ML18151A415
| ML18151A415 | |
| Person / Time | |
|---|---|
| Site: | Surry, North Anna  |
| Issue date: | 03/26/1997 |
| From: | Ohanlon J VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.) |
| To: | NRC (Affiliation Not Assigned) |
| References | |
| 97-173, NUDOCS 9704020089 | |
| Download: ML18151A415 (69) | |
Text
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VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 March 26, 1997 Director, Nuclear Reactor Regulation United States Nuclear Regulatory Commission Washington, D. C. 20555 Gentlemen:
VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 NORTH ANNA POWER STATION UNITS 1 AND 2 PRICE-ANDERSON ACT Serial No.97-173 NURPC Docket Nos. 50-280 50-281 50-338 50-339 License Nos. DPR-32
- DPR-37 NPF-4 NPF-7 Pursuant to 10 CFR 140.21 (e) regarding guarantees of payment of deferred premiums, we are providing the following information:
- 1.
Comparative Statements of Income for the three months ended December 31, 1996 and 199.5.
- 2.
Internal cash flow projection for calendar year 1997 with certification by an officer of the Company.
- 3.
Statement ensuring availability of funds for payment of retrospective premiums without curtailment of required nuclear construction expenditures.
- 4.
A copy of the Annual Report to Securities and Exchange Commission on Form 10-K for 1996.
In accordance with 10 CFR 140.7, we submitted a check to the NRC for $1,000 on November 21, 1996, which is the minimum required premium for the period November 15, 1996, through November 14, 1997.
Very truly yours,
~?~
James P. O'Hanlon Senior Vice President - Nuclear r
9704020009 970326~-*
I PDR ADOCK 05000280.
I
- PDR Enclosures
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I 1111111111111111111111111111111111111111111111111111111 9
7 II.
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U. S. Nuclear Regulatory Commission Region II 101 Marietta Street, N. W.
Suite 2900 Atlanta, Georgia 30323
@ U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D. C. 20555 Mr. R. A. Musser NRC Senior Resident Inspector Surry Power Station NRC Senior Resident Inspector North Anna Power Station
e VIRGINIA ELECTRIC & POWER COMPANY STATE1\\.1ENTS OF INCOME Operating revenues Operating expenses:
Operation:
Fuel, net Purchased power capacity, net Other Maintenance Depreciation and amortization Restructuring (Unaudited)
Amortization of terminated construction project costs Taxes - Income
- Other Total Operating income Other income Income before interest charges Interest charges:
Interest on long-term debt Other Allowance for borrowed funds used during construction Total Distribution - preferred securities of subsidiary trust, net Net income Preferred dividends Balance available for Common Stock Three Months Ended December 31, 1996 1995 (Millions)
$1,011.6 241.6 161.5 142.3 63.9 126.0 62.4 8.6 23.7 59.9 889.9 121.7 1.5 123.2
- 70.2 5.8 (0.3) 75.7 1.8
$1,026.3 237.1 170.2 144.2 57.8 120.0 82.0 8.6 25.0 62.5 907.4 118.9 (0.9) 118.0 74.9 4.2 (0.9) 78.2 1.8 45.7 38.0 8.8 9.2
$36.9
$28.8
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Virginia Electric & Power Company 1997 Estimated Internal Cash Flow (Millions ofDollars)
Jan Apr Jul Oct Estimated thru thru thru thru 1997 M!!r Jyn
~
~
Tot!!l Cash Receipts
$1,176.9
$1,020.7
$1,260.7-
$1,099.6 *
$4,557.9 Less:
Cash for Operations 632.8 615.5 654.0 642.8 2,545.1 Taxes 33.6 153.4 106.5 180.1 473.6 Interest 80.1 65.3 77.5 62.0 284.9 Dividends 111.7 111.7 111.7 111.7 446.8 Decommissioning Trust 9.1 9.1 9.1 9.1 36.4 Changes in Working Capital 30.2 10.4 60.3 28.6
~
Total Cash Flow (1)
S222.i W.l
~
~
~
(1) Before Financing and Construction Requirements.
H:\\FPB\\PLANNING\\1997\\BUDGEnDATA\\7CASH\\PRICEFNL.WK4 03/11/97
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VIRGINIA ELECTRIC AND POWER COMPANY CERTIFICATE I, the undersigned M. S. Bolton, Jr., do hereby certify, pursuant to the guarantee requirements set forth in the Commission's letter dated June 15, 1977, that the cash flow projection for 1997, provided herewith, is based on the best available information known at this time and is a reasonably accurate projection of the Company's 1997 cash flow.
Commonwealth of Virginia City of Richmond Sworn to and subscribed before me this l~ day of (Y\\u-l,V\\....-1997.
t{1_µ__q_~
Notary Public My commission expires: & / :5o [ 'I ~
NOTARIAL SEAL M. S. Bolton, Jr.
Controller
e VIRGINIA ELECTRIC AND POWER COMPANY STATEMENT The Company currently estimates 1997 construction and nuclear fuel expenditures (exclusive of Allowance for Funds Used During Construction) to be $529 million. Debt maturities in 1997 will total $311.3 million.
It is expected that approximately $642 million will be obtained from internal sources. The remaining $198.3 million of capital requirements will be obtained by a combination of sales of securities and short-term borrowings. The Company is reasonably assured that, based on the best available cash flow projections which are provided herewith, curtailment of capital expenditures f~r required nuclear programs would not be required to cover the Price-Anderson maximum retrospective premium assessment for a single incident of $326.8 million
($81.7 million, including a 3 percent insurance premium tax for Virginia, for each of the four reactors owned by the Company with assessments not to exceed $10.3 million per reactor per year) currently in force.
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Form lO~K (Mark One).
lg]
.D ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(0) OF'THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 or TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(0) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-2255 VIRGINIA ELECTRIC AND POWEP-COMPANY (Exact name of registrant as specified in its chaner)
VIRGINIA (State or other jurisdiction oF
'incorporation or organization) 701 East Cary Street
. Richmond, Virginia
.. ( Address of principal executive offices)
(804) 771-3000 54-0418825
- (l.R.S. Employer.
Identification no.).
23219-3932
.(Zip Code) *
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Preferred Stock (cumulative)
$ I 00 liquidation value:* *
$5.00 dividend Trust Preferred Securities.
$25 liquidation value:
8.05% dividend
- Name of each exchange on which registered New York Stock Exchange
- New York Stock Exchange..,**
Securities registered pursuant to. Section 12(g) of the Act:
None (Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for.such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the.past 90 days. Yes Y" No
- .* Indicate by check mark if disclosure of delinquent filers pursuant to Iteµi 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitiye proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Y" The aggregate market value of the voting stock held by non-affiliates of the registrant as of February 28, 1997 was zero.
As of February 28, 1997, 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
- -- l
VIRGINIA ELECTRIC AND POWER COMPANY Item Nwnber PART I
- 1. Business...........................................................................................................................................................................................
The Company..............................................................................................................................................................................
Regulation....................................................................................................................................................................................
General.....................................................................................................................................................................................
Virginia....................................................................................................................................................................................
North Carolina.........................................................................................................................................................................
FERC...................... **................ *...............................................................................................................................................
Environmental..........................................................................................................................................................................
Nuclear........................................................ :...........................................................................................................................
Capital Requirements and Financing Program...........................................................................................................................
Construction and Nuclear Fuel Expenditures.........................................................................................................................
Financing Program..................................................................................................,........................................ :......................
Rates.................................................................................. ***********************************************************************************************************
FERC........................................................................................................................................................................................
Virginia....................................................................................................................................................................................
North Carolina............................................ *............................................................................................................................
Sources of Power........................................................................................................................................................................
Company Generating Units.....................................................................................................................................................
Net Utility Purchases..,...........................................................................................................................................................
Non-Utility Generation................... :................................................................................................................... '...... :..............
Sources of Energy Used and Fuel Costs..................................*.................................................................................................
Nuclear Operations and Fuel Supply.....................................................................................................................................
Fossil Operations and Fuel Supply.........................................................................................................................................
Purchases and Sales of Power................................................................................................................................................
Interconnections............................................................................................................................ *............. *................................
Future Sources of Power.............................................................................................................................................................
Company Owned.Generation...................................................................................................... :'...........................................
Non-Utility Generation............................................................................................................................................................
Competition and Strategic Initiatives.........................................................................................................................................
Conservation and Load Management.........................................................................................................................................
- 2. Properties........................................................................ *................................................................................................................
- 3. Legal Proceedings...........................................................................................................................................................................
- 4. Submission of Matters to a Vote of Security Holders....................... :..........................................................................................
PART II
- 5. Market for the Registrant's Common Equity and Related Stockholder Matters.........................................................................
- 6. Selected Financial Data..................................................................................................................................................................
- 7. Management's Discussion and Analysis.of Financial Condition and Results of Operations........................ :............................
Liquidity and Capital Resources.................................................................................................................................................
Capital Requirements..................................................................................................................................................................
Results of Operations..................................................................................................................................................................
Future Issues................................................................................................................................................................................
- 8. Financial Statements and Supplementary Data..............,................... :...........................................................................................
- 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure....................................................
PART III Page Nwnber 1
1 2
2 2
4 4
5 6 *"
7 7
7 7
8 8
9 9
9 9
9 10 10 10 10 11 12 12 12 12 13 13 14 14 15 15 16 16 17 17 20 26 49
- 10. Dii-~cto~s and Executive Officers of the Registrant....................................................................................................................
50
- 11. Executive Compensation..............................,................................................................................................................................
52
- 12. Security Ownership of Certain Beneficial Owners and Management........................................................................................
56
- 13. Certain Relationships and Related Transactions..........................................................................................................................
56 PART IV
- 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................................................................
57
e PART*'I ITEM 1. BUSINESS.
.
- T~ COMPANY
- Virginia Electric and Power Company was incorporated in Virginia in 1909 and has its principal office at 701 East Cary Street, Richmond, Virginia 23219-3932, telephone (804) 771-3000. It is a wholly-owned subsidiary of Dominion Resources,
~nc. (Dominion Resources), a Virginia corporation.
Virginia Electric and Power Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy within a 30,000 square mile area in Virginia and northeastern North Carolina. It transacts business under the name Virginia Power in Virginia and under the name North Carolina Power in North Carolina. It sells electricity to
. retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives and munic-ipaHties. The Virginia service area comprises about 65 percent of Virginia's total)and area, but accounts for'over 80 percent of its population. As used herein, the terms "Virginia Power. and the "Comparty" shall refer to the entirety of Virginia Electric and, Power Company, including, without limitation, its Virginia and North _Carolina operations, and all of its subsidiaries.
Th~ electric utility industry in the United States is witnessing an evolutionary trend* toward less regulation and more
. coin.petition. This is evidenced by legislative and regulatory action at both the f~deral and state level. To the extent. that
. competition is either authorized. or mandated and regulation is eliminated or relaxed,_ele'ctric utilities will no longer, in the absence of appropriate.legislative or regulatory action during the transition period, be guaranteed an opportunity to recover their prudently-incurred costs including their.cost *of capital, and utilities with costs that exceed the market prices. established*
by the competitive market will run. the risk of suffering losses, which may be substantial.
. Vb:g'irii.a'Power has ~~*spoiided to* this *evolution hy undertaking cost:~utting 'meisures; ~ngaging in 're-engine~ring efforts of its core business processes, and pursuing a strategic planning initiative (called Vision 2000) to encourage innovative approaches to servicing traditional markets and to develop appropriate methods by which to service future, markets.*
- ;_: °A.'signific;ant p~ of t4e\\~i:impany';, strategy r~lies on d~vefop~g non~traditional. bu§i~dss oppo,rttinities designedto pr<;\\vide *growth. in earnings tiy ieveraging ¢xisting. core co~petencies. Toe company* has established *separatebusiriess* units for its -nuclear' operations, fos'sii !llld hydroelectric: operations, commercial operations, and its energy services business i:n an effort to pursue these opportunities 'to grow by 'off~rmg mt1Ifiple markets' a broad.' portfolio of_eriergy:r~latecf pi-odiicts' and
'. ' -~*.
. ~.....
services.
-* *
- In ~dditi~n. th~ Co~pany is* actlv~ly:pu~suing
- opportu~ities to* expand its mark~t reach through* ;trat~gic alliances with partners whose str~ngths, market position.anq strategies complement the Company's).nd where effidenci~s can be* gained througli_;the:*allfance.*
{
\\,..
For additional information on the changing utility industry and the Company's strategy see COMPETITION _AND s;IRATEGIC INITIATIVES below and Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION. AND-RESULTS OF OP-ERATIONS.. *
- I *- -- ---- -
The Company has franchises or permits for electric operations in substantially all cities and towns now, served. It also
. has certificates of convenience and necessity from the State Corporation Commission of Virginia (the Virginia Commission) v*for service in all territory served at retail in Virginia. The North Carolina Utilities Commission (the No_rth Car?lina ~ommis- /
sion) has assigned territory to* the :Company. for
- substantially an of its retail service outside. certain municipalities. in '
. Nor~t~::any st~ves to ~pe~a,te its gene;at~ng*.fadlitiesin ~c~ord~nce ;ith prude~t ~tility 0
industry' pr~c6ce~:. ~nd::~.\\
coµformity,with,applicable statutes, rules a.Qd:regulations. Like other electric utilities, the.~ompany's generating facilities are. \\\\.
subject to unanticipated*or extern;ied outa,ges for repail:s, replacements or modifications of equipment or otherwise to comply.
- with regulatory requirements. Such outages may involve.significant expenditures not previously budgeted, including replace-ment energy costs.
- The Company ~d it~ subsidiarie~ had 9,681 full~time employees on, December 31, 1996. '..( total of3,48't ~f fue 'Com-pany's employees are represented by the International Brotherhood of Electrical Workers* under a coritract extending fo March 31, 1998. * * * *
(
I I
. I I
e The matters discussed in this annual report on form 10-K contain "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including (without limitation) discussions as to expectations, beliefs, plans, objec-tives and future financial performance, or assumptions underlying or concerning matters discussed in this do~unie~t These discussions, and any other discussions contained in this report that are not historical facts, are forward-looking and, accord-ingly, involv_e estimates, projections, goals, forecasts, assumptio~s and uncertainties that could cause actual resuJts or out-comes to differ materially from those expressed in the forward-looking statements. In addition to certain contingency matters
. (and their respective cautionary statements) discussed elsewhere in this report, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS indicates some important factors that could cause actual results or outcomes to differ materially from those addressed in the forward-looking discussions.
REGULATION General*
In a wide :variety of matters in addition to rat~s. Virginia Power is.presently subject to* regulation by the Virginia Com-mission and the North Carolina Commission, the _Environmental Protection Agency (EPA), Department of Energy (DOE),-
Nuclear Regulatory Commission (NRC), the Federal Energy Regulatory Commission {FERC), the Army Corps of Engineers;
.and other federal, state and local authorities. Compliance with numerous laws and regulations increases the Company's operating ~d capital _costs by requiring, ariJ.oIJ.g other things, changes in the. design _and opera)ion, of existing facilities and changes or delays in the location, design, consmiction and operation of new faciliti~s.. Tl)e co:µ11:nissions regulating th~ C9m-pany's rates have historicalli permitted_ recovery of such costs..
Virginia Power may not construct, or incur financial commitments for construction of,,any subsbntial generating facili-
. ti.es or large capacity transmission lines without the *prior approval of state and*federal governmental agencies having jurisdic-
. tion over various aspects of its business. Such approvals relate to, among other*things, the environmental impact 'of such
. activities, the relationship of such activities to _the neeq for proviqing adequate utility seryice anq the design and ope::ration of proposed facilities:
~
Various provisions of the Energy Policy Act of 1992 (Energy Act) that could affect the Company include those provi-sions encouraging the development of non~utility generation, giving FERC authority to order transmission access for whole-*
sale !fil.risactions,. requiring higher energy efficiency ancl *alti:mative _fu(?lS use, restructuring of nJclear p1~t ~licen~in~ proce--
dures' and requiring state' r~gulatory 'authorities to give full rate 'treatment" for the effects of 'conservation and: demand 1nanagement programs, m:cludhlg the effects o(reducect sales. While: the* fiiii"i:tnpact of the En~rgy Act on the company.
cannot at this time he quantified, it is lilcely, ov*er time, td be* significant
- The Vrrginia General Ass~mbly, during the 1996 session, adopted Senate Joint Resolution No. 118, which created a joint
- legislative subcommittee to s~dy competition:and restructuring-in.fue electric utility'inctlistry. Toe subco~htee conducted pµbli2 hearings and met at various times throughout the year:* The 1997 Virginia General' Assembiy adopted Senate J6int
, _Resolution No. 259, which would continue the existence of the joint subcommittee for an additional year ati.d request i:ha:f tlie
- Staff of the* Virginia Commission provide by November 7; 199T,.a draft of a working model for the future structµre or" the electric: utility industry in Vrrginia, statutory or regulatory c)langes appropriate for _the model, and a:n appi:opriate *timetab"1~..
and transition for implementation of the model. The Virginia Commission has commenced hs work fo. response to* )his
~~
Virginia**
Ori September 18*, 1995, the Virginia C:ommission established a proceeding t6 rn~iew and ~onsider its policy* regarding,
. restructuring of, and competition in, the electric utility industry: The Commission Staff issued its Report on July 31, 1996.
The Report contained 14 recommendations, including continued monitoring of wholesale and retail competiti6n in the indus-
. try, increased monitoring of service quality; preservation of state' jurisdiction: over retail service, 'improved price signals, further study -'of stranded* cost recovery, and increased efforts *to.renegotiate non-utility generation contracts. Ori Septem-ber 23, 1996 Virginia Power filed its comments on the Staff Report and a request for oral argument. The comments *generally supported most of the Staff's sped.fie recommendations as well as its overall-recommendation that Vrrginia *should pursue a cautious aQd measured approach to the adoptfon of competitive initiatives, but Vrrginia Power stated that it would continue to
-pursue its Vision 2000 restructuring (see Note (P) t9 CONSOLIDATE]) FINANCIAL STATEMENTS). The comments stated that the question of recovery of potential stranded costs should be addre~sed now. On NovemQer 8, 1996, Virginia Power gave the Virginia Commission notice that it intended to institute a proc~eding under a recently enact~d ~tatute that allows the 2
Virginia Commission to consider alternative fonns of regulation. On November 12, 1996, the Commission directed its staff and electric utilities in Virginia to provide additional information relevant to potential changes in and possible emergence of
, competition in the electric industry. It directed utilities that have contracts for non-utility generation that impacts their Vrr-ginia jurisdictional rates to file, by June 1, 1997, a report de.tailing efforts to restructure contracts with non-utility generators (NUGs) to mitigate the potentially negative effect on current and future rates, and subsequently to file quarterly reports detailing continuing efforts in this area. The Commission has established separate working groups to consider the issues of reliability, costs and benefits of competition, stranded costs and benefits, models for industry restructuring, and environmen-tal matters. Each working group includes a Staff member and representatives of consumer groups, industrial customers, non-utility generators, utilities and sooperatives.
On November 12, 1996, th~ Commission also instituted a new proceeding and directed the Company to provide other information by March 31, 1997. Information required to be filed includes detailed cost-of-service studies, suggested adjust-ments for eliminating cross subsidies.among customer classes, methods for improving price signals to customers, illustrative tariffs that unbundle rates, analysis of reserve _margin requirements, analysis of whether incremental capacity needs could be met by a competitive market, evaluation of the capacity solicitation process, evaluation of conserv~tion and load management programs and other information. The Commission also directed that any proposed alternative form of regulation be filed in the newly instituted proceeding, and required that a 1996 calendar year be used as the test period, with an anticipated rate year beginning 150 days after the date of filing. On March 7, 1997, in this proceeding and in a separate Annual Information Filing proceeding, the Commission entered an order providing that the Company's rates shall become interim rates subject to refund as of March 1, 1997. On March 24, 1997, Virginia Power filed a proposed alternative regulatory plan with the Virginia Commission, in which it proposes a freeze of present rates through December 31, 2002, during which a portion of earnings above the approved level would be used to accelerate the write-off of generation-related regulatory assets and mitigate the costs associated with payments under power purchase contracts with NUGs. The Company also seeks approval of the princi-ple of stranded cost recovery as well as approval of a Transition Cost Charge mechanism *by which costs that may become stranded at the onset of competition will be recoverable from customers who elect to purchase their power in the competitive market if retail competition is allowed in Vrrginia. The Commission has not established a procedural schedule in this case, and the extent to which it will grant the Company's request cannot be predicted. For a more detailed discussion of competi-tion and the recovery of stranded costs, see Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION_S.
On December 18, 1995, Virginia Power applied to th~ Virginia Commission for approval of arrangements with Chesa-peake Paper Products Company (CPPC), under which Virginia Power would facilitate the design, construction and financing
- of a cogeneration plant to meet CPPC's energy requirements for its industrial processes at its plant in West Point, Virginia. A hearing has been held, and briefs have been filed'. Several parties opposed the arrangements by which Virginia Power would provide gas sales, fuel management and fuel* procurement services to the plant as being anticompetitive and beyond the Company's corporate and regulatory authority. Briefs were filed on January 6, 1997. After consideration of briefs, a hearing examiner's report will be issued.
On May 29., 1996, the Company filed an Application with the V~rginia Commission seeking authority to implement a monitoring program that requires certain non-utility generators to._provide certain ipformation sufficient to determine contin-ued compliance with the "Qualifying Facility" (QF) requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA). On October 10, 1996, the Commission Staff filed its brief concluding that the Commission had legal authority to require QFs to provide it with operating data and to adopt a monitoring program. On December 18, 1996, the Staff filed a report generally supporting the Application. On December 30, 1996, the Company filed its response requesting that the Commission adopt the Staff conclusions.
On June 7, 1996, the Company filed an application with the Virginia Commission to purchase a gas-frred combined cycle generator from Richmond Power Enterprise, L.P. (RPE) and to enter into a purchased power contract with RPE and Enron Power Marketing, Inc. (EPMI) without competitive bidding. Under this proposal, Virginia Power will purchase the generator, at a price of approximately $20 million, and the power purchase and operating agreement (PPOA) will be amended to reduce capacity payments, shorten the term of the agreement and provide for sales *of capacity and energy by RPE's assignee, EPMI, to Virginia Power from sources outside Virginia Power's service territory rather than from the generator. The Company estimates this arrangement will result in a savings of $63 million over the life of the existing PPOA. The Staff supported the application, and the Commission granted approval on November 18, 1996. On January 15, 1997, FERC issued the necessary approvals. The purchase was concluded on February..25, 1997.
3
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On October 8, 1996, Virginia Power filed with the Virginia Commission an application for authority to provide inter-exchange non-switched dedicated telecommunication services throughout Virginia. If the application is granted, Virginia Power will be authorized to provide a range of telecpmmunications services, including private line and,special access ser-*
vices and high capacity telecommunications service~. The application is opposed by the City of Richmond, and several telecommunications providers have intervened neither supporting nor opposing the application. Virginia Power filed its brief on March 7, 1997, supporting its authority.to offer the telecommunications services and responding to the positions taken by the other parties.
On November 8, 1996, the Virginia Commissi~n approved arrangements for services and transfers of assets between Virginia Power and A&C Enercom, Inc., a wholly-owiied subsidiary of Virginia Power that provides energy services to utility customers.
