ML18130A352
| ML18130A352 | |
| Person / Time | |
|---|---|
| Site: | Surry, North Anna, 05000000 |
| Issue date: | 03/26/1982 |
| From: | Berry W, Moore T VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.) |
| To: | |
| Shared Package | |
| ML18130A353 | List: |
| References | |
| NUDOCS 8204020524 | |
| Download: ML18130A352 (44) | |
Text
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On the Cover Construction progresses in the turbine building at Bath County Pumped Storage Station. The 2.1 million kilowatt project is now 60 percent complete.
Disposition of the 1981 Revenue Dollar Fuel used for Electric Generation including Purchased and Interchanged Power 39.1(;
lnterest-15.0(;
Salaries and Wages-11.0(;
Taxes-10.3(;
Other Operation and Maintenance Expenses-9.7(;
Preferred, Preference and Common Dividends-9.3(;
Depreciation and Other-3.9(;
Earnings Reinvested in Business-1.7(;
Contents Highlights..
Stockholders Letter.
Revenues.
Expenses.....................
Earnings and Dividends.
1 Rate Relief.
2 Current Operations.............
4 Meeting Future Demand.
4 Financial Support.
4 Gas Operations............
Financial Report...
4 6
... 10
... 12
... 14
... 17 Description of Business.
Management's Discussion and Analysis of Financial Condition.
Statistical Information.
Directors and Officers.
. 18
... 18
... 36
.. 40
1981 Highlights Increase
% Increase 1981 1980 (Decrease)
(Decrease)
Financial Total Operating Revenues
$2,161,853,000
$2,119,774,000
$ 42,079,000 2.0 Total Operating Expenses
$1,693,221,000
$1,730,242,000
$(37,021,000)
(2.1)
Net Income
$ 237,780,000
$ 241,620,000
$ (3,840,000)
(1.6)
Balance Available for Common Stock
$ 180,614,000
$ 184,329,000
$ (3,715,000)
(2.0)
Average Shares of Common Stock Outstanding 101,856,000 95,520,000 6,336,000 6.6 Stockholders-Common, Preferred and Preference 213,700 206,800 6,900 3.3 Earnings Per Share of Common Stock
$1.77
$1.93
$(.16)
(8.3)
Dividends Per Share of Common Stock
$1.425
$1.40
$.025 1.8 Book Value Per Share of Common Stock
$18.64
$18.63
$.01 0.1 Capital Expenditures
$ 676,295,000
$ 681,120,000
$ (4,825,000)
(0.7)
Long-Term Financings
$ 421,693,000
$ 480,874,000
$(59,181,000)
(12.3)
Operations System Output-Megawatt-hours (thousands) 42,889 42,489 400 0.9 Year-End Capability-Megawatts 10,959 10,830 129 1.2 Service Area Peak Load-Megawatts 8,638 8,484 154 1.8 Customers-Electric-Heating 352,048 325,728 26,320 8.1
-Other 1,029,052 1,021,372 7,680 0.8 Total Electric 1,381,100 1,347,100 34,000 2.5 Customers-Gas 121,400 120,100 1,300 1.1 Average Residential Use-Electric-Kilowatt-hours 10,948 11.056 (108)
(1.0)
Employees-Full Time 11,487 10,580 907 8.6 Virginia Electric and Power Company
- One James River Plaza
- Richmond, Virginia 23261
To Our Stockholders:
Steps taken in 1980 to improve all elements of the Company's operations became giant strides in 1981. Achiev-ing those improvements, many of which included costly upgrading of plant equipment, was an expensive but necessary investment in the future.
The progress made in meeting opera-tional goals during 1981 will begin to reap significant financial rewards in 1982, and will position Vepco favor-ably tor the rest of the decade and be-yond.
The goals set were to: increase the nuclear component in our energy sup-ply mix; continue our aggressive con-version of oil-tired units to coal; im-prove productivity of all fossil generating stations; and reduce our external financing requirements. The results were excellent.
Energy Supply The improvement in Vepco's energy supply mix in 1981 was dramatic. Our tour nuclear units were on line during the year and performed well. As a re-sult, nuclear units generated 41 per-cent of our total energy supply. This increase from 27 percent nuclear gen-eration in 1980 exceeded our goal tor the year. Coal generation amounted to 31 percent tor the year, up from 25 percent in 1980. With an aggressive program to convert oil-fired units to coal our dependence on expensive oil-tired generation dropped from 19 per-cent in 1980 to 8 percent in 1981.
Nuclear Units The return to service of Surry Power Station Unit 1 in July marked the com-pletion of the massive construction project to replace the steam genera-tors on both nuclear units at Surry.
This was the first such replacement project to be done in the world on commercial nuclear reactors.
The total cost was about $113 mil-lion, but was money well spent. These two nuclear units cost approximately
$257 a kilowatt of capacity when they were originally built. The steam gen-erator replacement increased the total cost to almost $330 a kilowatt, but it would cost more than three times that amount today to construct new nuclear generating units of similar size and quality.
Although both our North Anna nu-clear units experienced outages in 1981 as a result of problems with tur-bine rotors and transformers, both non-nuclear components, the resourcefulness of our engineering, construction and operational team kept these outages to a minimum. Both units finished the year with good per-formance records.
Fossil Fuel Units The most important capital improve-ment project underway is the conver-sion of tour large, coal-fired units from forced to balanced draft combustion.
Phase one of this project-making modifications necessary prior to install-ing new equipment-was completed in 1981. Phase two-the installation of balanced draft combustion hardware--
will be completed in 1983. This con-version project will lead to reduced maintenance costs and improved effi-ciency of these units.
The improvement program extends into virtually every aspect of the fossil fuel plant operations-upgraded per-sonnel qualifications and training, in-creased staffing, major renovations of existing equipment, and improved ad-ministrative procedures.
This program is scheduled tor com-pletion by 1984, but we began seeing positive results in 1981. The forced-outage rate at our five largest coal-William W. Berry, President and T. Justin Moore, Jr., Chairman of the Board 2
tired units was significantly reduced, and their availability was increased.
Our smaller coal-tired units also oper-ated extremely well during the year.
We completed conversion of our sixth oil unit to coal-Possum Point Unit 3. As of 1981, the 1.6 million kilo-watts of capacity Vepco has converted accounted tor over a third of all oil to coal conversions in the United States.
New Gas Division The Company in 1981 established a new Gas Division with the name Vir-ginia Natural Gas. By mid-1982, the division will have about 415 employ-ees assigned to it, all of whom are de-voting full-time to gas operations. We are confident this new division will lead to even better service to our 120,000 gas customers, and an expansion of our gas market.
Meeting New Demand We anticipate peak demand to grow between 2 to 3 percent a year in our service area during the remainder of the 1980s and 1990s. The Bath County Pumped Storage Project and North Anna Unit 3, our fifth nuclear unit which is now under construction, will give us the means of meeting pro-jected demand growth through 1991,
with adequate reserves. We initiated in 1981 a major three-year study of two conventional and a dozen non-conven-tional means of meeting or reducing growth in power demand tor the rest of the 1990s. The study will help us to identity the lowest cost means of meeting or reducing our future power demand.
Reducing Financial Burden We also made significant progress in 1981 in decreasing the financing burden of our current construction projects at Bath and North Anna.
Vepco agreed to sell 20 percent of the Bath County Project, and to sell or sell capacity of an additional 20 to 30 per-cent of the facility, to Allegheny Power System, Inc. (APS). Subject to obtain-ing all regulatory approvals, we would receive an initial payment of approxi-mately $190 million.
The Company also agreed in princi-ple to sell portions of our North Anna Power Station to the Old Dominion Electric Cooperative. It the sale is completed by the mid-1982 target date, we will receive about $300 mil-lion tor the existing facilities, and about
$500 million in the future as Old Do-minion's share of future costs of North Anna Unit 3.
Rate Decisions In 1981, we obtained rate increases amounting to $222 million on an an-
nual basis. While we did not achieve all we hoped for, there were significant gains.
Our Virginia service area accounts
- for 1.3 million retail customers and 85 percent of our revenues. In August, the State Corporation Commission granted $132 million of the $190 mil-lion we requested and authorized a 15 percent return on equity with an oppor-tunity for 15.5 percent, if certain condi-tions are met.
We do not consider this an ade-quate return in view of current eco-nomic circumstances, but it improves upon the 13.5 percent return that had been authorized since 1975. The com-mission confirmed that Vepco's can-cellation of North Anna Unit 4 was a prudent decision and authorized re-covery of the Company's investment and cancellation costs. The commis-sion also authorized the Company to earn cash income on additional expen-ditures for North Anna Unit 3 and other new projects commencing after September 1, 1981. This will lower Vepco's future external financing re-quirements.
The commission did not allow us to earn on the unamortized balance of the North Anna Unit 4 project, which was cancelled late in 1980. This was a particularly regrettable decision be-cause we strongly believe that Vepco's stockholders are entitled to a return on this investment.
The North Carolina Utilities Commis-sion in October granted a rate in-crease of $12.9 million, which was 78 percent of our request. The commis-sion also permitted the recovery over a 10-year period of costs associated with the cancellation of North Anna Unit 4, including the inclusion of the unamortized balance of such costs in the rate base. At the same time, the commission reduced our authorized return on equity to 1 O percent as a penalty for alleged substandard per-formance of fossil units in 1979. We considered an appeal, but decided that filing a new rate case in early 1982 was the quickest and best means of correcting this grossly inade-quate authorized return on equity.
On January 25, 1982, the Company filed a general rate increase for $20.5 million with a proposed 17.5 percent return on common equity.
Earnings Vepco has undertaken a number of programs that will have major long-term positive effects on earnings.
Though some of these programs will have a strong or moderate positive im-pact in the short term, the immediate effect of others on 1981 earnings was negative. These negative impacts, combined with high interest rates and a weak economy, resulted in Vepco's earnings dropping 16 cents per share, from $1.93 in 1980 to $1.77 in 1981.
We are confident, however, that our financial performance over a number of years will be improved for having taken these steps.
If the sale of a portion of the Bath County Project had been completed in 1981 it would have had a positive ef-fect on 1981 earnings of $3.3 million.
Assuming further regulatory approvals, we can still look forward to positive ef-fects from this sale in 1982 and beyond.
Vepco successfully sought authori-zation from the Virginia State Corpora-tion Commission to earn a cash return on expenditures for new projects and on additional expenditures for North Anna Unit 3 after September 1, 1981.
During the current year, this had a small positive effect. But in the long term it will have a strong positive im-pact by increasing cash flow and re-ducing financing requirements.
Two other Vepco actions-the can-cellation of North Anna Unit 4 and the planned sale of a portion of the North Anna Power Station to the Old Domin-ion Electric Cooperative-are having or will have short-term negative effects on earnings, which will become posi-tive impacts in the long term.
The failure of the Virginia State Cor-poration Commission to allow Vepco to earn on the unamortized balance of the investment in the cancelled North Anna Unit 4 hurt our earnings in 1981.
In the long term, however, the can-cellation will have a positive effect on earnings by reducing Vepco's external financing requirements.
Similarly, the sale of a portion of the North Anna Power Station will have a short-term negative impact on re-corded earnings as a result of the loss of sales which would otherwise be made to the Cooperative, and the loss of return on investment applicable to the facilities being sold to the Cooper-ative. But if the sale is completed in 1982, as hoped, Vepco will receive
$300 million initially and an estimated
$500 million during the remaining con-struction of North Anna Unit 3. This will allow us to reduce our financing requirements.
Our coal conversion program has a short-term negative impact because of
~fa,Z:,?n-./
0
":~~~s~~ Moore, Jr.
Chairman of the Board 3
the cost of financing the project. But these conversions provide immediate benefits to our customers by reducing fuel costs and they facilitate improved rate decisions over the longer term.
The major program we have under-way to improve our coal-fired units also has a negative immediate impact because of its cost. But these im-provements also will reduce fuel costs and improve our regulatory climate, thereby benefitting both customers and stockholders in the long term.
Three external factors also are af-fecting our current earnings and future prospects: high interest rates during much of 1981 ; changes in Federal tax law; and the condition of the economy.
High interest rates, combined with the sensitivity of a large share of Vepco's debt to short-term interest rate increases, produced interest costs
$56 million greater in 1981 than in 1980. If interest rates fall, there will be a positive effect on Vepco's earnings in 1982.
The accelerated depreciation provi-sions of the Economic Recovery Tax Act of 1981 had little impact this year, but in 1982 and beyond they will im-prove cash flow and indirectly benefit earnings. The new tax treatment of re-invested dividends beginning in 1982 will help us obtain additional capital.
Finally, Vepco's earnings were ad-versely affected in 1981 by the na-tional economic slowdown. Improve-ment in the national economy in the future will have significant positive ef-fects on the Company's sales and earnings.
We are confident for all these rea-sons that the long-term prospects for Vepco point to improved financial re-sults in the future. As evidence of that confidence, the Board in October in-creased the quarterly dividend by 2.5 cents per share to 37.5 cents per quarter for an indicated annual rate of
$1.50.
During the past several years, Vepco has been making the difficult transition into a new era of expensive energy. We now are positioned and organized to adapt promptly to new uncertainties. The progress we made in improving our power stations and operations in 1981 provide the basis for the improved financial performance we are confident will come in the years ahead.
~,.:::~
President
Financial Results Revenues Vepco's operating revenues in 1981 totaled $2.2 billion, up $42.1 million, or 2 percent over 1980. Our electric business generated $2,069.8 million, on sales of 39.9 billion kilo-watt-hours. Vepco's gas business gen-erated $92.1 million, a 31 percent in-crease over 1980.
