ML18130A328

Annual Financial Rept 1980

ML18130A328
Person / Time
Site:	Surry, North Anna
Issue date:	03/31/1981
From:	VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:
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ML18130A329	List: ML18130A328 ML18139B220
References
NUDOCS 8104030388
Download: ML18130A328 (43)

Text

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DEADLINE RETURN DATE RECORDS FACILITY BRANCH

On the Cover Massive coal pile at Chesterfield Power Station symbolizes our significant shift to coal. Vepco leads the nation in switching to this fossil fuel, resulting in lower charges to customers and less dependence on foreign oil.

Disposition of the 1980 Revenue Dollar po

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r co Contents Highlights..................................................

1 Stockholders Letter....................................

2 Revenues...................................................

4 Expenses...................................................

4 Earnings and Dividends..............................

4 Electric Output...........................................

6 Rates.........................................................

6 Nuclear Units.............................................

8 Bath County Pumped Storage..................... 10 Revised Construction Program.................... 1 0 Load Management...................................... 10 Coal Conversion......................................... 1 2 Nuclear Insurance Pool............................... 12 Finance...................................................... 12 Customer Relations.................................... 1 2 Investor Relations....................................... 14 Financial Report......................................... 1 7 Description of Business.............................. 1 8 Management's Discussion and Analysis of Statement of Income.............. 18 Statistical Information................................. 36 Directors and Officers................................. 40

1980 Highlights Increase

% Increase 1980 1979 (Decrease)

(Decrease)

Financial Total Operating Revenues

$2,119,774,000

$1,703,309,000

$416,465,000 24.5 Total Operating Expenses

$1,730,242,000

$1,386,915,000

$343,327,000 24.8 Net Income

$ 241,620,000 196,467,000

$ 45,153,000 23.0 Balance Available for Common Stock 184,329,000 141,344,000

$ 42,985,000 30.4 Average Shares of Common Stock Outstanding 95,520,000 86,965,000 8,555,000 9.8 Stockholders---Common, Preferred and Preference 206,800 195,100 11,700 6.0 Earnings Per Share of Common Stock

$1.93

$1.63

$.30 18.4 Dividends Per Share of Common Stock

$1.40

$1.38

$.02 1.4 Book Value Per Share of Common Stock

$18.63

$18.65

$(.02)

(0.1)

Capital Expenditures

$ 681,120,000

$ 708,756,000

$(27,636,000)

(3.9)

Long-Term Financings

$ 480,874,000

$ 407,198,000

$ 73,676,000 18.1 Operations System Output--Megawatt-hours (thousands) 42,489 40,484 2,005 5.0 Capability--Megawatts 11,154 9,999 1,155 11.6 Service Area Peak Load-Megawatts 8,484 7,929 555 7.0 Customers--Electric--Heating 325,728 296,234 29,494 10.0

--Other 1,021,372 1,012,866 8,506 0.8 Total Electric 1,347,100 1,309,100 38,000 2.9 Customers--Gas 120,100 118,600 1,500 1.3 Average Residential Use--Electric-Kilowatt-hours 11,056 10,721 335 3.1 Employees--Full Time 10,580 9,625 955 9.9 Virginia Electric and Power Company

• One James River Plaza

• Richmond, Virginia 23261

To Our Stockholders:

This annual report records some of the most significant operating events in the recent history of Vepco. The re-versals of 1979, caused in part by the regulatory reaction to the accident at Three Mile Island (TMI), compelled us to begin 1980 with a recital of pros-pects for possible improvements in op-erations and earnings. By year's end, it was no longer necessary to speak only of prospects and plans. The first fruits of our corporate strategy for the 1980s already were apparent to cus-tomers, investors and regulators. The results of the year spoke for them-selves.

Most conspicuous among the good results were the simultaneous reduc-tion in rates and increase in earnings.

Earnings per share rose by 18% while our most widely reported energy price-the 1,000 kilowatt-hour cost to Virginia residential customers-de-clined by 7.2%. This performance rec-ord clearly demonstrated that Vepco's dual objectives for the 1980s-rate re-straint and income improvement-are compatible and realistic.

We took our first steps toward these objectives with initial attainment of four primary goals-restoration of nor-mal operations at nuclear generating units, rigorous control of our construc-tion expenditures, aggressive con-version of oil-fired units to coal and im-proved productivity at all fossil generating stations.

Nuclear Operations Nuclear unit operations in 1980 confirmed the potential they hold for profitability and reasonable energy prices. We began the year in the midst of a national crisis of confidence in nu-clear power. But by year's end, Vepco contributed significantly to the restora-tion of that confidence. Full-power op-erations at North Anna 2 were delayed for more than a year by a nationwide licensing moratorium, but it withstood unprecedented scrutiny, including the country's most comprehensive emer-gency evacuation test, to become the first nuclear unit in the nation since TMI to receive a full-power permit and begin commercial operation. Its per-formance so far gives us every reason to expect it to equal or surpass the op-erating record of North Anna 1, which ranks among the most productive nu-clear units in the country.

At our Surry station, a serious set-back to our nuclear program is being overcome by an outstanding engineer-ing and construction achievement.

Surry 2 resumed normal operations in late summer after successful replace-ment of its steam generators. A similar generator replacement at Surry 1 was on schedule at the end of the year.

Vepco was the first utility to undertake such replacements, which may even-tually be necessary at more than 20 nuclear units in the United States and Canada. Our satisfactory completion of the difficult construction project at Surry 2 has attracted the attention of other utilities confronted by the same problem.

The work at Surry is renewing the life of two relatively young units that were built before the severe construc-tion cost inflation of the 1970s. It would cost eight times as much to re-place them with nuclear power today and seven times as much to build equivalent coal-fired generating ca-pacity.

Our nuclear operations in 1 980 ac-counted for 27% of the energy sup-plied to Vepco customers, compared with 17% in 1979. We project that nu-clear power will produce 41 % of total generation in 1981. This increased nuclear reliance is expected to reduce total fuel costs in 1981 by 20%-a sav-ings of $200 million-despite projected increases in fossil fuel prices.

Some of our severe regulatory crit-ics of the past now regard Vepco as the best operator of nuclear units in the United States. This is a judgment that reflects due credit on the team of engineers, construction managers and operators who run our program. Their performance in 1 980 can be illus-trated by a single episode that oc-curred last fall.

On the night of November 30, North Anna 2 was operating at full power during the last phase of testing. Eight hours before it was scheduled for commercial operation, a transformer failure destroyed the conduits that carry electrical power from the unit's generator to the transmission system.

The unit shut down automatically as designed, but our hopes for com-mercial operation in 1980 appeared to have ended. Two months was a rea-sonable estimate of the time required to assemble the materials, complete the repairs and return the unit to serv-ice. The Vepco team did the work in 1 O days and North Anna 2 was placed in commercial operation on December

14. It was an achievement that spoke plainly for the competence and morale of everyone involved.

2 Construction Program Our corporate strategy for the 1980s implies our conviction that rate restraint and profitability require close control of new construction costs. In the years since the OPEC oil embargo shattered worldwide assumptions about our energy future, utilities have scrambled to adjust expansion pro-grams, mandated by public service im-peratives, to a new set of energy eco-nomics.

Vepco completed its adjustment in 1980 after the most comprehensive analysis we have ever made of future generating options.

As a result, we reduced our plans to construct new generating capacity by approximately 50%. We accomplished this by canceling construction of the North Anna 4 nuclear unit and by reaching preliminary agreement in principle with the Allegheny Power System for joint use or ownership of the Bath County Pumped Storage Project. The effect of these actions is to reduce our construction financing requirements for the rest of this dec-ade by almost $2 billion.

Use of our share of Bath County in the mid-1980s and completion of the North Anna 3 nuclear unit by the end of the decade will meet projected growth in demand, which has fallen to an annual rate of about 2% from al-most 11 % before the OPEC embargo.

We have positioned ourselves to re-spond to future changes in demand growth by refraining from a com-mitment to a new plant after North Anna 3, by undertaking new programs to control electrical demand and by deciding to follow North Anna 3, when a commitment is necessary, with a coal-fired unit. Coal-fired units take less time to build than nuclear units and can be more easily varied in size.

A coal unit will, therefore, give us more flexibility in the timing and magnitude of our response to changes in demand during the balance of the century.

Because the decisions on North Anna 3 and 4 were difficult and inher-ently controversial, we were gratified by the generally favorable response to them. A Washington Post editorial commented: "Vepco's original deci-sion to begin North Anna 4 was right at the time it was made. But since then the whole development of the econ-omy has shifted and the decision to cancel the plant is the right one now."

In support of favorable regulatory treatment of cancellation costs, The Post added: " Utilities all over the

country face similar decisions. It's im-portant not to penalize them for mak-ing the unconventional choices that will ultimately save the customers far more than they cost.*

• Fossil Station Programs By the end of 1980, our program of converting about 2,250 megawatts of oil-fired generating capacity to coal was more than two-thirds complete.

We lead all other U.S. utilities in coal conversions, and by the time we finish the program in 1983 it will reduce im-ported oil consumption about 20 mil-lion barrels a year.

The most direct benefit of the con-version program flows to customers in the form of reduced fuel charges.

However, it is important to bear in mind that any fuel charge reduction improves customer relations and the regulatory climate and thus yields a significant indirect benefit to stock-holders.

Of equal importance to our con-version program is the systematic up-grading of fossil station productivity through capital improvements, mainte-nance improvements and improve-ments in operator training. The objec-tive of this program, which will be completed in 1983, is very simple. It is to achieve the maximum efficiency possible at our coal-fired generating stations.

Gas Department In recent years, price decontrol and supply increases have combined to create opportunities for renewed growth of our natural gas business.

Sales increased again last year and have now returned to the peak levels of the early 1970s. Prospects are bright for continued growth of this im-portant part of our energy utility serv-ice.

Summing Up Looking back at all aspects of our performance in 1980 is a cause of sat-isfaction. Our profit growth contrasted sharply with the overall profit decline for U.S. corporations, including other utilities. Our success in overcoming operating and regulatory problems at nuclear stations put us in a favorable competitive position with other utilities that are now confronting problems that faced us in the past. Our rate reduc-tions contrasted favorably with contin-ued nationwide inflation-consumer prices rose another 12%-and with the new surge in energy prices-the cost of residual oil, critical to our opera-tions, rose 36%.

It is especially gratifying that our performance improvement was recog-nized by customers. Perhaps the most significant indicator of this recognition was the response to our customer stock purchase plan. By year-end, about 14,000 individuals, more than 1 % of our residential customers, had subscribed to Vepco shares under this plan. Their purchases will provide

-,k-i T. Justin Moore, Jr.

Chairman of the Board 3

about $6.3 million in new equity funds.

A survey of these subscribers showed that almost half had never before pur-chased a share of common stock in any company.

In summary, 1980 was a year in which we renewed our commitment to superior performance and established an operating record that will challenge all of our 10,500 employees to im-prove on it this year. We are confident they are equal to the challenge.

~am::.~

President

Revenues Vepco operating revenues in 1980 ex-ceeded $2 billion for the first time. Our electric business generated $2,049.5 million and the gas business $70.3 million for a total of $2.1 billion, an in-crease of $416.5 million, or 24%,

compared with 1979.

Unusually warm weather in the summer resulted in a 4% increase in kilowatt-hour sales compared with sales last year.

Expenses Total operating expenses were $1. 7 billion, an increase of $343.3 million, or 25%. Increased sales, inflation, regulatory delay of nuclear unit opera-tions and the resulting cost of replac-ing nuclear generation with purchased power combined to increase expenses in 1980.

Planned maintenance programs and renovations at several large gen-erating stations resulted in a mainte-nance expense increase of $20. 1 mil-lion. Other operating costs, including taxes, depreciation, employee benefits and additional personnel, increased

$61.8 million.

Fuel expenses including purchased and interchanged power costs were up $261.5 million in 1980, although an analysis of these expenses on a monthly basis indicates that our fuel expenses have been decreasing dur-ing the past year. This was due to our increased use of nuclear and coal-fired generating units. Although pur-chased and interchanged power ex-penses in 1980 were up 75%, our cost per kilowatt-hour for purchases was less than the cost of generating elec-tricity with some of our own oil-fired units.

Earnings and Dividends The improvement in earnings per share to $1.93 in 1980, compared with $1.63 in 1979, reflects changes in a number of factors, including a substantial increase in generation from nuclear units, higher electric en-ergy sales and improved performance of coal-fired units.

The Company paid its common stockholders dividends of $1.40 per share in 1980, compared with $1.38 paid in 1979.

A preliminary determination in-dicates that 100% of the common and preference stock dividends and 3.3%

of the preferred stock dividends paid in 1 980 constitute a return of capital and therefore are not taxable as divi-dend income under requirements of the Federal income tax laws. It should be noted that this determination has not been reviewed by the Internal Rev-enue Service. The percentages may change based on a subsequent audit of the Company's Federal income tax returns.

Common stock prices and divi-dends for the last two years were:

1979 High Low Dividends First Quarter 143-4 13

$.33 Second Quarter 13'h 12

.35 Third Quarter 13 V.

11 %

.35 Fourth Quarter 12%

103/a

.35

$1.38 1980 High Low Dividends First Quarter 123/a gy.

$.35 Second Quarter 12V.

93,4

.35 Third Quarter 12 10V.

.35 Fourth Quarter 11 %

9'h

.35

$1.40 Fuel and Purchased and Interchanged Power Costs (Cents per Kilowatt-hour) 3 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~-3 2

1 0

JFMAMJJASOND JFMAMJJASOND 1979 1980 4

Electric Output Electric output rose 5% in 1980. Un-usually hot summer weather was the principal reason for the increase. Our customers set a new peak power de-mand record of 8,484 megawatts (Mw) in August, which was 7% higher than 1979's peak demand.

The 1980 winter peak demand of 7,445 Mw in February was surpassed in February 1981 when a new peak of 8,451 Mw occurred. Expanding use of electric heat pumps is moving us rap-idly toward the day when we will ex-perience balanced peak demands in the summer and winter.

As shown on the chart below, gen-eration from nuclear units increased substantially in 1980, contributing 27% of the electrical energy we sup-plied, compared with 17% in 1979.

Nuclear generation saved $414 million in fuel costs compared to the cost of oil that would have been necessary to produce the same amount of electric-ity. Coal generation accounted for 25%, and oil generation was greatly reduced to 19%, compared with 33%

in 1979.