On February 7, 1997, Virginia Power filed an application with the Virginia Commission requesting approval of arrange-ments between it and a wholly-owned subsidiary, Virginia Power Services, Inc., (VPS), by which Virginia Power would provide to VPS services that would enable Virginia Power Nuclear Services Company (VPN), a VPS subsidiary, to furnish nuclear management and operation services to electric utilities seeking assistance in the management and operation of their nuclear generating facilities. The arrangements contemplate the possibility of the creation of additional subsidiaries of VPS that would provide other unregulated services, such as energy servi"es, to third parties seeking such services. VPN has executed a Letter of Intent with Northeast Nuclear Energy Company to provide management services for Northeast Utilities' Millstone Unit 2 nuclear plant.
North Carolina On May 15, 1996, the North Carolina Commission issued an order initiating an investigation of emerging issues in the restructuring of the electric industry. As ordered, the Company filed comments on July 16, 1996, addressing the implications of FERC Order No. 888, Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities.
FERC On April 24, 1996, FERC issued final rules on open access transmission service; stranded costs, standards of conduct and open access same-time information systems (OASIS). On July 9, 1996, Virginia Power filed an open access transmission service tariff in compliance with FERC's Order No. 888. Also, in compliance with FERC's directive, Vrrgip.ia Power's OASIS became operational and company-filed standards of conduct requiring separation of transmission opera-tions/reliability functions from wholesale merchant/marketing functions became effective on January 3, 1997. The Company also made filings to comply with FERC's directive that, effective January 1, 1997, utilities no longer make bundled sales of transmission and generation services in economy energy transactions. In certain of those filings, Virginia Power canceled or committed not to use the economy energy rate schedules contained in interconnection agreements that Virginia Power has with neighboring utilities. With regard to its Wholesale Power Sales Tariff, Virginia Power filed amendments to that tariff to unbundle the bundled economy rates contained therein. On March 4, 1997, FERC issued Order No. 888-A, in which it addressed requests for rehearing of Order No. 888. Order No. 888-A essentially reaffirms the basic principles* of Order No. 888 and clarifies and makes limited modifications to Order No. 888. Parties seeking judicial review of Order Nos. 888 and 888-Amust file petition for review with the appropriate United States Court of Appeal by May 5, 1997. For a discussion of the status of the Company's Open Access Transmission Tariff filing, see ITEM 1, RATES, FERC below.
FERC also issued a notice of proposed rulemak.ing (NOPR) proposing replacement ofopen access tariffs with a capacity reservation tariff by December 31, 1997.
For additional disc~ssion of Open Access issues see COMPETITION AND STRATEGIC INITIATIVES under BUSI-NESS and Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
On July 31, 1996, FERC denied in part and granted in part, LG&E Westmoreland Southampton's (Southampton) request for a waiver of the Commission's operating requirements for QFs u_nder PURPA. Southampton owns and operates a 62.6 MW cogeneration facility located in Franklin, Virginia and sells the output of the facility to Virginia Power. FERC's decision preserved Southampton's QF status under the Public Utility Holding Company Act, but refused to waive Southampton's violation of the QF operating standards. The Order provided that Southampton refund to Virginia Power the difference between the amount that Virginia Power paid to Southampton in 1992 under its QF contract and a Commission-approved rate 4
e e
--~-1 equal to Vrrginia Power's incremental cost of economy energy during 1992. On August 23, 1996, Southampton filed a I
Motion for Clarification, and on August 30, 1996, it filed-a Request for Rehearing. Virginia Power filed responses to each
- Soutl1anipton'pleading. On September 30, 1996, FERC issued an order granting rehearing for the purpose of further consider-ation. On October 15, 1996, Virginia Power filed the data requested by FERC order showing Virginia Power's incremental cost of economy energy during each hour of 1992. On October 30, 1996, Southampton filed a response to Virginia Power's data filing. Southampton also filed a Petition for Review on September 23, 1996, against FERC in the United States Court of Appeals for the D.C. Circuit. Virginia Power filed a Motion to Intervene, which the Court granted on November 25, 1996. On November 27, 1996, Southampton initiated a separate rate proceeding at FERC seeking approval of the contract rates paid to it by Virginia Power in 1992 only. On December 26, 1996, Virginia Power filed a Motion to Intervene, Motion to Reject and Terminate Proceeding, and Protest. On January 10, 1997, Southampton filed its answer.
Environmental From time to time, the Company may be identified as a potentially responsible party (PRP) with respect to a Superfund site. EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs, but the parties can then bring contribution actions against each other and seek reimbursement from their insurance companies. As a result of the Superfund Act or other laws or regulations regarding the remediation of waste, the Company may be required to expend amounts on remedial investigations and actions. Although the Company is not currently aware of any sites or events, including those sites currently identified likely to result in significant liabilities, such amounts, in the future, could be significant.
Permits under the Clean Water Act and state laws have been issued for all of the Company's steam generating stations now in operation. Such permits are subject to reissuance and continuing review.
The Clean Air Act, as amende'd in 1990, requires the Company to reduce its emissions of sulfur dioxide (S02) and nitrogen oxides (NO). Beginning in 1995, the S02 reduction program is based on the issuance of a limited_ number of S02 emission allowances, each of which may be used as a permit __ to emit one ton of S02 into the atmosphere or may be sold to someone else. The program is admini~tered by the EPA.
The Company installed S02 control equipmept on Unit 3 at Mt. Storm Power Statio~ during 1994. Additional plans for S02 control involve switching to lower suJfur coal, purchase of emission allowances and additional S02 controls. Maximum flexibility and least-cost compliance.will be mmntained through annual studies. The ~ompany has completed its compliance plan for NOX control, with the exception of some additional studies concerning Phase II, for which EPA _issued final regula-tions m December 199?, and ozone control requirements, for which final regulations have not yet been promulgated..
In 1996 the Company installed NOx controls on Possum Point Unit 4 and at Mt. Storm Unit 3 at a total approximate cost of $10 million. The Company plans to install additional NOx controls and modify existing controls at Mt. Storm Units 1 and 2 in 1997, and to seek alternative emission limitations from EPA' for all three Mt. Storm Units; The Company has notified EPA of its decision (called "early election") to begin complying with Phase I NOx limits at ten of its units in Virginia in 1997, three years earlier than otherwise required. As a result, and provided that Phase I compliance limits are met, the units will not be subject to more stringent Phase II limits until 2008.
In order to assist.the Virginia Department of Environmental Quality in maintaining good air quality in the Richmond and Hampton Roads regions, and to avoid the necessity of more stringent regulations, the Company made voluntary commitments in 1996 to cap NOxemissions at its Chesterfield and Yorktown Power Stations and the Chesape~e Energy Center beginning in 2000.
Capital expenditures on Clean Air Act compliance over the next'five years are projected to be approximately $21 mil-lion. Changes in the regulatory environment, availability of allowances, and emissions control technology could substantially impact the timing and* magnitude of compliance expenditures.
The Clean Air Act amendments also require the Company to obtain operating permits for all major generating facilities.
Permit applications have been submitted, and deemed complete by the regulatory authorities, for the Mt. Storm and North Branch power stations. Applications for the Virginia stations are expected to be filed within the next two years.
The Company continues to work with the West Virginia Office of Air Quality concerning opacity requirements applica-.
ble to the Mt. Storm Power Station.
In regard to ambient air quality standards, the EPA recently announced proposals to add a fine particulate matter stan-dard and to revise the ozone standard, which could potentially result in significant expenditures to install controls to reduce sulfur dioxide and nitrogen oxide emissions.
5
e e
In 1993 the United Nations' Framework Convention on Climate Change, also called The Global Warming Treaty, which was signed by more than 150 countries, including the United States, became effective. The objective of the treaty is the stabilization of greenhouse gas. concentrations at a level that would prevent manmade emissions from interfering' with the climate system.
Although there is considerable scientific disagreement concerning the effects of greenhouse gas emissions on global climate, the United States and many other nations are supporting an international treaty, to be finalized in December 1997, containing legally binding emissions targets to be achieved between 2010 and 2020. The reduction in greenhouse gas emis-sions necessary to achieve these targets is likely to have a substantial financial impact on companies that consume or produce fossil fuel derived electric power, including Virginia Power.
For additional information on Environmental Matters, see *Note Q to CONSOLIDATED FINANCIAL STATEMENTS and ITEM 3. LEGAL PROCEEDINGS below.
Nuclear All aspects of the operation and. maintenance of the Company's nuclear. power stations are regulated by the NRC.
Operating licenses issued by the NRC are -subject to revocation, suspension or modification, and operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
F~om 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 mal.ntenarice of existing nuclear facilities. ff 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.
- On July 18, 1995, the Virginia Commission instituted an investigation regarding spent nuclear f'uel disposal. It directed interested parties to provide comments on legal and public policy issues related to spent nuclear. fuel storage and disposal, including, but not limited to, whether ~o ailow utilities to r:ecover from ratepayers some or all money paid to the Nuclear Waste Fund established by the Nuclear Policy Act of 1982, whether to establish an escrow account for spent nuclear fuel storage and/or disposal, and whether utilities should develop their own plans for storage and disposal of spent nuclear fuel.
The Commission's Order Establishing Investigation recites that Virginia Power has paid $343.6 million to the Nuclear Waste Fund through 1994, including $44.8 million in 1994, and that future payments could exceed $400 million assuming its North Anna and Surry reactors continue to operate through the end of their existing operat!ng licenses.*Virginia Power and others filed comments* on October 31, 1995. On February 27, 1996, the Commission Staff filed its Report recommending that adoption of a definitive policy on the spent nuclear fuel disposal fee be delayed until (1) a ruling is forthcoming on pending litigation which seeks to impose an obligation on the federal government to begin acceptance of spent nuclear fuel no later than January 31, 1998, (2) the outcome of proposed legislation which would amend the Nuclear Waste Policy Act to require the development of a centralized interim storage facility has been determined, and (3) a vision of the likely outcome of the electric utility industry's restructuring efforts has been more fully conceptualized. The Virginia Commission entered an order on October 7, 1996 in its proceeding regarding spent nuclear fuel disposal in which it directed that the proceeding be consoli-dated with Virginia Power's pending fuel cost recovery proceeding. On March 7, 1997, the Commission Staff filed a motion requesting that the Commission remove the spent nuclear fuel disposal issue from the Company's pending fuel factor pro-ceeding and return it to a separate proceeding.
For additional information on the Virginia fuel factor proceeding, see ITEM 1, RATES, Virginia, below.
On January 31, 1997, Virginia Power joined thirty-five other utility petitioners in filing a lawsuit against the U.S.
Department 9f Energy in the U.S.. Court of Appeals for the District of Columbia, asking the court to authorize suspension of payments to the Nuclear Waste Fund and to authorize payment into escrow those fees that are collected from customers until the DOE begins accepting used fuel.
6
e CAPITAL REQUIREMENTS AND FINANCING PROGRAM Construction and Nuclear Fuel Expenditures I
Virginia Power's estimated construction and nuclear fuel expenditures, including Allowance for Funds Used During Construction (AFC), for the three-year period 1997-1999, total $1.5 billion. It has adopted a 1997 budget for construction and nuclear fuel expenditures as set forth below:
Production:
Clean Air Act.............................................................................................................
Other.......................................................................... :...............................................
- General Support Facilities..............................................................................................
Transmission............ '............................................................................... :........... :...........
. Distribution.....................................................................................................................
Nuclear Fuel.................................................................................... :..............................
Total Construction Requirements and Nuclear Fuel..... :...........................................
AFC.........................................................................................................................
Total Expenditures.................................. :.............................. :....................................
Financing Program.
Estimated 1997 Expenditures (millions) 8 53 72 46 253 97 529 4
$533 In 1996 the Company issued $24.5 million of variable rate solid waste disposal securities to refund $24.5 million of securities assumed in its acquisition of the North Branch Power Station. Also in 1996, the Company retired a total of $259.6 million of Medium-Term Notes through mandatory maturiti~s.
In January 1997, the Company filed a new shelf registration statement with the Securities and Exchange Commission (SEC) for $400 million of Junior Subordinated Debentures. In 1995, the Company filed two shelf registration statements with the SEC, one for $575 million of First and Refunding Mortgage Bonds and the other for $200 million of Medium-Term Notes, Series F, respectively. In February 1997, the Company sold and issued $200 million of its First and Refunding Mort-gage Bonds. These three facilities combine to provide the Company with $975 million in unused debt capital resources. In addition, the Company has a Preferred Stock shelf registered with the SEC, for $100 million in aggregate principal amount, which has not been utilized.
, The Company intends to issue securities from time to time to meet its capital requirements, which includes $311.3 mil-lion of long-term debt maturities in 1997.
In June 1996, the Company increased the limit for its commercial paper program from $300 million to$500 million with the execution of $500 million of revolving credit facilities, which replaced existing liquidity support. Proceeds from the sale of commercial paper are primarily used to finance working capital for operations. Net borrowings under the commercial paper program were $312.4 million and $169.0 million at December 31, 1996 and December 31, 1995, respectively.
RATES The Company was subject to rate regulation in 1996 as follows:
Virginia retail:
Non-Governmental customers.......................
Governmental customers...................,...........
North Carolina retail.........................................
Wholesale:
Requirements -
Sales for Resale.................
Non-Requirements -
Sales for Resale........
Virginia Commission Negotiated Agreements North Carolina Commission FERC FERC 7
Percent of Revenues 77%
10 5
4 4
100%
1996 Percent of Kwh Sales 70%
11 4
5 10 100%
e e
Substantially all of the Company's electric sales are subject to recovery of changes in fuel costs either through fuel adjustment factors or periodic adjustments to base rates, each of which requires prior regulatory approval.
Each of these jurisdictions has the authority to disallow recovery of costs it determines to be excessive or imprudently incurred. Various cost items may be reviewed on occasion, including costs of constructing or modifying facilities, on-going purchases of capacity or providing replacement power during generating unit outages.
The principal rate proceedings in which the Company was involved in 1996 are described below by jurisdiction. Rate relief obtained by the Company is frequently less than requested.
FERC On May 14, 1996, the Department of the Navy, on behalf of the Department of Defense (DOD), filed a Petition request-ing FERC to declare DOD a wholesale customer within Virginia. Alternatively, the Petition requested FERC to order Vrrginia Power to wheel to DOD installations in Virginia. An agreement in principle was subsequently reached for a new power supply contract, and the Navy moved to withdraw its Petition, stating that the concerns expressed in the Petition had been resolved. On July 15, 1996, three power marketers filed a protest with DOD challenging the sole source negotiation and ill)pending contract with Virginia Power. The Department of the Navy, Naval Facilities Engineering Command issued a decision on October 22, 1996, denying the protest, and finding that competition between providers other than Virginia Power for the provisions of electrical service to DOD facilities and activitie_s within Virginia Power's service territory in Virginia is not currently available. The Navy also noted that the impending contract was not in contemplation of a new acquisition, but was the result of periodic review of, and negotiation of a new rate under an existing indefinite term contract. The supplemen-tal agreement incorporating the new rate was executed on October 30, 1996.
Iri compliance with FERC's Order No. 888, on July 9, 1996, Virginia Power filed an open access transmission service tariff, which became effective on July 9, 1996. On October 10, 1996, FERC issued a procedural order, scheduling a hearing for April 28, 1997. The Company and all parties reached a settlement of issues raised iri the proceeding, and on March 20, 1997, those parties jointly filed with FERC the Settlement Agreement* and Motion to Certify the Settlement Agreement. The Company is awaiting action on that motion by the *presiding Administrative Law Judge.
Virginia In 1995, the Virginia Commission authorized Virginia Power to implement a pilot program providing a real time pricing (RTP) option for its industrial customers with loads in excess of 10 Mw. Under this option, all or a portion of an industrial customer's load growth would be supplied at projected incremental hourly production costs, adjusted for line losses and taxes, plus a margin of 0.6 cents per Kwh. Additionally, a marginal cost-.based Generation Capacity Adder and a Transmis-sion Capacity Adder would be applicable during those hours when the Virginia Power system is approaching its forecasted annual peak demand. Up to 20% of an industrial customer's existing load could be served on an RTP basis if the customer executes a five-year contract for such service. On July 24,.1996, the Commission expanded the RTP schedule to make it available to commercial and industrial customers with loads above 5 Mw.
On July 31, 1996, Virginia J>ower filed with the Virginia Commission a.revised Schedule 19, which governs purchases.
from co generators and small power producers of 100 kW or less. The schedule, which contains rates substantially lower than those previously specified, became effective on an interim basis on January 1, 1997. A hearing was held on January 30, 1997.
The parties filed briefs on March 14, 1997.
On October 7, 1996, the Virginia Commission ordered that its investigation regarding spent nuclear fuei disposal be consolidated with Virginia Power's next fuel recovery proceeding. On October 21, 1996, Virginia Power filed an application with the Commission to increase its fuel cost recovery by approximately $48.2 million. On November 12, 1996, the Commis-sion ordered that the hearing on the consolidated proceedings be delayed from November 27, 1996 to February 27, 1997, and that the Company's proposed fuel factor become effective on December 1, 1996. On January 8, 1997, the Commission postponed the hearing to April 17, 1997. Any potential adjustments to the factor ordered after hearing will be reflected prospectively after entry of the final order. On March 7, 1997, the Commission Staff filed a motion requesting that the Commission remove the spent nuclear fuel disposal issue from the Company's pending fuel factor proceeding and return it to a separate proceeding.
8
e North Carolina On September 13, 1996, the Company filed an application with the North Carolina Utilities Commission for a $3.2 mil-
'lion tlecrease
- in fuel rates. On December 10, 1996, the Commission approved a $3.3 million decrease, effective January 1, 1997.
On November 4, 1996, the Company filed for approval of a new Schedule 19 which governs purchases from cogener-ators and small power producers. The Company proposed rates substantially lower than those previously specified as well as proposed to reduce the applicability threshold to 100 kW and shorten the maximum term of contracts under Schedule 19 to five years.
SOURCES OF POWER Company Generating Units Name of Station, Units and Location Nuclear:
Years Installed Surry Units 1 & 2, Surry, Va...............................................................................
1972-73 North Anna Units 1 & 2, Mineral, Va..................................................................
1978-80 Total nuclear stations.................................................................-........................
Fossil Fuel:
Steam:
Bremo Units 3 & 4, Bremo Bluff, Va.............................................................
1950-58 Chesterfield Units 3-6, Chester, Va.......... :......................................................
1952-69 Clover Units 1 & 2, Clover, Va......................................................................
1995-96 Mt. Storm Units 1-3, Mt. Storm, W. Va.........................................................
1965-73 Chesapeake Units 1-4, Chesapeake, Va..........................................................
1953-62 Possum Point Units 3 & 4, Dumfries, Va............... :.......................................
1955-62 Yorktown Units 1 & 2, Yorktown, Va............................................................
1957-59 Possum Point Units 1, 2, & 5, Dumfries, Va.................................................
1948-75 Yorktown Unit 3, Yorktown, Va......................................................................
1974 North Branch Unit 1, Bayard, W. Va..............................................................
1994 Combustion Turbines:
35 units (8 locations).................................................................................... ;.......
1967-90 Combined CycJe:
Chesterfield Units 7 & 8, Chester, Va................................................................
1990-92 Total fossil stations............................................................................................
Hydroelectric:
Gaston Units 1-4, Roanoke Rapids, N.C............................................................
1963 Roanoke Rapids Units 1-4, Roanoke Rapids, N.C.............................................
1955 Other......................................................................................................................
1930-87 Bath County Units 1-6, Warm Springs, Va.........................................................
1985 Total* hydro stations...........................................................................................
Total Company generating unit capability.......................................................
Net Utility Purchases...............................................................................................
Non-Utility Generation *******************************************:***********************************************
Total Capability.................................................................................................
'Iype of Fuel Nuclear Nuclear Coal Coal Coal Coal Coal Coal Coal Oil Oil & Gas
- Waste Coal Oil & Gas Oil & Gas Conventional Conventional Conventional Pumped Storage Summer Capability Mw 1,602 l,790(a) 3,392 227 1,250 882(b) 1,587 595 322 326 929 818 74(c) 1,019 397 8,426 225 96 3
1,260(d) 1,584 13,402 1,030 3,509 17,941 (a) Includes an undivided interest of 11.6 percent (208 Mw) owned by Old Dominion Electric Cooperative (ODEC).
(b) Includes an undivided interest of 50 percent (441 Mw) owned by ODEC.
(c) Effective January 25, 1996, this unit was placed in a cold reserve status.
(d) Reflects the Company's 60 percent undivided ownership interest in the 2,100 Mw station. A 40 percent undivided interest in the facility is owned by Allegheny Generating Company, a subsidiary of Allegheny Power System, Inc. (AP).
The Company's highest one-hour integrated service area summer peak demand was 14,003 Mw on August 2, 1995, and an all-time high one-hour integrated winter peak demand of 14,910 Mw was reached on February 5, 1996.
9
e e
SOURCES OF ENERGY USED AND FUEL COSTS *.
For information as to energy supply mix and the average fuel cost of energy supply, see Results of Operations under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERA.TIONS.'
Nuclear Operations and Fuel Supply In 1996, the Company's four nuclear units achieved a combined capacity factor of 88.2 percent.
The Company utilizes both long-term contracts and spot purchases to support its needs for nuclear fuel. Virginia Power's nuclear fuel supply and related services are expected to be adequate to support current and planned nuclear genera-tion requirements. The Company continually evaluates worldwide market conditions in order to obtain an adequate nuclear fuel supply. Current agreements, inventories and market availability should support planned fuel cycles throughout the remainder of the 1990s.
On December 17, 1996, the DOE indicated that it will have to delay the acceptance of spent fuel scheduled to begin in 1998. On-site spent nuclear fuel storage at the Surry Power Station is adequate for the Company's needs until the DOE begins accepting spent fuel. The North Anna Power Station will require additional spent fuel storage capacity in 1998. The Company submitted a license application to the NRC in May 1995 for such a facility at North Anna.
For details regarding nuclear insurance and certain related contingent liabilities as well as a NRC rule that requires proceeds from certain insurance policies to be used first to pay stabilization and decontamination expenses, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.
Fossil Operations and Fuel Supply The commercial operation of Clover Power Station Unit 2 commenced on March 28, 1996. The summer capability of both Units 1 and 2 have been determined to be 441 Mw. -
The Company's fossil fuel mix consists of coal, oil and natural gas. In 1996, Virginia Power consumed approximately 12 million tons of coal. As with nuclear fuel, the Company utilizes both long-term contracts and spot purchases to support its needs. The Company presently anticipates that sufficient coal supplies at reasonable prices will be av_ailable for the remainder of the 1990s. Current projections for an adequate supply of oil remain favorable, barring *unu.sual international events or extreme weather conditions which could affect both price and supply.
The Company uses natural gas as needed throughout the year for two combined cycle units and at several combustion turbine units. For winter usage at the combined cycle* sites, gas is purchased and stored during the summer and fall and consumed during the colder months when gas supplies are not available at favorable prices. The Company has firm transpor-tation contracts for the delivery of gas to the combined cycle units. Current projections _indicate gas supplies will be available for the next several years.
Purchases and Sales of Power Virginia Power relies on purchases of power to meet a portion of its capacity requirements. The Company also makes economy purchases of power from other utility systems when it is available at.a cost lower. than the Company's own genera-tion costs.