The small increase in total operating revenues was the result of reduced fuel revenues, and a generally slug-gish national economy.
Expenses Total operating expenses were $1.7 billion, down $37.0 million, or 2 per-cent from 1980-primarily because of reduced fuel expenses. In 1981, fuel expenses, including purchased and in-terchanged power costs, were $845.0 million, down $171.0 million from 1980, a 17 percent decrease. We were able to achieve this reduction in fuel cost because of the increased nu-clear component in our total power generation mix, and generally stabiliz-ing prices in all fuels.
Earnings and Dividends Earnings were down 16 cents per share, from $1.93 in 1980 to $1.77 in 1981. However, the quality of earn-ings-the proportion of cash in re-corded earnings-was improved over 1980. The Company paid its holders of common stock dividends of $1.425 per share in 1981, compared with $1.40 per share in 1980. In October, 1981,
Vepco increased the quarterly com-mon stock dividend by 2.5 cents rais-ing the quarterly dividend from 35 cents to 37.5 cents, and the indicated annual rate to $1.50, compared to
$1.40 per share in 1980.
The following table shows the Com-pany's high and low sales prices of common stock, principally traded on the New York Stock Exchange, and dividends paid for the last two years.
1980 High Low Dividends First Quarter 123/a 9Ve
$.35 Second Quarter 12V.
931.
.35 Third Quarter 12 101/ 4
.35 Fourth Quarter 11 1/e 9%
~
$1.40 1981 High Low Dividends First Quarter 11 7/a 101/a
$.35 Second Quarter 123/a 10%
.35 Third Quarter 121/ 2 1031.
.35 Fourth Quarter 13Va 101/e
.371/,
$1.42 112 On December 31, 1981 there were 190,735 holders of record of the Com-pany's common stock.
Rate Relief The Company aggressively pursued rate relief in all of its major jurisdic-tions dl!ring 1981. With inflation rapidly escalating our maintenance and op-erating expenses, other than fuel costs, this additional rate relief was needed to improve our financial health, and to permit us to provide for future growth in demand and continued reliable service.
Rate increases granted in 1981 by regulatory authorities and negotiated with governmental customers total
$222 million on an annual basis.
- The Virginia State Corporation Com-mission granted rate relief of $131.8 million effective August 29. The com-mission's order established a return on equity in the range of 15 to 15.5 per-cent but set the level of return at 15 percent for the present. This was up from the 13.5 percent return on equity set in 1975, but below the 16.5 per-cent requested by Vepco. The com-mission allowed an overall return of 10.68 percent.
- The North Carolina Utilities Commis-sion granted a $12.9 million rate in-crease effective August 1, represent-ing 78 percent of Vepco's request. The commission's order authorized a re-turn on equity of 10 percent with an overall return of 9.37 percent. The de-cision permitted Vepco to earn a cash return on construction work in progress in the rate base through March 31, 1981 (1979 test year). The commission also approved the recov-ery over a 10-year period of costs as-sociated with the cancellation of North Anna Unit 4 and permitted the inclu-sion of the unamortized balance of such costs in the rate base.
- The West Virginia Public Service Commission granted the Company an increase of $2.4 million effective Janu-ary 1, 1981. The commission autho-rized an overall rate of return of 10.41 percent based on a 14.5 percent re-turn on equity.
- On August 26, the Federal Energy Regulatory Commission (FERG) ap-proved a settlement increase of $16.5 million effective January 14, 1981 for the Company's cooperative and municipal customers. This increase was attributable to the commercial op-eration of North Anna Unit 2.
- The FERG also allowed an increase of $38 million to go into effect Septem-ber 1, 1981, subject to refund. The Company's requested increase was based on an overall cost of capital of 11.01 percent, including 15 percent re-turn on common equity. On December 31, 1981, the Company filed with the FERG a proposed settlement with the 4
I cooperative and municipal customers for a combined increase of $32.4 million.
- Vepco's electric rates to a number of state, county and municipal custom-ers, and Federal government agen-cies, are established by negotiation rather than by regulation.
Large Federal government custom-ers, such as military installations and the General Services Administration (GSA), have agreed to abide by rate decisions rendered by the FERG for Vepco's municipal resale customers.
Accordingly, Vepco received an an-nual increase of $4.4 million effective January 14, 1981, attributable to North Anna Unit 2 going into service. Addi-tionally, these Federal customers be-gan paying a general increase of $8.4 million effective September 1, 1981,
subject to refund.
Vepco's rates for the National Aero-nautics and Space Administration (NASA) are established by separate negotiations. Agreement with NASA was reached in 1981 for an annual in-crease of $1.3 million.
Vepco still has many long-term con-tracts for electricity at extremely low rates with municipalities in Virginia.
Expiration of one of these contracts in 1981 resulted in an increase in reve-nues from the City of Richmond of
$6.4 million at an annual rate effective December 1, 1981. Between now and January 1, 1983, several other large municipal customers' long-term con-tracts will expire, resulting in a further increase of revenues of approximately
$15 million per year.
Vepco achieved a greatly improved energy supply mix in 1981 as a result of increased efficiency of its nuclear and fossil unit operations, combined with continuing oil-to-coal conversions.
In 1981, the Company's four nuclear units accounted for 41 percent of Vepco's total energy supply, versus 27 percent in 1980. Coal units provided 31 percent of the total energy supply mix in 1981. At the same time, oil-fired generation decreased from 19 percent of the total energy supply mix in 1980, to 8 percent in 1981.
This meant that the number of kilo-watt-hours produced by Vepco's coal-fired units increased 21 percent from 10.8 billion kilowatt-hours in 1980, to 13.1 billion kilowatt-hours in 1981.
Similarly, the energy output from Vepco's nuclear units increased 55 percent in 1981, from 11.5 billion kilo-watt-hours in 1980 to 17.8 billion in 1981 This increased nuclear component in the generation mix enabled Vepco to reduce its fuel expenses in 1981 by
$171.0 million-from $1,016.0 million in 1980 to $845.0 million in 1981. We are projecting a 47 percent nuclear component in the power generation mix for 1982, and consequently an-other reduction in total fuel costs.
Nuclear Units Surry Power Station Unit 1 returned to service on July 8, 1981, following completion of a massive construction project to replace its three steam gen-erators. By completing this project about two months ahead of schedule, Vepco reduced system fuel expenses by approximately $31 million. Vepco previously completed replacement of the steam generators in Surry Unit 2 in August 1980.
These replacement projects were necessitated by a problem that is ge-neric to nuclear units of the design employed at Surry, and one that still confronts many U.S. utilities. They were the first such replacements ever performed on commercial nuclear re-actors, and established a standard of engineering and construction excel-lence for other companies.
Both Surry units operated at high capacity factors in 1981. Capacity fac-tor is a measure of a generating unit's productivity. A generating unit operat-ing at full power every day of the year would have a capacity factor of 100 percent. This theoretical maximum Construction continues on North Anna Unit 3.
Units 1 and 2 are in service and performing at top capacity.
Current Operations cannot be attained in practice because nuclear units require periodic outages for maintenance and refueling.
Following the successful completion of the steam generator replacement, Surry Unit 1 operated at a capacity factor of 77 percent. Surry Unit 2 oper-ated at a capacity factor of 84 percent.
North Anna Units 1 and 2 also per-formed well during the year. North Anna Unit 2 achieved a capacity factor of 71 percent in 1981. North Anna Unit 1 was out of service from January 1 to April 1 O for scheduled refueling, re-quired seismic reanalysis of piping systems and replacement of a turbine rotor. Due to this outage, North Anna Unit 1 had a capacity factor of only 58 percent for the year. However, once it returned to service on April 10, the unit operated at a capacity factor of 82 percent to the end of the year.
Vepco's team of engineering, con-struction and operational personnel demonstrated considerable ingenuity and skill in achieving these levels of nuclear operations.
Although North Anna Unit 2 experi-enced failure of several main trans-formers in June and July 1981, Vepco operations and construction personnel turned this to advantage by accom-plishing many design modifications that had been scheduled for a planned fall maintenance outage. This allowed Vepco to cancel the fall outage, allow-ing uninterrupted operation which con-tributed significantly to the unit's high net operating capacity for the year.
During the outage on North Anna Unit 1 last winter, a turbine inspection revealed cracks in the discs of one of the low-pressure turbine rotors. Nor-mally, procuring and installing a re-placement rotor would take many months, adding significantly to the length of the outage. However, Vepco personnel quickly located a replace-ment rotor in Pennsylvania, and over-came unique transportation problems posed by the rotor's enormous size.
The Vepco team's resourcefulness al-lowed the turbine repairs to be com-pleted without affecting the duration of the outage.
Fossil Station Operations The centerpiece of Vepco's continu-ing program to improve the efficiency of its fossil stations is the conversion of four large coal-fired units from pres-surized to balanced draft combustion.
These conversions will increase the operating availability of these units, and will significantly reduce future maintenance costs.
These complex projects are most economically done in two phases. The first phase, consisting of modifications to existing equipment, was completed in 1981. The installation of new equip-ment to complete the conversion of all four units will be accomplished by 1983.
Power Group staff meeting including (left to right) E.A. Baum, A.L. Parrish, Ill, WC. Spencer, J. I. Oatts (top picture) and (below) J. H. Ferguson and R.H. Leasburg.
7
Electrostatic Precipitators To meet the stringent air quality stan-dards imposed in the 1970s, Vepco is installing new electrostatic precipita-tors or upgrading existing equipment to control particulate emissions from coal-fired units. Installation and testing of a new precipitator was completed at Chesterfield Unit 5 in 1980, and modi-fication of an existing precipitator was begun on Chesterfield Unit 6. Precipi-tator construction projects were under-way on six other coal units during the year. When this precipitator program is completed in 1984, it will allow Vepco to operate its coal-fired units at full power, increasing their efficiency and the amount of electricity they can generate.
Four additional precipitators are planned for units to be converted to coal by 1986.
During 1981, significant progress also was made in improving the cur-rent availability and reliability of the major coal-fired units in the system:
Mt. Storm Units 1, 2, and 3, and Ches-terfield Units 5 and 6.
These five units, with combined ca-pacity of 2.5 million kilowatts, showed a 4 percent increase in operating availability and a 5 percent decrease in forced outage rate in 1981 com-pared to 1980. Vepco's smaller fossil units also showed operational im-provement during the year, with a 7 percent increase in operating availabil-ity and a 3 percent decrease in the forced outage rate. This encouraging improvement over the year came as a result of both administrative adjust-ments and major investments in up-grading plant equipment.
Longwall Mining System Yet another significant improvement in Vepco's fossil operations in 1981 was the installation of a longwall mining system at our Laurel Run Mine, adja-cent to our Mt. Storm Power Station in West Virginia. This $6 million system, which went into service in September, three months ahead of schedule, cuts coal in 400-foot strips at a much faster rate than conventional mining tech-niques. During its four months of oper-ation in 1981, it produced an average of 833 tons of coal per eight-hour shift, an increase of almost 600 tons per shift over the old continuous mining system.
Coal Conversions Vepco is conducting the nation's larg-est program of converting oil-fired units to coal. On February 11, 1981,
Possum Point Unit 3 returned to ser-vice following conversion, the sixth oil-fired unit converted to coal since the The longwa/1 mining system greatly improved coal production at our Laurel Run Mine.
Company began the program in 1975.
These six units, with a total capacity of 1.6 million kilowatts, represent more than one-third of all the oil-to-coal con-versions in the country. With these six converted units burning coal instead of oil in 1981, Vepco was able to reduce fuel costs significantly by displacing millions of barrels of higher-cost oil.
In 1981, the Company added four more oil units-Portsmouth Units 1 and 2, and Possum Point Units 1 and 2-to the conversion program. These units, with a combined capacity of 345,000 kilowatts, will be converted from oil to coal early in 1986. When the entire conversion program is com-pleted in 1986, 14 units with a total ca-pacity of 2.5 million kilowatts will have been converted. This enormous shift from oil-fired to coal-fired units will save customers an estimated $1 bil-lion in fuel costs through 1986.
Price Performance The Company's continuing shift away from expensive oil-fired units to nu-clear and coal-fired units enabled it to reduce its average price per kilowatt-hour in 1981, to 6.08 cents compared to 6.13 cents in 1980. Over the same period of time, the average rate of in-flation as measured by the Consumer Price Index (CPI) increased 10.4 percent.
Over the next decade, we expect our rates to increase in line with, or less than, the CPI. This should have beneficial effects on our regulatory environment.
Conservation, Load Management and Cogeneration Conservation, load management and cogeneration can allow Vepco to delay the need for building costly new generating facilities. Building new gen-erating capacity is unattractive be-cause current regulation does not al-low full recovery of the cost of new capital.
Programs already underway in con-servation, load management and cogeneration reduced, or helped to meet, 100,000 kilowatts of demand in 1981. To step up those efforts, Vepco established on July 1, 1981, the Eco-nomic Development and Energy Serv-ices Department.
In addition to working with our cus-tomers, the new department assists state and local governments in the Company's service area in seeking new business and industry.emphasizing energy-efficient development that will result in as small an increase in de-mand as possible.
In 1981, the department initiated a Home Energy Audit Program using in-stant computer analysis to evaluate cost and effectiveness data for cus-tomers. This program was imple-mented in selected areas in each division in 1981, and will be expanded in 1982.
The Company also continued to per-form industrial and commercial energy audits for small and medium-sized firms that lack sophisticated energy management programs. These audits reduced Vepco's summer peak de-mand by an estimated 71,000 kilo-watts, and winter peak demand by 62,000 kilowatts.