Sources of Electric Energy Percent Coal 80 79 78 77 72 80 79 78 77 72 Oil r--

I I,...-

Nuclear 80 79 78 77 72 I I

,'.d I

• .*,*= I r:i

-=-i 1--

I I

I Purchased and Interchanged

• Other 80 I

79 78.

77

• 72 0

10 20 30 40 50 During 1980, the Company took ad-vantage of opportunities to purchase power priced below our own oil-fired generating costs. These purchases accounted for 27% of electrical en-ergy supplied to customers. Most of these purchases were from coal-fired units of neighboring utilities that had capacity to spare. Hydro and com-bustion turbine generation contributed the remaining 2%.

In 1 981, we are projecting an en-ergy supply mix of 41 % nuclear; 40%

coal ; 10% oil; 7% purchases, and 2%

hydro and combustion turbine.

The number of residential custom-ers and the average annual residential usage of electricity each climbed 3%

in 1980.

Rates Despite 1980 increases in base rates, the net effect of all rate changes filed in Virginia, the Company's largest ju-risdiction, and North Carolina was an overall reduction in residential rates.

This was accomplished through re-duced fuel expenses made possible by increased generation from nuclear units, economical power purchases and decreased use of costly oil.

In Virginia, a residential customer's 1,000 kilowatt-hour monthly bill de-creased 7.2%. Although residential rates in North Carolina decreased slightly, the full effect of reduced fuel expenses will not be experienced until 1981 because of regulatory provi-sions.

Rate increases granted by regula-tory authorities and negotiated with governmental customers totaled

$132.3 million in 1980. Approximately

$64.6 million of these increases are subject to refund pending final hear-ing.

All rate filings are aggressively pur-sued and are crucial to our financial stability. Adequate rate relief is essen-tial if we are to continue to provide re-liable service when inflation is rapidly escalating our operating and mainte-nance expenses.

Following is a summary of 1980 rate cases:

Basic Rates The Virginia State Corporation Com-mission granted the Company $60 mil-lion of a $72.6 million request on Sep-tember 12, 1980. The request was to make up the deficiency below a 9.86%

rate of return experienced in the test year 1979. The Commission previously had approved a $46 million increase to be effective upon commercial oper-ation of North Anna Unit 2, which oc-curred on December 14.

The Company filed a $16.6 million rate increase with the North Carolina Utilities Commission on December 29.

This request was based on 1979 re-sults. It seeks a return on common equity of 15% and an overall return of 10.54%.

The West Virginia Public Service Commission suspended on August 29, 1980 the Company's filing for a $3.1 million increase until January 1, 1981.

An interim hearing was held October 20, 1980 and a full hearing is sched-uled for March 9, 1981.

On June 2, 1980, a Federal Energy Regulatory Commission (FERG) Ad-ministrative Law Judge issued an ini-tial decision in the Company's pending rate case relating to its municipal cus-tomers. These customers have been 6

Replacing the steam generators at Sur is part of an extensive overhaul progra both nuclear units to insure greater reliab

billed for an $8.5 million increase, subject to refund. However, we now estimate that the initial decision would permit an increase of only $5.1 mil-lion.

Exceptions to the initial decision were filed with FERG on July 2, 1980.

A provision is being recorded monthly for the difference between rates billed and rates indicated by the initial deci-sion.

The Company also filed on Novem-ber 14, 1980 an application with FERG for an $18.4 million rate in-crease to cooperative and municipal customers due to the commercial op-eration of North Anna Unit 2. This was put in effect January 13, 1981, sub-ject to refund.

Fuel Adjustment Approximately 98% of the Company's kilowatt-hour sales are subject to re-covery of current fuel costs, actual or estimated, through fuel expense re-covery procedures.

Nuclear Units Fourth Nuclear Unit Begins Operation Vepco 's fourth nuclear unit, North Anna Unit 2, received the first full-power operating license granted by the Nuclear Regulatory Commission (NRC) since the March 1979 accident at Three Mile Island. The Company was granted a low-power operating li-cense to load nuclear fuel and to per-form various tests in April 1980. The unit achieved its first self-sustaining nuclear chain reaction June 12 and was approved for full-power operation August 21.

The full-power license was granted following the successful completion of the most comprehensive emergency drill reviewed by the NRC and the Fed-eral Emergency Management Agency at that time. More than 300 represen-tatives of Vepco, Federal, State and local authorities participated in the day-long drill.

North Anna 2 was tested exten-sively and placed in commercial oper-ation December 14. At that time, a rate reduction of 4.3% went into effect for the Company's Virginia customers due to the lower fuel costs associated with nuclear power.

Other Nuclear Units During 1980, North Anna Unit 1 oper-ated at a capacity factor of 75%, well above the industry average of 56%. A unit operating at full power every hour of the year would have a capacity fac-tor of 100%, a theoretical maximum. A perfect capacity factor cannot be at-tained because of refueling every 12 to 18 months and periodic mainte-nance outages.

Surry Unit 2 returned to service in August after successful completion of piping support modifications required by the NRC before the unit could oper-ate. The Company also completed the replacement of that unit's steam gen-erators, the first project of its kind in the country. Many other utilities with similar steam generator problems are now looking to Vepco for expertise in dealing with such problems. During the remainder of the year, Surry 2 op-erated at a capacity factor of 87%.

Surry Unit 1 was out of service from February through May for repairs to its turbine and an engineering survey of its piping systems. The unit was re-moved from service in September for refueling, replacement of its steam generators and pipe support modifica-tions similar to those performed on Unit 2. From its May start-up until it was removed from service in Septem-ber, the unit operated at a 80% capac-ity factor.

In addition to replacement of the steam generators, work performed on Surry 2 and being performed on Surry 1 includes extensive overhaul of the turbines and installation of new equip-ment that will prevent steam generator problems in the future. This work also will increase the reliability of these units.

A number of modifications also were performed on all of the Com-pany's nuclear units in 1980 as a re-sult of lessons learned from the acci-dent at Three Mile Island. Many of these improvements were required by the NRC, and many were made at Vepco's own initiative.

North Anna 4 Cancellation When the North Anna station was first planned, the demand for electric-ity in our area was growing at nearly 11 % a year. Today, our demand growth has dropped to about 2% a year, making the capacity of North Anna 4 unnecessary in the early 1990s.

Since both the original decision to build North Anna 4 and the recent de-cision to cancel it were made in the in-terest of our customers, we will seek recovery of approximately $165 mil-lion invested in engineering, construc-tion and equipment for North Anna 4 that cannot be used in completing Unit

3. The Company is requesting regula-tory approval of recovery through rates over a 10-year period.

From the customers' standpoint, however, the savings from canceling the unit will more than offset the costs of cancellation during the 10 years.

North Anna 3 Construction Because of the need for new gener-ating capacity before 1990 and the current investment of more than $400 million, we believe it is in the best in-terest of our customers and stock-holders to complete North Anna 3 in 1989 as planned.

8 Construction will be continued on No Anna 3 (foreground). Licensing full-power operation of North Anna 2 w granted in August 1 9t

Bath County Pumped Storage Project The Company announced an agree-ment in October with Allegheny Power System CAPS) that provides for joint ownership or use of the Bath County Pumped Storage Project.

Under the agreement, APS must purchase either 40% of the project or the use of 40% of the project's capac-ity under long-term contract, or any combination of the two. APS may in-crease its share of the project up to 50% prior to December 31, 1984. Un-der any agreement, APS will be re-sponsible for providing the pumping energy required for its share of Bath County operations.

Negotiations are continuing on con-tract details. Vepco now expects to re-ceive about $260 million in 1981. The final agreement is subject to regula-tory approvals. The financing of the sale of an ownership interest in the project may be accomplished through the Bath County Hydroelectric Trust, a construction trust previously estab-lished by the Company for financing the project.

The Company's agreement with APS will reduce our external financing requirements while permitting us to continue construction of facilities needed to serve our customers. Three 350-Mw units are scheduled to begin operation in 1985 and three more in 1986. The station will have a total ca-pacity of 2,1 00 Mw.

Revised Construction Program In November, the Company an-nounced a revised construction pro-gram designed to provide the flexibility and balance necessary to meet cus-tomer demand in the 1980s.

This program includes the can-cellation of the North Anna 4 nuclear unit, which was previously planned for operation in 1992. The unit was less than 10% complete.

Other elements of the revised pro-gram include the completion of the North Anna 3 nuclear unit in 1989, the completion of the Bath County Pumped Storage Project in *1985-86 and a major emphasis on load man-agement, conservation and alternate energy sources to reduce the need for costly new facilities in the future.

This program is the result of an ex-tensive, year-long study of future de-mand growth, external financing re-quirements, the regulatory uncertainty surrounding nuclear power and the costs associated with various gener-ating options.

This revised construction program is our response to the unprecedented challenges posed by today's eco-nomic conditions and regulatory poli-cies. From the end of World War II until the OPEC embargo of 1973, energy utilities, their customers and their stockholders benefited from govern-ment policies and an economic climate that supported rapid growth. Since that time, we have taken measures to adapt to a rapidly changing world of severe inflation, soaring fuel costs and vascillating regulatory policy. Our re-vised construction program will enable us to cope with these changes without sacrificing the reliability of energy supplies, or the support of our inves-tors.

The key ingredient in utility plan-ning over the next decade will be flexi-bility. Our program balances energy needs with the Company's ability to fi-nance the facilities to meet those needs. While our reliance on nuclear power continues to produce savings to our customers, it is tempered by a full appreciation of the financial and regu-latory risks associated with nuclear units.

Current forecasts of growth in de-mand for electricity indicate the need for additional generating capacity sometime in the mid-1990s. Our cur-rent plan is to delay the need for any new generating facilities through load management. However, when it is again necessary to expand capacity, we plan to build a coal-fired unit. The size and in-service date of a coal-fired unit can be varied more easily than a nuclear unit, thus giving the Company continued flexibility. Also, the capital cost of a coal unit is smaller than a nu-clear unit, and a commitment to build a coal unit can be made later due to its shorter construction time.

Our commitment to build North Anna 3 remains firm. However, the major share of construction ex-penditures for North Anna 3 will not be made for several years. If the economy takes an unexpected turn, or if units of a similar design now nearing com-pletion encounter licensing difficulties, we will still be able to reassess our plans anytime before 1984.

Load Management One factor essential to the success of our revised construction program is effective use of load management. The goal of load management is to utilize generating units more efficiently by shifting demand from peak to off-peak periods. By controling peak demands on our system, the need to build costly new facilities can be delayed.

Vepco has employed load manage-ment techniques for years and is devel-oping new approaches through re-search and experimental programs.

Among programs the Company now has under way are interruptible service to customers' water heaters, interruptible 10 Work continues on the powerhouse!

Bath County Pumped Storage Project, whe generating facilities will be shared WI Allegheny Power SysteJ

service to large industrial customers with alternate fuel sources, and time-of-usage rate schedules to promote off-peak energy consumption.

Vepco's commitment to energy effi-ciency will help us match a financially feasible expansion program to our service area's still growing demand for electricity.

Coal Conversion The Company is continuing an aggres-sive program of converting oil-fired units to burn coal. We now have con-verted 1,639 Mw of capacity from oil to coal, more than any other utility in the nation. The use of coal not only produces lower costs for our custom-ers, it also helps our nation reduce its dependence on foreign oil.

Oil to Coal Conversions Units Capability (Mw)

Chesterfield 4

1 66 Chesterfield 5

31 0 Chesterfield 6

658 Portsmouth 4

1 90 Possum Point 3 (1981) 101 Possum Point 4

214 Total 1,639 After another 598 Mw of capacity are converted by the end of 1983, our coal conversions will displace about 20 million barrels of oil consumption each year.

Vepco's use of oil as a major fuel dates back to the 1960s and early 1970s. At that time, oil was less ex-pensive than coal and had less effect on the environment. The Company was able to save its customers money by taking advantage of this fuel which was available mostly to utilities with generating stations on navigable wa-ters.

However, the OPEC oil embargo of 1973 reversed the price relationship between coal and oil, thus making conversion of certain units economi-cally justifiable. Since that time, the cost differential has continued to in-crease and environmental require-ments have been better defined and Vepco is now converting all of its units that are capable of burning coal and not close to retirement.

Installation of electrostatic precipi-tators, or dust collection devices, to meet new air pollution standards is the major cause of coal conversion ex-pense and delays. The design, pro-curement and installation of a new precipitator takes about three years.

Increasing the collection efficiency from the previously-required 80% to the 99% now required significantly in-creases costs.

Nuclear Insurance Pool In recognition of the severe financial impact of the accident at Three Mile Island, nuclear utilities across the country, including Vepco, have formed an insurance company to protect the companies and their customers from the financial impact of purchasing re-placement power following the loss of a nuclear unit from an accident.

The insurance company, Nuclear Electric Insurance Limited (NEIL), is owned by the utilities and each partici-pating company is represented on its board of directors. NEIL was formed because the coverage it provides is not available from existing commercial insurers.

Participating companies are eligible for replacement power benefits from NEIL after 26 weeks following an acci-dent. A substantial portion of replace-ment power costs are covered for two years.

Finance The most significant aspect of the 1980 financing program was the crea-tion of the Bath County Hydroelectric Trust to finance the completion of the Bath County Pumped Storage Project.

The Trust was structured as a financ-ing vehicle for Vepco and Allegheny Power System. The Trust has issued

$201.8 million of short-term notes, guaranteed by the Company, to fi-nance Vepco's 1980 expenditures on the project. Fourteen foreign banks and one U.S. bank participated in the financing by providing credit support to the notes of the Trust.

We continued to utilize the inter-mediate term market in 1980 by plac-ing notes totaling $85 million with three foreign and four domestic lenders.

A summary of the $480.9 million in financings in 1980 is given in the fol-lowing table.

Millions of Dollars First and Refunding Mortgage Bonds of 1980,Series A, 12 'h%,

Due July 1, 2000

$ 75.0 Bath County Hydroelectric Trust 201.8 Pollution Control Note

• 40.0 Common Stock Public Offering

$54.0 Automatic Dividend Rein-vestment Plan 16.4 Employee Savings Plan 6.2 Installments received through Customer Stock Purchase Plan Intermediate Term Loans Total 2.5 79.1 85.0

$480.9

• The Company through an Industrial De-velopment Authority is financing the con-struction o.f tour electrostatic precipi-tators. Funds will be requisitioned as they are spent.