Under contracts effective January 1, 1985, Virginia Power agreed to purchase 400 Mw of electricity annually through 1999 from Hoosier Energy Rural Electric Cooperative, Inc. (Hoosier), and agreed to purchase 500 Mw of electricity annually during 1987-99 from certain operating units of American Electric Power Company, Inc. (AEP).
The Company has a diversity exchange agreement with AP under which AP delivers 200 Mw to Virginia Power in the summer and Virginia Power deiivers 200 Mw to AP in the winter.
Vrrginia Power also has 65 non-utility power purchase contracts with a combined dependable summer capacity of 3,524 Mw. Of this amount, 3,509 Mw were operational at the end of 1996 with the balance scheduled to come on-line through 1999 (see Non-Utility Generation under FUTURE SOURCES OF POWER and Note Q to CONSOLIDATED FINANCIAL STATEMENTS). In an effort to mitigate its exposure to above-market long-term purchased power contracts, the Company is evaluating its long-term purchased power contracts and negotiating modifications to their terms, including cancellations, where it is determined to be economically advantageous to do so. The Company has also negotiated settlements with several other parties to terminate their rights to sell power to the Company.
10
e In 1.995; a wholesale power group was formed within the Company to actively participate in the purchase and sale of wholesale electric power in the open market. The wholesale power group has expanded the Company's trading range beyond the geographic limits of the Virginia Power service territory, and has developed trading relationships with utilities on a
'nationwide basis. During 1996, the Company expanded its gas marketing activities, trading in the open market both within and outside the Virginia Power service territory. The gas marketing function is organized as a part of the wholesale power group and broadens the Company's product mix to provide a full range of wholesale energy marketing services.
On 1ugust 15,.1996; pursuant to the provisions of the Interconnec(ion and Operating Agreement between ODEC and Virginia Power, ODEC gave written notice of its intent to reduce its supplemental demand purchases under that Agreement to zero within nine_ years. 1997 supplemental demand charges (other than charges relating to transmission and distribution which will continue in any case) are expected to be $63 million. On November 19, 1996, the Company and ODEC reached principles of agreement providing that Virginia Power will continue to supply all of ODEC's supplemental capacity needs through 2005, rather than the declining amounts after. 1999 under prior agreements. Under the principles of agreement, the Company's recovery of fixed charges will be reduced over time as supplemental capacity rates transition from fully-embed-ded costs to market-based pricing. The Company estimates the reduced rates, offset in part by other revenues which may be earned under the agreement, will decrease income before taxes.by approximately $38 million through 2005.
. INTERCONNECTIONS The Company maintains major interconnections with Carolina Power and Light Company, AEP, AP and the utilities in the Pennsylvania-New Jersey-Maryland Power Pool. Through this major transmission network, the Company has arrange-ments with these utilities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy.
On June 19, 1996, a transmission alliance was formed among Virginia Power, Allegheny Power, Centerior Energy, and Ohio Edison to promote fair and equitable use of the transmission systems. This alliance is an outgrowth of the General Agreement on Parallel Paths (GAPP),. a.group of 21 utilities, independent power producers, cooperatives, and public power authorities, that was formed in the early 1990s to work on a series of principles to govern inter-system wholesale power transfers. The four utilities that are initiating the transmission alliance are all members of the GAPP initiative and are forming the alliance to specifically further the principles of GAPP as the electric utility industry continues the evolution to, and beyond, open access.transmission service. The alliance has adopted the specific GAPP principles to ensure that proper reim-bursement is made to each alliance utility handling a power transfer through the parallel path concept. A GAPP Matrix Subcommittee will determine the parallel paths any specif~c transaction will take and the GAPP compensation procedure will determine the compensation owed to the utilities involved. The Company views the alliance as an important step towards implementing flow and distance sensitive pricing of transmission service.
On December 4, 1996, Virginia Power and five other North American utilities announced plans for a test of principles designed to maintain the reiiability of electric transmission systems, encourage optimal use of the facilities, and ensure fair payment for their use. Virginia Power and the four other U.S. utilities involved in the plan asked FERC for permission to test compensation methods contained in GAPP. Using the. GAPP principles, participants in the test would use actual power flows to allocate among themselves transmission service revenues. The five U.S. participants asked FERC for permission to begin the test on'April 2, 1997. In addition to Virginia Power, the U.S. participants in the test include Allegheny Power, Centerior Energy, Ohio Edison and Southern Company. While not under FERC jurisdiction, Ontario Hydro is also a participant in the
- experiment. The experiment would also give utilities more thorough information' on the use of regional transmission capacity by utilizing the GAPP Information System (GIS). This system stores data regarding scheduled power transactions and ana-lyzes the anticipated paths the power will take during the transfers. The information* is essential for optimal use of the integrated transmission network.
The GAPP principles have* been developed during the last five years by a broad cross-section of transmission users, including utilities in the United States and Canada, public power authorities, rural electric cooperatives, power marketers and independent power producers. The principles are designed to cleal. with the issue of parallel flows. Within tightly intercon-nected transmission grids," power does not always flow in a direct path -
often called the "contract path"-'- from seller to buyer. The power may in fact flow through several adjoining* systems to get to the end-user, even if the buyer and seller are directly interconnected. Under current rules; utilities are not fully compensated for the use of these "parallel paths." Compen-sation for transmission services historically has* been based on contract paths. The companies in the GAPP experiment will analyze the paths power actually takes through their system, then allocate transmission service compensation to reflect those paths. For the five utilities 'in the United* States, the allocations will be based on the open access transmission tariffs each filed with FERC in response to FERC Order 888. In their filing, the participants noted that the test could be expanded to include 11
additional utilities and other entities that r~ceive revenue from transmission services. The test will have no effect on the rates the six utilities charge for transmission services.
The Company and Appalachia!). Po>>1er Company (AEP Virginia), an operating unit of AEP, have each sought approval, from the Virginia Commission to construct interconnecting transmission facilities. AEP Virginia proposes to construct 116 miles of 765 Kv line to connect with Vi~gini~ Power's proposed 102 miles of 500 Kv line. Virginia Power does not intend to build its facility unless the AEP Vi~giiiia facility, which requires approval in West Virginia as well as Virginia, is also approved and built. Approval of b~tll<#cilities has been recommended by a Virginia Commission Hearing Examiner. On*
December 13, 1995, the Virginia Commission issued an Interim Order in the AEP Virginia case in which it found that additional transmission capacity is nee'ded but directed AEP Virginia to provide further information as to routing, mitigation of visual impact, and uses of the line:,
~.
FUTURE SOURCES OF POWER As reported earlier, both the Hoosier 400 Mw long-term purchase and the AEP 500 Mw long-term purchase will expire on December 31, 1999. With the sche~uled termination of 900 Mw of long-term purchases and continued system load growth, the Company presently anticipat¢s adding 1,200 Mw of short-term (thi::ee-year) purchases beginning in the year 2000.
The Company has and will pursue capacity acquisition plans to provide that capacity and maintain a high degree of service reliability. This capacity may be owned ~nd operated by others and sold to the Company or may be built by the Company if it determines it can build capacity at a Iov,;,er overall cost. The Company also pursues conservation and demand-side manages ment (see CONSERVATION AND LOAD MANAGEMENT below).
The Company's continuing program to meet future capacity requirements is summarized in the following table:
Company Owned Generation No Company owned generation is' currently in the planning or construction stages..
Non-Utility Generation Projects Operational Projects Financed Unfinanced Projects Total Contracts Number of Projects For additional information, see Note.Q to CONSOLIDATED FINANCIAL STATEMENTS.
COMPETITION AND STRATEGIC INITIATIVES Mw 3,509 0
15 3,524 A number of developments in the United States are causing a trend toward less regulation of and *more competition i~
the electric utility industry. This is evidenced by legislative and regulatory action at both the federal and state levels. To the extent that competition is either authorized.or mandated and regulation is eliminated or relaxed, electric utilities will no longer, in the absence of appropriate legislative or regulatory action during the transition period, be guaranteed an opportu-nity to recover all of their prudently-incµrred costs including their cost of capital, and utilities with costs that exceed the market prices established by the compe~itive market will run the risk of suffering losses, which may be substantial.
Virginia Power has responded to these trends by undertaking cost-cutting measures, engaging in re-engineering efforts of *its core business processes, and pursuing a strategic planning initiative (called Vision 2000) to encourage innovative appro~ches to servicing traditional markets and to develop appropriate methods by which to service future markets. The C01i1pany has established separate busi.ness units for its nuclear operations, fossil _and hydroelectric operations, commercial operations and its energy services business. A re-engineering and re-missioning review of the Fossil and Hydroelectric Busi~
ness Unit and Nuclear Business Unit has been completeq and implementation is now complete. The.Corporate Center is now in the final stages of review. The Compimy's Commercial Operations Business Unit has completed its review and has begun implementation of several organizational modifications and applications of new technology to improve customer service and reduce operational costs. Some of these ~mprovements will require investments of approximately $100 million, which will be expended over s.everal years.
- i
,:1 12
e The Company has created a subsidiary to provide nuclear management and operation services to electric utilities !leeking assistance in the management and operation of their nuclear generating facilities; it acquired an *operating business, A&C Enerc0m; Inc.; a provider of marketing, program planning and design, customer engineering and energy consulting services; it is seeking approval to engage in the telecommunications business; and it is in the planning stages of creating additional subsidiaries to engage in these and other unregulated businesses. It is also taking regulatory and legislative initiatives designed to enhance the likelihood that i:he transition to competition is an orderly one and that the Company will not be prevented from recovering prudently-incurred costs and investments.
In addition, Virginia Power is actively pursuing opportunities to expand its markets through strategic alliances with partners whose strengths, market position and strategies complement the Company's and where efficiencies can be gained through the alliance.
A significant part of the Company's strategy relies on developing "non-traditional" business opportunities de~igned to provide growth in earnings. The Energy Services Business Unit is the most prominent example ofthis growth strategy. The Energy Services Business Unit is expected to contribute to earnings growth by offering the market a portfolio of energy related products and services. Other examples of such opportunities include the Fossil & Hydro Business Unit, through which the Company will target process type industries, such as chemical, paper, plastics and petroleum to become a service provider of instrumentation equipment, and the Nuclear Business Unit, whose position as an industry leader offers opportunities to provide services to other nuclear utilities striving to improve their safety records. The Commercial Operations Business Unit wili provid~ power distribution related service. Finally, the Telecommunications Act of 1996 opened up opportunities to generate growth through use of existing.telecommunications infrastructure to provide telecommunications services and new energy services through the Company's existing fiber-optic network.
Virginia Power has organized a wholesale power group to engage in off-system wholesale purchases and.sales, and that group is developing trading relationships beyond the geographic limits of Virginia Power's retail service territory. The Com-pany has also been successful in negotiation of wholesale requirements contracts with.multi-year provisions for notice of termination of service and a long~term contract with large federal government customers for service to facilities within the Company's service territory and has obtained regulatory approval of innovative pricing proposals for industrial. loads, although rate concessions have been necessary in some cases. To date, the Company has not experienced any material loss. of load, and the reduction of 1997 revenues attributable to such rate concessions is expected to approximate $22 million..
For a more detailed discussion, see FUTURE ISSUES-Competition under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
CONSERVATION AND LOAD MANAGEMENT The Company is committed to evaluating and selecting demand-side and supply-side options on a consistent basis in order to provide reliable, low-cost service to its customers. Conservation and load management programs are selected annu-ally at Virginia Power through an integrated resource planning process which directly compares the stream of costs and benefits from supply-side and demand-side options. This process supports the selection of a conservation and load manage-ment portfolio which contributes both to the selection of low-cost resources to meet the future electricity needs of the Com-pany's customers as well as the efficient use of current resources.
Recent declines in avoided costs and the arrival of competition have caused the Company to modify the package of cost-effective measures which it supports in the annual Energy Efficiency Plan. In the future, the Company anticipates a greater reliance on the use of price signals to convey information to our customers regarding costs, resulting in more efficient pur-chase decisions. Finally, in an investigation sparked by the fundamental changes occurring in the electric utility industry, the Virginia Commission has requested the Company to evaluate the Commission's current policies regarding conservation and load management programs.
ITEM 2. PROPERTIES The Company owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of its property is subject to the lien of a mortgage securing its First and Refunding Mortgage Bonds. Right-of-way grants from the apparent owners of real estate have been obtained for most electric lines, but underlying titles have not been examined except for transmissionHnes 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 13
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are on publicly owned property as to which permission for use is generally revocable. Portions of the Company's transmis-sion lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line if any exists.
The Company leases certain buildings and equipment. See Note H to CONSOLIDATED FINANCIAL STATEMENTS.
See Company Generating Units under SOURCES OF POWER under Item 1. BUSINESS.
ITEM 3. LEGAL PROCEEDINGS From time to time, the Company may be in violation of or in default under orders, statutes, rules or regulations relating to protection of the environment, compliance plans imposed upon or agreed to by the Company or permits issued by various local., state and federal agencies for the construction or operation of facilities. There may be pending from time to time administrative proceedings involving violations of state or federal environmental regulations that the Company believes are not material with respect to it and for which its aggregate liability for fines or penalties will not exceed $100,000. There are no material agency enforcement actions or citizen suits pending or, to the Company's present knowledge, threatened against the Company.
The civil action filed December 13, 1995, in the United States District Court for the Eastern District of Virginia, Norfolk Division, was dismissed by the Federal Court on August 7, 1996. However,two civil actions have been filed in the Virginia Circuit Court of the City of Norfolk against the City of Norfolk and Virginia Power, one for fifteen million dollars and one for three million dollars, by property owners who each allege contamination of their respective properties by hazardous substances originating on nearby property now owned by the city and formerly owned by the Company. The Company has filed answers denying liability. A trial date of August 18, 1997 has been set for the action seeking fifteen million dollars.
On May 24, 1996, in the proceeding to investigate the holding company structure and the relationship between Domin~
ion Resources and Virginia Power, the Virginia Commission entered an order imposing certain requrrements as to the adop-tion of conflict-of-interest standards, auditing of affi~iate transactions, and review of executive services provided by Dolhi~-
ion Resources. The proceeding was continued until July 12, 1997 to allow the Commission and its Staff to monitor the companies and evaluate whether further action by the Commission might be desirable. A consent order requiring Commis-sion approval before Dominion Resources can take certain corporate actions involving Virginia Power was allowed to expire in accordance with its terms on July 2, 1996.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 14
PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of the Company's Common Stock is owned by Dominion Resources.
During 1996 and 1995, the Company paid quarterly cash dividends on its C_ommon Stock as follows:
1996....................,...........................
1995................................................
1st
$ 95.3
$100.3 2nd 3rd (Millions)
$96.5
$96.1
$96.0
$99.2 ITEM 6. SELECTED FINANCIAL DATA Operating revenues...................................
Operating income............. :.......................
'Income before cumulative effect of a change in accounting principle............
Cumulative effect of a change in accounting principle.............................
Net income................................................
Balance available for Common Stock.....
Total assets................................................
Total net utility plant................................
Long-term debt, non.current capital lease obligations, preferred stock subject to mandatory redemption and preferred securities of subsidiary trust................
Utility plant expenditures (including nuclear fuel)..........................................
Capitalization ratios (percent):
Debt.......................................................
Preferred stock......................................
Preferred securities...............................
Common equity....................................
Embedded cost (percent):
Long-term debt.....................................
Preferred stock......................................
Preferred securities...............................
Weighted average.................................
1996 4,382.6 765.1 457.3 457.3 421.8 11,828.0 9,433.8 3,916.2 484.0 46.4 7.5 1.5 44.6 7.68 5.14 8.72 7.34 15 1995 1994 (Millions, except percentages) 4,350.4
$ 4,110.8 746.5 731.4 432.8 447.1 432.8 447.1 388.7 404.9 11,827.7 11,647.9 9,573.1 9,623.4 4,228.0 4,157.5 577.5 660.9
- 47.2 46.7 7.5 9.0 1.5 43.8 44.3 7.73 7.65 5.29 5.47 8.72 7.41 7.29 1993 4th
$ 97.9
$ 98.8 4,187.3 813.4 509.0 509.0 466.9 11,520.5 9,459.7 4,151.1 712.8 46.4 9.2 44.4 7.67 4.88 7.18 1992
$ 3,679.6 761.6 455.2 14.3 469.5 423.8 11,316.7 9,254.7 4,089.5 716.5 46.3 9.7 44:0 7.86 5.38 7.42
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This Management's Discussion and Analysis of Financial Condition and Results of Operations contains "fo~ard-look-ing statements" as defined by the Private Securities Litigation Reform Act of 1995, including (without lif!Utation) discussions as to expectations, beliefs, plans, objectives and future financial performance, or assumptions underlying or concerning mat-ters discussed in this document. These discussions, and any other discussions, including certain contingency* matters (and their respective cautionary statements) discussed elsewhere in this report, that are not historical facts, are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.
Some important factors that could cause actual results or outcomes to differ materially from those discussed in the forward-looking statements include current governmental policies and regulatory actions (including those of FERC, the EPA, the NRC and the Virginia Commission), industry and rate structure, operation of nuclear power facilities, acquisition and disposal of assets and facilities, operation and storage facilities, recovery of the cost of purchased power, nuclear decommis-sioning costs, and present or prospective wholesale and retail competition. The business and profitability of Virginia Power
_ are also influenced by economic and geographic factors including political and economic risks, changes in and compliance with environmental laws and policies, weather conditions and catastrophic weather-related damage, competition for retail and wholesale customers, pricing and.transportation of commodities, market demand for energy, inflation, capital market condi-tions, unanticipated changes in operating expenses and capital expenditures, competition for new energy development oppor-tunities and legal and administrative proceedings. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond the control of Virginia Power. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of each such factor on the business of the Company.
Any forward-looking statement speaks only as of the date on* which such statement is made, and Virginia Power under-takes no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.
Liquidity and Capital Resources Cash flow from operating activities has accounted for, on average, 75% of the Company's cash requirements over the past three years.
With the completion of the 882 Mw coal-fired power station near Clover, Virginia, the Company is in a period in which internal cash generation will exceed construction expenditures, The internal generation of cash in 1996, 1995 and 1994 provided 143%, 1 i9% and 88%, respectively, of the funds required for the Company's capital requirements.
Net cash provided by operating activities decreased $10.1 million in 1996 as compared to 1995, primarily as a result of normal operations.
Net cash provided by operating activities increased by $107.1 million in 1995 as compared to 1994, primarily as a result
- of increased sales, partially offset by a number of other factors resulting from normal operations.
Cash from (to) financing activities was as follows:
Common Stock......................................................................
Mortgage bonds.....................................................................
Medium-term notes...............................................................
Pollution control securities....................................................
Preferred securities of subsidiary trust.................................
Short-term debt......................................................................
Repayment of long-term debt and preferred stock..............
Dividends...............................................................................
Preferred securities distribution............................................
Other......................................................................................
Total.................. -................................................................
16 1996 24.5 143.4 (284.1)
(421.4)
(10.9)
(2.3)
$ (550.8) 1995 (Millions)
$ 200.0 40.0 135.0 169.0 (439.0)
(438.6)
(3.6)
(10.1)
$ (347.3) 1994 75.0 325.0 100.0 39.0 (43.0)
(334.3)
(438.2)
. (7.8)
$ (284.3)
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In 1996, the Company issued $24.5 million of variable rate solid waste disposal securities to refund $24.5 million of securitie~ assu,med in its acquisition of the North Branch Power Station. Also in 1996, the Company retired a total of$259.6 million of, Medium-Term Notes through mandatory maturities.
In June 1996, the Company increased the limitfor its commercial paper program from $300 million to $500 million with the execution of $500 million of revolving credit facilities, which replaced existing liquidity support. Proceeds from the sale of commercial paper are primarily used to finance working capital for operations. Net borrowings under the commercial paper program were $312.4 million at December 31, 1996.
In January 1997, the Company filed a registration statement with the Securities and Exchange Commission for $400 million of Junior Subordinated Debentures. At December 31, 1996, the Company had two additional shelf registration state-ments for debt securities registered with the Securities and Exchange Commission, one for $575 million of First and Refunding Mortgage Bonds and the other for $200 million of Medium-Term Notes, Series F. In February 1997, the Company issued $200 million of First and Refunding Mortgage Bonds, the proceeds of which were primarily used to refund a portion of the Company's debt that matured in February and March of 1997. These three shelf registrations combine to provide the Company with $975 million of unused debt capital resources. In addition, the Company has a Preferred Stock shelf, regis-tered with the Securities and Exchange Commission, for $100 million in aggregate principal amount, which has not been utilized. The Company intends to issue securities from time to time to meet its capital requirements.
Cash used in investing activities was as follows:
1996 1995 1994 (Millions)
Utility plant expenditures......................................................
$ (393.8)
$ (519.9)
$ (580.9)
Nuclear fuel,..........................................................................
N"uclear decommissioning contributions............. ~............*..,.
(90.2)
(57.6)
(80.0)
(36.2)
(28.5)
(24.5)
Sale of accounts receivable, net........ :..................................
Purchase of subsidiary assets................................................
(13:7)
(160.0)
(40.0)
Other................................................................ *...... *..............
(12.5)
(11.1)
(1.4)
- Total................... *.. **................. *.................. *......................
$ (546.4)
$ (777.1)
$ (726:8)
Investing*activities in 1996 resulted in a net cash outflow of $546.4 million'primarily due to $393.8 million of construc-tion expenditures and $90.2 million of nuclear fuel expenditures. The construction expenditures included approximately
$78.6 million for production projects, $244.6 million for transmission and distribution projects, and $17.1 million for new generating facilities.
Capital Requirements The Company presently anticipates that kilowatt-hour sales will grow approximately 2.4 percent a year through 2011.
The Hoosier,400 Mw and the AEP 500 Mw long-term purchase agreements will expire on December 31, 1999. With the scheduled termination of 900 Mw of long-term purchases and continued system load growth, the Company presently antici-pates adding 1,200 Mw of short-term (three-year) purchases beginning in the year 2000. The Company has and will pursue capacity acquisition plans to provide that capacity and maintain a high degree of service reliability. This capacity may be owned and operated by others and sold to the Company or may be built by the Company if it determines it can build capacity at a lower overall cost.
The Company's construction and nuclear fuel expenditures (excluding AFC), during 1997, 1998 and 1999 are expected to aggregate $529.2 million, $539.2 million and $397.0 million, respectively.
Clover Unit 2, which is part of a two-unit facility jointly owned with ODEC, began commercial operation in March 1996. The Company's fifty percent ownership share of the cost of construction was completed at a cost of $235 million.
The Company will require $311.3 million to meet long-term debt maturities in 1997. The Company presently estimates that all of its 1997 construction expenditures, including nuclear fuel expenditures, will be met through cash flow from opera-tions. Other capital requirements will be met through a combination of sales of securities and short-term borrowings.
Results of Operations
.The following is a, discussion of results of operations for the years ended 1996 as compared to 1995, and,1995 as compared to 1994.
17
e 1996 Compared to 1995 Balance available for Common Stock increased by $33.1 million as compared to 1995, pnmarily, as *a result,of an increase in operating revenues; a reduction in maintenance expenses primarily attributable to the Company's Vision 2000 initiatives, and a decline in restructuring costs, offset in part* by.the higher storm damage costs incurred from* destructive summer storms, and increased depreciation expense related to nuclear decommissioning and Clover Units 1 and 2, which began operations in October 1995 and March 1996, respectively.
Operating Revenues changed primarily due to the following:
- Increase (Decrease) *From Prior Year 1996 1995 (Millions)
Customer growth............................
