2001.
2000 Results
Operating Revenue
See Overview of
Operating Revenue—Consolidated.
Operating Expenses
Operating expenses were $718 million in 2000, as compared to $740 million in 1999. The decrease was primarily attributable to higher other operations and maintenance
expenses in 1999, as compared to 2000, as a result of significant service restoration costs in 1999 associated with ice storm and hurricane damage.
Corporate and Other
| |
|
2001
|
|
2000
|
|
1999
|
| |
|
(millions) |
| Expenses, net of related taxes |
|
$ |
164 |
|
$ |
36 |
|
$ |
255 |
22
2001 Results
Corporate and other operations reported expenses, net of related taxes, of $164 million in 2001, an increase of $128 million, as compared to 2000. These results include the following unusual charges which were not
allocated to the Company’s operating segments: pre-tax restructuring costs of $48 million; and a pre-tax charge of $220 million related to costs associated with the purchase of three non-utility generating plants and termination of certain
long-term power purchase contracts. See Notes 5 and 19 to the Consolidated Financial Statements.
2000 Results
Corporate and other operations reported expenses, net of related taxes, of $36 million in 2000, a decrease of $219 million, as compared to 1999. These
results include pre-tax restructuring charges of $71 million in 2000, offset by a $21 million gain, net of income taxes of $11 million, from the cumulative effect of a change in the Company’s method of accounting for pensions. In 1999, the
Company recorded an extraordinary item of $255 million (net of income taxes of $197 million), reflecting primarily the write-off of certain net regulatory assets. See Notes 3, 5 and 6 to the Consolidated Financial Statements.
Liquidity and Capital Resources
The
Company depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash flow from operations are generally satisfied with proceeds from short-term
borrowings. Long-term cash needs are met through sales of securities and additional long-term debt financing.
Internal Sources of Liquidity
Cash flow from operating activities provided $1.1 billion in each year during 2001, 2000 and 1999. During each of the three
years 1999 through 2001, cash flow from operating activities, after dividend payments, was sufficient to cover over 92 percent of our capital and nuclear fuel expenditures and, on average, approximately 69 percent of our total cash
requirements. 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.
The Company’s operations are subject to risks and uncertainties that may negatively impact cash flows from operations. Such risks and uncertainties include, but are not limited to,
the following:
| |
• |
|
unusual weather and its effect on energy sales to customers and energy commodity prices; |
| |
• |
|
extreme weather events that could disrupt or cause catastrophic damage to the Company’s electric distribution and transmission systems; |
| |
• |
|
exposure to unanticipated changes in prices for energy commodities purchased or sold; |
| |
• |
|
effectiveness of Dominion’s risk management activities and underlying assessment of market conditions and related factors, including energy commodity prices, basis,
counterparty credit risk, liquidity, volatility, capacity, transmission, currency exchange rates, and interest rates; |
| |
• |
|
the cost of replacement electric energy in the event of unscheduled generation outages; and |
| |
• |
|
timeliness of recovery for costs subject to cost-of-service utility rate regulation. |
External Sources of Liquidity
The Company relies on access to bank and capital markets
as a significant source of liquidity for capital requirements not satisfied by the cash provided by the Company’s operations. The Company’s ability to borrow funds or issue securities and the return demanded by investors are affected by
the Company’s credit ratings. In
23
addition, the raising of external capital is subject to certain regulatory approvals, including the SEC and the Virginia State Corporation Commission (Virginia Commission). Credit ratings are
intended to provide banks and capital market participants with a framework for comparing the credit quality of securities. Management believes that the current credit ratings of the Company provide sufficient access to the capital markets. However,
disruptions in the bank and capital markets not specifically related to the Company may affect the Company’s ability to access these funding sources or cause an increase in the return required by investors.
Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in
establishing the Company’s credit ratings. The credit ratings for the Company are most affected by the Company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, and changes in methodologies used
by the rating agencies. Credit ratings for the Company as of March 1, 2002 follow:
| |
|
Standard & Poor’s
|
|
Moody’s
|
| Mortgage bonds |
|
A |
|
A2 |
| Senior unsecured (including tax-exempt) debt securities |
|
A- |
|
A3 |
| Preferred securities of subsidiary trust |
|
BBB+ |
|
Baa1 |
| Preferred stock |
|
BBB+ |
|
Baa2 |
| Commercial paper |
|
A-1 |
|
P-1 |
A downgrade in the Company’s credit rating would not generally restrict its
ability to raise short-term or long-term financing so long as its credit rating is still “investment grade,” but it would increase the cost of borrowing. The Company’s management proactively manages the financial condition of its
operations in an effort to maintain its current credit ratings.
As part of borrowing funds and issuing debt (both short-term
and long-term) or preferred securities, the Company must enter enabling agreements. These agreements contain covenants that, in the event of default, could trigger the acceleration of principal and interest payments and, in some cases, the
termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to
the Company. Some of the typical covenants include:
| |
• |
|
the timely payment of principal and interest; |
| |
• |
|
information requirements, including submittal of financial reports filed with the SEC to lenders; |
| |
• |
|
keeping books and records in accordance with generally accepted accounting principles; |
| |
• |
|
payment of taxes; maintaining insurance; |
| |
• |
|
performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, restrictions on
disposition of substantial assets; |
| |
• |
|
financial covenants, such as a limit on total funded debt to total capitalization; |
| |
• |
|
compliance with collateral minimums or requirements related to mortgage bonds (See Note 14 to the Consolidated Financial Statements); and |
The Company
monitors the covenants on a regular basis in order to provide assurance that events of default will not occur. As of December 31, 2001, there were no events of default under the Company’s covenants.
During 2001, the Company issued long-term debt totaling $770 million. As discussed below, proceeds were used primarily to fund: the repayment of
short-term debt; the purchase of three generation facilities from non-utility generators and the termination of related long-term power purchase agreements; the repayment of long-term debt maturities; and the Company’s capital expenditures.
24
2001-Short-Term Borrowings
The Company participates in a credit facility that supports the combined commercial paper programs of Dominion, the Company and CNG. This facility, established in May 2001, is for $1.75
billion and matures in the second quarter of 2002 and is expected to be replaced. Although the Company has access to the full amount of the $1.75 billion facility, the Company operates with an internal allocation that may vary depending upon the
needs of participating entities.
The Company’s net borrowings under the commercial paper program were $436 million at
December 31, 2001, a decrease of $278 million from amounts outstanding at December 31, 2000. Commercial paper borrowings are used primarily to fund working capital requirements and may vary significantly during the course of the year, depending upon
the timing and amount of cash requirements not satisfied by cash provided by operations.
In addition to commercial paper, the
Company may also issue up to $200 million aggregate outstanding principal of extendible commercial notes (ECNs) to meet working capital requirements. ECNs are unsecured notes that are expected to be sold in private placements. Any ECNs issued by the
Company would have a stated maturity of 390 days from issuance and may be redeemed, at the Company’s option, within 90 days or less from issuance. There were no ECNs outstanding at December 31, 2001.
2001-Other Securities Issuances and Repayments
During 2001, the Company issued the following securities:
| |
• |
|
$50 million Series 2001A, variable rate tax-exempt pollution control revenue bonds due March 1, 2031 (Revenue Bonds); |
| |
• |
|
$600 million 5.75 percent senior notes due March 31, 2006 (Senior Notes); |
| |
• |
|
$120 million variable rate medium-term notes Series G due December 16, 2003 (MTNs). |
The net proceeds of the Revenue Bonds were used to finance qualifying expenditures made during the construction of facilities at the North Anna Power Station. The net proceeds of the
Senior Notes were used for general corporate purposes, including repayment of commercial paper and payments associated with the purchase of three generation facilities from non-utility generators and the termination of related long-term power
purchase agreements. The net proceeds of the MTNs were used for general corporate purposes, including the repayment of commercial paper.
In 2001, the Company repaid approximately $341 million of long-term debt securities:
| |
• |
|
$141 million of MTNs, various series, which matured on various dates in 2001; |
| |
• |
|
$100 million of 1991-A, 8.75 percent mortgage bonds originally due April 1, 2021; |
| |
• |
|
$100 million 1993-E, 6 percent mortgage bonds due August 1, 2001. |
Also in 2001, the Company purchased and redeemed, at par, all of the outstanding shares of the Money Market Preferred (MMP) Series January 1987 and June 1987 preferred stock for $125 million.
In January 2002, the Company called its $200 million, 6.75 percent 1997-A mortgage bonds due February 1, 2007 for redemption in February 2002. The
Company funded the redemption by issuing $650 million of 5.375 percent senior notes due 2007. The Company used the remaining proceeds for general corporate purposes and to repay other debt.
25
Amounts Available under Shelf Registrations
At December 31, 2001, the Company had approximately $900 million of remaining principal amount under currently effective shelf registrations, which was reduced in January 2002 by
the issuance of $650 million of senior notes due 2007.
Investing Activities
In 2001, the Company’s investing activities resulted in a net cash outflow of $733 million. These activities included capital expenditures of $668 million and nuclear fuel
expenditures of $83 million. Generation-related projects totaled approximately $311 million and included environmental upgrades, construction of combustion turbine plants, and routine capital improvements. The Company spent approximately $312
million on transmission and distribution-related projects, reflecting routine capital improvements and expenditures associated with new connections. Other general and information technology projects represented the remaining capital expenditures of
$45 million.
Capital Requirements
The Company expects to fund its capital requirements and debt maturities with cash flow from operations and a combination of sales of securities and
short-term borrowings.
Capacity
The Company anticipates that retail peak demand will grow approximately 2.2 percent a year through 2004. The Company 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
The Company’s generation construction and nuclear fuel expenditures planned for 2002, 2003 and 2004 are expected to
total $526 million, $543 million and $376 million, respectively. The Company’s transmission and distribution capital expenditures during 2002, 2003, and 2004, are expected to total $370 million, $360 million, and $362 million, respectively.
These expenditures will primarily provide for customer growth, reliability initiatives and routine replacements.
The Company is
installing sulfur dioxide (SO2) emission control equipment at two coal-fired generating units with an expected completion
date of early 2002. The total cost for this project is estimated to be $114 million, of which $110 million has been incurred as of December 31, 2001.
In response to Clean Air Act requirements, the Company is installing nitrogen oxide (NOx)
reduction equipment on all of its affected facilities at an estimated capital cost of $565 million, of which $189 million has been incurred as of December 31, 2001. The installations are scheduled for completion by midyear 2004. The Company is
also discontinuing the use of coal at its Possum Point station in Prince William County, Virginia. Over the next three years, oil-fired units will be retired and the two coal-fired units will be converted to gas, at an estimated capital cost of $15
million. Expenditures incurred as of December 31, 2001 were not material. See Environmental Matters for additional discussion of Clean Air Act matters.
Maturities
The Company will require $535 million to meet maturities of securities in
2002. See Note 14 to the Consolidated Financial Statements for a schedule of maturities beyond 2002.
26
Contractual Cash Obligations and Commitments
Other than planned capital expenditures, the Company has contractual cash obligations and commitments associated with the following: repayment of long-term debt and mandatorily
redeemable preferred securities of subsidiary trusts (see Notes 14 and 15 to the Consolidated Financial Statements) and power purchase contracts, fuel purchase contracts, and leases (see Note 19 to the Consolidated Financial Statements). The Company
expects to fund these obligations and commitments with cash flow from operations and a combination of sales of securities and short-term borrowings. Contractual cash obligations and commitments at December 31, 2001 follow: 2002—$1.7 billion;
2003—$1.3 billion; 2004—$1.2 billion; 2005—$811 million; 2006—$1.4 billion; and years after 2006—$10.4 billion. The amount for 2002 includes $535 million associated with the repayment of previously issued securities
that are scheduled to mature. These totals do not include any amounts for working capital commitments, including the repayment of short-term debt (see Note 13 to the Consolidated Financial Statements) and settlement of derivative and energy trading
contracts (see Note 9 to the Consolidated Financial Statements).
In addition, the Company has entered into agreements with
another Dominion subsidiary in order to develop, construct, finance and lease a new power generation facility at the Company’s Possum Point station in Prince William County, Virginia. The project is scheduled for completion in 2003 at an
estimated cost of $370 million. Upon completion, the Company will operate the new generating facility under an operating lease with estimated annual lease payments of $26 million. See Note 19 to the Consolidated Financial Statements.
Future Issues and Outlook
Regulated Electric
Operations
Electric Deregulation Legislation—Virginia
In 1999, Virginia enacted comprehensive restructuring legislation. The Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) established a plan to restructure
Virginia’s electric utility industry and provided for the phase-in of choice for retail customers from January 1, 2002 through January 1, 2004. The Virginia Commission has ordered that retail choice be fully implemented in Virginia by January
1, 2003 for customers of the Company.
Under the Virginia Restructuring Act, the generation portion of the Company’s
Virginia jurisdictional operations is no longer subject to cost-based rate regulation, effective January 1, 2002. The Company’s base rates (excluding fuel costs and certain other allowable adjustments) will remain capped until July 2007, unless
terminated sooner or otherwise modified consistent with the Virginia Restructuring Act. Recovery of generation-related costs will continue through capped rates and, where applicable, a wires charge assessed on those customers opting for alternative
suppliers. The Company may petition the Virginia Commission to terminate the capped rates after January 1, 2004. If the Company were to request that the capped rates be terminated, the Virginia Commission may terminate the capped rates if it finds
that a competitive generation services market exists within the Company’s service area. The Company’s wires charge is the excess of its capped unbundled rate for generation over the projected market price for generation. The wires charge
is intended to compensate the Company for its investment in and commitments for generation-related utility assets prior to the enactment of the restructuring legislation. The Company’s methodology for calculating the wires charge and applicable
market price has been approved by the Virginia Commission. Additionally, the Virginia Restructuring Act provides that after the end of the capped rate period, any default service provided by the Company will be based upon competitive market prices
for electric generation services.
The Company began the phase-in of retail choice on January 1, 2002. The phase-in will be
completed on January 1, 2003. The Company is able to accommodate this schedule as a result of experience gained during its retail access pilot program, as well as extensive testing of its processes and systems to support customers switching to
retail access. Additionally, the pilot program demonstrated the Company’s ability to sell energy displaced by shopping customers in the wholesale market.
27
During the capped rate period, the Company may require a 12-month minimum stay period for
electricity customers with an annual peak demand of 500 kilowatts or greater who request electricity supply service after receiving electricity supply service from a competitive service provider. This measure will mitigate the practice of large
commercial and industrial customers returning to the Company’s capped rate service during periods of higher market prices and leaving during periods of lower market prices—a practice known as “seasonal gaming.”
As discussed in the Separation of Generation and Delivery Operations in Virginia and Alliance RTO sections below, the Virginia
Restructuring Act also calls for the functional separation of generation, transmission and distribution.
Electric Deregulation
Legislation—North Carolina
The North Carolina General Assembly is exploring the future of electric service in
North Carolina, the development of a competitive wholesale market and retail competition. However, there has been little recent activity.
Separation of Generation and Delivery Operations in Virginia
The Virginia Restructuring
Act addressed divestiture, functional separation and other corporate relationships. The Act required Virginia’s electric utilities to file with the Virginia Commission their plans to separate generation from transmission and distribution
operations.
The Company’s proposed separation plan included transferring the generation assets and operations, including
its non-utility power purchase contracts, to a separate affiliated company. In December 2001, the Virginia Commission directed the Company to separate its generation, distribution, and transmission functions through creation of divisions within the
Company, rather than through a transfer of generation assets to a separate affiliate. The Virginia Commission’s December 2001 order did not preclude further consideration of the Company’s proposed corporate reorganization and asset
transfer, pending, in the Virginia Commission’s view, further developments in needed market structures and competitive retail electric generation markets. The Company has filed a notice of appeal of the Virginia Commission’s order. No
assessment can be made at this time concerning future developments.
Because the Company’s operations were largely
functionally separated in its existing corporate structure, implementation of the plan ordered by the Virginia Commission will require few changes in the Company’s operations. The Company will continue to provide electric service to its
customers at capped rates until July 1, 2007, unless capped rates are terminated after January 1, 2004, as provided in the Virginia Restructuring Act. The Company will continue serving customers who select alternative energy suppliers by delivering
the electric energy and will collect a wires charge, where applicable, as discussed above. The Company will also be permitted to continue its activities in wholesale energy markets. However, effective January 1, 2002, Virginia codes of conduct
became effective governing certain transactions and communications between the Company’s electric distribution and transmission operations and its generation division. These codes of conduct are designed to prevent cross-subsidies between the
generation and other divisions and to ensure that the generation and other divisions operate independently.
Alliance RTO
Both the Virginia Restructuring Act and the FERC merger conditions require the Company join a regional transmission
organization (RTO). By joining an RTO, the Company would transfer operational control of its transmission assets to the RTO, a separate entity. The Company, together with eight other member companies (Alliance Companies), filed with FERC for
approval of the proposed “Alliance RTO.” The Company also filed an application to transfer control of its transmission facilities to the Alliance RTO with the Virginia Commission and North Carolina Utilities Commission. In December 2001,
FERC concluded the Alliance Companies lack sufficient scope as an RTO and also ordered the Alliance Companies to determine how they could fit within the
28
Midwest Independent System Operator. The Company also will examine the possibility of joining RTOs other than those representing Midwest utilities, as directed by FERC. As a result of the FERC
decision, the North Carolina application was dismissed and the Virginia application was stayed. The Company expects to refile or amend the state applications.
Despite these delays, the Company remains committed to supporting electric deregulation by becoming a member of an RTO. The formation of RTOs is important to enhancing wholesale electric competition through the
creation of standardized market rules, tariffs, and interconnection agreements. RTOs will put all suppliers on an equal footing and enhance access to non-discriminatory delivery services. Membership in an RTO and regionalization of electric markets
will provide opportunities for the Company to expand its business by providing generation services to more customers. While a new regional authority will make major operational decisions and operate the entire grid, the Company will continue to
ensure that the local systems operate reliably. In 2001, the Company focused on the new systems, business processes, regulatory filings and contractual relationships necessary to implement electric deregulation and regional transmission operations.
Wholesale Competition
The Company sells electricity in the wholesale market under its market-based sales tariff authorized by FERC but has agreed not to make wholesale power sales under this tariff to loads located within its service
territory. In January 2002, the Company filed for FERC approval of a tariff to sell wholesale power at capped rates based on the Company’s embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or
outside the Company’s service territory. Any such sales would be voluntary. The Company expects FERC to approve the tariff during the first quarter of 2002.
The Company’s sales of natural gas and oil in wholesale markets are not regulated by FERC.
Exposure to Potentially 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. At December 31, 2001, the Company’s exposure to potentially stranded costs consisted of long-term power
purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits
not yet recognized in the financial statements.
The Company believes capped electric retail rates and, where applicable, wire
charges provided under the Virginia Restructuring Act provide a reasonable opportunity to recover a substantial portion of its potentially stranded costs. Based on estimates at March 31, 1999, the Company would have otherwise been exposed, on a
pre-tax basis, to an estimated $3.2 billion of potential losses related to long-term power purchase commitments without the recoveries provided by capped rates. Recovery of the Company’s potentially stranded costs remains subject to numerous
risks even in the capped-rate environment including, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital
costs, and recovery of certain other items. See Notes 6, 8 and 19 to the Consolidated Financial Statements.
Rate
Matters—Virginia
The Company’s separation plan, as described in Separation of Generation and Delivery
Operations in Virginia, proposed an index-based fuel cost recovery mechanism based on forecasted generation by fuel types and projected fuel price indices, to be effective after January 1, 2002. The Company subsequently withdrew
the index-based fuel cost recovery mechanism and will continue to develop an alternative methodology. The Company’s current Virginia jurisdictional fuel factor will remain in effect until December 31, 2002. Proceedings to be initiated during
2002 will determine the fuel factor after that date.
29
The Company filed its Virginia Commission-approved unbundled rates reflecting the functional
separation of generation, transmission and distribution in January 2002. As previously discussed, the Company will phase in retail choice for all customers in its service territory by January 1, 2003. Where applicable, wires charges, effective
January 1, 2002 and subject to annual adjustment, will be paid by the Company’s Virginia jurisdictional retail customers who choose an alternative generation supplier during the capped rate period.
Rate Matters—North Carolina
The Company cannot request an increase in its North Carolina jurisdictional base rates until 2006, except for certain events that would have a significant financial impact. Fuel rates, however, are still subject to change under annual
proceedings.
Electric Retail Access Pilot Program
At December 31, 2001 approximately 24,000 customers are using a competitive energy supplier. Beginning January 1, 2002, all customers who have volunteered to participate in the pilot
program became eligible to participate in full retail access.
FERC Policy Developments
FERC’s most significant near-term policy initiative regarding interstate gas pipelines may also impact the Company’s interstate electric transmission operations. FERC proposes
to eliminate its existing, separate code of conduct regulations for natural gas pipelines and electric transmission utilities, and to replace these requirements with uniform standards applicable to interstate “Transmission Providers” both
of natural gas and of electricity. The proposed standards would redefine the scope of affiliates covered by the standards of conduct for most FERC-regulated companies. If the proposed policy is adopted, it will supersede the existing broad
standards.