Customer Relations We continued during the past year to look for ways to improve our custom-ers' understanding of our policies and operations. Two programs were un-dertaken to meet this objective.

To provide a new forum for custom-ers to express their views on Company operations, we began to establish 12 At Chesterfield Power Station, entire r cars of coal are dumped automatically intc hopper that leads to conveyor belt for stockpi/i,

Customer Advisory Boards in each of our five divisions. The tfoard members are appointed from a list of candidates nominated by legislators, other gov-ernment officials, educators, con-sumer groups, church groups and leaders in business and industry. Rep-resentatives of the Company do not serve on the boards.

We also implemented what we be-lieve to be the first and most success-ful Customer Stock Purchase Plan of any utility in the nation. About 14,000 customers enrolled during 1980 and the volume of customer inquiries leads us to expect an even larger response to a 1981 offer we plan to make.

The plan enables our customers to acquire stock in the Company without paying brokerage fees or commis-sions. Participants contribute a fixed monthly installment they elect at the time they enroll in the 12-month plan.

The minimum monthly contribution is

$10. Participants receive 8% interest on their contributions, and pay any ad-ministrative expenses that exceed 4%

of the value of the stock issued. We expect under this plan to issue ap-proximately $6.3 million of our com-mon stock in September 1981.

In addition to these new programs, other proven customer and community relations programs continued to oper-ate effectively in 1980. Our Speakers' Bureau, composed of knowledgeable employees from all departments in the Company, spoke to 1,832 groups dur-ing 1980 to present the Company's views and respond to customer ques-tions. Approximately 20,000 students, teachers and interested citizens vis-ited our information centers at the Bath County and North Anna construc-tion sites.

Our operating districts compete through the President's Customer Re-lations Award Program to achieve the best customer relations record during the year. Competition is conducted in such areas as customer complaints and reductions in meter reading er-rors.

Investor Relations The Company undertook an important initiative last year to strengthen its relationship with professional financial analysts who influence investor atti-tudes toward our securities.

A manager of investor relations was appointed June 1 to maintain a steady flow of information on corporate per-formance to these analysts. The new manager responds daily to questions about the Company from investment professionals, arranges meetings be-tween financial analysts and senior management, distributes a compre-hensive five-year financial profile and prepares and distributes a monthly fi-nancial newsletter, Recent Events.

Stockholders END OF YEAR Geographic Distribution Preferred and Common Stock Owners Shares Preference Stocks Owners Shares Virginia 41,101 17,658,195 Virginia.......................

7,254 725,130 New York...................

15,934 35,639,411 North Carolina.................

2,177 468,496 Florida.......................

15,561 5,163,057 Florida............................

1,971 295,127 California.........

11,294 5,170,346 New York......... **...* *..*. *...

1,469 2,576,939 North Carolina............

9,007 2,993,134 California...........

1,117 253,728 Maryland...................

8,298 2,223,157 Maryland..........

1,022 166,842 Illinois...................

8,173 2,791,186 South Carolina................

796 155,838 New Jersey.........

7,257 4,149,177 Illinois....

763 484,945 Ohio 5,932 1,889,336 New Jersey........

689 1,252,498 Massachusetts...

5,658 2,684,983 Ohio.................... **...*...

659 102,253 Michigan............

5,298 1,478,923 West Virginia..

498 41,885 Texas..

4,516 1,944,304 Pennsylvania..

496 205,185 Pennsylvania.....

4,305 1,622,180 Texas...

487 105,450 Connecticut...............

3,369 1,659,050 Michigan.....

442 60,189 South Carolina...

2,638 844,425 Massachusetts....

380 105,762 Wisconsin 2,588 657,560 Missouri 346 106,554 Missouri.....................

2,576 967,500 District of Columbia..........

322 48,063 Tennessee.................

2,186 814,542 Georgia..........

308 79,666 West Virginia..............

2,113 665,846 Arizona..................

239 36,444 19 States...................

157,804 91,016,312 18 States and D.C.

21,435 7,270,g94 31 Other States, 32 Other States D. C. and 40 and 9 Foreign Foreign Countries 25,128 8,937,845 Countries 2,437 1,328,084 TOTALS......

182,932 99,954,1 57 TOTALS....

23,872 8,599,078 Distribution of Ownership Preferred and Common Stock Owners Shares Preference Stocks Owners Shares Women..

54,035 14,272,861 Women..............

8,120 785,002 Men...

53,049 16,789,100 Men................................

6,198 800,204 Joint Accounts...........

50,964 13,470,728 Joint Accounts.................

5,194 615,464 Trust Accounts...........

20,224 4,339,561 Trust Accounts................

1,931 220,590 Nominees...................

1,271 36,891,781 Nominees....................

669 2,105,573 Institutions and Institutions and Foundations...........

460 647,930 Foundations...........

141 1,571,434 Brokers and Brokers and Security Dealers.....

98 5,278,693 Security Dealers..........

82 38,024 Others..................

2,831 8,263,503 Others.............

1,537 2,462,787 TOTALS...............

182,932 99,954,157 TOTALS..................

23,872 8,599,078 14 Huge steel linings for the giant tunnels t will carry water from upper to lower reservo at Bath County Proje

Description of Business The electric business of the Company is conducted in most of Virginia and in parts of North Carolina and West Virginia. In its service area it sells electricity to retail customers (including gov-ernmental agencies), and at wholesale to rural electric coopera-Selected Financial Data Operating revenues...........................................................

Operating income.............................................................

Balance for common stock................................................

Earnings per share of common stock.................................

Dividends paid per share of common stock........................

Total assets......................................................................

Net utility plant..................................................................

Long-term debt and preferred stock subject to mandatory redemption...................................

tives and municipalities. Gas service is provided only in the Nor-folk-Newport News area (except Portsmouth) and in the area ex-tending from Newport News to and including Williamsburg.

Millions of Dollars (except per share amounts) 1980 1979 1978 1977 1976

$2,120

$1,703

$1,465

$1,359

$1,104 390 316 305 265 241 184 141 150 142 123 1.93 1.63 1.88 1.92 1.80 1.40 1.38 1.30 1.24 1.221h 6,491 5,961 5,211 4,802 4,315 5,586 5,229 4,686 4,305 3,909 3,216 2,941 2,681 2,407 2,144 Management's Discussion and Analysis of Financial Condition and Results of Operations LIQUIDITY. Since the Arab oil embargo in 1974, the Company has experienced deficiencies in its internal cash generation. Most recently these deficiencies have resulted from substantial increases ih the use of fossil fuels and re-placement power for unanticipated nuclear unit outages and for the steam generator repairs to Surry Nuclear Units 1 and 2 and from delays in obtaining recovery of these in-creased costs in rates.

As a result of several reductions in projected load growth, together with escalating construction costs, fi-nancing constraints upon the Company and regulatory constraints upon nuclear power, the Company has during the past six years, canceled three nuclear units and de-ferred in-service dates for one other nuclear unit and six pumped storage units. In spite of the cancellations and de-ferments, construction expenditures during this period have required substantial sales of securities.

Allowance for Funds Used During Construction (AFC),

non-cash income included in the accounts in accordance with the regulatory Uniform Systems of Accounts, has been increasing in recent years and now represents a sub-stantial portion of net income. At the same time, deprecia-tion charges, a non-cash expense which includes depreci-ation of previously capitalized AFC, have exceeded AFC credits in each year. As a result of the above and other non-cash charges, funds provided by operations have ex-ceeded net income for each of the years 1976 through 1980 (see Statements of Changes in Financial Position).

Internal cash generation during 1981 will be affected not only by the availability of the Company's nuclear gen-erating units and the cost of fossil fuel or replacement power, but also by the level of capital expenditures, the cost of funds to the Company to finance those ex-penditures, the outcome of rate proceedings and the pos-sible consummation of plans to sell a portion of the Bath County Pumped Storage Project (see Capital Resources

. below).

Liquidity for electric utilities like the Company, who have large amounts committed for construction projects, depends to a great extent on the ability to obtain outside funds, since charges to present customers are not de-18 sigried to fund construction costs for future generating ca-pacity. The Company has unsuccessfully sought to include the cost of financing in customer charges from the Virginia Commission and substantially reduce the accrual of AFC.

The Company expects to continue in similar efforts, but for the foreseeable future, liquidity will be maintained by the ability to obtain outside funds.

CAPITAL RESOURCES. The 1981 capital requirements result principally from the estimated $643 million of capital expenditures and $124.3 million of refunding and manda-tory cash -sinking fund obligations of long-term debt and Preferred Stock. The Company presently expects that 35% to 40% of these requirements will be obtained from internal sources, about 35%-40% from the sale of a por-tion of the Bath County Pumped Storage Project (dis-cussed below) and the remainder will be financed through sales of securities of various types, with the long-term ob-jective of achieving and maintaining capitalization ratios in the range of 52% long-term debt, 13% Preferred and Pref-erence Stock and 35% Common Equity.

Capital expenditures are generally financed initially by sales of commercial paper. To support these borrowings the Company has available bank lines of credit amounting to $391 million. See Note J to Financial Statements as to lines of credit and the amounts and costs of such borrow-ings in 1980.

Commercial paper is refunded by means of the sales of intermediate and long-term debt and equity securities, but an earnings limitation of the Mortgage would permit the is-suance at December 31, 1980 of $511 million of addi-tional Bonds assuming an interest rate of 15% for addi-tional Bonds. Another earnings limitation would permit no additional shares of Preferred Stock to be issued.

The construction program and related expenditures and financing can continue to change as a result of, among other factors, higher than anticipated inflation, additional regulatory and environmental costs, further changes in the rate of growth in peak demand, licensing and construction delays, results of rate proceedings and the possible con-sumation of sales of certain facilities.

The Company has been continuing negotiations for a sale for cash of some portion of its nuclear facilities in service and under construction with Cooperative custom-ers. It cannot be predicted at this time whether ultimate agreement can be reached or the terms upon which such an agreement might be reached or whether necessary reg-ulatory approvals could be obtained.

The Company is continuing negotiations on the details of a contract with Allegheny Power System, Inc. for the sale of a 40% interest (which may be increased to 50%

prior to 1985) in the Bath County Pumped Storage Project and associated transmission facilities ($631 million in-vested through December 31, 1980). If agreement is reached and regulatory and other approvals are received (there can be no assurance of either), the Company could receive about $260 million of cash in 1981.

RESULTS OF OPERATIONS. Due to the effects of infla-tion, delays in obtaining a nuclear unit license, unsched-uled outages of nuclear and coal fired units, rapidly esca-lating costs of oil, major maintenance and repairs at most of the fossil units, increased depreciation and mainte-nance associated with additional power station units placed in service and increased cQsts of capital and capi-tal expenditures, expenses have risen substantially during the past several years, and as a result, the Company has been granted substantial rate increases during these years. Since the receipt of rate increases has lagged in-creases in expenses up to a year or more, Balance for Common Stock has fluctuated since 1973. An increase of

34. 7 million average shares of Common Stock since 1975 has caused 1980 earnings per share of Common Stock to decline from its 1976 level despite the increase in Balance for Common Stock from 1976 to 1980.

Electric revenues increased from 1978 through 1980 prin-cipally as a result of the following:

Rate increases and fuel cost recovery...

Unit sales (excluding effect of above)....

Other, net............................................

Total....................................................

Revenues Increase From Prior Year (Millions of Dollars) 1980

$321.2 76.8 3.6

$401.6 1979

$215.3 14.8 4.0

$234.1 Gas revenues represent about 3.3% of total revenues.

With the Company again permitted to connect new gas customers, substantial numbers of residential and signifi-cant industrial customers have been added. As a result of increased sales to customers and deregulation of natural gas pricing, which will be passed on to the consumers through the purchased gas adjustment clause, gas reve-nues should rise substantially in the future but not to a level that would be significant compared to electric opera-tions.

Fuel and purchased and interchanged power expenses have fluctuated from 1978 through 1980 as a result of changes in fuel costs (see Notes A and F to Financial Statements), increased sales and the availability of coal-fired generation purchased from neighboring ultilities at a cost less than the Company's oil-fired generation during unscheduled outages of the Company's nuclear and coal 19 units. The average cost of fuel consumed per kilowatt-hour generated is shown below:

Mills Per Kilowatt-hour 1980 1979 1978 Nuclear................................

8.09*

Coal-Mt. Storm (mine-mouth)17.16

-Other........................ 20.36 Oil....................................... 44.73 Total system........................ 21. 76 5.27 13.80 20.61 31.45 20.44 5.18*

13.48 18.68 21.67 14.04

• Includes generation at North Anna Unit 2 (1980) and Unit 1 (1978) priced at the cost of displaced fuel during preliminary operations. Actual costs were 6.19 (1980) and 4.63 (1978) mills per kilowatt-hour.

Kilowatt-hour output by energy source is shown below:

1980 1979 1978 Nuclear................................

27%

17%

35%

Coal-Mt. Storm (mine-mouth).............

13 17 17

-Other........................

12 10 7

Oil.......................................

19 33 37 Purchased and interchanged 27 19 Other...................................

2 4

4 100%

100%

100%

The Company plans to convert most of its oil-fired gen-eration to coal by the end of 1983. After the conversions only 1604 Mw or about 16% of present total net summer generating capability will remain oil-fired excluding 4 7 4 Mw that will have been placed in a non-operating cold re-serve status and 439 Mw of combustion turbines.

Maintenance and depreciation expenses have in-creased since 1978 principally as a result of the addition of North Anna Unit 1 in mid 1978 and will increase in 1981 with the addition of North Anna Unit 2 in De.camber 1980.

For information with respect to changes in depreciation rates see Note G to Financial Statements.

For information with respect to Federal income and other taxes see Notes C and E to Financial Statements.

Continuation of the Company's capital expenditures and the related financing together with increases in con-struction and nuclear fuel costs and changes in internally generated funds and costs of capital have resulted in in-creases in the amounts of interest charges, preferred and preference dividends and AFC.

INFLATION. From the mid 1940's until the early 1970's customer demand increased so rapidly that the cost per kilowatt-hour to the customer declined. With the persistent high rates of inflation and rapid rises in oil costs during the 1970's, and significant decrease in the rate of growth of demand, the Company has required substantial amounts of rate relief including increases in fuel cost recovery bill-ings.