Test programs for time-of-usage rates were continued. In these pro-grams, lower rates are charged for electricity used during off-peak peri-ods, thereby saving customers money and enabling Vepco to reduce its peak demand. Pilot direct load management programs that allow the Company to control customers' water heaters, and development of cogeneration potential with industrial customers that use process steam or produce combustible wastes. also were continued in 1981.
Transmission and Distribution During 1981, the Company expanded its Supervisory Control and Data Ac-quisition System (SCADA), a comput-erized system designed to localize and identify power outages. This system allows Vepco to restore service more rapidly, and reduce the manhours re-quired to make repairs.
The Commercial Operations group discusses Vepco's Energy Conservation Program (left to right) G.C. Headley, Jr., W Bugg, Jr., WL. Proffitt, R.C. Steele, Ill, and J.L. Causey 9
As the result of a spell of record-breaking temperatures in parts of Vepco's service area, a new summer peak load of 8,638 Mw was estab-lished on June 16, 1981. This ex-ceeded by 1.8 percent the previous peak of 8,484 Mw set in August of last year. The 1981 winter peak demand of 8,451 Mw set in January was sur-passed on January 12, 1982, when a new winter peak of 8,879 Mw occurred.
Projected future growth in load un-der normal weather conditions is the major factor determining the need for new capacity. Variations in load as a result of extreme weather are one of the factors that must be considered in setting capacity reserve margins re-quired for reliable service.
Unless it is constrained by demand-reducing programs, peak demand in Vepco service territory is expected to grow between 2 to 3 percent a year through the mid-1990s. By the year 1995, peak demand for electricity will increase by nearly 3.0 million kilowatts compared to its level in 1981.
We anticipate winter loads will grow at a faster rate than summer loads be-cause electric space heating in the Vepco service area is expected to in-crease further from its current 25 per-cent to 34 percent in 1990. This is ex-pected to produce a balance of winter and summer peaks by the mid-1980s.
The balance in peaks will improve the load factor of our generating equip-ment. Load factor is the ratio of aver-age use, during a specified time inter-val, to the peak use during the same interval.
Bath County and North Anna Unit 3 To meet part of the forecasted in-crease in demand, Vepco now has un-der construction the Bath County Pumped Storage Project, with 2.1 mil-lion kilowatts of capacity. If the agree-ment to sell part of the Bath County capacity to APS is approved (see Fi-nancial Support), Vepco's share will be 1.05 million to 1.26 million kilowatts.
The Bath County Project is now 60 percent complete. Three of six units are scheduled to go into service in late 1985, and the remaining three units in mid-1986. When it is completed, Bath County will be the world's most power-ful pumped storage facility, and will give Vepco an economical means of meeting daily peaks in power demand.
Steel linings are being installed in tunnels which will carry water from upper to lower reservoirs at Bath County Pumped Storage Station.
Meeting Future Demand The Company also is building North Anna Unit 3, its fifth nuclear unit. This unit is scheduled to go into service in 1989 with 907,000 kilowatts of capac-ity. Construction on the project, which was slowed in 1979 while the Com-pany reassessed its entire construc-tion program, will be reintensified in 1982. Construction of North Anna Unit 3 was approximately 8 percent com-plete by year's end, with work under-way on major structural support sys-tems for the basic foundation design.
During 1981, Vepco assumed project management responsibilities from the general contractors on the Bath County Project. Vepco had previ-ously assumed these responsibilities on the North Anna Unit 3 Project in 1980. The Company also negotiated a new engineering and design services contract on North Anna Unit 3, which took effect on October 1, 1981. These steps will afford Vepco significantly in-creased flexibility and control over en-gineering as well as the construction of both projects.
With these two projects providing approximately 2 million kilowatts of ad-ditional capacity to the Vepco system by 1989, the Company will have the means to meet projected demand growth through 1991 with a reserve margin of about 25 percent.
However, the Company is faced with the decision of how best to meet the additional demand of almost 3 mil-lion kilowatts between 1992 and the end of the century.
Alternative Energy Sources The Company initiated in November 1981 a 3-year study to compare a dozen non-conventional and two con-ventional means of meeting or reduc-ing projected future growth in electric-ity demand.
The study will investigate the pos-sibilities for increased conservation, load management and cogeneration. It also will evaluate the use of solar units in homes and businesses, low-head hydro, wind turbines, fuel cells, com-bined cycle systems, solar photovol-taic cells, and three non-conventional fuels: peat, municipal waste and wood.
These non-conventional options will be compared with each other, and with conventional coal and gas genera-tion, to determine the lowest cost method of meeting projected demand.
Because of the time required to build and license conventional generating 1 stations, if they prove to be the best choice, the decision on how to pro-ceed must be made no later than 1985.
These options include deliberate measures to reduce demand below the levels being forecast. Vepco al-ready has conservation, load manage-ment and cogeneration programs that are expected to reduce 1989 power demand by more than 360,000 kilowatts.
Alternate Energy Study meeting including (left to right) W L. Proffitt, G. C.
Headley, WN. Thomas, Irene M. Moszer, M.L. Brehmer and J. H. Ferguson (below left).
11 Reviewing construction of electrostatic precipita-tors at Chesterfield Power Station are (left to right)
A.L. Parrish Ill, S.C. Brown, Jr. and WC. Spencer.
In 1981, Vepco raised a total of
$421.7 million in outside capital, in-cluding $181.0 million in term loans,
$138.0 million in First and Refunding Mortgage Bonds, $47.3 million in Bath County Hydroelectric Trust Funds and
$55.4 million of common stock sales and subscriptions, to finance its 1981 construction program. It also entered into agreements for the sale of por-tions of the Bath County Project and the North Anna Power Station, includ-ing North Anna Unit 3 which is now under construction. These sales would enable the Company to reduce sub-stantially its future financing requiremen Bath County Project Sale Vepco and APS signed an agree-ment in principle on June 19, 1981, for the sale of a portion of the Bath County Pumped Storage Project to APS. The agreement is subject to the approval of Federal and state regula-tory agencies, which we hope to re-ceive in 1982.
The Company agreed to sell 20 per-cent of the Bath County Project, and to sell or sell capacity of an additional 20 to 30 percent of the facility, to APS.
Subject to obtaining necessary regula-tory approvals, Vepco would receive about $190 million from APS for the 20 percent ownership interest. Subse-quently, the Company would receive about $143 million from APS as re-imbursement for future expenditures. If APS chooses to increase its interest in Bath County to 40 percent, Vepco's share of the project costs would be re-duced by about an additional $300 mil-lion. All state regulatory approvals have been obtained except for Penn-sylvania and Maryland. In Maryland, hearings have been completed and a decision is pending. In Pennsylvania, hearings on a show cause order are presently scheduled to begin in early March, but this schedule is in dispute.
The Company cannot predict the out-come or timing of these proceedings, but would hope to close the sale later in 1982.
North Anna Sale On October 21, 1981, after nearly 7 years of negotiation, Vepco agreed in principle to sell portions of its North Anna Power Station to Old Dominion Electric Cooperative.
The agreement calls for the cooper-ative to purchase 25 percent of North Anna Unit 2, 18 percent of North Anna Unit 3 which is now under construc-tion, and 12.5 percent of the common facilities at the North Anna Power Sta-Transmission lines span the Rappahannock River.
, Financial Support tion. Under terms of the agreement Old Dominion would pay Vepco ap-proximately $300 million for existing facilities to be purchased by Old Do-minion if a mid-1982 target date for compl~ting the agreement is met. Sub-sequently, Old Dominion would pay its proportionate share of the on-going construction costs of North Anna-about $500 million-as well as propor-tionate shares of operating and main-tenance costs.
The final agreement is subject to ap-proval by the Virginia State ~orpora-tion Commission, the West V1rg1rna Public Service Commission, the Nu-clear Regulatory Commission (NRG),
the FERG and REA.
Stock Sales Vepco sold 2 million shares of com-mon stock on September 9, 1981, to a limited number of institutional investors
, represented by a single investment advisor. Proceeds to the Company were $22.3 million.
Customer Stock Purchase Plan In September 1981, Vepco issued 544 163 shares of common stock val-ued' at more than $6 million to more than 13,000 customers, who com-pleted the first year (1980-81 ) of the Company's Customer Stock Purchase Plan. This unique installment purchase plan devised by Vepco in 1980 has been adopted by a number of other companies.
The plan permits Vepco customers to avoid brokerage fees and select the amount of their monthly installment payments, which can be as little as
$1 O. More than 20,000 customers have enrolled in the 1981-82 plan.
Dividend Reinvestment Plan The Administration's 1981 tax pack-age includes several provisions that may be of long-term benefit to our
' stockholders and customers alike. For the individual stockholder, the new law provides an incentive to participate in automatic dividend reinvestment plans.
The first $750 of dividends ($1,500 if filing a joint return) received in the form of newly issued common stock from a qualified plan is not taxed as dividend income. Instead, the cost ba-sis for the stock received from the re-invested dividends would be zero.
When the stock, if held more than a year, is sold, the taxpayer would pay taxes at the capital gains rate. The.
change is effective for dividends paid after December 31, 1981.
Employee Relations Vepco made important _progres~ in improving employee relations during 1981. Several improvements and changes were implemented ba_sed on a Company-wide employee attitude survey and recommendations made by an employee task force in 1980.
To assist managerial development and improve supervisory sk!lls, the.
Company increased supervisory train-ing by 30 percent, with about 780 su-pervisors participating. In an effort to provide greater professional opportuni-ties for employees, reduce co~ts and achieve a higher level of quality con-trol, Vepco is reducing its use_ of cc:in-sultants, especially in the eng1n~~nng and construction area. Instead, 1t 1s as-signing employees to work with con-sultants and to take over the consul-tants' responsibilities when possible.
On March 20, 1981, Vepco became one of the first 1 O companies to re-ceive approval from the NR~ C?f its Nu-clear Security Personnel Tra1rnn_g and Qualifications Plan. The plan, with more than 200 security personnel qualified, was put into effect 2 years ahead of a deadline set by the NRG.
Senior Staff meeting including (left to right) J. T Rhodes, R.F Hill, C.M. Jarvis, E. L.
Crump, Jr., PG. Edwards and B.D. Johnson {pictured above).
Discussing financing plans are (left to righ t)_D. S. Bro/lier, L. R. Robertson, O.J.
Peterson, Ill, S.B. Robertson, and J.R. Frazier, Jr.
13
Vepco established on October 2, 1981, a separate gas division to con-duct its gas distribution operations in Tidewater Virginia, where it serves ap-proximately 120,000 gas customers in the Norfolk-Newport News area. This service territory extends from Virginia Beach to Williamsburg.
The division's new name is Virginia Natural Gas, and by mid-1982 will have about 415 employees.
The new division reflects the Com-pany's confidence in the continued growth of its gas business, and the corresponding need for managers and employees in the division to focus en-tirely on gas operations.
Prior to the reorganization, Vepco's gas and electric operations were man-aged jointly. While the reorganization will have no effect on gas rates in the short term, both customers and Vepco will benefit from the new structure in the long term.
Greater efficiency will be achieved in the gas business by a team of manag-ers and employees concentrating solely on its operations. The restruc-turing will allow the development of greater expertise in this component of Vepco's business, especially among those employees who formerly had responsibility for both gas and electric operations. Inevitably, it will enable Vepco to provide even better service to its gas customers, and will lead to improved financial results for the Com-pany by allowing more aggressive marketing of gas services.
The new division consists of two dis-tricts serving customers north and south of Hampton Roads. Vepco has purchased a 24-acre tract in Norfolk, as a site for the division headquarters, met shop and the Southern district office.
The Northern district operations will be based in a structure now under construction on a 13-acre site in New-port News. This building is scheduled fc completion by the late summer of 1982 Increased Sales After a period of stagnation in the 1970s when gas was in short supply, the gas business now is entering a new period of growth. The 1978 Natu-ral Gas Policy Act, which provided for eventual price deregulation of new natural gas by 1985, already has led to a major increase in supply. Gas in-dustry forecasts predict demand, par-ticularly in industrial and commercial M. N. Early and E. C. Keeling inspect Virginia Natural Gas facilities.
___J
Gas Operations markets, could increase dramatically as a result of oil displacement and new industrial growth.
The emerging strength of Vepco's gas market was demonstrated in 1981 by the growth in Gas Division sales.
Sales reached 19,738,000 mcf (thou-sand cubic feet), a 13 percent in-crease over 1980.
This growth was aided by the addi-tion of Owens-Illinois Corp. to the divi-sion's list of customers during the year. Using 600,000 met annually, Owens-Illinois is now the division's largest firm customer. Anheuser-Busch, an already well-established customer, tripled its gas usage in 1981, making it the largest interrupt-ible customer in the division system.
Total revenues amounted to $92.1 million in 1981, a 31 percent increase over 1980. Significant revenue in-creases were registered in all four of the division's customer classes: Resi-dential (19 percent); Commercial-firm (30 percent); Industrial-firm (88 per-cent); and Interruptible (56 percent).
Yorktown Conversion Vepco began conversion in 1981 of the Yorktown Power Station Unit 3 from an oil-fired unit to one which will burn a mixture of oil and gas. By the spring of 1982, 16 percent of this unit's fuel supply will be gas.
While the savings in fuel costs from this conversion will depend on future oil and gas prices, Vepco estimates that by converting Yorktown Unit 3 to a mixed oil-gas unit the Company will save customers $15 million in fuel costs in future years.
To accommodate the conversion, Vepco also began construction in 1981 of a 20-inch gas pipeline, which is scheduled for completion in the spring of 1982. When completed, the
$3.5 million pipeline will run 8 miles from the Lee Hall section of Newport News to the Yorktown Power Station.