The Company supports FERC’s policy goal to ensure a competitive interstate energy market. However, the Company
advocates certain adjustments to recognize the significant operational differences between gas pipelines and electric transmission companies. The Company anticipates further action by FERC by mid-2002. While the Company expects the outcome of a
final rule to improve its ability to compete with similarly-situated transmission providers, the Company does not expect the final rule have a short-term material impact on its results of operations, financial position or cash flows.
Environmental Matters
The Company is
subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations.
They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
Historically, the Company recovered such costs through utility rates. However, to the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission, during the period
ending June 30, 2007, in excess of the level currently included in the Virginia jurisdictional electric retail rates, the Company’s results of operations will decrease. After that date, recovery through regulated rates may be sought for only
those environmental costs related to regulated electric transmission and distribution operations.
Environmental Protection
and Monitoring Expenditures
The Company incurred approximately $109 million, $90 million, and $78 million of expenses
(including depreciation) during 2001, 2000, and 1999, respectively, in connection with environmental protection and monitoring activities, and expects these expenses to be approximately $113 million in 2002. In addition, capital expenditures related
to environmental controls were $197 million, $207 million, and $74 million for 2001, 2000, and 1999, respectively. The amount estimated for 2002 for these expenditures is $263 million.
30
Clean Air Act Compliance
The Clean Air Act requires the Company to reduce its emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX), which are gaseous by-products of fossil fuel combustion, and to
obtain operating permits for all major emissions-emitting facilities. Permit applications have been submitted for the Company’s affected facilities. 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 a third party. Evaluation and planning of future projects to comply with SO2 and
NOX limitations are ongoing and will be influenced by changes in the regulatory environment, availability of
SO2 allowances, various state and federal SO2 and NOX control programs, and emission control technology.
In response to NOx reduction requirements mandated by the Environmental Protection Agency (EPA) for states in which it
operates, the Company plans to install NOx reduction equipment at its affected facilities at an estimated capital cost of approximately $565 million over the next several years.
In the near future, the Bush Administration and the United States Congress may consider various “multi-pollutant” legislative proposals that would require fossil-fuel fired
generating units to comply with more stringent pollution control standards for NOX, SO2 and mercury. Many of the proposals would rely upon flexible cap and trade programs for compliance and would exempt covered facilities from other Clean Air
Act requirements. All of the proposals would phase-in the emission reduction requirements under a variety of timeframes, up to 16 years. The Company’s management cannot predict whether any of these proposals will pass this year or in the
future. However, if more stringent emissions standards are ultimately imposed on the Company’s generating units, new, perhaps significant, expenditures could be required.
During 2000, the Company received a Notice of Violation from the EPA alleging that it failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified
construction projects at the Mt. Storm Power Station in West Virginia. The Attorney General of New York filed a suit against the Company alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. The Company also received
notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. Management believes that the Company has obtained the necessary permits for its generating facilities. The Company has reached
an agreement in principle with the federal government and the state of New York to resolve this situation. The agreement in principle includes payment of a $5 million civil penalty, a commitment of $14 million for environmental projects in Virginia,
West Virginia, Connecticut, New Jersey and New York, and a 12-year, $1.2 billion capital investment program for environmental improvements at the Company's coal-fired generating stations in Virginia and West Virginia. The Company had already
committed to a substantial portion of the $1.2 billion expenditures for SO2 and NOX emissions controls. The negotiations over the terms of a binding settlement have expanded beyond the basic agreement in principle and are ongoing.
Global Climate Change
In 1997, the United States signed an international Protocol to limit man-made greenhouse emissions. However, the Protocol will not become binding unless approved by the United States Senate. Currently, the Bush
Administration has indicated that it will not pursue ratification of the Protocol but will work to establish new “voluntary” approaches to achieve reductions of greenhouse gas emissions. However, the United States Congress may consider
legislation that would implement mandatory reductions of greenhouse gas emissions. The cost of compliance with the Protocol or similar mandatory greenhouse gas reduction obligations could be significant. Given the uncertainties of future action by
the federal government on this issue, the Company cannot predict the likely future impact on its operations at this time.
Accounting Matters
Recently Issued Accounting Standards
In 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations, SFAS No. 142, Goodwill and
Other Intangible Assets,
31
SFAS No. 143, Accounting for Asset Retirement Obligations, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. See Note 4 to the
Consolidated Financial Statements for a discussion of the impact of adopting these new standards.
Restructuring
Charges
After completing the transition period for fully integrating CNG into Dominion’s existing organization and
operations, management initiated a focused review of Dominion’s combined operations in the fourth quarter of 2001. The objective of this review was to identify any activities or resources that were no longer necessary since the end of the
transition period. As a result, restructuring charges of $48 million were recognized in the fourth quarter of 2001 for items such as employee severance and other termination benefits and cancellation or modification of leases to eliminate office
space no longer needed. See Note 5 to the Consolidated Financial Statements. The Company’s 2001 and 2000 restructuring plans should reduce future annualized operating costs by approximately $9 million and $34 million, respectively, that would
otherwise have been incurred.
Business Opportunities and Other Operations
Nuclear Relicensing
The Company filed applications for
20-year life-extensions for the North Anna and Surry units in May 2001 with the Nuclear Regulatory Commission (NRC). The NRC has accepted and is reviewing the applications. Over the next two years, the NRC will perform site visits and review the
applications in detail.
Nuclear Insurance
The Price Anderson Act (Act) expires in August 2002, but operating nuclear reactors would continue to be covered by the law, which would channel and cap claims if a nuclear accident
should occur. The Act has been renewed three times since 1957, and Congress is currently holding hearings on reauthorizing the legislation.
Effect of Changes in Commodity Prices
The Company’s operations are impacted by
changes in energy commodity prices. To the extent that energy commodities are sold by the Company and such sales are subject to cost-of-service rate regulation, the commodity costs are generally recovered through rates. Market price changes impact
the Company’s revenues from commodity sales through unregulated subsidiaries. The Company has established an enterprise risk management function to reduce such price risk exposure.
Market Rate Sensitive Instruments and Risk Management
The Company’s
financial instruments, derivative financial instruments and derivative commodity contracts are exposed to potential losses due to adverse changes in interest rates, foreign currency exchange rates, commodity prices and equity security prices as
described below. Interest rate risk generally is related to the Company’s outstanding debt. The Company is exposed to foreign exchange risk associated with certain purchases denominated in foreign currencies. Commodity price risk is present in
the Company’s electric operations and energy marketing and trading operations due to the exposure to market shifts for prices received and paid for natural gas, electricity and other commodities. The Company uses derivative commodity contracts
to manage price risk exposures for these operations. The Company is exposed to equity price risk primarily as a result of equity securities held in nuclear decommissioning trusts.
The Company’s sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10
percent unfavorable change in interest rates, foreign exchange rates and commodity prices.
32
Commodity Price Risk—Trading Activities
As part of its strategy to market energy and to manage related risks, the Company manages a portfolio of derivative commodity contracts held for trading purposes. These contracts
are sensitive to changes in the prices of natural gas, electricity and certain other commodities. The Company uses established policies and procedures to manage the risks associated with these price fluctuations and uses various commodity
instruments, such as futures, forwards, swaps and options, to reduce risk by creating offsetting market positions. In addition, the Company seeks to use its generation capacity, when not needed to serve customers in its service territory, to satisfy
commitments to sell energy.
A hypothetical 10 percent unfavorable change in commodity prices would have resulted in a decrease
of approximately $7 million and $3 million in the fair value of its commodity contracts held for trading purposes as of December 31, 2001 and 2000, respectively.
Interest Rate Risk
The Company manages its interest rate risk exposure predominantly by
maintaining a balance of fixed and variable rate debt. The Company also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at December 31, 2001, a
hypothetical 10 percent increase in market interest rates would decrease annual earnings by approximately $2 million. A hypothetical 10 percent increase in market interest rates, as determined at December 31, 2000, would have resulted in a
decrease in annual earnings of approximately $9 million.
Foreign Exchange Risk
The Company manages its foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel related services denominated in
foreign currencies by utilizing currency forward contracts. For currency forwards outstanding at December 31, 2001, a hypothetical 10 percent unfavorable change in relevant foreign exchange rates would decrease annual earnings by approximately $5
million. A hypothetical 10 percent unfavorable change in relevant foreign exchange rates, as determined at December 31, 2000, would have resulted in a decrease in annual earnings of approximately $4 million.
Equity Price Risk
The
Company is subject to equity price risk due to marketable equity securities held as investments in the nuclear decommissioning trusts. These marketable equity securities are reported on the balance sheet at fair value. The following table presents
marketable equity securities held by the Company at December 31, 2001 and 2000.
| |
|
At December 31,
|
| |
|
2001
|
|
2000
|
| |
|
Cost
|
|
Fair Value
|
|
Cost
|
|
Fair Value
|
| |
|
(Millions) |
| Nuclear decommissioning trust investments |
|
$ |
318 |
|
$ |
516 |
|
$ |
279 |
|
$ |
549 |
Risk Management Policies
The Company has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has
established an independent function at the corporate level to monitor compliance with the price risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s
financial condition, collateral requirements, where deemed necessary, and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition
of existing counterparties on an ongoing basis.
33
Management believes, based on Dominion’s credit policies and the Company’s December
31, 2001 provision for credit losses, that it is unlikely that a material adverse effect on the Company’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
See
Cautionary Statements Regarding Forward-Looking Information and Market Rate Sensitive Instruments and Risk Management under Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| |
|
Page No.
|
| |
|
35 |
| |
| |
|
36 |
| |
| |
|
37 |
| |
| |
|
38 |
| |
| |
|
40 |
| |
| |
|
41 |
| |
| |
|
42 |
| |
| |
|
43 |
34
The Company’s management is responsible for all information and
representations contained in the Consolidated Financial Statements and other sections of the Company’s annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have
been prepared in conformity with generally accepted accounting principles. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.
Management maintains a system of internal accounting controls designed to provide reasonable assurance that the Company’s assets are safeguarded against loss from unauthorized use
or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control and, therefore, cannot provide absolute assurance
that the objectives of the established internal accounting controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of
qualified personnel and internal audits. In addition, management encourages a strong ethical climate through its Code of Ethics which is routinely communicated to all employees.
The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by the Board of Directors. Their audits were conducted
in accordance with auditing standards generally accepted in the United States of America and included a review of the Company’s accounting systems, procedures and internal controls to the extent necessary for the purpose of its report.
The Audit Committee of the Board of Directors of Dominion Resources, Inc., composed entirely of directors who are not officers
or employees of Dominion Resources, Inc. or its subsidiaries, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters of the Company and
to ensure that each is properly discharging its responsibilities. Both the independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.
VIRGINIA ELECTRIC AND POWER COMPANY
| /s/ G. SCOTT
HETZER G. Scott Hetzer Senior Vice President and Treasurer (Principal Financial Officer) |
|
/s/ STEVEN A. ROGERS Steven A. Rogers Vice President (Principal Accounting Officer) |
35
To the Board of Directors of
Virginia Electric and Power Company
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary
of Dominion Resources, Inc.) and subsidiaries (the Company) as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in
the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of
Virginia Electric and Power Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 9 to the consolidated financial statements,
effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended. Also, as discussed in Note 3 to the consolidated financial
statements, the Company changed its method of accounting used to develop the market-related value of pension plan assets in 2000.
/s/ DELOITTE & TOUCHE LLP
Richmond,
Virginia
January 22, 2002
36
VIRGINIA ELECTRIC AND POWER COMPANY
| |
|
Year Ended December 31,
|
|
| |
|
2001
|
|
2000
|
|
1999
|
|
| |
|
(Millions) |
|
| Operating Revenue |
|
|
|
|
|
|
|
|
|
|
| Regulated electric sales |
|
$ |
4,620 |
|
$ |
4,492 |
|
$ |
4,227 |
|
| Other |
|
|
324 |
|
|
299 |
|
|
364 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Total operating revenue |
|
|
4,944 |
|
|
4,791 |
|
|
4,591 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Operating Expenses |
|
|
|
|
|
|
|
|
|
|
| Electric fuel and energy purchases, net |
|
|
1,252 |
|
|
1,104 |
|
|
986 |
|
| Purchased electric capacity |
|
|
680 |
|
|
740 |
|
|
809 |
|
| Restructuring costs |
|
|
48 |
|
|
71 |
|
|
— |
|
| Other operations and maintenance |
|
|
1,268 |
|
|
957 |
|
|
959 |
|
| Depreciation and amortization |
|
|
518 |
|
|
558 |
|
|
548 |
|
| Other taxes |
|
|
179 |
|
|
275 |
|
|
282 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Total operating expenses |
|
|
3,945 |
|
|
3,705 |
|
|
3,584 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Income from operations |
|
|
999 |
|
|
1,086 |
|
|
1,007 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Other income |
|
|
33 |
|
|
47 |
|
|
25 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Interest and related charges: |
|
|
|
|
|
|
|
|
|
|
| Interest expense |
|
|
289 |
|
|
285 |
|
|
278 |
|
| Distributions—preferred securities of subsidiary trust |
|
|
11 |
|
|
11 |
|
|
11 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Total interest and related charges |
|
|
300 |
|
|
296 |
|
|
289 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Income before income taxes |
|
|
732 |
|
|
837 |
|
|
743 |
|
| Income taxes |
|
|
286 |
|
|
279 |
|
|
258 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Income before extraordinary item and cumulative effect of a change in accounting principle |
|
|
446 |
|
|
558 |
|
|
485 |
|
| Extraordinary item (net of income taxes of $197) |
|
|
— |
|
|
— |
|
|
(255 |
) |
| Cumulative effect of a change in accounting principle (net of income taxes of $11) |
|
|
— |
|
|
21 |
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
| Net income |
|
|
446 |
|
|
579 |
|
|
230 |
|
| Preferred dividends |
|
|
23 |
|
|
36 |
|
|
37 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Balance available for common stock |
|
$ |
423 |
|
$ |
543 |
|
$ |
193 |
|
| |
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the Consolidated Financial Statements.
37
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS
| |
|
At December 31,
|
| |
|
2001
|
|
2000
|
| |
|
(Millions) |
| A S S E T S |
|
|
|
|
|
|
| Current Assets |
|
|
|
|
|
|
| Cash and cash equivalents |
|
$ |
84 |
|
$ |
141 |
| Accounts receivable: |
|
|
|
|
|
|
| Customers (less allowance for doubtful accounts of $23 in 2001 and $16 in 2000) |
|
|
1,105 |
|
|
1,134 |
| Other |
|
|
57 |
|
|
82 |
| Receivables from affiliates |
|
|
54 |
|
|
30 |
| Inventories (average cost method): |
|
|
|
|
|
|
| Materials and supplies |
|
|
163 |
|
|
129 |
| Fossil fuel |
|
|
149 |
|
|
83 |
| Gas stored |
|
|
59 |
|
|
19 |
| Derivative and energy trading assets |
|
|
1,039 |
|
|
1,047 |
| Prepayments |
|
|
140 |
|
|
104 |
| Other |
|
|
71 |
|
|
60 |
| |
|
|
|
|
|
|
| Total current assets |
|
|
2,921 |
|
|
2,829 |
| |
|
|
|
|
|
|
| Investments |
|
|
|
|
|
|
| Nuclear decommissioning trust funds |
|
|
858 |
|
|
851 |
| Other |
|
|
25 |
|
|
63 |
| |
|
|
|
|
|
|
| Total investments |
|
|
883 |
|
|
914 |
| |
|
|
|
|
|
|
| Property, Plant and Equipment |
|
|
|
|
|
|
| Property, plant and equipment |
|
|
16,661 |
|
|
16,190 |
| Less accumulated depreciation and amortization |
|
|
7,455 |
|
|
7,165 |
| |
|
|
|
|
|
|
| |
|
|
9,206 |
|
|
9,025 |
| Nuclear fuel, net |
|
|
154 |
|
|
140 |
| |
|
|
|
|
|
|
| Property, plant and equipment, net |
|
|
9,360 |
|
|
9,165 |
| |
|
|
|
|
|
|
| Deferred Charges and Other Assets |
|
|
|
|
|
|
| Regulatory assets, net |
|
|
231 |
|
|
235 |
| Derivative and energy trading assets |
|
|
323 |
|
|
79 |
| Other |
|
|
66 |
|
|
109 |
| |
|
|
|
|
|
|
| Total deferred charges and other assets |
|
|
620 |
|
|
423 |
| |
|
|
|
|
|
|
| Total assets |
|
$ |
13,784 |
|
$ |
13,331 |
| |
|
|
|
|
|
|
The accompanying notes are an integral part of the Consolidated Financial Statements.
38
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS (Continued)
| |
|
At December 31,
|
| |
|
2001
|
|
|
2000
|
| |
|
(Millions) |
| L I A B I L I T I E S A N D
S H A R E H O L D E R ’ S E Q U I T Y |
|
|
|
|
|
|
|
| |
| Current Liabilities |
|
|
|
|
|
|
|
| Securities due within one year |
|
$ |
535 |
|
|
$ |
241 |
| Short-term debt |
|
|
436 |
|
|
|
714 |
| Accounts payable, trade |
|
|
1,014 |
|
|
|
882 |
| Payables to affiliates |
|
|
192 |
|
|
|
122 |
| Customer deposits |
|
|
63 |
|
|
|
55 |
| Accrued interest |
|
|
99 |
|
|
|
94 |
| Accrued payroll |
|
|
83 |
|
|
|
88 |
| Accrued taxes |
|
|
32 |
|
|
|
60 |
| Derivative and energy trading liabilities |
|
|
1,010 |
|
|
|
994 |
| Other |
|
|
155 |
|
|
|
100 |
| |
|
|
|
|
|
|
|
| Total current liabilities |
|
|
3,619 |
|
|
|
3,350 |
| |
|
|
|
|
|
|
|
| Long-Term Debt |
|
|
3,704 |
|
|
|
3,561 |
| |
|
|
|
|
|
|
|
| Deferred Credits And Other Liabilities |
|
|
|
|
|
|
|
| Deferred income taxes |
|
|
1,537 |
|
|
|
1,494 |
| Deferred investment tax credits |
|
|
113 |
|
|
|
130 |
| Derivative and energy trading liabilities |
|
|
246 |
|
|
|
87 |
| Other |
|
|
170 |
|
|
|
216 |
| |
|
|
|
|
|
|
|
| Total deferred credits and other liabilities |
|
|
2,066 |
|
|
|
1,927 |
| |
|
|
|
|
|
|
|
| Total liabilities |
|
|
9,389 |
|
|
|
8,838 |
| |
|
|
|
|
|
|
|
| Commitments And Contingencies (See Note 19) |
|
|
|
|
|
|
|
| |
| Obligated Mandatorily Redeemable Preferred Securities Of Subsidiary Trust (1) |
|
|
135 |
|
|
|
135 |
| |
|
|
|
|
|
|
|
| Preferred Stock |
|
|
|
|
|
|
|
| Preferred stock not subject to mandatory redemption |
|
|
384 |
|
|
|
509 |
| |
|
|
|
|
|
|
|
| Common Shareholder’s Equity |
|
|
|
|
|
|
|
| Common stock, no par, 300.0 shares authorized, 171.5 shares outstanding |
|
|
2,738 |
|
|
|
2,738 |
| Other paid-in capital |
|
|
14 |
|
|
|
16 |
| Accumulated other comprehensive loss |
|
|
(4 |
) |
|
|
— |
| Retained earnings |
|
|
1,128 |
|
|
|
1,095 |
| |
|
|
|
|
|
|
|
| Total common shareholder’s equity |
|
|
3,876 |
|
|
|
3,849 |
| |
|
|
|
|
|
|
|
| Total liabilities and shareholder’s equity |
|
$ |
13,784 |
|
|
$ |
13,331 |
| |
|
|
|
|
|
|
|
(1) |
|
As described in Note 15 to Consolidated Financial Statements, the 8.05% Junior Subordinated Notes totaling $139 million principal amount constitute 100 percent
of the Trust’s assets. |
The accompanying notes are an integral part of the Consolidated Financial Statements.
39
VIRGINIA ELECTRIC AND POWER COMPANY
| |
|
Common Stock
|
|
Other Paid-In Capital
|
|
|
Accumulated Other Comprehensive Loss
|
|
|
Retained Earnings
|
|
|
Total
|
|
| |
|
Shares
|
|
Amount
|
|
|
|
|
| |
|
(Millions) |
|
| Balance at January 1, 1999 |
|
171.5 |
|
$ |
2,738 |
|
$ |
17 |
|
|
|
|
|
|
$ |
1,178 |
|
|
$ |
3,933 |
|
| Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
230 |
|
|
|
230 |
|
| Dividends and other adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(420 |
) |
|
|
(420 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at December 31,1999 |
|
171.5 |
|
|
2,738 |
|
|
17 |
|
|
|
|
|
|
|
988 |
|
|
|
3,743 |
|
| |
| Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
579 |
|
|
|
579 |
|
| Dividends and other adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(444 |
) |
|
|
(444 |
) |
| Other |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(28 |
) |
|
|
(29 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at December 31, 2000 |
|
171.5 |
|
|
2,738 |
|
|
16 |
|
|
|
|
|
|
|
1,095 |
|
|
|
3,849 |
|
| |
| Comprehensive income |
|
|
|
|
|
|
|
|
|
|
$ |
(4 |
) |
|
|
446 |
|
|
|
442 |
|
| Dividends and other adjustments |
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
(413 |
) |
|
|
(415 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance at December 31, 2001 |
|
171.5 |
|
$ |
2,738 |
|
$ |
14 |
|
|
$ |
(4 |
) |
|
$ |
1,128 |
|
|
$ |
3,876 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the
Consolidated Financial Statements.