For a capital intensive electric utility, inflation increases the cost of materials and labor in not only operating ex-penses but also the construction program at a time when inflation and the fiscal and monetary policies of the Fed-eral government have resulted in record high costs of capi-tal. Also to a great extent, operating and construction costs have been affected by the tremendous growth in reg-ulation in recent years, particularly at the Federal level.

An estimate of the effect of inflation measured by con-stant dollar accounting and current cost accounting for se-lected financial data is presented in Note P to Financial Statements.

• .,a ___ ~----

~

Report of Management The management of Virginia Electric and Power Company is responsible for all information and representations con-tained in the financial statements and other sections of the annual report. The financial statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the annual report is consistent with that in the financial statements.

Management maintains a system of internal accounting control designed to provide reasonable assurance at a rea-sonable 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. This system includes written poli-cies, an organizational structure designed to ensure appropriate division of responsibilities, careful selection and train-ing of qualified personnel and a program of internal audits.

The financial statements have been examined by Coopers & Lybrand, independent certified public accountants. Their examination is conducted in accordance with generally accepted auditing standards and includes a review of the Com-pany's accounting systems, procedures and internal controls, and the performance of tests and other auditing proce-dures sufficient to provide reasonable assurance that the financial statements neither are materially misleading nor con-tain 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 executive manager-internal auditing and management to discuss auditing, internal accounting control and financial reporting matters and to ensure that each is properly dis-charging its responsibilities. Both the independent auditors and the executive manager-internal auditing periodically meet alone with the Audit Committee and have free access to the Committee at any time.

VIRGINIA ELECTRIC AND POWER COMPANY

-- -*-----*------- --- ------ - - -- - ---- --- ----------*------------------~

\\

Report of Independent Certified Public Accountants To the Stockholders and Board of Directors of Virginia Electric and Power Company:

We have examined the balance sheets of Virginia Electric and Power Company as of December 31, 1980 and 1979, and the related statements of income, earnings reinvested in business and changes in financial position for each of the five years in the period ended December 31, 1980. Our examinations were made in accordance with generally accepted auditing standards and, accordingly, included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

In our report dated February 6, 1980, our opinion was qualified as being subject to the effects on the 1979 financial statements of such adjustments as might have been required had it been known what part of deferred costs associated with purchased and interchanged power, if any, would not be recoverable either through fuel cost recovery procedures or in base rates. As discussed in Note B to Financial Statements, the Virginia State Corporation Commission has issued a rate order permitting recovery of these deferred costs in base rates. Accordingly, our present opinion on the 1979 finan-cial statements, as presented herein, is no longer qualified.

In our opinion, the financial statements referred to above present fairly the financial position of Virginia Electric and Power Company as of December 31, 1980 and 1979, and the results of its operations and the changes in its financial position for each of the five years in the period ended December 31, 1980, in conformity with generally accepted ac-counting principles applied on a consistent basis.

New York, New York February 4, 1981 20 COOPERS & LYBRAND

Virginia Electric and Power Company Statements of Income Operating revenues (Notes A and L)

Electric.....................................................................

Gas..........................................................................

Total.................................................................

Operating expenses:

Operation:

Fuel used in eiectric generation (Notes A, Band F).......................................................

Purchased and interchanged power (Note B)..........

Other (Note F).......................................................

Maintenance (Note A)................................................

Depreciation (Notes A and G)....................................

Amortization of abandoned project costs (Note D)................................................................

Taxes-Federal income (Notes A and C)...................

--Other (Note E).............................................

Total.................................................................

Operating income.............................................................

Other income:

Allowance for other funds used during construction (Note A)............................................

Allowance for funds used during construction (Note A)............................................

Miscellaneous, net...................*................................

Income taxes associated with miscellaneous, net.......

Total.................................................................

Income before interest charges.........................................

Interest charges:

Interest on long-term debt.........................................

Other........................................................................

Allowance for borrowed funds used during construction (Note A)............................................

Total.................................................................

Net income.......................................................................

Preferred and preference dividends...................................

Balance for common stock................................................

Shares of common stock-average for year (thousands)....

Earnings per share of common stock.................................

Cash dividends paid per common share.............................

) Denotes red figure.

1980

$2,049,518 70,256 2,119,774 674,996 341,011 250,848 123,962 145,032 6,933 70,004 117,456 1,730,242 389,532 73,206 2,973 (550) 75,629 465,161 234,561 28,530 (39,550) 223,541 241,620 57,291

$ 184,329 95,520

$1.93

$1.40 The accompanying notes are an integral part of the financial statements.

21 Years 1979 1978 1977 1976 (Thousands of Dollars)

$1,647,928

$1,413,866

$1,313,937

$1,060,663 55,381 51,039 44,923 43,413 1,703,309 1,464,905 1,358,860 1,104,076 559,998 585,625 575,151 446,984 194,547 9,384 52,273 15,747 210,840 183,906 153,514 131,485 103,856 90,317 69,885 53,749 136,280 117,481 98,527 95,191 7,292 6,760 3,173 69,744 72,658 59,736 48,751 104,358 93,499 81,174 71,413 1,386,915 1,159,630 1,093,433 863,320 316,394 305,275 265,427 240,756 66,603 64,002 72,361 80,429 1,282 2,209 (305) 283 (308)

(867)

(358) 208 67,577 65,344 71,698 80,920 383,971 370,619 337,125 321,676 204,392 184,947 168,885 147,481 12,417 6,677 5,748 7,409 (29,305)

(24,869)

(27,301) 187,504 166,755 147,332 154,890 196,467 203,864 189,793 166,786 55,123 53,588 47,719 43,821

$ 141,344 150,276

$ 142,074

$ 122,965 86,965 80,060 74,025 68,137

$1.63

$1.88

$1.92

$1.80

$1.38

$1.30

$1.24

$1.221h

Virginia Electric and Power Company Balance Sheets Assets December 31, December 31, 1980 1979 (Thousands of Dollars)

UTILITY PLANT (Note A):

Electric.........................................................................

$6,445,405

$5,960,549 Gas..............................................................................

66,289 62,130 Common.......................................................................

16,892 14,293 Total (includes $1,451,292,000 plant under construction [1979-$1, 731,012,000]).

6,528,586 6,036,972 Less accumulated depreciation (Note G)....................

1,118,308 999,990 5,410,278 5,036,982 Nuclear fuel (less accumulated amortization of

$131,321,000 [1979---$79, 151,000]) **********************

176,187 191,521 Net utility plant...........................................

5,586,465 5,228,503 INVESTMENTS:

Nonutility property at cost or written-down amounts (less allowance of $7,575,000)....................

6,327 5,150 Subsidiary companies at equity (includes advances of $13,659,000 [1979---$15, 789,000]) (Notes A and N)......................................................................

19,851 20,223 Net investments.........................................

26,178 25,373 CURRENT ASSETS:

Cash (Note J)................................................................

6,261 4,868 Temporary cash investments.........................................

8,500 Accounts receivable:

Customers................................................................

$181,745

$156,378 Uranium settlement (Note N)......................................

41,000 Other................................................... '.....................

7,128 6,912 188,873 204,290 Less allowance for doubtful accounts.........

1,360 187,513 2,038 202,252 Accrued unbilled revenues............................................

83,123 93,802 Materials and supplies at average cost or less:

Plant and general (including construction ma-terials)..................................................................

55,515 40,301 Fossil fuel.................................................................

130,203 185,718 131,370 171,671 Prepayments:

Taxes.......................................................................

32,959 31,615 Other........................................................................

11,806 44,765 4,713 36,328 I

Total current assets...................................

515,880 508,921 DEFERRED DEBITS:

Unamortized abandoned project costs (less ac-cumulated amortization of $24, 158,000 [1979-

$17,225,000]) (Note 0).............................................

172,720 56,322 Deferred fuel costs (Notes A and 8)...............................

78,104 89,250 Pollution control project funds.......................................

45,570 7,836 Unamortized expense on debt.......................................

8,754 8,009 Other............................................................................

57,793 36,370 Total deferred debits..................................

362,941 197,787

$6,491,464

$5,960,584 The accompanying notes are an integral part of the financial statements.

22

Capital and Liabilities PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-

$1 00 par, cumulative (Note H)..................................................................

PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION-

$100 par, cumulative (Note I)....................................................................

PREFERENCE STOCK NOT SUBJECT TO MANDATORY REDEMPTION-no par, cumulative; authorized 30,000,000 shares (Note I)....................................

COMMON STOCKHOLDERS' EQUITY (Note I):

Common stock-no par....................................................................................

Other paid-in capital.........................................................................................

Earnings reinvested in business, as annexed.....................................................

Total common stockholders' equity...................................................

LONG-TERM DEBT (Note K).................................................................................

CURRENT LIABILITIES:

Securities due within one year (Notes H and K)..................................................

Loans payable, pending permanent financing (Note J).......................................

Accounts payable, trade...................................................................................

Customer deposits...........................................................................................

Payrolls accrued *..............................................................................................

Taxes accrued.................................................................................................

Interest accrued..................................... :.........................................................

Deferred income taxes (Notes A and C).............................................................

Other................ :.-.............................................................................................

Total current liabilities......................................................................

DEFERRED CREDITS:

Uranium settlement (Note N).............................................................................

Accumulated deferred income taxes (Notes A and C):

Liberalized depreciation...............................................................................

Abandoned project costs..............................................................................

Accelerated amortization..............................................................................

Other...........................................................................................................

Deferred investment tax credits (Notes A and C)................................................

Other (Note F)..................................................................................................

Total deferred credits.......................................................................

COMMITMENTS AND CONTINGENCIES (Note N) 23 December 31, 1980 (Thousands

$ 328,911 289,014 57,360 1,400,874 25,352 435,430 1,861,656 2,887,114 124,276 83,721 111,674 11,884 13,498 53,606 76,501 14,856 60,797 550,813 142,172 149,867 63,514 10,036 16,004 106,808 28,195 516,596

$6,491,464 December 31, 1979 of Dollars)

$ 330,894 289,014 57,360 1,319,303 27,859 384,600 1,731,762 2,610,308 62,093 131,730 127,684 12,004 11,365 25,764 69,284 17,316 40,683 497,923 130,346 108,758 24,931 11,583 39,528 100,181 27,996 443,323

$5,960,584

Virginia Electric and Power Company Statements of Earnings Reinvested in Business 1980 Balance at beginning of year.............................................

$384,600 Net income (see "Statements of Income").........................

241,620 Total.................................................................

626,220 Cash dividends:

Preferred stock subject to mandatory redemption:

$7.325 preferred......................................................

5,128

$8.40 preferred........................................................

6,720

$9.125 preferred......................................................

1,825

$8.20 preferred........................................................

4,920

$8.60 preferred........................................................

3,189

$8.625 preferred......................................................

3,191

$8.925 preferred......................................................

2,499 Preferred stock not subject to mandatory redemption:

$5.00 preferred........................................................

533

$4.04 preferred........................................................

52

$4.20 preferred........................................................

62

$4. 1 2 preferred........................................................

134

$4.80 preferred........................................................

351

$7.72 preferred........................................................

2,702

$8.84 preferred........................................................

3,094

$7.45 preferred........................................................

2,980

$7.20 preferred........................................................

3,240

$7. 72 preferred (1972 Series)...................................

3,860

$9. 75 preferred........................................................

5,850 Preference stock not subject to mandatory redemption:

$2.90 preference......................................................

6,960 Common stock..............................................................

133,005 Total dividends.............................................

190,295 Transfer to common stock as authorized by Board of Directors.........................................................

Other deductions, net........................................................

495 Total.............................................................

495 Balance at end of year.......................................................

$435,430 The accompanying notes are an integral part of the financial statements.

24 1979

$364,215 196,467 560,682 5,128 6,720 1,825 4,920 3,291 3,191 153 533 52 62 134 351 2,702 3,094 2,980 3,240 3,860 5,850 6,960 120,638 175,684 398 398

$384,600 Years 1978 1977 1976 (Thousands of Dollars)

$318,507

$328,115

$290,260 203,864 189,793 166,786 522,371 517,908 457,046 5,128 5,128 5,128 6,720 6,720 6,720 1,825 1,825 345 4,920 1,134 3,392 1,785 533 1,447 1,447 52 404 404 62 420 420 134 515 515 351 1,440 1,440 2,702 2,702 2,702 3,094 3,094 3,094 2,980 2,980 2,980 3,240 3,240 3,240 3,860 3,860 3,860 5,850 5,850 4,566 6,960 6,960 6,960 103,474 91,225 82,923 157,062 138,944 126,744 60,000 1,094 457 2,187 1,094 60,457 2,187

$364,215

$318,507

$328,115

Virginia Electric and Power Company Stafements of Changes in Financial Position Years 1980 1979 1978 1977 1976 (Thousands of Dollars)

SOURCE OF FUNDS:

Funds provided by operations:

Net income.................................................................... $241,620

$196,467

$203,864

$189,793

$166,786 Items not affecting working capital:

Provision for depreciation (Notes A and G).................

145,032 136,280 117,481 98,527 95,191 Amortization of nuclear fuel (Note A)..........................

52,170 25,576 29,702 14,526 8,962 Amortization of abandoned project costs (Note D).......

6,933 7,292 6,760 3,173 Allowance for other funds used during construction (Note A).............................................

(73,206)

(66,603)

(64,002)

(72,361)

Allowance for borrowed funds used during construction (Note A).............................................

(39,550)

(29,305)

(24,869)

(27,301)

Allowance for funds used during construction (Note A)................................................................

(80,429)

Deferred income taxes (Notes A and C)......................

52,177 66,545 14,668 31,536 14,002 Deferred investment tax credits, net (Notes A and C).....................................................

6,627 (5,250) 34,827 19,009 32,540 Total funds provided by operations.....................

391,803 331,002 318,431 256,902 237,052 Funds provided by financing and other sources:

Mortgage bonds (Note K)...............................................

75,000 235,000 213,000 150,000 220,000 Preferred stock subject to mandatory redemption (Note H)....................................................................

28,000 37,000 60,000 20,000 Preferred stock not subject to mandatory redemption (Note 1)......................................................................

60,000 Common stock (Note I):

Public offering...........................................................

53,950 64,050 68,275 70,400 73,875 Automatic dividend reinvestment plan........................

16,379 12,926 11,690 9,229 7,727 Employee savings plan and TRASOP..........................

6,261 7,222 4,774 4,213 3,900 Customer stock purchase plan subscriptions..............

2,474 Bath County hydroelectric trust (Note K).........................

201,810 Term notes (Note K)......................................................

