ML18087A918

Forwards Annual Financial Repts for 1982

ML18087A918
Person / Time
Site:	Salem, Hope Creek, 05000000
Issue date:	05/17/1983
From:	Fryling R Public Service Enterprise Group
To:	Office of Nuclear Reactor Regulation
References
NUDOCS 8305200067
Download: ML18087A918 (186)

Text

-0 PS~G Publi.vice Electric and Gas Company 80 Park Plaza, Newark, NJ 07101I201 430-6462 MAILING ADDRESS I P.O. Box 570, Newark, NJ 07101 James R. Lacey General Solicitor - 5E Salem Generating Station Docket Nos. 50-272 & 50-311

• Operating License Nos. DPR-70 & DPR-75 Office of the Director Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, D.C. 20555

Dear Sir:

May 17, 1983 Hope Creek Generating Station Docket No. 50-354 Construction Permit No. CPPR-120 Pursuant to the NRC Rules and Regulations, enclosed please find ten copies each of the 1982 Annual Report of Public Service Electric and Gas Company, Atlantic City Electric Company, Delmarva Power and Light Company and Philadelphia Electric Company 1n the Salem Generating Station dockets. Please accept same reports of Public Service Electric and Gas Company and Atlantic City Electric Company in the Hope Creek Generating Station docket.

RF:mbb Enclosures i~83o52ooo6i 830517-- --- ----~.

I.\\ PDR ADOCK 05000272

"\\' I PDR The EnerQY People Very truly yours,

~~,~

Richard Fryling, Jr.

Assistant Qeneral Solicitor 95-4966 (2.5M) 2-83

PS~G NOTICE THE ATTACHED FILES ARE OFFICIAL RECORDS OF THE DIVISION OF DOCUMENT CONTROL. THEY HAVE BEEN CHARGED TO YOU FOR A LIMITED TIME PERIOD AND MUST BE RETURNED TO THE RECORDS FACILITY BRANCH *016.

PLEASE DO NOT SEND DOCUMENTS CHARGED OUT THROUGH THE MAIL. REMOVAL OF ANY PAGE(S) FROM DOCUMENT FOR REPRODUCTION MUST BE REFERRED TO FILE PERSONNEL.

So-)..7"J-DEADLINE RETURN DATE RECORDS FACILITY BRANCH

~

0 PS~G I

Public Service Electric and Gas Company 80 Park Plaza. Newark. New Jersey 07101 (201 ) 430-7000 Stockholder Information -

Toll Free New Jersey residents (800) 242-0813 Outside New Jersey (800) 526-8050 r

able of Contents Public Service Electric and Gas

1. Financial Highlights Company is the largest utility in New Jersey and serves approximately 5.4

2. Message to Shareholders million people. nearly three-quarters of

5. Financial Review the state's population. The Company's

7. Construction Expenditures service area. covering some 2.600

10. Nuclear Operations Consolidated square miles. runs diagonally across

12. Production and Distribution the state's industrial and commercial

16. Customer and Marketing Services corridor from the New York state bor-

18. Conservation and Load Management der on the north to south of Camden.

20. Area Development This highly diversified and heavily

22. Research and Development populated area includes the six major

24. Community and Employee Relations cities of New Jersey as well as nearly

25. Financial Statement Responsibility 300 suburban and rural communities.

25. Accounting Policies

27. Financial Statements

31. Independent Accountants' Opinion

34. Notes to Financial Statements

40. Operating Statistics

42. Financial Statistics Lh nut tho Cr\\\\/{ r

44. Management"s Discussion and Analysis of Financial Condition Panoramic air view of PSE&G's nuclear and Results of Operations complex on the lower Delaware River

48. Officers and Directors in southern New Jersey encompasses cover of this 1982 annual report. On the front. Salem Generating Station and its two containment structures are predominant with power transmission lines stretching out in the distance.

On the back. progress is shown on construction of the Hope Creek Gen-erating Station. During 1982. the Company's nuclear activities were con-solidated at the site of these facilities.

1982 Annual Report Financial Highlights 1982 Earnings per average share of Common Stock

$3.24 Shares of Common Stock Average 89,233,000 Year-end 94,845,000 Dividends paid per share of Common Stock

$2.53 Book Value per share of Common Stock

$25.90 Total Operating Revenues

$3,873,976,000 Total Operating Expenses

$3,419,517,000 Earnings Available for Common Stock

$ 288,962,000 Gross Additions to Utility Plant

$ 81 3,375,000 Total Utility Plant

$ 8.100,579,000 Annual Meeting Please note that the Annual Meeting of Stockholders of the Company will be held at Newark Symphony Hall. 1020 Broad Street. Newark. New Jersey, Tues-day. April 19. 1983, at 2:00 P.M. A summary of the meeting will be sent to all stockholders of record at a later date.

1981 Increase

$2.63 23 80,962,000 10 86.089,000 10

$2.44 4

$25.66

$3.471.652,000 12

$3.117.385.000 10

$ 212.599.000 36

$ 683.849.000 19

$7.320.764.000 11 Robert I. Smith, Chairman, addresses shareholder informational meeting in West Palm Beach, Florida, one of three held in that state in November. More than 22,000 shareholders, about 9 per cent of the Company's total. live in Florida. These informa-tional meetings are part of PSE&G's extensive investor relations program.

2 A

though it was a year marked by economic reces-sion, your Company made significant progress during 1982 with improvements realized in various phases of operations and -

more importantly-in financial results.

Message to Shareholders A major event during the year was the signing of an agreement designed to promote the timely completion of the Hope Creek I generating unit.

Another important achievement was the establishment of the newly-formed Nuclear Depart-ment at the site of our nuclear generating stations.

Other noteworthy accom-plishments were the completion of a reorganization of customer and marketing activities; the development of an accelerated conservation and load manage-ment program; and an upgrading of production and distribution facilities. Overall.

1982 was a year of improved efficiency and customer service.

A high degree of service reliability was maintained throughout the year despite a 41 -day strike by two unions representing approximately 4.600 employees. The strike began when contracts expired at midnight on April 30 and ended in June when new two-year agreements were reached.

E arnings Increase Earnings per share of Common Stock rose to $3.24 from $2.63 in 1981. Total reve-nues increased to $3.87 billion from $3.47 billion.

The gains in earnings and revenues were mainly attribu-table to an increase of $390 million in base rates on an annual basis effective in Febru-ary 1982 that was approved by the New Jersey Board of Public Utilities (BPU).

The quarterly dividend on common stock was increased to 64 cents a share in the second quarter of 1982 from 61 cents.

This was the seventh consecutive year in which the dividend was increased. It is management's objective to raise dividends on a regular basis subject. of course.

to adequate levels of earnings to support such dividends.

S ales Decline Reflecting the recessionary economy, overall electric kilo-watthour sales declined 2.7 per cent for the year compared with 1981. Sales in the commercial category were an exception. ris-ing 1.6 per cent and providing evidence of strong growth in service and distribution busi-nesses in our territory.

Total gas therm sales de-creased by 1.0 per cent. A gain of 4.7 per cent in sales to com-mercial customers was not suffi-cient to offset a decline of 9.4 per cent in the industrial classi-fication that was mainly at-tributable to the economic recession. Sales to residential customers were virtually the same as in 1981. despite new connections. as warmer weather late in the year reduced demand for heating.

N uclear Output Rises During the year 34 per cent of our electric output came from nuclear generation, up from 25 per cent in 1981. The nuclear production was bolstered by

excellent performance of No. 2 unit at Salem Generating Station in its first full year of commer-cial operation. The unit was available 97 per cent of the time in 1982. a remarkable record for a new unit.

Construction of the Hope Creek I generating unit. being built adjacent to Salem. was more than 60 per cent com-pleted at the end of the year. The unit is scheduled to go on line in late1986.

In August a cost-contain-ment agreement for Hope Creek was signed by the Company with the New Jersey Department of Energy and the state Public Advocate. As part of the agree-ment. the Public Advocate agreed not to challenge the need for the unit before any state or federal agency. The agreement requires the approval of the BPU which has held hearings prepa-ratory to making a decision.

The agreement provides a targeted in-service date of December 1986 and a targeted cost at the time of commercial operation of $3.795 billion.

There would be a penalty in the form of reduced earnings to the Company if costs exceed $3.795 billion. unless the overruns were due to extraordinary events be-yond our control. On the other hand. there would be a benefit to earnings if the unit should be completed for less than $3.55 billion.

Our present estimate is that the unit will cost between $3.55 billion and $3.79 billion.

In June. the Company began recovering the abandon-Construction work on the Hope Creek I generating unit was intensified in 1982 after cancellation of the second unit at the station. Among high-lights of the year were the lifting of a 409-ton crane into the reactor building where it will be used for moving large pieces of equipment, and placement of the unit's 440-ton steel containment dome. At year end. the plant was more than 60 per cent completed.

ment costs of the second Hope Creek unit. which was cancelled in December 1981. The recovery will be over a 15-year period and amounts to $172 million. after tax considerations. This recovery is on an accelerated basis. so that about half of the amount will be recouped in the first five years and will provide additional cash flow for the funding of Hope Creek I.

N uclear Operations Centralized Nuclear operations were strengthened during the year by the centralization of activities of the Nuclear Department in a new headquarters at the site of the Salem and Hope Creek sta-tions. Most personnel involved in nuclear power operations were transferred from Newark to the department headquarters.

We are determined to make certain that we have the most thoroughly trained and qualified nuclear plant operators and sup-port personnel. As part of this effort. we completed construc-tion and opened a Nuclear Training Center for employees of the Nuclear Department.

C onservation Program In line with our efforts to reduce the need for new facili-ties -

and consequently capital expenditures -

we developed a broad plan to promote the con-servation and efficient use of 3

4 energy by our customers. The plan includes subsidization of loans to finance home conserva-tion measures. the encourage-ment of energy audits, weatherization assistance. and rebates for the installation of high efficiency equipment.

Because of the relatively low rate of growth in the projected demand for electricity, we do not foresee the need to construct any new generating capacity.other than Hope Creek I.

until the late 1990's.

C onsumer Panels A new dimension was added to our customer relations and information effort with the establishment of three consumer advisory panels. geographically situated to serve our three cus-tomer and marketing services divisions. Membership on the panels has been drawn from a cross-section of customer and consumer groups.

R ecession Impact Felt Even though inflation has subsided and interest rates have declined, the deep economic reces-sion continues to have a dampening effect on the Company's perfor-mance. We have intensified our efforts to reduce expenses wher-ever possible. Budgets have been severely cut and a cap has been placed on the number of employees.

Despite the most stringent measures. our cost of providing service continues to rise and we have been unable to realize our allowed rate of return.

On January 7, 1983, the Company filed a petition with the New Jersey Board of Public Utilities for an increase in base rates to pro-vide additional annual revenues of

$464.5 million. The total includes

$397.4 million for electric service.

and $67.1 million for gas.

The BPU is presently consid-ering a motion by the Public Advo-cate of New Jersey to dismiss the Company's petition. New rates can only be put in effect after required hearings.

Robert I. Smith Chairman of the Board and Chief Executive Officer R

esponsibilities Fulfilled Our Company-80 years old in 1983-has demonstrated its ability to fulfill its responsibilities to customers. stockholders and em-ployees throughout its history.

Ever mindful of the contri-bution to our Company's success by thousands of talented and dedi-cated employees, we appreciate the continuing support of Company shareholders in all our endeavors.

Harold W. Sonn President and Chief Operating Officer February 14, 1983

pinancial Review D

spite a lingering and deepening economic recession in 1982, revenues and earnings increased, although electric sales dropped 2. 7 per cent and gas sales fell 1.04 per cent, compared with 1981. Declines in the rate of inflation and in interest rates were positive factors in an otherwise bleak economy that handicapped performance.

Earnings and Dividends per Share 3.50 3.00 2.50 2.00 1.50 1978 79 80 Earnings

• Dividends 81 82 The gain in overall revenues to $3.87 billion from $3.47 billion in 1981 was due largely to the in-crease of $390 million in rates on an annual basis that became effec-tive on February 14. A $73.9 million rise in the gas raw materials adjustment charge beginning in October also was a factor. These revenue increases were offset par-tially by a lowering of the electric energy adjustment charge which will reduce revenues by $250 mil-lion for the 13-month period that began in June.

Electric revenues accounted for 66 per cent of the total, rising to $2.54 billion. an increase of 9.5 per cent. Gas revenues composed the other 34 per cent. increasing to

$1.33 billion. or by 15.8 per cent.

The sources of the 1982 revenues by customer classification were:

Electric Gas Combined E

xpenses Continue to Increase Operating expenses rose to

$3.42 billion. up $302 million. or 9.7 per cent from $3.12 billion in 1981.

Production costs increased by $69.7 million. a rise of 3.5 per cent. Electric production expenses declined 4.9 per cent. mainly be-cause of greater use of lower-cost nuclear and coal-fired generation.

Gas production costs. which include the cost of natural gas. rose 18.5 per cent.

Prices of purchased natural gas continued to increase mainly because of higher wellhead prices permitted under the Natural Gas Policy Act of 1978. Costs of raw materials to manufacture gas also increased.

Labor costs increased by

$40.8 million. or 15.9 per cent.

Residential 31 %

54%

39%

New two-year agreements reached Commercial 39 28 35 in June. which ended a 41 -day Industrial 28 18 25 strike by two unions representing Street Lighting 2 some 4.600 employees. provided 1_ a_n_d_o_th_e_r _________

1 wage increases of 8.25 per cent in Total 100%

100%

100%

the first year and 8.0 per cent in 1-------------1 the second. Improvements in Capitalization Ratios (Year-End) 100 80 60 40 20 1978 79 80 81 82 Common Equity Preferred Stock Long-Term Debt employee benefits made total increases of 10.81 per cent in the first year and 9.02 per cent in the second. The total cost on a company-wide basis is estimated at

$38 million in the first year of the contract and an additional $34 million in the second.

As a result of the Company"s higher revenues. New Jersey gross receipts taxes increased to $514 million from $462 million. a rise of 11.3 per cent.

5

E arnings Rise The Company's earnings per share of Common Stock in 1982 in-creased to $3.24 from $2.63. an increase of 23.2 per cent. The im-provement reflected the $390 million rate increase effective in February. The average number of common shares outstanding rose during the year to 89.2 million from 81.0 million in 1981.

D ividend Increased The quarterly dividend on Common Stock was increased in the second quarter of 1982 to 64 cents a share from 61 cents paid in the first quarter. The increase was the seventh in as many years.

Total dividends paid for the year amounted to $2.53 per share compared with $2.44 in 1981.

Dividends paid in 1982 on all classes of stock are fully taxable.

Due to special circumstances in some prior years. portions of divi-dends were determined to be a return on capital and therefore non-taxable as current income.

The 1982 Income Dollar Such circumstances included the cancellation of nuclear plant projects no longer needed and the sale of the Company's transporta-tion subsidiary. Decisions on the taxability of dividends are governed by Internal Revenue Service rules and are based on calculations of the Company's estimated tax liability.

e ition Filed for Increase of

$465 Million in Rates On January 7. 1983. the Company petitioned the New Jer-sey Board of Public Utilities (BPU) for an annual increase of $464.5 million in base rates. The request was necessary because the Compa-ny's cost of providing service con-tinues to increase. Of the amount.

$397.4 million would be in electric revenues. a 15.6 per cent increase.

and $67.1 million in gas revenues. a 4.5 per cent increase. The petition asks for a return on rate base of 11.66 per cent and 17 per cent on common equity.

On January 18. the Public Advocate of New Jersey moved to dismiss the Company's petition con-tending that a previous BPU order requires the Company to show "emergent" circumstances to be al-lowed to file for rate relief before July 1. 1983. The Company has opposed the motion. which is currently being considered by the BPU. If the case is allowed to pro-ceed. public hearings would be required. and the statutory review period would delay the effective date of any new rates until late in 1983.

In its order in the Company's last rate case the BPU allowed a 10.67 per cent return on rate base and 16 per cent on common equity.

The Company's actual return on equity of 12.2 per cent during 1982 was far short of the return allowed in the rate decision.

E lectric Acljustment Charge Lowered In June. the Company reduced its electric levelized energy adjustment charge by $250 million for the period through June 30.

1983. The reduction. which did not Where It Went

~

• To

affect earnings, lessened the impact on customers of the $338 million increase in electric base rates that became effective in February.

The reduction was made possible by additional nuclear gen-eration from the second Salem unit.

a decline in oil prices. purchases of power at lower cost. and comple-tion of the recovery of nearly all electric energy costs from previous periods.

On January 13. 1983 the Company requested permission from the BPU to lower the energy adjustment charge by an additional

$104 million for the 17-month period beginning February 1. 1983 through June 30. 1984. The pro-posed reduction was based on projections of a greater percentage of nuclear generation than previ-ously estimated and lower oil and coal prices. The BPU took the re-quest under consideration.

G as Adjustment Charge Increased Effective September 30. the BPU approved an increase in the gas raw materials adjustment charge to provide $73.9 million in additional revenues. The increase is designed to cover higher prices the Company expects to pay for natural gas through September 1983.

Changes in federal regulation are permitting progressively higher natural gas prices.

C ost Containment Agreement on Hope Creek Unit A cost containment agreement for the Hope Creek I nuclear generating unit was signed in August with the New Jersey Department of Energy, the state Public Advocate and Atlantic City Electric Company. which owns 5 per cent of the unit. The agree-ment is subject to approval by the BPU which began hearings pre-liminary to making a decision.

There is a provision in the agreement that the Public Advocate will not challenge the need for Hope Creek before any state or federal agency. Earlier. the Advo-cate had questioned the need for and the ultimate cost of the unit.

The agreement provides a targeted in-service date of Decem-ber 1986 and a targeted cost at the time of commercial operation of

$3.795 billion, including approxi-mately $995 million of Allowance for Funds Used During Construc-tion (AFDC).

The Company had estimated the cost of the unit between $3.55 billion and $3.795 billion. including

$950 million of AFDC. The differ-ence between the estimate and the targeted amount represents poten-tial cost overruns that were indicated in an independent study the Company commissioned in 1981.

At the end of 1982. Hope Creek was more than 60 per cent completed and expenditures were closely tracking construction cost estimates. The Company's estimate of the cost of the unit is still be-tween $3.55 billion and $3.795 billion. of which 5 per cent is the share of Atlantic City Electric Company.

The agreement provides that the Company's rate base revenue requirements at the time of com-mercial operation of the unit would be adjusted to reflect only 80 per cent of any reasonable cost over-runs up to 10 per cent above the targeted amount. Should the unit's cost exceed the target figure by more than 10 per cent. only 70 per cent of the additional overruns would be included in the revenue-requirement calculation. Any such adjustment would have the effect of reducing earnings.

Under the agreement. adjust-ments would not be made for over-runs due to extraordinary events.

On the other hand. there would be a benefit to the Company if the unit should be completed for less than $3.55 billion. Revenue requirements for rate making purposes would be calculated at actual plant cost plus an additional return on 20 per cent of the amount under $3.55 billion. No ad-justment to revenue requirements would be made if the unit costs be-tween $3.55 billion and $3.795 billion.