40
VIRGINIA ELECTRIC AND POWER COMPANY
| |
|
Year Ended December 31, 2001
|
|
| |
|
Before-Tax Amount
|
|
|
Deferred Tax Benefit (Expense)
|
|
|
After Tax Amount
|
|
| |
|
(millions) |
|
| Net income |
|
|
|
|
|
|
|
|
|
$ |
446 |
|
| Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
| Net deferred gains on derivatives—hedging activities |
|
$ |
(2 |
) |
|
$ |
1 |
|
|
|
(1 |
) |
| Cumulative effect of change in accounting principle |
|
|
(23 |
) |
|
|
9 |
|
|
|
(14 |
) |
| |
| Amounts reclassified to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
| Net losses on derivatives–hedging activities |
|
|
18 |
|
|
|
(7 |
) |
|
|
11 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Other comprehensive loss |
|
$ |
(7 |
) |
|
$ |
3 |
|
|
|
(4 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Comprehensive income |
|
|
|
|
|
|
|
|
|
$ |
442 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
The Company’s net income was $579 and $230 for 2000 and 1999, respectively.
The Company had no other comprehensive income reportable for those years in accordance with SFAS No. 130, Reporting Comprehensive Income.
The accompanying notes are an integral part of the Consolidated Financial Statements.
41
VIRGINIA ELECTRIC AND POWER COMPANY
| |
|
For The Years Ended December 31,
|
|
| |
|
2001
|
|
|
2000
|
|
|
1999
|
|
| |
|
(Millions) |
|
| Cash Flows From (Used In) Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
| Net income |
|
$ |
446 |
|
|
$ |
579 |
|
|
$ |
230 |
|
| Adjustments to reconcile net income to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Cumulative effect of a change in accounting principle, net of income taxes |
|
|
|
|
|
|
(21 |
) |
|
|
|
|
| Extraordinary item, net of income taxes |
|
|
|
|
|
|
|
|
|
|
255 |
|
| Depreciation and amortization |
|
|
588 |
|
|
|
637 |
|
|
|
629 |
|
| Deferred income taxes |
|
|
68 |
|
|
|
27 |
|
|
|
38 |
|
| Deferred investment tax credits |
|
|
(17 |
) |
|
|
(17 |
) |
|
|
(17 |
) |
| Deferred fuel expenses, net |
|
|
(24 |
) |
|
|
(33 |
) |
|
|
(35 |
) |
| Changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Accounts receivable |
|
|
54 |
|
|
|
(496 |
) |
|
|
124 |
|
| Affiliated accounts receivables and payables |
|
|
46 |
|
|
|
94 |
|
|
|
(1 |
) |
| Inventories |
|
|
(140 |
) |
|
|
4 |
|
|
|
2 |
|
| Prepayments |
|
|
(36 |
) |
|
|
(48 |
) |
|
|
4 |
|
| Accounts payable, trade |
|
|
132 |
|
|
|
365 |
|
|
|
(32 |
) |
| Accrued interest and taxes |
|
|
(23 |
) |
|
|
5 |
|
|
|
7 |
|
| Derivative and energy trading assets and liabilities (including affiliates) |
|
|
(60 |
) |
|
|
(33 |
) |
|
|
(92 |
) |
| Other |
|
|
58 |
|
|
|
42 |
|
|
|
(4 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Net Cash Flows From Operating Activities |
|
|
1,092 |
|
|
|
1,105 |
|
|
|
1,108 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash Flows From (Used In) Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
| Plant construction and other property additions |
|
|
(668 |
) |
|
|
(652 |
) |
|
|
(673 |
) |
| Nuclear fuel |
|
|
(83 |
) |
|
|
(82 |
) |
|
|
(64 |
) |
| Nuclear decommissioning contributions |
|
|
(36 |
) |
|
|
(36 |
) |
|
|
(35 |
) |
| Other |
|
|
54 |
|
|
|
— |
|
|
|
(3 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Net Cash Flows Used in Investing Activities |
|
|
(733 |
) |
|
|
(770 |
) |
|
|
(775 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash Flows From (Used In) Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
| Issuance (repayment) of short-term debt, net |
|
|
(278 |
) |
|
|
336 |
|
|
|
156 |
|
| Issuance of long-term debt |
|
|
770 |
|
|
|
250 |
|
|
|
305 |
|
| Repayment of long-term debt, preferred stock and capital lease obligations |
|
|
(473 |
) |
|
|
(376 |
) |
|
|
(345 |
) |
| Common stock dividend payments |
|
|
(392 |
) |
|
|
(408 |
) |
|
|
(383 |
) |
| Preferred stock dividend payments |
|
|
(25 |
) |
|
|
(36 |
) |
|
|
(37 |
) |
| Distribution-preferred securities of subsidiary trust |
|
|
(11 |
) |
|
|
(11 |
) |
|
|
(11 |
) |
| Other |
|
|
(7 |
) |
|
|
(11 |
) |
|
|
(5 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Net Cash Flows Used in Financing Activities |
|
|
(416 |
) |
|
|
(256 |
) |
|
|
(320 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Increase (decrease) in cash and cash equivalents |
|
|
(57 |
) |
|
|
79 |
|
|
|
13 |
|
| Cash and cash equivalents at beginning of year |
|
|
141 |
|
|
|
62 |
|
|
|
49 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash and cash equivalents at end of year |
|
$ |
84 |
|
|
$ |
141 |
|
|
$ |
62 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash paid for: |
|
|
|
|
|
|
|
|
|
|
|
|
| Interest, excluding amounts capitalized |
|
$ |
287 |
|
|
$ |
291 |
|
|
$ |
278 |
|
| Income taxes |
|
|
145 |
|
|
|
331 |
|
|
|
232 |
|
| Non-cash transactions from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Conveyance of telecommunications subsidiary to parent, net of cash |
|
|
|
|
|
|
19 |
|
|
|
|
|
The accompanying notes are an integral part of the Consolidated Financial Statements.
42
VIRGINIA ELECTRIC AND POWER COMPANY
Note 1. Nature of Operations
Virginia Electric and Power Company (Virginia Power or the Company), a Virginia public service company, is a wholly-owned subsidiary of
Dominion Resources, Inc. (Dominion). The Company is a regulated public utility that generates, transmits, and distributes electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to
approximately 2.1 million retail customers, including governmental agencies, and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65% of
Virginia’s total land area, but accounts for over 80% of its population. The Company has trading relationships beyond the geographic limits of its retail service territory and buys and sells wholesale electricity and natural gas off-system.
Within this document, the term “Company” refers to the entirety of Virginia Electric and Power Company, including its Virginia and North Carolina operations, and all of its subsidiaries.
The Company manages its daily operations along two operating segments, Energy and Delivery. The Energy segment encompasses the Company’s portfolio
of generating facilities and power purchase contracts and its trading and marketing activities. The Delivery segment includes bulk power transmission, distribution and metering services and customer service. The Delivery segment continues to be
subject to the requirements of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Note 2. Significant Accounting Policies
General
The Company includes certain estimates and assumptions in preparing consolidated financial statements in accordance with generally accepted accounting
principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses for the
periods presented. Actual results may differ from those estimates.
The consolidated financial statements represent the
Company’s accounts after the elimination of intercompany transactions.
Certain amounts in the 2000 and 1999 consolidated
financial statements have been reclassified to conform to the 2001 presentation.
Use of Fair Value Measurements
The Company reports certain contracts and instruments at fair value in accordance with applicable generally accepted accounting principles. Fair value
is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information
from external sources is not available, the Company must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis. For options and contracts with option-like
characteristics where pricing information is not available from external sources, the Company uses a modified Black-Scholes model and considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating
fair value. For contracts with unique characteristics, the Company estimates fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not
available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value.
43
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Concentration of Credit Risk
The Company sells electricity and provides distribution and transmission services to a diverse group of customers,
including residential, commercial and industrial customers as well as rural electric cooperatives and municipalities. In addition, the Company enters into contracts with various companies in the energy industry for purchases and sales of
energy-related commodities, including natural gas, electricity in its energy trading, hedging and arbitrage activities. These transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. Although this
concentration could affect the Company’s overall exposure to credit risk, management believes that the Company is exposed to minimal risk. A significant portion of the Company’s energy trading, hedging and arbitrage business is conducted
with major companies in the energy industry. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Dominion and its subsidiaries, including the Company, maintain credit policies
with respect to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements, where deemed necessary, and in the case
of energy trading, hedging and arbitrage activities, the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. Dominion, on behalf of the Company and its subsidiaries, also monitors the
financial condition of existing counterparties on an ongoing basis. The Company maintains a provision for credit losses based upon factors surrounding the credit risk of its customers, historical trends and other information. Management believes,
based on Dominion’s credit policies and the Company’s December 31, 2001 provision for credit losses, that it is unlikely that a material adverse effect on the Company’s financial position, results of operations or cash flows would
occur as a result of counterparty nonperformance.
Derivatives
The Company uses derivatives such as forwards, futures, swaps, and options to manage the commodity, currency exchange and financial market risks of its business operations. The Company
also manages a portfolio of commodity contracts held for trading purposes as part of its strategy to market energy and to manage related risks. Effective January 1, 2001, upon adoption of SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, derivatives are generally recognized on the Consolidated Balance Sheets at fair value. See Note 9 for further discussion of the Company’s use of derivatives and energy trading contracts, including its risk management
policy, its accounting policy for derivatives under SFAS No. 133, and the results of its hedging activities for the year ended December 31, 2001.
Prior to January 1, 2001, the Company considered derivative instruments to be effective hedges when the item being hedged and the underlying financial or commodity instrument showed strong historical correlation. The
Company used deferral accounting to account for futures, forwards and other derivative instruments that were designated as hedges. Under this method, realized gains and losses (including the payment of any premium) related to effective hedges of
existing assets and liabilities were 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 were included in the
measurement of the subsequent transaction.
Operating Revenue
Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Regulated electric sales
consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services.
Other revenue includes revenue from energy trading activities, sales of electricity and natural gas at market-based rates, brokered gas sales, service fees associated with rate-regulated electric distribution and
other miscellaneous revenue. Revenue from energy trading activities includes realized contract settlements, net of
44
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
related cost of sales, and unrealized gains and losses resulting from marking to market those commodity contracts not yet settled.
Electric Fuel and Energy Purchases—Deferred Costs
Where permitted by
regulatory authorities, the differences between actual electric fuel and purchased energy and the levels of recovery of such expenses in current rates are deferred and matched against recoveries in future rates. Approximately 94 percent of rate
regulated fuel costs are subject to deferral accounting. See Regulatory Assets and Liabilities below and Note 10.
Property, Plant and
Equipment
Property, plant and equipment, including additions and replacements, is recorded at original cost
including labor, materials, other direct costs and capitalized interest. The costs of repairs and maintenance including minor additions and replacements, are charged to expense as incurred. In 2001, 2000, and 1999, the Company capitalized interest
costs of $20 million, $18 million and $13 million, respectively.
The cost of electric transmission and distribution property
retired and related cost of removal, less salvage, are charged to accumulated depreciation. For generation-related property, cost of removal is charged to expense as incurred. The Company records gains and losses upon retirement of
generation-related property based upon the difference between proceeds received, if any, and the property’s undepreciated basis at the retirement date.
Depreciation of property, plant, and equipment is computed on the straight-line method based on projected useful service lives. Estimated useful lives of the Company’s property, plant and equipment are as
follows: generation 20-60 years, transmission 34 years, distribution 27 years and other 5-25 years. Amortization of nuclear fuel used in electric generation is provided on a unit-of-production basis sufficient to fully amortize, over the estimated
service life, the cost of the fuel plus permanent storage and disposal costs. In 2001, the Company increased its estimate of the useful lives of its nuclear facilities by 20 years. This change in estimate was made in connection with the filing of
applications for re-licensing with the Nuclear Regulatory Commission (NRC).
Income Taxes
The Company files a consolidated federal income tax return and participates in an intercompany tax allocation agreement with Dominion and its
subsidiaries. The Company’s current income taxes are based on its taxable income, determined on a separate company basis. However, under the Public Utility Holding Company Act of 1935 (1935 Act), the Company’s cash payments to Dominion
under the intercompany tax allocation agreement are reduced for any income tax benefits realized by Dominion, the holding company. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of
SFAS No. 109, Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. Deferred investment tax credits are being
amortized over the service lives of the property giving rise to such credits.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2001 and 2000, the
Company’s accounts payable included the net effect of checks outstanding but not yet presented for payment of $100 million and $78 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and
cash equivalents to include cash on hand, cash in banks and temporary investments purchased with an initial maturity of three months or less.
45
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Impairment of Long-Lived
Assets
The Company performs an evaluation for impairment whenever events or changes in circumstances indicate that
the carrying amount of long-lived assets or intangible assets may not be recoverable. Long-lived assets are written down to fair value if the sum of the expected future undiscounted cash flows is less than the carrying amount.
Regulatory Assets and Liabilities
Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. The economic effects of allocations
prescribed by regulatory authorities for rate-making purposes must be considered in the application of generally accepted accounting principles. See Notes 6 and 10 for the impact of legislation on continued application of SFAS No. 71, and additional
information on regulatory assets and liabilities.
Amortization of Debt Issuance Costs
The Company defers and amortizes debt issuance costs and debt premiums or discounts over the lives of the respective debt issues. As permitted by
regulatory commissions, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based regulation have also been deferred and amortized over the lives of the new issues.
Note 3. Accounting Change for Pension Costs
Effective January 1, 2000 and in connection with Dominion’s acquisition of the Consolidated Natural Gas Company (CNG), Dominion and its subsidiaries, including the Company, adopted a new company-wide method of
calculating the market-related value of pension plan assets used to determine the expected return on pension plan assets, a component of net periodic pension cost. Management believes the new method enhances the predictability of the expected return
on pension plan assets; provides consistent treatment of all investment gains and losses; and results in calculated market-related pension plan asset values that are closer to market value as compared to values calculated under the pre-acquisition
methods used by Dominion and CNG.
As the primary participating employer in the Dominion Resources Retirement Plan, the Company
recorded in 2000 its proportionate share of the cumulative effect of the change in accounting principle, $21 million (net of income taxes of $11 million). Other than the impact of the cumulative effect of the change in accounting principle, the
effect of the change on net income for 2000 was not material.
Retroactive application of the new method, on a pro forma basis,
would not have materially changed the Company’s net income for 1999.
Note 4. Recently Issued Accounting
Standards
Business Combinations and Goodwill
In 2001, the Financial Accounting Standards Board (FASB) issued SFAS Nos. 141, Business Combinations, and 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires
that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 141 also includes guidance on the
46
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
initial recognition and measurement of goodwill and other intangible assets arising from business combinations initiated after June 30, 2001. SFAS No. 142 prohibits the amortization of goodwill
and intangible assets with indefinite useful lives. SFAS No. 142 requires that these assets be reviewed for impairment at least annually. Intangible assets with finite lives will continue to be amortized over their estimated useful lives.
The Company will adopt this standard effective January 1, 2002. At December 31, 2001, the Company had no material goodwill or
other intangible assets obtained in business combinations.
Asset Retirement Obligations
In 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition
and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived
assets. Accretion of the liabilities due to the passage of time will be an operating expense. The Company will adopt this standard effective January 1, 2003.
The Company has identified retirement obligations associated with the decommissioning of its nuclear generation facilities. However, the Company has not yet performed a complete assessment of possible retirement
obligations associated with its other electric utility property. The Company has not yet determined the financial impact of adopting this new standard.
Also, under the new standard, the realized and unrealized earnings of external trusts available for funding decommissioning activities at the Company’s nuclear power plants will be recorded in other income and
other comprehensive income, as appropriate. Currently, the Company records these trusts’ earnings in other income with an offsetting charge to expense, also recorded in other income, associated with the accretion of the decommissioning
liability. See Note 8. Upon adoption of the new standard, the Company will discontinue its practice of accruing, as part of depreciation expense, amounts associated with the future costs of removal of its utility plant. However, the Company may
continue its practice of accruing for such costs subject to cost of service rate regulation even when an asset removal obligation does not exist but would do so through the recognition of regulatory assets and liabilities, as appropriate.
Impairment or Disposal of Long-Lived Assets
In 2001, FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which provides guidance that will eliminate inconsistencies in accounting for
the impairment or disposal of long-lived assets under existing accounting pronouncements. The Company will apply the provisions of this standard prospectively beginning January 1, 2002 and does not expect the adoption to have a material impact on
its results of operations or financial condition.
Note 5. Restructuring Costs
2001 Restructuring Costs
In the fourth quarter
of 2001, after completing the transition period for fully integrating Dominion’s existing organization and operations, management initiated a focused review of Dominion’s combined operations. The objective of this review was to identify
any activities or resources which were no longer necessary now that the post-CNG acquisition transition period ended. As a result, the Company recognized $48 million of restructuring costs which include employee severance and termination benefits,
and abandonment of leased office space no longer needed.
47
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The Company recorded
$42 million in total severance and related costs, including $26 million billed to the Company by Dominion Resources Services, Inc. (Dominion Services). Under the restructuring plan, the Company identified approximately 124 positions to be eliminated
and recorded $16 million in employee severance-related costs. Employee terminations are expected to begin early in the first quarter of 2002. Severance payments were based on the individual’s base salary and years of service at the time of
termination.
Restructuring and related costs for the year ended December 31, 2001 were as follows:
| |
|
2001
|
| |
|
(Millions) |
| Severance and related costs |
|
$ |
16 |
| Severance and related costs—Dominion Services(1) |
|
|
26 |
| Other, net(2) |
|
|
6 |
| |
|
|
|
| Total restructuring costs |
|
$ |
48 |
| |
|
|
|
| Ending severance liability at December 31, 2001 |
|
$ |
16 |
| |
|
|
|
(1) |
|
Dominion Services, a subsidiary service company under the 1935 Act, provides certain services to Dominion’s operating subsidiaries. Accordingly, charges are allocated and
billed among the operating subsidiaries in accordance with predefined service agreements. See Note 21. |
(2) |
|
Includes charges for abandonment of leased office space and related costs by the Company and Dominion Services. |
2000 Restructuring Costs
In 2000, following the
acquisition of CNG by Dominion, Dominion and its subsidiaries implemented a plan to restructure the operations of the combined companies. The restructuring plan included an involuntary severance program, a voluntary early retirement program (ERP)
and a transition plan to implement operational changes to provide efficiencies, including the consolidation of post-merger operations and the integration of information technology systems. Through December 31, 2001, a total of 174 positions had been
eliminated, and approximately $13 million of severance benefits had been paid. In addition, during 2001, the Company adjusted the severance liability by approximately $1 million, reflecting a revision in severance benefits payable for differences
between the estimates used in the plan and the actual base salaries and years of service for those employees terminated under the plan. During 2000, approximately 400 employees elected to participate in the ERP, resulting in an expense approximating
$51 million. Some of the ERP participants also received benefits under the involuntary severance package; benefits under the involuntary severance package were subject to reduction as a result of coordination with the additional retirement plan
benefits provided by the ERP.
For the year ended December 31, 2000, the Company recorded $71 million for charges in connection
with the 2000 restructuring plan, as follows:
| |
• |
|
$14 million under an involuntary severance program (discussed above), |
| |
• |
|
$51 million under the ERP (see Note 18) and |
| |
• |
|
$6 million of other costs related to consolidation and integration of business operations and administrative functions. |
As of December 31, 2001, less than $1 million of severance and related benefit costs accrued under the 2000 restructuring plan had not been paid.
48
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note
6. Extraordinary Item
Discontinuance of SFAS No. 71
In 1999, legislation was passed that established 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 the Company’s generation operations in 1999. The Company’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, the cost of fuel used in electric generation continues to be subject to deferral accounting.
In order to measure the amount of regulatory assets to be written off upon discontinuance of SFAS No. 71, the Company evaluated the estimated recovery of regulatory assets through its Virginia jurisdictional rates during the transition
period ending July 2007. Generation-related assets and liabilities that will not be recovered through the transition period rates were written off in 1999, resulting in an after-tax charge to earnings of $255 million. See Note 10 for discussion of
net regulatory assets at December 31, 2001. The $255 million charge also included the write-off of approximately $38 million, after-tax, of deferred investment tax credits and approximately $18 million, after-tax, of other generation-related
assets. A corresponding regulatory asset of $23 million was established representing the amount expected to be recovered during the transition period related to these assets.