125,000 60,000 104,750 108,500 25,000 Increase (decrease) in loans payable..............................

(48,009) 128,293 (49,613) 26,550 (83,550)

Uranium settlement (Note N)..........................................

11,826 130,346 Total funds provided by financing and other sources................................................

444,691 665,837 389,876 428,892 326,952

$836,494

$996,839

$708,307

$685,794

$564,004 APPLICATION OF FUNDS:

Utility plant expenditures (excluding AFC).......................... $536,049

$551,881

$422,857

$394,875

$343,693 Nuclear fuel (excluding AFC)..............................................

32,315 60,967 17,458 74,531 57,479 Abandoned project costs (Note D)......................................

1,332 (2,542) 2,631 16,050 Pollution control project funds............................................

37,734 (3,914) 8,019 721 1,227 Dividends on common, preferred and preference stocks.....

190,295 175,684 157,062 138,944 126,744 Increase (decrease) in deferred fuel costs (Notes A and B).............................................................

(11,146) 85,867 (29,898)

(18,812) 8,427 Securities reacquired or repaid..........................................

65,300 74,883 97,273 58,250 10,000 Increase (decrease) in investment (net of repayment of advances) in subsidiary companies (Notes A and N)........

(372) 797 4,345 3,137 4,869 Increase (decrease) in working capital other than loans payable*.............................................................

(31,757) 42,136 36,551 14,684 10,968 Other, net..........................................................................

16,744 11,080 (7,991) 3,414 597

$836,494

$996,839

$708,307

$685,794

$564,004 Changes in the individual amounts comprising working capital other than loans payable* were as follows:

Accounts receivable (excluding uranium settlement)........ $ 26,261

$ 33,197

$ 20,312 2,103

$ 13,017 Uranium settlement (Note N)...........................................

(41,000) 41,000 Accrued unbilled revenues.............................................

(10,679) 32,395 (2,523) 4,965 19,386 Deferred fuel surcharge.................................................

(11,028) 628 (1,670)

Materials and supplies...................................................

14,047 42,675 7,284 26,392 17,080 Accounts payable, trade.................................................

16,010 (73,271) 19,350 1,775 (32,963)

Taxes accrued...............................................................

(27,843) 8,027 (20,426)

(4,842) 666 Interest accrued............................................................

(7,217)

(4,633)

(11,388)

(6,916)

(7,177)

Deferred income taxes (Notes A and C)...........................

2,460 1,464 4,657 (2,537)

(577)

Other, net......................................................................

(3,796)

(38,718) 30,313 (6,884) 3,206

$(31,757)

$ 42,136

$ 36,551

$ 14,684

$ 10,968

• Does not include reclassification as current liabilities of maturing long-term debt and cash sinking fund obligations of debt and preferred stock as follows: 1980-$124,276,000; 1979--$62,093,000; 1978-$75,293,000; 1977--$89,433,000 and 1976--$58,250,000.

The accompanying notes are an integral part of the financial statements. 25

Notes to Financial Statements A. Significant Accounting Policies:

General:

The Company's accounting practices are prescribed by the Uniform System of Accounts promulgated by the regula-tory commissions having jurisdiction.

Revenues:

Operating revenues are recorded on the basis of service rendered.

Utility Plant and Depreciation:

Utility plant is recorded at original cost which includes la-bor, materials, services, allowance for funds used during construction and other indirect costs. The cost of depre-ciable utility plant retired and cost of removal, less salvage, are charged to accumulated depreciation.

The cost of maintenance and repairs is charged to the appropriate operating expense and clearing accounts. The cost of renewals and betterments is charged to the appro-priate utility plant account, except the cost of minor re-placements which is charged to maintenance expense.

Provisions for depreciation, which include amounts applicable to estimated decommissioning costs of

$30,000,000 for nuclear units in service (assuming moth-balling in pairs), are recorded on the straight-line method based upon estimated service lives.

Nuclear Fuel:

Progress payments are being made for fuel to be owned or leased.

Amortization of owned nuclear fuel is provided on a unit of production basis sufficient to amortize the cost over the estimated service life. Before 1978, the Company provided for estimated reprocessing costs relating to fuel, which was being burned, for all jurisdictions. Effective in 1978, the North Carolina Commission granted approval to recover the cost of permanent storage of spent fuel in base rates and the Federal Energy Regulatory Commission (FERC) allowed the recovery of these costs through the fuel clause. For pe-riods subsequent to these two decisions, operating ex-penses include reprocessing costs for Virginia jurisdictional customers and costs of permanent storage for North Caro-lina and FERC jurisdictional customers.

Subsidiaries:

The Company has two wholly-owned subsidiaries. Laurel Run Mining Company is engaged in the underground mining of coal, which is utilized solely by the Company. Virginia Nu-clear, Inc. was organized to explore for uranium reserves; however, no such activities are presently being conducted.

Federal Income Taxes:

The Company's practice is to reduce the current provi-sion for Federal income taxes to reflect the tax benefit re-sulting from the use of the double-declining-balance method of depreciation for property additions and the adop-tion of the Asset Depreciation Range and Class Life Sys-tems. Effective with property additions placed in service in 197 4, the Company has provided deferred income taxes on the aforementioned benefit and, subsequently, has pro-vided deferred taxes on other differences between book in-come and income taxable for Federal income taxes to the extent permitted by the regulatory commissions having ju-risdiction.

Investment Tax Credits:

Accumulated investment tax credits at July 1, 1970 are being amortized over a ten-year period, and credits re-corded after that date are being amortized over the service lives of the property giving rise to such credits. An addi-tional investment tax credit of 1 % related to the Tax Reduc-tion Act Stock Ownership Plan (TRASOP) does not affect net income and is recorded as a liability until the contribu-tion is made to the TRASOP trust.

Allowance for Funds Used During Construction:

The applicable regulatory Uniform Systems of Accounts defines AFC as the net cost for the period of construction of borrowed funds used for construction purposes and a rea-sonable rate on other funds when so used.

In accordance with a change in FERC accounting rules effective January 1, 1977, the Company is separately de-termining rates and reporting amounts applicable to bor-rowed funds, calculated on a net of tax basis, and to equity funds.

In accordance therewith, for 1980, 1979, 1978 and 1977, aggregate rates of 7. 79%, 7.80%, 7.54% and

7. 75%, respectively, were employed for the accrual of AFC.

For 1976, AFC was accrued at 8% and reported in ac-cordance with the accounting rules then in effect. Since the assumptions as to source of construction funds, costs of such funds and capital ratios used by the Company prior to January 1, 1977, are not equivalent to those prescribed in the new accounting rules, the Company believes that retro-active reclassification of AFC accrued in 1976 would be in-*

appropriate. Assuming that funds used to finance construc-tion in 1976 were obtained, 35% from common equity, 52%

from debt and 13% from preferred and preference stocks, the common equity component of AFC as related to earn-ings available for common stock amounted to 17.4% for 1976.

For expenditures on the Bath County Pumped Storage Project after December 31, 1979, AFC is being accrued in an amount equal to the cost of borrowings associated with the Project Financing.

Deferred Fuel Costs:

The Company is deferring for accounting and rate-mak-ing purposes that portion of the cost of fuel consumed which, through the application of the annual fuel factor, may result in increased operating revenues in a later period.

26 Retirement Annuity Plan:

The Company has a contributory retirement annuity plan and funds pension costs accrued. Prior service cost arising out of amendments to the plan in 1976 and 1979, and changes in actuarial assumptions in 1977 is being provided in the accounts and funded on the basis of future salaries of participants currently covered by the plan.

Leases:

The Company's practice is to account for all leases as operating leases in accordance with the rate-making prac-tices presently in effect.

B. Deferred Fuel Accounting:

Monthly billings under the annual fuel factor which was approved by the Virginia Commission but subject to quar-terly hearings, include projected 1980 fuel costs, including net estimated fuel costs unrecovered at December 31, 1979. Projected 1981 fuel costs, including unrecovered costs at December 31, 1980, are to be considered by the Virginia Commission in hearings scheduled to begin March 13,1981.

In 1980, the Company deferred $39.6 million of costs as-sociated with purchased and interchanged power. Similar C. Federal Income Taxes:

Details of Federal income taxes were as follows:

Computed tax expense on book income before costs amounting to $21.5 million were deferred in 1979 and the Virginia Commission has issued a rate order permitting the recovery of 1979 costs in base rates beginning October 1980.

In the event that future developments dictate a change in the fuel adjustment billing lag period or in the fuel cost base, the Company will request regulatory approval to recover through billings to customers any unrecovered deferred fuel costs.

Years 1980 1979 1978 1977 1976 (Thousands of Dollars)

Federal income taxes at statutory rate....................... $143,600

$122,599

$133,147

$119,946 $103,358 (Decreases) increases resulting from:

Excess of tax over book depreciation not normalized.......................................................

AFC.....................................................................

Investment tax credits, amortization......................

Other, net............................................................

Federal income tax expense......................................... $

Currently payable......................................................... $

Tax effects of timing differences:

Abandoned project costs......................................

Fuel related items:

Current year.....................................................

Reprocessing/disposal costs on nuclear fuel....

Fuel expense-nuclear plant testing.................

Nuclear fuel-owned.......................................

Liberalized depreciation.......................................

Virginia gross receipts taxes.................................

Nuclear decommissioning costs............................

Spare parts inventory adjustment..........................

Accelerated amortization......................................

Indirect construction costs....................................

Cost of removal of property retirements.................

Contributions in aid of construction.......................

Other...................................................................

Investment tax credits...................................................

Investment tax credits, amortization..............................

Net deferred investment tax credits.......................

Federal income tax expense......................................... $

The Company has investment tax credit carry-forwards of $97,119,000, of which $12,464,000, $19,630,000 and (12,982)

(4,301)

(16,402)

(9,956)

(14,840)

(51,868)

(44,118)

(42,658)

(47,838)

(38,606)

(5,171)

(5,820)

(5,467)

(4,539)

(3,028)

(3,575) 1,384 4,038 2,123 1,867 (73,596)

(52,855)

(60,489)

(60,210)

(54,607) 70,004

$ 69,744

$ 72,658

$ 59,736 $ 48,7_51 11,200 8,449

$ 23,163 9,191 2,209 38,582 (4,421)

(1,822) 31,175 (19,087) 47,054 (21,681)

(9,588) 3,243 (7,988)

(8,067)

(6,791)

(6,385)

(4,076)

(3,663)

(2,669)

(4,452)

(487) 41,108 32,418 38,509 13,101 12,320 (2,460)

(1,464) 636 2,375 1,379 (764) 4,120 (1,547)

(1,547)

(1,547)

(1,547)

(1,547) 2,800 3,463 3,154 2,912 1,796 3,729 3,545 2,484 1,696 1,426 2,203 (2,203) 16 16 10 (539) 52,177 66,545 14,668 31,536 14,002 11,798 570 40,294 23,548 35,568 (5,171)

(5,820)

(5,467)

(4,539)

(3,028) 6,627 (5,250) 34,827 19,009 32,540 70,004

$ 69,744

$ 72,658

$ 59,736 $ 48,751

$65,025,000 will expire in 1985, 1986, and 1987, respec-tively.

27

D. Abandoned Project Costs:

In March 1977, the Company canceled Surry Units 3 and

4. At December 31, 1980, the Company had expended

$74.5 million, and additional cancellation costs could be as much as $34.6 million. The Company has been amortizing such costs, net of Federal income taxes, over a ten-year pe-riod as incurred. The Virginia, North Carolina and West Vir-ginia State Commissions have approved the recovery of these costs in base rates and an Administrative Law Judge has recommended approval of recovery from FERC cus-tomers.

In November 1980, following completion of a study which assessed the advantages and disadvantages associ-ated with both the continued construction of North Anna Units 3 and 4, as well as the replacement of those Units with alternative coal-fired facilities, the Company has decided to continue construction of Unit 3 on a schedule that would permit commercial operation in 1989. But Unit 4 was can-celed due primarily to reduced load growth projections, high financing costs, the uncertainty surrounding the regu-lation of nuclear power and the Company's load manage-ment programs which are estimated to result in a delay of additional generating capacity requirements. Expenditures at December 31, 1980 amounted to $122.4 million net of transfers of certain parts and equipment to other projects.

After additional costs which may be incurred, the loss is presently estimated to be in the range of $165 million. The Company will request rate relief to recover from customers, over a ten-year period, the actual loss resulting from the cancellation.

E. Supplementary Income Statement Information:

The amounts of royalties, advertising costs and research and development costs were not significant. Taxes other Taxes, other than Federal income taxes:

Real estate and property........................................

State and local gross receipts.................................

State income..........................................................

Other......................................................................

Total..............................................................................

F. Leases:

Rents charged to expenses consisted of the following:

Operating leases:

Nuclear fuel...........................................................

Combustion turbines..............................................

Other (principally buildings and teleprocessing equipment).........................................................

Total..............................................................................

In 1971, the Company sold and leased back 28 com-bustion turbines for a term of 20 years (plus two optional five-year renewal terms). Annual rental payments are

$3,674,000 for the remaining year of the first ten-year term and $6,444,000 during the second ten-year term. Addi-tional rentals are being accrued during the first ten years, when payments represent only interest, so that the annual effect on net income will be equalized over the twenty-year period. Deferred credits, other at December 31, 1980, in-clude $19,254,000 with regard to such accruals. Had the lease been capitalized, the net asset value and present value of the lease commitment would be $22,721,000 and

$42,601,000, respectively, at December 31, 1980 and

$24,851,000 and $42,601,000, respectively, at December 31, 1979.

The Company has heat supply contracts for the nuclear fuel for Surry Units 1 and 2 providing for an aggregate com-mitment of $110 million at December 31, 1980. Quarterly payments are charged to income in amounts sufficient to pay for the fuel burned during each quarter (excluding re-processing and permanent disposal costs) plus interest.

Had the contracts been capitalized, the net asset value and than Federal income taxes charged to expenses were as follows:

Years 28 1980 1979 1978 1977 1976 (Thousands of Dollars)

$ 29,182 $ 28,462

$26,333

$25,257

$22,899 71,838 60,934 54,865 49,812 42,382 162 57 505 248 215 16,274 14,905 11,796 5,857 5,917

$117,456 $104,358

$93,499

$81,174

$71,413 Years 1980 1979 1978 1977 1976 (Thousands of Dollars)

$21,140

$11,632

$35,491

$29,518

$21,447 5,524 5,611 5,694 5,935 6,185 11,206 10,583 8,427 6,648 5,552

$37,870

$27,826

$49,612

$42,101

$33,184 present value of these commitments would be $99,118,000 and $102,398,000, respectively, at December 31, 1980 and $103,395,000 and $106,162,000, respectively, at De-cember 31, 1979.