C onstruction Expenditures Up Expenditures for construc-tion. including Allowance for Funds Used During Construction (AFDC).

payments for nuclear fuel and ad-vances to subsidiaries. increased to

$842 million in 1982 from $717 million in 1981. Construction expenditures in 1983 are estimated at $904 million. including $129 million of AFDC.

Expenditures for all projects.

including Hope Creek I. in the five years through 1987. are estimated at $3.8 billion. including $736 million of AFDC. Of the total.

expenditures for nuclear generating facilities and fuel will be about

$2.35 billion or 62 per cent of the overall figure. As indicated in the accompanying table. annual expen-ditures are projected to peak in 1984. and then decline to less than one-half in 1987 after completion of Hope Creek I.

Over the next five years. the Company expects with adequate rate relief to generate at least half 7

Activities of members of the Board of Directors are not limited to meet-ings and committee assignments but include inspection trips to various Company locations. In November 1982 the directors, accompanied by senior management, inspected the Company's nuclear facilities. The trip included tours of the Salem and Hope Creek stations and of the new Nuclear Training Center.

of its construction expenditures internally. excluding AFDC. The bal-ance of the requirements will be provided through permanent fi-nancing by the issuance of Mort-gage Bonds. Preferred Stock and Common Stock.

Estimated Construction Expenditures (Including AFDC)

Year 1983 1984 1985 1986 1987 (Millions)

Totals

$904 $971 $884 $659 $401 In April the Company issued amount of 121/a per cent. 30-year

$23.500,000 principal amount of First and Refunding Mortgage 121/z per cent. 30-year First and Bonds.

Refunding Mortgage Pollution Con-The Company also raised trol Bonds.

$80.7 million through the sale of Four million shares of almost four million shares of Com-Common Stock were sold in August man Stock under the Dividend to a group of underwriters at Reinvestment and Stock Purchase

$22.53 a share. Proceeds to the Plan. and $16.4 million through Company from this sale totaled issuance of shares under the Em-

$90.120.000.

ployee Stock Purchase Plan. the Tax In September. the Company Reduction Act Employee Stock sold $100.000.000 principal Ownership Plan. and the Thrift Plan.

amount of 14% per cent. 30-year Proceeds from the sale of S

First and Refunding Mortgage these securities were used to repay ecurities Sold Bonds. At the same time 350,000 short-term debt incurred in con-During 1982 the Company shares of 12.80 per cent Cumula-nection with the Company's raised more than $443 million tive Preferred Stock. $100 par construction program. Short-term through the sale of Mortgage value, were sold.

needs were financed through the Bonds. Preferred Stock and Com-In December. the Company sale of commercial paper. At year man Stock.

sold $100,000.000 principal end there was no short-term debt

__,_ ____________ _, outstanding.

8 A

venues Opened for Financing Abroad Early in the year the Company negotiated a $75 million revolving credit agreement with several major European banks to provide an alternative source of short-term capital. Subsequently, PSE&G Over-seas Finance N.V.. a wholly-owned Netherlands Antilles subsidiary. was formed. The financial subsidiary will be able to provide the Company with access to long-term capital markets abroad.

D ividend Reinvestment Plan Adds Participants There were 67.572 holders of Common Stock participating in the Company's Dividend Reinvest-ment and Stock Purchase Plan at the end of 1982. This was a 26.5 per cent increase from the 53,435 enrolled at year-end 1981.

Members of the Board of Directors and senior management were given an update on plant operations at the Salem Generating Station and a progress report on Hope Creek construction during their tour of the fa-cilities. Nuclear Department personnel conducted the tours. The November meeting of the Board was held at the Nuclear Training Center.

Effective January 1. 1983 greater flexibility was provided in the optional cash investment fea-ture of the Plan. Stockholders may now make optional cash invest-ments at anytime up to $20.000 a year. The limit was previously set at

$5.000 in each quarter.

Holders of record of $1.40 Dividend Preference Common Stock and Preferred Stock. both

$100 and $25 par. also may partici-pate in the Plan. Dividends on these issues are used to purchase Com-mon Stock at 100 per cent of market price average. Common Stock dividends are reinvested at 95 per cent of the market price average.

Federal income tax rules pro-vide that individual stockholders may exclude from gross income.

and thereby defer taxes on divi-dends reinvested in Common Stock under provisions of the Plan. Indi-viduals may defer taxes on up to

$750 in reinvested dividends and those filingjoint returns may defer up to $1.500 of such dividends under qualified public utility plans each year. This provision will be in effect for the years 1982 through 1985 inclusive.

S tockholders At the end of 1982. stock-holders of record totalled 268.696 compared with 273.132 at the close of 1981. a decrease of 1.6 per cent. They included 230.485 owners of Common Stock; 11.806 holders of $1.40 Dividend Prefer-ence Common Stock; 14.946 holders of Preferred Stock -

$1 00 Par; and 11.459 holders of Preferred Stock -

$25 Par.

9

10 Nuclear Operations Consolidated N

uclear operations of the Company were consoli-dated during the year at the site of the Salem and Hope Creek Generating Stations with the establishment there of the headquarters of the newly-formed Nuclear Department.

The department, created in the Fall of 1981, has the responsibility for the safe and efficient operation of the Company's nuclear facilities.

Most employees involved in nuclear activities were trans-ferred from Newark to Salem during the year.

A broad curriculum that covers the various aspects of nuclear operations is provided at the Nuclear Training Center.

Dedication of the Center is planned to take place in April 1983.

Q utstanding Performance by Salem No. 2 An outstanding performance by the No. 2 nuclear unit at the Salem Generating Station in its first full year of commercial operation was a major factor in boosting nu-clear production to 34 per cent of total electric output in 1982.

Overall nuclear production came from four units in which the Company shares ownership with other utilities. The units are the two at the Salem station. which the Company built and operates. and two at the Peach Bottom station in Pennsylvania. The Company has a 42.59 per cent interest in Salem and a 42.49 per cent interest in Peach Bottom.

Salem No. 2 was available 97 per cent of the time in 1982 and for the first eight months of the year led all U.S. nuclear units in total output. an excellent record for a new unit. For all of 1982. the unit's output was second in the na-tion only to Peach Bottom No. 3.

one of two nuclear units at that station.

Salem No. 1 was shut down for refueling and maintenance on October 15. During the operating cycle between refuelings the unit was available nearly 98 per cent of the time. Return of the unit to service. originally scheduled for early January 1983. was delayed.

Repairs in a low pressure river service water system that cools equipment in various support sys-tems required more extensive work than originally anticipated.

N uclear Training Center Opened Construction was completed during the year on the Nuclear Training Center which is located in Salem. N.J., about eight miles from the Salem and Hope Creek stations. Classes for personnel of the stations, which previously had been held in temporary quarters.

were begun at the center.

In addition to classrooms. the center has laboratories. shops and other facilities to support a wide variety of training courses.

Major installations at the cen-ter will be the plant simulators to train control room operating per-sonnel of the stations. The Salem simulator was delivered in early 1983. Delivery of the Hope Creek simulator is scheduled in 1984.

12 P.roduction

& Distribution E

lectric output de-clined by 2.0 per cent in 1982 as sales dropped because of the continuing economic recession, customer conser-vation, and cooler summer weather that reduced de-mand for air conditioning.

Total megawatthours pro-duced, purchased and interchanged amounted to 31.6 million, compared with 32.2 million in 1981.

Electric Peak Load and Installed Capacity at Time of Peak (Millions of Kilowatts) 10.0 9.5 9.0 8.5 8.0 7.5 7.0 6.5 6.0 5.5 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0

1973 74 75 76 77 78 79 80 81 82 Peak Load

• Installed Capacity Peak demand of 7.042 mega-watts occurred on July 19. an increase of 0.1 per cent from the peak of 7.034 megawatts on July

9. 1981. The record high of 7.159 megawatts was reached on July 21.

1980.

The maximum day*s output of 134.654 megawatthours also occurred on July 19. The figure was 1.1 per cent less than the 136.113 megawatthours output on July 9.

1981. and 4.2 per cent below the all-time high of 140.591 mega-watthours on July 21. 1980.

At the time of the system peak load. the Company had an installed generating capacity of 8.995 megawatts, or an installed capacity reserve of 28 per cent. At the end of the year installed gener-ating capacity also was 8.995 megawatts.

The accompanying table shows the planning peak electric loads. installed operating capacities and per cent reserves anticipated for the next ten years.

Gas Peak Sendout and Daily Capacity at Time of Peak (Millions ofTherms) 20 19 18 17 16 15 14 13 12 11 10 9

8 7

6 5

4 3

1 0

Heating 1972 73 74 75 76 77 78 79 80 81 Season 73 74 75 76 77 78 79 80 81 82 24-Hour Peak Sendout

• Manufactured Gas

• Winter Storage Natural Gas High Load Factor Natural Gas Generating Capacity Forecast Year 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 Planning Instilled Peak Load Capacity (Megawatts) 7.025 8,999 7,220 8.999 7.390 8.999 7,555 9,099 7,740 10,013 7.915 10,013 8,070 10,013 8,200 10,013 8.315 10.013 8,395 10,329 L ess Oil Used for Generation Per Cent Reserve 28 25 22 20 29 27 24 22 20 23 The Company continued to cut back its use of oil for electric generation in 1982. As a result.

only 10 per cent of the year's elec-tric output was fueled by oil, down from 13 per cent in 1981.

The reduction was achieved by increased nuclear and coal-fired generation. Nuclear provided 34 per cent of the electric output. up from 25 per cent in 1981. Coal ac-counted for 30 per cent compared with 27 per cent the previous year.

A total of 463 million therms of natural gas. equivalent to 7.6 million barrels of oil, was used at a cost savings of approximately $62 million. although gas use was lower than in 1981. Additional savings of

$2.3 million were realized through spot market purchases of coal and oil.

During the year. 5.8 million barrels of oil, down 23 per cent from 1981. and 2.1 million tons of coal, up 5 per cent. were purchased for New Jersey electric production facilities.

E el Prices Stabilize Oil and coal prices were fairly stable. The average price of low sulfur heavy fuel oil purchased to generate electricity was $33.08 per barrel. 7.0 per cent lower than in 1981. Coal prices for New Jersey facilities increased 4.6 per cent above the-1981 level. The increase was due to increased transporta-tion costs and higher mine labor costs.

Comparative fuel costs in 1982 per million British thermal units were: oil $5.51; coal $2.28; gas $3.98 and nuclear 66 cents.

The Company's electric output by sources in 1982 compared with 1981 follows:

Source 1982 1981 Coal 30%

27%

Oil 10 13 Natural Gas 12 17 Nuclear 34 Purchased and Interchanged 14 100%

U ranium Prices Continue to Decline 25 18 100%

During 1982. the demand for uranium on a national basis contin-ued to decline and prices on the spot market reached a low of $17 a pound in August. Major U.S.

producers purchased surplus uranium to meet their obligations rather than operating mining and milling facilities at a higher cost.

The Company has long term contracts for the supply of uranium. It is expected that suffi-cient uranium will be provided from these contracts and from con-tracts to be negotiated in the future PSE&G's capability to obtain greater amounts of low-cost, coal-generated power from utilities in western Pennsylvania and the M idwest was improved with the installation of 230.000 - volt capacitor banks at two switching stations. Work was the first phase of a Pennsylvania - New Jersey-Maryland Interconnection project to improve transmission capability.

to operate the two Salem units and Hope Creek I through the early 1990's.

The availability of lower cost uranium from these sources has resulted in the further deferment of deliveries under a long-term contract with Kerr-McGee Nuclear Corporation. It is anticipated that the project for supplying this contract will remain in a standby condition until January 1986.

Resumption of production after that date will be at the option of the Company.

Under the Kerr-McGee con-tract. $40.5 million had been advanced as of December 31. 1982 to finance mining and milling facili-ties. The Company advanced 70 per cent of the amount and the co-owners of the Salem and Hope Creek stations advanced the bal-ance. Of these advances. $14.5 million. including $4.7 million of interest. has been recovered through credits against the pur-chase price of uranium concen-trates delivered by Kerr-McGee.

Recoupment of unrecovered advanced payments will depend upon the sale of uranium to the Company or other buyers. or Kerr-McGee's sale of the project properties.

C on Edison Link Completed After several years of con-struction. a second 345.000-volt cable connecting the Hudson Generating Station with Consoli-dated Edison Company's Farragut substation in Brooklyn was placed in service in July.

The cable was part of a com-prehensive project to reinforce existing interconnections with Con Edison. In addition. the project included a second 345,000-volt interconnection between the Company's Waldwick switching station in Bergen County and Con Edison's Ramapo substation in Rockland County. NY.

The new interconnections and associated 230,000-volt reinforce-ments within the Company system will permit increased interchange of power between the two compa-nies and provide more reliable and economic operations.

M ercer Station Among Most Efficient Mercer Generating Station.

which has two large coal-burning units each with a capacity of 306 megawatts. in 1982 ranked among the most efficient facilities in the nation for the second consecutive year.

The 20-year old station had an overall heat rate efficiency of 9.331 Btu/Kwhr. Heat rate is a method employed to measure the 13

14 Critical maintenance has been expedited and costs reduced for work previously contracted outside the company through the operation of the Central Maintenance Shop. Work at the shop includes overhaul and repair of steam and gas turbines.

efficiency of the conve'rsion of.

energy available in fuel to electrical energy. It is one of several factors used to assess the economic opera-tion of a generating unit or plant.

Mercer station achieved a heat rate efficiency of 9.272 Btu/Kwhr in 1981 and ranked fourth in the nation when figures were compiled in mid-1982.

Over the last several years the Company has emphasized a pro-gram of maintenance and rehabili-tation of generating units and stations. This rehabilitation. which included the Mercer station. has in-creased the capability of generating units in achieving higher levels of efficiency. availability and reliability.

D istribution System Expanded The Company's distribution system was expanded with the installation of a new substation and seven new 13.000-volt circuits.

In 1981 the Company volun-tarily initiated a program to elimi-nate all pole-top capacitors filled with polychlorinated biphenyls (PCBs) over a ten-year period.

The schedule was revised in 1982 to comply with the provisions of a Federal law passed in August requiring removal of the capacitors by 1988.

G asSendout Unchanged In 1982 the Company's total gas sendout was 2.15 billion therms. virtually the same as that sent out during 1981. The warmest December on record offset gains due to customer conversions from oil to gas heating and colder weather early in the year.

A new record peak day send-out of 16.201,000 therms was set on January 17. 1982 when the average temperature was - 4°F.

This was 9.4 per cent over the previous record of 14,812,000 therms set on January 12. 1981 when the average temperature was 6°F.

D aily Gas Capacity Improved The Company's daily gas capacity increased by 129.000 therms in 1982. This increase reflected the additional purchase of firm pipeline transportation service for deliveries of gas from storage.

The daily capacity of 19,139.000 therms on December 31 was com-posed of:

Type of Gas Natural Gas Liquefied Petroleum Gas Oil Gas Synthetic Natural Gas Refinery Gas Total Therms Per Day 14,592,000 1,981.000 1,186,000 1.1 25.000 255.000 19,139,000 A

dequate Supplies of Gas Continue Deliveries of pipeline gas by interstate suppliers were curtailed by only 0.2 per cent compared with 0.7 per cent in 1981 and 1.2 per cent in 1980. making three consec-utive years that virtually full con-tract amounts were available to the Company.

The natural gas supplies re-ceived in 1982 were obtained under long-term contracts with three interstate pipelines. from wells owned by Energy Develop-ment Corporation. a Company subsidiary. and through several short-term arrangements with other gas companies.

The amount of natural gas purchased for distribution to cus-tomers totaled 2.02 billion therms.

approximately the same as in 1981.

The average cost of natural gas was $3.59 per million Btu in 1982 compared to $2.95 per mil-lion Btu in 1981. This increase of 21.7 per cent was attributable to the higher wellhead prices allow-able under the Natural Gas Policy Act of 1978 and rate increases put in effect by the Company's pipeline suppliers.

S upplemental Supplies The Company supplements its natural gas supplies with gas pur-chased from Exxon's Bayway Refinery and. in the coldest periods of the winter season. with gas manufactured in Company-owned facilities.

Refinery gas purchases in 1982 amounted to 93.8 million therms. compared to 92.3 million therms in 1981. The cost of this gas averaged $4.76 per million Btu compared to $6.04 per million Btu in 1981. This reduction in cost was principally the result of a renegotia-tion of the pricing provisions in the contract.

The total production of manu-factured gases amounted to 30.2 million therms in 1982 compared to 29.0 million therms in 1981.

A pproval Sought for LNG Facilities The Company continued to seek the required Federal Energy Regulatory Commission (FERC) ap-proval to place in service two lique-fied natural gas tanks and related facilities on Staten Island. New York. to store domestic natural gas for use by the Company and others during periods of peak demand.

Operation of the tanks.

owned by Energy Terminal Services Corporation (ETSC). a Company subsidiary. will require construction of a liquefaction unit and other facilities including a pipeline under the Arthur Kill to New Jersey. The Company's investment in ETSC at the end of 1982 was $76.3 million.

During early 1982 the pro-cessing of the applications before FERC proceeded with the submis-sion of evidence and hearings on economic. need, environmental and safety issues. The FERC staff issued a Final Supplement to its Environ-mental Impact Statement which concluded that the proposed facility would be designed with sufficient safeguards to either prevent acci-dents or reduce the impact of credible accidents.

At year end. the FERC pro-ceedings were still pending. ETSC must also satisfy requirements of the U.S. Department of Transporta-tion relating to pipeline safety.

R ecord Earnings by Exploration Unit Energy Development Corpo-ration. (EDC). the Company's ex-ploration subsidiary. achieved record earnings for the fourth con-secutive year despite reduced natu-ral gas and oil production.

Revenues from the sale of natural gas and oil totaled $73.2 million. a decrease of 2.7 per cent from 1981. Net income increased 4.8 per cent to $12.0 million as a result of reduced operating expenses.

Deliveries of natural gas to the Company totaled 159 million therms in 1982. The subsidiary is the third largest source of gas sup-ply to the Company.

EDC operations reflected the industry-wide slump in drilling activity. During the year EDC drilled a total of 57 wells. a decline of 15 per cent from 1981. Of the total. 29 were onshore and 28 offshore.

Onshore operations were con-centrated in the Gulf Coast region of Texas and Louisiana. The result of onshore drilling was 14 success-ful wells and 15 that were aban-doned. At year end three onshore wells were still being drilled.

Offshore activity included ex-ploratory drilling on six untested lease blocks and development drill-ing to delineate prior discoveries.

During the year 24 wells were classified as successful and four were abandoned. There were two offshore wells still being drilled at year end.

G as System Grows More than 280 miles of main and service lines were added to the underground gas distribution sys-tem during 1982. The total was slightly less than in 1981 because of a decline in the number of custom-ers who converted to gas from oil heat. The connection of nearly 150,000 customers since 1978.

primarily conversions. necessitated numerous reinforcement projects to insure adequate pressures and supplies throughout the service territory.

15

16 customer

& Marketing Services A computer-based system together with up-to-date facilities have pro-vided higher efficiency in operations and enhanced service to customers.

Representatives are able to respond more expeditiously to customer in-quiries with pertinent data, including records of customer accounts, readily available on video display screens. Service also has been stream-lined at centers in downtown urban areas.