The events that caused the discontinuance of SFAS No. 71 for generation-related operations also required a review of generation assets for impairment. This review was based on estimates
of possible future market prices, load growth, competition and many other assumptions. It also included the effects of nuclear decommissioning and other currently identified environmental expenditures. Based on those analyses, no plant write-downs
were appropriate at that time.
The Company also reviewed its long-term power purchase contracts for potential loss in
accordance with SFAS No. 5, Accounting for Contingencies, and Accounting Research Bulletin No. 43, Chapter 4, Inventory Pricing. Based on projections of possible future market prices for wholesale electricity as of March 31, 1999, the
results of the analyses indicated no loss recognition was appropriate at that time. Other projections of possible future market prices indicated a possible loss of $500 million. In the absence of the transition period rates provided by the
legislation, the potential loss exposure would have been approximately $3.2 billion at March 31, 1999.
Significant estimates
were required in recording the effect of the deregulation legislation, including the resulting impact on the fair value determination of generating facilities and estimated purchases under long-term power purchase contracts. Such projections were
highly dependent on future customer load projections, generating unit availability, the timing and type of future capacity additions in the Company’s market area and future market prices for fuel and electricity.
49
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 7. Income
Taxes
Details of income tax expense are as follows:
| |
|
Year ended December 31,
|
|
| |
|
2001
|
|
|
2000
|
|
|
1999
|
|
| |
|
(Millions) |
|
| Current expense: |
|
|
|
|
|
|
|
|
|
|
|
|
| Federal |
|
$ |
198 |
|
|
$ |
262 |
|
|
$ |
224 |
|
| State |
|
|
37 |
|
|
|
7 |
|
|
|
13 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Total current |
|
|
235 |
|
|
|
269 |
|
|
|
237 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Deferred expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
| Federal |
|
|
50 |
|
|
|
32 |
|
|
|
36 |
|
| State |
|
|
18 |
|
|
|
(5 |
) |
|
|
2 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Total deferred |
|
|
68 |
|
|
|
27 |
|
|
|
38 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Amortization of deferred investment tax credits-net |
|
|
(17 |
) |
|
|
(17 |
) |
|
|
(17 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Total income tax expense |
|
$ |
286 |
|
|
$ |
279 |
|
|
$ |
258 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Total statutory U.S. federal income rate reconciles to the effective income tax
rates as follows:
| |
|
Year Ended December 31,
|
|
| |
|
2001
|
|
|
2000
|
|
|
1999
|
|
| U.S statutory rate |
|
35.0 |
% |
|
35.0 |
% |
|
35.0 |
% |
| Increases (reductions) resulting from: |
|
|
|
|
|
|
|
|
|
| Utility plant differences |
|
.7 |
|
|
.4 |
|
|
.4 |
|
| Amortization of investment tax credits |
|
(1.8 |
) |
|
(1.4 |
) |
|
(2.0 |
) |
| State income tax, net of federal tax benefit |
|
4.9 |
|
|
.2 |
|
|
1.4 |
|
| Other, net |
|
.3 |
|
|
(.9 |
) |
|
(.1 |
) |
| |
|
|
|
|
|
|
|
|
|
| Effective tax rate |
|
39.1 |
% |
|
33.3 |
% |
|
34.7 |
% |
| |
|
|
|
|
|
|
|
|
|
The Company’s effective income tax rate increased in 2001 due to its utility
operations in Virginia becoming subject to state income taxes in lieu of gross receipts taxes.
50
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The Company’s
net accumulated deferred income taxes consist of the following:
| |
|
At December 31,
|
| |
|
2001
|
|
2000
|
| |
|
(Millions) |
| Deferred income tax assets: |
|
|
|
|
|
|
| Deferred investment tax credits |
|
$ |
43 |
|
$ |
50 |
| Other |
|
|
37 |
|
|
54 |
| |
|
|
|
|
|
|
| Total deferred income tax assets |
|
|
80 |
|
|
104 |
| |
|
|
|
|
|
|
| Deferred income tax liabilities: |
|
|
|
|
|
|
| Depreciation method and plant basis differences |
|
|
1,506 |
|
|
1,502 |
| Income taxes recoverable through future rates |
|
|
19 |
|
|
18 |
| Other |
|
|
55 |
|
|
24 |
| |
|
|
|
|
|
|
| Total deferred income tax liabilities |
|
|
1,580 |
|
|
1,544 |
| |
|
|
|
|
|
|
| Total net deferred income tax liabilities(1) |
|
$ |
1,500 |
|
$ |
1,440 |
| |
|
|
|
|
|
|
(1) |
|
For 2001 and 2000, includes $37 million and $54 million, respectively of current deferred tax assets reported in other current assets. |
Note 8. Nuclear Operations
The Company has four licensed nuclear reactors at its Surry and North Anna plants in Virginia that serve native load in its regulated electric utility operations. Decommissioning represents the decontamination and
removal of radioactive contaminants from a nuclear power plant, once operations have ceased, in accordance with standards established by the Nuclear Regulatory Commission (NRC). Through July 2007, amounts are being collected from ratepayers and
placed in external trusts and invested to fund the expected costs of decommissioning the Surry and North Anna units.
Accounting for Decommissioning
In accordance with the accounting policy recognized by regulatory authorities having jurisdiction over its electric utility
operations, the Company recognizes an expense for the future cost of decommissioning in amounts equal to amounts collected from ratepayers and earnings on trust investments dedicated to funding the decommissioning of the Company’s nuclear
plants. On the consolidated balance sheets, the external trusts are reported at fair value with the accumulated provision for decommissioning included in accumulated depreciation. Net realized and unrealized earnings on the trust investments, as
well as the offsetting expense for decommissioning, are recorded as a component of other income, as permitted by regulatory authorities.
The balance of investments held in external trusts for decommissioning, as well as the accumulated provision for decommissioning, at December 31, 2001 and 2000, was $858 million and $851 million, respectively.
The Company collected $36 million from ratepayers in each of the years 2001, 2000 and 1999 and expensed like amounts as a
component of depreciation. The Company recognized net realized gains of $32 million, $20 million and $17 million for 2001, 2000, and 1999. The Company recognized net unrealized losses of $61 million and $23 million, for 2001 and 2000, respectively;
and net unrealized gains in 1999 of $60 million. The Company recognized offsetting increases or decreases to its provision for decommissioning for amounts equal to net realized and unrealized gains or losses for each period.
51
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Expected Costs for Decommissioning
The total estimated cost to decommission the Company’s four nuclear units is $1.6 billion based upon a site-specific
study that was completed in 1998. A new cost estimate will be completed in 2002. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. Under current operating licenses, decommissioning would
begin in 2012 as detailed in the table below. However, the Company filed a request with the NRC for a 20-year life extension for the Surry and North Anna units in 2001. The Company expects to decommission the units during the period 2032 to 2045.
| |
|
Surry
|
|
North Anna
|
|
Total All
|
| |
|
Unit 1
|
|
Unit 2
|
|
Unit 1
|
|
Unit 2
|
|
Units
|
| |
|
(Millions) |
| NRC license expiration year |
|
|
2012 |
|
|
2013 |
|
|
2018 |
|
|
2020 |
|
|
|
| Current cost estimate (1998 dollars) |
|
$ |
411 |
|
$ |
413 |
|
$ |
401 |
|
$ |
387 |
|
$ |
1,612 |
| Funds in external trusts at December 31, 2001 |
|
|
239 |
|
|
234 |
|
|
198 |
|
|
187 |
|
|
858 |
| 2001 contributions to external trusts |
|
|
11 |
|
|
11 |
|
|
7 |
|
|
7 |
|
|
36 |
The NRC requires nuclear power plant owners to annually update minimum financial
assurance amounts for the future decommissioning of the nuclear facilities. The Company’s 2001 NRC minimum financial assurance amount, aggregated for the four nuclear units, was $1.1 billion and will be satisfied by a combination of surety
bonds and the funds being collected in the external trusts.
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. The Company has purchased $200 million of coverage from the commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear
incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $88 million for each of its four licensed reactors, not to exceed $10 million per year per reactor. There is no limit to the number of incidents
for which this retrospective premium can be assessed.
The Price-Anderson Act was first enacted in 1957 and has been renewed
three times – in 1967, 1975 and 1988. Price-Anderson expires August 1, 2002, but operating nuclear reactors would continue to be covered by the law. Congress is currently holding hearings to reauthorize the legislation.
The Company’s current level of property insurance coverage ($2.55 billion for North Anna and $2.55 billion for Surry) exceeds the NRC’s
minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance are used first to return
the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The Company’s nuclear property insurance is provided by Nuclear Electric
Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is
$42 million. Based on the severity of the incident, the board of directors of the Company’s nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. The Company has the financial responsibility 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.
52
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The Company
purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, the Company 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 $19 million.
The North Anna Power Station is jointly owned as discussed in Note 12. The co-owner 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.
Note 9. Derivatives, Hedge Accounting and Energy Trading
Activities
Adoption of SFAS No. 133
The Company adopted SFAS No. 133 on January 1, 2001 and recorded an after-tax charge to accumulated other comprehensive income (AOCI) of $14 million, net of taxes of $9 million. The Company reclassified approximately
$13 million of AOCI associated with the January 1, 2001 transition adjustment to earnings during 2001. The effect of the amounts reclassified from AOCI to earnings was generally offset by the recognition of the hedged transactions (e.g., anticipated
sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.
Risk Management Policy
The Company uses derivatives to manage the commodity, currency exchange and financial market risks of its business
operations. The Company manages the price risk associated with purchases of natural gas and oil by utilizing derivative commodity instruments including futures and swaps. The Company manages its foreign exchange risk associated with anticipated
future purchases denominated in foreign currencies by utilizing currency forward contracts. The Company manages its interest rate risk exposure, in part, by entering into interest rate swap transactions.
As part of its strategy to market energy and to manage related risks, the Company 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. The Company 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. The Company has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are
maintained regarding the use of derivatives. In addition, Dominion has established an independent function to monitor compliance with the price risk management policies of all subsidiaries.
The Company designates a substantial portion of derivatives held for purposes other than trading as fair value or cash flow hedges. A significant portion of the Company’s hedge
strategies represents cash flow hedges of the variable price risk associated with purchases of natural gas, oil and other commodities. The Company also uses cash flow hedge strategies to hedge the variability in foreign exchange rates and variable
interest rates on long-term debt using derivative instruments discussed in the preceding paragraphs. The Company also has designated interest rate swaps as fair value hedges to manage its exposure to fixed interest rates on certain long-term debt.
Certain of the Company’s non-trading derivative instruments are not designated as hedges for accounting purposes. However, management believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity
prices and interest rates. All of the Company’s derivatives that are designated as hedges at December 31, 2001 represent cash flow hedges of the variable price risk associated with purchases of natural gas and oil, the risk of variability in
foreign exchange rates and the risk of variable interest rates on long-term debt.
53
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Accounting Policy
Under SFAS No. 133, derivatives are recognized on the Consolidated Balance Sheets at fair value, unless an exception is available under the
standard. Commodity contracts representing unrealized gain positions are reported as derivative and energy trading assets; commodity contracts representing unrealized losses are reported as derivative and energy trading liabilities.
In addition, purchased options and options sold are reported as derivative and energy trading assets and derivative and energy trading liabilities, respectively, at estimated market value until exercise or expiration.
For all derivatives designated as hedges, the Company formally documents the relationship between the hedging instrument and the hedged item,
as well as the risk management objective and strategy for using the
hedging instrument. The Company assesses whether the hedge relationship between the derivative and the hedged item is highly
effective in offsetting changes in fair value or cash flows both at the inception of the hedge and on an ongoing basis. Any change in fair value of the derivative that is not effective in offsetting changes in the fair value of the hedged item is
recognized currently in earnings. Further, for derivatives that have ceased to be highly effective hedges, the Company discontinues hedge accounting prospectively.
For fair value hedge transactions in which the Company is hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative will
generally be offset in the consolidated statements of income by changes in the hedged item’s fair value. For cash flow hedge transactions in which the Company is hedging the variability of cash flows related to a variable-priced asset,
liability, commitment, or forecasted transaction, changes in the fair value of the derivative are reported in AOCI. Derivative gains and losses reported in AOCI are reclassified as earnings in the periods in which earnings are impacted by the
variability of the cash flows of the hedged item. The ineffective portion of the change in fair value of derivatives and the change in fair value of derivatives not designated as hedges for accounting purposes are recognized in current period
earnings. For foreign currency forward contracts designated as cash flow hedges, hedge effectiveness is measured based on changes in the fair value of the contract attributable to changes in the forward exchange rate. For options designated either
as fair value or cash flow hedges, changes in time value are excluded from the measurement of hedge effectiveness and are therefore recorded in earnings.
Gains and losses on derivatives designated as hedges, when recognized, are included in operating revenue, expenses or interest and related charges in the Consolidated Statements of Income. Specific line
item classification is determined based on the nature of the risk underlying individual hedge strategies. Changes in the fair value of derivatives not designated as hedges and the portion of hedging derivatives excluded from the measurement of
effectiveness are included in other operation and maintenance expense in the Consolidated Statements of Income. Cash flows resulting from the settlement of derivatives used as hedging instruments are included in net cash flows from
operating activities.
2001 Derivative and Hedge Accounting Results
The Company experienced less than $1 million of ineffectiveness related to its hedges during 2001. Approximately $1 million of net losses in AOCI at December 31, 2001 is expected to be
reclassified to earnings during 2002. The actual amounts that will be reclassified to earnings in 2002 will vary from this amount as a result of changes in market prices. The effect of amounts being reclassified from AOCI to earnings will generally
be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies. As of December 31, 2001, the Company is
hedging its exposure to the variability in future cash flows for forecasted transactions over periods of one to five years.
54
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Energy Trading Activities
The Company’s energy trading contracts are reported at fair value, with corresponding changes in value recognized
immediately in earnings. Net gains and losses associated with the Company’s commodity trading activities are accounted for net of related cost of sales in non-regulated electric sales and non-regulated gas sales. Cash flows resulting from the
settlement of energy trading contracts are included in net cash flows from operating activities. The composition of operating revenue from commodity trading activities for the years 2001, 2000 and 1999 follows:
| |
|
Gains
|
|
Losses
|
|
|
Total
|
| |
|
(millions) |
| 2001 |
|
|
|
|
|
|
|
|
|
|
| Contract settlements |
|
$ |
5,520 |
|
$ |
(5,508 |
) |
|
$ |
12 |
| Unrealized gains and losses |
|
|
1,502 |
|
|
(1,361 |
) |
|
|
141 |
| |
|
|
|
|
|
|
|
|
|
|
| Operating revenue |
|
$ |
7,022 |
|
$ |
(6,869 |
) |
|
$ |
153 |
| |
|
|
|
|
|
|
|
|
|
|
| 2000 |
|
|
|
|
|
|
|
|
|
|
| Contract settlements |
|
$ |
2,773 |
|
$ |
(2,692 |
) |
|
$ |
81 |
| Unrealized gains and losses |
|
|
1,236 |
|
|
(1,211 |
) |
|
|
25 |
| |
|
|
|
|
|
|
|
|
|
|
| Operating revenue |
|
$ |
4,009 |
|
$ |
(3,903 |
) |
|
$ |
106 |
| |
|
|
|
|
|
|
|
|
|
|
| 1999 |
|
|
|
|
|
|
|
|
|
|
| Contract settlements |
|
$ |
2,577 |
|
$ |
(2,481 |
) |
|
$ |
96 |
| Unrealized gains and losses |
|
|
114 |
|
|
(101 |
) |
|
|
13 |
| |
|
|
|
|
|
|
|
|
|
|
| Operating revenue |
|
$ |
2,691 |
|
$ |
(2,582 |
) |
|
$ |
109 |
| |
|
|
|
|
|
|
|
|
|
|
Other
In June 2001, the FASB cleared guidance that permits certain option-type contracts for the purchase or sale of electricity to qualify for the normal purchases and normal sales exception, if certain criteria are met.
Qualifying contracts, for which the Company elects and formally documents this exception, are not reported at fair value, as otherwise required by SFAS No. 133. In response to the June 2001 guidance and other guidance issued during the second
quarter, the Company reevaluated certain of its long-term power purchase contracts. The Company determined that such contracts qualified under the guidance and thus designated them as normal purchases and sales. In late December 2001, the FASB
issued revised guidance on this matter to be effective April 1, 2002. The Company believes that its long-term power purchase contracts that are currently designated as normal purchases and normal sales will continue to qualify for the exception.
Future interpretations of SFAS No. 133 by the FASB or other standard-setting bodies could result in fair value accounting being
required for certain contracts that are not currently being subjected to such requirements. Accordingly, future interpretations may impact the Company’s ultimate application of the standard. However, if future SFAS No. 133 interpretive guidance
results in additional contracts becoming subject to fair value accounting, the Company would pursue hedging strategies to mitigate any potential future volatility in reported earnings.
55
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 10. Regulatory
Assets
The Company accounts for its regulated operations in accordance with SFAS No. 71. Regulatory assets represent
probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process.
The Company’s regulatory assets and liabilities included the following:
| |
|
At December 31,
|
| |
|
2001
|
|
2000
|
| |
|
(Millions) |
| Income taxes recoverable through future rates |
|
$ |
49 |
|
$ |
55 |
| Cost of decommissioning DOE uranium enrichment facilities |
|
|
42 |
|
|
49 |
| Deferred fuel |
|
|
119 |
|
|
98 |
| Other |
|
|
21 |
|
|
33 |
| |
|
|
|
|
|
|
| Total |
|
$ |
231 |
|
$ |
235 |
| |
|
|
|
|
|
|
The incurred costs underlying regulatory assets may represent past expenditures
by the Company’s rate regulated operations or may represent the recognition of liabilities that ultimately will be settled at some time in the future. At December 31, 2001, approximately $30 million of the Company’s regulatory assets
represented past expenditures on which it does not earn a return. These expenditures consist primarily of deferred fuel costs that are recovered within two years.
Income taxes recoverable or refundable through future rates resulted from the recognition of additional deferred income taxes, not previously recorded because of past ratemaking
practices.
The cost of decommissioning the Department of Energy’s (DOE) uranium enrichment facilities represents the
Company’s required contributions to a fund for decommissioning and decontaminating the DOE’s uranium enrichment facilities. The Company began making contributions in 1992 which are expected to continue over a 15-year period with escalation
for inflation. These costs are currently being recovered in fuel rates.
Deferred fuel accounting provides that the difference
between 1) reasonably incurred actual cost of fuels used in electric generation and energy purchases and 2) the recovery for such costs included in current rates is deferred and matched against future revenue.
56
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 11. Property, Plant and Equipment
Property, plant and equipment, other than nuclear fuel, consists of the following:
| |
|
At December 31,
|
| |
|
2001
|
|
2000
|
| |
|
(Millions) |
| Generation |
|
$ |
8,415 |
|
$ |
8,103 |
| Transmission |
|
|
1,565 |
|
|
1,557 |
| Distribution |
|
|
5,288 |
|
|
5,070 |
| Other |
|
|
852 |
|
|
944 |
| |
|
|
|
|
|
|
| |
|
|
16,120 |
|
|
15,674 |
| Plant under construction |
|
|
541 |
|
|
516 |
| |
|
|
|
|
|
|
| Total |
|
$ |
16,661 |
|
$ |
16,190 |
| |
|
|
|
|
|
|
Note 12. Jointly Owned Plants
The following information relates to the Company’s proportionate share of jointly owned plants at December 31, 2001:
| |
|
Bath County Pumped Storage Station
|
|
|
North Anna Power Station
|
|
|
Clover Power Station
|
|
| |
|
(Millions) |
|
| Ownership interest |
|
|
60.0 |
% |
|
|
88.4 |
% |
|
|
50.0 |
% |
| Plant in service |
|
$ |
1,028 |
|
|
$ |
1,859 |
|
|
$ |
533 |
|
| Accumulated depreciation |
|
|
321 |
|
|
|
1,162 |
|
|
|
83 |
|
| Nuclear fuel |
|
|
— |
|
|
|
314 |
|
|
|
— |
|
| Accumulated amortization of nuclear fuel |
|
|
— |
|
|
|
303 |
|
|
|
— |
|
| Plant under construction |
|
|
3 |
|
|
|
28 |
|
|
|
4 |
|
The co-owners are obligated to pay their share of all future construction
expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interest. The Company’s share of operating costs is classified in the appropriate operating expense (fuel, operations and
maintenance, depreciation, taxes, etc.) in the Consolidated Statements of Income.
Note 13. Short-term Debt and Credit
Agreements
The Company has credit agreements with various expiration dates and fees. These agreements provided for maximum
borrowings of $489 million and $800 million at December 31, 2001 and 2000, respectively. There was no amount borrowed under the credit agreements for either period.
The Company has a commercial paper program supported by a credit facility that supports the combined commercial paper programs of Dominion, CNG and the Company. This credit facility,
established in May 2001, is for $1.75 billion and matures in the second quarter of 2002. The Company has full access to this credit facility; however, the internal allocation may vary depending upon the needs of the participating entities. The
Company expects to renew this credit facility after its maturity.