$ 52.5
$ 76.2 Weather...........................................
4.4 81.6 Base rate variance..........................
(35.5).
6.3 Fuel rate variance...........................
(89.6)
(8.9)
. Other, net.................................... :...
34.1
~)
Total retail..:.;..... :........................
(34.1) 149.2 Sales for resale...............................
33.1 32.8 Other operating revenues...............
33.2
~)
Total revenues.............................
$ 32.2
$179.6 As detailed in the chart above, the decrease in retail revenues reflects a reduction in fuel rate revenues and a reduction in base revenues due to the effect of the mild summer weather in 1996 on the Company's sumrner*retail rates which are designed to reflect expected usage during normal weather conditions, offset in part by* continued customer growth during 1996. The increased sales for resale were primarily a result of the Company;s marketing efforts during_ 1996, offset by a decrease in sales to ODEC due to completion of Clover Units 1 and 2, of which ODEC owns a 50 percent interest. Other operating revenues increased primarily as a result of the revenues generated by the Company's non-regulated subsidiary, A&C Enercom, Inc,; which was forme(l in January 1996 to provide marketing, program planning and* design, customer engineering and energy consulting services.
During 1996, the Company had 44,528 new connections to its system compared to 44,955 and 46,741 in i995 and 1994, respectively.
Customer kilowatt-hour sales changed as follows:
Residential......................................
Commercial............,........................
. Industrial.....,........,..........................
Public authorities............................
Total retail sales.............................
Resale............................. -.................
Total sales............. :*........... :.............
- Cooling and heating degree days were as follows:
Cooling degree days.......................
Percentage change compared to prior year....................................
Heating degree. days........ :.. :.;.........
Percentage change compared to prior year....................................
1996 1,365 (18.1)%
4,131 9.0 %
Increase (Decrease) From Prior Year
_ 1996 1995 2.3%
4.1%
- 2.3 3.6 2.3 3.6 2.6 4.0 2.4 3.8 36.3 13.4 6.3 4.9 1995 1,667 3.3%
3,790 7.8%
Normal 1,531 3,672
- The increase in retail kilowatt-hour sales in 1996 as compared to 1995 reflects continued customer growth. The increase in kilowatt-hour sales for resale was primarily due to the Company's power marketing efforts.
18
e The average fuel cost of system energy output is shown below:
Nuclear............................................
Coal.................................................
Oil...................................................
Purchased power, net.....................
Other...............................................
Average fuel cost............................
System energy output is shown below:
Nuclear(*)..................,.....................
Coal(**)...........................................
Oil.................................................. *.
Purchased power, net......................
Other..... *...........................................
1996 4.48 14.32 27.75 21.99 26.98 13.47 Estimated 1997 33%
40 24 3
100%
Mills Per Kilowatt-hour 1995 1994
\\
4.92 4.89 14.44 14.61 25.11 23.00 22.50 23.99 23.82 25.46 13.73 14.02 Actual 1996 1995 1994 32%
32%
34%
38 39 36 I
1 3
27 25
. 23 2
3 4
100%
100%
100%
(*) Excludes ODEC's 11.6 percent ownership interest in the North Anna Power Station. The Company's four nuclear units operated at a combined capacity factor of 88.2% during 1996, a Company record.
(**) Excludes ODEC's 50 percent ownership interest in the Clover Power Station Fuel, net decreased as compared to 1995, primarily as a result of a higher recovery of fuel expenses subject to deferral accounting in 1995, offset in part by increased purchases of energy from other wholesale power suppliers:
Maintenance decreased as compared to 1995, primarily as a result ofa reduction in expenses attributable to the Com-pany's Vision 2000 initiatives, offset in part by the higher storm damage costs incurred from destructive summer storms, including Hurricane Fran.
Restructuring charges incurred as part of the Vision 2000 program (see Note P to CONSOLIDATED FINANCIAL STATEMENTS) decreased as compared to 1995, primarily as a result of the $37.3 million charge during 1995 for the cancel-lation of a project to construct a facility to handle low level radioactive waste at the Company's North Anna Power Station and the 1995 writedown of inventory and certain real estate, partially offset by a reserve recorded in 1996 for expected adjustments to regulatory assets. The Company recorded $91.6 million and $117.9 million of restructuring charges in 1996 and 1995, respectively. Restructuring charges included severance costs, purchased power contract restructuring and negoti-ated settlement costs, capital project cancellation costs and other costs. The Company estimates that the staffing reductions will result in annual savings, net of outsourcing costs, in the range of $62 million-to $90 million. When realized, savings from staffing reductions will be reflected in lower construction expenditures-as well-as lower operation and maintenance expenses.
While the Company may incur additional charges for.further staffing reductions µi 1997, the amounts are not expected to be significant.
The incurrence of restructuring charges and the savings resulting therefrom in subsequent periods are elements of the Company's cost of operations and will be considered in the cost of service information filed by the Company in response to the Virginia Commission's Order issued on November 12, 1996. See Regulation-Virginia Commission under Item 1. BUS-INESS for additional information on current rate proceedings.
In this increasingly competitive environment, the Company has also concluded that it is appropriate to utilize available*
savings and cost reductions, such as those generated by the Vision 2000 program, to accelerate the write-off of existing unamortized regulatory assets. Not only will this strategically position the Company in anticipation of competition, but it also reflects the Company's commitment to mitigate its exposure to potentially stranded costs (see Competition below). As of December 31, 1996, the Company had identified savings of $26.7 million which were used to establish a reserve for expected adjustments to regulatory assets.
19
e As part of re-engineering operations, the Company has adopted a plan to improve customer service which will require an investment in excess of $100 million over the next several years. That plan includes the installation of automated electric meters in metropolitan and inaccessible rural and urban locations. The plan also provides for the installation ~f m~bile data
,dispatch technology in the Company's service fleet, accompanied by digitized mapping of the Company's service territory.
Furthermore, technological changes are being made to enhance the Company's ability to handle customer calls during power outages. In order to increase service reliability, the Company has initiated both local and regional distribution line improve-ment projects.
Depreciation and amortization increased as compared to 1995, primarily as a result of greater nuclear decommissioning expense and depreciation related to Clover Units 1 and 2 which were placed in service in October 1995 and March 1996, respectively.
1995 Compared to 1994 Operating revenues increased as compared to 1994, primarily as a result of the weather, i.e., increased heating and cooling degree days, experienced in the last six months of 1995, customer gro~th and increased sales for resale.
Operating expenses -
Other and Maintenance decreased as compared to 1994. Expenses during 1994 included payroll and voluntary separation costs for those employees who elected to terminate service with the Company under the 1994 Early Retirement and Voluntary Separation Programs, offset in part by recognition of insurance policyholder distributions.
Expenses in 1995 reflected a decrease in payroll costs due to reduced staffing levels and weather-related overtime, offset by 1995 salary increases and the impact of employees being reassigned from capital to operation and maintenance activities. In addition, 1995 expenses include expenses associated with the North Branch Power Station, increased obsolete inventory costs, increased accruals for employee benefits, and increased nuclear outage costs.
Restructuring - The Company announced the implementation phase of its Vision 2000 program in March 1995. During 1995, the Company recorded $117.9 million of restructuring charges which included severance costs, purchase power con-tract cancellation and negotiated settlement costs, capital project cancellation costs and other costs.
Interest Charges - Interest on long-term debt increased as compared to 1994 primarily as a result of higher interest rates on First and Refunding Mortgage Bonds and Pollution Control Notes.
. Interest Charges - Other increased in 1995 primarily as a result of a reduction of $10.6 million in the interest accrued for prior years on certain tax obligations in 1994.
Future Issues Utility Rate Regulation
- Regulatory policy continues to be of fundamental importance to the Company and to its financial performance.
On November 12, 1996, the Virginia Commission instituted a proceeding and directed the Company to provide certain information, including any alternative form of regulation proposed by the Company at this time, by March 31, 1997. On March 7, 1997, in this proceeding and in a separate Annual Information Filing proceeding, the Virginia Commission entered an order providing that the Company's rates shall become interim rates subject to refund as of March 1, 1997.
For additional information on the current rate proceedings, see Regulation under Item 1. BUSINESS.
Environmental Matters The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and,.
regulations designed to protect human health and the environment, These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemak-ing process; however, should material costs be incurred and not recovered.through rates, the Company's results of operations and financial condition could be adversely impacted.
Environmental Protection and Monitoring Expenditures The Company incurred $71.1 million, $68.3 million and $67.3 million (including depreciation) during 1996, 1995 and 1994, respectively, in connection with the use of environmental protection facilities and expects these expenses to be approx-imately $71.5 million in 1997. In addition, capital expenditures to limit or monitor hazardous substances were $22.4 million,
':}
20
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$23.4 million and $47.3 million for 1996, 1995 and 1994, respectively. The amount estimated for 1997 for these expenditures is $14.3 million.
Clean Air Act Compliance The Clean Air Act, as amended in 1990, requires the Company to reduce its emissions of sulfur dioxide (S02) and nitrogen oxides (NO). Beginning in 1995, the S02 reduction program is based on the issuance of a limited number of S02 emission allowances, each of which may be used as a permit to emit one ton of S02 into the atmosphere or may be sold to someone else. The program is administered by the EPA.
The Company has installed S02 control equipment on Unit 3 at Mt. Storm Power Station. The S02 control equipment began operation on October 31, 1994. The cost of this and related equipment was $147 million. Additional plans for S02 control involve switching to lower sulfur coal, purchase of emniission allowances and additional S02 controls. Maximum flexibility and least-cost compliance will be maintained through annual studies. The Company has completed its compliance plan for NOx control, with the exception of some additional studies concerning Phase II of the Clean Air Act, for which the EPA issued final regulations in December 1996, and ozone control requirements, for which final regulations have not yet been promulgated.
In 1996, the Company installed NOx controls on Possum Point Unit 4 at a cost of about $4 million, and at Mt. Storm Unit 3 at a cost of about $6 million. The Company plans to install additional NOx controls and modify existing controls at Mt. Storm Units 1 and 2 in 1997, and to seek alternative emission limitations from the EPA for all three Mt.. Storm units. The Company has notified the EPA of its decision (called "early election") to begin complying with Phase I NOx limits at ten of its units in Virginia in 1997, three years earlier than otherwise required. As a result, the units will not be subject to more stringent Phase II limits until 2008.
In order to assist the Virginia Department of Environmental Quality in maintaining good air quality in the Richmond and Hampton Roads regions, and to avoid the necessity of more stringent regulations, the Company made voluntary commitments in 1996 to cap NOx emissions-at its Chesterfield and Yorktown Power Stations.and the Chesapeake Energy Center beginning in 2000.
- Capital expenditures on Clean Air Act compliance over the next five years are projected to be approximately $21 mil-lion. Changes in the.regulatory environment, availability of allowan~es, and emission~ control technology could substantially impact the timing and magnitude of compfoµ1ce expenditures.
- The Clean Air Act amendments also require the Company to obtain operating permits for all major e~issions-emitting facilities. Permit applications have been submitted, and deemed complete by the regulatory authorities, for the Mt. Storm and North Branch power stations. Applications for the Virginia stations are expected to be filed within the next two years.
Global Climate Change In 1993, the United Nation's Framework; Convention on Climate Change, als~ called The Global Warming Tre~ty, which was signed by more than 150 countries, including the United States, became effective. The objective of the treaty is the stabilization of greenhouse gas concentrations at a level that would prevent manmade emissions from interfering with the climate system.
Although there is considerable scientific* disagreement concerning the effects of greenhouse gas emissions on global climate, the United States and many other nations are supporting an international treaty, to be finalized in December 1997, containing legally binding emissions targets to.be achieved between 2010 and 2020. The reduction in greenhouse gas emis-sions necessary to achieve these targets is likely to have a substantial financial impact on companies that consume or produce fossil fuel derived electric power, including Virginia Power.
Electromagnetic Fields The possibility that exposure to electromagnetic fields emanating from power lines, household appliances and other electric sources may result in adverse health effects has been a subject of increased public, governmental and media attention.
A considerable amount of scientific research has been conducted on this topic without definitive results. Research is continu-ing to resolve scientific uncertainties. It is too soon to tell what, if any, impact these actions may have on the Company's financial condition.
21
e Nuclear Operations The NRC revised the nuclear power plant license renewal rules issued in 1991. The Company intends to work ~ith industry groups on license renewal programs, and apply for renewal of the current 40-year licenses.
For information on nuclear decommissioning, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.
Risk Management Policy In January 1997, the Company adopted a formal risk management policy. The primary purpose of that policy is to ensure that the Company's risk management activities (1) support the advancement of the Company's strategic business plan, (2) properly manage and mitigate the business and financial risks of the Company through the implementation of strategies with respect to trading, contracting, and other tactics in order to coordinate the effective management of the Company's physical assets, and (3) manage the total risk profile of the Company including physical and financial risk positions utilizing a portfolio approach. NYMEX futures, NYMEX exchange options, over-the-counter (OTC) swaps, and OTC options are
- permitted financial instruments if utilized in the natural gas, oil products, electric power and coal markets. The use of deriva-tives with financial instruments as underlyings are also permitted, but are subject to review and approval on an individual transaction basis. The risk management policy strictly prohibits the undertaking of activities for purely speculative purposes.
While the Company has in the past used swaps, options and other derivative instruments to hedge business and other financial risks, such activity has not been material.
Competition -
In General A number of developments in the United States are causing a trend toward less regulation of and more competition in the. electric utility industry. This is evidenced by legislative and regulatory action at both the federal and state levels. To the extent that competition is either authorized or mandated and regulation is eliminated or relaxed, electric utilities will no
- longer, in the absence of appropriate legislative or regulatory action during the transition period, be guaranteed an opportu-nity to recover all of their prudently-incurred costs including their cost of capital, and utilities with costs that exceed the market prices established by the competitive market will run the risk 9f suffering losses, which may be substantial.
Virginia Power has responded to these trends by undertaking cost-cutting measures, engaging in re-engineering efforts.
of its core business processes, and pursuing a strategic planning initiative (called Vision 2000) to encourage innovative approaches to servicing traditional markets and to develop appropriate methods by which to service future markets. The Company has established separate business units for its nuclear operations, fossil and hydroelectric operations, commercial operations and its energy services business: It has created a subsidiary to provide nuclear management and operation services to electric utilities seeking assistance in the management and operation of their nuclear generating facilities; it.acquired an operating business, A&C Enercom, Inc., a provider of marketing, program planning and design, customer engineering and energy consulting services; it is seeking approval to engage in the telecommunications business; and it is in the planning stages of creating additional subsidiaries to engage in these and other unregulated businesses. It is also taking regulatory and legislative initiatives designed to enhance the likelihood that the transition to competition is an orderly one and that the Company will not be prevented from recovering prudently-incurred costs and investments.
In addition, Virginia Power is actively pursuing opportunities to expand its markets through strategic alliances with partners whose strengths, market position and strategies complement the Company's and where efficiencies can be gained through the alliance.
A significant part of the Company's strategy relies on developing "non-traditional" business opportunities designed to provide growth in earnings. The Energy Services Business Unit is the most prominent example of this growth strategy. The Energy Services Business Unit is expected to contribute to earnings growth by offering the market a portfolio of energy related products and services. Other examples of such opportunities include the Fossil & Hydro Business Unit, through which the company will target process type industries, such as chemical, paper, plastics and petroleum to become a service provider of instrumentation equipment, and the Nuclear Business Unit, whose position as an industry leader offers opportunities to provide services to other nuclear utilities striving to improve their safety and operating records. The Commercial Operations Business Unit will provide power distribution related services. Finally, the Telecommunications Act of 1996 opened up opportunities to generate growth through use of existing telecommunications infrastructure to provide.-.telecommunications services and new energy services through the Company's *existing fiber~optic network.
22
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Virginia Power has organized a wholesale power group to engage in off-system wholesale purchases and sales, and that group is developing trading relationships beyond the geographic limits of Virginia Power's retail service territory. The Com-pany has. also.been successful in negotiation of wholesale requirements contracts with multi-year provisions for notice of termination of service and a long-term contract with large federal government customers for service to facilities within the Company's service territory and has obtained regulatory approval of innovative pricing proposals for industrial loads, although rate concessions have been necessary in some cases. To date, the Company has not experienced any material loss of load, and the reduction of 1997 revenues attributable to such rate concessions is expected to approximate $22 million.
Competition -
Wholesale Competition at the wholesale level has been mandated by the Energy Policy Act and the FERC regulations thereunder.
During 1996, sales to wholesale customers represented approximately 8 percent of the Company's t9tal revenues from elec-tric sales. Approximately 4 percent of wholesale rev¢nues resulted from the Company's power marketing efforts to make off-system sales.
FERC established the requirements for open transmission access and related matters in final rules issued on April 24, 1996 in Order No. 888 and Order No. 889. This enables other suppliers of power to displace electric service provided by a utility to wholesale customers served by the utility's'transmission system, unless those customers are required by contract to take service from the utility. The orders required utilities to file with FERC an open access transmission tariff, which Virginia Power did on July 9, 1996; they require utilities to take transmission service under that tariff for wholesale power sales; they provide for utilities to recover legitimate, prudent and verifiable costs that would be unrecoverable in a competitive market (strimded costs); they require utilities to participate in an open access same-time information system (OASIS); and they require separation of transmission operations and reliability functions from wholesale merchant and marketing functions.
FERC also issued a notice of proposed rulemaking proposing replacement of open access tariffs with a capacity reservatioff tariff by December 31, 1997. On March 4, 1997, FERC issued Order No. 888-A, in which it addressed requests for rehearing of Order No. 888. Order No: 888-A essentially reaffirms the basic principles of Order No. 888 and clarifies and makes limited modifications to Order No. 888. Parties seeking judicial review of Order Nos. 888 and 888-A must file petition for review with the appropriate United States Court of Appeal by May 5, 1997.
On August 15, 1996, pursuant to the provisions of the Interconnection and Operating Agreement between ODEC and Virginia Power, ODEC gave written notice of its intent to reduce its supplemental demand purchases under that Agreement to zero within nine years. 1997 supplement~! demand charges (other than charges relating to transmission and dis_tribution which will continue in any case) are expected to be $63 million. On November 19, 1996, the Company and ODEC reached principles of agreement providing that Virginia Power will continue to supply all of ODEC's supplemental capacity needs through 2005, rather than the declining amounts after 1999 under prior agreements. Under the principles of agreement, the Company's recovery of fixed charges will be reduced over time as supplemental capacity rates transition from fully-embed-ded costs to market-based pricing: The Company estimates the reduced rates, offset in part by other revenues which may be earned under the agreement, will decrease income before taxes by approximately $38 million through 2005.
Competition -:- Retail General retail competition presently is not authorized in Virginia and North Carolina, and as a result Virginia Power faces competition for retail sales only in the ability of certain business customers to relocate among utility service territories, to substitute other energy sources for electric power, and to generate their own electricity. But major customers, principally industrial, and other suppliers of power are advocating retail competition vigorously in Congress and in the Virginia and North Carolina legislatures and commissions. Legislation either to authorize or require retail competition is under considera-tion in the present Congress, a joint sub-committee of the Virginia Senate and House of Delegates is considering whether and how such competition should be allowed or required, and legislation is pending before the North Carolina.General Assembly that would establish a study commission to determine whether legislation is necessary to ensure adequate, reliable and eco-nomical electric service in light of current trends in the industry.
Virginia Power has been advocating a cautious and measured approach to the question of retail competition. In 1996 it initiated legislation, which was enacted by the Virginia General Assembly and became effective July 1, 1996, that authorizes the Virginia Commission to approve alternative forms of regulation, economic development rates and packages of incentive rates; that facilitates a regulated utility's ability to enter into joint ventures and parQ1.erships; that authorizes the Virginia Commission to determine the treatment of stranded costs for service to federal customer accounts, which are otherwise outside the Commission's ratemaking jurisdiction; that establishes that a local referendum must be held before municipaliza-tion of utility services. may occur for services previously provided by a utility; and that authorizes the Virginia Commission to 23
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determine stranded cost payments when utility property is condemned by a municipality or other corporation possessing the power of eminent domain. The Company has also obtained regulatory approval of innovative pricing proposals for industrial loads in Virginia and North Carolina and entered into an energy partnership with a key industrial custo~er.,
The Virginia Commission is taking an active interest in retail competition in the electric utility industry and the industry restructuring that might accompany such competition. It has instituted both a generic investigation of industry restructuring and competition and a separate proceeding specifically invol.ving Virginia Power, the Company has proposed in that case an alternative regulatory plan intended to facilitate an orderly transition to competition~ if such competition should be allowed, including full recovery of any potentially stranded costs. The Company's case was filed with the Commission on March 24, 1997, and it proposes a freeze of present rates. through December 31, 2002, during which a portion of earnings above the approved level would be used to accelerate the write-off of generation-related regulatory assets and mitigate the costs associ-ated with payments under power purchase contracts with non-utility* generators. If the proposed plan is approved, the Com-*
pany would commit to write-off $494 million of regulatory assets or other potentially stranded costs during the five-year rate freeze period; however, the Company believes that current rates, which are requested to remain in effect, would be sufficient to permit the recognition.of these costs without adversely impacting the results of operations during and after the five-year period. The Company also seeks approval of the principle of stranded cost.recovery as well as approval of a Transition Cost Charge mechanism by which costs that may become stranded at the onset of competition will be recoverable from customers who elect to purchase their power in:the competitive market if retail competition is allowed in Virginia. The Commission has not established a procedural schedule for the Company's case.
For a more qetailed description of the Virginia Commission proceedings, see Regulation under Item L BUSINESS.
Competition -
SPAS 71 Virginia Power's regulated rates are designed to recover its prudently incurred costs of providing service, including the opportunity to earn a reasonable return on its shareholder's investment. The Company's financial statements reflect assets and costs under this cost-based rate regulation in accordance with Statement of.Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation," which provides* that certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets and are recognized as the related amounts are included in rates and recovered from customers. Continued accounting under SFAS 71 requires that rates designed to recover the utility's specific costs of providing service, are, and will continue to be, *established by regulators. The presence of increasing competition that limits the utility's ability to charge rates that recover its costs, or a change in the method of.
regulation with the same effect, could result in the discontinued applicability of SFAS 71.
Rate-regulated companies are required to write off regulatory assets against earnings whenever those assets no longer meet the criteria for recognition as defined by SFAS 71. In addition, SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," requires a review of long-lived assets for impairment whenever events or changes in circumstances., such as those used to determine c.ontinued applicability of SFAS 71, indicate that the carrying amount of an asset may not be recoverable.
Virginia Power's operations currently satisfy the SFAS 71 criteria. However, if events or circumstances should change so that those criteria are no longer satisfied, management believes that a material adverse effect on the Company's results of operations and financial position may result. In light of changes predicted for the electric utility industry, however, the Company will continue monitoring its regulatory operations in light of the SFAS 71 requirements.
Competition -
Exposure to Potentially. Stranded Costs Under traditional cost-based regulation, utilities have generally* had an obligation to serve supported by an implicit promise of the opportunity to recover prudently incurred costs. The most significant potential adverse effect of competition is "stranded costs." Stranded costs are those costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market. Regulatory assets recognized under SFAS 71, umecovered investment in power plants, commitments such as long-term purchased power contracts and nuclear decommis-sioning costs are items that may become stranded costs if prices for electric services are determined by the market rather than based on the cost of providing that service.