A major reorganiza-tion and relocation of customer and marketing operations, begun in 1980, was virtually completed in 1982.

Under a new field organiza-tion there are three divisions -

northern. central and southern -

which oversee nine district offices.

15 customer service centers and two separate meter reading offices.

In addition. there is a centralized customer services division which is responsible for two inquiry and ac-counting centers and a bill payment processing center.

Greater efficiency and pro-ductivity has been realized along with improved customer service under the new arrangement which reflects changing population pat-terns. particularly growth of subur-ban areas. in the Company's service territory.

Large. antiquated commercial offices have been replaced by leas-ing a lesser amount of office space in modern buildings. Customer ser-vice centers. conveniently located in downtown urban areas. provide places where customers can con-tinue to pay bills and make service inquiries.

The modernization program.

together with a new sophisticated computer system. has provided a major advance in the handling of customer accounts. inquiries and work orders.

The first full year of opera-tion of the two customer inquiry and accounting centers. opened during 1981 in Newark and Bor-dentown. also has resulted in a significant improvement in service.

More than 3.4 million cus-tomer service and billing calls were handled with an average response time of 51 seconds. Additional im-provements in service will take place over the next several years as new developments are implemented.

Meter reading was improved and costs were reduced by the use of hand-held microprocessors in a trial program. The microprocessors will be used system-wide in 1983.

At the end of 1982. the Company had 1.705.481 electric customers and 1.319.745 gas customers.

G as Heating Program Accelerated In the first three quarters of 1982. customer requests for gas service declined because of the weak economy and a stabilization in oil prices. An accelerated market-ing and advertising program was undertaken that emphasized the advantages of gas for heating.

including the fact that gas contin-ues to cost less than oil.

During the year. 24,761 new gas customers were connected of whom 22.335 were residential.

2.183 commercial and 243 indus-trial. The residential customers in-cluded 17.267 who converted from oil to gas heat. Of these. 9.329 were connected in the last quarter of the year.

In the electric heating market.

growing customer acceptance of heat pumps continued to increase because of the cost effectiveness of these energy conserving systems.

During the year. 337 commercial and industrial and 2.021 residential heat pumps were installed.

State and municipal author-ities continued to upgrade street lighting facilities which resulted in 10.257 installations of efficient high sodium lights. In addition.

5.837 dusk-to-dawn units were in-stalled. bringing the total to more than 89.000. These installations benefit customers by providing greater safety and security and the Company by the use of electricity in off-peak periods.

Total gas and electric connec-tions made in 1982 will provide an estimated $85 million annually in additional revenues.

The Company formed three consumer advisory panels with representa-tives drawn from the northern, central and southern customer service divisions. The panels represent various social, economic and civic inter-ests and will serve as new communication links with customers. First meetings of the panels featured a slide presentation covering various facets of the Company's operations.

A quaS or Program Gets Under Way The Company's solar water heating program. an outgrowth of a three-year demonstration project.

was implemented in 1982. The first installation was completed late in the year and the Company plans a promotional campaign in 1983.

The program. named "Aqua-Sol". offers residential customers whose homes meet certain criteria a choice of two systems at a cost of between $3.500 and $4.000.

One system uses electricity for backup and the other utilizes natural gas. A family of five could expect a solar system to provide up to half of their annual hot water requirements.

Bm Collection Improvement Program A bill collection improvement program designed to reduce the number of late payments and uncollectible accounts was initiated.

Additional personnel were assigned to collections and new procedures were implemented.

The full impact of these initia-tives is not expected to be seen in collection results until 1983 since they were fully operational only during the last half of 1982.

A late payment charge for commercial and industrial custom-ers was approved by the New Jersey Board of Public Utilities.

effective in January 1983. The charge places a portion of the rising cost of collection on customers who pay bills late.

E fforts Expanded to Prevent Energy Theft The Company's energy theft prevention program was strength-ened during the year. In a pilot project. an eight-member team of specially-trained employees was formed to coordinate efforts in the prevention. detection and investiga-tion of thefts of energy. as well as the collection of revenues due.

The expanded program will include inspections of metering and service equipment. installation of security devices. computerized statistical analysis designed to indicate abnormal usage. and legal actions. The pilot project will pro-vide a basis for a system-wide program.

17

conservation

& Load Management I

n 1982, the Company developed an accelerated plan for conservation, cogen-eration and load manage-ment. The New Jersey Board of Public Utilities (BPU) ap-proved the plan in November and directed other utilities in the state to file similar programs.

The plan resulted from a BPU order in March providing for recovery by the Company of the abandonment costs of the No. 2 Hope Creek unit.

The Company worked with the BPU to develop a plan that would enhance conser-vation and energy efficiency.

Three Energy Update Seminars were con-ducted for management personnel of large industrial and commercial customers. These sessions provided energy information to assist customers in planning. budgeting and operating their facilities.

18 The Company programs are responsive to an increasing desire of customers to conserve energy and to help customers. especially those in low income brackets. to deal with increasing energy costs.

The potential cost-benefits of these programs are somewhat uncertain and each will be re-evaluated on a periodic basis so as to optimize conservation expenditures.

The programs include subsi-dization of loans to finance major home energy saving measures.

the promotion of low cost home energy audits and weatherization assistance. Included also are rebates to customers who install An associate marketing engineer checks a customer's boiler system to determine the feasibility of conversion to gas. Marketing engineers act as liai-sons between the Company and indus-trial and commercial customers.

high efficiency air conditioners and heat pumps. home seal-up services and the utilization of cogeneration.

Subsidized loans to customers for financing the installation of energy saving equipment will be made through banks. The loans are on a zero-interest basis for custom-ers with family incomes of less than

$30.000 a year. Loans to families with income from $30.000 to

$50.000 carry an interest subsidy equal to one-half the prevailing consumer loan rate.

The energy audits are pro-vided under the existing Home Energy Savings Program (HESP).

The promotion includes additional

As part of the Company's conservation and load management activities a number of devices are being evaluated. In a coolness storage unit (left),

ice is made at night when demand for electricity is low, and then used for cooling during daytime periods of peak electric demand. Another device, a heat pump water heater, removes heat from air in home basements and utilizes it in water heating systems.

advertising and a complimentary insulation kit to those who have their home audited.

Energy audits for small com-mercial and industrial businesses also are conducted for a nominal fee. Other facets of the program will include a conservation center staffed by experts with a toll-free number to handle customer in-quiries. and a mobile energy con-servation exhibit.

Weatherization assistance includes the offering of do-it-yourself kits to low-income cus-tomers as well as grants through a state agency. Weather stripping and caulking are parts of the seal-up services offered in the new pro-gram. These will be provided at a nominal fee to gas or electric heat-ing customers. Certain weatheriza-tion services will be offered free of charge to selected low-income residents in the Company's service territory.

Rebates to customers who in-stall high efficiency air conditioners and heat pump equipment are part of the load management aspect of the plan. A study also is being made of the en.ergy savings potential of a refrigerator rebate program.

In addition. the Company will offer reports and graphs to large volume customers served under time-of-day large power and light and high tension rate schedule classifications that will give them analytical tools in determining how to better manage their use of elec-trical energy.

In the area of cogeneration.

the Company is developing an informational program for new and existing customers to increase their awareness of this process. Included is a screening guide to assess cogeneration feasibility. A computerized technical and eco-nomic analysis program will be made available to customers con-sidering cogeneration projects.

The Company will purchase energy from cogenerators and small power producers. Contracts have been signed to purchase elec-trical output from two projects.

the Paterson Falls Hydroelectric Station and the Trenton Integrated Community Energy System. In addition. negotiations are under way with others. including the Port Authority of New York and New Jersey. for energy from proposed resource recovery facilities.

Cogeneration is not new with the Company. Electricity and pro-cess steam have been cogenerated since 1957 at the Linden Generat-ing Station. The steam from the cogeneration process is exchanged with the adjacent Exxon Bayway Refinery for boiler fuel and water.

The Company already has de-veloped a load management pro-gram designed to result in a reduc-tion in projected peak demand by some 1.000 megawatts by 1995.

including interruptible load esti-mates of about 465 megawatts.

The program involves influencing customer use of electricity through means of specialized devices. con-trol equipment and innovative rate making. The interruptible service rate now available to large indus-trial and commercial customers already has resulted in about 130 megawatts of controllable load.

19

20 Area Development Te trend in New Jersey. particularly in the Company's territory. toward a service-oriented economy from one with a heavy indus-trial base. continued during the year. Despite a somewhat soft market, the location and construction of new office facilities stayed at a high level, spurred by ever-increasing cost of space in New York City. Southern New Jersey also continued to attract firms seeking office space.

A promotional program was launched to attract high technology indus-tries to New Jersey. Television, radio and print media were utilized to fea-ture testimonials from leading business executives in the state. Shown during taping of a commercial is Robert H. Franklin, PSE&G Vice President-Public Relations, (left) and Josh Weston, President and Chief Executive Officer of Automatic Data Processing Company.

Recognizing the state*s strength. the Company has con-ducted highly-rewarding promotional campaigns that have attracted numerous office.

research. light industrial and distribution facilities of national and international corporations.

Demand for office space in New Jersey by domestic and foreign firms remained relatively strong in 1982. This was aided by a campaign that promoted New Jer-sey as the "'Headquarters State:*

H igh Technology Firms Sought In the second half of the year.

efforts focused on attracting high technology industries for which the state has distinct advantages. New Jersey has more scientists. engi-neers and technicians per capita than any other state in the nation.

There are more than 650 academic and industrial laboratories and one out of every ten private and federal research dollars is spent in the state.

High technology firms pro-vide the state with an opportunity to replace companies andjobs lost in the traditional manufacturing sector and to accelerate economic growth.

During the year. 306 major industrial and commercial firms.

employing approximately 17.700.

located or expanded in the Compa-ny"s service territory. Lost were 44 companies. employing 7.200. leav-ing a net gain of about 10.500 jobs.

Typical of commercial development in PSE&G's service area is this project under construction in Teaneck. The complex, named Glenpointe, will in-clude a 14-story, 350 -room Loews hotel, two office buildings, 40 shops and 300 town houses.

R apid Meadowlands Development Major development continued during the year in the Meadow-lands with the most significant project being "Harmon Meadow."

the newest project of Hartz Mountain Industries. The $1 billion development will include more than three million square feet of office space; a 100.000-square-foot retail complex; 4.000 residential units and a 156-room Hilton Hotel.

The Hackensack Development Meadowlands Commission over-sees development of the 20.000-acre district in Hudson and Bergen counties. Since its inception in 1968. the Commission has issued 2.208 building permits that have resulted in $493 million in con-struction and the creation of more than 39,000 permanentjobs.

U rban Revitalization Progress continued in urban revitalization in downtown Newark and New Brunswick during the year. Construction advanced in Newark on The Prudential Insur-ance Company's $53 million Gate-way Ill office building. and the $33 million One Washington Park build-ing neared completion. Johnson &

Johnson's $73 million new corpo-rate headquarters was in the final construction stages and a $20 mil-lion Hyatt-Regency Hotel opened in New Brunswick.

The Port Authority of New York and New Jersey announced that. if legislative approval is ob-tained. it plans to provide $100 million in site improvements toward a proposed $500 million renewal project in Hoboken.

The project. to be located along the Hudson River. north of the former Erie Lackawanna Rail-road Terminal. would include a 400-room hotel. 670 residential units. retail stores. 1.4 million square feet of office space and a large marina.

More than eight million persons at-tended events during 1982 at the New Jersey Sports and Exposition Authority's complex in the Meadowlands. Profes-sional hockey was added to the attrac-tions as the Meadowlands arena became the home of the New Jersey Devils of the National Hockey League. The complex also includes Giants Stadium and the Meadowlands Racetrack.

21

zz Research

& Development A significant step in PSE&G's aquaculture program was achieved in 1982 when "Pocono Springs" rainbow trout were sold in supermar-kets. Marketing followed about 10 years of research in aquaculture using the warm-water discharge from the Mercer Generating Sta-tion. Limestone Springs hatchery operations in Richland, Pa., leased in 1979, expanded production of trout to a million pounds per year.

Tai research and devel-opment expenditures in 1982 were $16.8 million. Partially offsetting these costs was

$3.8 million obtained from sales and reimbursements. Of the balance, $4. 7 million was spent for internally-conducted activities and $8.3 million went to support research by industry-sponsored organizations.

A major portion of the Company's research activities are carried out by PSE&G Research Corporation. a subsidiary estab-lished in 1977 to facilitate work on near and long-term energy projects.

During the year. the Research Advisory Council. formed in 1979.

continued to provide advice to PSE&G Research Corporation and serve as a communications link with the public. The council. com-posed of 21 prominent citizens representing a broad public interest. reviews research and development programs. including the level of funding. from an eco-nomic and social viewpoint.

W aste Energy Applications Since 1979. the Company has operated an experimental system to recover methane from a landfill in Cinnaminson. N.J. Methane is a gas generated by decaying matter in the landfill. The gas is being sold to a metal processing plant near the site.

During the year. methane from the landfill also was used to heat a small greenhouse in which vegetables and flowering plants were grown. The plants responded well to the growing conditions in-duced by heat produced by burning the landfill gas.

The Company also was selected during the year to install a gas recovery system at a landfill adjacent to the new headquarters and environmental center of the Hackensack Meadowlands Develop-ment Commission. The system will supply gas to a generating unit which will feed power into the elec-tric grid.

H ydrogen Generating System Tested A prototype advanced elec-trolyzer. a device for making hydro-gen from water. was installed at Sewaren Generating Station during the year. The testing of the elec-trolyzer is a joint project of the Company. the Electric Power Research Institute. and the General Electric Company.

The project will seek to demonstrate. over a two-year period. the economic and technical feasibility of producing hydrogen for Company use instead of pur-chasing it from outside firms.

Hydrogen is used for cooling

Computerized scanning electron microscope at PSE&G Research and Test-ing Laboratory is vital for testing metal samples in evaluation of piping and other equipment utilized at Company facilities. Testing includes anal-ysis of failures. Metallurgical analysis is one of a number of services marketed commercially by the Laboratory.

generators during the production of electricity.

Advanced design electrolyzers hold the promise of a more eco-nomic and reliable source of hydro-gen. The prototype electrolyzer utilizes a solid polymer electrolyte originally developed for fuel cells and oxygen generators used in the space program.

S olar Electric Study The Company and RCA Lab-oratories in Princeton. N.J. com-pleted a study in 1982 on the potential long-range applications of nomically competitive with conven-tional peaking generation.

Photovoltaic generation would require extensive capital in-vestment and more land space than conventional alternatives but it could make some contribution to meeting future energy needs.

E nergy Storage The Company has been a leader in the development of energy storage systems. These sys-tems store electricity generated at times of low demand when it is less expensive to produce for use later at periods of peak demand.

During the year the Company was allocated an additional $1.9 million in funds to continue battery testing and to install an advanced zinc-chloride battery system pro-duced by Energy Development Associates. a subsidiary of Gulf

+ Western Industries. Funding of the project is provided principally by the U.S. Department of Energy and the Electric Power Research Institute. the research arm of the electric utility industry.

L aboratory Work Expanded The Company's Research and Testing taboratory continued in 1982 to help insure a high level of operating efficiency and reliability in service for customers. The Lab-oratory provides testing and anal-ysis programs that measure the quality of materials and equipment used throughout the Company's system.

These programs were expanded to emphasize the use of nondestructive examination and vibration analysis of equipment to monitor performance and lessen failures in energy production and distribution.

Laboratory services in testing

---

~--------------l and analysis are commercially avail-photovoltaic generation as a central station type of power plant in New Jersey. RCA has been doing research work since 1974 on thin-film amorphous-silicon solar cells which appear to have poten-tial for providing a major cost breakthrough.

Based on RCA projected costs for a conceptual photovoltaic power plant to be built in the 1990's. electric power produced from the sun could become eco-The major project in this area is the Battery Energy Storage Test (BEST) facility which is located in Hillsborough. N.J.. adjacent to a Company substation. Construction of the facility was completed in 1981 and testing operations began in 1982 using a 1.8 megawatt-hour lead-acid battery. the world's largest. Results of initial tests indi-cate that batteries can play a significant role in making electric system operations more efficient.

able to other utilities. industries and organizations. For the past several years this type of work has produced additional revenue for the Company. In 1982. such work included the testing and calibration of power systems at industrial sites as well as several municipally-owned substations.

23

24 community

& Employee Relations Two PSE&G financial specialists were among 900 men and women volun-,

teers from across the nation who served during the 1982 summer on President Reagan's Private Sector Survey on Cost Control in the federal government. The two PSE&G representatives were Eileen Moran, a senior J financial analyst. and Frank Cassidy, manager of engineering economics, shown in Washington during a break from their survey work.

T.

Company during 1982 continued to participate in various community activi-ties in its service territory.

Employees served in many volunteer positions in numer-ous civic, cultural and educational organizations.

Particular emphasis was placed on maintaining the Company's long-standing commitment to agencies and groups that work to improve the quality of life of com-munities, especially in urban areas.

Special programs emphasiz-ing educational development for youths in minority groups in urban areas received support.

Two training programs were conducted for unemployed youth among minorities who were referred to the Company by the Greater Newark Private Industry Council. The purpose of the pro-grams was to provide skills for the unemployed that are needed within the business community.

C ommunications A wide-range communications program was conducted in 1982 to supply information about the Company and its activities to stock-holders. the financial community.

the media and the public at large.

Information was provided on a regular basis to the media and the financial community. In addition.

senior company executives in November addressed the New York Society of Security Analysts.

The Company's Speakers*

Bureau presented more than 295 talks before approximately 14.000 persons.

More than 17.600 persons visited the Second Sun the Compa-ny's energy information center at the Salem Generating Station.

Presentations were made on energy-related topics and other subjects of community interest to civic. social and school groups.

More than 190.000 persons at-tended these presentations.

An Energy Education Advisory Committee consisting of 15 ele-mentary. secondary and college educators was formed by the Company during the year. The com-mittee will provide recommenda-tions for the development of energy educational activities.

Initially. the committee reviewed and evaluated educational texts and other materials on energy which resulted in the Company's pur-chase of sets of appropriate material that will be made available to schools on a loan basis.

E mployees Company employees at the end of 1982 totaled 13.118 com-pared with 12.782 at the close of 1981. Wages and salaries for the year totaled $379 million including

$11 million of disability benefits and workers compensation.

The Company continued to stress its Affirmative Action Programs in the employment of women and members of minority groups.

At the end of the year there were 1.918 female employees and 1.903 minority group employees.

The management of PSE&G is responsible for the integrity and objectivity of the financial statements of the Company. These statements are prepared by the Company in accordance with generally accepted accounting principles applied on a consistent basis and include the use of informed estimates where appro-priate. Management believes that they present fairly the Company's financial condition. Information in other parts of this Annual Report is consistent with these financial statements.

The Company maintains an accounting system established with sound accounting and business policies which are communi-cated to the appropriate personnel. The system is designed to provide reasonable assurance that transactions are executed in accordance with management's authorizations and that assets are safeguarded. The concept of reasonable assurance recog-nizes that the costs of internal controls should not exceed the related benefits. The system. together with its related internal controls. is continually reviewed by the Company's staff of internal auditors.