Net borrowings under the commercial paper program were $436
million and $714 million at December 31, 2001 and 2000, with a weighted average interest rate of 4.03% and 6.63%, respectively.
57
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 14. Long-term
Debt
| |
|
December 31,
|
|
| |
|
2001
|
|
|
2000
|
|
| |
|
(millions) |
|
| First and Refunding Mortgage Bonds(1): |
|
|
|
|
|
|
|
|
| 6.0%, due 2001 |
|
$ |
— |
|
|
$ |
100 |
|
| 6.0% to 8.0%, due 2002 to 2004 |
|
|
705 |
|
|
|
705 |
|
| 8.75%, due 2021(2) |
|
|
— |
|
|
|
100 |
|
| 6.75% to 8.625%, due 2007 to 2025(3) |
|
|
1,416 |
|
|
|
1,416 |
|
| Senior and Medium-Term Notes: |
|
|
|
|
|
|
|
|
| 6.3% to 9.85%, due 2001 |
|
|
— |
|
|
|
140 |
|
| Variable rate, due 2002 to 2003(4) |
|
|
340 |
|
|
|
220 |
|
| 5.75% to 9.6%, due 2002 to 2006 |
|
|
775 |
|
|
|
175 |
|
| 5.73% to 7.15%, due 2008 to 2038 |
|
|
420 |
|
|
|
420 |
|
| Tax-Exempt Financings(5): |
|
|
|
|
|
|
|
|
| Variable rate, due 2007 to 2027(4) |
|
|
489 |
|
|
|
489 |
|
| 4.0% to 5.45%, due 2022 to 2031 |
|
|
110 |
|
|
|
60 |
|
| |
|
|
|
|
|
|
|
|
| |
|
|
4,255 |
|
|
|
3,825 |
|
| Fair value hedge valuation(6) |
|
|
4 |
|
|
|
— |
|
| Amount due within one year |
|
|
(535 |
) |
|
|
(241 |
) |
| Unamortized discount and premium, net |
|
|
(20 |
) |
|
|
(23 |
) |
| |
|
|
|
|
|
|
|
|
| Total long-term debt |
|
$ |
3,704 |
|
|
$ |
3,561 |
|
| |
|
|
|
|
|
|
|
|
(1) |
|
Substantially all of the Company’s property is subject to the lien of the mortgage securing its First and Refunding Mortgage Bonds (Mortgage Bonds).
|
(2) |
|
The Company redeemed its 1991-A mortgage bonds in 2001. |
(3) |
|
In January 2002, the Company called its $200 million, 1997-A, 6.75% mortgage bonds due February 1, 2007 for redemption in February 2002 at a price of 102.74 plus accrued
interest. In January 2002, the Company issued $650 million of 5.375% senior notes due February 1, 2007. |
(4) |
|
The weighted average interest rates of all series of variable rate debt ranged from 2.52% to 4.463% in 2001. |
(5) |
|
Certain pollution control facilities at the Company’s generating facilities have been pledged or conveyed to secure these financings. |
(6) |
|
Represents changes in fair value of certain fixed rate long-term debt associated with fair value hedging relationships, as described in Note 9. |
The Company’s scheduled principal payments of long-term debt at December 31, 2001 are as follows
(in millions):
| 2002
|
|
2003
|
|
2004
|
|
2005
|
|
2006
|
|
Thereafter
|
|
Total
|
| $535 |
|
$360 |
|
$325 |
|
$— |
|
$600 |
|
$2,435 |
|
$4,255 |
The Company’s short-term credit facilities and long-term debt agreements
contain customary covenants and default provisions. As of December 31, 2001, there were no events of default under the Company’s covenants.
Note
15. Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust
In 1995, the Company
established Virginia Power Capital Trust I (VP Capital Trust). In this transaction, VP Capital Trust sold 5.4 million trust preferred securities for $135 million, representing preferred beneficial interests and 97 percent beneficial ownership in the
assets held by VP Capital Trust.
58
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
In exchange for the
$135 million realized from the sale of the trust preferred securities and $4 million of common securities that represent the remaining 3 percent beneficial ownership interest in the assets held by VP Capital Trust, the Company issued $139 million of
its 1995 Series A, 8.05% Junior Subordinated Notes (the Notes) due September 30, 2025. The Notes constitute 100 percent of VP Capital Trust’s assets. The Notes may be extended for up to an additional ten years from date of original maturity if
certain conditions are satisfied.
Note 16. Preferred Stock
The Company is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference. Upon involuntary liquidation, dissolution or winding-up of the Company, each
share is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.
In 2001, the Company purchased
and redeemed all shares of its Money Market Preferred Stock Series January 1987 and June 1987 for $125 million representing a price of $100 per share.
Shown below are the series of preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2001:
| |
|
Issued and Outstanding Dividend Shares(1)
|
|
Entitled Per Share Upon Liquidation
|
|
| $5.00 |
|
107 |
|
$ |
112.50 |
|
| 4.04 |
|
13 |
|
|
102.27 |
|
| 4.20 |
|
15 |
|
|
102.50 |
|
| 4.12 |
|
32 |
|
|
103.73 |
|
| 4.80 |
|
73 |
|
|
101.00 |
|
| 7.05 |
|
500 |
|
|
105.00 |
(2) |
| 6.98 |
|
600 |
|
|
105.00 |
(3) |
| MMP 10/88(4) |
|
750 |
|
|
100.00 |
|
| MMP 6/89(4) |
|
750 |
|
|
100.00 |
|
| MMP 9/92, Series A(4) |
|
500 |
|
|
100.00 |
|
| MMP 9/92, Series B(4) |
|
500 |
|
|
100.00 |
|
| |
|
|
|
|
|
|
| Total |
|
3,840 |
|
|
|
|
| |
|
|
|
|
|
|
(1) |
|
Shares are presented in thousands. |
(2) |
|
Through 7/31/03; amounts decline in steps thereafter to $100.00 after 7/31/13. |
(3) |
|
Through 8/31/03; amounts decline in steps thereafter to $100.00 after 8/31/13. |
(4) |
|
Money Market Preferred dividend rates are variable and are set every 49 days via an auction process. The combined weighted average rates for all series outstanding during 2001,
2000, and 1999, including fees for broker/dealer agreements, were 4.32 percent, 5.71 percent and 4.82 percent, respectively. |
Note
17. Long-term Incentives
Employees of the Company may receive stock-based awards, such as stock
options and restricted stock, granted under Dominion sponsored stock plans. The Company measures compensation cost in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related
interpretations (APB 25). Under APB 25, no compensation expense was recognized for grants of stock options where the exercise price equaled the market price of Dominion’s common stock on the date of grant. Compensation expense recognized for
the issuance of stock-awards was not significant in 2001, 2000, or 1999.
59
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
During 2001 and 2000, the pro forma impact on net income, had the Company measured compensation expense based on the fair value of the options on the date of grant, would not have been material.
During 1999, Dominion granted approximately 2 million common stock options to certain officers and key employees of the Company, and these options vested on January 1, 2000. Had the Company measured compensation expense based on the fair value of
the options on the date of grant, pro forma net income for 1999 would have been reduced by approximately $5 million.
Note
18. Employee Benefit Plans
The Company provides certain benefits to eligible active employees,
retirees and qualifying dependents. Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
The Company participates in the Dominion Resources, Inc. Retirement Plan (DRI Plan), a defined benefit pension plan. Benefits
payable under the plans are based primarily on years of service, age and the employee’s compensation. The Company’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.
In 1999 and 1998, the
Company provided certain retiree health care and life insurance benefits with annual premiums based on several factors such as age, retirement date, and years of service. Beginning in 2000, the Company participated in plans which provide these
benefits to multiple Dominion subsidiaries. The Company is the primary participating employer in the DRI Plan.
In 2000,
subsequent to Dominion’s acquisition of CNG, Dominion and its subsidiaries developed and began the implementation of a plan to restructure the operations of the combined companies. This plan included a voluntary early retirement program (ERP).
Salaried employees of the Company, excluding officers, who had attained age 52 and completed at least five years of service as of July 1, 2000 were eligible under the ERP. The early retirement option provided up to three additional years of age and
three additional years of employee service, subject to age and service maximums, for benefit formula purposes under Dominion’s postretirement medical and pension plans. The effect of the ERP on the Company’s pension plan and post
retirement benefit expenses was $38 million and $13 million, respectively.
60
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following tables
summarize information for those pension and other benefit plans in which the Company participates, including the changes in the pension and other postretirement benefit plan obligations and plan assets for each of the years ended December 31, 2001
and 2000, and a statement of the plans’ funded status as of December 31, 2001 and 2000:
| |
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
| |
|
2001
|
|
|
2000
|
|
|
2001
|
|
|
2000
|
|
| Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Benefit obligation at beginning of year |
|
$ |
1,241 |
|
|
$ |
1,097 |
|
|
$ |
436 |
|
|
$ |
401 |
|
| Adoption of plan by affiliates |
|
|
66 |
|
|
|
— |
|
|
|
21 |
|
|
|
— |
|
| Service cost |
|
|
47 |
|
|
|
39 |
|
|
|
26 |
|
|
|
19 |
|
| Interest cost |
|
|
95 |
|
|
|
85 |
|
|
|
37 |
|
|
|
29 |
|
| Special termination benefit cost |
|
|
— |
|
|
|
38 |
|
|
|
— |
|
|
|
13 |
|
| Benefits paid |
|
|
(55 |
) |
|
|
(49 |
) |
|
|
(18 |
) |
|
|
(21 |
) |
| Plan amendments |
|
|
1 |
|
|
|
(16 |
) |
|
|
— |
|
|
|
(22 |
) |
| Actuarial loss during the year |
|
|
66 |
|
|
|
47 |
|
|
|
74 |
|
|
|
17 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Expected benefit obligation at end of year |
|
|
1,461 |
|
|
|
1,241 |
|
|
|
576 |
|
|
|
436 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fair value of plan assets at beginning of year |
|
|
1,266 |
|
|
|
1,305 |
|
|
|
275 |
|
|
|
272 |
|
| Actual return on plan assets |
|
|
(45 |
) |
|
|
(5 |
) |
|
|
(22 |
) |
|
|
(7 |
) |
| Contributions |
|
|
19 |
|
|
|
15 |
|
|
|
16 |
|
|
|
11 |
|
| Benefits paid from plan assets |
|
|
(55 |
) |
|
|
(49 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fair value of plan assets at end of year |
|
|
1,185 |
|
|
|
1,266 |
|
|
|
268 |
|
|
|
275 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Reconciliation of funded status: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Funded status |
|
|
(276 |
) |
|
|
25 |
|
|
|
(308 |
) |
|
|
(161 |
) |
| Unrecognized net actuarial (gain)/loss |
|
|
244 |
|
|
|
14 |
|
|
|
111 |
|
|
|
(10 |
) |
| Unamortized prior service cost |
|
|
(12 |
) |
|
|
(14 |
) |
|
|
(2 |
) |
|
|
(2 |
) |
| Unrecognized net transition (asset)/obligation |
|
|
(5 |
) |
|
|
(8 |
) |
|
|
115 |
|
|
|
126 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Prepaid (accrued) benefit cost |
|
$ |
(49 |
) |
|
$ |
17 |
|
|
$ |
(84 |
) |
|
$ |
(47 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Amounts recognized in the Company’s Consolidated Balance Sheets at December 31 consist of the following: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Prepaid benefit cost |
|
$ |
16 |
|
|
$ |
16 |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accrued benefit liability |
|
|
|
|
|
|
|
|
|
$ |
(46 |
) |
|
$ |
(52 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The components of
the provision for net periodic benefit cost were as follows:
| |
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
| |
|
Year ending December 31,
|
|
| |
|
2001
|
|
|
2000
|
|
|
1999
|
|
|
2001
|
|
|
2000
|
|
|
1999
|
|
| |
|
(Millions) |
|
|
(Millions) |
|
| Service cost |
|
$ |
47 |
|
|
$ |
39 |
|
|
$ |
40 |
|
|
$ |
26 |
|
|
$ |
19 |
|
|
$ |
16 |
|
| Interest cost |
|
|
95 |
|
|
|
85 |
|
|
|
76 |
|
|
|
37 |
|
|
|
29 |
|
|
|
27 |
|
| Expected return on plan assets |
|
|
(119 |
) |
|
|
(108 |
) |
|
|
(93 |
) |
|
|
(25 |
) |
|
|
(25 |
) |
|
|
(19 |
) |
| Amortization of transition obligation |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
— |
|
|
|
11 |
|
|
|
12 |
|
|
|
12 |
|
| Amortization of prior service cost |
|
|
(1 |
) |
|
|
1 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| ERP benefit costs |
|
|
— |
|
|
|
38 |
|
|
|
— |
|
|
|
— |
|
|
|
13 |
|
|
|
— |
|
| Net amortization and deferral |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(2 |
) |
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net periodic benefit cost |
|
$ |
19 |
|
|
$ |
52 |
|
|
|
23 |
|
|
$ |
49 |
|
|
$ |
46 |
|
|
$ |
36 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Company allocated expense |
|
$ |
7 |
|
|
$ |
50 |
|
|
$ |
21 |
|
|
$ |
35 |
|
|
$ |
42 |
|
|
$ |
36 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant assumptions used in determining net periodic pension cost, the
projected benefit obligation, and postretirement benefit obligations were:
| |
|
Pension Benefits
|
|
Other Postretirement Benefits
|
| |
|
2001
|
|
2000
|
|
2001
|
|
2000
|
| Discount rates |
|
7.25% |
|
7.50% |
|
7.25% |
|
7.50% |
| Expected return on plan assets |
|
9.50% |
|
9.50% |
|
9.00% |
|
6.50% |
| Rate of increase for compensation income |
|
4.60% |
|
5.00% |
|
4.60% |
|
5.00% |
| Medical cost trend rate |
|
|
|
|
|
9.00% |
|
9.00% |
The medical cost trend rate is assumed to gradually decrease to 4.75% by 2006 and
continue at that rate for years thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
| |
|
One Percentage Point Increase
|
|
One Percentage Point Decrease
|
|
| |
|
(Millions) |
|
| Effect on total of service and interest cost components for 2001 |
|
$ |
10 |
|
$ |
(8 |
) |
| Effect on postretirement benefit obligation at December 31, 2001 |
|
|
74 |
|
|
(60 |
) |
The funds collected for other postretirement benefits in rates, in excess of
benefits actually paid during the year, are contributed to external benefit trusts. See Note 19 for a discussion of the impact of deregulation legislation on the recoverability of potentially stranded costs.
The Company also sponsors employee savings plans which cover substantially all employees. Employer matching contributions of $10 million, $12 million
and $11 million were expensed in 2001, 2000 and 1999, respectively.
62
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note
19. Commitments and Contingencies
As the result of issues generated in the course of daily business,
the Company is 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 a material adverse effect on the Company’s operations, financial position, liquidity or results of operations.
Utility
Rate Regulation
The Company faces competition as a result of utility industry deregulation. Under Virginia’s electric
utility industry deregulation legislation, the Company’s base rates will remain capped until July 2007 unless the Company petitions for, and the Virginia Commission approves, an earlier termination anytime after January 1, 2004. The capped
rates will provide recovery of certain generation-related costs. The Company remains exposed to numerous risks, including, among others, exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws,
inflation and increased capital costs. At December 31, 2001 the Company’s exposure to potentially stranded costs was comprised of: long-term power purchase contracts that could ultimately be determined to be above market (see Power Purchase
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 8 and 18.
Capital Expenditures
The Company has made substantial commitments in connection with its capital expenditures program. Those expenditures are estimated to total approximately $827 million, $816 million and $655 million for 2002, 2003 and
2004 respectively. Purchases of nuclear fuel are included in Fuel Purchase Commitments below. The Company expects that these expenditures will be met through cash flow from operations and through a combination of sales of securities and
short-term borrowings.
Power Purchase Contracts
The Company has entered into contracts for the long-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. The Company has 43 non-utility purchase contracts
with a combined dependable summer capacity of 3,770 megawatts.
The table below reflects the Company’s minimum commitments
as of December 31, 2001, for power purchases from utility and non-utility suppliers.
| |
|
Commitment
|
| |
|
Capacity
|
|
Other
|
| |
|
(Millions) |
| Year
|
|
|
| 2002 |
|
$ |
685 |
|
$ |
33 |
| 2003 |
|
|
635 |
|
|
20 |
| 2004 |
|
|
634 |
|
|
17 |
| 2005 |
|
|
627 |
|
|
12 |
| 2006 |
|
|
613 |
|
|
12 |
| Later years |
|
|
5,856 |
|
|
128 |
| |
|
|
|
|
|
|
| Total |
|
$ |
9,050 |
|
$ |
222 |
| |
|
|
|
|
|
|
| Present value of the total |
|
$ |
5,091 |
|
$ |
116 |
| |
|
|
|
|
|
|
63
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
In addition to the
minimum commitments in the table above, under some of these contracts, the Company may purchase, at its option, energy 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 2001, 2000, and 1999 were $1.1 billion, $1.1 billion, and $1.2 billion, respectively.
In 2001, the Company completed the purchase of three generating facilities and the termination of seven contracts which provided electricity to the Company under long-term power purchase agreements with non-utility generators (NUG). The
Company recorded an after-tax charge of $136 million in connection with the purchase and termination of the long-term power purchase agreements. Cash payments related to the purchase of the three generating facilities totaled $207 million. The
allocation of the purchase price was assigned to the assets and liabilities acquired based upon estimated fair values as of the date of acquisition. Substantially all of the value was attributed to the power purchase agreements which were terminated
and resulted in a charge included in operations and maintenance expense.
See Note 6 for additional disclosure regarding
the evaluation of the Company’s potential exposure under its long-term power purchase commitments.
Fuel Purchase Commitments
The Company enters into long-term purchase commitments for fuel used in electric generation. Estimated fuel purchase commitments for the next
five years are as follows: 2002—$398 million; 2003—$215 million; 2004—$171 million; 2005—$152 million; and 2006—$117 million. The Company recovers the costs of these purchases through regulated rates.
Lease Commitments
The Company leases
various facilities, vehicles, and equipment under both operating and capital leases. Future minimum lease payments under the Company’s capital and operating leases that have initial or remaining lease terms in excess of one year as of December
31, 2001 are as follows: 2002—$37 million; 2003—$29 million; 2004—$20 million; 2005—$19 million; 2006—$12 million and years after 2006—$52 million.
Rental expense included in other operations and maintenance expense was $25 million, $24 million, and $26 million for 2001, 2000, and 1999, respectively.
In addition, the Company has entered into agreements with another Dominion subsidiary in order to develop, construct, finance and lease a new power
generation facility at the Company’s Possum Point station in Prince William County, Virginia. The project is scheduled for completion in 2003 at an estimated cost of $370 million. Upon completion, the Company will operate the new
generating facility under an operating lease with estimated annual lease payments of $26 million.
Energy Trading
Subsidiaries of the Company enter into purchases and sales of commodity-based contracts in the energy-related markets, including natural gas,
electricity, coal and oil. These agreements may cover current and future periods. The volume of these transactions varies from day to day, based on market conditions. See Note 9 for a discussion of the Company’s energy trading activities and
risk management policies.
64
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Environmental Matters
The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed
to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
Historically, the Company recovered such costs arising from regulated electric operations through utility rates. However, to the extent environmental
costs are incurred in connection with operations regulated by the Virginia State Corporation Commission, during the period ending June 30, 2007, in excess of the level currently included in Virginia jurisdictional rates, the Company’s results
of operations will decrease. After that date, the Company may seek recovery from customers through utility rates of only those environmental costs related to transmission and distribution operations.
Superfund Sites
In 1987, the Environmental
Protection Agency (EPA) identified the Company and a number of other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. Current cost studies estimate total remediation costs for the sites
to range from $98 million to $153 million. The Company’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. The majority
of remediation activities at the Kentucky site are complete and remediation design is ongoing for the Pennsylvania site. The Company has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of
the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay their share of the costs. The Company generally seeks to recover its costs associated with environmental remediation from third party
insurers. At December 31, 2001, any pending or possible claims were not recognized as an asset or offset against such obligations.
Other EPA Matters
In 1999, the Department of Justice (DOJ) notified the Company of an alleged noncompliance with the EPA’s oil spill
prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of the Company’s power stations. In December 2001, the Company reached a settlement agreement with the DOJ and EPA covering all alleged
noncompliance issues. The settlement will not have a material impact on the Company’s financial condition or results of operations. The Company also identified matters at other power stations that the EPA might view as not in compliance with
the SPCC and FRP requirements and reported these matters to the EPA. The Company also reported its plans for correcting the issues. The Company does not believe that the settlement of these self-reported matters, if any, will be material to its
results of operations or financial conditions.