Rate Case Results On June 30, 1981, the Company filed a request with the Virginia State Corporation Commission (SCC) for a 3.8 percent increase in gas revenue, or about $2.8 million on an annual ba-sis. The increase was based on a test year ending March 31, 1981. The Company also requested an increase in the rate of return on common equity from 13.5 percent to 16.5 percent.
On November 16, 1981, the com-mission granted a $2 million increase in revenue effective November 23, 1981, or about 71 percent of the re-quested amount. The rate increase raised the monthly bill of a typical space heating customer 1 percent, from $76.52 to $77.30. The sec in-creased Vepco's rate of return on common equity to 15 percent.
~
'1V1rg1rna
~
Narural
~ Gas Virginia Natural Gas Service Area 15
Virginia Natural Gas Operating Statistics 1981 1980 Operating revenues (thousands):
Residential.......................................
$ 42,036 35,323 Commercial and industrial.........................
49,539 34,411 Other............................................
514 522 Total gas operating revenues..................
$ 92,089 70,256 Population served at retail-estimated....................
981,000 971,000 Number of customers:
Residential.......................................
112,220 111,164 Commercial and industrial-firm..............
9,182 8,885 Interruptible......................................
69 59 Total gas customers..........................
121,471 120,108 Sales-Met (thousands)...............................
19,738 17,495 Output-Met manufactured (thousands).................
244 57 Mcf natural gas purchased (thousands).........
20,755 18,906 Miles of main.........................................
2,123 2,108 Maurice L. Gamel/, M.N. Early and E. C. Keeling in Virginia Natural Gas Control Room.
Years 1979 29,380 25,346 655 55,381 875,000 109,902 8,718 36 118,656 16,307 74 17,499 2,095 1978 1977 30,621 26,640 20,000 17,981 418 302 51,039 44,923 875,000 875,000 110,390 111, 188 8,861 9,035 37 39 119,288 120,262 15,303 15,065 236 650 16,407 15,448 2,096 2,099 Construction of Virginia Natural Gas pipeline will facilitate partial conversion to gas at the Yorktown Power Station.
~ - -
17 1981 Financial Report Virginia Electric and Power Company
Description of Business The electric business of the Company is conducted in most of Virginia and Company (Virginia Natural Gas) provides gas service in the Norfolk-in parts of North Carolina and West Virginia. In its service area it sells Newport News area (except Portsmouth) and in the area extending from electricity to retail customers (including governmental agencies), and at Newport News to and including Williamsburg.
wholesale to rural electric cooperatives and municipalities. A division of the Selected Financial Data Millions of Dollars (except per share amounts) 1981 1980 1979 1978 1977 Operating revenues....................................
$2,162
$2,120
$1,703
$1,465
$1,359 Operating income......................................
469 390 316 305 265 Balance for common stock..............................
181 184 141 150 142 Earnings per share of common stock....................
1.77 1.93 1.63 1.88 1.92 Dividends paid per share of common stock...............
1.425 1.40 1.38 1.30 1.24 Total assets...........................................
7,058 6,511 5,961 5,211 4,802 Net utility plant........................................
6,013 5,586 5,229 4,686 4,305 Long-term debt and preferred stock subject to mandatory redemption......................
3,487 3,216 2,941 2,681 2,407 Management's Discussion and Analysis of Financial Condition and Results of Operations LIQUIDITY. Since the Arab oil embargo in 1974, the Company has experienced -internal cash generation below the desired levels. More recently, the substantial increases in the use of fossil fuels and replacement power for unantici-pated nuclear unit outages and for the steam generator repairs to Surry Nuclear Units 1 and 2, delays in obtaining recovery of these increased costs in rates and increased financing costs have offset to some extent the effect of substantial rate increases.
As a result of several reductions in projected load growth, together with escalating construction costs, financing con-straints upon the Company and regulatory constraints upon nuclear power, the Company has canceled three nuclear units and deferred in-service dates for one other nuclear unit and six pumped storage units since 1974. In spite of the cancellations and deferments, construction expenditures during this period have required substantial sales of securi-ties.
Internal cash generation during 1982 will be affected not only by the availability of the Company's nuclear generating 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 expenditures, the outcome of rate proceedings and the possible consummation of plans to sell a portion of the Bath County Pumped Storage Project and North Anna Station (see Capital Resources below).
Liquidity for electric utilities like the Company, which 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 designed to fund total construction costs for future generating capacity.
CAPITAL RESOURCES. The 1982 capital requirements result principally from the estimated $799 million of capital expenditures and $95 million of refunding and mandatory cash sinking fund obligations of long-term debt and Pre-ferred Stock. The Company presently expects that approxi-mately 56% of these capital requirements will be obtained from internal sources, about 21 % from the sale of a portion of the Bath County Pumped Storage Project (discussed below) and the remainder will be financed through sales of 18 securities of various types, with the long-term objective of achieving and maintaining capitalization ratios in the range of 52% long-term debt, 13% Preferred and Preference 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
$416 million.
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 have permitted the issuance at December 31, 1981 of $607 million of additional Bonds assuming an interest rate of 16.5% for additional 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 regula-tory and environmental costs, further changes in the rate of growth in peak demand, licensing and construction delays, results of rate proceedings and the possible consummation of sales of certain facilities.
On October 21, 1981, the Company agreed in principle with Old Dominion Electric Cooperative (ODEC) on the major terms of an arrangement for the purchase by ODEC of an ownership interest of 25% in North Anna Unit 2, 18% in North Anna Unit 3 and 12.5% in common facilities. The members of ODEC participating in this purchase arrange-ment are 12 Virginia cooperatives served by the Company at wholesale. The purchase is subject to the negotiation and execution of definitive agreements and to the receipt of required regulatory approvals. If definitive agreements can be reached and the necessary approvals are granted in 1982, the Company would receive approximately $300 million for existing facilities, and ODEC would pay its propor-tionate share of future costs of the North Anna Station. No assurance can be given that negotiations will be completed and the necessary regulatory approvals obtained.
The Company and Allegheny Power System, Inc. (APS) have signed agreements for sale of a part of the Bath County
Pumped Storage Project ($762 million invested through December 31, 1981 ). Under the agreements, APS is to pur-chase first an undivided interest of approximately 20%
in the Project. APS is to fulfill the remainder of its 40%
obligation through further purchases of undivided interests in the Project or through a capacity purchase agreement. Also, APS will be entitled to increase its 40% obligation up to 50%
before December 31, 1984.
The agreements are subject to receipt of required regula-tory approvals. After obtaining those approvals, the agree-ments provide for APS to pay approximately 20% of the Project's cost incurred through a closing date (anticipated to be during the first quarter of 1982) and to continue to pay approximately 20% of ongoing construction costs through part of 1984 (based on the present construction schedule). If the total Project costs exceed the present estimate, APS would not be obligated to pay for any portion of the excess, but if APS does not pay its proportionate share of such excess costs, its ownership interest would be correspond-ingly reduced. The Company estimates that it will receive about $190 million in cash for the acquisition by APS of an approximate 20% ownership interest, calculated on the basis of a first quarter 1982 closing. The Company would receive additional cash reimbursements for future expendi-tures, a reduction in its capital requirements or a combina-tion of both, in the amount of about $143 million for APS's acquisition of this 20% ownership interest. In addition, if APS elects to increase its ownership interest to 40%, the Compa-ny's share of the Project costs would be reduced by about an additional $300 million.
If the necessary regulatory approvals are not received in order to consummate the sale as planned, the Company may reduce its capital expenditures for 1982, including Project expenditures, or obtain additional financing, or a combination of the foregoing, to cover any delay in receipt or failure to receive the proceeds from the sale to APS. If Project expenditures scheduled for 1982 were significantly reduced, the in-service dates for the Project would likely be deferred. A deferral for one year in the in-service dates for the Project (total cost presently estimated at $1.7 billion) could result in additional Project costs of $300 million or more.
RESULTS OF OPERATIONS. Due to the effects of infla-tion, delays in obtaining a nuclear unit license, unscheduled outages of nuclear and coal fired units, rapidly escalating costs of oil, major maintenance and repairs at most of the fossil units, increased depreciation and maintenance associ-ated with additional power station units placed in service and increased costs of capital and capital expenditures, ex-penses have risen substantially during the past several years, and as a result, the Company has been granted substantial rate increases during these years.
After giving effect to the adjustments discussed in Note N to Financial Statements for the reduction in the provision for Federal income taxes resulting from the refund made to FERG jurisdictional customers and the refinement in the Company's method of amortizing investment tax credits, the balance for Common Stock decreased $3. 7 million from 1980 to 1981. The decrease reflects the loss of allowance for funds used during construction ("AFC") due to the cancellation of North Anna Unit 4 and the impact of inflation on operating and financing costs offset, in part, by additional revenues from rate increases, increased sales, decreased fuel costs and the termination of certain customers' con-tracts as discussed in Note N to Financial Statements.
19 Electric revenues changed from 1979 through 1981 princi-pally as a result of the following:
Rate increases and fuel cost recovery.
Unit sales (excluding effect of above)..
Other, net...........................
Total...............................
Revenues Increase (Decrease)
From Prior Year (Millions of Dollars) 1981
$(16.1) 35.2 1.1
$20.2 1980
$321.2 76.8 3.6
$401.6 Gas Revenues represent about 4.3% of total revenues. In 1981 the Company established Virginia Natural Gas, a new Gas Division. With the Company again permitted to connect new gas customers, substantial numbers of residential and significant industrial customers have been added. As a result of increased sales to customers and deregulation of natural gas pricing, gas revenues should continue to increase in the future but not to a level that would be significant compared to electric operations.
Fuel and purchased and interchanged power expenses have fluctuated from 1979 through 1981 as a result of changes in fuel costs, increased sales and the availability of coal-fired generation purchased from neighboring utilities at a cost less than the Company's oil-fired generation. The average cost of fuel consumed per kilowatt-hour generated is shown below:
Nuclear.....................
Coal-Mt. Storm (mine-mouth)
-Other.................
Oil.........................
Total System................
Mills Per Kilowatt-hour 1981 1980 1979 6.52 21.80 22.18 57.31 17.77 8.09*
17.16 20.36 44.73 21.76 5.27 13.80 20.61 31.45 20.44
- Includes generation at North Anna Unit 2 priced at the cost of displaced fuel during preliminary operations. Actual costs were 6.19 mills per kilowatt-hour.
Kilowatt-hour output by energy source is shown below:
Nuclear.....................
Coal-Mt. Storm (mine-mouth)
-Other.................
Oil.........................
Purchased and interchanged Other.......................
1981 41%
13 18 8
19 1
1980 27%
13 12 19 27 2
1979 17%
17 10 33 19 4
100%
100%
100%
The Company plans to convert most of its oil-fired genera-tion to coal by the end of 1986. The Company has retired certain older and less efficient units (Chesterfield Units 1 &
- 2) and has placed 4 oil-fired units aggregating 474 Mw, in a non-operating cold reserve status and plans to convert these to coal.
Maintenance and depreciation expenses have increased since 1979 principally as a result of the addition of North Anna Unit 2 in December 1980, the Company's program for improvement of generating unit capability, and increased costs for labor and materials.
For information with respect to Federal income and other taxes see Notes B and D to Financial Statements.
Continuation of the Company's capital expenditures and the related financing together with increases in construction and nuclear fuel costs and changes in internally generated funds and costs of capital have resulted in increases in the amounts of interest charges.
AFC for other (equity) funds decreased in 1981 principally as a result of the cancellation of construction of North Anna Unit 4 in November 1980 and of the placing in service of North Anna Unit 2 in December 1980. As a result of approval by the Virginia Commission to discontinue AFC for Virginia jurisdictional customers on all new projects commenced after September 1, 1981 and to discontinue AFC on all expenditures for North Anna Unit 3 after that date, the amounts accrued in future years should decline further.
These reductions of AFC have been reflected in increased Virginia jurisdictional rates.
AFC for borrowed funds did not decrease in 1981 because of the effect of the Bath County Project Financing. De-creases in the accrual of AFC-borrowed in future years as a result of the discontinuance of AFC applicable to Virginia jurisdictional customers will be offset to some extent by this project financing, depending on the amounts and cost of borrowings.
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 billings.
An estimate of the effect of inflation measured by constant dollar accounting and current cost accounting for selected financial data is presented in Note O to Financial State-ments.
Report of Management The management of Virginia Electric and Power Company is responsible for all information and representations contained 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 reasonable 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 policies, an organizational structure designed to ensure appropriate division of responsibilities, careful selection and training 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 Company's accounting systems, procedures and internal controls, and the performance of tests and other auditing procedures sufficient to provide reasonable assurance that the financial statements neither are materially misleading nor contain material errors.
The Audit Committee of the Board of Directors, composed entirely of directors who are not officers or employees of the Company, meets periodically with the independent auditors, the executive manager-internal auditing and management to discuss auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging 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, 1981 and 1980, 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, 1981. 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 opinion, the financial statements referred to above present fairly the financial position of Virginia Electric and Power Company as of December 31, 1981 and 1980, 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, 1981, in conformity with generally accepted accounting principles applied on a consistent basis.
New York, New York February 3, 1982 COOPERS & LYBRAND 20
Virginia Electric and Power Company Statements of Income Operating revenues (Notes A and K)
Electric..........................................
Gas.............................................
Total........................................
Operating expenses:
Operation:
Fuel used in electric generation (Notes A and E).....................................
Purchased and interchanged power..............
Other (Note E).................................
Maintenance (Note A).............................
Depreciation (Notes A and F)......................
Amortization of abandoned project costs (Note C).......................................