The Company's potential exposure to stranded costs is comprised of long-term purchased power contracts that may be above market, costs pertaining to certain generating plants that may become uneconomic in a deregulated environment and regulatory assets for items such as income tax benefits previously flowed-through to customers, deferred losses on reacquired*
debt, and other costs (see Note G to CONSOLIDATED FINANCIAL STATEMENTS). In addition, unfunded obligations for 24
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nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements could contribute to the Company's exposure to potentially stranded costs. See Notes C and O to CONSOLIDATED FINANCIAL STATEMENTS.
Any forecast of potentially stranded costs is inextricably tied to the assumptions made at the time of the analysis, including the timing of open access (customer choice) in the market for electric service, the extent of open access permitted, potential prices in the competitive market, sales and load growth forecasts, future operating performance, rate revenues per-mitted during the transition, cost structure over time, mitigation opportunities and stranded cost recovery mechanisms. The c_alculation of potentially stranded costs is extremely sensitive to the various assumptions made. Certain combinations of these assumptions as applied to Virginia Power would produce little to no stranded costs; under other scenarios Virginia Power's exposure to potentially stranded costs could be substantial.
Virginia Power is presently assessing the reasonableness of various possible assumptions, but it has not been able to settle on any particular combination thereof. Thus Virginia Power's maximum exposure to potentially stranded costs is uncer-tain, as is the extent to which such costs, if any, will be recoverable from customers. Virginia Power believes that recovery of such costs, if any, is appropriate and will vigorously pursue the recovery of any potentially stranded costs with the regulatory*
commissions having jurisdiction over its operations and continue to implement cost-reduction measures in an effort to miti-gate the amount at risk.
Presently, Virginia Power expects to continue to operate under regulation and to recover its cost of providing traditional electric service. However, the form of cost-based rate regulation under which Virginia Power operates is likely to evolve as a result of various legislative or regulatory initiatives, including Virginia Power's alternative regulatory plan filed with the Virginia Commission on March 24, 1997. At this time, Virginia Power management can predict neither the ultimate outcome of regulatory reform in the electric utility industry nor the impact such changes would have on Virginia Power.
25
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX*
Page '
No.
Report of Management.....................................................................................,................ :...............................
27 Report of Independent Auditors....................................................... :............................................................ :...
28 Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994....................
29 Consolidated Balance Sheets at December 31, 1996 and 1995......................................................................
30 Consolidated Statements of Earnings Reinvested in Business for the years ended December 31, 1996, 1995 and 1994............................................................................................................................ :..................
32 Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994............
33 Notes to Consolidated Financial Statements................ ;........................................ '............................................
34 26
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- REPORT OF MANAGEMENT The Company's management is responsible for all information and representations contained in the Consolidated Finan-
'cial Stateµients an,d other sections of the Company's annu11I report on Form 10-K.. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.
Management maintains a system, of internal accounting controls designed to provide reasonable assurance, at *a reason-able cost, that the Company's assets are.safeguarded against loss.from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control and, therefore cannot provide absolute assurance that the objectives of the established internal accounting controls will be met. This system includes written policies, an organization~! structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Manage-ment believes that during 1996 the system of internal control was adequate to accomplish the intended objective.
The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by the Board of Directors. Their audits were conducted Ill accordance with generally accepted auditing stan-dards and included a review of the Company's accounting systems,'procedures and internal controls, and the performance of tests and other auditing procedures sufficient to provide reasonable assurance that the Consolidated Financial Statements are not materially misleading and do not contain material errors.
The Audit Committee of the Board of Directors, composed entirely of directors who are not officers or employees of the Company, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, inter-nal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. Both the independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.
Management recognizes its responsibility for fostering a strong ethical climate so that the Company's affairs are con-ducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Company's Code of Ethics, which is distributed throughout the Company. The Code of Ethics addresses, among other things, the importance of ensuring open communication within the Company; potential conflicts of interest; compliance with all domestic and foreign laws, including those relating to financial disclosure; the confidentiality of proprietary information; and full disclosure of public information.
J. T. Rhodes President and Chief Executive Officer VIRGINIA ELECTRIC AND POWER COMPANY 27 E. M. Roach, Jr.
Senior Vice President-Finance, Regulation & General Counsel
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REPORT OF INDEPENDENT AUDITORS To the Board of Directors of Virginia Electric and Power Company:
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power c*ompany (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the Company) as of December 31, 1°996 and 1995, and the related consolidated statements of income, earnings reinvested in business, and cash flows for each of the three years in the period ended December 31, 1996. 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 corid~cted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurapce about w~ether the financial st;;i.tements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial stateµients. An audit also includes assessing the accounting principles used and.significant estimates made by management, as well as evalu-ating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such conspHdated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with ~enerally accepted accounting principles.
DELOITTE & TOUCHE LLP Richmond, Virginia Februar:y 11, 1997 28
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VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1996 1995 1994 (Millions)
Operating revenues***************************************************************.**********
$4,382.6
$4,350.4
$4,170.8 Operating expenses:
Operation:
Fuel, net..................................................................................
987.0 1,006.9 973.0 Purchased power capacity, net....................... _........................
700.5 688.4 669.4 Other.......................................................................................
546.9 543.8 577.4 Maintenance............................... :................................................
250.9 260.5 263.2 Restructuring...............................................................................
91.6 117.9 Depreciation and amortization...................................................
502.0 469.1 446.3 Amortization of terminated construction project costs.............
34.4 34.4 34.4 Taxes -
Income.........................................................................
241.9 228.1
'223.0
-Other.................................................. :.........................
262.3 254.8 252.7 Total................................*...................................................
3,617.5 3,603.9 3,439.4 Operating income...........................................................................
765.1 746.5 731.4 Other income..................................................................................
7.7 6.7 10.9 Income before interest charges............................... *.......................
772.8 753.2 742.3 Interest charges:
Interest on long-term dept..........................................................
287.9 302.6 291.9 Other...........................................................................................
22.4 20.1 7.5 Allowance for borrowed funds used° during construction........
(1.9)
(4.7)
(4.2)
Total.. :................................................................................
308.4 318.0 295.2 Distributions -
preferred securities of subsidiary trust, net.......
7.1 2.4 Net income......................................................................................
457.3 432.8 447.1 Preferred dividends.........................................................................
35.5 44.1 42.2 Balance available for Common Stock...........................................
$ 421.8
$ 388.7.
$ 404.9 The accompanying notes are an integral part of the financial statements.
29
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VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Assets (Millions of Dollars)
UTILITY PLANT:
Plant (includes plant under construction of $180.1 in 1996 and $512.1 in 1995) **********************************************************************************************************
Less accumulated depreciation.....................................................................
Nuclear fuel (less accumulated amortization of $698.5 in 1996 and
$703.6 in 1995).........................................................................................
Total net utility plant.......... :.............................................................'.....
INVESTMENTS:
Nuclear decommissioning trust funds..........................................................
Other............................................................................................-..................
Total net i.J;lvestments.............................................................................
CURRENT ASSETS:
Cash and cash equivalents................................................................. _...........
Accounts receivable:
Customers (less allowance for doubtful accounts of $2.4 in 1996 and
$1.7 in 1995).........................................................................................
Other...........................................................................................................
Accrued unbilled revenues............................................................................
Materials and supplies at average cost or less:
. Plant and general.......................................................................................
Fossil fuel...................................................................................................
Other..............................................................................................................
Total current assets................................................................................
DEFERRED DEBITS AND OTHER ASSETS:
Regulatory assets...........................................................................................
Unamortized debt issuance costs..................................................................
Other..............................................................................................,.... ;..........
Total deferred debits and other assets..................................................
Total assets.............................................................................................
The accompanying notes are an integral part of the financial statements.
30 At December 31, 1996 1995
$14,506.8
$14,201.6 5,218.3 4,760.9 9,288.5 9,440.7 145.3 132.4 9,433.8 9,573.1 443.3 351.4 34.5 32.9 477.8 384.3 47.9 29.8 354.8 362.6 80.4 58.3 162.8 179.5 148.7 160.2 76.8 71.2 124.5 75.2 995.9 936.8 773.9 816.4 24.7 26.6 121.9 90.5 920.5 933.5
$11,828.0
$11,827.7
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VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED BALANCE SHEETS Liabilities and Shareholders' Equity (Millions of Dollars)
LONG-TERM DEBT....................................-....................................................
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST*.........................
PREFERRED STOCK:
Preferred stock subject to mandatory redemption.......................................
Preferred stock not subject to mandatory redemption.................................
COMMON STOCKHOLDER'S EQillTY:
Common Stock, no par, 300,000 shares authorized, 171,484 shares outstanding at December 31, 1996 and 1995..........................................
Other paid-in capital......................................................................................
Earnings reinvested in business....................................................................
Total common stockholder's equity........................................................
CURRENT LIABILITIES:
Securities due within one year.....................................................................
Short-term debt..............................................................................................
Accounts payable, trade......................................................................,.........
Customer deposits.........................................................................................
Payrolls accrued.............................................................................................
Severance costs accrued................................................................................
Interest accrued..............................................................................................
Other..................................................................... *........................................
Total current liabilities.............................................................................
DEFERRED CREDITS AND OTIIER LIABILITIES:
Accumulated deferred income taxes.............................................................
Deferred investment tax credits....................................................................
Deferred fuel expenses..................................................................................
Other..............................................................................................................
Total deferred credits and other liabilities..............................................
COMMITMENTS AND CONTINGENCIES (See Note Q)
Total liabilities and shareholders' equity................................................
At December 31, 1996 1995
$ 3,579.4
$ 3,889.4 135.0 135.0 180.0 180.0 509.0 509.0 2,737.4 2,737.4 16.9 16.9 1,308.4 1,272.5 4,062.7 4,026.8 311.3 259.6 312.4 169.0 368.5 310.7 50.0 55.4 73.2 77.7 50.2 42.5 95.3 101.8 126.1 99.0 1,387.0 1,115.7 1,565.2 1,498.8 255.3 272.2 3.3 57.7 151.1 143.1 1,974.9 1,971.8
$11,828.0
$11,827.7
(*) As described in Note J to CONSOLIDATED FINANCIAL STATEMENTS, the 8.05% Junior Subordinated Notes total-ling $139.2 million principal amount constitute 100% of the Trust's assets.
The accompanying notes are an integral part of the financial statements.
31
VI!INIA ELECTRIC AND POWER COMP, CONSOLIDATED STATEMENTS OF EARNINGS REINVESTED IN BUSINESS For the Years Ended D:2cember.31, 1996 1995 (Millions)
Balance at beginning of year.........................................................
$1,272.5
$1,277.8 Net income.................................................................................. :...
457.3 432.8 Total........................................................................................
1,729.8 1,710.6 Cash dividends:
Preferred stock subject to mandatory redemption....................
11.1 13.5 Preferred stock not subject to mandatory redemption..............
24.5 30.8
- Common Stock............................................................ ;..............
385.8 394.3 Total dividends.......................................................................
421.4' 438.6 Other additions (deductions), net...................................................
0.5 Balance at end of year............................................................... _._..,
$1,308.4
$1,272.5
- The accompanying notes are an integral part of the financial statements.
32 1994
$1,269.3 447.1 1,716.4 14.4 28.3 395.5 438.2 (0.4)
$1,277.8
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VIRGINIA ELECTRIC AND POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1996 1995 1994 (Millions)
Cash F.low From Operating Activities:
Net mcome.................................................................................................
$ 457.3
$ 432.8
$ 447.1 Adjustments to reconcile net income to net cash provided by
- operating activities:
Depreciation and amortization....... :..................................................
Allowance for other funds used during construction................... :..
616.0 585.1 558.3 (3.0)
(6.7)
(6.4)
Deferred income taxes................................. ;....................................
- 69.1 11.8 56.7 Deferred investment tax credits........................................................
(17.0)
(16.9)
(17.1)
Noncash return on terminated construction project costs -
pretax............................................................................... ;..............
(6.4)
(8.4)
(10.3)
Deferred fuel expenses, net...............................................................
(54.4) 6.2 (2.6)
Deferred capacity expenses................................................................
(9.2) 6.4 26.5 Restructuring......................................................................................
56.3 96.2 Changes in:
Accounts receivable.......................................................................
(11.3)
(54.3) 36.5 Accrued unbilled revenues............................................................
17.6 (27.7) 11.9
.Materials and supplies...................................................................
6.0 61.1 (6.5)
A~counts payable, trade.................................................................
Accrued expenses..........................................................................
57;8 (8.9) 21.1 (62.6) 44.7 (29.0)
Provision for rate refunds..........................................................,..
(12.2)
(89.5)
Other...............................................................................................'...
(.9) 16.2 21.6 Net Cash Flow From Operating Activities.................................................
1,115.3 1,125.4 1,018.3 Cash Flow From (To) Financing Activities:
Issuance of Common Stock......................................................................
75.0 Issuance of long-term debt........................................................................
24.5 240.0 464.0 Issuance of preferred securities of subsidiary trust.................................
135.0 Issuance (Repayment) of short-term debt................................................
143.4 169.0 (43.0)
Repayment of long-term debt and preferred stock..................................
(284.1)
(439.0)
(334.3)
Common Stock dividend payments..........................................................
(385.8)
(394.3)
(395.5)
Preferred stock dividend payments....................,......................................
(35.6)
(44.3)
(42.7)
Distribution-preferred securities of subsidiary trust..................................
(10.9)
(3.6)
Other..........................................................................................................
(2.3)
(10.1)
(7.8)
Net Cash Flow To Financing Activities.......................................................
(550.8)
(347.3)
(284.3)
Cash Flow From Used In Investing Activities:
Utility plant expenditures (excluding AFC-other funds)...................
(393.8)
(519.9)
(580.9)
Nuc.lear fuel (excluding AFC-other funds)........................................
(90.2)
(57.6)
(80.0)
Nuclear decommissioning contributions......................,............................
(36.2)
(28.5)
(24.5)
Sale of accounts receivable, net...............................................................
(160.0)
(40.0)
Purchase of subsidiary assets................... :................................................
(13.7)
Other..........................................................................................................
(12.5)
(11.1)
(1.4)
Net Cash Flow Used In Investing Activities...............................................
(546.4)
(777.1)
(726.8)
Increase in cash and cash equivalents..........................................................
18.1 1.0 7.2 Cash and cash equivalents at beginning of year.........................................
29.8 28.8 21.6 Cash and cash equivalents at end of year....................................................
47.9 29.8 28.8 Cash paid during the year for:
Interest (reduced for the cost of borrowed funds capitalized as AFC).
$ 295.4
$ 3145
$ 302.9 Income taxes..............................................................................................
Non-cash transactions for financing and investing activities:
216.1 215.8 190.5 AsSUJ?J?~ion of o~lJgations........................................................................
Acqms1t10n of utility property..................................................................
26.3 26.3 The accompanying notes are an integral part of the financial statements.
33
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VIRGINIA ELECTRIC AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A. Significant Accounting Policies:
General Virginia Electric and Power Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy within a 30,000 square mile area in Virginia and northeastern North Carolina. It sells electricity to retail customers (including governmental agencies) and to wholesale customers such as rural electric cooperatives and munic-ipalities. The Virginia service area comprises about 65 percent of Virginia's total land area, but accounts for over 80 percent of its population.
The Company's accounting practices are generally prescribed by the Uniform System of Accounts promulgated by the regulatory commissions having jurisdiction and are in accordance with generally accepted accounting principles applicable to regulated enterprises. The financial statements include. the accounts of the Company and its subsidiaries, with all significant intercompany transactions and accounts being eliminated on consolidation.
The Company is a wholly-owned subsidiary of Dominion Resources, Inc., a Virginia corporation.
The preparation of financial statements in conformity with generally accepted accounting principles requires manage-ment to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and.expenses during.the reporting period. Actual results could differ from those estimates.
Revenues Operating revenues are recorded on the basis of service rendered.
Pr~perty, Plant and Equipment Utility plant is recorded at original cost which includes labor, materials, services, AFC, where permitted by regulators, and other indirect costs. The cost of maintenance and repairs is charged to the appropriate operating expense and clearing
.accounts. The cost of additions and.replacements is charged to the appropriate utility plant account, except that. the cost of minor additions and replacements, as provided in the Uriiform System of Accounts, is charged to maintenance expense.
Depreciation and Amortization Depreciation of utility plant (other than nuclear fuel) is computed on the straight-line method based on projected useful service lives. The cost of depreciable utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation. The provision for depreciation provides for the recovery of the cost of assets including the estimated cost of removal, net of salvage, and is based on the weighted average depreciable plant using a rate of 3.2 percent for 1996, 1995 and 1994.
Operating expenses include amortization of nuclear fuel, which is provided on a unit of production basis sufficient to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs.
34
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Federal Income Taxes
~e !=oml?any files a consolidated federal income tax return with Dominion Resources.
Deferred inve'stment tax credits are being amortized over the service lives of the property giving rise to such credits.
Allowance for Funds Used During Construction The applicable regulatory Uniform System of Accounts defines AFC as the cost during the construction period of bor-rowed funds used for construction purposes and a reasonable rate on other funds when so used.
The pretax AFC rates for 1996, 1995 -and 1994 were 8.1, 8.9 and 8.9 percent, respectively. No AFC_ is_ accrued,for
' approximately 82 percent of the Company's construction work in progress whic~ is instead inc.luded in rate base. A cai;h return is currently collected on the poqion of construction work in progrei;s included in rate base...
Deferred Capacity and Fuel Expense
. Approximately 80% of capacity expenses and 90% _of fuel expenses are subject to deferral accounting. The difference between reasonably incurred actual expenses and the level of expenses included in current rates is deferred and matched against future revenues.
Amortization of Debt Issuance Costs
- The Company defers and amortizes any expenses incurred in the issuance of long-term debt, including premiums and discounts associated with such debt, ~ver the lives of the respective issues. Any gains or losses resulting from the refinancing of debt are also deferred and amortized over the lives of the* new issues of long-term debt as permitted by the appropriate regulatory jurisdictions. Gains or losses* resulting from the redemption of debt without refinancing are amortized over tlie remaining lives of the redeemed issues.
Cash. and Cash Equivalents Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, -1996 and_ 1995, the Company's acc;:ounts payable included the net effect of checks outstanding but not yet presented for payment of $64.8 million and $62.7 *million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on_hand _a,nd temporary investments purchased with an initial maturity of three months or less.
Reclassification Certain amounts in the 1995 and 1994 financial statements have_ been :redassifi~d *t~ _co~fo~ to the 1996 presentation.
3S-
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B. Income Taxes:
Details of income tax expense are as follows:
Years '
1996 1995 1994 (Millions)
Current expense:
Federal..............................................................................................
$ 185.3
$ 231.0
$ 185.6 State..................................................................................................
2.3 2.1 2.1 187.6 233.1 187.7 Deferred expense:
Plant related items...........................................................................
65.4 48.9 39.0 Deferred fuel and capacity..............................................................
22.3 (6.0)
(8.2)
Debt issuance costs.........................................................................
(2.8) 1.3 3.7 Customer accounts reserve..............................................................
36.8 Terminated construction project costs............................................
(7.3)
(7.3)
(7.3)
Other............................................................................. *..................
(6.4)
(25.0)
. (11.6) 71.2 11.9 52.4
- Net deferred investment tax credits-amortization..............................
(16.9)
(16.9)
(17.1)
Income tax expense-operating income...............................................
241.9 228.1 223.0 Income tax expense associated with nonoperating income:
Current expense:
4.2 0.8 (1.7)
(2.1)
(0.1) 4.3 Federal........................................... *..................................................
Deferred expense.................................................................................
Income.tax expense-nonoperating.income.................................. ;......
2.1 0.7 2.6 Total income tax expense....................................................................
$ 244.0
$ 228.8
$ 225.6 Total federal income tax expense differs from the amount computed by applying the statutory federal income tax rate to pr~tax income for the following reasons:
Federal income tax expense at statutory rate of 35%....
Increases (decreases) resulting from:
Utility plant differences................................................
Ratable amortization of investment tax credits...........
Terminated construction project costs.........................
- other, net............. ;....................................... :................
Total federal income tax expense....................................
Effective tax rate..............................................................
1996
$242.8 5.7 (16.9)
- 5.0 3.7
~)
$240.3 34.6%
Years 1995 (Millions)
$229.9 3.2 (16.9) 5.0 4.2
_ii:~)
$225.4 34.3%
The following chart reconciles total income tax expense as shown on the Consolidated Statements of Income:
Years 1996 1995 (Millions)
Total federal income tax expense....................................
$240.3
$225.4 Less: federal income tax charged other income.............
2.1 0.7 Add: state income tax charged to operating income......
3.7 3.4 Total income tax expense charged to operating income
$241.9
$228.1 36 1994
$234.4 (1.8)
(17.1) 5.0 2.1 (11.8)
$222.6 33.2%
1994
$222.6 2.6 3.0
$223.0
e The Company's net accumulated deferred income taxes consist of the following:
Deferred income tax assets:
Investment tax credits...............................................................................
Deferred income tax liabilities:
Plant-method and basis differences..........................................................
Terminated construction project costs.......................................................
Income taxes recoverable through future rates...................... :.................
Other................................................................................... :.................... :.
Total deferred income tax liabilities.............................................................
Total net accumulated deferred income taxes............ :.................................
C. Nuclear Operations:
Decommissioning 1996 90.3 1,440.5 14.4 168.8 31.8 1,655.5
$1,565.2 Years (Millions) 1995 96.4 1,384.4 19.5 171.6 19.7 1,595.2
$1,498.8 Nuclear plant decommissioning costs are accrued and recovered through rates over the expected service lives of the Company's nuclear generating units. The amounts collected from customers are being placed in trusts, which, with the accu-mulated earnings thereon, will be utilized solely to fund future decommissioning obligations.
NRC license expiration year......................... :........................ *...........................
Method of decommissioning.........................................................................
Current cost estimate (1994) dollars............................................................
Funds in external trusts at December 31, 1996...........................................
1996 contribution to external trusts..............................................................
North Anna Surry Unit 1 Unit 2 Unit 1 Unit 2 2018 DECON
$247.0 105.1 7.6 2020 DECON 2012 DECON (Millions)
$253.6
$272.4 98.9 121.8 7.2 10.6 2013.
DECON
$274.0 117.5 10.8 Approximately every four years, site-specific studies are prepare.ct to determine the decommissioning cost estimate for the Company's four nuclear units. DECON assumes the activities associated with decontamination or prompt removal of radioactive contaminants will begin shortly after cessation of operations so that the property may be released for unrestricted use.
The accumulated provision for decommissioning of $443.3 million and $351.4 million is included in Utility Plant Accu-mulated Depreciation at December 31, 1996 and 1995, respectively. Provisions for decommissioning of $36.2 million, $28.5 million and $24.5 million applicable to 1996, 1995 and 1994, respectively, are included in Depreciation and Amortization Expense. The net unrealized gains of $80.5 million and $40.7 million associated with securities held by the Company's Nuclear Decommissioning trusts at December 31, 1996 and 1995, respectively, are included in the accumulated provision for decommissioning.
Earnings of the trust funds were $16.0 million, $15.9 million and $15.2 million for 1996, 1995 and 1994, respectively, and are included in Other Income in the Company's Consolidated Statements of Income. The accretion of the accumulated provision for decommissioning, equal to the e;rrmngs of the trust funds, is also recorded in Other Income.