Accounting Principles Financial statements are presented in accordance with generally accepted accounting principles (GAAP). As a result of accounting requirements imposed under rate-making decisions by the Board of Public Utilities of the State of New Jersey (BPU) and the Federal Energy Regulatory Commis-sion (FERC). the applications of GAAP by the Company differ in certain respects from applications by non-regulated busi-nesses. The Company is under the jurisdiction of the FERC and the BPU and maintains its accounts in accordance with their prescribed Uniform Systems of Accounts. which are the same.

Investments in Subsidiaries The Company's investments in its subsidiaries. which in the aggregate are not significant as defined by the Securities and Exchange Commission. are reported in the accompanying financial statements on the equity method of accounting.

The carrying value of investments in subsidiaries is reported under Other Property and Investments in the Balance Sheets. and under the equity method of accounting is ad-justed for earnings or losses of such subsidiaries as reported under Other Income in the Statements of Income.

Revenues Revenues are recorded based on estimated service rendered.

but are billed to customers through monthly cycle billings on the basis of actual usage.

Amortization of Deferred Items Deferred debits are amortized and recovered through rates as prescribed by the BPU. Also see note 5 of Notes to Finan-cial Statements for further information.

Management believes the effectiveness of this system is enhanced by a program of continuous and selective training of employees. In addition. management has communicated to all employees its Policies on Business Conduct. Company Assets and Internal Control.

The firm of Deloitte Haskins & Sells. independent certified pub-lic accountants. is engaged to examine the Company's financial statements and issue an opinion thereon. Their examination is conducted in accordance with generally accepted auditing stan-dards and includes a review of internal controls and tests of transactions.

The Board of Directors carries out its responsibility of finan-cial disclosure through the Audit Committee currently consist-ing of five directors who are not employees of the Company.

The Audit Committee meets periodically with management as well as with representatives of the internal auditors and inde-pendent certified public accountants and reviews the work of each to ensure that their respective responsibilities are being carried out. and to discuss related matters. Both groups have full and free access to the Audit Committee.

Fuel Costs The Company projects the costs of fuel for electric genera-tion. purchased and interchanged power. gas purchased and materials for gas produced for twelve-month periods.

Adjustment clauses in the Company's rate structure allow the recovery of the excess of such projected costs over those included in the Company's base rates through levelized monthly charges over the period of projection. Any under or over recoveries are deferred and charged to operations in the period in which they are reflected in rates.

Utility Plant and Related Depreciation and Amortization The cost of replacements of units of property is charged to utility plant. The cost of maintenance. repairs and replace-ments of minor items of property is charged to appropriate expense accounts. At the time units of depreciable properties are retired or otherwise disposed of. the original cost less net salvage value is charged to the appropriate provision for accumulated depreciation.

Depreciation and Amortization. for financial reporting pur-poses. are computed under the straight-line method.

Depreciation is based on estimated average remaining lives of the several classes of depreciable property. Amortization of leasehold improvements is based on the term of the lease. Depreciation applicable to nuclear plant provides for estimated costs of dismantling or decommissioning. These estimates are reviewed continuously and necessary adjust-ments are made as approved by the BPU. Depreciation provisions stated in percentages of original cost of depreci-able property are 3.52% for 1982. 3.49% for 1981 and 3.48% for 1980.

25

Amortization of Nuclear Fuel Nuclear energy burnup costs are charged to fuel expense on the basis of the number of units of thermal energy produced as they relate to total thermal units expected to be produced over the life of the fuel. The rate calculated for fuel used at all of the Company's nuclear units includes a provision for estimated spent fuel disposal costs. By rate order effective February 14. 1982 amounts previously not permitted to be recovered were recorded and are being recovered through the levelized energy adjustment clause.

Income Taxes The Company and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated. for reporting purposes. to the Company and its subsidiaries based on taxable income or Joss of each.

Deferred income taxes are provided for differences between book and taxable income to the extent permitted for rate-making purposes.

Investment tax credits are deferred and amortized over the useful life of the related property including nuclear fuel.

The Company's tax normalization practices are in compliance with the requirements of the Economic Recovery Tax Act of 1981.

26 Allowance for Funds Used During Construction Allowance for funds used during construction (AFDC) is a cost accounting procedure whereby the cost of financing construction (interest and equity costs) is transferred from the income statement to construction work in progress (CW! P) in the balance sheet. This results in treating such cost in the same manner as construction labor and material costs.

The rates used for calculating AFDC were 8 1/2% for 1982 and 8% for 1981 and 1980 which were within the limits set by FERC.

As a result of BPU rate orders. the Company is allowed to include a portion of CWIP in rate base on which a current return is permitted to be recovered through operating reve-nues. Starting in 1982. the BPU allowed the Company to include in rate base an additional $125.000.000 of CWIP.

raising the total amount to $375,000.000. No AFDC is accrued on this level of CWIP which is included in rate base.

Pension Plan Pension costs are determined on the basis of an acceptable actuarial method and are charged to operating expenses.

utility plant and other accounts. The Company's policy is to fund pension costs accrued. Prior service costs are being funded over a period of 35 years which began January 1.

1967.

For the Years Ended December 3 1.

1982 198 1 1980 Operating Revenues (Thousands of Dollars)

Electric

$2.543.191

$2.322.042

$2.083.900 Gas 1.330.785 1.149.610 910. 154 Total Operating Revenues 3.873.976 3.471.652 2.994.054 Operating Expenses Operation Fuel for Electric Generation and Interchanged Power -

net 959.382 1.059.539 866.802 Gas Purchased and Materials for Gas Produced 821.479 692.3 19 513.988 Other 452.115 385. 149 322.220 Maintenance 220.456 192.768 169.813 Depreciation and Amortization 192.860 178.532 169.987 Amortization of Property Losses (note 5) 43.345 15.362 11.024 Taxes Other than Federal Income Taxes 553.241 474.979 43 1.890 Federal Income Taxes (note 1) 176.639 11 8.737 13 1.1 78 Total Operating Expenses 3.419.517

3. 117.385 2.616.902 Operating Income 454.459 354.267 377.152 Other Income Allowance for Funds Used During Construction -

Equity 58.367 51.877 45.655 Earnings of Subsidiaries -

net (note 2) 10.460 9.490 4.83 1 Miscellaneous -

net 7.118 6.290 5.428 Total Other Income 75.945 67.657 55.914 Income Before Interest Charges 530.404 42 1.924 433.066 Interest Charges Long-Term Debt 198.413 184.133 173.199 Short-Term Debt 13.978 16.574 11.236 Other 8.246 882

5. 127 Allowance for Funds Used During Construction -

Debt (33.060)

(43.802)

(31.897)

Net Interest Charges 187,577 157.787 157.665 Income Before Extraordinary Items 342.827 264.137 275.401 Extraordinary Items. net of income tax (notes 3 and 5) 6.316 Net Income 342.827 264.137 281.717 Dividends on Cumulative Preferred Stock and

$1.40 Dividend Preference Common Stock 53.865 51.538 46.341 Earnings Available for Common Stock

$ 288.962

$ 212.599

$ 235.376 Shares of Common Stock Outstanding End of Year 94.844.596 86.089.491 76.614.995 Average for Year 89.233.028 80.962.344 73.068.848 Earnings per average share of Common Stock before Extraordinary Items

$ 3.24

$ 2.63

$ 3. 13 Extraordinary Items. net of income tax (notes 3 and 5)

.09 Earnings per average share of Common Stock

$ 3.24

$ 2.63

$ 3.22 Dividends paid per share of Common Stock

$ 2.53

$ 2.44

$ 2.29 See Summary of Significant Accounting Policies and Notes to Financial Statements.

27

December 31.

Assets Utility Plant Original cost Electric Plant Gas Plant Common Plant Nuclear Fuel Utility Plant in Service Less Accumulated Depreciation and Amortization Net Utility Plant in Service Construction Work in Progress Plant Held for Future Use Net Utility Plant Other Property and Investments Nonutility Property. net of accumulated depreciation -

1982. $2.675: 1981. $204 Investments in and Advances to Subsidiaries (note 2)

Total Other Property and Investments Current Assets Cash (note 4)

Working Funds Pollution Control Bonds Escrow Funds Temporary Cash Investments Accounts Receivable. net of allowance for doubtful accounts -

1982. $13.291 : 1981. $12.563 Unbilled Revenues Fuel. at average cost Materials and Supplies. at average cost Prepayments Total Current Assets Deferred Debits (note 5)

Extraordinary Property Losses Hope Creek Unit 2 Atlantic Project Other Gross Receipts Taxes Unamortized Nuclear Fuel Disposal Costs Unamortized Debt Expense Total Deferred Debits Total See Summary of Significant Accounting Policies and Notes to Financial Statements.

28 1982 1981 (Thousands of Dollars)

$4.638.440

$4.459.245 1.083.183 1.020.236 137,650 126.561 60,987 55.445 5.920,260 5.661.487 2.065.510 1.874,668 3.854,750 3.786.819 2.157,900 1.637.277 22.416 21.997 6.035.066 5.446.093 11.702 8.408 287.934 261.010 299.636 269.418 9.981 5.595 24.308 10.665 4.108 49.900 376.589 377.924 182.287 176.948 261,9 17 218.223 44.659 40.071 8.743 8.646 962.492 838.072 262,767 290.750 260.412 275.472 3.330 3.632 12.899 31.867 47.269 23.096 23.639 609.773 625.360

$7.906,967

$7.178.943

Liabilities Capitalization Common Equity Common Stock (see statements. page 32)

Premium on Capital Stock Paid-In Capital Retained Earnings (see statements. page 31)

Total Common Equity Preferred Stock without mandatory redemption (see statements. page 32)

Preferred Stock with mandatory redemption (see statements. page 32)

Long-Term Debt (see statements. page 33)

Total Capitalization Current Liabilities Long-Term Debt due within one year Preferred Stock to be redeemed within one year Commercial Paper (note 6)

Accounts Payable Taxes Accrued. including New Jersey Gross Receipts Taxes -

1982. $514.378: 1981. $4 75.856 Deferred Income Taxes. Unbilled Revenues (note 1)

Interest Accrued Gas Purchased Other Total Current Liabilities Deferred Credits Accumulated Deferred Income Taxes (note 1)

Deferred Electric Energy and Gas Fuel Costs -

net Extraordinary Property Losses Hope Creek Unit 2 Atlantic Project Depreciation and Amortization Other Accumulated Deferred Investment Tax Credits (note 1)

Over (Under) recovered Electric Energy and Gas Fuel Costs -

net (note 5)

Nuclear Fuel Disposal Costs (note 5)

Other Total Deferred Credits Commitments and Contingent Liabilities (note 8)

Total 1982 1981 (Thousands of Dollars)

$1.610.879

$1.423.739 557 557 26.185 26.143 888.262 827.497 2,525.883 2.277.936 554.994 554.994 111.250 77.913 2.579.782 2.410.823 5.771.909 5.321.666 48.243 2.230 381 207.551 263.913 262.734 535.318 492.010 83.852 81.396 57.925 47.750 107.583 83.641 49.927 45.111 1.147.142 1.222.423 (32.595) 45.619 108.223 126.327 109.493 115.896 358.545 312.595 (6.851) 11.577 301.420 113.890 66.672 (98.146) 58.622 24.387 7.096 987.916 634.854

$7.906.967

$7.178.943 29

For the Years Ended December 31.

1982 1981 1980 Funds Provided (Thousands of Dollars)

Income before Extraordinary Items

$ 342.827

$264.137

$275.401 Add (Deduct) Items not affecting Working Capital Depreciation and Amortization 304.319 231.431 207.650 Recovery (Deferral) of Electric Energy and Gas Fuel Costs -

net 164.818 Provision for Deferred Income Taxes (note 1) 104.199 (28.068)

Depreciation and Amortization -

net 45,950 37,716 39.136 Extraordinary Property Losses -

net (24.507) 119.991 (4.571)

Deferred Electric Energy and Gas Fuel Costs -

net (78.214)

(48.188) 12.634 Other -

net (18.428)

(4.640)

(3.262)

Investment Tax Credits -

net 205,261 4.998 5.844 Allowance for Funds Used During Construction (AFDC)

(91.427)

(95.679)

(77.552)

Equity in Net Earnings of Subsidiaries (10.460)

(9.490)

(8.610)

Other (963)

(1.419) 141 Total Funds from Operations 839.176 603.056 418.743 Income from Extraordinary Items -

net (notes 3 and 5) 6.316 Related Items not affecting Working Capital Sale of Transport of New Jersey (note 3) 18.155 Unrecoverable Costs of Atlantic Project (note 5) 13.219 Total Funds from Extraordinary Items 37.690 Total Funds from Internal Sources 839.176 603.056 456.433 Net proceeds from sales of Long-Term Debt 221.022 99.320 99,042 Preferred Stock 34.646 49.456 Common Stock 186,883 171.420 144.839 Total Security Sales 442.551 320.196 243.881 Total Funds Provided

$1.281.727

$923.252

$700.314 Funds Applied Additions to Utility Plant. excluding AFDC

$ 721.948

$588.170

$547.978 Cash Dividends 281.459 249.061 215.158 Advances to Subsidiaries 16.464 31.026 45.154 Reductions of Long-Term Debt 50.553 5.572 34.345 Hope Creek Unit 2 Abandonment (note 5)

Total Construction Costs. including AFDC of $33.000 (223.000)

Recoverable Costs. including deferred cancellation costs 290.750 Miscellaneous 11.602 17.506 (6.011)

Total Funds Applied 1.082.026 959.085 836.624 Changes in Working Capital -

Increase (Decrease)

Short-Term Debt 207,551 (26.686)

(85.990)

Long-Term Debt due within one year (46.013) 30.835 (8.866)

Cash 4.386 1.844 (1.654)

Working Funds 13.643 1.288 1.154 Pollution Control Bonds Escrow Funds 4,108 (1 1.248)

Temporary Cash Investments 49,900 Accounts Receivable (1.335) 25.929 118.8 11 Unbilled Revenues 5,339 13.602 49.469 Fuel 43.694

35. 164 7.363 Accounts Payable (1.179)

(56.838)

(84.580)

Taxes Accrued (43.308)

(55.860)

(73.500)

Deferred Income Taxes (note 1)

(2.456)

(6.257)

(22.756)

Gas Purchased (23.942)

(8.762)

(25.934)

Other *

(10.687) 9.908 1.421 Net Increase (Decrease) in Working Capital 199.701 (35.833)

(136.310)

Total Funds Applied and Changes in Working Capital

$1.281.727

$923.252

$700.314 See Summary of Significant Accounting Policies and Notes to Financial Statements.

30

For the Years Ended December 31.

1982 1981 1980 (Thousands of Dollars)

Balance January 1

$ 827.497

$ 813.181

$ 747.076 Add Net Income 342.827 264.137 281.717 Total 1.170.324 1.077.318 1.028.793 Deduct Cash Dividends Preferred Stock. at required rates 51.984 49.657 44.414

$1.40 Dividend Preference Common Stock 1.881 1.881 1.881 Common Stock*

227.594 197.523 168.863 Total Cash Dividends 281.459 249.061 215.158 Capital Stock Expenses 603 760 454 Total Deductions 282.062 249.821 215.612 Balance December 31

$ 888.262

$ 827.497

$ 813.181

• Restrictions on the payment of dividends are contained in the Charter. certain of the indentures supplemental to the Company's Mortgage. and certain debenture bond indentures. However. none of these restrictions presently limits the payment of dividends out of current earnings. The amount of retained earnings free of these restrictions at December 31. 1982 was $878.262.000.

See Summary of Significant Accounting Policies and Notes to Financial Statements.

Deloitte Haskins+Sells Certified Public Accountants 550 Broad Street Newark. New Jersey 07102 To the Stockholders and Board of Directors of Public Service Electric and Gas Company:

We have examined the balance sheets and statements of capital stock and long-term debt of Public Service Electric and Gas Company as of December 31. 1982 and 1981 and the related statements of income. retained earnings. and changes in financial position for each of the three years in the period ended December 31. 1982. Our examinations were made in accordance with generally accepted audit-ing 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. such financial statements. appearing on pages 25 to 39. inclusive. present fairly the financial position of Public Service Electric and Gas Company as of December31.1982and 1981 andtheresultsofits operations and the changes in its financial position for each of the three years in the period ended December 31.

1982. in conformity with generally accepted accounting principles applied on a consistent basis.

February 14. 1983 31

December 31.

Outstanding Shares (note A)

Nonparticipating Cumulative Preferred Stock (note B)

With Mandatory Redemption (note C)

$100 par value -

Series 12.25%

13.44% (500.000 shares issued in 1981) 12.80% (350.000 shares issued in 1982)

Less amount to be redeemed within one year Preferred Stock with Mandatory Redemption Without Mandatory Redemption (note D)

$25 par value-Series 9.75%

8.70%

$100 par value-Series 4.08%

4.18%

4.30%

5.05%

5.28%

6.80%

9.62%

7.40%

7.52%

8.08%

7.80%

7.70%

8.16%

Preferred Stock without Mandatory Redemption (no changes in 1981 and 1980) 266.306 500.000 350.000 1.600.000 2.000.000 250.000 249.942 250.000 250.000 250.000 250.000 350.000 500.000 500.000 150.000 750.000 600.000 300.000 Dividend Preference Common Stock and Common Stock Current Redemption Price Per Share

$112.00 113.44 112.80

$ 26.50 26.50 103.00 103.00 102.75 103.00 103.00 102.00 107.00 103.00 103.00 103.00 103.00 106.56 106.86 Certain Refundings Restricted Prior to 2/1/85 4/1/86 10/1/87 1982 1981 (Thousands of Dollars)

$ 26.631

$ 27.913 50,000 50.000 35,000 381

$111.250

$ 77.913

$ 40.000

$ 40.000 50.000 50.000 25.000 25.000 24.994 24.994 25.000 25.000 25.000 25.000 25,000 25.000 25.000 25,000 35.000 35.000 50,000 50.000 50.000 50.000 15.000 15.000 75,000 75.000 60.000 60.000 30.000 30.000

$554.994

$554.994

$1.40 Dividend Preference Common Stock (no par) -

1.343.999 shares authorized.

issued and outstanding: current redemption price $35.00 per share (note E)

Common Stock (no par) -

authorized 150.000.000 shares (note F): issued and outstanding as of December 31. 1982. 94.844.596 shares and as of December 31. 1981. 86.089.491 shares (8.755.105 shares issued for $187.140.000 in 1982: 9.474.496 shares issued for

$171.636.000 in 1981: and 7.700.646 shares issued for $145.279.000 in 1980)

$1.610.879

$1.423.739 Notes A. In addition. there are 1.733.752 shares of $100 par value and 6.400.000 shares of $25 par value Cumulative Preferred Stock which are authorized and unissued. and which upon issuance may or may not provide for mandatory sinking fund redemption.

B. As of December 31. 1982 the annual dividend requirement and embedded dividend costs were $14.462.000 and 13.18%. respec-tively. for Preferred Stock with mandatory redemption and

$40.629.000 and 7.38%. respectively. for Preferred Stock with-out mandatory redemption.