In 1974, the Company sold and leased back three office buildings for terms of twenty years (plus two optional five-year renewal terms). Annual rental payments are $730,000 during the initial terms of the leases. In 1978, the Company leased a newly constructed headquarters office building for a term of thirty years (plus four optional five-year renewal terms). Annual rental payments are $2,993,000 during the initial term of the lease. Had the leases been capitalized, the net asset value and present value of the lease commitments would be $37,087,000 and $40,106,000, respectively, at December 31, 1980 and $38,610,000 and $40,675,000, respectively, at December 31, 1979.

If the Company had capitalized the above noted leases and contracts, the increase in operating expenses for 1977 through 1 980 would not have been material.

The Company is responsible for expenses in connection with the leased turbines, nuclear fuel and buildings noted above, including insurance, taxes and maintenance.

G. Depreciation:

The provision for depreciation based on mean depre-ciable plant has been as follows:

1980 1979 1978 1977, 1976 Electric Gas Common 3.3%

3.3 3.2 3.1 3.1%

3.1 3.1 2.6 4.0%

4.4 2.4 2.3 With Virginia Commission approvals, the depreciation rates were increased for Gas plant as of January 1, 1978 and for Electric and Common plant as of April 1, 1979.

H. Preferred Stock Subject to Mandatory Redemption:

Preferred Stock Subject to Mandatory Redemption was represented by 3,308,938 shares outstanding at December 31, 1980, as follows:

Entitled Per Share Upon Voluntary Liquidation Redemption Dividend

$7.325 8.40 9.125 8.20 8.60 8.625 8.925 Total Authorized 700,000 800,000 200,000 600,000 358,938 370,000 280,000 3,308,938 Shares Less shares due within one year....

Balance.......................................

Outstanding 700,000 800,000 200,000(1) 600,000(2) 358,938(3,5) 370,000(4) 280,000(6) 3,308,938(7) 19,834(7) 3,289, 104(8)

Amount

$110.00 115.00 110.00 115.00 107.00 108.63 108.93 Through 3/31/83 3/31/84 9/19/81 9/20/87 12/20/87 6/20/83 9/20/84 And Thereafter To Amounts Declining In Steps To

$101.00 after 3/31 /88 100.00 after 3/31 /04 102.00 after 9/19/91 100.41 after 9/20/96 100.00 after 12/20/97 100.00 after 6/20/02 100.00 after 9/20/09 (1) Issued October 1976.

(2) Issued September 1977.

(3) Issued December 1977.

(4) 355,000 shares issued in May 1978 and 15,000 shares issued in September 1978.

(5) No voluntary redel']lption priqr to December 20, 1982.

(6) Issued November 1979.

(7) Sinking Fund requirements call for annual redemption at $100 per share as follows:

Series

$8.60 9.125 8.20 7.325 Percentage of Shares Issued 3%

4 5

4 Beginning Dec. 1978 Sept.1981 Sept.1983 April 1984 Ending Dec. 2010 Sept. 2000 Sept. 1996 April 2008 Series 8.625 8.925 8.40 Percentage of Shares Issued 5

3.75 4

Beginning June 1984 Sept. 1984 April 1985 Ending June 2002 Sept. 2009 April.2009 (8) Maturities through 1985 are as

$10,683,000; 1985-$13,883,000.

follows: 1981-$1,983,000; 1982-$1,983,000; 1983-$4,983,000; 1984-The total number of authorized shares for all Preferred Stock is 7,500,000 shares. Upon involuntary liquidation, all Preferred Stock shares are entitled to receive $100 per share plus accrued dividends. Dividends are cumulative and payable March 20, June 20, September 20 and De-cember 20.

I. Preferred and Preference Stock Not Subject to Mandatory Redemption, Common Stock and Other Paid-In Capital:

Preferred Stock, Not Subject to Mandatory Redemption:

Preferred Stock, that is not subject to mandatory redemption, was represented by 2,890,140 shares outstanding at December 31, 1980, as follows:

Entitled Per Share Upon Voluntary. Liquidation Redemption Authorized and Dividend

$5.00 4.04 4.20 4.12 4.80 7.72 8.84 7.45 7.20

7. 72(1972 Series) 9.75 Total (1) Issued March 1976.

Outstanding Shares 106,677 12,926 14,797 32,534 73,206 350,000 350,000 400,000 450,000 500,000 600,000(1) 2,890,140 29 Amount

$112.50 102.27 102.50 103.73 101.00 106.00 107.00 106.00 106.00 106.00 109.75 Through 5/31/81 8/31/82 2/28/81 1/31/82 9/30/82 2/28/81 And Thereafter To Amounts Declining In Steps To

$101.50 after 5/31 /84 101.00 after 8/31 /85 101.00 after 2/29/84 101.00 after 1 /31 /85 101.00 after 9/30/85 101.00 after 2/28/91

Preference Stock Not Subject to Mandatory Redemption:

Preference Stock was authorized for issuance effective April 17, 1975. On May 22, 1975, the Company issued 2,400,000 shares of $2.90 Dividend Preference Stock at

$23.90 per share which aggregated $57,360,000.

The Preference Stock is redeemable at the Company's Common Stock:

Common Stock was represented by 99,954,157 shares outstanding at December 31, 1980. In addition, 2,222,222 shares (based on the conversion price of $22.50 per share)

Public Ottering Automatic Dividend Reinvestment Plan Additions to Additions to Shares Capital Account Shares Capital Account 1980.... 5,000,000 1979.... 6,000,000 1978.... 5,000,000 1977.... 5,000,000 1976.... 5,000,000

$ 53,950,000 1,505,423 64,050,000 1,049,874 68,275,000 827,514 70,400,000 626,886 73,875,000 541,248

$16,378,807 12,925,755 11,689,651 9,229,553 7,726,113 option at $27.90 per share prior to May 1, 1980, and there-after declines in steps to $25.25 on May 1, 1990. Upon liq-uidation, all shares are entitled to receive $25 per share plus accrued dividends. Dividends are cumulative and pay-able March 20, June 20, September 20 and December 20.

are reserved for conversion of the 3% % Convertible Deben-tures due May 1, 1986. During the years 1976 through 1980 the following changes in Common Stock occurred:

Savings and Stock Ownership Plans Additions to Shares Capital Account 574,622 583,138 337,143 284,167 277,798

$6,261,638 7,222,482 4,774,135 4,212,884 3,900,245 Total Outstanding Shares Capital Account 99,954,157 92,874,112 85,241,100 79,076,443 73,165,390 67,346,344(3)

$1,400,874,668(1) 1,319,303,162 1,235,104,925 1, 150,366, 139(2) 1,006,523,702 921,022,344 (1) Includes $2,507,316 of transfers from Other Paid-In Capital and $2,473,745 of subscriptions received pursuant to the Customer Stock Purchase Plan.

(2) In May 1977, $60,000,000 was transferred from Earnings Reinvested in Business to the Common Stock account as authorized by the Board of Directors.

(3) Outstanding January 1, 1976.

On April 22, 1976, and May 8, 1979, the number of authorized shares was increased from 70,000,000 to 95,000,000 and from 95,000,000 to 120,000,000, respectively.

Other Paid-In Capital:

In 1977, the Company solicited tenders of shares of cer-tain series of Preferred Stock in exchange for shares of

$8.60 Dividend Preferred Stock. The purpose of this ex-change offer was to increase the balance sheet ratio of Common equity to total equity consistent with the objective of the Company to achieve and maintain capitalization ra-tios in the range of 52% long-term debt, 13% Preferred and Preference Stock and 35% Common equity. The difference between the stated value of the shares exchanged and that of the $8..60 Dividend series shares amounting to

$27,859,000, net of cash paid for fractional shares, was transferred to Other Paid-In Capital.

In 1980, with Virginia Commission Staff approval, the Company transferred $2,507,000 associated with $8.60 Dividend shares redeemed to the Common Stock account.

J. Short-Term Loans and Compensating Balances:

Year End Interest Rate At End 1980 Maturity Amount ofYear(1)

Commercial paper........................

(2)

$ 72,003,000 18.25%

Master notes................................

(3) 2,058,000 15.00 Pollution control notes.................

(2) 9,660,000 7.26 1979 Commercial paper........................

(2) 122,543,000 14.25 Master notes................................

(3) 6,937,000 12.25 Pollution control notes.................

(2) 2,250,000 7.25 Dally Average Outstanding Interest Amount Rate(1)

$155,772,000 13.54%

3,520,000 10.47 5,177,000 7.09 69,736,000 11.03 3,520,000 9.98 203,000 7.25 Maximum Outstanding

$280,525,000 12,300,000 9,660,000 175,750,000 6,937,000 2,250,000 (1) Weighted average interest.

(2) Principally 30 to 90 days.

(3) Maximum 180 days.

Available bank lines of credit amounted to

$390,975,000 at December 31, 1980, including

$180,000,000 applicable to revolving credit agreements effective through August 29, 1981. The Company maintains compensating balances of up to 1 0% or pays fees in lieu of 30 balances in connection with its lines of credit. Utilization un-der the line of credit may require additional balances or fees. Compensation for the revolving credit agreements are consistent with the requirements for the lines of credit.

K. L:ong-Term Debt:

Long-term debt outstanding at December 31, 1980:

First and refunding mortgage bonds(1 ):

Series I 3%%, due 1981.............. $

Series J 31.4%, due 1982..............

Series DD 101h%, due 1983..............

Series K 3Ya%, due 1984..............

Series L 3%%, due 1985..............

Series A 6¥s%, due 1985..............

Series M 4 Ya%, due 1986..............

Series N 41h %, due 1987..............

Series O 3%%, due 1988..............

Series P 4%%, due 1990..............

Series a 4%%, due 1991..............

Series R 4%%, due 1993..............

Series S 41h%, due 1993..............

Series FF 11 %, due 1994.................

Series EE 11 %, due 1994.................

Series T 41h%, due 1995..............

Series U 5%%, due 1997..............

Series V 6%%, due 1997..............

Series KK 8.95%, due 1998............

Series W 7%%, due 1999..............

Series X 7% %, due 1999..............

Series Y 9%, due 2000.................

1980 Series A 121h%, due 2000........

• Series Z 8%%, due 2000..............

Series AA 7%%, due 2001..............

, Series BB 71h%, due 2001..............

Series CC 7%%, due 2002..............

Series C 6.15%, due 2003..............

1979 Series B 9.95%, due 2004........

Series A 81h%, due 2005..............

Series GG 10%, due 2005.................

Series HH 9%%, due 2006..............

Series B 6%%, due 2006..............

Series II 8%%, due 2006..............

Series JJ 8%%, due 2007..............

Series LL 9%%, due 2008..............

1979 Series A 10%%, due 2009........

Total..............................................

Term notes (including

$125,000,000 issued in 1980) (2)..

Convertible debentures 3%%, due 1986 *********************************************

Pollution control revenue bonds (3).....

Bath County project financing (4)........

Less amounts due within one year:

Sinking fund obligations(1).............

Term notes(2)................................

First and Refunding Mortgage Bonds........................................

Pollution Control Revenue Bonds(3)

Less unamortized discount-net 20,000,000 20,000,000 75,000,000 25,000,000 25,000,000 8,000,000*

20,000,000 20,000,000 25,000,000 25,000,000 30,000,000 30,000,000 30,000,000 117,000,000 81,793,000 60,000,000 50,000,000 50,000,000 55,000,000 85,000,000 75,000,000 83,725,000 75,000,000**

83,725,000 90,000,000 50,000,000 100,000,000 8,000,000*

135,000,000 18,000,000*

100,000,000 100,000,000 20,000,000

• 100,000,000 150,000,000 150,000,000 100,000,000 2,290,243,000 430,000,000 50,000,000 47,000,000 201,8~ 0,000 3,019,053,000 10,043,000 90,000,000 20,000,000 2,250,000 of premium.....................................

9,646,000 Total long-term debt................... $2,887,114,000

• Pollution Control Series.

• Issued in 1980.

The Company has redeemed the $64,117,000 of long-term debt and sinking fund obligations due in 1980. Matu-rities (including cash sinking fund obligations) through 1985 are as follows: 1981-$122,293,000; 1982-

$90,500,000; 1983-$150,500,000; and 1984-

$338,310,000; 1985-$120,250,000.

31 (1) The Mortgage provides for sinking funds as follows:

Series I through CC..............

Series EE and FF..................

Series KK............................

1979 Series A and B............

1980 Series A......................

Pollution Control Series A Pollution Control Series B Pollution Control Series C Commencing Begun 1984 1985 1986 1986 1992 1989 Annual Sinking Fund Requirements

$10,000,000 13,250,000 2,750,000 10,750,000 4,875,000 500,000 250,000 375,000

• The Company may satisfy these requirements by waiv-ing the privilege to issue an equal amount of Bonds by sub-stituting property therefor and intends to do so in 1981.

Substantially all of the Company's property is subject to the lien of the Mortgage.

(2) Term Notes:

Variable Interest Rate Percentage of Base Notto Principal Lending Exceed an Fixed Inter-Amount Maturity Rate of Average of est Rate

$60,000,000 1981 115%

81h%

5,000,000 1981 8.15%

25,000,000 1981 100%

9.65 50,000,000 1982 115 8%

5,000,000 1982 8%

10,000,000 1983 8%

5,000,000 1983 11%

5,000,000 1983 8%

40,000,000 1983 60 8

10,000,000 1984 8%

5,000,000 1984 115 9.9 5,000,000 1984 1071h 9.9 50,000,000 1984 10%

25,000,000 1984 11 %

20,000,000 1985 115 8%

5,000,000 1985 8%

15,000,000 1985 15%

5,000,000 1985 151h 15,000,000 1985 11 %

10,000,000 1987 141h 50,000,000 1988 9

10,000,000 1995 12%

$430,000,000

• 118% of the higher of commercial paper rate plus % of 1 % or base lending rate. Interest not to be less than 8%.