During 2000, the Company received a Notice of Violation from the EPA alleging
that the Company failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at the Mt. Storm Power Station in West Virginia. The Attorney General of New York filed a suit against the
Company alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. The Company also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. Management
believes that the Company has obtained the necessary permits for its generating facilities. The Company has reached an agreement in principle with the federal government and the state of New York to resolve this situation. The agreement in
principle includes payment of a $5 million civil penalty, a
65
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
commitment of $14 million for environmental projects in Virginia, West Virginia, Connecticut, New Jersey and New York, and a 12-year, $1.2 billion capital investment program for environmental
improvements at the Company's coal-fired generating stations in Virginia and West Virginia. The Company had already committed to a substantial portion of the $1.2 billion expenditures for sulfur dioxide and nitrogen oxide emissions controls. The
negotiations over the terms of a binding settlement have expanded beyond the basic agreement in principle and are ongoing. As of December 31, 2001, the Company has recorded, on a discounted basis, $18 million for the civil penalty and environmental
projects.
Spent Nuclear Fuel
Under provisions of the Nuclear Waste Policy Act of 1982, the Company has entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent nuclear fuel on January 31, 1998, the
date provided by the Nuclear Waste Policy Act and by the Company’s contract with the DOE. The Company will continue to safely manage its spent fuel until accepted by the DOE.
Retrospective Premium Assessments
Under several of the Company’s nuclear insurance
policies, the Company is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to these insurance companies. For additional information, see Note 8.
Note 20. Fair Value of Financial Instruments
Substantially all of the Company’s financial instruments are recorded at fair value, with the exception of the instruments described below. Fair value amounts have been determined using available market
information and valuation methodologies considered appropriate by management.
The Company reports the following financial
instruments based on historical cost rather than fair value. The financial instruments’ carrying amounts and fair values as of December 31, 2001 and 2000 were as follows:
| |
|
2001
|
|
2000
|
| |
|
Carrying Amount
|
|
Estimated Fair Value
|
|
Carrying Amount
|
|
Estimated Fair Value
|
| |
|
(Millions) |
|
(Millions) |
| Long-term debt(1) |
|
$ |
4,255 |
|
$ |
4,313 |
|
$ |
3,825 |
|
$ |
3,813 |
| Preferred securities of subsidiary trust(2) |
|
|
135 |
|
|
137 |
|
|
135 |
|
|
133 |
| Unrecognized financial instruments(3): |
|
|
|
|
|
|
|
|
|
|
|
|
| Interest rate swaps(4) |
|
|
— |
|
|
— |
|
|
— |
|
|
3 |
(1) |
|
Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities are used
to estimate fair value. |
(2) |
|
Fair value is based on market quotations. |
(3) |
|
Upon adoption of SFAS No. 133 on January 1, 2001, all derivatives are reported at fair value. The fair value of unrecognized financial instruments at December 31, 2000 was
recognized as a component of the January 1, 2001 SFAS No. 133 transition adjustment. See Note 9 for discussion of the Company’s derivatives and hedge accounting activities. |
(4) |
|
Fair value was 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. |
66
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 21. Related
Party Transactions
The Company, through an unregulated subsidiary, exchanges certain quantities of natural gas and oil with
affiliates at index prices, and electricity at market prices in the ordinary course of business. The Company purchased approximately $117 million and $60 million of natural gas from other Dominion affiliates and sold approximately $229 million and
$33 million to affiliates in 2001 and during the period January 28, 2000 through December 31, 2000, respectively. In addition, the Company purchased gas transportation, storage and other services from affiliates for $16 million and $5 million in
2001 and during the period January 28, 2000 through December 31, 2000, respectively. The Company sold $4 million and $5 million of electricity at market prices to affiliated companies in 2001 and during the period January 28, 2000 to December 31,
2000, respectively. In 2001, the Company sold $1 million of oil to affiliates at market.
The Company, through an unregulated
subsidiary, is involved in facilitating Dominion's enterprise risk management strategy. In connection with this strategy, the Company enters into certain commodity derivative contracts with other Dominion affiliates. These contracts, which are
principally comprised of commodity swaps, are used by Dominion affiliates to manage commodity price risks associated with purchases and sales of natural gas. As part of Dominion's enterprise risk management strategy, the Company generally manages
such risk exposures by entering into offsetting derivative instruments with non-affiliates. The Company reports both affiliated and non-affiliated derivative instruments at fair value, with changes thereto included in earnings. The Company's
Consolidated Balance Sheets include derivative and energy trading assets of $159 million and $171 million with Dominion affiliates and derivative and energy trading liabilities of $77 million and $55 million with Dominion affiliates at December 31,
2001 and 2000, respectively. The Company reported net realized gains of $2 million and net realized losses of $21 million in 2001 and 2000, respectively, related to commodity derivative contracts with Dominion affiliates.
Effective February 1, 2000, Dominion created a subsidiary service company, Dominion Resources Services, Inc. (Dominion Services), which provides certain
services to the Company. In connection with the formation of Dominion Services, certain of the Company’s employees became employees of Dominion Services. The cost of services provided by Dominion Services to the Company during 2001 and the
period February 1, 2000 through December 31, 2000 was approximately $313 million and $202 million, respectively. In 2001, the Company transferred certain assets and liabilities to Dominion Services with a net book value of approximately
$27 million; no gain or loss was recorded on the transfer.
In addition, prior to February 1, 2000, certain employees of
Dominion provided services to the Company. The cost of these services was $2 million and $9 million during the period from January 1, 2000 through January 31, 2000 and during 1999, respectively. The Company also charged affiliates for certain
costs incurred on their behalf, including facility and equipment expenses and personnel costs. The cost of services charged by the Company to affiliates was $23 million, $15 million and $2 million in 2001, 2000 and 1999, respectively.
The Company leases its principal office building from Dominion under an agreement approved by the Virginia Commission that expires in 2006.
This agreement is accounted for as a capital lease. The capitalized cost of the property under that lease, net of accumulated amortization, was approximately $17 million and $19 million at December 31, 2001 and 2000, respectively. The rental
payments for this lease were $3 million in each of the years ended December 31, 2001, 2000 and 1999.
For information about the
Company’s agreement with Dominion Equipment, Inc. to develop, construct, finance and lease a new power generation facility at its Possum Point station in Prince William County, Virginia, see Lease Commitments in Note 19.
67
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
In July 2000, the
Company transferred all of its issued and outstanding common stock in VPS Communications, Inc. (VPS) to Dominion. Dominion renamed VPS to Dominion Telecom, Inc. (DTI). In 2001, Dominion contributed DTI to Dominion Fiber Ventures LLC (DFV), a
telecommunications joint venture. DFV is the sole owner of DTI. The Company leases fiber optic capacity to DTI at rates subject to the approval of the Virginia Commission. Payments received by the Company in connection with Dominion Telecom’s
lease of fiber optic equipment, and related fiber optic support and maintenance services, during 2001 and the period August 1, 2000 through December 31, 2000 were approximately $4 million and $1 million, respectively. The capitalized cost of the
property under that lease, net of accumulated amortization, was approximately $5 million at December 31, 2001 and December 31, 2000.
In 2001, an unregulated division of the Company transferred some energy management services contracts and related leases to another Dominion subsidiary for $14 million, representing the Company’s net book value recorded on its books
for these contracts.
The Company had a net outstanding payable balance of approximately $192 million and $122 million to
affiliates and a net outstanding receivable of approximately $54 million and $30 million as of December 31, 2001 and 2000, respectively. The Company also had a $5 million note receivable from affiliates outstanding at December 31, 2001 and December
31, 2000. Balances due to or from affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions.
See Notes 2, 17, and 18 for discussion of the inclusion of the Company in Dominion’s consolidated federal income tax return and the Company’s participation in certain Dominion
employee incentive and benefit plans.
Note 22. Dividend Restrictions
The Virginia Commission may prohibit any public service company from declaring or paying a dividend to an affiliate, if found not to be in
the public interest. As of December 31, 2001, the Virginia Commission had not restricted the payment of dividends by the Company.
Note
23. Operating Segments
The Company is organized primarily on the basis of products and services sold
in the United States. The Company manages its operations based on two operating segments:
| |
• |
|
Energy encompasses the Company’s portfolio of generating facilities and power purchase contracts, and its trading and marketing activities.
|
| |
• |
|
Delivery includes bulk power transmission, distribution and metering services, and customer service and continues to be subject to the requirements of SFAS No. 71.
|
The majority of the Company’s revenue is provided through bundled rate tariffs. Generally, such
revenues are allocated between the two segments for management reporting based on prior cost of service studies.
In addition,
the Company also reports Corporate and Other as a segment. Corporate and other include certain expenses which are not allocated to the Energy and Delivery segments, including:
| |
1) |
|
corporate operations and assets; |
68
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| |
2) |
|
transactions or events not allocated to the operating segments for internal reporting purposes: |
— 2001 Non-utility generator and power purchase charge (see Note 19);
— 2001 and 2000 restructuring costs (see Note 5);
— 2000 cumulative effect of a change in accounting principle (see Note 3); and
— 1999 extraordinary item (see Note 6).
The following table presents segment information pertaining to the
Company’s operations
| Description
|
|
Energy
|
|
Delivery
|
|
Corporate and Other
|
|
|
Eliminations
|
|
|
Consolidated Total
|
| |
|
(millions) |
| Year ended December 31, 2001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulated electric sales |
|
$ |
3,475 |
|
$ |
1,145 |
|
|
— |
|
|
|
— |
|
|
$ |
4,620 |
| Other revenue |
|
|
247 |
|
|
67 |
|
$ |
12 |
|
|
$ |
(2 |
) |
|
|
324 |
| Total operating revenue |
|
|
3,722 |
|
|
1,212 |
|
|
12 |
|
|
|
(2 |
) |
|
|
4,944 |
| Depreciation and amortization |
|
|
222 |
|
|
264 |
|
|
32 |
|
|
|
— |
|
|
|
518 |
| Interest and related charges |
|
|
145 |
|
|
156 |
|
|
3 |
|
|
|
(4 |
) |
|
|
300 |
| Income tax expense |
|
|
246 |
|
|
142 |
|
|
(102 |
) |
|
|
— |
|
|
|
286 |
| Net income |
|
|
380 |
|
|
230 |
|
|
(164 |
) |
|
|
— |
|
|
|
446 |
| Total assets |
|
|
8,320 |
|
|
5,464 |
|
|
— |
|
|
|
— |
|
|
|
13,784 |
| Capital expenditures |
|
|
330 |
|
|
338 |
|
|
— |
|
|
|
— |
|
|
|
668 |
| |
| Year ended December 31, 2000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulated electric sales |
|
|
3,341 |
|
|
1,151 |
|
|
— |
|
|
|
— |
|
|
|
4,492 |
| Other revenue |
|
|
236 |
|
|
59 |
|
|
6 |
|
|
|
(2 |
) |
|
|
299 |
| Total operating revenue |
|
|
3,577 |
|
|
1,210 |
|
|
6 |
|
|
|
(2 |
) |
|
|
4,791 |
| Depreciation and amortization |
|
|
269 |
|
|
251 |
|
|
38 |
|
|
|
— |
|
|
|
558 |
| Interest and related charges |
|
|
148 |
|
|
145 |
|
|
7 |
|
|
|
(4 |
) |
|
|
296 |
| Income tax expense |
|
|
178 |
|
|
133 |
|
|
(32 |
) |
|
|
— |
|
|
|
279 |
| Net income |
|
|
369 |
|
|
246 |
|
|
(36 |
) |
|
|
— |
|
|
|
579 |
| Total assets |
|
|
7,885 |
|
|
5,446 |
|
|
— |
|
|
|
— |
|
|
|
13,331 |
| Capital expenditures |
|
|
319 |
|
|
333 |
|
|
— |
|
|
|
— |
|
|
|
652 |
| |
| Year ended December 31, 1999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Regulated electric sales |
|
|
3,121 |
|
|
1,109 |
|
|
(3 |
) |
|
|
— |
|
|
|
4,227 |
| Other revenue |
|
|
302 |
|
|
51 |
|
|
11 |
|
|
|
— |
|
|
|
364 |
| Total operating revenue |
|
|
3,423 |
|
|
1,160 |
|
|
8 |
|
|
|
— |
|
|
|
4,591 |
| Depreciation and amortization |
|
|
275 |
|
|
246 |
|
|
27 |
|
|
|
— |
|
|
|
548 |
| Interest and related charges |
|
|
142 |
|
|
148 |
|
|
1 |
|
|
|
(2 |
) |
|
|
289 |
| Income tax expense |
|
|
149 |
|
|
109 |
|
|
— |
|
|
|
— |
|
|
|
258 |
| Net income |
|
|
292 |
|
|
193 |
|
|
(255 |
) |
|
|
— |
|
|
|
230 |
| Capital expenditures |
|
|
347 |
|
|
326 |
|
|
— |
|
|
|
— |
|
|
|
673 |
69
VIRGINIA ELECTRIC AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Note 24. Quarterly
Financial Data (Unaudited)
A summary of the quarterly results of operations for the years 2001 and 2000 follows. Amounts
reflect all adjustments, consisting of only normal recurring accruals (except as discussed below), necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a
result of weather conditions, changes in rates and other factors.
In 2000, Dominion and its subsidiaries, including the
Company, adopted a company-wide method of calculating the market related value of pension plan assets used to determine the expected return on pension plan assets, a component of net periodic pension cost. The cumulative effect of the accounting
change on prior years, recorded as of January 1, 2000, was $21 million (net of taxes of $11 million).
| |
|
1st Quarter
|
|
2nd Quarter
|
|
3rd Quarter
|
|
4th Quarter
|
|
Total
|
| 2001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating revenue |
|
$ |
1,222 |
|
$ |
1,177 |
|
$ |
1,444 |
|
$ |
1,101 |
|
$ |
4,944 |
| Income from operations |
|
|
109 |
|
|
297 |
|
|
495 |
|
|
98 |
|
|
999 |
| Net income |
|
|
25 |
|
|
134 |
|
|
266 |
|
|
21 |
|
|
446 |
| Balance available for common stock |
|
|
18 |
|
|
128 |
|
|
260 |
|
|
17 |
|
|
423 |
| |
| 2000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating revenue |
|
$ |
1,126 |
|
$ |
1,147 |
|
$ |
1,378 |
|
$ |
1,140 |
|
$ |
4,791 |
| Income from operations |
|
|
259 |
|
|
220 |
|
|
444 |
|
|
163 |
|
|
1,086 |
| Income before extraordinary item and cumulative effect of a change in accounting principle |
|
|
130 |
|
|
97 |
|
|
263 |
|
|
68 |
|
|
558 |
| Net income |
|
|
151 |
|
|
97 |
|
|
263 |
|
|
68 |
|
|
579 |
| Balance available for common stock |
|
|
141 |
|
|
88 |
|
|
254 |
|
|
60 |
|
|
543 |
70
None.
PART III
(a) Information concerning directors of Virginia Electric and Power Company, each of whom is elected annually, is as follows:
| Name And Age
|
|
Principal Occupation For Last 5 Years, Directorships in Public
Corporations
|
|
Year First Elected As Director
|
| Thos. E. Capps (66)
|
|
Chairman of the Board of Virginia Electric and Power Company from September 1997 to date; Chairman of the Board of Directors, President and Chief Executive Officer of Dominion
Resources, Inc. from August 2000 to date; Vice Chairman of the Board of Directors, President and Chief Executive Officer of Dominion Resources, Inc. from January 2000 to August 2000; Chairman of the Board of Directors, President and Chief
Executive Officer from September 1995 to January 2000 of Dominion Resources, Inc. |
|
1986 |
| |
| Thomas F. Farrell, II (47)
|
|
Executive Vice President of Dominion Resources, Inc. from March 1999 to date and Chief Executive Officer of Virginia Electric and Power Company from May 1999 to
date; Executive Vice President of Consolidated Natural Gas Company from January 2000 to date; Executive Vice President, General Counsel and Corporate Secretary of Virginia Electric and Power Company from July 1998 to April 1999; Executive Vice
President and General Counsel of Virginia Electric and Power Company from April 1998 to June 1998; Executive Vice President of Virginia Electric and Power Company from September 1997 to April 1998; Senior Vice President—Corporate Affairs of
Dominion Resources, Inc. from September 1997 to March 1999; Senior Vice President—Corporate Affairs and General Counsel of Dominion Resources, Inc. from January 1997 to September 1999. |
|
1999 |
| |
| Edgar M. Roach, Jr. (53) |
|
President and Chief Executive Officer of Virginia Electric and Power Company from December 2001 to date and Executive Vice President of Dominion Resources, Inc. from
September 1997 to date; Executive Vice President of Consolidated Natural Gas Company from January 2000 to date; Chief Executive Officer of Virginia Electric and Power Company from May 1999 to December 2001. Senior Vice President—Finance,
Regulation and General Counsel of Virginia Electric and Power Company from January 1996 to September 1997. |
|
1999 |
71
(b) Information concerning the executive officers of Virginia Electric and Power
Company, each of whom is elected annually is as follows:
| Name And Age
|
|
Business Experience Past Five Years
|
| Thomas F. Farrell, II (47)
|
|
Executive Vice President of Dominion Resources, Inc. from March 1999 to date and Chief Executive Officer of Virginia Electric and Power Company from
May 1999 to date; Executive Vice President of Consolidated Natural Gas Company from January 2000 to date; Executive Vice President, General Counsel and Corporate Secretary of Virginia Electric and Power Company from July 1998 to April 1999;
Executive Vice President and General Counsel of Virginia Electric and Power Company from April 1998 to June 1998; Executive Vice President of Virginia Electric and Power Company from September 1997 to April 1998; Senior Vice President—Corporate
Affairs of Dominion Resources, Inc. from September 1997 to March 1999; Senior Vice President—Corporate Affairs and General Counsel of Dominion Resources, Inc. from January 1997 to September 1999. |
| Edgar M. Roach, Jr. (53)
|
|
President and Chief Executive Officer of Virginia Electric and Power Company from December 2001 to date and Executive Vice President of Dominion Resources, Inc.
from September 1997 to date; Executive Vice President of Consolidated Natural Gas Company from January 2000 to date; Chief Executive Officer of Virginia Electric and Power Company from May 1999 to December 2001. Senior Vice President—Finance,
Regulation and General Counsel of Virginia Electric and Power Company from January 1996 to September 1997. |
| James P. O’Hanlon (58)
|
|
President and Chief Operating Officer of Virginia Electric and Power Company and Executive Vice President of Dominion Resources, Inc. from May 1999 to date;
Executive Vice President of Consolidated Natural Gas Company from January 2000 to date; President, Chief Operating Officer and Chief Nuclear Officer of Virginia Electric and Power Company from May 1999 to April 2000; Senior Vice
President—Nuclear, June 1994 to May 1999. |
| M. Stuart Bolton, Jr. (48)
|
|
Senior Vice President—Financial Management of Virginia Electric and Power Company from January 2000 to date; Vice President and Controller of Virginia
Electric and Power Company from January 1999 to January 2000; Controller of Virginia Electric and Power Company, from January 1996 to January 1999. |
| David A. Christian (47)
|
|
Senior Vice President—Nuclear Operations and Chief Nuclear Officer from April 2000 to date; Vice President—Nuclear Operations from July 1998 to April
2000; Site Vice President—Surry from March 1998 to June 1998; Station Manager from September 1994 to March 1998. |
| G. Scott Hetzer (45)
|
|
Senior Vice President and Treasurer of Virginia Electric and Power Company and Consolidated Natural Gas Company from January 2000 to date; Senior Vice President
and Treasurer of Dominion Resources, Inc. from May 1999 to date; Vice President and Treasurer of Dominion Resources, Inc. from October 1997 to May 1999; Managing Director of Wheat First Butcher Singer prior to October 1997. |
72
| Name And Age
|
|
Business Experience Past Five Years
|
| E. Paul Hilton (58) |
|
Senior Vice President of Virginia Electric and Power Company from January 2000 to date; Vice President-Regulation of Virginia Electric and Power Company, September 1997 to
January 2000; Manager, Rates and Regulation of Virginia Electric and Power Company, February 1996 to October 1997. |
| Thomas A. Hyman, Jr (50)
|
|
Senior Vice President—Gas Distribution and Customer Services of Virginia Electric and Power Company from January 2002 to date; Senior Vice President—Gas
Distribution and Customer Services of Hope Gas, Inc., The East Ohio Gas Company and The Peoples Natural Gas Company from December 2001 to date; Senior Vice President—Gas Distribution of Hope Gas, Inc., The East Ohio Gas Company and The Peoples
Natural Gas Company from October 2000 to December 2001; Senior Vice President—Electric Distribution of Virginia Electric and Power Company from January 2000 to October 2000; Vice President and General Manager—Distribution of Virginia
Electric and Power Company from May 1999 to January 2000; Vice President—Distribution Operations and North Carolina Power of Virginia Electric and Power from June 1997 to April 1999. |
| Paul D. Koonce (42)
|
|
Senior Vice President—Portfolio Management of Virginia Electric and Power Company from January 2000 to date; Senior Vice President Commercial Operations of Consolidated
Natural Gas Company from January 1999 to date; Executive Vice President—Sonat Power Systems from August 1997 to January 1999; Executive Vice President-Sonat Marketing Company and Senior Vice President-Sonat Energy Services prior to August
1997. |
| Margaret E. McDermid (53)
|
|
Senior Vice President—Information Technology and Chief Information Officer of Virginia Electric and Power Company from January 2001 to date; Vice
President—Information Technology and Chief Information Officer of Virginia Electric and Power Company from October 1998 to January 2001; Manager—Information Systems and Client Services from December 1991 to October 1998.
|
| Edward J. Rivas (57)
|
|
Senior Vice President—Fossil & Hydro of Virginia Electric and Power Company from September 1999 to date; Vice President—Fossil & Hydro Operations of
Virginia Electric and Power Company from February 1998 to August 1999; Station Manager—Fossil (Clover) March 1994 to February 1998 |
| Jimmy D. Staton (41)
|
|
Senior Vice President—Electric Transmission and Electric Distribution of Virginia Electric and Power Company from December 2001 to date; Senior Vice
President—Electric Distribution of Virginia Electric and Power Company from October 2000 to date; Senior Vice President—Gas Distribution and Regulatory of Virginia Electric and Power Company from January 2000 to October 2000; Senior Vice
President of Hope Gas, Inc. and The Peoples Natural Gas Company from June 1999 to January 2000; Senior Vice President of The East Ohio Gas Company from April 1999 to January 2000; Vice President of Hope Gas, Inc. and The Peoples Natural Gas Company
from January 1999 to June 1999; Vice President of The East Ohio Gas Company from January 1999 to April 1999; Vice President and Treasurer of CNG Transmission Corporation from March 1997 to June 1999; Vice President of CNG Transmission Corporation
August 1996 to March 1997. |
73
| Name And Age
|
|
Business Experience Past Five Years
|
| Steven A. Rogers (40) |
|
Vice President, Controller and Principal Accounting Officer of Dominion Resources, Inc. and Consolidated Natural Gas Company and Vice President and Principal Accounting
Officer of Virginia Electric and Power Company from June 2000 to date; Controller of Virginia Electric and Power Company from January 2000 to May 2000; Controller of Dominion Energy, Inc. from September 1998 to June 2000; Vice President and
Controller of Optacor Financial Services Company from February 1997 through September 1998. |
There is no family relationship between any of the persons named in response to
Item 10.