The Financial Accounting Standards Board (FASB) is reviewing the accounting for nuclear plant decommissioning. If current electric utility industry practices for such decommissioning are changed, annual provisions for decommissioning could increase. The FASB has tentatively determined that the estimated cost of decommissioning should be reported as a liability rather than as accumulated depreciation and that a substantial portion of the decommissioning obligation should be recognized earlier in the operating life of the nuclear plant.
During its deliberations, the FASB expanded the scope of this project to include similar unavoidable obligations to perform closure and post-closure activities incurred as a condition to operate assets other than nuclear power plants. Whether this position, if adopted, would impact other assets of the Company cannot be determined at this time. Furthermore, the FASB has tentatively determined that it would be inappropriate to account for cost of removal as negative salvage; thus, any forthcoming standard may also cause changes in industry plant depreciation practices.
37
e Insurance The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $8.9 billion for a single nuclear incident. The Price-Anderson Amendments Act of 1988 allows for an inflationary provision adj\\IStment every five years. The Company has purchased $200 million of coverage from the commercial insurance pools with the rem'ainder pro-vided 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 $81.7 million (including a 3% insurance premium tax for Virginia) for each of its four licensed reactors not to exceed $10.3 million (including a 3% insurance premium tax for Virginia) per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.
Nuclear liability coverage for claims made by nuclear workers first hired on or after January 1, 1988, except those arising out of an extraordinary nuclear occurrence, is provided under the Master Worker insurance program. (Those first hired into the nuclear industry prior to January 1, 1988, are covered by the policy discussed above.) The aggregate limit of cover-age for the industry is $400 million ($200 million policy limit with automatic reinstatements of an additional $200 million).
The Company's maximum retrospective assessment is approximately $12.5 million (including a 3% insurance premium tax for Virginia).
The Company's current level of property insurance coverage ($2.55 billion for North Anna and $2.40 billion: for Surry) exceeds the NRC' s minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain ii 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 Mutual Limited (NML)
- and Nuclear Electric Insurance Limited (NEIL), two mutual insurance companies, and is subject to retrospective premium assessments, in any policy year in which losses exceed the funds available to these insur-ance companies. The maximum assessment for the current policy period is $44.8 million. Based on the severity of the inci-dent, the Boards of Directors of the Company's nuclear insurers have the discretion to lower the maximum retrospective premium assessment or eliminate either or both completely. For any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination, the Company has the finan-cial responsibility for these losses.
The Company purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Virginia Power is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period's maxi-mum assessment is $9 million.
As part owner of the North Anna Power Station, ODEC is responsible for its proportionate share (11.6 percent) of the insurance premiums applicable to that station, including any retrospective premium assessments and any losses not _covered by insurance.
D. Sale of Receivables:
The Company had an agreement to sell, with limited recourse, certain accounts receivable including unbilled amounts, up to a maximum of $200 million. The agreement was allowed to expire on October 1, 1996. At December 31, 1995, no amounts were outstanding under this agreement.
E. Utility Plant:
Utility plant consisted of the following:
At December 31, 1996 1995 (Millions)
Production........................... _...................................................................................................................
$ 7,691.9
$ 7,340.0 Transmission..........................................................................................................................................
1,386.5 1,316.1 Distribution............................................................................................................................................
4,385.4 4,215.7 Other.............................. *.......................................................................................................................
862.9 817.7 14,326.7
. 13,689.5 Construction work in progress..............................................................................................................
180.1 512.1 Total...........................................................................................................................................
$14,506.8
$14,201.6 38
F. Jointly Owned Plants:
'IpeJoJlowi~g information relates to the Company's proportionate share of jointly owned plants at December 31, *1996:
North Bath County Anna Clover Pumped Storage Power Power Station Station Station Ownership interest.....................................................................
60.0%
88.4%
50.0%
(Millions)
Utility plant in service................................................. :............
$1,075.4
$1,819.5
$530.1 Accumulated depreciation.........................................................
208.8 716.9 13.2 Nuclear fuel...............................................................................
449.4 Accumulated amortization of nuclear fuel...............................
380.7 Construction work in progress..................................................
.1 49.1 3.6 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, maintenance, depreciation, taxes, etc.) in the Consolidated Statements of Income.
G. Regulatory Assets:
Certain expenses normally reflected in income are deferred on the balance sheet as regulatory assets and are recognized in income as the related amounts are included in rates and recovered from customers. The Company's regulatory assets included the following:
Income taxes recoverable through future rates..............................................................................................
Cost of decommissioning DOE uranium enrichment facilities.....................................................................
Deferred losses (gains) on reacquired debt, net....................,........................................................................
North Anna Unit 3 project termination costs................................................................................................
Other................................................................................................................................................................
At December 31.,
1996 1995 (Millions)
$477.0
$484.5 73.5 78.5 91.5 99.3 73.1 101.8 58.8 52.3 Total.....................................................................................................................................................
$773.9
$816;4 Income taxes recoverable through future rates represent principally the tax effect of depreciation differences not normal-ized in earlier years for ratemaking purposes. These amounts are amortized as the related temporary differences reverse...
The costs of decommissioning the Department of Energy's (DOE) uranium enrichment facilities have been deferred and represent the unamortized portion of Virginia Power's required contributions to a fund for decommissioning and decontami-nating the DOE's uranium enrichment facilities. Virginia Power is making such contributions over a fifteen-year period with escalation for inflation. These costs are being recovered in fuel rates.
Losses or gains on reacquired debt are deferred and amortized over the lives of the new issues of long-term debt. Gain.s or losses resulting from the redemption of debt without refinancing are amortized over the remaining lives of the redeemed issues.
The construction of North Anna Unit 3 was terminated in November 1982. All retail jurisdictions have permitted recov-ery of the incurred costs. For Virginia and FERC jurisdictional customers, the amounts deferred are being amortized from the date termination costs were first includible in rates.
The incurred costs underlying these regulatory assets may represent expenditures by the Company or may represent the recognition of liabilities that ultimately will be settled at some time in the future. For some of those regulatory assets repre-senting past expenditures that are not included in the Company's rate base or used to adjust the Company's capital structure, the Company is not allowed to earn a return on the unrecovered balance. Of the $773.9* million of regulatory assets at December 31, 1996, approximately $117 million represent past expenditures that are effectively excluded from rate base by the Virginia State Corporation Commission which has primary jurisdiction over the Company's rates. However, of that amount $73.1 million represent the present value of amounts to be recovered through future rates for North Anna Unit 3 project termination costs, and thus reflect a reduction in the actual dollars to be recovered through future rates for the time 39
e value of money. The Company does not earn a return on the remaining $43.9 million of regulatory assets, effectively excluded from rate base, to be recovered over various recovery periods up to 23 years, depending on the nature of the deferred costs.
In addition, the Company's depreciation practices for early retirements of plant and equipment and cost of removal, along with changing operating plant scenarios, have resulted in an accumulated depreciation reserve deficiency estimated to be $245 million at December 31, 1996. Currently, the Company is allowed to amortize reserve deficiencies over estimated remaining functional plant lives in all of the regulatory jurisdictions it serves.
H. Leases:
Plant and property under capital leases included the following:
Office buildings (*)........................................................,....,........................ ;,..
. Data processing equipment........................................................,...... -,..... '......
Total plant and property under capital leases... ;............................ :..
Less accumulated amortization.....................................................................
Net plant and property under capital leases.................................................
1996
$34.4 2.5 36.9 13.3
$23.6 At December 31, (Millions) 1995 *
$34.4 2.8 37.2 11.8
$25.4
(*) The Company leases its principal office building from its parent, Dominion Resources. The capitalized cost of the property under that lease, net of accumulated amortization, represented $23 million and $24 million at December 31, 1996 and 1995, respectively. Rental payments for such lease were $3 million for each of the three years ended December 31, 1996, 1995 and 1994.
The Company is responsible for expenses in connection with the leases noted above, including maintenance.
Future minimum lease payments under noncancellable capital leases and for operating leases that have initial or remain-ing lease terms in excess of one year as of December 31, 1996, are as follows:
- 1997................................................................................................................
1998................................................................................................................
1999................................... *................... *......-.. *...............-*.......... *<:.*..... ---.--.*.*.*
2000................................................................................................................
2001........................ *............................................................ *.... *................ -...'. *.
After 2001......................................................................... :............................
Total future minimum lease payments... ::......................... :.......... :::.............
Less interest element included above.......................................'.:..................
Pres,ent value of future minimum lease payments****************:**********************
Capital Leases
$ 3.6 3.3 3.0 3.0 3.0 19.7 35.6 12.0
$23.6 (Millions)
Operating Leases
$12.5 7.8 5.8 3.6 3.4 25.4
$58.5 Rents on leases, which have been charged to other operation expenses, were $12.8..;,11i11ion, $9.8 million and $9.6 million for 1996,.1995 and 1994, respectively.
_40
e I. Long-term Debt:
~011~-teqn d~bt included the following:
First and Refunding Mortgage Bonds (1):
Series U, 5.125%, due 1997.............................................................................................
1992 Series B, 7.25%, due 1997......................................................................................
1988 Series A, 9.375%, due 1998....................................................................................
1992 Series F, 6.25%, due 1998......................................................................................
1989 Series B, 8.875%, due 1999..............................................................,.....................
1993 Series C, 5.875%, due 2000....................................................................................
Various* series, 6.0-8%, due 2001-2004............................................................................
1992 Series D, 7.625%, due 2007................................................. ~..................................
Various series, 5.45-8.75%, due 2021-2025.....................................................................
Total First and Refunding Mortgage Bonds..............................................................
Other long-term debt:
Bank loans, notes and term loans:
Fixed interest rate, 6.15%-10.00%, due 1996-2003.....................................................
Pollution control financings (2):
Money Market Municipals, due 2007-2027(3).............................................................
Total other _long-term Debt.......................................................................................
Less amounts due within one year:
First and Refunding Mortgage Bonds..............................................................................
Bank loans, notes and term loans.....................................................................................
Total amount due within one year................................ ;...........................................
Less unamortized discount, net of premium..............................................................'..........
Total long-term debt................................................................,.................................
At December 31, 1996 1995 49.3
- 250.0 150.0 75.0 100.0 135.Q 805.0 215.0 1,144.5 2,923.8 503.1 488.6 991.7 3915.5 299.3 12.0 311.3 24.8
$3,579.4 (Millions) 49.3 250.0 150.0 75.0 100.0 135.0 805.0 215.0 1,144.5 2,923.8 762.7 488.6 1,251.3 4,175.1 259.6 259.6 26.1
$3,889.4 (1) Substantially all of the Company's property is subject to the lien of its mortgage, securing its First and Refunding Mortgage Bonds.
(2) Certain pollution control facilities at the Company's generating facilities have been pledged or conveyed to secure the financings.
(3) Interest rates vary based on short-term, ~-exempt market rates. The weighted average daily interest rates were 3.57% and. 3.89% for 1996 and 1995, respectively. Pollution control bonds subject to remarketing within one year are classi-fied as long-term debt to the extent that the Company's intention to maintain the debt is supported by long-term bank commitments.
Maturities through 2001 are as follows (millions): 1997 -
$311.3; 1998 -
$333.5; 1999 -
$261; 2000 -
$195.5; and 2001 -
$160.7.
In January 1997, the Company filed a registration statement with the Securities and Exchange Commission for
$400 million of Junior Subordinated Debentures. In February 1997, the Company issued $200 million of First and Refunding Mortgage Bonds, the proceeds of which were primarily used to refund a portion of the Company's debt that matured in February and March of 1997.
J. Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust:
In 1995, the Company established Virginia Power Capital Trust I (VP Capital Trust). VP Capital Trust sold 5,400,000 shares of Preferred Securities for $135 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by VP Capital Trust.
41
e The Company issued $139.2 million of its 1995 Series A, 8.05% Junior Subordinated Notes (the Notes) in exchange for the $135 million realized from the sale of the Preferred Securities and $4.2 million of common securities of VP Capital Trust.
The common securities represent the remaining 3% beneficial ownership interest in the assets held by VP,Capital Trust. The Notes constitute 100% of VP Capital Trust's assets.
The Notes are due September 30, 2025, but may be extended up to an additional ten years, subject to satisfying certain conditions. However, the Company may redeem the Notes on or after September 30, 2000, under certain circumstances. The Preferred Securities are subject to mandatory redemption upon repayment of the Notes at maturity or earlier redemption. At redemption, each Preferred Security shall be entitled to receive a.liquidation amount of $25 plus accrued and unpaid distribu-tions, including any interest thereon.
K. Preferred Stock Subject to Mandatory Redemption:
Preferred stock subject to mandatory redemption, $100 liquidation preference; at December 31,. 1996, was as follows:
Dividend.
$5.58.....,..... '................,.........,..
6.35.......................................
Total...........................
(a) Shares are non-callable prior to redemption.
(b) All shares to be redeemed on 3/1/2000.
(c) All shares to be redteemed on 9/1/2000,.
During the years 1994 through 1996, the following shares were redeemed:
Issued and Outstanding.
' Shares 400,000(a)(b) 1,400,000(a)(c) 1,800,000 Year Dividend Shares 417,319 37,681 l995.................... *.*.... *.*......... *............ *....... *..
1994...................... :......................... ::.. :..... :::..
"$7.30 7.30 The total nuniber of authorized shares for all preferred stock is 10,000,000 shares. Upon involuntary liquidation, all presently outstanding preferred stock is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.
L. Preferred Stock Not Subject to Mandatory Redemption:
Preferred stock not subject to mandatory redemption,; $100
- liquidation preference, at December 31, 1996, was as follows:
Dividend Issued and Outstanding
.. :S!iares
$5.00................ *.* :.......... *........ *.. :.. :.. *;'.... *-.. *.. :.......... *... *.. **. *......
- .*.* 106,677 4.04............................,.... _'*.. *......... *... :......... ;........... :...... * *...........
'12,926
- 4.20...............................................................................................
14,797 4.12...............................................................................................
.32,534
.. 4.80................. :.... *.:........... '........ :.. *... *.................. *... *.... *.. *. *........... *..
73,206 7.05...............................................................................................
500,000 6.98................... **.... *..... :.............. *.:.**... *........,*....... *.... :........... *.
600,000
- MMP 1/87 (*).. :............ :...........,*.. :.;:... ;..... ;:..... :,*.,.,:.... :.. ;,.:'... :.:.. ::..* :.
1500;000 MMP 6/87 (*)....... *................................,........... :.,..... :... J::,.... ;:......
- . *' 750,000 MMP 10/88 (*)..............................................................................
750,000 MMP 6/89 (*)................................................................................
750,000 MMP 9/92A (*)................................. ;..* ;::.:;:.. ;...... "****'*:*:.:............ -.: **
500,000 MMP 9/92:B (*).....................,:*******,******.. *:**;*****:***:******:**,:,******.. :*.-:.
.. 500,000 Total.....*.................,........... :... :...,..........,;:............,.:... :... :.:............. **,. 5,090,140 42 Entitled per Share upon Liquidation And Thereafter to Amounts Declining in Amount. Through Steps to
$112.50 102.27 102.50 103.73 101.00 105.00 105.00
- *100.00 100.00 100.00 100.00 100.00
- 100.00 7/31/03 8/31/03
$100.00 after 7/31/13
$100.00 after 8/31/13
(*) Money Market Preferred (MMP) dividend rates are variable and are set every 49 days via an auction process. The combifled weighte.d average rates for these series in 1996, 1995 and 1994, including fees for broker/dealer agreements, were 4.48%, 4.93% and 3.75%, respectively.
During the years 1994 through 1996, the following shares were redeemed:
Year 1995 1995 M. Common Stock:
Dividend
$7.45 7.20 During the years 1994 through 1996, the following changes in Common Stock occurre.d:
- vears Balance at January 1...............
Issuance to Dominion Resources.............................
Balance at December 31.........
N. Short-term Debt:
Shares Outstanding 171,484 171,484 1996 Amount
$2,737.4
$2,737.4 Shares Outstanding 1995 Amount (Millions, Except Shares)
. 171,484
$2,737.4 171,484
$2,737.4 Shares 400,000 450,000 Shares 1994 Outstanding 168,277 3,207 171,484 Amount
$2,662.4 75.0
$2,737.4 The Company has. an established commercial paper program with a maximum borrowing capacity of $500 million which is supported by two credit facilities. One is a $300 million, five-year credit facility that was effective on June 7, 1996 and expires on June 7, 2001. The other is a $200 million credit facility, also effective June. 7, 1996, with an initial term of 364
- days and provisions for subsequent 364-day extensions. The total amount of commercial paper outstanding was $312.4 mil-lion and $169.0 million at December 31, 19% and 1995, respectively.
The weighted-average interest rate for commercial 'paper was 5.51 % and 5.79% on December 31, 1996 and 1995, respectively.
- 0. Retirement Plan, Postretirement Benefits and Other Benefits:
Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
Retirement Plan The Company participates in the Dominion Resources, Inc. RetirementPlan (the Retirement Plan), a defined benefit pension plan. The Retirement Plan covers virtually all employees of Dominion Resources and its subsidiaries, including the Company. The benefits are b.ased on years of service and average base compensation over the consecutive 60-month period in which pay is highest.
. Pension plan expenses were $24.8 million, $20.3 million and $19.3 million for 1996, 1995 and 1994, respectively and the amounts funded were $28.4 Illlllion, $42:7 million and $42:7 million in 1996, 1995 and 1994, respectively.
43
Postretirement Benefits Net periodic postretirement benefit expense was as follows:
Service cost...................................................................................................
Interest cost...................................................................................................
Return on plan assets....................................................................................
Amortization of transition obligation...........................................................
Net amortization and deferral.........................................,.............................
Net periodic postretirement benefit expense................................................
The following table sets forth the funded status of the plan:
Fair value of plan assets..............................-.................................................
Accumulated postretirement benefit obligation:
Retirees......................................................................................................
Active plan participants*******************;*:................................,.....................
Accumulated postretirement benefit obligation...................................
Accumulated postretirement benefit obligation in excess of plan assets..................................................................................................
Umecognized transition obligation...............................................................
Umecognized net experience (gain)/loss........... :..................................... :...
- Accrued postretirement benefit cost..................... ;.......................................
Year Ended December 31, 1996 1995 (Millions)
$ 12.1
$ 8.7 23.9 21.7 (16.6)
(6.2) 12.1 12.1 7.1 0.1
$ 38.6
$36.4 At December 31, 1996 1995 (Millions)
$ 133.0
$ 96.3
$ 201.7
$ 210.7 122.2 96.5 323.9 307.2 (190.9)
(210.9) 192.8 204.9 (3.6) 7.9
$ (1.7) 1.9 A one percent increase in the health care cost trend rate would result in an increase of $31.8 million in the service arid interest cost components and a $268.0 million increase in the accumulated postretirement benefit obligation.
- Significant assumptions used in determining the postretirement benefit obligation were:
Discount rates......................................................................................
Assumed return on plan assets...........................................................
Medical cost trend rate................................. :............................... :.....
8%
9%
1996 7% for 1st year 6% for 2nd year Scaling down to 4.75% beginning in the year 2000 8%
9%
1995 8%for 1st year 7% for 2nd year Scaling down to 4.75% beginning in the year 2000 The Company is recovering these costs in rates on an accrual basis in all material respects, in all jurisdictions. The funds being collected for Other Postretirement Benefits (OPEB) accruals in rates, in excess of OPEB benefits actually paid during the year, are contributed to external benefit trusts under the Company's current funding policy (see Comp~tition under MAN-AGEMENT'S mscussmN AND.ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS).
Other Benefits In 1994, the Company offered an early retirement program to employees aged 50 or older and offered a voluntary separation program to all regular full-time employees. Approximately 1,400 employees accepted offers under these programs.
The costs associated with these programs were $90.1 million. The Company capitalized $25.9 million based upon regulatory precedent and expensed $64.2 million.
P. Restructuring:
In March 1995, the Company announced the implementation phase of its Vision 2000 program. During this phase, the Company began reviewing operations with the objective of outsourcing services where economical and appropriate and re-44
engineering the remaining functions to streamline operations. The re-engineering process is resulting in outsourcing, decen-tralization, reorganization and downsizing for portions of the Company's operations. As part of this process, the Company is reevaluating ifs utilization of capital resources in the operations of the Company to identify further opportunities for opera-tional efficiencies through outsourcing or re-engineering of its processes.
Restructuring charges of $91.6 million and $117.9 million in 1996 and 1995, respectively, included severance costs, purchased power contract restructuring and negotiated settlement costs, capital project cancellation costs, and other costs incurred directly as a result of the Vision 2000 initiatives. While the Company may incur additional charges for severance in 1997, the amounts are not expected to be significant.
In 1995, the Company established a* comprehensive involuntary severance package for salaried employees who may no longer be employed as a result of these initiatives. The Company is recognizing the cost associated with employee termina-tions in accordance with Emerging Issues Task Force Consensus No. 94-3 as management identifies the positions to be
, eliminated. Severance payments will be made over. a period not to exceed twenty months. Through December 31, 1996, management had identified 1,811 positions to be eliminated. Those positions were identified as a result of the Company's review of the Fossil and Hydroelectric, Nuclear. and Commercial Operations Business Units and portions of the corporate center operations. The recognition of severance costs resulted in charges to operations in 1996 and 1995 of $49.2 million and
$51.2 million, respectively. At December 31, 1996, 1,266 employees had been terminated and severance payments totaling
$45 million had been paid. The Company estimates that these staffing reductions will result in annual savings, net of out-sourcing costs, in the range of $62 million to $90 million. However, such savings may be offset in part by future salary increases, possible outsourcing costs and increased payroll costs associated with staffing for growth opportunities such as those in the Energy Services Business Unit. The savings from staffing reductions will be reflected in lower construction expenditures as well as lower operation and maintenance expenses.
Iri. an effort to minimize its exposure to potential stranded investment, the Company is evaluating its long-term pur-chased power contracts and negotiating modifications.to their terms, including cancellations, where it is determined to be economically advantageous to do so. The Company has also negotiated settlements with several other parties to terminate their rights to sell power to the Company. The cost of contract *modifications, contract cancellations and negotiated settle-ments was $7.8 million and $8.1 million in 1996 and 1995, respectively. Using contract terms, estimated quantities of power that would have otherwise been delivered and other _relevant factors at the time of each transaction, the Company estimated that its annual future purchased power costs, in~luding energy payments, would be reduced by up to $5.8 million and
$147.0 million for the 1996 transaction~ and 1995 transactions, respectively. The cost of alternative sources of power that might ultimately be required as a result of these settlements is expected to be significantly less than the estimated reduction in purchased power costs.
Restructuring ch_arges reported in 1995 included $37.3 million for the cancellation of a project to construct a facility to handle low level radioactive waste at the Company's North Anna Power Station. As a result of reevaluating the handling of low level radioactive waste, the Company concluded that the facility should not be completed due to the additional capital investment required, decreased Company volumes of low level radioactive waste resulting from improvements in station procedures and the availability of more economical offsite processing.
The incurrence of restructuring charges and the savings resulting therefrom in subsequent periods are elements of the Company's cost of operations and will be *considered in the cost of service information filed by the Company in response to the Virginia Commission's Order issued on November 12, 1996. See Regulation -
Virginia Commission under Item 1. BUS-INESS for additional information on current rate proceedings.