(3) Pollution Control Revenue Bonds:

Mandatory Sinking Fund Reguirements Principal Amount Maturity

$ 6,000,000 1981-83*

4,500,000 1989 22,000,000 2002 14,500,000 2004 Interest Annual Rate Amount Commencing 7.2-7.4%

None

{

$250,000 8.0 500,000 750,000 5%

500,000 8%

750,000 1981 1984 1987 1990 1990

$47,000,000

• $2,000,000 of the $6,000,000 principal amount of Serial Bonds mature annually.

(4) In 1980, the Company issued a 31h year term collat-eral note securing borrowings of a trust which is fi-nancing construction expenditures (including interest) after 1979 on the Bath County Pumped Storage Proj-ect. Borrowings under the present arrangements are limited to $220 million. Weighted average interest for 1980, including fees for supporting lines of credit, amounted to 14.16%.

L. Effect of Rate Increases on Operating Revenues:

In 1980, the Company obtained rate relief of about

$132.3 million on an annual basis from the three State Com-missions, FERC and non-jurisdictional customers.

Rate increases and a decrease which became effective for portions of the following years increased (decreased) operating revenues for the respective years by the approxi-mate amounts shown:

M. Retirement Annuity Plan:

Costs to the Company under the plan were: 1980--

$11,186,000; 1979-$9,697,000; 1978-$8,586,000; 1977-$7,594,000; and 1976-$5,046,000. At January 1, 1980, the date of the latest available actuarial report the unfunded liability of the plan amounted to approximately

$12.4 million.

The present value of benefits, as of January 1, 1980, as N. Commitments and Contingencies:

The Company has made substantial commitments in con-nection with its construction program, which is presently estimated to be $643 million for 1981. Additional financing is contemplated in connection with this program.

The major portion of Laurel Run Mining Company's min-ing equipment is leased. As guarantor, the Company has a contingent liability for annual lease payments of $1.1 million in 1981, $1.0 million in* 1982 and $.8 million in 1983.

The FERC has directed the Company to write-off $6.3 million ($4.3 million of AFC and $2.0 million of other costs) associated with a boiler implosion in 197 4 at Yorktown Unit 3 which the Company has capitalized on its books. In 1980, an Administrative Law Judge ruled against the Company, but the Company intends to appeal.

In 1979, settlement was reached in the Westinghouse uranium dispute which provides for cash and discounts on uranium and goods and services over the period 1979-1997 which is estimated to equal the value of contracts liti-gated had they been fully performed by Westinghouse.

The following amounts (not examined by independent certified public accountants) reflect all adjustments, con-sisting of only normal recurring accruals, necessary in the opinion of the Company for a fair statement of the results for the interim periods, except as disclosed below for the inven-Balance Earnings for Per Share Operating Operating Common of Common Quarter Revenues Income Stock Stock 1980 (Thousands of Dollars) 1st............. $572,820

$88,649

$40,173

$.43 2nd............ 473,472 79,395 28,395

.30 3rd............

576,472 107,780 57,311

.60 4th.............

497,010 113,708 58,450

.60 Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.

In the fourth quarter of 1980, the Company began ac-counting on an inventory basis for spare parts and equip-32 1980 Electric................ $36.4 Gas.....................

(.7)

(Millions of Dollars) 1979 1978 1977

$56.4 $56.9

$3.0

.4 determined by the actuaries, were as follows:

1976

$6.3

.9 Vested accumulated plan benefits.......

$129,406,000 Nonvested accumulated plan benefits.

16,136,000 Total..........................................

$145,542,000 Plan net assets available for benefits...

$129,722,000 A 6% rate of return is used in determining the present value of vested and nonvested accumulated plan benefits.

Through December 31, 1980, the Company had received

$147 million in cash and goods and services, $55 million of which was received in 1980 (including $41 million of cash).

Settlement proceeds will reduce fuel expenses under pro-cedures currently under review by regulatory authorities.

On January 8, 1979 the Company filed with the Internal Revenue Service a request for a ruling with respect to the Federal income tax consequences of the settlement. Such filing requested that the value received froni the settlement be treated as a reduction in fuel expense over the life of the nuclear fuel, and not as taxable income in the year of the settlement. The Company's ruling request is still under con-sideration by the Internal Revenue Service.

For a discussion of possible sales of power station proj-ects and related facilities, see the last two paragraphs un-der Capital Resources under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPER-ATIONS.

tory adjustment recorded in the fourth quarter of 1 980 and except for the deferral of purchased and interchanged power costs in 1979 (as discussed in Note B to Financial Statements.)

Ba1Bnce Earnings for Per Share Operating Operating Common of Common Quarter Revenues Income Stock Stock 1979 (Thousands of Dollars) 1st............. $403,952

$76,138

$34,710

$.41 2nd............

374,082 73,039 29,772

.35 3rd............

457,004 92,361 47,951

.56 4th.............

468,271 74,856 28,911

.31 ment which had been expensed. The effect of the adjust-ment, which amounted to $8.9 million ($4.8 million net of Federal.income taxes), was to increase earnings per share by $.05.

P. Supplementary Data On Changing Prices (Unaudited):

The following supplementary information is supplied in accordance with the requirements of FASB Statement No.

33, Financial Reporting and Changing Prices, for the pur-pose of providing certain information about the effects of changing prices. It should be viewed as an estimate of the approximate effect of inflation, rather than as a precise measure.

Constant dollar amounts represent historical costs stated in terms of dollars of equal purchasing power, as measured by the Consumer Price Index for All Urban Con-sumers (CPI-U). Current cost amounts reflect the changes in specific prices of plant from the date the plant was ac-quired to the present, and differ from constant dollar amounts to the extent that specific prices have increased more or less rapidly than prices in general.

The current cost of property, plant and equipment, which includes intangible plant, property held for future use and construction work in progress, represents the estimated cost of replacing existing plant assets and was determined by indexing the surviving plant by the Handy-Whitman Index of Public Utility Construction Costs. The current cost of land and general plant was determined by using the CPI-U. The current year's provision for depreciation on the constant dollar and current cost amounts of property, plant and equipment was determined by applying the Company's de-preciation rates to the indexed plant amounts.

Fuel used in electric generation has been restated to re-flect the constant dollars and current cost of nuclear fuel.

The cost of other types of fuel used in electric generation and gas purchased for resale have not been restated since these costs are considered to be current.

33 Fuel inventories, with the exception of nuclear fuel, have not been restated from their historical cost in nominal dol-lars. The nuclear fuel inventory is considered an integral part of the plant investment and, therefore, should be re-stated and adjusted to net recoverable cost. As indicated above, other types of fuel inventories have not been re-stated since the costs of these assets are considered to be current.

Preferred stock subject to mandatory redemption has been classified as a monetary liability in determining the gain from decline in purchasing power of dollars related to net amounts owed, in accordance with the definition of a monetary liability in FASB Statement No. 33.

As prescribed in Statement 33, income taxes were not adjusted.

To properly reflect the economics of rate regulation in the Statement of Income from Continuing Operations, the ad-justment of property, plant and equipment to net recover-able cost should be offset or combined, as appropriate, by the gain from the decline in purchasing power of the dollars related to net amounts owed. During a period of inflation, holders of monetary assets suffer a loss of general purchas-ing power while holders of monetary liabilities experience a gain. The gain from the decline in purchasing power of the dollars related to net amounts owed is primarily attributable to the substantial amount of debt which has been used to finance property, plant and equipment. Since the deprecia-tion on this plant is limited by regulation to the recovery of historical costs, a holding gain on debt is not allowed and the Company is limited to recovery of the embedded cost of the asset.

Statement of Income from Continuing Operations Adjusted for Changing Prices (Unaudited)

Operating revenues......................................................

Fuel used in electric generation....................................

Depreciation................................................................

Other operating and maintenance expense...................................................................

Federal income taxes...................................................

Interest expense (net of allowance for borrowed funds used during construction).................

Other income and deductions-net.................................

Income from continuing operations (excluding adjustment to net recoverable cost)............................................

Increase in specific prices (current cost) of property, plant and equipment held during the year**..............

Adjustment to net recoverable cost...............................

Effect of increase in general price level................................................................

Excess of increase in general price level over increase in specific prices after adjustment to net recoverable cost.................................................

Gain from decline in purchasing power of dollars related to net amounts owed..........................

Net..............................................................................

For The Year Ended December 31, 1980 Conventional Historical Cost

$2,119,774 674,996 145,032 840,210 70,004 223,541 (75,629) 1,878,154

$ 241,620 Constant Dollar Average 1980 Dollars (Thousands of Dollars)

$2,119,774 693,777 279,720 840,210 70,004 223,541 (75,629) 2,031,623 88,151*

$ (473,392) 388,967 (84,425)

Current Cost Average 1980 Dollars

$2,119,774 706,816 305,465 840,210 70,004 223,541 (75,629) 2,070,407 49,367

$ 516,022 113,815 (1,064,445)

(434,608) 388,967 (45,641)

• Including the adjustment of property, plant and equipment to net recoverable cost, the loss from continuing oper-ations on a constant dollar basis would have been $385,241,000 for 1980.

• At December 31, 1980, current cost of property, plant and equipment, net of accumulated depreciation and amortization was $9,532,569,000, while historical cost or net cost recoverable thrOLigh depreciation and amortization was $5,586,465,000.

34

Five Year.Comparison of Selected Supplementary Financial Data Adjusted for Effects of Changing Prices (Unaudited)

Years Ended December 31, 1980 1979 1978 1977 1976 (In Thousands* of Average 1980 Dollars)

Operating revenues.................................................. $2,119,774 $1,933,655 $1,850,248 $1,847,750 $1,598,158 Historical cost information adjusted for general inflation Income from continuing operations (excluding adjustment to net recoverable cost)......

$88,151

$91,951 Income per common share (after dividend requirements on preferred and preference stock).......................

$0.32

$0.34 Net assets at year-end at net recoverable cost.................................................. $2,111,046 $2,231,871 Current cost information Income from continuing operations (excluding adjustment to net recoverable cost)......

$49,367

$42,815 (Loss) per common share (after dividend requirements on preferred and preference stock).......................

$(0.08)

$(0.23)

Excess of increase in general price level over increase in specific prices after adjustment to net recoverable cost.........................................

$548,423

$520,206 Net assets at year-end at net recoverable cost.................................................. $2,111,046 $2,231,871 General information Gain from decline in purchasing power of dollars related to net amounts owed.................................

$388,967

$421,584 Cash dividends declared per common share.....................................................

$1.40

$1.57 Market price per common share at year-end..........................................................

$9.92

$11.27 Average consumer price index (1967=100)..............

246.8 217.4

• Except per share amounts and indexes.

35

$1.64

$17.03 195.4

$1.69

$19.23 181.5

$1.77

$21.77 170.5

Ten Year Comparative Summary of Performance Operating revenues:

Electric..................................................................................

Gas.......................................................................................

Total operating revenues................................................

Expenses (operation and maintenance)......................................

Depreciation..............................................................................

Amortization of abandoned project costs....................................

Taxes:

Federal income:

Currently payable (refundable)...........................................

Investment tax credits, including carry-back.......................

Investment tax credits, amortization....................................

Deferred-accelerated amortization...................................

-liberalized depreciation.....................................

--other................................................................

Other....................................................................................

Total operating expenses...............................................

Operating income......................................................................

Other income:

Allowance for other funds used during construction.................

Allowance for funds used during construction.........................

Miscellaneous, net.................................................................

Total other income.........................................................

Income before interest charges..................................................

Interest charges:

Interest on long-term debt......................................................

Other....................................................................................

Allowance for borrowed funds used during construction..........

Total interest charges....................................................

Income before cumulative effect of change in accounting method Cumulative effect to January 1, 197 4 of accruing estimated unbilled revenues, net of taxes...............................................

Net income................................................................................

Dividends paid:

On preferred and preference stock.........................................

On common stock..................................................................

Total dividends..............................................................

Earnings reinvested in business..................................................

Shares of common stock-average for year (thousands)...................................................................

Earnings per share of common stock..........................................

Dividends paid per share of common stock.................................

Pay-out ratio..............................................................................

Return of capital:

Common stock dividends.......................................................

Preferred stock dividends......................................................

Preference stock dividends....................................................

Utility plant at original cost.........................................................

Utility plant expenditures............................................................

Accumulated depreciation and amortization................................

Capitalization:

Preferred and preference stock..............................................

Common equity......................................................................

Debt (excluding short-term debt)............................................

Total capitalization.........................................................

Short-term debt-pending permanent financing......................

Capitalization ratios:

Preferred and preference stock..............................................

Common equity......................................................................

Debt (excluding short-term debt)............................................

1980

$2,049,518 70,256 2,119,774 1,390,817 145,032 6,933 11,200 11,798 (5,171)

(1,547) 41,108 12,616 117,456 1,730,242 389,532 73,206 2,423 75,629 465,161 234,561 28,530 (39,550) 223,541 241,620 241,620 57,290 133,005 190,295 51,325 95,520

$1.93

$1.40 72%

100.000%

3.300%

100.000%

$6,836,094

$ 681,120

$1,249,629

$ 677,268 1,861,656 3,019,053

$5,557,977 83,721 12%

34 54 (Thousands of Dollars) 1979 1978

$1,647,928

$1,413,866 55,381 51,039 1,703,309 1,464,905 1,069,241 869,232 136,280 117,481 7,292 6,760 8,449 23,163 570 40,294 (5,820)

(5,467)

(1,547)

(1,547) 32,418 38,509 35,674 (22,294) 104,358 93,499 1,386,915 1,159,630 316,394 305,275 66,603 64,002 974 1,342 67,577 65,344 383,971 370,619 204,392 184,947 12,417 6,677 (29,305)

(24,869) 187,504 166,755 196,467 203,864 196,467 203,864 55,046 53,588 120,638 103,474 175,684 157,062 20,783 46,802 86,965 80,060

$1.63

$1.88

$1.38

$1.30 85%

69%

(2)

$6,307,644

$5,626,671

$ 708,756

$ 529,186

$1,079,142

$ 940,958 678,451

$ 651,634 1,731,762 1,627,179 2,681,360 2,460,060

$5,091,573

$4,738,873

$ 131,730 3,437 13%

14%

34 34 53 52 (1) Includes non-recurring cumulative effect of change in accounting for unbilled revenues of $.24 per share.

(2) 1979 Return of capital was 33.02% for the first quarter and 91.95% for the remainder of the year.

36 1977

$1,313,93i 44,92~

1,358,86(

850,82~

98,52i 3,17~

9,19" 23,54f (4,53!

(1,54; 13,10" 19,98:

81,17*

1,093,43:

265,42'.