74
Summary Compensation Table
The Summary Compensation Table below includes compensation paid by the Company for services rendered in 2001, 2000 and 1999
to the Chief Executive Officers and the four other most highly compensated executive officers (as of December 31, 2001) as determined under the SEC executive compensation disclosure rules.
Summary Compensation Table(1)
| |
|
|
|
|
|
|
|
|
|
Long Term Compensation Awards
|
|
|
|
|
| |
|
Annual Compensation
|
|
Restricted Stock Awards(4)
|
|
Securities Underlying Options/ SAR
|
|
Payouts
|
| Name & Principal Position
|
|
Year
|
|
Salary(2)
|
|
Bonus
|
|
Other Annual Compensation(3)
|
|
|
|
LTIP Pay Out
|
|
All Other Compensation(5)
|
| |
|
|
|
($) |
|
($) |
|
($) |
|
($) |
|
(#) |
|
($) |
|
($) |
| Edgar M. Roach, Jr. |
|
2001 |
|
$ |
334,664 |
|
$ |
279,098 |
|
$ |
66,550 |
|
$ |
495,525 |
|
298,500 |
|
$ |
0 |
|
$ |
145,541 |
| President and Chief |
|
2000 |
|
|
251,732 |
|
|
314,424 |
|
|
71,914 |
|
|
0 |
|
61,289 |
|
|
211,638 |
|
|
125,795 |
| Executive Officer |
|
1999 |
|
|
98,000 |
|
|
79,380 |
|
|
0 |
|
|
0 |
|
220,500 |
|
|
205,917 |
|
|
3,383 |
| |
| Thomas F. Farrell, II |
|
2001 |
|
|
328,498 |
|
|
273,955 |
|
|
58,197 |
|
|
489,154 |
|
351,600 |
|
|
0 |
|
|
135,728 |
| Chief Executive Officer |
|
2000 |
|
|
324,638 |
|
|
409,214 |
|
|
71,002 |
|
|
0 |
|
79,765 |
|
|
275,441 |
|
|
155,914 |
| |
|
1999 |
|
|
123,299 |
|
|
48,628 |
|
|
0 |
|
|
0 |
|
112,500 |
|
|
113,126 |
|
|
3,486 |
| |
| David A. Christian |
|
2001 |
|
|
285,900 |
|
|
183,977 |
|
|
24,675 |
|
|
397,571 |
|
190,600 |
|
|
0 |
|
|
64,343 |
| Senior Vice President - |
|
2000 |
|
|
183,484 |
|
|
158,064 |
|
|
24,183 |
|
|
0 |
|
33,832 |
|
|
93,655 |
|
|
31,211 |
| Nuclear Operations & Chief Nuclear Officer |
|
1999 |
|
|
142,950 |
|
|
109,607 |
|
|
0 |
|
|
0 |
|
53,368 |
|
|
19,564 |
|
|
4,289 |
| |
| James P. O’Hanlon |
|
2001 |
|
|
234,400 |
|
|
175,800 |
|
|
46,807 |
|
|
363,253 |
|
205,100 |
|
|
0 |
|
|
109,148 |
| President and Chief |
|
2000 |
|
|
268,570 |
|
|
305,690 |
|
|
56,667 |
|
|
0 |
|
64,926 |
|
|
221,045 |
|
|
127,595 |
| Operating Officer |
|
1999 |
|
|
243,400 |
|
|
100,637 |
|
|
0 |
|
|
0 |
|
192,500 |
|
|
115,951 |
|
|
355,800 |
| |
| Jimmy D. Staton (6) |
|
2001 |
|
|
260,000 |
|
|
117,000 |
|
|
34,100 |
|
|
300,500 |
|
100,000 |
|
|
0 |
|
|
81,284 |
| Senior Vice President -Elec Distr & Elec Trans |
|
2000 |
|
|
63,225 |
|
|
30,222 |
|
|
2,216 |
|
|
0 |
|
11,250 |
|
|
0 |
|
|
6,959 |
| |
| Edward J. Rivas |
|
2001 |
|
|
162,360 |
|
|
72,331 |
|
|
25,765 |
|
|
239,318 |
|
73,800 |
|
|
0 |
|
|
61,885 |
| Senior Vice President |
|
2000 |
|
|
208,634 |
|
|
191,836 |
|
|
34,912 |
|
|
0 |
|
40,000 |
|
|
102,264 |
|
|
81,475 |
| Fossil & Hydro |
|
1999 |
|
|
128,067 |
|
|
67,796 |
|
|
0 |
|
|
0 |
|
81,833 |
|
|
38,619 |
|
|
3,842 |
| |
| Robert E. Rigsby (7) |
|
2001 |
|
|
243,392 |
|
|
179,100 |
|
|
15,632 |
|
|
405,964 |
|
119,400 |
|
|
0 |
|
|
43,669 |
| President and Chief |
|
2000 |
|
|
220,077 |
|
|
165,163 |
|
|
14,244 |
|
|
0 |
|
16,320 |
|
|
175,845 |
|
|
33,936 |
| Operating Officer (retired) |
|
1999 |
|
|
231,727 |
|
|
161,841 |
|
|
0 |
|
|
0 |
|
262,500 |
|
|
229,352 |
|
|
4,800 |
(1) |
|
The executive officers included in this table may perform services for more than one subsidiary of Dominion. Compensation for the individuals listed in the table reflects only
that portion which is allocated to the Company. |
(2) |
|
Salary—Amounts shown may include vacation sold back to the Company. |
(3) |
|
Other Annual Compensation—None of the named executives above received perquisites or other personal benefits in excess of $50,000 or 10% of their total cash
compensation. The amounts listed in this column are tax payments made on behalf of the executive. |
75
(4) |
|
Restricted Stock Awards—The number and value of each executive’s restricted stock holdings at year-end, based on a December 31, 2001 closing price of
$60.10 per share, were as follows: |
| Officer
|
|
Number of Restricted Shares (*)
|
|
Value
|
|
Vesting Schedule
|
| |
|
(#) |
|
($) |
|
|
| Edgar M. Roach, Jr. |
|
2,275 |
|
$136,728 |
|
2 years |
| |
|
5,970 |
|
358,797 |
|
3 years |
| Thomas F. Farrell, II |
|
2,279 |
|
136,968 |
|
2 years |
| |
|
5,860 |
|
352,186 |
|
3 years |
| David A. Christian |
|
262 |
|
15,716 |
|
2 years |
| |
|
6,354 |
|
381,854 |
|
3 years |
| James P. O’Hanlon |
|
1,161 |
|
69,776 |
|
2 years |
| |
|
4,883 |
|
293,477 |
|
3 years |
| Jimmy D. Staton |
|
5,000 |
|
300,500 |
|
3 years |
| Edward J. Rivas |
|
292 |
|
17,549 |
|
2 years |
| |
|
3,690 |
|
221,769 |
|
3 years |
| Robert E. Rigsby(7) |
|
1,780 |
|
106,978 |
|
2 years |
| |
|
4,975 |
|
298,986 |
|
3 years |
| |
* Dividends |
|
are paid on restricted shares. |
(5) |
|
All Other Compensation—The amounts listed for 2001 are as follows: |
| Officer
|
|
Employee Savings Plan Match
|
|
Executive Stock Loan Program Interest Subsidy
|
|
Employee Savings Plan Match Above IRS Limits
|
| Edgar M. Roach, Jr. |
|
$ |
3,045 |
|
$ |
136,675 |
|
$ |
5,821 |
| Thomas F. Farrell, II |
|
|
2,989 |
|
|
126,059 |
|
|
6,680 |
| David A. Christian |
|
|
6,480 |
|
|
52,907 |
|
|
4,956 |
| James P. O’Hanlon |
|
|
2,989 |
|
|
102,174 |
|
|
3,985 |
| Jimmy D. Staton |
|
|
5,100 |
|
|
73,484 |
|
|
2,700 |
| Edward J. Rivas |
|
|
5,018 |
|
|
56,365 |
|
|
502 |
| Robert E. Rigsby |
|
|
3,980 |
|
|
34,197 |
|
|
5,492 |
(6) |
|
Mr. Staton was not an officer associated with Virginia Power prior to October 1, 2000. |
(7) |
|
At December 31, 2001, Mr. Rigsby was not serving as an executive officer of the Company but is listed in this table according to SEC disclosure rules. He retired from the
Company on February 1, 2002. |
76
Option/SAR Grants in Last Fiscal Year(1)
| Officer
|
|
Number of Securities Underlying Options/SARs Granted
|
|
Percent of Total Options/SAR’s Granted to Employees in Fiscal Year(3)
|
|
|
Exercise or Base Price
|
|
Expiration Date(4)
|
|
Grant Date Present Value(5)
|
| |
|
(#)(2) |
|
% |
|
|
($/Sh) |
|
|
|
$ |
| Edgar M. Roach, Jr. |
|
99,500 99,500 99,500 |
|
5.6 |
% |
|
$ |
59.96 |
|
1/01/08 1/01/09 1/01/10 |
|
$ |
1,078,580 1,089,525 1,099,475 |
| Thomas F. Farrell, II |
|
117,200 117,200 117,200 |
|
6.7 |
% |
|
$ |
59.96 |
|
1/01/08 1/01/09 1/01/10 |
|
|
1,270,448 1,283,340 1,295,060 |
| David A. Christian |
|
63,533 63,533 63,534 |
|
4.1 |
% |
|
$ |
59.96 |
|
1/01/08 1/01/09 1/01/10 |
|
|
688,698 695,686 702,051 |
| James P. O’Hanlon |
|
68,366 68,367 68,367 |
|
3.9 |
% |
|
$ |
59.96 |
|
1/01/08 1/01/09 1/01/10 |
|
|
741,087 748,619 755,455 |
| Jimmy D. Staton |
|
33,333 33,333 33,334 |
|
1.9 |
% |
|
$ |
59.96 |
|
1/01/08 1/01/09 1/01/10 |
|
|
361,330 364,996 368,341 |
| Edward J. Rivas |
|
24,600 24,600 24,600 |
|
1.4 |
% |
|
$ |
59.96 |
|
1/01/08 1/01/09 1/01/10 |
|
|
266,664 269,370 271,830 |
| Robert E. Rigsby(6) |
|
39,800 39,800 39,800 |
|
2.3 |
% |
|
$ |
59.96 |
|
1/01/08 1/01/09 1/01/10 |
|
|
431,432 435,810 439,790 |
(1) |
|
The executive officers included in the table may perform services for more than one company. Therefore, compensation for the individuals listed in the table reflects only that
portion which is allocated to the Company. |
(2) |
|
Nonstatutory stock options were granted on July 1, 2001 to the named executives at an exercise price of $59.96 per share which equaled 100% of the Fair Market Value of the
shares on the date of grant. The shares vest one-third per year on each January 1 of 2003, 2004 and 2005. |
(3) |
|
The total number of options granted in 2001 to Virginia Power employees was 5,286,860. Virginia Power has no outside directors. |
(4) |
|
Options granted expire five years from the vesting date. |
(5) |
|
The Black-Scholes pricing model was used to calculate the present value of the stock options. The assumptions underlying this model are: |
| |
|
Expiration Date
|
|
| |
|
1/01/08
|
|
|
1/01/09
|
|
|
1/01/10
|
|
| Volatility |
|
|
22.24 |
% |
|
|
22.24 |
% |
|
|
22.24 |
% |
| Risk Free Rate |
|
|
5.14 |
% |
|
|
5.24 |
% |
|
|
5.33 |
% |
| Dividend Yield Rate |
|
|
4.30 |
% |
|
|
4.30 |
% |
|
|
4.30 |
% |
| Option Value |
|
$ |
10.84 |
|
|
$ |
10.95 |
|
|
$ |
11.05 |
|
(6) |
|
At December 31, 2001 Mr. Rigsby was no longer serving as an executive officer of the Company. He retired from the Company on February 1, 2002. |
77
Aggregated Option/SAR Exercises in Last Fiscal Year(1)
And FY-End Option/SAR Values
| |
|
Shares Acquired on Exercise
|
|
Value Realized
|
|
Number of Securities Underlying Unexercised Options/SARs At FY-End
|
|
Value of Unexercised In-the-Money Options/SARs At FY-End
|
| Officer
|
|
|
|
Exercisable
|
|
Unexercisable
|
|
Exercisable(2)
|
|
Unexercisable
|
| |
|
(#) |
|
($) |
|
($) |
|
($) |
|
($) |
|
($) |
| Edgar M. Roach, Jr. |
|
0 |
|
$ |
0 |
|
268,650 |
|
298,500 |
|
$ |
5,064,053 |
|
$ |
41,790 |
| Thomas F. Farrell, II |
|
0 |
|
|
0 |
|
263,700 |
|
351,600 |
|
|
4,970,745 |
|
|
49,224 |
| David A. Christian |
|
0 |
|
|
0 |
|
63,215 |
|
195,524 |
|
|
1,149,758 |
|
|
98,577 |
| James P. O’Hanlon |
|
0 |
|
|
0 |
|
205,100 |
|
205,100 |
|
|
3,866,135 |
|
|
28,714 |
| Jimmy D. Staton |
|
0 |
|
|
0 |
|
25,000 |
|
100,000 |
|
|
350,250 |
|
|
14,000 |
| Edward J. Rivas |
|
0 |
|
|
0 |
|
41,328 |
|
73,800 |
|
|
779,033 |
|
|
10,332 |
| Robert E. Rigsby(3) |
|
89,550 |
|
|
1,547,514 |
|
119,400 |
|
119,400 |
|
|
2,250,690 |
|
|
16,716 |
(1) |
|
The executive officers included in this table may perform services for more than one subsidiary of Dominion. Compensation for individuals listed in the table reflects only that
portion which is allocated to the Company. |
(2) |
|
Spread between the market value at year-end minus the exercise price. Year-end stock price was $60.10 per share. |
(3) |
|
At December 31, 2001 Mr. Rigsby was no longer serving as an executive officer of the Company. He retired from the Company on February 1, 2002. |
Executive Compensation
The
Company’s executive compensation program is recommended to the Company’s board by the Organization, Compensation and Nominating Committee (Dominion’s Committee) of Dominion’s board. Dominion’s Committee works with outside
consultants to develop programs that will attract, retain and motivate high caliber employees.
Annual Incentive
Under the annual incentive program, if goals are achieved or exceeded, the executive’s total cash compensation for the year is targeted to be
between the median and 75th percentile of total cash compensation for similar positions at companies in our executive
labor market.
Under this program, “target awards” are established for each executive officer. These target awards are
expressed as a percentage of the individual executive’s base salary (for example, 40% x base salary). The target award is the amount of cash that will be paid at year-end if the executive achieves 100% of the goals established at the beginning
of the year. A “threshold” – or minimum acceptable level of financial performance – is established, and if this threshold is not met, no executive receives an annual incentive payment. Actual payments, if any, are based on a
pre-established formula and may exceed 100% of the target award. Annual bonuses paid to the named executives are detailed in the Summary Compensation Table.
Long-term Incentives
The Company’s long-term incentive programs play a critical part in its compensation
practices and philosophy. Long-term incentives for 2001 focused on stock ownership in the form of stock options and restricted stock. Options were granted at 100% of the fair market value of Dominion’s stock price on the date of grant. The
combination of options and restricted stock provide balance to the Company’s long-term incentive program in 2001 and underscores commitment to the Company while rewarding performance.
78
Stock Ownership Guidelines
In 2000, stock ownership guidelines were established for the Company’s executive officers. These guidelines place an emphasis on stock ownership that aligns management with the
interests of Dominion shareholders. Officers have up to five years to meet the guidelines outlined below. In addition, in 2001, Dominion’s Committee established an Executive Stock Purchase Tool Kit (which is described below) to assist Company
executives in meeting the guidelines. As reported under the Share Ownership Table, the named executive officers have met these guidelines.
Dominion Resources, Inc.
Stock Ownership Guidelines
| Positions
|
|
Share Ownership
|
| CEO/COO-Operating Companies |
|
35,000 |
| Senior Vice President |
|
20,000 |
| Vice President |
|
10,000 |
Retirement Plans
The table below shows the estimated annual straight life benefit that the Company would pay to an employee at normal retirement (age 65) under the benefit formula of the Retirement Plan.
Estimated Annual Benefits Payable Upon Retirement
| |
|
Credited Years Of Service
|
| Final Average Earnings
|
|
15
|
|
20
|
|
25
|
|
30
|
| $185,000 |
|
$ |
5,810 |
|
$ |
60,966 |
|
$ |
76,122 |
|
$ |
91,278 |
| $200,000 |
|
|
49,888 |
|
|
66,394 |
|
|
82,900 |
|
|
99,406 |
| $250,000 |
|
|
63,481 |
|
|
84,487 |
|
|
105,493 |
|
|
126,499 |
| $300,000 |
|
|
77,073 |
|
|
102,579 |
|
|
128,085 |
|
|
153,591 |
| $350,000 |
|
|
90,666 |
|
|
120,672 |
|
|
150,678 |
|
|
180,684 |
| $400,000 |
|
|
104,258 |
|
|
138,764 |
|
|
173,270 |
|
|
207,776 |
Benefits under the Retirement Plan are based on:
| |
• |
|
highest average base salary over a five-year period during the ten years preceding retirement; |
| |
• |
|
years of credited service; |
| |
• |
|
the offset of Social Security benefits. |
In 2001, the Company introduced a Special Retirement Account (SRA) feature to the Pension Plan. This account is credited with 2% of an employee’s base salary earned during the year. Account balances grow with interest based on the
30-year Treasury Bond rate. The impact of this feature is reflected in the above table.
In addition, certain officers, if they
reach a specified age while still employed, will be credited with additional years of service. Each of the named executives in the Summary Compensation Table, except for Mr. Staton, will have 30 years of credited service at age 60. Other
retirement agreements and arrangements for the named executives are described below under Other Executive Agreements and Arrangements.
Benefit
Restoration Plan
The Retirement Plan pays a benefit that is calculated on average base salary over a five-year period. In
some years our executives’ base salaries were set below the competitive market median in order to more closely link
79
annual pay to Company performance through the incentive programs. In connection with the Restoration Plan, we calculate a “market-based adjustment” to base salary in those years when
base salary was below the market median. The difference between the benefit calculated on the market-based salary and the benefit provided by the Retirement Plan is paid to the executive under the Restoration Plan.
In 2001, a market-based adjustment to executive base salaries was not necessary.
Also, the Internal Revenue Code imposes certain limits related to Retirement Plan benefits. Any resulting reductions in an executive’s Retirement Plan benefit will be compensated
for under the Restoration Plan.
Executive Supplemental Retirement Plan
The Supplemental Plan provides an annual retirement benefit equal to 25 percent of a participant’s final cash compensation (base pay plus target annual incentive). To retire with
full benefits under the Supplemental Plan, an executive must be 55 years old and have been employed by the Company for at least five years. Benefits under the plan are provided either as a lump sum cash payment at retirement or as a monthly annuity
typically paid over 10 years. Certain executive officers receive this benefit for their lifetime. Based on 2001 cash compensation, the estimated annual benefit under this plan for certain executives named in the Summary Compensation Table are: Mr.