If dividends upon any shares of such stock are in arrears to an amount equal to the annual dividend thereon. voting rights for the election of a majority of the Board of Directors become operative and continue until all acccumulated and unpaid dividends thereon have been paid. whereupon all such voting rights cease. subject to being again revived from time to time.

C. The 12.25% series is subject to a mandatory annual sinking fund redemption of 17.500 shares which is cumulative. plus redemption of up to an additional 17.500 shares at the option of the Company.

all at a redemption price of $100 per share. An aggregate of 12.822 shares. 27.672 shares and 43.200 shares of the 12.25%

series were purchased and redeemed in 1982. 1981 and 1980. re-spectively. On March 31. 1987. the 13.44% series will become sub-ject to a mandatory annual sinking fund redemption of 25.000 shares which is cumulative. plus redemption of up to an additional 32 25.000 shares annually at the option of the Company. all at a re-demption price of $100 per share. On September 30. 1988. the 12.80% series will become subject to a mandatory annual sinking fund redemption of 17.500 shares which is cumulative. plus re-demption of up to an additional 17.500 shares annually at the option of the Company. all at a redemption price of $100 per share.

These series are subject to optional redemption upon payment of the applicable optional redemption price. A redemption of shares of any series also requires payment of all accumulated and unpaid divi-dends to the date fixed for redemption.

D. Preferred Stock without mandatory redemption is subject to re-demption solely at the option of the Company upon payment of the applicable redemption price plus accumulated and unpaid dividends to the date fixed for redemption.

E. Each share of $1.40 Dividend Preference Common Stock is enti-tled to cumulative dividends. to two votes. and. on liquidation or dissolution to twice as much as each share of Common Stock. There were no changes in outstanding shares in 1982. 1981. or 1980.

F. Includes 18.273.462 shares of Common Stock reserved for possible issuance under the Company's Dividend Reinvestment and Stock Purchase Plan. Tax Reduction Act Employee Stock Ownership Plan. Employee Stock Purchase Plan and Thrift Plan.

See Summary of Significant Accounting Policies and Notes to Financial Statements.

December 31,

1982 1981 (Thousands of Dollars)

First and Refunding Mortgage Bonds (note A)

Series 3 1/4% October 1. 1983 21,294 $

21.304 3 1/4% May 1. 1984 50,000 50.000 4% % November 1. 1986 50,000 50.000 47/aO/o September 1. 1987 60.000 60.000 4% % August 1. 1988 60.000 60.000 5 1/aO/o June 1. 1989 50,000 50.000 4%% September 1. 1 990 50,000 50.000 4%% August 1. 1992 40,000 40.000 4%% June 1. 1993 40.000 40.000 4% % September 1. 1 994 60.000 60.000 4% % September 1. 1995 60,000 60.000 6 1/4% June 1. 1997 75.000 75.000 7

% June 1. 1998 75.000 75.000 7%% April 1. 1999 75.000 75.000 9 1/aO/o March 1. 2000 98.000 98.000 8%% A May 15. 2001 69,300 69.300 7%% B November 15. 2001 80.000 80.000 7 1/2% C April 1. 2002 125.000 125.000 8 1/2% 0 March 1. 2004 90.000 90.000 12

% E October 1. 2004 10,730 10.730 8%% F April 1. 2006 60.000 60.000 8.45% G September 1. 2006 60.000 60.000 8 1/4% H June 1. 2007 125,000 125.000 8 1/aO/o I September 1. 2007 59,900 59.900 9%% J November 1. 2008 100,000 100.000 9%% K July 1. 2009 100.000 100.000 12

% L November 1. 2009 125.000 125.000 12 1/aO/o MJune1.2010 100,000 100.000 157/aO/o N August 1. 1991 100.000 100.000 14%% 0 September 1. 2012 100.000 12 1/aO/o P December 1. 2012 100.000 8

% June 1. 2037 7.463 7.463 5

% July 1. 2037 7.538 7.538 Pollution Control Series 6.30% A October 1. 2006 14.300 14.300 6.90% B September 1. 2009 42,620 42.620 6.90% C September 1. 2009 2.990 2.990 12 1/2% D April 1. 2012 23,500 Total First and Refunding Mortgage Bonds

$2.367.635 $2.144.1 45 Notes A. The Company's Mortgage. securing the First and Refunding Mortgage Bonds. constitutes a direct first mortgage lien on sub-stantially all property and franchises.

B. As of December 31. 1982 the annual interest requi rement on Long-Term Debt was $220.828.000 of which $201. 166.000 was the requirement for First and Refunding Mortgage Bonds. The embedded interest cost on Long-Term Debt was 8.60%.

C. As of December 31. 1982. the Company had unexercised com-mitments under a Credit Agreement with 12 domestic banks for issuance of revolving loans up to an aggregate amount of

$200.000.000 to be outstanding at any time to April 1. 1984. The Debenture Bonds unsecured 4%% October 1. 1983 5%% June 1. 1991 7 1/40/o December 1. 1993 9 % November 1. 1995 7%% August 15. 1996 8%% November 1. 1996 6 % July 1. 1998 Total Debenture Bonds Other Long-Term Debt 6 1/2% Note due serially to November 15. 1983 Total Long-Term Debt Principal amount out-standing (notes Band C)

Less amount due within one year (note D)

Long-Term Debt excluding amount due within one year (note D)

Net Unamortized Discount Long-Term Debt less Net Unamortized Discount 1982 1981 (Thousands of Dollars) 24.800 $

24.832 39.597 40.557 28.385 29.329 54.694

56. 145 57.340 59.040 42.010 43.059 18,195 18,195 265.021 271. 157 720 1.200 2.633.376 2.4 16.502 48.243 2.230 2.585.133 2.4 14.272 (5.351)

(3.449)

$2.579.782 $2.4 10.823 Company may terminate the commitments. in whole or in part.

without penalty or premium. Under the agreement. any borrow-ings outstanding at April 1. 1984 are convertible. at the Company"s option. into three year term loans. The Company is required to pay commitment fees of 3!a of 1 % per annum on the first

$125.000.000 and 1/s of 1 % per annum on the next $75.000.000 of any unused portion. The Company has the right. with the con-sent of the banks. to extend the agreement on a year to year basis.

D. The aggregate principal amounts of requirements for sinking funds and maturities for each of the five years following December

31. 1982 is as fol lows:

Sinking Year Funds Maturities Total (Thousands of Dollars) 1983

$1.429

$ 46.814

$ 48.243 1984

6. 197 50.000 56.1 97 1985 6.200 6.200 1986 6.200 50.000 56.200 1987 6.200 60.000 66.200

$26.226

$206.814

$233.040 For sinking fund purposes. certain First and Refunding Mortgage Bond issues require annually the retirement of $22.400.000 princi-pal amount of bonds or the utilization of bondable property addi-tions at 60% of cost. The portion expected to be met by property additions has been excluded from the table above. Also. the Company may. at its option. retire additional amounts up to

$6.200.000 annually through sinking funds of certain debenture bonds. The election of any such option is included in long-term debt due within one year See Summary of Significant Accounting Policies and Notes to Financial Statements.

33

1. Federal Income Taxes A reconciliation of reported Net Income with pre-tax income and of Federal income tax expense with the amount computed by multiplying pre-tax income by the statutory Federal income tax rate of 46% is as follows:

Net Income Federal income taxes included in:

Operating income Current provision Provision for deferred income taxes-net*

Investment tax credits -

net Total included in operating income Miscellaneous other income -

net Extraordinary Items Total Federal income tax provisions Subtotal Earnings of subsidiaries -

net Pre-tax income Tax expense at the statutory rate 1982 1981 1980 (Thousands of Dollars)

$342.827 $264.137 $28 1.717 34.762 2.603 58.64 1 (72.743) 111.136 66.693 214.620 4.998 5.844 176.639 118.737 131.178 3.265 3.586 1.703 (54.885) 179.904 122.323 77.996 522.731 386.460 359.713 (10.460)

(9.490)

(4.831)

$512.271 $376.970 $354.882

$235.645 $173.406 $163.246 Adjustments to pre-tax income. computed at statutory rate.

for which deferred taxes are not provided under current rate-making policies:

Tax depreciation under book depreciation 21.837 18.608

16. 16 1 Allowance for funds used during construction (42.056)

(44.012)

(35.674)

Overhead costs capitalized (11.500)

(8.858)

(7.262)

Extraordinary Items (32.543)

Other (277) 445 (2.890)

Subtotal (31.996)

(33.817)

(62.208)

Amortization of deferred tax items (23.745)

(17.266)

(23.042)

Subtotal (55.741)

(5 1.083)

(85.250)

Total Federal income tax provisions

$179,904 $122.323 $ 77.996

• The provision for deferred income taxes represents the tax effects of the following items:

Current Liabilities Unbilled revenues Deferred Credits Hope Creek Abandonment Atlantic Abandonment Additional tax depreciation Repair allowance property Gross receipts taxes Deferred fuel costs -

net Nuclear Plant Decommissioning Costs Nuclear Fuel Disposal Costs Loss on reacquired debt Other Subtotal Total 34 2.456 $

6.257 $ 22.756 (18.104)

(6.403) 48.791 (4.524)

(2.912)

(78.214)

(4.651) 126.327 (6.336) 41.479 (5.236)

(2.033)

(48.188)

(10.150)

(1.775)

(415)

(571 )

1.383 1.212 (75.199) 104.879

$ (72.743) $111.136 (4.587) 31.799 6.362 (985) 12.634 (1.492)

(570) 776 43.937

$66.693 As a result of an Internal Revenue Service (IRS) audit for tax-able years 1976 through 1978. the IRS has proposed an in-crease in taxable income which would increase tax liability by approximately $8 million. after using available investment credits of $44 million. This is primarily the result of including unbilled revenues as taxable income in the year estimated services were provided. The Company has not agreed to the results of this audit and is presently appealing the I RS assessment.

Investment tax credits -

net for 1982 includes credits carried forward from 1978 through 1981. The balance of investment tax credits not utilized as of December 31. 1982. in the amount of $44 million. is available as a carryover to future years and will expire in 1997. Should the IRS prevail in its assessment.

this investment credit carryover would be eliminated. Invest-ment tax credits can be utilized to offset 90% of 1982 tax liability before investment credit. 80% of 1981 tax liability and 70% of 1980 tax liability.

The Company has a Tax Reduction Act Employee Stock Owner-ship Plan (TRASOP) under provisions of the Internal Revenue Code of 1954, as amended (the Code). Such provisions permit the Company to elect an additional 1 % investment tax credit ifthe Company transfers to the TRASOP an equivalent amount of cash for the purchase of shares of Common Stock. The Company may also claim an additional 1/2% investment tax credit if it contributes an equivalent amount of cash to the TRASOP. but only to the extent that such amount is matched by contributions by participants.The Company presently estimates that all TRASOP credits claimed will be utilized no later than in its 1983 tax return.

2. Investments in and Advances to Subsidiaries Investments in and advances to subsidiaries (including the Company's equity in undistributed earnings or losses) are sum-marized as follows:

December 31.

Energy Development Corporation Investment Advances Other Subsidiaries. primarily LNG Project Advances Total 1982 1981 1980 (Thousands of Dollars)

$ 37.628 $ 25.663 $ 14.245 172.368 151.168 123.034 209.996 176.831 137.279 77.938 84.179 83.2 15

$287.934 $26 1.010 $220.494 The major subsidiary included in "Other Subsidiaries" above is Energy Terminal Services Corporation (ETSC). Its principal asset. which has not been placed in operation. is a Liquefied Natural Gas (LNG) terminal on Staten Island in the New York City harbor area. Annual expenditures for protection and main-tenance of the terminal. including local real estate taxes. are approximately $4.0 million.

The Company had originally intended to utilize the terminal for the importation of LNG. However. due to uncertainties and delays relating to the importation project. including lack of regulatory approvals which resulted in a loss of a supply of LNG. the terminal has not been placed in operation. ETSC is now pursuing the utilization of the two storage tanks at the terminal to provide an LNG peaking service for the Company and others. This will necessitate the construction of a liquefac-tion facility at the site. The additional construction will not pro-ceed until the necessary permits are obtained from the

appropriate federal. state and local regulatory agencies. The proposed service will increase the Company's capability to store supplies of domestic natural gas in order to meet the demands of its customers for gas on the coldest winter days.

If necessary permits are not received and the facilities are not placed in service. the Company would anticipate seeking favora-ble rate treatment from the BPU for any loss which may occur.

Any loss not provided for. in the opinion of management. would not have a material effect on the financial position or results of operations of the Company.

3. Sale of Transport of New Jersey On October 14. 1980. the Company sold all of the outstanding capital stock of Transport of New Jersey (TNJ) to New Jersey Transit Corporation (NJTC). an agency of the State of New Jer-sey. for $32.1 million. This resulted in a pre-tax loss of $30.0 million which was more than offset by income tax benefits to the Company of $49.5 million. Such tax benefits resulted in a non-recurring credit to earnings for 1980 of $19.5 million or 27C per average share of Common Stock.

4. Compensating Balances Cash at December 31. 1982 and December 31. 1981 consisted primarily of compensating balances under informal arrange-ments with various banks to compensate them for services and to support lines of credit of $180.9 million and $178.2 mil-lion. respectively. There are no legal restrictions placed on the withdrawal or other use of these bank balances. In addition. at December 31. 1982 and December 31. 1981. the Company had

$35.0 million and $30.0 million. respectively. of lines of credit which were compensated for by fees.

5. Deferred Items Abandonment of Hope Creek Unit No. 2 On December 23. 1981. the Company abandoned the construc-tion of Hope Creek Generating Station Unit No. 2 in Lower Alloways Creek Township. New Jersey. Total unrecovered costs of $290.8 million. including an estimated $67.8 million of can-cellation and close-out costs. were charged to Extraordinary Property Losses and the associated tax reduction of $126.3 million was included in Accumulated Deferred Income Taxes.

On March 4. 1982. the BPU authorized the transfer of $112 million of Hope Creek 2 costs to Hope Creek 1 and recovery of all after-tax abandonment costs for Hope Creek 2 from custom-ers through the levelized electric energy adjustment clause. The recovery is over 15 years on an accelerated method which com-menced June 1982. During 1983. the amount of amortization will be $33.2 million. less related taxes of $13.5 million.

Abandonment of Atlantic Proj ect In December 1978. the Company cancelled its floating nuclear plant project which was to have consisted of four generating units. The BPU is allowing the Company to recover the costs relating to the project over a period of 20 years commencing on April 17. 1980 exclusive of $18.6 million which. after a re-lated tax reduction of $5.4 million. resulted in a net extraordi-nary charge to income in 1980 of $13.2 million or 18C per average share of Common Stock.

Costs are being amortized in the amount of $15.1 million annu-ally. less related taxes of $6.3 million.

Gross Receipts Taxes Effective January 1. 1973. the Company began accruing New Jersey gross receipts taxes on current revenues rather than on the previous basis of taxes paid. The gross receipts taxes on 1972 revenues were deferred and are being charged to opera-tions by an amount equivalent to 1/2% of revenues subject to the gross receipts tax. During 1983 the Company expects to amortize the remaining $12.9 million. less related taxes of $5.9 million.

Unamortized Debt Expense These costs. associated with the issuance or reacquisition of debt. are deferred and amortized over the lives of the related issues. Amounts shown in the Balance Sheets consist principally of costs associated with the Company's tender offer for its 12%

Series E Mortgage Bonds which will mature in October 2004.

The Company expects to amortize $1.1 million of these costs in 1983.

Over (Under) recovered Electric Energy and Gas Fuel Costs -

net The net overrecovered costs as of December 31. 1982 consist primarily of overrecovered electric costs of $45.2 million and overrecovered gas costs of $34.0 million. which will be re-funded to customers through reduced bills during the remain-ders of the respective current levelized periods. The offsetting balance of $12.5 million represents underrecovered electric costs from prior periods which are expected to be recouped by the end of February 1984.

Nuclear Fuel Disposal Costs In February 1982 previously unallowed nuclear fuel disposal costs were recorded and amortization of such costs com-menced. Salem 2 costs are being amortized over two years and Peach Bottom 2 and 3 costs are being amortized over seven years. The unamortized balance consists of $1.6 million applica-ble to Salem 2 and $45.6 million applicable to Peach Bottom.

During 1983 the Company expects to amortize $8.9 million of such costs less related taxes of $4.1 million. In 1982 the Company recorded $58.6 million of estimated nuclear fuel disposal costs applicable to Peach Bottom 2 and 3 together with a deferred liability pending the establishment of a payment schedule by the Department of Energy (D.O.E.). Until regula-tions are issued by the D.O.E.. the Company is presently unable to determine when payments of the deferred liability will com-mence or the amounts of such payments.

6. Bank Loans and Commercial Paper Bank loans represent the Company's unsecured promissory notes issued under credit arrangements with various banks and have a term of eleven months or less. Such notes were issued to a limited extent in 1981.

Commercial paper represents the Company's unsecured bearer promissory notes sold to dealers at a discount with a term of nine months or less. Certain information regarding short-term debt follows:

Maximum amount outstanding at any month end Average daily outstanding (A)

Weighted average annual interest rate (B)

Weighted average interest rate for commercial paper outstanding at year end 1982 1981 (Thousands of Dollars)

$216.015 $207.55 1

$107.950 $101.226 12.95%

16.27%

None 12.72%

(A) Computed by dividing the sum of the daily principal amounts out-standing during the year by the total number of days in the year.

35

(B) Computed by dividing short-term interest expense by the average daily short-term net proceeds.

7. Pension Plan The Company has a non-contributory. trusteed plan covering all employees who complete one year of service. As of December

31. 1982. the unfunded prior service costs were approximately

$323.370.000. Information on accumulated plan benefits and net assets follows:

December 31.

Actuarial present value of accumulated plan benefits Vested Nonvested Assumed rate of return Market value of Plan Net Assets 1982 1981 (Thousands of Dollars)

$357.290 $326.343

45. 782 33.616

$403.072 $359.959 10.0%

10.5%

$367.702 $283.021 The Company's annual contribution is actuarially determined to provide for full funding by December 31. 2001. Pension costs for the past three years were charged as follows:

Operating Expenses Utility Plant and Other Accounts Total Pension Costs 1982 1981 1 980 (Thousands of Dollars)

$50.286

$47.505

$38.042 10.344 10.954 10.284

$60.630

$58.459

$48.326 The Company offered a special early retirement program dur-ing the period from June 1. 1980 to October 1. 1980 to em-ployees meeting certain age and service requirements. Under the program. 1.367 employees retired. Employees who retired under the program are paid an unreduced pension under the Company's Pension Plan and a special supplement. initially

$500 per month and increasing to $650 per month. payable out of the Company's general funds. The special supplement ceases at age 65. upon death. or upon re-employment by the Company. It is estimated that the special supplement will cost the Company $50 million over ten years beginning 1980. As al-lowed by the BPU. these costs are being recovered as incurred.

The unreduced pension provision under the Plan requires addi-tional funding which is included in the unfunded prior service cost.

8. Commitments and Contingent Liabilities The Company has substantial commitments as part of its con-struction program as well as commitments to obtain sufficient sources of fuel for electric generation and adequate gas sup-plies. Construction expenditures of $3.8 billion. including $736 million of AFDC. are expected to be incurred during the years 1983 through 1987.