In this increasingly competitive environment, the Company has also concluded that it is appropriate to utilize available savings and cost reductions, such as those generated by the Vision 2000 program, to accelerate the write-off of existing unamortized regulatory assets. Not only will this strategically position the Company in anticipation of competition, but it also reflects the Company's commitment to mitigate its exposure to potentially stranded costs (see Competition in MANAGE-MENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS). As of December 31, 1996, the Company had identified savings of $26.7 million which were used to establish a reserve for expected adjustments to regulatory assets.
As part of re-engineering operations, the Company has adopted a plan to improve cust~mer service which will require an investment in excess of $100 million over the next several years. That plan includes the installation of automated electric meters in metropolitan and inaccessible rural and urban locations. The plan also provides for the installation of mobile data dispatch technology in the Company's service fleet, accompanied by digitized mapping of the Company's service territory.
Furthermore, technological changes are being made to enhance the Company's ability to handle customer calls during power 45
e outages. In order to increase service reliability, the Company has initiated both local and regional distribution line improve-ment projects.
Q. Commitments and Contingencies:
The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or the financial position of the Company.
Federal Energy Regulatory Commission Audit The FERC has conducted a compliance audit of the Company's financial statements for the years 1990 through 1994.
The Company has received a preliminary audit report in which certain compliance exceptions were noted. The Company has
_supplied information to the FERC staff relating to these preliminary exceptions. Based on information available at this time,
- the disposition of these issues is not expected to have a significant effect on the Company's financial position or results of
-operations.
Retrospective Premium Assessments Under several of the Company's nuclear insurance policies, the Company is subject to retrospective premium assess-
- ments in any policy year in which losses exceed the funds available to these insurance companies. For additional information, see Note C to CONSOLIDATED FINANCIAL STATEMENTS.
Construction Program The Company has made substantial commitments in connection with its construction program and nuclear fuel expendi-tures. Those expenditures are estimated to total $529.2 million (excluding AFC) for 1997. The Company presently estimates
_that all of its 1997 construction expenditures, including nuclear fuel, will be met through cash flow from operations.
Purchased Power Contracts Since 1984, 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 65 non-utility purchase contracts with a combined dependable summer capacity of 3,524 Mw. Of these, 62 projects (aggregating 3,509 Mw) were operational as of the end of 1996 with the remaining three projects to become operational before 1999.
The table below reflects the Company's minimum commitments as of December 31, 1996, for power purchases from
_utility and non-utility suppliers.
Commitment Year Capacity Other (Millions) 1997............. :.................................................
790.7
$ 211.2 1998...............................................................
793.5 216.8 1999...............................................................
796.6 220.3 2000...............................................................
709.2 157.9 2001...............................................................
712.1 161.5 Later years.....................................................
10,098.0 788.0 Total...........................................................
$13,900.1
$1,755.7 Present value of the total..............................
$ 6,147.2
$ 986.7 Payments made by Virginia Power in satisfaction of the minimum purchase commitments shown in the above table are subject to reduction or partial refund if (1) the non-utility suppliers fail to meet performance requirements or (2) changes in federal or state law or administrative actions disallow or have the effect of disallowing Virginia Power's recovery of such costs from its customers. The amount of such payment reductions or refunds, if any, will be determined and administered as provided in individual supply contracts, although (1) the deferral of refund obligations, (2) disputes over the applicability of such payment reductions or refund obligations and (3) the ability of some non-utility suppliers to make refunds could limit Virginia Power's ability to benefit from these contract provisions.
In addition to the minimum purchase commitments in the table above, under some of these contracts, the Company may purchase, at its option, additional power as needed. Actual payments for purchased power (including economy, emergency, 46
limited term, short-term and-long-term purchases) for the years 1996, 1995 and 1994 were $1,183 million, $1,093 million and
$1,025 million, respectively. For a discussion of the Company's efforts to restructure certain purchased power contracts, see b[ote P tG CONSOLIDATED FINANCIAL STATEMENTS.
J J
Fuel Purchase Commitments The Company'.s estimated fuel purchase commitments for the next five years for system generation are as follows (millions): 1997 -$326; 1998 -$274; 1999 -$194; 2000-$157; and* 2001 -$110.
Sale of Power The Company has a diversity exchange agreement with AP under which AP delivers 200 Mw to Virginia Power in the summer and Virginia Power delivers 200 Mw to AP in the winter.
- In addition, the Company has entered into agreements to supply wholesale power unde~ various terms on a firm basis
'during certain upcoming winter and summer months. Under these agreements, the Company has_ the following commitments:
1 Years 1997 1998 (Mw of Capacity)
Winter.................................................................. ;................... *..............................................
.200 110 Summer....................................................................................................................................
510 200 Environmental Matters
- The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to. protect human health and the environment. These laws and regulations affect future planning and existing operations, These laws and regulations can result in increased capital, operating and other costs-as a result of compli-ance, remediation, containment and monitoring obligations of the Company. These costs have been historically recovered through the ratemaking process; however, should material costs be incurred and not recovered through rates, the Company's results of operations and financial condition could be adversely illlpacted.
Site Remediation The EPA has identified the Company and several other entities as Potentiallr Responsible Parties (PRPs) at two.
Superfund sites located in Kentucky and Pennsylvania. The estimated future remediation costs for the sites are in the range of
$61.5 million to $72.5 million. The Company's proportionate share of the cost ~s expected to be in the range.of $1.7 million to $2.5 million, based upon allocation :formulas and the volume of waste shipped to the sites. As of December 31, 1996, the Company had accrued a reserve of $1.7 million to meet its obligations at these two sites. Based on a financial assessment of.
the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay the costs apportioned to them.
. The Company and Dominion Resources along with Consolidated Natural Gas have remedial action responsibilities remaining at two coal tar sites. The Company accrued a $2 million reserve to meet its estimated liability based on site studies and investigations performed at these sites. In addition, two civil actions have been instituted against the City of Norfolk and Virginia Power by property owners who allege that their property has been contaminated by toxic pollutants originating from one of the coal tar sites now owned by the City of Norfolk _llild formerly owned by the Company. The plaintiffs are seeking compensatory damages of $12 millicin and punitive damages of $6 million. It.is too early in the cases for the Company t_o predict their outcome. The Company has filed answers denying liability. A trial date of Augtist 18, 1997 has been set for orie of the two actions seeking fifteen million dollars.
The Company generally seeks to recover its costs associated with environmental remediation from third party insurers.
At December 31, 1996, any pending or possible claims were not recognized as an asset or offset against recorded obligations of the Company.
R. Fair Value of Financial Instruments:
The Company used available market information and appropriate valuation-methodologies to estimate the fair valu~ of each class of financial instrument for which it is practicable to estimate fair value. These estimates are not necessarily indica-tive of the amounts the Company could realize in a market exchange. In.addition, the U$e of different market assumptions may have a material_ effect on the estimated fair -value amounts.
47
e December 31, 1996 1995 Carrying Fair Carrying Fair Amount Value Amount Value (Millions)
Assets:
Cash and cash equivalents....................................................
47.9 47.9 29.8 29.8 Nuclear decommissioning trust funds.......................... :.......
443.3 443.3 351.4 351.4 Pollution control project funds.............................................
9.7 9.7 11.9 11.9 Liabilities and capitalization:
Short-term debt...........................................,..........................
312.4 312.4 169.0 169.0
- Long-term debt:
First and Refunding Mortgage Bonds..............................
2,923.8 2,957.4 2,923.8 3,106.3 Medium-term notes......................................,....................
503.1 531.3 762.7 810.1
- Money Market Municipal pollution control notes...........
488.6 488.6 488.6 488.6 Preferred stock subject to mandatory redemption...............
180.0 185.8 180.0 190.9
- Preferred securities of subsidiary trust.................................
135.0 135.0 135.0 140.4 Cash and cash equivalents, pollution control project funds and short-term debt: The carrying amount of these items approximates fair value because of their short maturity.
Nuclear decommissioning trust funds: The fair value is based on available market information and generally is the average of bid and asked price.
First and Refunding Mortgage Bonds and pollution control bonds: Fair value is based on market quotations.
Medium-term notes: These notes were valued by discounting the remaining cash flows at a rate estimated for each issue.
A yield curve rate was estimated to relate Treasury Bond rates for specific issues to the corresponding maturities.
Money Market Municipal pollution control notes: These notes have variable interest rates which are set so that fair value approximates carrying value.
Preferred stock subject to mandatory redemption: The fair value is based on market quotations or is estimated by dis-counting the dividend and principal payments for a representative issue of each series over the average remaining life of the series.
Preferred securities of subsidiary trust: Fair value is based on market quotations.
S. Quarterly Financial Data (unaudited):
The following amounts reflect all adjustments, consisting of only normal recurring accruals (except as discussed below),
necessary in the opinion of the management for a fair statement of the results for the interim periods.
Balance Available Operating Operating Net for Common Quarter Revenues Income Income Stock (Millions) 1996 1st.................................
$1,164.8
$231.3
$152.8
$143.8 2nd................................
1,029.1 173.1 96.6 87.8 3rd................................
1,177.1 239.0 162.2 153.3 4th................................
1,011.6 121.7 45.7 36.9 1995 1st.................................
$1,076.3
$191.8
$115.0
$103.3 2nd................................
971.1 156.7 78.0 66.3 3rd................................
1,276.6 279.1 201.8 190.3 4th................................
1,026.4 118.9 38.0 28.8 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.
As part of the Vision 2000 program (see Note P to CONSOLIDATED FINANCIAL STATEMENTS) the Company recorded $91.6 million and $117.9 million of restructuring charges in 1996 and 1995, respectively. Restructuring charges 48
e included severance costs, purchased power contract restructuring and negotiated settlement costs, capital project cancellation costs, and other costs incurred directly as' a result of the Vision 2000 initiatives. The Company expensed $5.4 million,
$.19.3 miHion, *$4.6 million and $62.3. million of these costs during the first, second, third and fourth quarters of 1996, and
$3.5 million, $1.8 million, $30.6 million and $82.0 million during the first, second, third and fourth quarters of 1995. The impact of the write-off reduced Balance Available for Common Stock by $3.5 million, $12.5 million, $3.0 million and $40.6 million for the first, second, third, and fourth quarters of 1996, respectively, and by $2.3 million, $1.1 million, $19.9 million and $53.3 million for the first, second, third, and fourth quarters of 1995, respectively.
T. Subsequent Event (unaudited):
On November 12, 1996, the Virginia Commission instituted a proceeding and directed the Company to provide certain information, including any alternative form of regulation proposed by the Company at this time, by March 31, 1997. On March 7, 1997, in this proceeding and in a separate Annual Information Filing proceeding, the Virginia Commission entered
- an order providing that the Company's rates shaU become interim rates subject to refund as of March 1, 1997. For additional information, see Regulation under Item 1. BUSINESS.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
49
PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (a) Information concerning directors of Virginia Electric and Power Company is as follows:
Name and Age John B. Adams, Jr. (52)
James T. Rhodes (55)
James F. Betts (64)
Jean E. Clary (53)
Benjamin J. Lambert, III (60)
Richard L. Leatherwood (57)
Harvey L. Lindsay, Jr. (67)
William T. Roos (69)
Robert H. Spilman (69)
William G. Thomas (57)
Principal Occupation for Last 5 Years, Directorships in Public Corporations President and Chief Executive Officer of The Bowman Companies, Fredericksburg, Virginia, a manufacturer and bottler of alcohol beverages and Chairman of the Board of Directors and a Director of Virginia Electric and Power Company. He is a Director of Dominion Resources..
President and Chief Executive Officer of Virginia Electric and Power Company. He js a Director of NationsBank, N.A.
Former Chairman of the Board and President, The_Life Insurance Company of Virginia, Richmond, Virginia. He is a Director of Central Fidelity Bank, Inc.
President and owner of Century 21 Clary and Associates, Inc., South Hill, Virginia Optometrist, Richmond, Virginia. He is a Director of Consolidated Bank and Trust Company, Student Loan Marketing Association (SallieMae) and Dominion Resources.
Retired, Baltimore, Maryland (prior to December 1, 1991, President and Chief Executive Officer, CSX Equipment, an operating unit of CSX Transportation, Inc.). He is a Director of Dominion Resources.
Chairman and Chief Executive Officer of Harvey Lindsay Commercial Real Estate, Norfolk, Virginia, a commercial real estate firm. He is a Director of Dominion Resources.
Retired, Hampton, Virginia (prior to December 31, 1993, President of Penn Luggage, Inc., retail specialty stores).
He is a Director of Dominion Resources.
Chairman, Chief Executive Officer and a Director of Bassett Furniture Industries, Inc., Bassett, Virginia. He is
- Chairman of the Board and a Director of Jefferson-Pilot Corp., Greensboro, North Carolina. He is a Director of NationsBank Corporation, TRINOVA Corporation, The Pittston Company and Dominion Resources.
President of Hazel & Thomas, Alexandria, Virginia, a law firm.
Year First Elected a Director 1987 1989 1978 1996 1992 1994 1986 1975 1994 1987 The Directors are divided into three classes, with staggered terms. Each class consists, as nearly as possible, of one-third of the total number of Directors. Each Director holds office until the annual meeting for the year in which his class term expires, or until his successor is duly qualified and elected as provided in the Company's Articles of Incorporation.
Mr. Thomas has entered into a Consent Decree with the Office of Thrift Supervision in connection with the lending and credit granting activities of Perpetual Savings Bank, FSB, which Mr. Thomas formerly served as a director. The Consent Decree requires that Mr. Thomas obtain approval from the appropriate federal banking agency before accepting certain posi-tions involving lending or credit activities with an insured depository institution.
50
e (b) Information concerning the executive officers of Virginia*Electric,and Power Company.is as follows:
Name. and Age James 'f. 'Rhodes-(55)
Robert E. Rigsby ( 47)
Business Experience past Five Years President and Chief Executive Officer.***
Executive Vice President, January 1, 1996 to date; SeniorVice,President-I<'inance.and.
Controller, January 1, 1995 to January 1, 1996; Vice President-Hilman Resource's prior toJanuary.. l, 1995:*
William R. Cartwright.(54) *,, -Senior Vice President-Fossil. and Hydro,July l, 1995 to date;.Vice President Fossil and Hydro prior to July 1, 1995.
- Lawrence E. De Simone (49)
Senior Vice President-Energy Services, July 15, 1996 to date; *vice president-strategic.
Larry M. Girvin (5}).
planning for Central & South West Corp;, a Dallas-based electric utility holding company, priorto July 15;*,1-996.\\*:*c *..
Senior. Vice President-Commercial Operations, January 1, 1996 to date; Vice President- -
-. Hilman Resources/January 1, 1995 to January 1, 1996; Vice President-Nuclear
.**Services; September 1, 1992 to January 1, 1995; Vice President-Central Division prior
...: - to September 1, 1992.
James P. O'Hanlon ~53).. * *
- Senior Vice*President-Nm;lear,'-Jurie -T;' i.994'to date; Vice President-Nuclear Operations,*-
January 1, 1992:to:June), 1994;Vice Pr.:esideqt-Nuclear Services pri,q(to Janµiµ-y l,.
- - 1991.' *.'
- Senior \\Tice Presiden(~Finance, Regµhti~n an{Qen~ral C~unsel, January l; J99i5' to i;late;.
Vice President-Regulation and Qener~l Coun~el,.January -1, 1995 to Januafy 1, 1996; *
- Vice.President-Regulation, February 1, 1994 fo January 1, 1995; Partner in the law firm*'qf Hunton & Williams; RaJeigh,'Nortli.. C~olina pdor to February 1~. 1994:., -*.
Vice President~Centra1 Division, S_eptember 1,. 1992 to date; Vice President-Procurement
. Edgar M. Roach~: J1:. (48).
Charles A. Brown (54) prior to September, 1, 1992; Thomas L. Caviness, Jr. (51);
Vice Presideiit-RetaiLEnergy Servic;es, July 1, 199f to date;Vice Presiderit-Eastetn.
J, Kennerly):)av,is, Jr. (51)
Division priodo July 1, 1995.. ;,, *:
Vice P,r~sident-Finance and Adminis,trative Seryices, Treasurer and Corporate Secretary, January 1, 1996 to-date; Vice }:>resident, Tre11surer an(Corporate Secretary, Oc,tober 1!
1994 :to January 1, 1996; Vice Pre.sident and: <;orporate Secrj;:tary.,of:Don)inio_p.:
Resources prior to October 1, 1994.
. Jam.es T. Earwpod; :1( (53)
- Vice Pre.sident-Bulk Power Delivery,,January 1, 1997 to date;Vice President-Energy Efficiency and Division Service~, January 1,: 1996,to January 1, 1997; Vice President~.*
Thomas A. Hyman, Jr. ( 45)
¥icha,eJ ;R. K,:ansl~.r ( 42)
Mark E M'cGettrick (39)
William S.
1 Mistr (49)...
Division Service~ prior to January. 1, 1996: :.
- Vice President-Eastern Division and North Carolina Power, July l, 1995 to date; Vice***":*
President-Southern Division, June 1, 1994 to July 1, 1995; Sta.tioh Mariager-Bremo Power Station, September 1, 1992 to June 1, 1994; Assistant Controller Financial..
, *._St:~i_ce~, pryor.to Septe.rnb¢r. l;. 1~92,
. Xie~, Pre~.ident,ijµc1ear 9peration.s,,~uary.-1, 1991; t9 d,!i~;Vice President~Nu_clear.. *,,.
- , Engin~ering and_ Service~, Octobc:r 1, 199.5_ to_ JaIJ.tlary. 1, 1.997; Yice President-1-fucle,ar, Services,'January 1, 1995*fo October 1, 1995,; Manager~Nu'clear Operations Support;
.,. *. September 1; 1994 tci January 1, 1995; Station-:Manager-Surry.Nuclear Power Station
- prior to September 1, 1994. *
. Vice President-Customer* Service, January.1, 1997 to date; Corporate Restruc~ring Project Manager, February 1,. 1995 to*January 1, 1997; Assistant Controller, September 1, 1992 tmFebruary,l;-1-995; Manager-Btidgetirig:andAdministration prior to, Septe_mber r, 1992...... '"
Vice President-Toforrriation T~ciinofogy, January L* 1996 to' date; Vice Preside~t and
.Treasurer; Dominion.Energy*, Inc:, October,-I,,1994 to Janu\\lfY-1; 1996;, Assistant Treasurer, Dorn).nion R,~so9-Tces/Oec,:embj;:r: 1-, 15192.to October 1, l994; Assistant*.
Treasurer prie>r to December 1, 1992.
- E Kenneth' Mooie-(55) '.
. *
- Vice 'President~Fcissihind *Hydro 'Services; July 1,* f995*to: date. Vice* President-'
Procurement, S~ptember 1, 1992 to July 1, 1995; Vice President-Nuclear Engineering*
Service,s priotJo.Septemb~r.),.J992...
Vice President:Hiunan Resources, Jainiary i; 1996 tci date;* Vice President-Energy.
. -'.Efficiency; September 1; *1992 to' January,1; 1996; Vice Presid~nFRegulation, prior to September.I, 1992.
. Vice President~N~c:lear E.rigineering an~ S~rv_ices, January 1, 1997 to date; Vice Presideht~NucleafOperations;June 1, 1994 to January i; 1997; Assistant Vice President-Nuclear Operations, prior to June 1, 1994.
.Tli~mas J.
- ffNeil: (54)
- Robert F. Saunders (53)
.., :~
I. "..
Vice Presid~Ilt-Nortllern.,anci Wt::stern Divisions, Jun~.* l, _1994: to date; Vice President-Western Division, prior to -lune 1, 1994.
. Vice Presid~nt-Public Aff~ks'.',,
Johnny V., Shena:I (51).
~ -* -.
Eva S. Teig (52) 5l
I I.
e e
There is no family relationship between any of the persons named in response to Item 10.
ITEM 11. EXECUTIVE COMPENSATION Summary Conipe'nsation Table. *
~
the Summary Table below includes compensation paid by the Company for services rendered in 1996, 1995 and 1994 for the. Chief Executive Officer* and the four other most highly compensated executive officers ( as of December. 31, 1996). as d~termined by total salary and incentive.payments for 1996:
Summary C~mpens~ti~n Table Long* Term Co1ppensation *
- Awards Payouts, *
.Annual Compensation Nam~ &'~rincipai Positio~
Year Salary
- . Incentiyes(l)'..
Other Annual Compensation(2)
J. '.f. Rho.des...
1996
$410,575
$247,506
$0 Presid~nt & CEO 1995 406,075*
273,poo 0
1994 356,000 193;830
'O*'**.
-~. :.
R.E. Rigsby
. 1996 226,469 143,892
- 0.
Executive Vice President 1995.
171,456 105;000 *_
()
1994
'135,825 50,800 0
J. i>. O'Hanlon 1996
'220,815.
128,511
'0.
Senior Vice President~.*. *
- 1995 207,555 *
. 13.6,400. '
0 Nuclear
. 1994 l'Z2,625 87,980.. *-
... :o, E. M: Roach, *1r.
- 1996 184,094.
. 99;820
- o Senior Vice-President_:.
1995 164,800 69,010 0
Finance, Regulation &. General *1994 142,<;)83.
50,052 0
~ounsel
- L. W. Ellis '
1996 191,754 87,077 0
Senior Vice President 1995 *. *.. i89,360 102,900
- o Power Operations and 1994 181,160 82,950 0
Planning*
(Retired December 31, 19_9.<?)
Restricted
- Stock Awards
$0'(3) 0 O*
0(5).
0 o*
0(8) 0
- 0.
0(10)
.0 o:*,,'
0(12) 0 0
Securities
. Underlying Options/
Sar Grants
$0 0
0 0
0 0
0 O*
0 0
0
- 0.
0 0
0
. LTIP Ali Othe/
Payout Compensation
$75,684( 4) 4,500(7).
77,970,',
4,500(7) 69,709.
4,500(7) 43,157(6)
- 4,500(7) 3,4,569 4,500 16;230 4,075
. 56,152(9) 4,500(7)'
. 45,109 4,500(7) 19,787 4,500
- 29,466(11).
4,500(7) 0 4,500 0
387
, 50,333(13) -. 128,523(14) 54,041.
4,500(7) 29,096
.
- 4,500(7)
(1) The Company does not maintain "bonus" plans which are used by some companies to supplement salaries based on
. the success of the company without regard to.individual perfqmiance. However, the Company has iri place varicius incetjtive plans tq.~t compepsate officers and erii.p}oyebs for achieving pre:'determined,specified' perfonhance goals. '
-*.. (2) No~e of the'* ~xecu,ti;~ officers ;ib~ve received perquisit~s-*6r othe~ ;erso~al be~efits in excess of either $50,000 or 10% of their total salary and bonus.
.. -. (3) The aggregate nuinb,e/ of shares of restricted stock at December 31, 1996. totaled: 7,326 with~ dggregat~ val~e ~f
$282,051 (based on* a closing. price on December 31, 1996 of $38.50*:per share).
. * (4) 1,863, shares ~f stock were awarded Fe}?ruary 21, 1997, at,the* enct'of a three-year performance period (1994-1996).
(5) The aggregate number of shares of restricted stock at December 31, 1996.totaled: 5,421 with an aggregate value of
$208,709*(1;,ased 011.' a closing pnce on December 31, 1996 of $38.50 per share).
~
(6) 549 shares. of stock and $20,854 in ~ash were awarded February *21,.1997, ~t the*end of a three-year performanc~
period (1994-1996).
(7) Employer matching contribution on Employee Savings Plan: contributions.