Taxes-Federal income (Notes A and B)............
-Other (Note D)............................
Total........................................
Operating income.....................................
Other income:
Allowance for other funds used during construction (Note A)...........................
Miscellaneous, net (Note N)........................
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.
1981
$2,069,764 92,089 2,161,853 555,466 289,558 309,147 138,147 174,120 12,203 93,669 120,911 1,693,221 468,632 44,264 16,236 (7,607) 52,893 521,525 280,012 44,276 (40,543) 283,745 237,780 57,166
$ 180,614 101,856
$1.77
$1.425 The accompanying notes are an integral part of the financial statements.
21 Years 1980 1979 1978 1977 (Thousands of Dollars)
$2,049,518
$1,647,928
$1,413,866
$1,313,937 70,256 55,381 51,039 44,923 2,119,774 1,703,309 1,464,905 1,358,860 674,996 559,998 585,625 575,151 341,011 194,547 9,384 52,273 250,848 210,840 183,906 153,514 123,962 103,856 90,317 69,885 145,032 136,280 117,481 98,527 6,933 7,292 6,760 3,173 70,004 69,744 72,658 59,736 117,456 104,358 93,499 81,174 1,730,242 1,386,915 1,159,630 1,093,433 389,532 316,394 305,275 265,427 73,206 66,603 64,002 72,361 2,973 1,282 2,209 (305)
(550)
(308)
(867)
(358) 75,629 67,577 65,344 71,698 465,161 383,971 370,619 337,125 234,561 204,392 184,947 168,885 28,530 12,417 6,677 5,748 (39,550}
(29,305)
(24,869)
(27,301}
223,541 187,504 166,755 147,332 241,620 196,467 203,864 189,793 57,291 55,123 53,588 47,719
$ 184,329
$ 141,344
$ 150,276
$ 142,074 95,520 86,965 80,060 74,025
$1.93
$1.63
$1.88
$1.92
$1.40
$1.38
$1.30
$1.24
Virginia Electric and Power Company Balance Sheets Assets December 31, 1981 December 31, 1980 (Thousands of Dollars)
UTILITY PLANT (Note A):
Electric.............................................
Gas................................................
Common...........................................
Total (includes $1,618,880,000 plant under construction [1980-$1,451,292,000]).
Less accumulated depreciation (Note F).............
Nuclear fuel (less accumulated amortization of
$210,879,000 [1980-$131,321,000])................
Net utility plant..............................
INVESTMENTS:
Nonutility property at cost or written-down amounts (less allowance of $7,657,000
[1980-$7,546,000])...............................
Subsidiary companies at equity (includes advances of $14,758,000 [1980-$13,659,000])(Notes A and M)...........................................
Net investments.............................
CURRENT ASSETS:
Cash (Note I).......................................
Temporary cash investments.........................
Accounts receivable:
Customers........................................
Other.............................................
Less allowance for doubtful accounts..........
Accrued unbilled revenues............................
Materials and supplies at average cost or less:
Plant and general (including construction materials).......................................
Fossil fuel........................................
Prepayments:
Taxes............................................
Other.............................................
Total current assets..........................
DEFERRED DEBITS:
Abandoned project costs (less ac-cumulated amortization of $36,361,000 [1980-
$24, 158,000])(Note C).............................
Deferred fuel costs (Note A)..........................
Deferred interest charges (Note A)....................
Pollution control project funds.........................
Unamortized expense on debt........................
Other...............................................
Total deferred debits.........................
$186,665 25,560 212,225 2,002 76,924 129,557 28,964 18,712 The accompanying notes are an integral part of the financial statements.
22
$7,032,549 75,949 22,918 7,131,416 1,263,867 5,867,549 145,339 6,012,888 5,472 21,282 26,754 16,669 210,223 93,551 206,481 47,676 574,600 193,112 137,000 22,740 37,667 8,971 44,099 443,589
$7,057,831
$181,745 20,050 201,795 1,360 55,515 130,203 32,959 11,806
$6,445,405 66,289 16,892 6,528,586 1,118,308 5,410,278 176,187 5,586,465 6,327 19,851 26,178 26,290 8,500 200,435 83,123 185,718 44,765 548,831 172,720 78,104 19,818 45,570 8,754 25,053 350,019
$6,511,493
Capital and Liabilities December 31, December 31, 1981 1980 (Thousands of Dollars)
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
$100 par, cumulative (Note G)................................................
$ 326,927
$ 328,911 PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION-
$100 par, cumulative (Note H)................................................
289,014 289,014 PREFERENCE STOCK NOT SUBJECT TO MANDATORY REDEMPTION-no par, cumulative; authorized 30,000,000 shares (Note H)......................
57,360 57,360 COMMON STOCKHOLDERS' EQUITY (Note H):
Common stock-no par..........................................................
1,457,072 1,400,874 Other paid-in capital..............................................................
24,516 25,352 Earnings reinvested in business, as annexed.......................................
470,888 435,430 Total common stockholders' equity.................. *......................
1,952,476 1,861,656 LONG-TERM DEBT (Note J).......................................................
3,160,014 2,887,114 CURRENT LIABILITIES:
Securities due within one year (Notes G and J).....................................
94,983 124,276 Loans payable, pending permanent financing (Note I)...............................
164,938 83,721 Accounts payable, trade..........................................................
87,742 111,674 Customer deposits...............................................................
14,424 11,884 Payrolls accrued.................................................................
16,611 13,498 Taxes accrued..................................................................
74,730 53,606 Interest accrued.................................................................
83,192 76,501 Deferred income taxes (Notes A and B)............................................
14,313 14,856 Other...........................................................................
89,263 80,826 Total current liabilities....................................................
640,196 570,842 DEFERRED CREDITS:
Uranium settlement (Note M).....................................................
160,914 142,172 Accumulated deferred income taxes (Notes A and B):
Liberalized depreciation........................................................
203,714 149,867 Abandoned project costs.......................................................
73,384 63,514 Other.........................................................................
34,591 26,040 Deferred investment tax credits (Notes A and 8)....................................
109,647 106,808 Other (Note E)..................................................................
49,594 28,195 Total deferred credits....................................................
631,844 516,596 COMMITMENTS AND CONTINGENCIES (Note M)
$7,057,831
$6,511,493 23
Virginia Electric and Power Company Statements of Earnings Reinvested in Business 1981 Balance at beginning of year............................
$435,430 Net income (see "Statements of Income")................
237,780 Total.........................................
673,210 Cash dividends:
Preferred stock subject to mandatory redemption:
$7.325 preferred...................................
5,128
$8.40 preferred....................................
6,720
$9.125 preferred...................................
1,807
$8.20.preferred....................................
4,920
$8.60 preferred....................................
3,087
$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 prefe*rred....................................
62
$4.12 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......................................
144,937 Total dividends..............................
202,107 Transfer to common stock as authorized by Board of Directors...................................
Other deductions, net..................................
215 Total.......................................
215 Balance at end of year.................................
$470,888 The accompanying notes are an integral part of the financial statements.
24 Years 1980 1979 1978 1977 (Thousands of Dollars)
$384,600
$364,215
$318,507
$328,115 241,620 196,467 203,864 189,793 626,220 560,682 522,371 517,908 5,128 5,128 5,128 5,128 6,720 6,720 6,720 6,720 1,825 1,825 1,825 1,825 4,920 4,920 4,920 1,134 3,189 3,291 3,392 3,191 3,191 1,785 2,499 153 533 533 533 1,447 52 52 52 404 62 62 62 420 134 134 134 515 351 351 351 1,440 2,702 2,702 2,702 2,702 3,094 3,094 3,094 3,094 2,980 2,980 2,980 2,980 3,240 3,240 3,240 3,240 3,860 3,860 3,860 3,860 5,850 5,850 5,850 5,850 6,960 6,960 6,960 6,960 133,005 120,638 103,474 91,225 190,295 175,684 157,062 138,944 60,000 495 398 1,094 457 495 398 1,094 60,457
$435,430
$384,600
$364,215
$318,507
Virginia Electric and Power Company Statements of Changes in Financial Position Years 1981 1980 1979 1978 1977 (Thousands of Dollars)
SOURCE OF FUNDS:
Funds provided by operations:
Net income.......................................
$ 237,780
$241,620
$ 196,467
$203,864
$189,793 Items not affecting working capital:
Provision for depreciation (Notes A and F).........
174,120 145,032 136,280 117,481 98,527 Amortization of nuclear fuel (Note A)..............
79,558 52,170 25,576 29,702 14,526 Amortization of abandoned project costs (Note C)...
12,203 6,933 7,292 6,760 3,173 Allowance for other funds used during construction (Note A)..........................
(44,264)
(73,206)
(66,603)
(64,002)
(72,361)
Allowance for borrowed funds used during construction (Note A)..........................
(40,543)
(39,550)
(29,305)
(24,869)
(27,301)
Deferred income taxes (Notes A and B)............
72,226 52,177 66,545 14,668 31,536 Deferred investment tax credits, net (Notes A and B)...............................
6,711 6,627 (5,250) 34,827 19,009 Total funds provided by operations............
497,791 391,803 331,002 318,431 256,902 Funds provided by financing and other sources:
Mortgage bonds (Note J)...........................
138,000 75,000 235,000 213,000 150,000 Preferred stock subject to mandatory redemption (Note G)........................................
28,000 37,000 60,000 Common stock (Note H):
Public offering...................................
22,290 53,950 64,050 68,275 70,400 Automatic dividend reinvestment plan..............
18,387 16,379 12,926 11,690 9,229 Employee savings plan and TRASOP..............
7,975 6,261 7,222 4,774 4,213 Customer stock purchase plan subscriptions.......
6,701 2,474 Bath County hydroelectric trust (Note J).............
47,340 201,810 Term notes (Note J)...............................
181,000 125,000 60,000 104,750 108,500 Pollution control project funds.......................
7,903 (37,734) 3,914 (8,019)
(721)
Increase (decrease) in loans payable................
81,217 (48,009) 128,293 (49,613) 26,550 Uranium settlement (Note M)........................
18,742 11,826 130,346 Total funds provided by financing and other sources.............................
529,555 406,957 669,751 381,857 428,171
$1,027,346
$798,760
$1,000,753
$700,288
$685,073 APPLICATION OF FUNDS:
Utility plant expenditures (excluding AFC)..............
$ 542,331
$536,049
$ 551,881
$422,857
$394,875 Nuclear fuel (excluding AFC).........................
49,157 32,315 60,967 17,458 74,531 Abandoned project costs (Note C).....................
32,595 1,332 (2,542) 2,631 16,050 Dividends on common, preferred and preference stocks.
202,107 190,295 175,684 157,062 138,944 Increase (decrease) in deferred fuel costs (Note A)..........................................
58,896 (11,146) 85,867 (29,898)
(18,812)
Increase (decrease) in deferred interest charges (Note A) 2,922 5,357 11,907 2,553 (3,078)
Securities reacquired or repaid........................
124,276 65,300 74,883 97,273 58,250 Increase (decrease) in investment (net of repayment of advances) in subsidiary companies (Notes A and M)..
1,431 (372) 797 4,345 3,137 Increase (decrease) in working capital other than loans payable*....................................
8,339 (31,757) 42,136 36,551 14,684 Other, net...........................................
5,292 11,387 (827)
(10,544) 6,492
$1,027,346
$798,760
$1,000,753
$700,288
$685,073 Changes in the individual amounts comprising working capital other than loans payable* were as follows:
Accounts receivable...............................
9,788
$ 38,537 33,842
$ 17,215 1,687 Uranium settlement (Note M)........................
(41,000) 41,000 Accrued unbilled revenues..........................
10,428 (10,679) 32,395 (2,523) 4,965 Materials and supplies.............................
20,763 14,047 42,675 7,284 26,392 Accounts payable, trade............................
23,932 16,010 (73,271) 19,350 1,775 Taxes accrued....................................
(21,124)
(27,843) 8,027 (20,426)
(4,842)
Interest accrued...................................
(6,691)
(7,217)
(4,633)
(11,388)
(6,916)
Deferred income taxes (Notes A and B)..............
543 2,460 1,464 4,657 (2,537)
Other, net.................. *.......................
(29,300)
(16,072)
(39,363) 22,382 (5,840) 8,339
$ (31,757) 42,136
$ 36,551
$ 14,684
- Does not include reclassification as current liabilities of maturing long-term debt and cash sinking fund obligations of debt and preferred stock as follows: 1981-$94,983,000; 1980-$124,276,000; 1979-$62,093,000; 1978-$75,293,000; and 1977-$89,433,000.
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 Systems of Accounts promulgated by the regu-latory 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 labor, materials, services, allowance for funds used during construction and other indirect costs. The cost of deprecia-ble 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 appropri-ate utility plant account, except the cost of minor replace-ments which is charged to maintenance expense.
The present value of estimated decommissioning costs of
$134,624,000 for nuclear units in service (assuming moth-balling) is being charged to customers subject to the jurisdic-tion of the Virginia Commission. For the remaining jurisdic-tions, estimated decommissioning costs are being recorded on the straight-line depreciation method based upon esti-mated 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. Effective in 1978, the North Carolina Commission granted approval to recover the cost of perma-nent storage of spent fuel in base rates and the Federal Energy Regulatory Commission (FERG) allowed the recov-ery of these costs through the fuel clause. For periods subsequent to these two decisions, operating expenses include reprocessing costs for Virginia jurisdictional custom-ers, permanent storage costs for North Carolina jurisdic-tional customers and projection of interim storage costs only for FERG 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 Nuclear, 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 provision for Federal income taxes to reflect the tax benefit resulting from the use of the double-declining-balance method of depreciation for property additions, the adoptjon of the Asset Depreciation Range and Class Life Systems, and the adop-tion of the Accelerated Cost Recovery System. Effective with property additions placed in service in 197 4, the Company has provided deferred income taxes on the aforementioned benefit and, subsequently, has provided deferred taxes on other differences between book income and income taxable for Federal income taxes to the extent permitted by the regulatory commissions having jurisdiction.