A contract with Kerr-McGee Nuclear Corporation to supply uranium concentrates was amended in 1980 to substantially curtail open pit mine operations. In November 1982 an agree-ment was reached with Kerr-McGee which calls for an extension of the curtailed operations until January 1. 1986. As of Decem-ber 31. 1982. the Company and the co-owners of the Salem and Hope Creek Generating Stations had advanced $40.5 million to Kerr-McGee against deliveries of uranium concentrates.

Credits have been received amounting to $14.5 million. includ-ing interest of $4.7 million. The recoupment of $30.7 million.

36 the balance of such advances. of which approximately 30% is the responsibility of the other co-owners. is dependent upon the sale of uranium concentrates by Kerr-McGee to the Company or other buyers or upon the sale by Kerr-McGee of the project properties. The Company cannot presently predict the extent to which such advance payments will ultimately be recovered. For additional information see page 13.

The Company's insurance coverages for its nuclear operations are as follows:

Maximum Retrospective Maximum Assessment for a Type and Source of Coverage Coverage single incident Public Liability American Nuclear Insurers Federal Government (A)

Property Damage Nuclear Mutual Limited (D)

Nuclear Electric Insurance Limited (D)

American Nuclear Insurers Replacement Power Nuclear Electric Insurance Limited (D)

(Millions of Dollars)

$160

$None 400

~(B )

$560 (C)

$ 8.5

$500

$30.4 415 7.7 67 None

$982

$38.1

$ 2.5 (E)

$13.5 (A) Combined retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954. as amended. Subject to retrospective assessment with respect to loss from incident at any licensed nuclear reactor in the United States.

(B) Maximum assessment would be $17.0 million in the event of more than one incident in any year.

(C) Limit of liability under the Atomic Energy Act of 1954. as amended. for each nuclear incident.

(D) Utility-owned mutual insurance company of which the Company is a member. Subject to retrospective assessment with respect to loss at any nuclear generating station covered by such insurance.

(E) Maximum weekly indemnity for 52 weeks which commences after the first 26 weeks of an outage. Also provides $1.25 million weekly for an additional 52 weeks.

9. Accounting for Leases The Company has certain leases for property and equipment that meet the criteria for capitalization. but in accordance with rate-making treatment are accounted for as operating leases.

The capitalization of such leases would not have a significant ef-fect on assets. liabilities or expenses.

10. Supplementary Information Concerning the Effects of Inflation (Unaudited)

The Company's financial statements are prepared in accordance with generally accepted accounting principles and are stated on the basis of historical costs. namely. the prices that were in ef-fect when the underlying transactions occurred. The following supplementary financial information. prepared in accordance with Financial Accounting Standards Board Statement No. 33 (FAS 33). is an estimate of the effects on the Company of general inflation (Constant Dollar) and changes in specific prices (Current Cost).

The Company advises readers of the imprecise nature of this data and of the many subjective judgments required in the restatement of selected historical costs to Constant Do!lar and Current Cost. This data should not be used to make acfjust-ments to the Company's primary financial statements and the related earnings per average share of Common Stock other

than those adjustments shown in the following supplementary financial data.

Constant Dollar costs were determined by adjusting historical costs of Utility Plant and certain other items into dollars of the same general purchasing power by using the Consumer Price Index for All Urban Consumers (CPl-U).

Current Cost data purports to show the estimated cost of cur-rently replacing existing Utility Plant and was measured by applying primarily the Handy-Whitman Index of Public Utility Construction Costs to the historical costs of Utility Plant.

Depreciation and Amortization expense. and Amortization of Nuclear Fuel (included in Electric Fuel. Interchanged Power and Gas) were adjusted for Constant Dollar and Current*Cost using the rates and methods for computing book depreciation and amortization applied to the appropriate inflation adjusted Utility Plant balances. In accordance with FAS 33. income tax expense was not adjusted.

FAS 33 requires the disclosure of the amount required to re-flect Net Utility Plant at its Recoverable Cost if that cost is lower than the inflation adjusted amounts. Also required under Current Cost is the disclosure of the increase in Current Cost of Net Utility Plant held during the year and the related effect of general inflation. The amounts shown in the following table illustrate that during 1982 the increase in general inflation was less than the increase in the Current Cost of Net Utility Plant. Jn addition. the amounts shown as Adjustments of Net Utility Plant to Recoverable Cost (both Constant Dollar and Current Cost) are adjustments to Historical Cost in average 1982 dol-lars. Historical Cost is the amount permitted to be recovered under the rate regulatory process for utilities in New Jersey.

During inflationary periods. holders of monetary assets. such as cash and receivables. suffer losses of general purchasing power while holders of monetary liabilities experience gains. In 1982 the Company's monetary liabilities. primarily long-term debt.

exceeded its monetary assets resulting in a gain. Since this gain is primarily attributable to long-term debt which has been used to finance Utility Plant. it is netted against the amount by which the increase in general inflation is (higher) lower than the in-crease in Current Cost of Net Utility Plant after adjustment to recoverable cost in the following table.

Supplementary Financial Data Adjusted for the Effects of Changing Prices for the Year Ended December 31. 1982 (Unaudited)

Operating Revenues Operating Expenses Electric Fuel. Interchanged Power and Gas Other Operation and Maintenance Depreciation and Amortization Taxes Total Operating Expenses Operating Income Other (including Interest Expenses)

Income from Continuing Operations (excluding Adjustment of Net Utility Plant to Recoverable Cost)

Increase in Current Cost of Net Utility Plant held during the year**

Adjustment of Net Utility Plant to Recoverable Cost Effect of the increase in General Inflation Amount by which increase in general inflation is lower than increase in Current Cost of Net Utility Plant after adjustment to Recoverable Cost Gain from decline in purchasing power of Net Monetary Liabilities Net Historical Cost (Condensed from the Financial Statements)

$3.873.976 1.780.861 715.916 192.860 729.880 3.419.517 454.459 (111.632)

$ 342.827 Constant Dollar (Average 1982 Dollars)

(Thousands of Dollars)

$3.873.976 1.784,238 715.916 439.971 729.880 3.670.005 203.971 (111,632) 92.339*

35.342 103.892

$ 139.234 Current Cost (Average 1982 Dollars)

$3.873.976 1.797.299 715.916 489.097 729.880 3.732.192 141.784 (111.632) 30,152

$ 612.070 (150.475)

(364.066) 97.529 103.892

$ 201.421

• Including Adjustment of Net Utility Plant to Recoverable Cost. Income from Continuing Operations adjusted for Constant Dollar would have been

$127.681.000.

• • At December 31. 1982 the Current Cost of Net Utility Plant was $10.136.132.000. while historical (net recoverable) cost was $6.035.066.000.

37

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

(000 omitted where applicable and all adjusted figures are in average 1982 dollars)

For the Years Ended December 31.

1982 1981 1980 1979 1978 Operating Revenues Historical

$3.873.976

$3.471.652

$2.994.054

$2.416.707

$2.219.785 Acf)usted for General Inflation

$3.873.976

$3.684.488

$3.507.216

$3.213.753

$3.284.237 Income (Loss) from Continuing Operations (excluding Adjustment of Net Utility Plant to Recoverable Cost)

Historical

$ 342.827

$ 264.137

$ 275.401

$ 233.329 Acf)usted for General Inflation 92.339 46.930

$ 115.557

$ 103.108 Acf)usted for Current Cost 30.152

$ (13.402) $

39.510 20.155 Income (Loss) from Continuing Operations per Average Common Share (excluding Adjustment of Net Utility Plant to Recoverable Cost)*

Historical

$ 3.24

$ 2.63

$ 3.13

$ 2.85 Acf)usted for General Inflation

.43

$ ( 10)

.84

.62 Acfjusted for Current Cost

$ (27)

$ (84)

$ (20)

$ (65)

Amount by which increase in general inflation is (higher) lower than increase in Current Cost of Net Utility Plant after acf)ustment to Recoverable Cost 97.529

$ (190.813) $ (396.969) $ (466.956)

Cain from decline in purchasing power of Net Monetary Liabilities

$ 103.892

$ 235.151

$ 331.151

$ 362.346 Net Assets at Year End**

Historical

$3.080.877

$2.832.930

$2.646.928

$2.435.516 Acfjusted for General Inflation and Current Cost

$3.046.107

$2.909.414

$2.961.404

$3.062.669 Cash Dividends Declared per Common Share Historical

$ 2.53

$ 2.44

$ 2.29

$ 2.20

$ 2.08 Acf)usted for General Inflation

$ 2.53

$ 2.59

$ 2.68

$ 2.93

$ 3.08 Market Price per Common Share at Year End Historical

$23.25

$18.00

$17.00

$19.25

$20.25 Acf)usted for General Inflation***

$2325

$18.70

$19.24

$24.48

$29.18 Consumer Price Index ( 1967 = 100)

Average 289.1 272.4 246.8 217.4 195.4 Year End 292.4 281.5 258.4 229.9 202.9

• After deducting Cumulative Preferred Stock and $1.40 Dividend Preference Common Stock dividends on a historical basis in 1982 and in Average 1982 Dollars for prior years.

• • Equals Common Equity and Preferred Stock without mandatory redemption.

• • • Year-end 1982 Dollars.

Prices have been increasing over the last five years. The average CPl-U increased from 195.4 in 1978 to 289.1 in 1982. an aver-age annual increase of 10.3%. The increase from 1981 to 1982 was 6.1 %. an indication that the rate of inflation in 1982 has slowed.

Revenues for the five-year period increased from $2.220 bil-lion in 1978 to $3.874 billion in 1982. an average annual increase of 14.9%. Restated in average 1982 dollars. revenues for the same period would have increased from $3.284 billion to $3.874 billion. an average annual increase of only 4.2%.

Cash dividends declared per common share went from $2.08 in 1978 to $2.53 in 1982 or an average annual increase of 5.0%.

However: such dividends would have decreased at an average annual rate of 4.8% or from $3.08 in 1978 to $2.53 in 1982 when restated in average 1982 dollars.

38 Market price per common share at year end from 1978 to 1982 had an average annual increase of 3.5% or from $20.25 to $23.25. Restated in year-end 1982 dollars the 1978 market price would have been $29.18 instead of $20.25 resulting in an average annual decrease of 5.5% from 1978 to 1982.

As shown in the tables above. the gain from decline in purchas-ing power of net monetary liabilities was not enough to offset the significant effect of inflation on capital costs (utility plant).

nuclear fuel costs and depreciation.

Lack of adequate recognition of inflation in rate-making in addi-tion to delayed rate relief accelerates attrition. thereby contributing to poorer cash flow. By the time increased costs are included in rates. the related funds have already been expended.

11. Jointly-Owned Facilities

12.

The Company has an ownership interest and is responsible for providing its share of the necessary financing for the following jointly-owned facilities. All amounts reflect the Company's share of each jointly-owned project and the corresponding direct ex-penses are included in the Statements of Income as an operat-ing expense.

Plant Ownership Interest Coal Generating Conemaugh 22.50%

Keystone 22.84%

Nuclear Generating Peach Bottom 42.49%

Salem 42.59%

Hope Creek 95.00%

Nuclear Training Center Various Pumped Storage Generating Yards Creek 50.00%

Transmission Facilities Various Merrill Creek Reservoir 13.906%

Linden Synthetic Natural Gas 90.00%

Financial Information by Business Segments Electric For the Years Ended December 31.

1982 1981 1980 Operating Revenues

$2.543.191

$2.322.042 $2.083.900 Depreciation and Amortization 146.643 134.050 127.655 Operating Income Before Income Taxes 533.855 378.082 407.662 Gross Additions to Utility Plant 735.997 615.976 551.110 December 31.

Net Utility Plant

$5.369,929 $4.813.875 $4.570.355 Gas Exploration Subsidiary and LNG Project Other Corporate Assets 1.148,364 1.168.539 944.195 Total Assets

$6.518.293 $5.982.414 $5.514.550 Amount of Utility Plant Accumulated Provision Jn Service for Depreciation (Thousands of Dollars)

$ 67.629

$ 17.642 55.308 17.835 408.087 111.441 712.198 97.571 6.747 132 16.884 3.567 74.485 7.347 65.988 34.329 Gas 1982 1981 1980 1982 (Thousands of Dollars)

$1.330.785 $1.149.610

$910.154 $3.873.976 46.217 44.482 42.332 192.860 99.108 94.937 101.147 632.963 77.378 67.873 74.420 813.375

$ 665.137 $ 632.218

$606.894 $6.035.066 287.911 261.000 220.484 287.911 435.626 401.457 382.932 1.583.990

$1.388.674 $1.294.675 $1.210.310 $7.906.967 Amount of Plant Under Construction

$1.825.704 8.130 27.476 3.445 Total 1981 1980

$3.471.652 $2.994.054 178.532 169.987 473.019 508.809 683.849 625.530

$5.446.093 $5.177.249 261,000 220.484 1.569.996 1.327.127

$7.277.089 $6.724.860

13. Selected Quarterly Data (Unaudited)

The information shown below in the opinion of the Company includes all adjustments. consisting only of normal recurring accruals. necessary to a fair presentation of such amounts.

Calendar Quarter Ended March 31.

1982 1981 Operating Revenues

$1.144.277

$982.938 Operating Income 111.347 101.669 Net Income 83.389 77.404 Earnings Available for Common Stock 70.226

$ 65.865 Earnings per Average Share of Common Stock

$.81

$.86 Average Shares of Common Stock Outstanding 86.181 76.680 Due to the seasonal nature of the business. quarterly amounts vary significantly during the year.

June 30.

September 30.

December 31.

1982 1981 1982 1981 1982 1981 (Thousands where applicable)

$872.657

$733.255

$872.292

$809.805

$984.750

$945.654 100.839 74.1 83 126.805 94.677 115.468 83.738 71.530 52.941 98.289 71.665 89.619 62.127

$ 58.386

$ 39.339

$ 84.975

$ 58.447

$ 75.375

$ 48.948

$.67

$.51

$.95

$.69

$.80

$.57 87.176 77.526 89.626 84.252 93.861 85.261 39

% Annual Increase -

1982 compared with (000 omitted where applicable) 1982 1981 1981 1972 Electric Revenues from Sales of Electricity (a)

Residential

$ 791.279

$ 728.642 8.60 12.76 Commercial 981,795 871.377 12.67 15.61 Industrial 716.662 684.976 4.63 14.28 Public Street Lighting 37.809 33.249 13.71 9.14 Total Revenues from Sales to Customers 2.527.545 2.318.244 9.03 14.15 Interdepartmental 1.709 1.612 6.02 10.22 Total Revenues from Sales of Electricity 2.529.254 2.319.856 9.03 14.15 Other Electric Revenues 13.937 2.186 537.56 24.59 Total Operating Revenues

$2.543.191

$2.322.042 9.52 14.19 Sales of Electricity -

kilowatthours (a)

Residential 7.686.548 7.795.988 (1.40)

.38 Commercial 11.114.655 10.940.609 1.59 2.98 Industrial 10.017.613 10.923.042 (8.29)

(1.26)

Public Street Lighting 301.603 275.489 9.48 2.04 Total Sales to Customers 29.120.419 29.935.128 (2.72)

.64 Interdepartmental 25.154 25.567 (1.62)

(.26)

Total Sales of Electricity 29.145.573 29.960.695 (2.72)

.64 Kilowatthours Produced. Purchased and Interchanged -

net 31.563,231 32.204.191 (1.99)

.68 Load Factor 51.2%

52.3%

Capacity Factor 34.7%

33.2%

Heat Rate -

Btu of fuel per net kwh generated 10.677 10.725

(.45)

(.01)

Net Installed Generating Capacity at December 31 -

kilowatts 8.995 9.101

( 1.16) 1.39 Net Peak Load -

kilowatts (60-minute integrated) 7.042 7.034

.11 1.28 Cooling Degree Hours 6.329 8.615 (26.54)

(1.40)

Temperature Humidity Index Hours 12.155 15.494 (21.55)

(1.71 )

Average Annual Use per Residential Customer -

kwh 5.156 5.261 (2.00)

(.29)

Meters in Service at December 31 1.746 1.739

.40

.53 Gas Revenues from Sales of Gas (a)

Residential

$ 716.308

$ 604.521 18.49 14.56 Commercial 371.027 302.281 22.74 17.99 Industrial 241.437 240.7 11

.30 19.58 Street Lighting 350 290 20.69 14.80 Total Revenues from Sales to Customers 1.329.122 1.147.803 15.80 16.23 I nterdepa rtmenta I 1,068 1.075

(.65) 6.82 Total Revenues from Sales of Gas 1.330,190 1.148.878 15.78 16.22 Other Gas Revenues 595 732 (18.72) 15.32 Total Operating Revenues

$1.330.785

$1.149.610 15.76 16.22 Sales of Gas -

therms (a)

Residential 994.647 993.527

.11

(.47)

Commercial 581,739 555.806 4.67 1.83 Industrial 465.835 5 14. 136 (9.39)

(.59)

Street Lighting 331 334

(.90)

(3.00)

Total Sales to Customers 2.042.552 2.063.803 (1.03)

.10 I nterdepa rtmenta I 2.090 2.430 (13.99)

(7.31)

Total Sales of Gas 2.044.642 2.066.233 (1.04)

.08 Gas Produced and Purchased -

therms 2.148.875

2. 145.325

.17

.17 Effective Daily Capacity at December 3 1 -

therms 19,139 19.010

.68 1.19 Maximum 24-hour Gas Sendout -

therms 16.201 14.812 9.38 2.94 Heating Degree Days (a) 4.820 5.082 (5.16)

(.12)

Average Annual Use per Residential Customer -

therms 853 857

(.47)

(.88)

Meters in Service at December 31 1.384 1.378

.44

.34 (a) Starting in 1973. revenues and sales by customer classification reflect temperature effect on these recorded sales. heating degree include accrued and unbilled dollar amounts and sales volumes days are also reported on a calendar-year basis effective with 1973.

from meter reading date to the end of the calendar year. To better For 1972. heating degree days remain on a sales-year basis.