- . (8) The ~ggrega~ n~mber ~/shares of rt;stricted stock at Decembe~ 31, 1996 ~otaled: 3,507 with*~ aggregrate* valu~- of
$135,020 (based on a closing price on December 31, 1996 of $38.50 per share).
. (9) 714 shares of sto 0
c.:lc.and $27,146 in ~-ash were awarded February 21,' 1997, at the end of a three-y~ar perfonriance period (1994-1996).
(10) The aggregate number of shares of restricted stock at December 31, 1996 totaled: 2,868 with an aggregate value *of
$110,418 (based on a closing price on December 31; 1996 of $38,50 per ~hare).
52
e (11) $29,466 in cash was awarded February 21, 1997, at the end of a three-year performance period (1994-1996).
- (1 ?) pie ~ggregate number of shares of restricted stock at December 31, 1996 totaled: 2,868 with an aggregate value of
$110,418 (based on a closing price on December 31, 1996 of $38.50 per share).
(13) 640 shares of stock and $24,333 in cash were awarded February 21, 1997, at the end of a three-year performance period (1994-1996).
(14) Employer matching contribution on Employee Savings Plan contributions ($4,500), retirement payment as provided by Company's Early Retirement and Voluntary Separation Program ($97,266) and payment at retirement for accrued vacation
($26,757).
Long-term Incentive Compensation Long-term incentive awards made during 1996 are shown in the following table.
Long-term Incentive Plans -
Awards in the Last Fiscal Year 1996-1998 Long-term Incentive Plan Estimated Future Payouts Performance or Number of Other Period under Non-stock Price Based Plans(2)
Shares, Units until Maturation Threshold Target Maximum Name or Other Rights(!)
or Payout
(#)
-2!2_
(#)
J. T. Rhodes 7,326 3 years 3,663 4,884 7,326 R. E. Rigsby 5,421 3 years 2,711 3,614 5,421 J.P. O'Hanlon 3,507 3 years 1,754 2,338 3,507 E. M. Roach, Jr.
2,868 3 years 1,434 1,912 2,868
- 1.:w. Ellis 2,868 3 years 1,434 1,912 2,868 (1) The restricted shares of Dominion Resources Common_ Stock to be awarded at the end of performance period.
(2) Performance based restricted stock, the vesting of which is tied to the achievement of the cumulative measure of
- Economic Value Added (EVA) over a three year period (1996-1998). The threshold amount will be earned if the minimum specified EVA is_ achieved. The maximum amount will be earned if 320% of the EVA goal is achieved.
Retirement Plans The table below sets forth the estimated annual straight life benefit that would be paid following retirement under the benefit formula of the Dominion Resources, Inc. Retirement Plan (the Retirement Plan).
Estimated Annual Benefits Payable upon Retirement Credited Years of Service Final Average Earnings 15 20 25 30 150,000
$ 40,901
$ 54,535
$ 68,169
$ 81,803 175,000 48,514 64,685 80,857 97,028 200,000 56,126 74,835 93,544 112,253 225,000
- 63,739 84,985 106,232 127,478 250,000 71,351 95,135 118,919 142,703 300,000 86,576 115,435 144,294 173,153 350,000 101,801 135,735 169,669 203,603 400,000
.-\\'.
117,026 156,035 195,044 234,053 450,000 132,251 176,335 220,419 264,503 500,000 147,476 196,635 245,794 294,953 550,000 162,701 216,935 271;169 325,403 600,000
- 177,926 237,235 296,544 355,853 650,000 193,151 257,535 321,919 386,303 Benefits under the Retirement Plan are based on (i) average base compensation over the consecutive 60-month period in which pay is highest, (ii) years of credited service, (iii) age at retirement, and (iv) the offset of Social Security Benefits.
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Certain officers have entered into retirement agreements that give additional credited years of service for retirement and retirement life insurance purposes, and retirement medical benefit purposes contingent upon the officer reaching a specified age arid remaining in the employ of the Company or an affiliate.
For purposes of the above table, based on 1996 compensation, credited years of service (including any additional years earned in connection with the retirement agreements) for each of the individuals named in the cash compensation table would be as follows:
James T. Rhodes: 30; Robert E. Rigsby: 25; James P. O'Hanlon: 7; Edgar M. Roach, Jr: 2; and Larry W. Ellis: 30.
Virginia Power's executive compensation program has placed increased emphasis on incentive compensation opportuni-ties linked to financial and operating performance. Base salaries have been held below the mean for comparable positions ar comparable companies. The Retirement Plan benefit formula recognizes base salary, but not incentive compensation pay-ments. Therefore, each year the Organization and Compensation Committee approves a market-based adjustment to execu-tive base salaries for use in calculating the retirement benefit under the Dominion Resources, Inc. Benefit Restoration Plan (the Restoration Plan). In 1996, this adjustment was 11 percent. Also, the Internal Revenue Code limits the annual retirement benefit that may be paid from a qualified retirement plan and the amount of compensation that may be recognized by the Retirement Plan. To the extent that benefits determined under the Retirement Plan's benefit formula excee_d the limitations imposed by the Internal Revenue Code, they will be paid under the Dominion Resources, Inc. Benefit Restoration Plan.
- The Company also provides an Executive Supplemental Retirement Plan (the Supplemental Plan) to its elected officers designated to participate by the Board of Directors. The Supplemental Plan provides an annual retirement benefit equal to 25 percent of a participant's final compensation (base pay plus annual incentive plan payments). The normal form of benefit is monthly installments for 120 months to a participant with 60 months of service, who (i) retires at or after age 55 from the employ of the Company, (ii) has become permanently disabled, or (iii) dies. Ifa participant dies while employed, the normal form *of benefit will be paid to a designated beneficiary. If a participant dies while retired, but before receiving all benefit payments, the remaining installments will be paid to a designated beneficiary. In order to be entitled to benefits under the Supplemental Plan, an employee must be employed as an elected officer of the Company until death, disability or retirement.
In addition, an employee will vest in 20% of the supplemental plan benefit for each year of service as an elected officer after age 50. Dr. Rhodes' benefit is payable for life with a minimum of 10 years payments. A lump sum payment is available under certain conditions.
Based on 1996 compensation, the estimated annual retirement benefit for each of the executive* officers under the Sup.:*
plemental Plan would be as follows: James T. Rhodes: $165,600; Robert E. Rigsby: $92,651; James P. O'Hanlon: $86,291; Edgar M. Roach, Jr.: $70,668; and Larry W. Ellis: $72,018.
Retirement Benefit Funding Plan The Company maintains a Retirement Benefit Funding Plan to provide a means to secure obligations under the Supple-mental Plan, the Restoration Plan, and retirement agreements. The Retirement Benefit Funding Plan does not provide any additional benefits; it simply helps secure the funding for these benefit obligations. The amount payable by Virginia Power under the Supplemental Plan, the Restoration Plan and retirement agreements is reduced, on a dollar-for-dollar _basis,. by the funds ~vailable under the Retirement Benefit Funding Plan.
Employment Agreements The Company has entered into employment continuity agreements (the Agreements) with its key management execu-tives, including James T. Rhodes, Robert E. Rigsby, Edgar M. Roach, Jr., Larry W. Ellis and James P. O'Hanlon, which provide benefits in the event of a change in control. Each Agreement has a three-year term and thereafter is automatically _
extended on its anniversary date for an additional year unless notified that the Agreement will not be extended by the Com-pany. If, following a change in control (as defined in the Agreements) of Dominion Resources or the Company, an execu-tive'.s employment is terminated by the Company without cause, or voluntarily by the executive within sixty days after a material_reduction in the executive's compensation, benefits or responsibilities, the Company will be obligated to pay to the executive continued compensation equaling the average base salary and cash incentive bonuses for the thirty-six full month period of employment preceding the change in control or employment termination. In addition, the terminated executive will continue to be entitled to any benefits due under any stock or benefit plans. The Agreements do not alter the compensation and benefits available to an executive whose employment with the Company continues for the full term of the executive's Agreement. The amount of benefits provided under each executive's Agreement will be reduced by any compensation earned 54
e by the executive from comparable employment by another employer during the thirty-six months following termination of employment with the Company. An executive shall not be entitled to the above benefits in the event termination is for cause.
The Company'has entered into an employment agreement with Dr. James T. Rhodes which provides *that Dr. Rhodes will continue in the employ of the Company, as Chief Executive Officer until July 31, 1999. During this term; Dr. Rhodes' base salary will not be reduced, and he will participate in the compensation and benefit plans provided for* senior management.
If Dr. Rhodes' employment is terminated, for any reason, his retirement benefits will be calculated using his final salary and will assume 60 years of age and 30 years of service. In addition, any restricted stock held for Dr. Rhodes will become
- fully vested, his benefit under the Executive Supplemental Retirement Plan will be paid for life, he will receive immediate payment for all outstanding awards under. the Performance Achievement Plan, and he will receive a lump sum payment approximately equal to his 1994 salary plus incentive, and he will receive a c.ash payment equal to the net present value of base salary and incentives that he would be projected to receive between August 1, 1996 and April 21, 1997. Salary and incentive will be calculated at a rate not less than the maximum rate paid during the prior three years. Termination as a result of disability, at any time during the term of employment, will also result in the payment of the benefits descri~ed above. In the case of termination due to death, the benefits described above will be paid to the designated beneficiary, but payments under the Executive Supplemental Retirement Plan will be made for ten years.
Compensation of Directors The non-employee members of the Board receive an annual retainer of $19,000 and a fee of $900 for each Board or committee meeting attended. Committee chairmen receive an additional annual retainer of $3,000 and the Chairman of the Board receives an additional $25,000 annual retainer. These Directors may elect to defer their annual retainer and/or their meeting fees under the Deferred Compensation Plan until they retire from the Board or otherwise direct. The deferred fees are credited, for bookkeeping purposes, with earnings and losses as if they were invested in either an interest bearing account or Dominion Resources Common Stock, depending on the Director's election.
In 1996, the Company adopted the Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors. This plan aligns a portion of a non-employee director's compensation with the interests of the shareholders by increasing the director's ownership of common stock. Upon election to the Board, a non-employee director receives a one-time award of Stock Units (which are equivalent in value to common stock). The award is determined by (i) multiplying the director's retainer by 17 and (ii) dividing the result by the average price of common stock on the last trading days of the three nicinths before the director's election to the Board. The Stock Units awarded to a director are credited to a book account." A separate accourit is credited with additional Stock Units equal in value to dividends. A director must have 17 years of service in order to receive all of the Stock Units awarded and accumulated under the plan.
Directors Charitable Contribution Program Dominion Resources administers a Directors' Charitable Contribution Program (the Program) that covers Directors *of the Company, as part of its overall program of charitable giving. Beginning at the death of a Director a donation in an aggregate amount of $50,000 per year for 10 years will be made to one or more qualifying charitable organizations recom-mended by the individual Director. Life insurance policies have been purchased on the lives of the Directors in connection with the Program. These policies are owned by Dominion Resources, which is also the beneficiary. The Directors derive no financial or tax benefits from the Program.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The table below sets forth as of February 21, 1997, except as noted, the number of shares of Comrrlon Stock 'of Domin-ion Resources owned by Directors and four other more highly compensated executive officers of Vrrginia Electric and Power Company.
Name James T. Rhodes..................................................
Robert E. Rigsby................................................. '.
Larry W. Ellis......................................................
James P. O'Hanlon..............................................
Edgar M. Roach, Jr..............................................
John B. Adams, Jr...............................................
James F. Betts......................................................
Jean E. Clary............ :...........................................
Benjamin J.* Lambert, ill.....................................
Richard L. Leatherwood......................................
Harvey L. Lindsay, Jr..........................................
. William T. Roos...................................................
Robert H. Spilman.............................................. *.
William G. Thomas..............................................
Shares of Common Stock Beneficially Owned 22,961(1) 14,422(1) 9,595(1) 7,343(1) 3,295(1) 3,509 7,500 0
0 1,000 400 11,496(3) 1,164 0
Director Plan Accounts(2) 8,500 0
0 9,548 14,724 8,500 11,405 8,500 3,267 (1) The amounts indicated include restricted stock as follows: Dr. Rhodes-'- 7,326; Mr. Rigsby~ 5,421; Mr. Ellis.
956; Mr. O'Hankm -
3,507; Mr. Roach -
2,868; and all Directors and executive officers as a group -
44,777.
(2) The number noted under this heading represents the number of shares that may be distributable to the Director under the Deferred Compensation Plan and/or the Stock Accumulation Plan.
(3) Members of Mr. Roos' family are beneficiaries of trusts that own 4,387 shares of Common Stock for which he disclaims beneficial ownership.
All Directors and executive officers a.s a group (31 persons) beneficially own, in the aggregate, 256,934 shares of Com-
- man Stock of Dominion Resources. Beneficial ownership of shares of the total are disclaimed. No shares of the Company's Preferred Stock are owned by the Directors or executive officers as a group.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Hazel & Thomas, a professional corporation, from time to time acts as counsel to the Company. Mr. Thomas, a Directoi of the Company, is a shareholder of Hazel & Thonias.
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PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this Form 10-K:
- 1. Financial Statements See Index on page 21.
- 2. Exhibits 3(i) 3(ii) 4(i) 4(ii) 4(iii)
Restated Articles of Incorporation, as amended, as in effect on September 12, 1994 (Exhibit 3(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference).
Bylaws, as amended, as in effect on December 31, 1994 (Exhibit 3(ii), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).
See Exhibit 3 (i) above.
Indenture of Mortgage of the Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference); Fifty-Ninth Supplemental Indenture (Exhibit 4(ii), Form 10-Q for the quarter ended March 31, 1986, File No. 1-2255, incorporated by reference); Sixtieth Supplemental Indenture (Exhibit 4(ii), Form 10-Q for the quarter ended September 30, 1986, File No. 1-2255, incorporated by reference);
Sixty-First Supplemental Indenture (Exhibit 4(ii), Form 10-Q for the quarter ended June 30, 1987, File No. 1-2255, incorporated by reference); Sixty-Second Supplemental Indenture (Exhibit 4(ii), Form 8-K, dated November 3, 1987, File No. 1-2255, incorporated by reference);
Sixty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated June 8, 1988, File No. 1-2255, incorporated by reference); Sixty Fourth Supplemental Indenture (Exhibit 4(i),
Form 8-K, dated February 8, 1989, File No. 1-2255, incorporated by reference); Sixty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated June 22, 1989, File No. 1-2255, incorporated by reference); Sixty-Sixth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated February 27, 1990, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference); Sixty-Eighth Supplemental Indenture, (Exhibit 4(i)), Sixty-Ninth Supplemental Indenture, (Exhibit 4(ii)) and Seventieth Supplemental Indenture, (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture, (Exhibit.
4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 6, 1993, File No. 1~2255, incorporated by reference); Seventy-Sixth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 21, 1993, File No.' 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated June 8, 1993, File No. 1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Ninth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1-2255, incorporated by reference); Eighty-First Supplemental Indenture, (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture, (Exhibit 4(i),
Form 8-K, dated January 18, 1994, File No. 1-2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference); Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 22, 1995, File No. 1-2255, incorporated by reference; and Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K; dated February 20, 1997, File No. 1-2255, incorporated by reference).
Indenture, dated April 1, 1985, between Virginia Electric and Power Company and Crestar Bank (formerly United Virginia Bank) (Exhibit 4(iv), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).
57
4(iv) 4(v) 4(vi) 4(vii) lO(i) lO(ii) lO(iii) lO(iv) lO(v) lO(vi) lO(vii) lO(viii) lO(ix) lO(x) _,
lO(xi)*
lO(xii)*
lO(xiii)*
e Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and Chemical Bank (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).
fudenture, dated April 1; 1988, between Virginia Electric and Power Company andChernic:al 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).
Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and The Chase Manhattan Bank (formerly Chemical Bank), as Trustee, as.
supplemented (Exhibit 4(a), Form S-3 Registration Statement File No, 333-20561 as filed on January 28, 1997, incorporated by reference).
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.
Operating* Agreement, dated June 17, 1981, between Virginia Electric and Power Company and Monongahela*Power Company, the Potomac Edison Company, West Penn Power Company, and Allegheny Generating Company (Exhibit lO(vi), Form 10-K for the fiscal year ended December 31, 1983, File No. 1-8489; incorporated by reference).
Purchase, Construction and* Ownership Agreement, dated as of December 28, 1982 but amended arid restated on October 17, 1983, between Virginia Electric and Power Company and Old
-Dominion Electric Cooperative (Exhibit lO(viii);Form 10-K for the fiscal year ended December 31, 1983, File No. 1~8489, incorporated by reference).
_Interconnection and Operating Agreement, dated as of December 28, 1982 a:s amended and restated on October 17, 1983, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(ix), Forin 10-K for the fiscal year ended December 31, 1983, File No. 1-8489, incorporated by reference).
Nuclear Fuel Agreement,, dated as of December 28, 1982 as amended and restated on October 17,.1983, between Virginia Electric and Power Company_and Old Dominion Electric Cooperative (Exhibit lO(x), Form 10-K for the fiscal year end_ed December 31, 1983, File No. 1~8489, incorporated by reference).
Credit Agreements dated June 7, 1996, between Chase Manhattan Bank (formerly Chemical Bank) and Vi,rginia Electric and Power Company (Exhibits lO(i) and lO(ii), Form 10-Q for the period ended_June 30, 1996, File No. 1-2255, incorporated by reference).
Credit Agreement, dated December 1, 1985, between Virginia Elec;tric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xix), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-8489, incorporated by reference).
Agreement for Northern Virginia Services, dated as of November 1, 1985, between Potomac Electric Power Company and Virginia Electric and Power Company (Exhibit lO(xxi),
Form 10-K for the fiscal year ended December 31, 1985, File No. 1-8489, incorporated by reference).
Purchase, Construction and Ownership* Agreement, dated May 31, 1990, between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit lO(xi),
Form 10-K for the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).
Operatirig Agreement, dated May 31, 1990, between Virginia Electric and Power Company and
- Old Dominion Electric Cooperative (Exhibit lO(x~i), Form 10-K for the fiscal year ended
-December 31, 1990, File No. 1-2255, incorporated by reference).
Coal-Fired Unit Turnkey Contract (Volume 1), dated April 6, 1989, and the Unit 2 Amendment (Volume 1), dated May 3_1; 1990 between Virginia Electric and Power Company and Old Dominion Electric Cooperative, Westinghouse, Black & Veatch, Combustion Engineering and H.B. Zachry (Volumes 2-11 contain technical specifications) (Exhibit lO(xiii), Form 10-K for
~
the fiscal year ended December 31, 1990, File No. 1-2255, incorporated by reference).
Description. of arrangements with *certain officers regardil).g additional credited years of service for retirement purposes (ExhibiUO(xii), Form 10-K for the fiscal year ended December 31, 1992, File No. 1-2255, incorporated by reference).
Dominion Resources, Inc. Directors' Deferred Compensation Plan effective July 1, 1986, as amended and restated on January J, 1996 (filed herewith).
-Dominion Resources, Inc. Performance Achievement Plan, effective January 1, 1986, as amended and restated effective February 19, 1988 (Exhibit lO(xxiii), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).
58
I. ~
lO(xiv)*
lO(xv)*.
lO(xvi)**
ilJ.O(xvii)*
"'iO(xviii)*
lO(xix)*
lO(xx)*
lO(xxi):
lO(xxii) lO(xxiii)
- lO(xxiv) 23(i) 23(ii) 23(iii) 27-e e
Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 1981 as amended and restated effective October 22, 1988 and as amended and restated June 15,. 1990 (Exhibit lO(xxiv); Form 10-K for.the fiscal year ended December 31,' 1994, File No.' 1-1255,.
- Dorninio_n Resources, Inc.'.s.~as~ Incentive Plan as adopted December 20, 1991 (Exhibit lO(xxv), Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).
Employment Continuity Agreement for James T. Rhodes of Vrrginia Power (Exhibit lO(xxvii),
Form lO;K for, the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by
'reference): :
- 'nbmiriiori Resources, Inc. Retirement Benefit Funding Plan, effective june 29, 1990
- .. (Exhibit* lO(xxviii~, Form 10-K for.the fiscal year ended December -31, 1994,.:File No. 1~2255, incorporated by reference)..
. Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective J an'uary 1,
.1991 (Exhibit lO(xxix),_Form 10-K for the fiscal year ended December 31, 1994, File No. 1-2255, incorporated by reference).
Porninio.n Resources, I;nc. Executives' Deferred Compensation Plan,, effective January 1, 1994,
', - as amended and 'restated on January 1, 1997 (filed herewith).
Employment Agreement dated April 21, 1995 betwee'n Vrrgiliia Power and James T. Rhodes (Exhibit 10, Form 10-Qfor the period ended March 31, 1995, incorporated by reference) and an.
amendment dated September 15, 1995 (Exhibit 10; Form 10-Q f9r the period ended.
September 30, 199-5, incorporated,by-reference):
Form of an Employment Agreement dated June 23, 1994*betweenVirginia Power and certain executive officers (filed herewith);
Employment Agreement dated September 15, 1995 between Vrrgi,nia, Power and Robert K Rigsby (filed herewith)...
Employment Agreement dated September 15, 1995 between \\Trrginia Power and Edgar M.
Roach, Jr. (filed herewith)..
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, effective April 23, 1996 (filed herewith). -,. ;
Consent of Hunton &_Williams (fiied herewith).
Consent of Jackson & Kelly (filed herewith).
Consent of Deloitte & Touche LLP * (filed here~itli). *-*
Financial Data Sch~duli:i (filed herewith).
- Indicates management contract' or conipensatciry plan or arrangement_
- (**:*: *-
(b) Reports on Forni' 8-K The Comp~y filed.a xepoi;t on Fopn}.-~-'- d!ited February 20, 1997, relating t<>. the sale of $200 rnilli~n Fb.-sLand
- Refunding Mortgage***Bonds.
,*, '... ~.
-~<,: '
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SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the reg1strant has duly caused this report to be signed on its behalf by the undersigned,' thereunto duly authorized.
Date: March 24, 1997 VIRGINIA ELECTRIC AND POWER COMPANY By_~~_____,.-=---=-ls~l~J~O_HN---=-B~*~AD::--:-A_M_S~,J_R~*~~~~~-
(John B. Adams, Jr., Chairman of the Board of Directors)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 24, 1997.
Signature Isl JOHN B. ADAMS, JR.
John B. Adams, Jr.
Isl JAMES F. BETTS James_F. Betts.
- Isl JEAN E. CLARY Jean E. Clary
--Isl BENJAMIN J. LAMBERT, III Benjamin J. Lambert, m Isl RICHARD L. LEATHERWOOD Richard L. Leatherwo"Hf' **
Isl HARVEY L. LINDSAY, JR.
Harvey L. Lindsay, Jr.
Isl J. T. RHODES.
J. T. Rhodes Isl WILLIAM T. Roos William T. Roos Robert H. Spilman Isl WILLIAM G. THOMAS William G. Thomas Isl R. E. RIGSBY R. E. Rigsby 60 Title Chairman of the Board of Directors and Director Director.
Director Director
.Director Director President.(Chief Executive Officer) and Director Director Director Director Executive Vice President
Isl
. *' y Isl
("1 e
E. M. ROACH, JR.
E. M. Roach, Jr.
M. S. BOLTON, JR.
M. S. Bolton, Jr.
61 e
Senior Vice President-Finance, Regulation, and General Counsel (Chief Financial Officer)
Controller (Principal Accounting Officer)