Roach—$151,862; Mr. Farrell—$149,064; Mr. Christian—$117,934; Mr. O’Hanlon—$102,550; Mr. Staton—$94,250; Mr. Rivas—$58,856; Mr. Rigsby—$104,475.
Other Executive Agreements and Arrangements
Companies that are in a rapidly
changing industry require the expertise and loyalty of exceptional executives. Not only is the business itself competitive, but so is the demand for such executives. In order to secure the continued services and focus of key management executives,
the Company has entered into certain agreements with them, including those named in the Summary Compensation Table.
Each of
Messrs. Roach, Farrell, O’Hanlon or Christian have enhanced retirement benefits as well as employment continuity agreements as described below under Special Arrangements.
Mr. Staton has an employment agreement with the Company’s parent, Dominion, for a three-year period ending on August 1, 2003. During the term of the agreement, Mr. Staton will
continue to receive a salary at least equal to his salary on the date of the agreement and will be eligible for bonuses and all employee benefits provided to senior management. The agreement also provides for enhanced retirement benefits and
benefits in the event of death or disability. If Mr. Staton’s employment is terminated without cause or if his salary, incentives or benefits are reduced or not paid, or he is demoted to a position that is not a senior management position, he
will, subject to notice and remedy provisions: (1) receive a lump sum payment equal to the present value of salary and cash bonus for the balance of the contract period, (2) vest in his outstanding restricted stock and (3) receive continued benefit
plan coverage through the end of the contract period. In addition, as of the effective date of Mr. Staton’s employment agreement, a payment was made into an account created by him in the Dominion Resources, Inc. Executives’ Deferred
Compensation Plan. This payment was made in lieu of Mr. Staton’s right to receive payment under his change in control agreement with CNG. If Mr. Staton’s employment is terminated for any reason, he will receive payment of the deferred
amount together with payment of his benefits under the Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas Company and its Participating Subsidiaries Who Are Not Represented by a Recognized Union. These amounts will be paid
in lieu of severance benefits under any severance program maintained by Dominion (except for benefits specifically provided for under his employment continuity agreement as described below).
Mr. Rigsby resigned from his officer position with the Company and its subsidiaries effective December 1, 2001, and retired effective February 1, 2002. In accordance with employment and
retirement agreements, he
80
received a lump sum payment equal to 18 months salary and accelerated vesting and extended expiration dates on options he held. He also received other enhanced retirement and miscellaneous
benefits.
Special Arrangements
Executives named in the Summary Compensation Table have entered into employment continuity agreements, which provide benefits in the event of a change in control. Each agreement has a three-year term and is automatically extended for an
additional year, unless cancelled by the Company.
The agreements provide for the continuation of salary and benefits for a
maximum period of three years after either (1) a change in control, (2) termination without cause following a change in control, or (3) a reduction of responsibilities, salary and incentives following a change in control (if the executive gives 60
days notice). Payment of this benefit will be made in either a lump sum or installments over three years. In addition, the agreements indemnify the executives for potential penalties related to the Internal Revenue Code and fees associated with the
enforcement of the agreements. If an executive is terminated for cause, the agreements are not effective.
Messrs. Roach,
Farrell, and Christian also have Supplemental Agreements with Dominion providing each of them with a lump sum payment of up to 12 months base salary upon retirement in consideration for their agreement not to compete with any activities of Dominion
nor solicit any employees of Dominion during their employment and for a period of two years following termination of their employment.
For purposes of the continuity agreements described above, a change of control shall be deemed to have occurred if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or
(ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, a merger or other business combination, sale of assets, or contested election, the Directors constituting the Dominion Board before any such transactions
cease to represent a majority of Dominion or its successor’s Board within two years after the last of such transactions.
Executive Deferred
Compensation Plan
Under this plan, executives may defer a portion of their cash compensation. Deferrals are credited at the
executive’s discretion, for bookkeeping purposes, with earnings and losses as if they were invested in any of several mutual fund options, or Dominion common stock. Distributions are made at the direction of the executive.
Executives may also defer gains received as a result of a stock option exercise. Stock option gain deferrals must be invested in Dominion
common stock. Under this Plan, the Company also credits the accounts of eligible executives with the amount of “lost” company matching contributions under the Company’s Employee Savings Plan as a result of Internal Revenue Code
Section 401(a)(17).
Executives may elect to defer their benefits under both the Executive Supplemental Retirement Plan and the
Benefit Restoration Plan if they choose to receive these payments in the form of a lump sum at retirement.
Executive Stock Purchase and Loan Program
At the end of 1999, Dominion’s Board approved target levels of stock ownership for executives. The Board also approved
a Stock Purchase and Loan Program intended to encourage and facilitate executives’ ownership of common stock through the availability of loans guaranteed by Dominion.
Under the Program, loans must be used to purchase Dominion common stock. An executive may borrow up to ten times his or her base salary, subject to credit approval, with a term of five
years. Executives who meet their
81
target ownership level through their participation in the Program receive “bonus shares” equal to five percent of the number of shares purchased under the Program. The dividends on the
stock purchased through the program are used to pay the interest on the loan. The interest payments are subsidized to the extent that the current dividend rate does not fully cover the payments. The subsidy of the loan will end if it is pre-paid or
if the stock is sold. As of December 31, 2001, Dominion officers have borrowed in aggregate $84.1 million, for which they are personally liable and which Dominion has guaranteed.
Executive Stock Purchase Tool Kit
During 2001, the executive stock ownership guidelines
were reconfirmed. Dominion’s Board of Directors approved the implementation of the Executive Stock Purchase Tool Kit (“Tool Kit”) to encourage ownership of Dominion stock by executives who could not participate in the Executive Stock
Purchase and Loan Program offered in 2000. The Tool Kit consists of a variety of programs, including bonus deferrals into Dominion stock, restricted stock exchanges, stock purchases through Dominion Direct and the availability of loans guaranteed by
Dominion. Executives who participate in one or more of the Tool Kit programs to achieve their stock ownership target levels receive “bonus shares” up to ten percent of the value of their investment in Dominion stock.
Compensation of Directors
All of the
Directors, who are also officers of the Company, do not receive any compensation for services they provide as directors.
The
table below sets forth as of March 1, 2002, except as noted, the number of shares of Dominion common stock owned by Directors and the executive officers named on the Summary Compensation Table.
|
|
Beneficial Share Ownership
|
|
|
| Name
|
|
Shares
|
|
Restricted Shares
|
|
Exercisable Stock Options
|
|
Total
|
|
Deferred Cash Compensation(1)
|
| Thos. E. Capps(2) |
|
326,309 |
|
16,667 |
|
1,233,000 |
|
1,575,976 |
|
— |
| Thomas F. Farrell II(2) |
|
142,915 |
|
10,000 |
|
450,000 |
|
602,915 |
|
— |
| Edgar M. Roach Jr. |
|
141,964 |
|
10,000 |
|
450,000 |
|
601,964 |
|
1,593 |
| James P. O’Hanlon |
|
103,500 |
|
8,333 |
|
350,000 |
|
461,833 |
|
— |
| David A. Christian |
|
24,044 |
|
6,667 |
|
71,500 |
|
102,211 |
|
— |
| Jimmy D. Staton |
|
21,309 |
|
5,000 |
|
8,333 |
|
34,642 |
|
— |
| Robert E. Rigsby(3) |
|
52,432 |
|
11,893 |
|
350,000 |
|
414,325 |
|
— |
| Edward J. Rivas |
|
46,962 |
|
5,000 |
|
81,833 |
|
133,795 |
|
— |
| All officers as a group (15 persons)(4) |
|
1,066,635 |
|
108,560 |
|
3,457,826 |
|
4,633,021 |
|
1,593 |
(1) |
|
Amounts in this column represent share equivalents and do not have voting rights. At a director’s or executive’s election, cash compensation is deferred until a
specified age, future date or retirement and will be distributed in cash. |
(2) |
|
Messrs. Capps and Farrell disclaim ownership for 323 and 399 shares, respectively. |
(3) |
|
Mr. Rigsby’s ownership is reported as of December 1, 2001, the date he ceased to be an executive. |
(4) |
|
All directors and executive officers as a group own approximately 1.7 percent of the number of shares outstanding at March 1, 2002. |
82
See Item 11. EXECUTIVE
COMPENSATION—Executive Stock Purchase and Loan Program, for information concerning certain transactions with executive officers under the Executive Stock Purchase and Loan Program.
The Company leases fiber optic capacity to Dominion Telecom, Inc. at rates subject to the approval of the Virginia Commission. For additional information on this matter, see Note 21 to
the Consolidated Financial Statements.
83
PART IV
(a) The following documents are filed as part of this Form 10-K:
1. Financial Statements
See Index on page
.
2. Financial
Statement Schedules
| |
|
Page
|
| Independent Auditors’ Report on Financial Statement Schedule |
|
88 |
| Schedule II—Valuation and Qualifying Accounts |
|
89 |
All other schedules are omitted because they are not applicable, or the required
information is shown in the financial statements or the notes thereto.
3. Exhibits
| |
| 3.1 — |
|
Restated Articles of Incorporation, as amended, as in effect on May 6, 1999 (Exhibit 3.1), Form 10-Q for the period ended March
31, 1999, File No. 1-2255, incorporated by reference) as amended December 12, 2001 and December 18, 2001 (filed herewith). |
| |
| 3.2 — |
|
Bylaws, as amended, as in effect on April 28, 2000 (Exhibit 3, Form 10-Q for the period ended March 31, 2000, File No.
1-2255, incorporated by reference). |
| |
| 4.1 — |
|
See Exhibit 3 (i) above. |
| |
| 4.2 — |
|
Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures
(Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by
reference and Seventieth Supplemental Indenture (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture
(Exhibit 4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth
Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 6, 1993, File No. 1-2255, incorporated by
reference); Seventy-Sixth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated June 8, 1993, File No.
1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Ninth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated August
10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1- 2255, incorporated by reference); Eighty-First Supplemental Indenture (Exhibit 4(iii), Form 10-K for
the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture (Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1-2255, incorporated by reference); Eighty-Third Supplemental
Indenture (Exhibit 4(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference); Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 22, 1995, File No. 1-2255, incorporated by reference; and
Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference). |
84
| |
| 4.3 — |
|
Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase
Manhattan Bank and Chemical Bank) (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference). |
| |
| 4.4 — |
|
Indenture, dated April 1, 1988, between Virginia Electric and Power Company JP Morgan Chase Bank (formerly The Chase Manhattan
Bank and Chemical Bank), as supplemented and modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Second Supplemental
Indenture (Exhibit 4.2, Form S-3, dated April 13, 1999, File No. 333-76155, incorporated by reference). |
| |
| 4.5 — |
|
Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and JP Morgan Chase Bank
(formerly The Chase Manhattan Bank and 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). |
| |
| 4.6 — |
|
Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and JP Morgan Chase Bank
(formerly 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); Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999, File No. 1- 2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated March
22, 2001, File No. 1-2255, incorporated by reference); and Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2,
Form 8-k, dated January 24, 2002, incorporated by reference). |
| |
| 4.7 — |
|
Virginia Electric and Power Company agrees to furnish to the Commission upon request any other instrument with respect to long-
term debt as to which the total amount of securities authorized thereunder does not exceed 10 percent of Virginia Electric and Power Company’s total assets. |
| |
| 10.1 — |
|
Amended and Restated Interconnection and Operating Agreement, dated as of July 29, 1997 between Virginia Electric and Power
Company and Old Dominion Electric Cooperative (Exhibit 10.3, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255 incorporated by reference). |
| |
| 10.2 — |
|
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). |
| |
| 10.3 — |
|
Support Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company effective January 1, 2000
(Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference). |
| |
| 10.4 — |
|
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) |
| |
| 10.5*— |
|
Description of arrangements with certain officers regarding additional credited years of service for retirement purposes (Exhibit
10 (xii), Form 10-K for the fiscal year ended December 31, 1992, File No. 1-2255, incorporated by reference). |
85
| |
| 10.6* — |
|
Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 1981 as amended and restated September 1,
1996 (with amendment dated June 20, 1997 and amendment dated March 3, 1998 (Exhibit 10.14, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference); amendment dated November 26, 2001 (filed
herewith). |
| |
| 10.7* — |
|
Dominion Resources, Inc.’s Cash Incentive Plan as adopted December 20, 1991 (Exhibit 10 xxv), Form 10-K for the fiscal
year ended December 31, 1994, File No. 1-2255, incorporated by reference). |
| |
| 10.8* — |
|
Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September 1, 1996 (Exhibit
10.16, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference). |
| |
| 10.9* — |
|
Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective January 1, 1991 as amended and restated
September 1, 1996 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 1997, File No. 1-2255, incorporated by reference); amendment dated November 26, 2001 (filed herewith). |
| |
| 10.10* — |
|
Dominion Resources, Inc. Executives’ Deferred Compensation Plan, effective January 1, 1994 and as amended and restated
effective December 1, 2001 (filed herewith). |
| |
| 10.11* — |
|
Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001
(Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001, File No. 1-8489, incorporated by reference). |
| |
| 10.12* — |
|
Employment Agreement dated September 15, 1995 between Virginia Power and Robert E. Rigsby (Exhibit 10 (xxii), Form 10-K for the
fiscal year ended December 31, 1996, File No. 1-2255, incorporated by reference) and clarification letter dated May 27, 1997 (filed herewith). |
| |
| 10.13* — |
|
Form of an Employment Agreement dated March 16, 1998 between Virginia Power and certain executive officers (Exhibit 10.1, Form
10-Q for the period ended March 31, 1998, File No. 1-2255, incorporated by reference). [The only material respect in which the particular employment agreements differ is the base salary set forth therein.] |
| |
| 10.14* — |
|
Employment Agreement dated September 12, 1997 between Dominion and Thomas F. Farrell, II (Exhibit 10.24, Form 10-K for the fiscal
year ended December 31, 1998, File No. 1-2255, incorporated by reference) expired September 12, 2000, except Section 5c. |
| |
| 10.15* — |
|
Form of Employment Continuity Agreement for certain officers of the Company including Messrs. Roach, Farrell, Christian,
O’Hanlon, Staton, Rivas and Rigsby, (Exhibit 10.2, Form 10-Q for the period ended June 30, 1999, File No. 1-2255, incorporated by reference) and as amended October 19, 2001 (filed herewith). |
| |
| 10.16* — |
|
Employment Agreement dated September 12, 1997, between Dominion and Edgar M. Roach, Jr. (Exhibit 10(xxxiv) Form 10-K for fiscal
year ended December 31, 1997, File No. 1-8489, incorporated by reference) expired September 12, 2000, except Section 5c. |
| |
| 10.17* — |
|
Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001
(Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001, File No. 1-8489, incorporated by reference). |
| |
| 10.18* — |
|
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001 (Exhibit 10.1, Form 10-Q for the
quarter ended September 30, 2001, File No. 1-8489, incorporated by reference). |
| |
| 10.19* — |
|
Form of Executive Supplemental Retirement Plan Lifetime Benefits for certain officers of the Company including Messrs. Roach,
Farrell, and Rigsby (filed herewith). |
86
| |
| 10.20* — |
|
Supplemental Agreement dated December 12, 2000, between the Company and Thomas F. Farrell, II (filed
herewith). |
| |
| 10.21* — |
|
Supplemental Agreement dated December 12, 2000, between the Company and Edgar M. Roach, Jr. (filed
herewith). |
| |
| 10.22* — |
|
Offer of employment dated May 26, 1989 between the Company and James P. O'Hanlon, as amended September 18, 1997 (filed
herewith). |
| |
| 10.23* — |
|
Retirement Agreement dated November 16, 2000 with Robert E. Rigsby (filed herewith). |
| |
| 10.24* — |
|
Employment Agreement dated August 1, 2000 between the Company and Jimmy D. Staton (filed herewith) |
| |
| 10.25* — |
|
Supplemental Retirement Agreement dated December 12, 2000, between the Company and David A. Christian (filed
herewith). |
| |
| 18 — |
|
Letter re change in accounting principles (Exhibit 18, Form 10-Q for the period ended September 30, 2000, File No. 1-2255,
incorporated by reference). |
| |
| 23.1 — |
|
Consent of McGuireWoods LLP (filed herewith). |
| |
| 23.2 — |
|
Consent of Jackson & Kelly (filed herewith) |
| |
| 23.3 — |
|
Consent of Deloitte & Touche LLP (filed herewith). |
* |
|
Indicates management contract or compensatory plan or arrangement |
(b) Reports on Form 8-K
(1) The Company filed a report
on Form 8-K, dated January 18, 2002, relating to the Virginia Commission’s Order on Functional Separation.
(2) The Company filed a report on Form 8-K, dated January 29, 2002, relating to Dominion’s press release announcing unaudited results of operations for the fiscal year ended December 31, 2001.
87
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors of
Virginia Electric and Power Company
Richmond, Virginia
We have audited the consolidated
financial statements of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc) and subsidiaries (the Company) as of December 31, 2001 and 2000, and for each of the three years in the period ended December 31,
2001, and have issued our report thereon dated January 22, 2002, which report includes an explanatory paragraph as to a change in accounting principle for derivative instruments and hedging activities in 2001 and a change in the method of accounting
used to develop the market-related value of pension plan assets in 2000; such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of Virginia
Electric and Power Company and subsidiaries, listed in Item 14. This consolidated financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion,
such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Richmond, Virginia
January 22,
2002
88
VIRGINIA ELECTRIC AND POWER COMPANY
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
| Column A
|
|
|
|
Column B
|
|
Column C
|
|
Column D
|
|
|
Column E
|
| |
|
|
|
|
|
Additions
|
|
|
|
|
|
| Description
|
|
|
|
Balance at beginning of period
|
|
Charged to expense
|
|
|
Charge to other accounts
|
|
Deductions
|
|
|
Balance at end of period
|
| |
|
(millions) |
| Valuation and qualifying accounts which are deducted in the balance sheet from the assets to which the apply:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Allowance for doubtful accounts |
|
1999 |
|
$ |
5 |
|
$ |
19 |
|
|
— |
|
$ |
12 |
(a) |
|
$ |
12 |
| |
|
2000 |
|
|
12 |
|
|
18 |
|
|
— |
|
|
14 |
(a) |
|
|
16 |
| |
|
2001 |
|
|
16 |
|
|
18 |
|
|
— |
|
|
11 |
(a) |
|
|
23 |
| Valuation allowance for commodity contracts |
|
1999 |
|
|
13 |
|
|
9 |
(b) |
|
— |
|
|
— |
|
|
|
22 |
| |
|
2000 |
|
|
22 |
|
|
(3 |
)(b) |
|
— |
|
|
— |
|
|
|
19 |
| |
|
2001 |
|
|
19 |
|
|
7 |
(b) |
|
— |
|
|
— |
|
|
|
26 |
| Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Liability for pre—2000 workforce reductions |
|
1999 |
|
|
16 |
|
|
— |
|
|
— |
|
|
12 |
(c) |
|
|
4 |
| |
|
2000 |
|
|
4 |
|
|
— |
|
|
— |
|
|
4 |
(c) |
|
|
— |
| |
|
2001 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
| Liabilities for restructuring costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| 2000 Plan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Severance and related costs |
|
1999 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
| |
|
2000 |
|
|
— |
|
|
14 |
|
|
— |
|
|
8 |
(c) |
|
|
6 |
| |
|
2001 |
|
|
6 |
|
|
(1 |
)(b) |
|
— |
|
|
5 |
(c) |
|
|
— |
| 2001 Plan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Severance and related costs |
|
1999 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
| |
|
2000 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
| |
|
2001 |
|
|
— |
|
|
16 |
|
|
— |
|
|
— |
|
|
|
16 |
(a) |
|
Represents net amounts charged off as uncollectible. |
(b) |
|
Represents adjustments reflecting changes in estimates. |
(c) |
|
Represents payments for workforce reductions and/or restructuring liabilities. |
89
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
| VIRGINIA ELECTRIC AND POWER COMPANY |
| |
| BY: |
|
/s/ THOS E. CAPPS
|
| |
|
(THOS. E. CAPPS. Chairman of the Board of Directors) |
Date March 11, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on the 11th day of March, 2002.
| Name
|
|
Position
|
| /s/ THOS. E. CAPPS
Thos. E. Capps |
|
Chairman of the Board of Directors |
| |
| /s/ EDGAR M. ROACH, JR.
Edgar M. Roach, Jr. |
|
President, Chief Executive Officer and Director |
| |
| /s/ THOMAS F. FARRELL, II
Thomas F. Farrell, II |
|
Chief Executive Officer and Director |
| |
| /s/ G. SCOTT HETZER
G. Scott Hetzer |
|
Senior Vice President and Treasurer (Principal Financial Officer) |
| |
| /s/ STEVEN A. ROGERS
Steven A. Rogers |
|
Vice President (Principal Accounting Officer) |
90