40

1980 1979 1978 1977 1972

$ 684.343

$ 545.049

$ 512.071

$ 492.473

$238.025 765.356 625.596 574.557 531. 118 230,176 598.716 484.037 444.595 414,058 188.667 32.693 31.437 29.925 27.622 15.773 2.081.108 1.686.119 1.561.148 1.465.271 672,641 1.720 1.559 1.670 1.916 646 2.082,828 1.687.678 1.562.818 1.467.187 673.287 1.072 2.179 2.016 2.931 1.546

$2.083.900

$1.689.857

$1.564.834

$1.470.118

$674,833 8.129. 198 7.777.369 7.760,868 7.769.629 7.399.963 10.726.086 10.336.445 10.152.827 9.747.908 8.289.066 11.049.642 11.185.952 11.134.634 10.627.734 11.375,579 265.126 260.915 260,922 259.277 246.496 30,170,052 29.560.681 29.309,251 28.404.548 27.31 1.104 27.684 26.629 32.638 38,331 25.807 30.197.736 29.587.310 29.341,889 28.442.879 27.336.911 32.703.504 32.021.737 31.628,876 30.771.719 29,509.136 52.0%

54.3%

54.6%

50.9%

54.2%

35.6%

31.8%

34.4%

32.7%

3B.6%

10.713 10.566 10.599 10.677 10.685 9.242 9.023 9.061 9.247 7.836 7.159 6.736 6.615 6.895 6.201 9.869 7.201 7.188 8.269 7,287 16.526 14.545 13.899 14.883 14.450 5.443 5.233 5.378 5.403 5.307 1.732 1.724 1.713 1.704 1.656

$ 515.013

$ 415.157

$ 399.134

$ 344.444

$183.953 228.577 179.970 163.931 137.811 70.953 164.762 129.665 90.240 78.474 40.381 282 274 248 178 88 908,634 725.066 653.553 560.907 295.375 925 790 802 572 552 909.559 725.856 654.355 561.479 295.927 595 994 596 1.198 143

$ 910.154

$ 726.850

$ 654.951

$ 562.677

$296.070 1.023.027 970.462 1.013.043 980.570 1,042.793 506,550 456.902 447.923 432.810 485.358 447.474 410.605 306.672 329.211 494.454 335 350 367 376 449 1.977.386 1.838,319 1.768,005 1.742.967 2.023.054 2.322 2.328 2.490 2.064 4.463 1.979.708 1.840.647 1.770.495 1.745.031 2.027.517 2.077.653 1.931.549 1.852.869 1.811.019 2.112,844 18.439 18.639 18,639 18.933 16.999 14.444 13.349 12.235 14.006 12.125 5.256 4.677 5.317

5. 155 4.879 875 833 893 862 932 1.370 1.357 1.350 1.350 1.338 41

(000 omitted where applicable)

Condensed Statements of Income (a)

Operating Revenues Electric Gas Total Operating Revenues Operating Expenses Fuel for Electric Generation and Interchanged Power -

net Gas Purchased and Materials for Gas Produced Other Operation Expenses Maintenance Depreciation and Amortization Amortization of Property Losses Taxes Other than Federal Income Taxes Federal Income Taxes Total Operating Expenses Operating Income Electric Gas Total Operating Income Amount

$2.543,191 1.330,785 3,873,976 959,382 821.479 452.115 220.456 192,860 43,345 553,241 176.639 3.419,517 383.213 71,246 454.459 1982 1981 Amount 66

$2.322.042 67 34 1.149.610 33 100 3.471.652 100 25 1.059.539 31 21 692.319 20 12 385.149 11 6

192.768 6

5 178.532 5

1 15.362 14 474.979 14 4

118.737 3

88 3.117,385 90 10 288.087 8

2 66.180 2

12 354.267 10 Allowance for Funds Used During Construction (Debt and Equity)

Other Income -

net 91.427 17.578 2

95.679 3

1 15.780 Interest Charges Income before Extraordinary Items Extraordinary Items. net of income tax:

Unrecoverable costs of Atlantic Project Gain on sale of Transport of New Jersey Net Extraordinary Items Net Income Preferred and Preference Stock Dividends Earnings Available for Common Stock Shares of Common Stock Outstanding End of Year Average for Year Earnings per average share of Common Stock Dividends Paid per Share Payout Ratio Rate of Return on Average Common Equity (c)

Ratio of Earnings to Fixed Charges Before Income Taxes (d)

Book Value per Common Share (e)

Utility Plant Accumulated Depreciation and Amortization Total Assets Capitalization Mortgage Bonds Debenture Bonds Other Long-Term Debt Total Long-Term Debt Preferred Stock with Mandatory Redemption Preferred Stock without Mandatory Redemption

$1.40 Dividend Preference Common Stock and Common Stock Premium on Capital Stock Paid-In Capital Retained Earnings Total Common Equity Total Capitalization (a) See Summary of Significant Accounting Policies. page 25. Notes to Financial Statements. page 34. and Management's Discussion and Anal-ysis of Financial Condition and Results of Operations. page 44.

42 (220.637)

(6)

(201.589)

(6) 342.827 9

264.137 7

342,827 9

264,137 7

53,865 2

51,538 1

$ 288.962 7

$ 212.599 6

94.845 86.089 89.233 80.962

$3.24

$2.63

$2.53

$2.44 78%

93%

12.22%

9.79%

3.32 2.87

$25.90

$25.66

$8,100,579

$7.320,764

$2,065.513

$1.874.671

$7.906.967

$7.277,089

$2.341, 142 41

$2.140.835 40 238,640 4

269.268 5

720 2.579.782 45 2.410.823 45 111,250 2

77.913 2

554.994 9

554.994 10 1.610.879 28 1.423.739 27 557 557 26.185 1

26.143 888,262 15 827.497 16 2,525.883 44 2,277.936 43

$5.771.909 100

$5.321.666 100 (b) Excludes the net extraordinary gain of $6.316.000 or $.09 per share.

(c) Balance available for $1.40 Dividend Preference Common Stock and Common Stock divided by the thirteen-month average of Common Equity.

1980 1979 1978 1977 1972 Amount Amount Amount Amount Amount

$2.083,900 70

$1.689,857 70

$1.564.834 70

$1.470. 118 72

$ 674,833 70 910.1 54 30 726,850 30 654,951 30 562.677 28 296,070 30 2,994,054 100 2.416,707 100 2,219,785 100 2.032.795 100 970.903 100 866,802 29 620,546 26 541,802 24 538.916 27 203.381 22 513,988 17 384,759 16 327,990 15 257,897 13 117,910 12 322,220 11 287.086 12 267.731 12 250,531 12 168, 132 17 169,813 6

149,027 6

127.423 6

124.876 6

80,215 8

169,987 6

162,989 7

158,248 7

147,652 7

91,037 9

11,024 303 1,038

1. 185 431,890 14 364.411 15 328.216 15 293,796 14 132,827 14 131, 178 4

123,965 5

146,937 7

120,969 6

(991 )

2,616,902 87 2,093,086 87 1,899,385 86 1,735,822 85 792.511 82 307,372 10 269.443 11 266,513 12 250,385 13 141,181 14 69,780 3

54,178 2

53,887 2

46,588 2

37,211 4

377, 152 13 323,621 13 320.400 14 296.973 15 178,392 18 77,552 2

56,593 3

41,305 2

49,540 2

45.011 5

10.259 6,263 4,515 1,447 (5, 166)

( 1)

(1 89,562)

(6)

(153,148)

(6)

(137.434)

(6)

(133,718)

(7)

(102,034) (10) 275,401 9

233,329 10 228,786 10 214.242 10 116.203 12 (13,219) 19.535 6.316 281,717 9

233.329 10 228,786 10 214,242 10 116,203 12 46,341 1

46,799 2

46.799 2

45,065 2

21, 117 2

$ 235,376 8

$ 186,530 8

$ 181,987 8

$ 169,177 8

95,086 10 76,615 68,914 64,120 59,806 43.861 73,069 65,409 61,783 59.243 41.541

$3.13 (b)

$2.85

$2.95

$2.86

$2.29

$2.29

$2.20

$2.08

$1.92

$1.70 73% (b) 77%

71 %

67%

74%

11.63%

10.46%

11.01 %

10.95%

9.36%

3.14 3.36 3.77 3.52 2.08

$26.38

$26.26

$26.13

$25.57

$23.48

$6,881,209

$6,325,033

$5,810,329

$5.654,097

$3.999.474

$1,703,960

$1.589,049

$1,447,039

$1,314,916

$ 831,673

$6.724.860

$6,088.766

$5,508,164

$5,125,497

$3,402.305

$2,041,556 41

$1,940,513 41

$1,692,642 39

$1,647,445 40

$1,239,602 39 276,590 5

314,726 7

322.682 7

330,812 8

430,857 14 1,200 1,680 2,160 2,640 2.319,346 46 2,256,919 48 2.017.484 46 1,980,897 48 1,670.459 53 29,750 3 1,500 35,000 35,000 554,994 11 554.994 12 554,994 13 554,994 13 374,994 12 1,252,103 25 1,106,824 23 1.014.184 23 919.752 22 622.878 20 557 557 557 557 539 26,093 1

26,065 1

26,065 1

26,065 26.065 1

813, 181 16 747,076 16 704,909 16 651.885 16 443.443 14 2,091,934 42 1,880,522 40 1,745,715 40 1,598,259 38 1,092,925 35

$4,996,024 100

$4,723,935 100

$4,353,193 100

$4.169.150 100

$3.138,378 100 (d} Net Income plus Income Taxes. Deferred Income Taxes, Investment pense and. starting in 1980. an interest factor in rentals.

Tax Credits and Fixed Charges divided by Fixed Charges. Fixed Charges (e) Total Common Equity divided by year-end Common Stock shares include Interest on Long-Term and Short-Term Debt. Other Interest Ex-plus double the $1.40 Dividend Preference Common Stock shares.

43

On January 7. 1983. the Company filed a petition with the Board of Public Utilities of the State of New Jersey (BPU) designed to increase base rates by $464.5 million on an annual basis. The total is comprised of $397.4 million for electric service and $67.1 million for gas. The request was necessary due to inadequate financial relief in recent rate cases. the need for improved cash flow to complete the con-struction program. and the decline in electric and gas sales due to the slow economic recovery. As more fully discussed on page 6. the Public Advocate of New Jersey has moved to dismiss the Company's petition. The motion is currently being considered by the BPU.

A more detailed discussion of the Company's operating results. liquidity and capital resources follows.

Earnings and Dividends Earnings per average share of Common Stock were $3.24 for 1982. an increase of 61 C or 23% from 1981. Increased revenues. reflecting the February 1982 rate increase. out-paced the rise in operating costs.

Earnings per share were $2.63 for 1981. a decline of SOC or 16% from 1980 before giving effect to the net extraordi-nary gain of 9C in 1980. Including the 1980 extraordinary items. earnings were lower by 59C per share. Revenues in 1981 did not keep pace with operating costs as a result of continuing inflation. minimal sales growth. and lack of addi-tional rate relief.

Dividends paid to holders of Common Stock have grown over the last three years rising to $2.53 per share in 1982 from $2.44 per share paid in 1981. and $2.29 per share in 1980. Such amounts. compared to earnings before extraor-dinary items. resulted in payout ratios of 78%. 93%. and 73%. respectively. Total Common Stock dividend payments in 1982 increased 15% over 1981 and 35% over 1980 due to the increase in shares of Common Stock outstanding as well as the higher dividend rate.

Revenues and Sales Total revenues increased in 1982 due primarily to higher rates and in 1981 to greater recoveries of electric energy and gas fuel costs. Electric energy and gas fuel costs follow amounts recovered through revenues. as permitted by energy cost rate orders. and therefore have no effect on earnings.

Electric revenues increased 9.5% in 1982 and 11.4% in 1981. The components of these changes are highlighted in the table below:

Changes in base rates Recoveries of energy costs Kilowatthour sales Other operating revenues 44 Increase or (Decrease) 1982vs. 1981 1981 vs. 1980 (Millions of Dollars)

$291

$ 36 (49) 216 (33)

(15) 12 1

$221

$238 1982 -

Electric kilowatthour sales decreased 2.7%. The cooler and less humid weather in 1982 and continued cus-tomer conservation were the main reasons for the 1.4%

drop in Residential sales. Also. Industrial sales declined 8.3%

as a result of the economic recession. These decreases were slightly offset by the 1.6% increase in Commercial sales.

1981 -

Electric kilowatthour sales decreased.8% from 1980. Despite an increase in customers. Residential sales de-creased 4.1 % primarily due to customer conservation and the cooler and less humid weather during the summer. The 1.1 % decline in Industrial sales was due to a drop in produc-tion levels as a result of the sluggish economy during the year. Commercial sales increased 2.0%. principally due to a slight increase in customers. All classes of sales continued to reflect the overall impact of the economic slump and the effect of continued energy conservation throughout the Company's service area.

Gas revenues rose 15.8% in 1982 and 26.3% in 1981.

The principal factors are shown below:

Changes in base rates Recoveries of gas costs Therm sales Increase or (Decrease) 1982 vs. 1981 1981 vs. 1980 (Millions of Dollars)

$ 39

$ 24 136 204 6

11

$181

$239 1982 -

Gas therm sales decreased 1.0%. Industrial sales fell 9.4% from 1981 primarily as a result of the continuing economic recession. Commercial sales were up 4.7%. the re-sult of greater customer usage and an increase in customers.

Residential sales were held to an increase of.1 % principally due to moderate weather conditions experienced late in the year and continued conservation.

1981 -

Gas therm sales increased 4.4%. Commercial and Industrial sales increased 9.7% and 14.9%. respectively.

These gains came about as the price advantage and availabil-ity of gas continued to spur conversions from oil during the year. Over 300 large Commercial and Industrial customers were added. Despite an increase in customers. Residental therm sales decreased 2.9% from 1980 as winter tempera-tures were less severe and customers continued to conserve.

Substantially all revenues are subject to New Jersey gross receipts taxes and as a result the amount of these taxes varies in direct proportion to revenues. The effective rate is approximately 13%.

Energy Costs The year 1982 marked the first time in over a decade that the cost of fuel for electric generation decreased. As a result of a full year's generation from Salem 2 and outstanding performances by the two Peach Bottom units. nuclear gen-eration increased by more than a third over the previous year and provided 34% of the Company's total energy re-quirements compared to 25% in 1981. These factors made it possible to reduce higher priced steam generation from oil and natural gas an average of 22%. Demands for other gen-eration and Pennsylvania-New Jersey-Maryland (P JM) inter-changed power pool energy. two of the higher priced sources when compared to nuclear power. were down 55%

and 39%. respectively.

Effective June 1982 the electric Levelized Energy Adjust-ment Clause (LEAC). with the approval of the BPU. was re-duced $250 million over the ensuing 13 months. The reduction was made possible by an increase in nuclear generation. a decline in oil prices. purchases of power at lower cost. and completion of the recovery of nearly all elec-tric costs of previous periods. On January 13. 1983, the Company filed a petition with the BPU to lower the LEAC for a second time. by $104 million. for the 17-month period through June 1984. again reflecting projected greater nuclear production and lower fuel costs. The BPU took the request under consideration.

As a member of the P JM and as a party to several agree-ments which provide for the purchase of available power from neighboring utilities. the Company is able to optimize its mix of internal and external sources using the lowest cost energy available at any given time. Energy costs are adjusted to match amounts permitted to be recovered through revenues and have no effect on earnings.

Total energy costs decreased 9% in 1982, as compared to an increase of 22% in 1981 over 1980. as described below:

Increase or (Decrease) 1982 vs. 1981 1981 vs. 1980 (Millions of Dollars)

Change in prices paid for fuel supplies and power purchases

$(122)

$110 Kilowatthour output (19)

(13)

Adjustment of actual costs to match recoveries through revenues 44 93 Replacement energy costs in 1981 for which recovery was disallowed by BPU (3) 3

$(100)

$193 Gas costs are adjusted to match amounts recovered through revenues and do not affect earnings. Costs were 19% higher in 1982 and 35% higher in 1981. Contributing factors are shown below:

Increase or (Decrease) 1982 vs. 1981 1981 vs. 1980 (Millions of Dollars)

Higher prices paid for gas supplies

$104

$141 Refunds from pipeline suppliers 4

(17)

Therm sendout 1

18 Adjustment of actual costs to match recoveries through revenues 20 36

$129

$178 Liquidity and Capital Resources The Company's liquidity is affected principally by the con-struction program and. to a lesser degree. by other capital requirements such as maturing debt and sinking fund re-quirements. The capital resources available to meet these re-quirements are funds from internal generation and external financing. Internally generated funds depend upon economic conditions and adequate and timely rate relief. while access to the long-term and short-term capital and credit markets is necessary for obtaining funds externally.

Construction Program The Company maintains a continuous construction program.

which includes payments for nuclear fuel and investments in and advances to energy resource subsidiaries. This program is periodically revised as a result of changes in economic conditions. and depends on the ability of the Company to fi-nance construction costs and to obtain timely rate relief.

Changes in the Company's plans and forecasts. price changes. cost escalation under construction contracts. and requirements of regulatory authorities may also result in revisions of the construction program.

Construction expenditures of $842 million in 1982 and

$717 million in 1981 included allowance for funds used dur-ing construction (AFDC) of $91 million and $96 million.

respectively. Construction expenditures are estimated at

$3.8 billion for the five years ending in 1987 and include AFDC of $736 million.

These estimates are based on certain expected comple-tion dates and anticipated escalation due to inflation of ap-proximately 8.5%. Therefore. construction delays or inordinate inflation levels could cause significant increases in these amounts. The Company expects that with adequate rate relief it will generate internally approximately 50% of its construction expenditure requirements. excluding AFDC.

No assurance can be given as to future rate increases. The balance will be provided by permanent financing through the sale of securities and may include term bank loans.

Long-Term Financing During 1982 the Company raised more than $443 million through the sale of $223.5 million of Mortgage Bonds.

$187.1 million of Common Stock and $35.0 million of Pre-ferred Stock. As a result. the Company's interest and divi-dend requirements have continued to increase.

At December 31. 1982 book value per common share amounted to $25.90 compared to $25.66 at December 31.

1981. The market value of common shares expressed as a percentage of book value was 89.8% and 70.1 % at year-end 1982 and 1981. respectively.

In addition to periodic sinking fund redemption require-ments. five bond issues aggregating $206 million will ma-ture and will require refinancing by 1987.

Under the terms of the Company's Mortgage and Restated Certificate of Incorporation. at December 31. 1982 the Company could issue an additional $1.1 billion principal amount of Mortgage Bonds at a rate of 12.25% or $800 million of Preferred Stock at a rate of 12.0%. Present plans for 1983 call for the issuance of Mortgage Bonds. Common Stock and Preferred Stock.

In April 1982 the Company renewed a then existing $125 million domestic revolving credit agreement and increased the line of credit to $200 million. The present revolving agreement expires in April 1984. but permits the Company to convert the balance outstanding at the end of the period to term loans due in April 1987. The Company also has the option to extend the agreement on a year to year basis. The Company has not made any borrowings under this agreement.

In 1982. PSE&G Overseas Finance N.V.. a wholly-owned Netherlands Antilles subsidiary. was formed. The financial subsidiary will be able to provide the Company with access to long-term capital markets abroad.

45

Short-Term Financing For interim financing. the Company is authorized to have a total of $300 million of short-term obligations outstanding at any given time. The availability of short-term financing provides the Company greater flexibility in the issuance of long-term securities. The Company's average daily short-term debt during 1982 was $108 million -

$7 million over last year's average. However. at year end the Company had no short-term debt outstanding.

In January 1982. the Company entered into a Letter Agreement establishing a $75 million Two-Year Revolving Credit Facility with a group of international banks. under which the Banks have agreed to make revolving loans for one month. three months or six months at a rate based upon the London Interbank Offered Rate for deposits in United States Dollars. No borrowings have been made under this arrangement.

The Company continues to have to finance larger cus-tomer accounts receivable. As of the end of 1982 receivables from customers approximated $361 million (excluding un-billed revenues of $182 million) and were $22 million higher than at the end of 1981. Reflecting the slowdown in the economy. customer payments have slowed as the amounts of bills have increased. Furthermore. net write-off of uncol-lectible accounts this year was $5.4 million greater than the

$27.0 million in 1981. The increases in accounts receivable and uncollectible accounts also reflect a requirement of the BPU prohibiting the termination of electric and gas service in New Jersey during the winter months with respect to cer-tain customers with financial need who are unable to pay utility bills.