72,36" (66:

71,691 337,12!

168,88!

5,74:

(27,30 147,33:

189,79:

189,79 47,71 91,22 138,94 50,84 74,02

$1.9

$1.2 6

72.65

$5,109,09

$ 569,06

$ 803,60

$ 619,10 1,493,52 2,238,40

$4,351,03 53,05 1,

3 e

~

1976 1975 1974 1973 1972 1971 1970 1,060,663

$ 998,933

$ 735,962

$ 524,963

$ 445,668

$ 390,370

$ 353,151 43,413 34,403 28,050 26,000 25,185 23,302 21,729

,104,076 1,033,336 764,012 550,963 470,853 413,672 374,880 647,965 629,162 478,716 278,750 264,906 218,846 181,434 95,191 89,805 77,757 68,436 53,058 49,950 46,841 2,209 (1,142)

(7,678)

(1,010)

(6,850) 8,652 23,784 35,568 2,286 (3,195) 3,901 7,368 1,952 1,163 (3,028)

(2,452)

(2,412)

(2,413)

(2,225)

(2,062)

(1,318)

(1,547)

(1,547)

(1,547)

(1,547)

(1,547)

(1,547)

(1,547) 12,320 9,360 3,202 3,229 20,873 5,018 7,265 1,356 1,050 71,413 57,169 48,216 42,170 36,629 33,514 29,367 863,320 803,514 598,077 395,552 352,695 310,355 279,724 240,756 229,822 165,935 155,411 118,158 103,317 95,156 80,429 66,873 65,735 57,359 58,451 39,993 24,175 491 544 411 336 (156) 142 274 80,920 67,417 66,146 57,695 58,295 40,135 24,449 321,676 297,239 232,081 213,106 176,453 143,452 119,605 147,481 122,951 94,058 78,350 67,554 58,130 44,083 7,409 19,556 23,214 10,684 5,162 3,274 3,368 154,890 142,507 117,272 89,034 72,716 61,404 47,451 166,786 154,732 114,809 124,072 103,737 82,048 72,154 12,353 166,786 154,732 127,162 124,072 103,737 82,048 72,154 43,821 35,971 30,419 24,147 16,472 12,216 7,728 82,923 70,786 60,165 54,796 46,905 41,993 39,906 126,744 106,757 90,584 78,943 63,377 54,209 47,634 40,042 47,975 36,578 45,129 40,360 27,839 24,520 68,137 60,854 52,100 47,021 41,883 37,829 35,881

$1.80

$1.95

$1.86(1)

$2.13

$2.08

$1.85

$1.80

$1.22%

$1.18

$1.18

$1.16%

$1.12

$1.12

$1.12 67%

60%

71%

55%

54%

60%

62%

25.267%

100.000%

49.407%

100.000%

96.724%

54.243%

100.000%

55.565%

609,416

$4,142,900

$3,739,395

$3,298,447

$2,847,614

$2,416,130

$2,082,487 481,601

$ 432,139

$ 460,912

$ 486,709

$ 472,819

$ 380,268

$ 338,074 700,254

$ 609,304

$ 545,296

$ 476,121

$ 414,941

$ 373,834

$ 335,605 583,807

$ 503,807

$ 446,447

$ 366,447

$ 296,447

$ 201,447

$ 161,447

,334,639 1,211,282 1,042,677 948,369 810,121 680,800 574,633

,038,150 1,803,150 1,578,350 1,289,890 1,242,440 1,070,440 932,000

,956,596

$3,518,239

$3,067,474

$2,604,706

$2,349,008

$1,952,687

$1,668,080 26,500 110,050

$ 256,945

$ 220,150 88,400 61,800 53,700 15%

14%

15%

14%

13%

10%

10%

34 35 34 36 34 35 34 51 51 51 50 53 55 56 37

Ten Year Operating Statistics ELECTRIC DEPARTMENT Operating revenues (thousands):

Residential........................................................................

Commercial.......................................................................

Industrial...........................................................................

Other sales of electric energy............................................

Other electric revenues.....................................................

Total operating revenues---electric................................

Population served at retail-estimated...................................

Number of customers:

Residential........................................................................

Commercial........................................................................

Industrial........................................................................,..

Other................................................................................

Total customers.............................................................

Sales of electricity-Mwh (thousands):

Residential........................................................................

Commercial.......................................................................

Industrial...........................................................................

Other................................................................................

Total sales of electricity.................................................

Losses and miscellaneous system uses..................................

Total distribution-energy supply..................................

Less: Sales outside of service area.........................................

Total distribution...........................................................

Source of electricity-Mwh (thousands):

Steam-Fossil..................................................................

-Nuclear................................................................

Hydro...............................................................................

Other.................................................................................

Net purchased and interchanged...........................................

Company energy supply_................................................

Less: Sales outside of service area.........................................

System output...............................................................

Interchange deliveries for account of others.......................

Company's service area output......................................

Company's service area peak load-Mw................................

Power supply available for peak load-Mw Generating capability:

Steam-Fossil..............................................................

-Nuclear...........................................................

Hydro...........................................................................

Other..................................................*.........................

Total generating capability.........................................

SEPA power disposed of in Company's service area...........

Available for firm peak load............................................

Purchase (sale) outside service area..................................

Available for service area peak load...............................

BTU per kilowatt-hour generated............................................

Average fuel cost per KWH generated-mills............................

Electric line-pole miles........................................................

Underground construction-miles of route.............................

GAS DEPARTMENT Operating revenues (thousands):

Residential....................................................................

Commercial and industrial...............................................

Other............................................................................

Total operating revenues--gas..................................

Population served at retail-estimated...............................

Number of customers........................................................

Sales-Met (thousands)....................................................

Output-Met manufactured (thousands)............................

Met natural gas purchased (thousands)................

Miles of main.....................................................................

1980

$ 806,156 534,241 281,316 413,022 14,783

$2,049,518 3,579,000 1,208,500 120,869 920 16,878 1,347,167 13,154 9,597 6,459 10,035 39,245 3,244 42,489 42,489 18,840 11,466 616 208 11 359 42,489 42,489 326 42,815 8,484 6,144 2,329 326 439 9,238 165 9,403 1,300 10,703 11,235 21.76 42,297 10,127 35,323 34,411 522 70,256 971,000 120,108 17,495 57 18,906 2,108 1979

$ 637,519 431,191 220,814 347,276 11,128

$1,647,928 3,523,000 1,174,351 117,965 920 15,873 1,309,109 12,397 9,161 6,460 9,557 37,575 2,909 40,484 40,484 24,301 7,055 1,122 356 7 650 40,484 40,484 325 40,809 7,929 6,321 2,448 326 439 9,534 165 9,699 300 9,999 11,067 20.44 42,149 9,314 29,380 25,346 655 55,381 875,000 118,656 16,307 74 17,499 2,095 1978 563,561 392,101 182,901 268,213 7,090

$1,413,866 3,465,000 1,138,470 115,121 920 15,446 1,269,957 12,405 9,170 6,152 9,340 37,067 2,901 39,968 39,968 24,438 14,098 967 399 66 39,968 39,968 325 40,293 7,805 6,321 2,448 326 439 9,534 165 9,699 300 9,999 11,018 14.04 41,698 8,395 30,621 20,000 418 51,039 875,000 119,288 15,303 236 16,407 2,096 1977

$ 524,3 365,3 176,5 242,6 5,0

$1,313,9 3,415,0 1,100,8 111,6 9

14,9 1,228,3 11,8 8,7 6,0 8,8 35,4 2,7 38,2 38,2 26,4 9,4 4

6 1 2.

38,2 38,2 3

38,5 7,9 6,3 1,5 3

4 8,6 1

8,8 3

9, 1 10,9

15.

41,4 7,7 26,6 17,9 3

44,9 875,C 120.~

15,(

E 15,4 2,0

• Excludes the cumulative effect to January 1, 1974 of accruing estimated unbilled revenues ($18,842,000 electric-$1,565,000 gas) shown as a non-recurring item on the income statement, net of taxes.

38

1976 1975 1974 1973 1972 1971 1970 420,150

$ 402,889 308,834 229,860 191,924 169,113 158,698 298,681 288,357 211,486 150,758 130,599 113,646 99,957 144,770 137,181 106,309 66,131 58,785 48,375 41,889 193,096 166,854 106,018 75,170 61,440 56,392 50,073 3,966 3,652 3,315 3,044 2,920 2,844 2,534

,060,663

$ 998,933

$ 735,962*

$ 524,963

$ 445,668

$ 390,370 353,151

,365,000 3,315,000 3,270,000 3,225,000 3,185,000 3,150,000 3,100,000

,071,528 1,041,234 1,018,346 989,471 954,374 920,839 895,210 108,197 105,942 105,531 103,253 100,175 98,223 97,113 920 918 916 910 894 874 873 14,462 14,881 13,045 12,350 11,817 11,392 10,948

, 195,107 1,162,975 1,137,838 1,105,984 1,067,260 1,031,328 1,004,144 11,137 10,373 9,850 9,911 8,775 8,121 7,873 8,455 7,970 7,307 7,330 6,471 5,980 5,617 6,011 5,404 5,658 5,535 5,136 4,683 4,456 8,510 7,741 7,120 7,268 6,529 5,902 5,560 34,113 31,488 29,935 30,044 26,911 24,686 23,506 2,261 2,585 2,518 2,335 2,199 2,019 1,777 36,374 34,073 32,453 32,379 29,110 26,705 25,283 216 36,374 34,073 32,453 32,379 29,110 26,705 25,067 27,090 23,562 22,819 22,311 23,710 24,335 23,218 7,740 8,969 5,953 6,857 370 599 988 774 949 1,071 825 445 407 226 629 459 558 323 350 538 328 2,278 1,803 3,401 1,222 1,270 36,374 34,073 32,453 32,379 29,110 26,705 25,283 216 36,374 34,073 32,453 32,379 29,110 26,705 25,067 326 325 325 315 312 307 301 36,700 34,398 32,778 32,694 29,422 27,012 25,368 7,040 7,133 6,734 6,900 6,232 5,295 4,852 6,321 6,321 5,684 4,866 4,306 4,334 4,330 1,576 1,576 1,576 1,576 788 326 326 326 326 326 326 326 454 469 530 530 530 530 342 8,677 8,692 8,116 7,298 5,950 5,190 4,998 165 165 165 165 132 132 131 8,842 8,857 8,281 7,463 6,082 5,322 5,129 313 316 251 122 680 610 194 9,155 9,173 8,532 7,585 6,762 5,932 5,323 10,739 10,892 10,868 10,673 10,529 10,382 10,268 12.94 13.06 12.43 4.98 4.63 4.28 3.55 41,186 40,663 40,121 39,578 39,055 38,404 37,803 6,824 6,266 5,641 4,772 4,055 3,367 2,763 24,914 21,280 17,265 16,038 16,132 14,847 14,600 18,308 12,944 10,598 9,775 8,858 8,252 6,922 191 179 187 187 195 203 207 43,413 34,403 28,050*

26,000 25,185 23,302 21,729 875,000 875,000 864,000 853,000 852,000 850,000 800,000 122,103 122,486 124,395 125,525 125,277 124,029 122,489 17,228 15,017 16,888 17,666 17,620 17,772 16,239 138 92 12 297 247 341 378 18,519 16,274 17,938 18,696 18,824 18,563 17,035 2,100 2,014 2,012 1,992 1,993 1,955 1,909 39

Directors William W. Berry,<1l President James F. Betts, President Continental Financial Services Company, Richmond Charles F. Burroughs, Jr., Retired Milton L. Drewer, Jr., President First American Bank of Virginia, McLean Mrs. Mary C. Fray, Culpeper Bruce C. Gottwald,<2i President Ethyl Corporation, Richmond Dr. Allix B. James, President Emeritus Virginia Union University, Richmond T. Justin Moore, Jr., Chairman of the Board of Directors William S. Peebles, Ill, President W. S. Peebles and Company, Inc., Lawrenceville Shirley S. Pierce, President The Ahoskie Fertilizer Company, Inc., Ahoskie, N.C.

Kenneth A. Randall, President, The Conference Board, New York William T. Roos, President, Penn Luggage, Inc., Hampton Roy R. Smith, Chairman of the Board Smith's Transfer Corporation, Staunton William F. Vosbeck, Jr., President VVKR Incorporated, Alexandria Officers T. Justin Moore, Jr., Chairman of the Board and Chief Executive Officer, Age 55 William W. Berry, President and Chief Operating Officer, Age 48 Jack H. Ferguson, Executive Vice President, Age 49 Senior Vice Presidents Samuel C. Brown, Jr., Power Station Engineering and Construction, Age 55 Leon D. Johnson, Ill, Support Servlces, Age 63 John I. Oatts, Power Operations, Age 51 William L. Proffitt, Commercial Operations, Age 51 Vice Presidents Wadsworth Bugg, Jr., Age 59 Robert F. Hill, Age 44 Charles M. Jarvis, Age 52 B.D. Johnson, Vice President and Controller, Age 48 Ronald H. Leasburg,<3 > Age 47

0. James Peterson, Ill, Vice President and Treasurer, Age 45 William C. Spencer, Age 48 William N. Thomas, Age 57 Corporate Secretary S. Brooks Robertson, Age 63 Division Vice Presidents Northern Division, James P. Cox, Jr., Age 62 Eastern Division, Harrison Hubard, Age 63 Southern Division, Randolph D. Mciver, Age 50 Western Division, Richard W. Carroll, Age 62 Central Division, David W. Poole, Age 56 (1) Effective 5/16/80 replacing Stanley Ragone (2) Effective 1 /1 /81 replacing John M. McGurn (3) Effective 2/23/81 40 Membership of Committees of the Board 0 Committee Chairman

• Member* Ex Officio*

Organization and Employee Finance Audit Nominating Compensation Benefit 0

0 0

0 0

Stock and Convertible Debenture Listings New York Stock Exchange Transfer Agents-Registrars United Virginia Bank, Richmond The Chase Manhattan Bank, N.A., New York Annual Meeting April 15, 1981

A TRIBUTE Stanley Ragone's tragic death on April 25, 1980, in an automobile accident that also was fatal to his devoted wife Ber-tha, deprived our Company and our indus-try of a trusted leader and cherished friend. As President from 1978 to 1980, his ability, integrity and consideration for others strengthened the bonds of respect and loyalty within the Vepco family.

NORTH CAROLI NA