26 Investment Tax Credits:
Accumulated investment tax credits are being amortized over the service lives of the property giving rise to such credits. An additional investment tax credit of 1 % related to the Tax Reduction Act Stock Ownership Plan (TRASOP) does not affect net income and is recorded as a liability until the contribution 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.
The Company separately determines rates and reports amounts applicable to borrowed funds, calculated on a net of tax basis, and to equity funds. In accordance therewith, for 1981, 1980, 1979, 1978 and 1977, aggregate rates of 8.06%, 7.79%, 7.80%, 7.54% and 7.75%, respectively, were employed for the accrual of AFC.
For expenditures on the Bath County Pumped Storage Project after December 31, 1979, AFC is being accrued in an amount equal to the net of tax cost of borrowings associated with the Project Financing.
In August 1981, the Virginia Commission granted rate relief of $131.8 million that included the Company's proposal to eliminate AFC on additional construction expenditures for North Anna 3 and on all new projects commencing after September 1, 1981.
Deferred Fuel Costs:
The Company is deferring for accounting and rate-making 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. 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.
Deferred Interest Costs:
The Company charges to operations an interest cost associated with variable interest rate loans based on the interest rate ceiling stated in the loan agreements. Amounts paid in excess of the amounts charged to operations are deferred pending refund from the applicable lending institu-tions.
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 1979 and changes in actuarial assumptions in 1977 are 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.
Reclassification:
Certain amounts in the 1980 financial statements have been reclassified to conform to the 1981 presentation.
B. Federal Income Taxes:
Details of Federal income taxes were as follows:
Years 1981 1980 1979 1978 1977 (Thousands of Dollars)
Computed tax expense on book income before Federal income taxes at statutory rate.............
$155,966
$143,600
$122,599
$133,147
$119,946 (Decreases) increases resulting from:
Excess of tax over book depreciation............
(14,354)
(12,982)
(4,301)
(16,402)
(9,956)
AFC.........................................
(39,011)
(51,868)
(44,118)
(42,658)
(47,838)
Investment tax credits, amortization*............
(8,843)
(5,171)
(5,820)
(5,467)
(4,539)
Other, net*...................................
(89)
(3,575) 1,384 4,038 2,123 (62,297)
(73,596)
(52,855)
(60,489)
(60,210)
Federal income tax expense........................
$ 93,669
$ 70,004
$ 69,744
$ 72,658
$ 59,736 Currently payable.................................
$ 14,732
$ 11,200
$ 8,449
$ 23,163
$ 9,191 Tax effects of timing differences:
Abandoned project costs.......................
9,870 38,582 (4,421)
(1,822) 31,175 Fuel related items:
Current year deferred fuel adjustment.........
19,149 (19,087) 47,054 (21,681)
(9,588)
Reprocessing/disposal costs on nuclear fuel....
(13,063)
(7,988)
(8,067)
(6,791)
(6,385)
Fuel expense nuclear plant testing............
(2,410)
(3,663)
Nuclear fuel-owned........................
5,572 (2,669)
(4,452)
(487)
Liberalized depreciation........................
53,847 41,108 32,418 38,509 13,101 Virginia gross receipts taxes....................
(1,429)
(2,460)
(1,464) 636 2,375 Nuclear decommissioning costs................
(994)
(764)
Spare parts inventory adjustment...............
(3,117) 4,120 Accelerated amortization.......................
(1,547)
(1,547)
(1,547)
(1,547)
(1,547)
Indirect construction costs......................
2,310 2,800 3,463 3,154 2,912 Cost of removal of property retirements..........
2,057 3,729 3,545 2,484 1,696 Customer accounts reserve....................
(812)
Variable prime interest........................
2,293 Contributions in aid of construction..............
2,203 (2,203)
Other........................................
500 16 16 10 72,226 52,177 66,545 14,668 31,536 Investment tax credits..............................
15,554 11,798 570 40,294 23,548 Investment tax credits, amortization*.................
(8,843)
(5,171)
(5,820)
(5,467)
(4,539)
Net deferred investment tax credits..............
6,711 6,627 (5,250) 34,827 19,009 Federal income tax expense........................
$ 93,669
$ 70,004
$ 69,744
$ 72,658
$ 59,736
- See Note N to Financial Statements for the effects on the 1981 provision for Federal income taxes of a rate refund and a change in amortization of investment tax credits applicable to nuclear fuel.
The Company has investment tax credit carry-forwards of $137,374,000, of which $6,885,000, $18,870,000, $63,372,000 and $48,247,000 will expire, unless used, in 1993, 1994, 1995, and 1996 respectively.
C. Abandoned Project Costs:
In March 1977, the Company canceled the construction of Surry Units 3 and 4, for which $98.2 million was expended at December 31, 1981. The Company amortizes such costs, net of Federal income taxes, over a ten-year period as incurred, for accounting and rate-making purposes.
In November 1980, the Company canceled the construc-tion of North Anna Unit 4 due primarily to reduced load growth projections, high financing costs, the uncertainty surrounding the regulation of nuclear power and the Compa-ny's load management programs which are estimated to result in a delay of additional generating capacity require-27 ments. Expenditures at December 31, 1981 amounted to
$127. 7 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 $154.5 million.
the Virginia and North Carolina Commissions approved the recovery of cancellation costs in base rates over a ten-year period, effective in August 1981 and October 1981 respec-tively. Additionally, the North Carolina Commission permit-ted the inclusion of the unamortized balance of such costs in rate base. The Company has requested similar rate-making treatment from the West Virginia Commission and the FERC.
D. Supplementary Income Statement Information:
The amounts of royalties, advertising costs and research than Federal income taxes charged to expenses were as and development costs were not significant. Taxes other follows:
Years 1981 1980 1979 1978 1977 (Thousands of Dollars)
Taxes, other than Federal income taxes:
Real estate and property........................ $ 33,577
$ 29,182
$ 28,462
$26,333
$25,257 State and local gross receipts....................
65,750 71,838 60,934 54,865 49,812 State income...................................
47 162 57 505 248 Other..........................................
21,537 16,274 14,905 11,796 5,857 Total.............................................. $120,911
$117,456
$104,358
$93,499
$81,174 E. Leases:
Rents charged to expenses consisted of the following:
Years 1981 1980 1979 1978 1977 (Thousands of Dollars)
Operating leases:
Nuclear fuel....................................
$38,989
$21,140
$11,632
$35,491
$29,518 Combustion turbines............................
5,451 5,524 5,611 5,694 5,935 Other (principally buildings and teleprocessing equipment)...................................
10,771 11,206 10,583 8,427 6,648 Total..............................................
$55,211
$37,870
$27,826
$49,612
$42,101 In 1971, the Company sold and leased back 28 combus-tion turbines for a term of 20 years (plus two optional five-year renewal terms). Annual rental payments are
$6,444,000 during the second ten year term. Additional rentals were accrued during the first ten years when pay-ments represented only interest, so that the annual effect on net income would be equalized over the twenty-year period.
Deferred credits other, at December 31, 1981, include
$19,828,000 with regard to such accruals. Had the lease been capitalized, the net asset value and present value of the lease commitment would be $20,591,000 and
$42,601,000, respectively, at December 31, 1981 and
$22,721,000 and $42,601,000, respectively, at December 31, 1980.
The Company has heat supply contracts for the nuclear fuel for Surry Units 1 and 2 providing for an aggregate commitment of $110 million at December 31, 1981. Quar-terly payments are charged to income in amounts sufficient to pay for the fuel burned during each quarter (excluding reprocessing and permanent disposal costs) plus interest.
Had the contracts been capitalized, the net asset value and present value of these commitments would be $98,930,000 F. Depreciation:
and $101,822,000, respectively, at December 31, 1981 and
$99,118,000 and $102,398,000, respectively, at December 31, 1980.
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 $35,565,000 and $39,490,000, respectively, at December 31, 1981 and $37,087,000 and $40,106,000, respectively, at December 31, 1980.
If the Company had capitalized the above noted leases and contracts, the increase in operating expenses 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.
The provision for depreciation based on mean depreciable plant has been as follows:
Electric Gas Common 1981 3.3%
3.1%
4.1%
1980 3.3 3.1 4.0 1979 3.3 3.1 4.4 1978 3.2 3.1 2.4 1977 3.1 2.6 2.3 28
G. Preferred Stock Subject to Mandatory Redemption:
Preferred Stock subject to mandatory redemption was represented by 3,289,104 shares outstanding at December 31, 1981, as follows:
Authorized and Outstanding Dividend Shares
$7.325 700,000 8.40 800,000 9.125 192,000 8.20 600,000(1) 8.60 347, 104(2,4) 8.625 370,000(3) 8.925 280,000(5)
Total 3,289, 104(6)
Less shares due with-in one year......
19,834(6)
Balance........... 3,269,270(7)
Amount
$110.00 115.00 107.00 115.00 107.00 108.63 108.93 Entitled Per Share Upon Voluntary Liquidation Redemption Through 3/31/83 3/31/84 9/19/86 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 September 1977. (2) Issued December 1977. (3) 355,000 shares issued in May 1978 and 15,000 shares issued in September 1978. (4) No voluntary redemption prior to December 20, 1982. (5) Issued November 1979. (6) Sinking Fund requirements call for annual redemption at $100 per share as follows:
Annual Sinking Annual Sinking Fund Requirements Fund Requirements Series Shares Beginning Ending Series Shares Beginning Ending
=---=----___;:;-
$8.60 8,000 Dec. 1978 Dec. 201 O $8.625 18,500 June 1984 June 2002 Sept. 2009 April 2009 9.125 11,834 Sept. 1981 Sept. 2000 8.925 10,500 Sept. 1984 8.20 30,000 Sept. 1983 Sept. 1996 8.40 32,000 April 1985 7.325 28,000 April 1984 April 2008 (7) Maturities through 1986 are as follows: 1982-$1,983,000; 1983-$4,983,000; 1984-$10,683,000; 1985-$13,883,000; and 1986-$13,883,000.
The total number of authorized shares for all Preferred share plus accrued dividends. Dividends are cumulative and Stock is 7,500,000 shares. Upon involuntary liquidation, all payable March 20,June 20, September 20 and December 20.
Preferred Stock shares are entitled to receive $100 per H. 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 not subject to mandatory redemption was represented by 2,890,140 shares outstanding at Decem-ber 31, 1981, as follows:
Authorized and Outstanding Shares Entitled Per Share Upon Voluntary Liquidation Redemption 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 106,677 12,926 14,797 32,534 73,206 350,000 350,000 400,000 450,000 500,000 600,000 2,890,140 Amount
$112.50 102.27 102.50 103.73 101.00 103.50 107.00 103.00 106.00 106.00 106.50 Preference Stock Not Subject to Mandatory Redemp-tion:
Through 5/31/84 8/31/82 2/29/84 1/31/82 9/30/82 2/28/86 And Thereafter To Amounts Declining In Steps To
$101.50 Thereafter 101.00 after 8/31/85 101.00 Thereafter 101.00 after 1/31/85 101.00 after 9/30/85 101.00 after 2/28/91 In 1975, the Company issued 2,400,000 shares of $2.90 Dividend Preference Stock at $23.90 per share which aggre-gated $57,360,000. The Preference Stock is redeemable at the Company's option and declines in steps to $25.25 on May 1, 1990. Upon liquidation, all shares are entitled* to receive $25 per share plus accrued dividends. Dividends are cumulative and payable March 20, June 20, September 20 and December 20.
29
Common Stock:
Common Stock was represented by 104,768,299 shares outstanding at December 31, 1981. In addition, 2,259,435 shares (based on the conversion price of $22.125 per share)
Dividend Reinvestment Year Public Offering and Customer Installment Plans Additions to Additions to Shares Capital Account Shares Capital Account 1981..... 2,000,000
$22,290,000 2,119,961
$25,097,483 1980..... 5,000,000 53,950,000 1,505,423 18,852,552 1979..... 6,000,000 64,050,000 1,049,874 12,925,755 1978..... 5,000,000 68,275,000 827,514 11,689,651 1977..... 5,000,000 70,400,000 626,886 9,229,553 are reserved for conversion of the 3%% Convertible Deben-tures due May 1, 1986. During the years 1977 through 1981 the following changes in Common Stock occurred:
Employee Savings and Stock Ownershie Plans Total Outstanding Additions to Shares Capital Account Shares Capital Account 694,181
$7,974,573 104,768,299
$1,457,072,496(1) 574,622 6,261,638 99,954,157 1,400,874,668(1) 583,138 7,222,482 92,874,112 1,319,303,162 337,143 4,774,135 85,241,100 1,235,104,925 284,167 4,212,884 79,076,443 1, 150,366, 139(2) 73, 165,390(3) 1,006,523,702 (1) Includes $835,772 and $2,507,316 of transfers from Other Paid-In Capital in 1981 and 1980,respectively.
(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, 1977.
On May 8, 1979, the number of authorized shares was increased from 95,000,000 to 120,000,000.
Other Paid-In Capital:
In 1977, the Company solicited tenders of shares of certain series of Preferred Stock in exchange for shares of
$8.60 Dividend Preferred Stock. 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 1981 and 1980, the Company transferred $836,000 and
$2,507,000, respectively, associated with $8.60 Dividend shares redeemed to the Common Stock account.
I. Short-Term Loans and Compensating Balances:
Year End 1981 Maturity Amount Commercial paper..............
(2)
$148,896,000 Master notes...................
(3) 9,542,000 Pollution control notes..........
(3) 6,500,000 1980 Commercial paper..............
(2) 72,003,000 Master notes...................
(3) 2,058,000 Pollution control notes..........
(2) 9,660,000 1979 Commercial paper..............
(2) 122,543,000 Master notes...................
(3) 6,937,000 Pollution control notes..........
(2) 2,250,000 (1) Weighted average interest.
(2) Principally 30 to 90 days.
Available bank lines of credit amounted to $415,975,000 at December 31, 1981, including $200,000,000 applicable to revolving credit agreements effective through August 30, 1985. The Company maintains compensating balances of up to 10% or pays fees in lieu of balances in connection with 30 Daily Average Outstanding Interest Rate At End Interest of Year(1)
Amount Rate(1)
Maximum Outstanding 13.61%
$184,608,000 16.60%
$279,395,000 12.75 2,965,000 14.26 18,237,000 9.55 5,781,000 8.81 9,660,000 18.25 155,772,000 13.54 280,525,000 15.00 3,520,000 10.47 12,300,000 7.26 5,177,000 7.09 9,660,000 14.25 69,736,000 11.03 175,750,000 12.25 3,520,000 9.98 6,937,000 7.25 203,000 7.25 2,250,000 (3) Maximum 180 days.
its lines of credit. Utilization under the lines of credit may require additional balances or fees. Compensation for the revolving credit agreements are consistent with the require-ments for the lines of credit.
J. Long-Term Debt:
Long-term debt outstanding at December 31, 1981:
First and refunding mortgage bonds(1 ):
Series J 3%%, due 1982.........
Series DD 10%%, due 1983........
Series K 3%%, due 1984........
Series L 3%%, due 1985.........
Series A 67/a%, due 1985........
Series M 4 Va%, due 1986........
Series N 4 %%, due 1987........
Series O 37/a%, due 1988........
1981 Series A 15%%, due 1989.....
Series P 4%%, due 1990........
Series Q 47/s%, due 1991........
Series R 4%%, due 1993........
Series S 4%%, due 1993........
Series FF 11 %, due 1994..........
Series EE 11 %, due 1994..........
Series T 4 %%, due 1995........
1981 Series B 15%%, due 1996.....
1981 Series C 15%%, due 1996....
Series U 5%%, due 1997........
Series V 67/s%, 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 12%%, due 2000.....
Series Z 87/s%, due 2000........
Series AA 7%%, due 2001........
Series BB 7%%, due 2001........
Series CC 7%%, due 2002........
Series C 6.15%, due 2003.......
1979 Series B 9.95%, due 2004.....
Series A 8%%, 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
($181,000,000 issued in 1981 )(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 of premium......................
Total long-term debt...........
20,000,000 75,000,000 25,000,000 25,000,000 8,000,000*
20,000,000 20,000,000 25,000,000 100,000,000**
25,000,000 30,000,000 30,000,000 30,000,000 108,750,000 80,000,000 60,000,000 8,000,000**
30,000,000**
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 2,398,200,000 521,000,000 49,990,000 44,750,000 249,150,000 3,263,090,000 13,250,000 57,500,000 20,000,000 2,250,000 10,076,000
$3,160,014,000
- Pollution Control Series. ** Issued in 1981.
The Company redeemed $122,293,000 of long-term debt and sinking fund obligations due in 1981. Maturities (includ-ing cash sinking fund obligations) are as follows: 1982-31
$93,000,000; 1983-$148,000,000; 1984-$270,000,000; 1985-$422,900,000, and 1986-$105, 115,000.
(1) The Mortgage provides for sinking funds as follows:
Annual S1nkmg Series J through CC.......
Series EE and FF.........
Series KK.................
1979 Series A and B.......
1980 Series A, 1981 Series A, Pollution Control Series A 1981 Series C.............
Pollution Control Series B..
Pollution Control Series C..
Commencing Fund Requirements Begun 1984 1985 1986 1987 1992 1989
$10,000,000 13,250,000 2,750,000 10,750,000 6,125,000 4,875,000 250,000 375,000
- The Company may satisfy these requirements by waiv-ing the privilege to issue an equal amount of Bonds by substituting property therefor and intends to do so in 1982.
Substantially all of the Company's property is subject to the lien of the Mortgage.
(2) Term Notes:
Principal Amount 50,000,000 5,000,000 2,500,000 10,000,000 2,500,000 5,000,000 500,000 39,500,000 6,000,000 10,000,000 5,000,000 5,000,000 50,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 20,000,000 5,000,000 15,000,000 5,000,000 15,000,000 25,000,000 50,000,000 10,000,000 50,000,000 10,000,000
$ 521,000,000 Maturity 1982 1982 1982 1983 1983 1983 1983 1983 1984 1984 1984 1984 1984 1984 1984 1984 1984 1984 1985 1985 1985 1985 1985 1985 1985 1987 1988 1995 Variable Interest Rate Percentage of Base Lending Rate of 115%
60 60 115 107%
65 115 Not to Exceed an Average of 87/a%
8%
9%
9.9 9.9 11 8%
9 Fixed Inter-est Rate 8%%
11%
8%
11%
85/a 8.55 8%
10%
11 7/s 14.82 14%
12%
85/a 15%
15%
11 7/s 144/s 16.72 14%
12%
- 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 Requirements Principal Amount
$ 4,000,000 4,250,000 22,000,000 14,500,000
$44,750,000 Maturity 1982-83*
1989 2002 2004 Interest Annual Rate Amount 7.3-7.4%
None
{
$250,000 8.0 500,000 750,000 5%
500,000 8%
750,000 Commencing Begun 1984 1987 1990 1990
- $2,000,000 of the $4,000,000 principal amount of Serial Bonds mature annually.
(4) In 1980, the Company issued a collateral note securing borrowings of a trust which is financing construction expenditures (including interest) after 1979 on the Bath County Pumped Storage Project. Borrowings under the present arrangements, which increased by $47,340,000 during 1981, are limited to $250 million and mature on December 31, 1985. Weighted average interest for 1981, including fees for supporting lines of credit, amounted to 17.6%.
K. Effect of Rate Increases on Operating Revenues:
In 1981, the Company obtained rate relief of about $222 million on an annual basis from the three State Commis-sions, FERG and non-jurisdictional customers.
Rate increases and decreases, exclusive of fuel cost recovery, which became effective for portions of the follow-ing years increased (decreased) operating revenues for the respective years by the approximate amounts shown:
L. Retirement Annuity Plan:
Costs to the Company under the plan were: 1981-
$11, 187,000; 1980-$11, 186,000; 1979-$9,697,000; 1978-$8,586,000; and 1977-$7,594,000. At January 1, 1981, the date of the latest available actuarial report the unfunded liability of the plan amounted to approximately
$12.7 million.
The present value of benefits, as of January 1, 1981, as determined by the actuaries, was as follows:
M. Commitments and Contingencies:
The Company has made substantial commitments in connection with its construction program, which is presently estimated to be $799 million for 1982. Additional financing is contemplated in connection with this program.
The major portion of Laurel Run Mining Company's mining equipment is leased. As guarantor, the Company has a contingent liability for annual lease payments of $1.0 million in 1982 and $.8 million in 1983.
The FERG 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 1974 at Yorktown Unit 3 which the Company has capitalized on its books. The Company has filed an appeal of FERC's decision in the Federal Circuit Court of Appeals.
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 are estimated to equal the value of contracts litigated had they been fully performed by Westinghouse. Through December 31, 1981, the Company had received $176 million in cash and goods and services, $29 million of which was received in 1981. Settlement proceeds are applied to reduce fuel expenses to the extent that fuel expenses reflect higher costs as a result of the breached contracts. In 1979 the Company filed with the Internal Revenue Service a request for a ruling that the value received from the settle-ment 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 ruling, received on June 1, 1981, held that cash and the value of discounts on purchases of equipment and services accrued at the time of settlement and could be used to offset the damages in the cost of replacement uranium acquired up to the date of settlement.
This treatment was not extended to replacement uranium acquired after the date of settlement. The Company, to-(Millions of Dollars) 1981 Electric..............
$92.2*
Gas.................
(.2) 1980
$36.4
(.7) 1979 1978 1977
$56.4 $56.9 $3.0
.4
- Includes approximately $15.5 million subject to refund.
Vested accumulated plan benefits...
Nonvested accumulated plan benefits Total..........................
Plan net assets available for benefits
$125,756,000 16,373,000
$142,129,000
$159,027,000 A 7% rate of return is used in determining the present value of vested and nonvested accumulated plan benefits.
gether with other utilities involved in the Westinghouse settlement, is pursuing a legislative remedy to this problem.
If the Company is required to pay taxes as a result of the settlement, such provision would be normalized in order to match the tax effect of the settlement with the credit to fuel expenses per books.
A group of utilities, including the Company, has estab-lished Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides insurance for replacement power costs resulting from an accident at a nuclear site. The Company has purchased the maximum coverage available, which is $2.3 million per week per unit for the first 52 weeks of coverage and $1.15 million per week per unit for the next 52 weeks, subject to an initial 26-week deductible period. In addition, NEIL began providing excess property damage insurance through a separate program that commenced on November 15, 1981 and which is ultimately to provide $500 million of property insurance coverage to meet losses in excess of $500 million. The company has committed to purchase the maximum amount available, subject to regula-tory approvals. The annual premiums for the current year are $6.7 million for the replacement power insurance. The premiums for the excess property coverage will be $1.9 million for the initial year. Each program also obligates participants to a retrospective premium adjustment for six years following each policy year. These adjustments are not to exceed five times the annual premium, in the case of the replacement power insurance, and 7.5 times the annual premium, in the case of the excess property coverage, in the event that losses exceed the accumulated funds of the applicable program.
For a discussion of possible sales of power station projects and related facilities see Capital Resources under MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDI-TION AND RESULTS OF OPERATIONS.
32
N. Quarterly Financial Data (Unaudited):
The following amounts (not examined by independent certified public accountants) reflect all adjustments, consist-ing of only normal recurring accruals, necessary in the opinion of the Company for a fair statement of the results for Balance Earnings for Per Share Operating Operating Common of Common Quarter Revenues Income Stock Stock 1981 (Thousands of Dollars) 1st..........
$554,203
$106,544
$40,260
$.40 2nd..........
484,984 97,194 23,491
.23 3rd..........
567,628 141,427 63,992
. 63(2,3) 4th..........
555,038 123,467 52,871
.51 (1)
Results for interim periods may fluctuate as a result of weather conditions, rate relief and other factors.
(1) In December 1981, eleven of the Company's North Carolina municipal customers terminated contracts for elec-tric service by the Company to purchase their own generat-ing capacity from another utility. Accordingly, the Company agreed to phase out its wholesale power contracts with these customers over a two-year period beginning Decem-ber 30, 1981, in return for a payment to the Company on that date of approximately $15.5 million. Of this amount, $13.3 million was credited to other income with a resulting increase in balance for common stock and earnings per share of $7.2 million and $.07, respectively, and $2.2 million was credited to accumulated amortization of nuclear fuel.
(2) From September 1978 through August 1981 the Company provided a reserve for the difference between interim rates in effect for FERG jurisdictional customers and estimated final rates. The Company neither sought nor received regulatory approval to provide deferred taxes on this reserve which was not considered to be deductible for Federal income tax purposes until a refund was made. As a result of a final rate order received in the third quarter of the interim periods, except as disclosed below for the adjustments recorded in the third and fourth quarter of 1981 and the fourth quarter of 1980.
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(4) 1981, a refund substantially equal to the amount previously provided was made. The tax benefit of this refund had the effect of reducing the Company's 1981 provision for Federal income taxes by $12,419,000 and of increasing 1981 earn-ings per share by $0.12.
(3) Beginning in the third quarter of 1981 the investment tax credit applicable to nuclear fuel is being amortized over the average burn life of the fuel, which is three years, rather than over the average composite life of all plant assets. This refinement of the Company's method of amortizing the tax credits had the effect of reducing the 1981 provision for Federal income taxes by $5,292,000 (including $3,305,000 applicable to periods prior to 1981) and of increasing 1981 earnings per share by $.05. The effect of this refinement on the results of operations of periods prior to 1981 would not have been significant.
(4) In the fourth quarter of 1980, the Company began accounting on an inventory basis for spare parts and equip-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.
- 0. 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 Consumers (CPI-U). Current cost amounts reflect the changes in specific prices of plant from the date the plant was acquired to the p_resent, 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 depreciation rates to the indexed plant amounts.
Fuel used in electric generation has been restated to reflect 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 dollars. The nuclear fuel inventory is considered an integral part of the plant investment and, therefore, should be restated and adjusted to net recoverable cost. As indicated above, other types of fuel inventories have not been restated 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 mone-tary 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 recoverable 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 (loss) 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, 1981 Conventional Historical Cost
$2,161,853 555,466 174,120 869,966 93,669 283,745 (52,893) 1,924,073
$ 237,780 Constant Dollar Average 1981 Dollars (Thousands of Dollars)
$2,161,853 587,028 367,351 869,966 93,669 283,745 (52,893) 2,148,866 12,987*
$ (272,258) 307,911 35,653 Current Cost Average 1981 Dollars
$2,161,853 611,589 395,036 869,966 93,669 283,745 (52,893) 2,201,112 (39,259)
$1,561,522 (901,598)
(879,936)
(220,012) 307,911 87,899
- Including the adjustment of property, plant and equipment to net recoverable cost, the loss from continuing operations on a constant dollar basis would have been $259,271,000 for 1981.
- At December 31, 1981, current cost of property, plant and equipment, net of accumulated depreciation and amortization, was $11,243,476,000, while historical cost or net cost recoverable through depreciation and amortization was $6,012,888,000.
34
Five Year Comparison of Selected Supplementary Financial Data Adjusted for Effects of Changing Prices (Unaudited)
Years Ended December 31, 1981 1980 1979 1978 1977 (In Thousands* of Average 1981 Dollars)
Operating revenues..............................
$2,161,853
$2,339,653
$2,134,229 $2,042,170
$2,039,413 Historical cost information adjusted for general inflation Income from continuing operations (excluding adjustment to net recoverable cost)....
Income (loss) per common share (after dividend requirements on preferred and preference stock)..
Net assets a1 year-end at net recoverable cost...............................
Current cost information Income (loss) from continuing operations (excluding adjustment to net recoverable cost)..............
(Loss) per common share (after dividend requirements on preferred and preference stock)...............
Excess of increase in general price level over increase in specific prices after adjustment to net recoverable cost.........................
Net assets at year-end at net recoverable cost...............................
General information Gain from decline in purchasing power of dollars related to net amounts owed....................
Cash dividends declared per common share................................
Market price per common share at year-end...................................
Average consumer price index (1967 = 100).......
- Except per share amounts and indexes.
$12,987
$(0.43)
$97,295
$101,489
$0.35
$0.38
$2,423,401
$2,331,269
$2,463,378
$(39,259)
$54,488
$47,256
$(0.95)
$(0.09)
$(0.25)
$220,012
$479,689
$574,166
$2,423,401
$2,331,269
$2,463,378
$307,911
$429,314
$465,314
$1.42
$1.55
$1.73
$11.37
$10.95
$12.44 272.4 246.8 217.4 35
$1.81
$18.80 195.4
$1.87
$21.22 181.5
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....................................
Stiort-term debt-pending permanent financing..............
Capitalization ratios:
Preferred and preference stock............................
Common equity..........................................
Debt (excluding short-term debt)...........................
1981
$2,069,764 92,089 2,161,853 1,292,318 174,120 12,203 14,732 15,554 (8,843)
(1,547) 53,847 19,926 120,911 1,693,221 468,632 44,264 8,629 52,893 521,525 280,012 44,276 (40,543) 283,745 237,780 237,780 57,170 144,937 202,107 35,673 101,856
$1.77
$1.42%
80%
40.22%
$7,487,634
$ 676,295
$1,474,746
$ 675,284 1,952,476 3,263,090
$5,890,850
$ 164,938 12%
33 55 (Thousands of Dollars) 1980 1979
$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
$1,647,928 55,381 1,703,309 1,069,241 136,280 7,292 8,449 570 (5,820)
(1,547) 32,418 35,674 104,358 1,386,915 316,394 66,603 974 67,577 383,971 204,392 12,417 (29,305) 187,504 196,467 196,467 55,046 120,638 175,684 20,783 86,965
$1.63
$1.38 85%
(2)
$6,307,644
$ 708,756
$1,079,142
$ 678,451 1,731,762 2,681,360
$5,091,573
$ 131,730 13%
34 53 (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 1978
$1,413,866 51,039 1,464,905 869,232 117,481 6,760 23,163 40,294 (5,467)
(1,547) 38,509 (22,294) 93,499 1,159,630 305,275 64,0021 1,342 1
65,344 370,619 184,947 6,677 (24,869) 166,755 203,864 203,864 53,588 103,474 157,062 46,802 80,060
$1.88
$1.30 69'
$5,626,6711
$ 529,1861
$ 940,958
$ 651,6341 1,627,179 2,460,060
$4,738,873 3,437 14 34 52
1977 1,313,937 44,923 1,358,860 850,823 98,527 3,173 9,191 23,548 (4,539)
(1,547) 13,101 19,982 81,174
.1,093,433 265,427 72,361 (663) 71,698 337,125 168,885 5,748 (27,301) 147,332 189,793 189,793 47,719 91,225 138,944 50,849 74,025
$1.92
$1.24 64%
I I 72.654%
r5,109,099 569,068 803,604 619,109 1,493,521 2,238,400 4,351,030 53,050 14%
34 52 1976
$1,060,663 43,413 1,104,076 647,965 95,191 2,209 35,568 (3,028)
(1,547) 12,320 3,229 71,413 863,320 240,756 80,429 491 80,920 321,676 147,481 7,409 154,890 166,786 166,786 43,821 82,923 126,744 40,042 68,137
$1.80
$1.22%
67%
25.267%
$4,609,416
$ 481,601
$ 700,254
$ 583,807 1,334,639 2,038,150
$3,956,596 26,500 15%
34 51 1975
$ 998,933 34,403 1,033,336 629,162 89,805 (1,142) 2,286 (2,452)
(1,547) 9,360 20,873 57,169 803,514 229,822 66,873 544 67,417 297,239 122,951 19,556 142,507 154,732 154,732 35,971 70,786 106,757 47,975 60,854
$1.95
$1.18 60%
$4,142,900
$ 432,139
$ 609,304
$ 503,807 1,211,282 1,803,150
$3,518,239
$ 110,050 14%
35 51 1974
$ 735,962 28,050 764,012 478,716 77,757 (7,678)
(3,195)
(2,412)
(1,547) 3,202 5,018 48,216 598,077 165,935 65,735 411 66,146 232,081 94,058 23,214 117,272 114,809 12,353 127,162 30,419 60,165 90,584 36,578 52,100
$1.86(1)
$1.18 71%
100.000%
100.000%
$3,739,395
$ 460,912
$ 545,296
$ 446,447 1,042,677 1,578,350
$3,067,474
$ 256,945 15%
34 51 1973
$ 524,963 26,000 550,963 278,750 68,436 (1,010) 3,901 (2,413)
(1,547) 7,265 42,170 395,552 155,411 57,359 336 57,695 213,106 78,350 10,684 89,034 124,072 124,072 24,147 54,796 78,943 45,129 47,021
$2.13
$1.16%
55%
49.407%
$3,298,447
$ 486,709
$ 476,121
$ 366,447 948,369 1,289,890
$2,604,706
$ 220,150 37 14%
36 50 1972
$ 445,668 25,185 470,853 264,906 53,058 (6,850) 7,368 (2,225)
(1,547) 1,356 36,629 352,695 118,158 58,451 (156) 58,295 176,453 67,554 5,162 72,716 103,737 103,737 16,472 46,905 63,377 40,360 41,883
$2.08
$1.12 54%
100.000%
55.565%
$2,847,614
$ 472,819
$ 414,941
$ 296,447 810,121 1,242,440
$2,349,008 88,400 13%
34 53 1971
$ 390,370 23,302 413,672 218,846 49,950 8,652 1,952 (2,062)
(1,547) 1,050 33,514 310,355 103,317 39,993 142 40,135 143,452 58,130 3,274 61,404 82,048 82,048 12,216 41,993 54,209 27,839 37,829
$1.85
$1.12 60%
96.724%
$2,416,130
$ 380,268
$ 373,834
$ 201,447 680,800 1,070,440
$1,952,687 61,800 10%
35 55
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......................
Source of electricity-Mwh (thousands):
Steam-Fossil.........................................
-Nuclear.......................................
Hydro................................................
Other...........................................,.....
Net purchased and interchanged..........................
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..................
1981
$ 814,152 541,264 261,825 436,663 15,860
$2,069,764 3,638,000 1,238,530 123,939 920 17,749 1,381,138 13,399 9,816 6,416 10,275 39,906 2,983 42,889 16,539 17,818 263 201 8,068 42,889 325 43,214 8,638 6,112 3,199 326 439 10,076 165 10,241 900 11,141 11,170 17.77 42,502 10,775 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 18,840 11,466 616 208 11,359 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 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 24,301 7,055 1,122 356 7,650 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 1978
$ 563,56 392,10 182,90 268,21 7,09
$1,413,8E 3,465,0C 1,138,47 115, 1 ~
9~
15,4.!l 1,269,9e 12,4(
9,17 6,H 9,3.!l 37,0E 2,9(
39,96 24,43 14,09
~1 39,9~
32 40,29 7,8(
6,3~
2,44 3~
4~
9,5~
1E 9,6~
3(
9,9~
11,01 14.C 41,6~
8,3~
- Excludes the cumulative effect to January 1, 1974 of accruing estimated unbilled revenues shown as a nonrecurring item on the income statement, 1 of taxes.
38
1977 1976 1975 1974 1973 1972 1971 524,336
$ 420,150
$ 402,889
$ 308,834
$ 229,860
$ 191,924
$ 169,113 365,340 298,681 288,357 211,486 150,758 130,599 113,646 176,573 144,770 137,181 106,309 66,131 58,785 48,375 242,686 193,096 166,854 106,018 75,170 61,440 56,392 5,002 3,966 3,652 3,315 3,044 2,920 2,844 1,313,937
$1,060,663
$ 998,933
$ 735,962*
$ 524,963
$ 445,668
$ 390,370
~,415,000 3,365,000 3,315,000 3,270,000 3,225,000 3,185,000 3,150,000 1,100,876 1,071,528 1,041,234 1,018,346 989,471 954,374 920,839 111,662 108,197 105,942 105,531 103,253 100,175 98,223 920 920 918 916 910 894 874 14,922 14,462 14,881 13,045 12,350 11,817 11,392 1,228,380 1,195,107 1,162,975 1,137,838 1,105,984 1,067,260 1,031,328 I 11,867 11,137 10,373 9,850 9,911 8,775 8,121 I
8,762 8,455 7,970 7,307 7,330 6,471 5,980 6,022 6,011 5,404 5,658 5,535 5,136 4,683 8,806 8,510 7,741 7,120 7,268 6,529 5,902 35,457 34,113 31,488 29,935 30,044 26,911 24,686 2,792 2,261 2,585 2,518 2,335 2,199 2,019 38,249 36,374 34,073 32,453 32,379 29,110 26,705 26,403 27,090 23,562 22,819 22,311 23,710 24,335 9,481 7,740 8,969 5,953 6,857 370 444 599 988 774 949 1,071 825 625 407 226 629 459 558 323 1,296 538 328 2,278 1,803 3,401 1,222 38,249 36,374 34,073 32,453 32,379 29,110 26,705 325 326 325 325 315 312 307 38,574 36,700 34,398 32,778 32,694 29,422 27,012 7,902 7,040 7,133 6,734 6,900 6,232 5,295 6,321 6,321 6,321 5,684 4,866 4,306 4,334 1,550 1,576 1,576 1,576 1,576 788 326 326 326 326 326 326 326 439 454 469 530 530 530 530 8,636 8,677 8,692 8,116 7,298 5,950 5,190 165 165 165 165 165 132 132 8,801 8,842 8,857 8,281 7,463 6,082 5,322 300 313 316 251 122 680 610 9,101 9,155 9,173 8,532 7,585 6,762 5,932 10,933 10,739 10,892 10,868 10,673 10,529 10,382 15.23 12.94 13.06 12.43 4.98 4.63 4.28 41,446 41,186 40,663 40,121 39,578 39,055 38,404 7,794 6,824 6,266 5,641 4,772 4,055 3,367 39
Directors John B. Bernhardt, President Virginia National Bankshares Inc., Norfolk William W. Berry, President James F. Betts, President Continental Financial Services Company, Richmond Milton L. Drewer, Jr., President First American Bank of Virginia, McLean Mrs. Mary C. Fray, Culpeper Bruce C. Gottwald, 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 56 William W. Berry, President and Chief Operating Officer, Age 49 Jack H. Ferguson, Executive Vice President, Age 50 Senior Vice Presidents Samuel C. Brown, Jr., Power Station Engineering and Construction, Age 56 John I. Oatts, Power Operations, Age 52 William L. Proffitt, Commercial Operations, Age 52 Vice Presidents Wadsworth Bugg, Jr., Age 60 Paul G. Edwards, Age 43 Gerald C. Headley, Jr., Age 47 Robert F. Hill, Age 45 Charles M. Jarvis, Age 53 B. D. Johnson, Vice President and Controller, Age 49 Ronald H. Leasburg, Age 48
- 0. James Peterson, Ill, Vice President and Treasurer, Age 46 James T. Rhodes, Age 40 William C. Spencer, Age 49 William N. Thomas, Age 58 Corporate Secretary S. Brooks Robertson, Age 64 Division Vice Presidents Northern Division, James P. Cox, Jr., Age 63 Eastern Division, William H. Blackwell, Jr., Age 52 Southern Division, Randolph D. Mciver, Age 51 Western Division, Richard W. Carroll, Age 63 Central Division, David W. Poole, Age 57 Virginia Natural Gas, Eugene C. Keeling, Age 58 40 Membership of Committees of the Board 0 Committee Chairman
- Member
- Ex Officio Finance 0
Audit 0
Organization and Employee Nominating Compensation Benefit 0
0 0
Stock and Convertible Debenture Listings New York Stock Exchange Symbol-VEL Transfer Agents-Registrars United Virginia Bank, Richmond The Chase Manhattan Bank, N.A., New York Annual Meeting April 21, 1982 Cassette Recordings of this 1981 Annual Report are available as a service to the visually impaired. Requests should be directed to the Corporate Secretary of the Company.
William W. Berry T. Justin Moore, Jr. John B. Bernhardt William T. Roos Mrs. Mary C. Fray James F. Betts Dr. Allix B. James Shirley S. Pierce Milton L. Drewer, Jr.
Kenneth A. Randall
BULK RATE U.S. POSTAGE PAID PERMIT NO. 930 RICHMOND, VA.