Cash Position The Company's cash position improved greatly during 1982 as a result of the collection of energy costs deferred from prior years. the overrecoveries of 1982 energy costs. rate relief granted in February 1982. and equity and long-term debt financing.

Any improvement resulting from overrecoveries is only temporary because any overrecovery remaining at the end of one levelized period is returned to customers with inter-est in the subsequent period.

Effects of Inflation Inflation continues to affect the national economy and the Company but not as severely as in the past few years. The Average Consumer Price Index was 289.1. an increase of 6%

over 1981 compared to increases of over 10% for the preceding three years. The Company has experienced record interest charges in recent years and increased dividend re-quirements at a time when substantial amounts must be raised in the capital markets to finance needed construction.

Rising prices also have impacted construction. fuel and labor costs.

For additional information on the effects of changing prices. see Note 10 of Notes to Financial Statements.

46

Stock Symbol PEG The Company's Common Stock and $1.40 Dividend Preference Common Stock are traded on the New York Stock Exchange and the Philadelphia Stock Exchange.

The following table shows the quarterly dividends paid for the periods indicated and the high and low NYSE Composite prices of such stocks:

Common Stock Dividend Price First Quarter Second Quarter Third Quarter Fourth Quarter

• 61 C First Quarter only.

$1.40 Dividend 1982 64C*

20 1/4-17%

2 F/a-191/a 23 1/4-191/a 23%- 20%

Preference Common Stock 1982 Dividend 35C Price First Quarter Second Quarter Third Quarter Fourth Quarter 11

- 93/a 11

- 9 1/z 11 %- 9%

12%-107/a Transfer Agents All Stocks 1981 61 c 19 1/4-17 19%- 17 19 1/4-161/z 20 1/a-161/z 1981 35C 107/a-101/a 10%-10 10%- 9 1/z 11

- 9 1/z Morgan Guaranty Trust Company of New York, 30 West Broadway. New York. NY. 10015 Stockholder Services.

Public Service Electric and Gas Company 80 Park Plaza. P.O. Box 570.

Newark. N.J. 07101 Registrars All Stocks Fidelity Union Bank.

765 Broad Street. Newark. N.J. 07101 Morgan Guaranty Trust Company of New York, 30 West Broadway. New York. NY. 10015 Additional Reports Available Form 10-K Stockholders or other interested persons wishing to obtain a copy of the Company's 1982 Annual Report to the Securities and Exchange Commission. filed on Form 10-K.

may obtain one without charge by writing to the Vice President and Treasurer. Public Service Electric and Gas Company, P.O. Box 570, Newark, New Jersey 07101. The copy so provided will be without exhibits. Exhibits may be purchased for a specified fee.

Financial and Statistical Review A comprehensive statistical supplement to this report. containing financial and operating data for the years 1972-1982 will be available this Spring. If you wish to receive a copy, please write to the Vice President and Treasurer.

Public Service Electric and Gas Company.

P.O. Box 570. Newark. N.J. 07101.

47

48 Omcers Robert I. Smith Chairman of the Board and Chief Executive Officer Harold W. Sann President and Chief Operating Officer William E. Scott Executive Vice President -

Finance Stephen A. Mallard Senior Vice President - Planning and Research and President of PSE&G Research Corporation James B. Randel, Jr.

Senior Vice President of the Company and President of Energy Development Corporation Richard M. Eckert Senior Vice President - Energy Supply and Engineering Robert W. Lockwood Senior Vice President - Administration John F. McDonald Senior Vice President -

Governmental Affairs Changes in Organization Edward J. Lenihan. Vice President -

Public Relations. retired on February 28.

1982. after more than 43 years of ser-vice. Robert H. Franklin was elected Vice President - Public Relations by the Board of Directors. effective March 1.

1982.

Edward G. Outlaw. Executive Vice President - Corporate Planning, retired effective August 31. 1982. after more than 43 years of service. The Everett L. Morris Senior Vice President -

Customer Operations Frederick W. Schneider Senior Vice President -

Corporate Planning Donald A. Anderson Vice President -

Computer Systems and Services Frederick M. Broadfoot Vice President - Law Robert M. Crockett Vice President - Fuel Supply and President of Energy Pipeline Corporation and Energy Terminal Services Corporation Fredrick R. Desanti Vice President -

Rates and Load Management Robert H. Franklin Vice President - Public Relations Carroll D. James Vice President -

Administrative Planning Frank P. Librizzi Vice President - Production Board of Directors elected Frederick W.

Schneider as Senior Vice President -

Corporate Planning. and Frank P.

Librizzi to succeed Mr. Schneider as Vice President - Production. both effective September 1. 1982.

Frederick M. Broadfoot retired as Vice President - Law on December 31. 1982 after 34 years of service. Effective Jan-uary 1. 1983. R. Edwin Selover was elected Vice President and General Counsel.

Charles E. Maginn. Jr.

Vice President - Human Resources Wallace A. Maginn Vice President and Treasurer Winthrop E. Mange, Jr.

Vice President -

Corporate Services Thomas J. Martin Vice President -

Engineering and Construction Parker C. Peterman Vice President and Comptroller Louis L. Rizzi Vice President - Customer and Marketing Services Robert J. Selbach Vice President - Transmission and Distribution Rudolph D. Stys Vice President - System Planning Richard A. Uderitz Vice President - Nuclear Robert S. Smith Secretary Lawrence R. Codey was elected Vice President and Corporate Rate Counsel.

also effective January 1. 1983.

John F. McDonald. Senior Vice Presi-dent - Governmental Affairs. retired effective December 31. 1982. after more than 34 years of service. William Saller was elected Vice President -

Governmental Affairs. effective January 1, 1983.

Directors James R. Cowan, M.D.

President and Chief Executive Officer. United Hospitals Medical Center. Newark. New Jersey.

Member of Audit Committee.

W. Robert Davis Former Chairman of the Board and Chief Executive Officer. Bancshares of New Jersey. Moorestown.

New Jersey.

Chairman of Audit Committee and Member of Nominating Committee.

T.J. Dermot Dunphy President. Chief Executive Officer and director.

Sealed Air Corporation (manufactures protective packaging systems). Saddle Brook. New Jersey.

Member of Nominating Committee and Organization and Compensation Committee.

Robert R. Ferguson, Jr.

President. Chief Executive Officer and director. First National State Bancorporation. Newark. New Jersey.

Member of Finance Committee.

Margery Somers Foster Professor of Economics Emeritus. and former Dean of Douglass College. Rutgers. The State University of New Jersey, New Brunswick. New Jersey.

Member of Audit Committee and Nominating Committee.

D. Wayne Hallstein Director and former President. Ingersoll-Rand Company (diversified manufacturer of machinery.

equipment and tools). Woodcliff Lake. New Jersey.

Member of Finance Committee and Organization and Compensation Committee.

Irwin Lerner President. Chief Executive Officer and director.

Hoffmann-La Roche Inc. (manufactures pharmaceuticals and fine chemicals and provides health testing services). Nutley. New Jersey.

Member of Organization and Compensation Committee.

William E. Marfuggi Chairman of the Board and director. Victory Optical Manufacturing Company (manufactures ophthalmic frames) and Chairman of the Board and director.

Plaza Sunglasses. Inc. (manufactu res sunglasses).

both of Newark. New Jersey.

Member of Finance Committee.

Marilyn M. Pfaltz Partner of P and R Associates (public relations and publicity specialists). Summit. New Jersey.

Member of Audit Committee.

James C. Pitney Partner in the law firm of Pitney. Hardin. Kipp &

Szuch. Newark and Morristown. New Jersey.

Member of Audit Committee and Executive Committee.

Kenneth C. Rogers President. Stevens Institute of Technology, Hoboken. New Jersey.

Chairman of Nominating Committee and Member of Organization and Compensation Committee.

William E. Scott Executive Vice President-Finance of the Company.

Member of Executive Committee and Chairman of Finance Committee.

Robert I. Smith Chairman of the Board and Chief Executive Officer of the Company.

Chairman of Executive Committee and Member of Finance Committee.

Harold W. Sann President and Chief Operating Officer of the Company.

Member of Executive Committee and Finance Committee.

Robert V. Van Fossan Chairman of the Board. Chief Executive Officer and director. The Mutual Benefit Life Insurance Company.

Newark. New Jersey.

Member of Executive Committee and Finance Committee and Chairman of Organization and Compensation Committee.

PS~G Public Service Electric and Gas Company 80 Park Plaza. Newark. New Jersey 07101 Mailing Address:

P.O. Box 570. Newark. New Jersey 07101 U.S. Postage PAID Bulk Rate Public Service Electric and Gas Company

NOTICE -

THE ATTACHED FILES ARE OFFICIAL RECORDS OF THE DIVISION OF DOCUMENT CONTROL. THEY HAVE BEEN CHARGED TO YOU FOR A LIMITED TIME PERIOD ANO MUST BE RETURNED TO THE RECORDS FACILITY BRANCH 016.

PLEASE DO NOT SEND DOCUMENTS CHARGED OUT THROUGH THE MAIL. REMOVAL OF ANY PAGE(S) FROM DOCUMENT FOR REPRODUCTION MUST BE REFERRED TO FILE PERSONNEL.

DEADLINE RETURN DATE RECORDS FACILITY BRANCH

Cumulative Peach Bottom Savings Versus Plant Cost (PE. Portion)

Tutal Plant Cost

Page '

Phlladelphla Electric Company Annual Report 1982 Flnanclal Hlghllghts 1982 1981 Change Operating Revenues

$2,644,753,000 Operating Expenses

$2,256,026,000 Tuxes Charged to Operations

$ 372,180,000 Operating Income

$ 388,727,000 Earnings Applicable to Common Stock

$ 278,623,000 Earnings per Average Common Share

$2.39 Cash Dividends Paid per Common Share

$2.06 Average Shares of Common Stock Outstanding 116,480,000 Construction Expenditures

$ 883,898,000

'Ibtal Assets

$7,157,998,000 Letter to Shareholders Financial Matters Rate Matters Electric Operations Gas Operations Customer Activities Financial Section Shareholder Information Officers and Directors Earnings and Dividends Per Share Dollars 2 40 200 *--

160 120 BO 40 78 79 BO 81 82 Earmn9s Per Share Dividends Per Share

$2, 433, 425, 000

$2, 110,432,000

$ 274,796,000

$ 322,993,000

$ 223, 761,000

$2.25

$1.90 99,557,000

$ 793,959,000

$6,352,546,000 M1lhon Dollars 1.000 800 600 400 200 2

4 8

12 16 18 21 40 41 Construction Expenditures External Sources Internal Sources 9%

7%

35%

20%

25%

6%

8%

17%

11%

13%

James L. Everett in the lobby of the Franklin Plaza Hotel, Philadelphia Page z lb Our Shareholders:

Despite the severe recession, 1982 was a year of achieve-ment for Philadelphia Electric Com-pany Here are the highlights.

Earnings per share increased from $2.25 in 1981 to $2.39 in 1982. Return on common share-holders' equity increased from 12.3%

to 13.4%. While the improvement is gratifying, we still have a way to go to achieve an adequate return.

The dividend rate on common stock was increased from

$2.00 to $2.12 per year.

Sales of electricity; gas and steam were weak due to the effects of the severe recession and the weather. Particularly hard hit were our major customers: the steel com-panies, the oil refineries and paper products manufacturers.

Rate increases were granted by the Pennsylvania Public Utility Commission (PUC) for all three services to offset higher costs. Electric rates were permitted to increase revenue by $221. 7 million; gas and steam rate increases will add $31. 5 million and $3.4 million to revenue, respectively Rates remained com-petitive with other urban utilities on the northeastern seaboard. The Com-pany's electric rates are at or below the median of the eleven companies with which we compare ourselves.

Excellent performance by our low-cost nuclear plants (which generated 34%of the Company's electricity) and purchases of coal-generated electric-ity from midwestern utilities lowered fuel costs. These savings were passed on to our customers and largely offset the base rate increase granted by the PUC.

Salem Unit No. 2 nuclear generator ( 43% owned by the Com-pany) completed its first full year of operation in 1982. Its performance was excellent. The Company's share of its output was sold to Jersey Central Power & Light Company, resulting in

$135 million of revenue.

Our Peach Bottom nuclear plant had another excellent year. Unit No. 3 set another record for electric generation, exceeded only by its sister unit, No. 2 in 1979. It oper-ated at full capacity 94% of the time, a record unmatched by any of our fuel-burning units in the history of the Company The Company's con-struction program continued at a fast pace during 1982 to assure continued reliable service with up-to-date, state-of-the-art facilities. Limerick nuclear Unit No. 1 is within two years of com-pletion, and operating license pro-ceedings are in progress.

Flue gas scrubbers, which remove sulfur dioxide gas and particulates from the smokestacks of the Company's coal-burning plants, were completed at Eddystone and Cromby Stations. These plants are in full compliance with air pollution con-trol standards, while continuing to have the capability to burn high-sulfur

. coal, a Pennsylvania resource.

The PUC ordered the Company either to abandon construc-tion of Limerick Unit No. 2 or delay its completion until Unit No. 1 is finished, in spite of the PUC Administrative Law Judge's finding that completing both units as expeditiously as pos-sible was in the best interests of the Company's customers. However, the Company appealed the order to Com-monwealth Court, which reversed the Commission. We are convinced that Limerick Unit No. 2 is the least cost alternative for supplying needed capacity for the future. Therefore, we are planning to continue construction on the unit for service in late 1988.

Unit No. 1 is ahead of schedule for service in early 1985.

Robert F Gilkeson retired from the position of Chairman of the Board on June 28. During his years of leadership, he guided the Company through one of its most difficult periods An innovative engineer, nationally-recognized industrial leader and distinguished citizen of the Greater Philadelphia community, Mr. Gilkeson's 43-year career at Philadelphia Electric has contributed greatly to the Company's shareholders, customers and person-nel. He continues as a Director and Chairman of the Executive Commit-tee.

This year's Annual Report featlires pictures of a cross section of the Company's larger cus-tomers. In them we see excellent examples of the modern use of energy -

electricity, gas and steam As we look toward the future, it is essential that our area-and our nation -

have adequate supplies of energy at reasonable cost, free from the threat of foreign interruption. We remain dedicated to meeting these objectives for our customers.

A little over a 100 years ago, Thomas Edison founded our in-dustry He was widely recognized as a genius, but he was also a practi-cal man. He was active in inventing and developing new devices and pro-cesses during his entire life. He never lost faith in American ingenuity At.

age 84, in 1931, when our nation was in a depression that makes even to-day's economic troubles seem trivial, he said in his last public message, "Be Pag.... a courageous. I have lived a long time. I have seen history repeat itself again and again. I have seen many depres-sions... Always, America has come out strong and more prosperous. Be as brave as your fathers were before you. Have faith-go forward." That message is just as appropriate today and we pledge no less to our shareholders.

No Annual Report would be complete without recognizing the outstanding employee team at Phila-delphia Electric. Our 10,200 dedi-cated, competent, professional and highly skilled men and women pro-vide reliable and economical service to nearly 4,000,000 people. They are the Philadelphia Electric Company We thank our share-holders for their interest in and sup-port of our Company We will continue to work diligently to make your invest-ment a sound one and a fruitful one.

James L. Everett Chairman of the Board and Chief Executive Officer john H Austin, Jr.

President and Chief Operating Officer John B. Awstin, Jr., near the guided missile cruiaer Josephus Daniels at the Philadelphia Naval Shipyard.

Eamings Increase Common stock earnings in 1982 were $2. 39 per share, an increase of 6% over 1981 earnings of $2.25. 'Ibtal common stock earnings were $279 million, up $55 million or 25% from 1981. The average number of shares outstanding increased 17% to 116 million.

The increase in earnings was due primarily to electric and gas rate increases which became effective in 1981 and 1982.

Conunon Stock Dividend Raised On July 26, the Board of Directors voted to increase the quarterly common stock dividend from fifty to fifty-three cents per share, effective with the third quarter payment..As a result, dividends per share paid in 1982 amounted to $2.06, compared to $1.90 in 1981.

The increase, the second in two years, recognizes the necessity of providing a competitive return on the common stock shareholders' investment.

Electric Sales Rise; Gas, Steam Sales Fall

'Ibtal electric sales increased by 5% to 29.6 billion kilowatthours (kWh). The increase was due to higher sales of the Company's share of the output of Salem Unit No. 2 to Jersey Central Power & Light Company Electric sales to regular customers, excluding sales to Jersey Central Power & Light CompanYi declined by 3% to 26.2 billion kWh. The recession caused depressed kilowatthour sales to large commercial and industrial customers. A cooler summer in 1982 held air conditioning loads below 1981 levels.

Gas sales decreased by 6% to 69 billion cubic feet as a result of milder weather and lower sales to large commercial and industrial customers. Steam sales dropped 7% to five billion pounds as a result of continued conservation and conversion to other fuels by our steam customers.

Revenue, Expenses Increase

'Ibtal operating revenue amounted to $2.6 billion, 9%

above 1981. Electric operating revenue rose to $2.2 billion, an increase of $179 million or 9% over 1981. This increase reflects higher base rates and an increase in revenue from the sale of Salem Unit No. 2 output and capacity Gas revenue amounted to $390 million, an increase of 10% over 1981, and steam revenue reached $73 million.

'Ibtal operating expenses before depreciation and taxes amounted to $1.7 billion, an increase of $35 million or 2% over 1981.

The major elements of this increase were $18 million of increased costs associated with the full-year operation of Salem Unit No. 2, higher wages and benefits and increased costs for materials and supplies. Management continued to hold controllable costs to a minimum, consistent with reliable service. Interest charges increased

$41 million ( 14%) and preferred dividends increased $4 million (7% ).

Page 4

John Wanamaker Electric, Gas and Steam Customer The Eagle in the grand court of John Wanamaker's center city department store has been a famous meeting place for over 70 years. This bird's eye view of the court is from atop the great organ, another Wanamaker landmark. The organ

- a six-manual console, with 451 stops, 964 controls, and over 30,000 pipes - is one o the largest and finest in the world and has been played every business day since its installation in 1911. Retail operations con-sist of 16 stores, with 8 stores in our service territory which employ nearly 4,600 people.

Page 5

Construction Program Expenditures for new plant and equipment in 1982 amounted to $884 million. Of this amount, approximately $588 million were spent on the Limerick project and related transmission facilities, and $104 million in completing the flue gas scrubbing systems, or "scrubbers", for Eddystone and Cromby coal-fired generating stations.

The remainder was spent for necessary projects throughout the electric, gas, and steam systems. Estimated construction outlays are

$996 million for 1983.

1982 Financing Program During 1982, the Company raised more than $600 million,. the second-highest amount of capital ever raised by Philadelphia Electric, to meet the needs of our construction program and refundings. The Company's major 1982 financings are sum-marized in the table on page 7. Internal cash sources, primarily depreciation and deferred taxes, provided the remaining funds for construction.

The magnitude of the Company's construction program, as well as recent market conditions, have caused the Company to utilize several innovative financing techniques to tap new sources of capital. For example, the Company sold $30 million of tax-exempt commercial paper to provide interim financing for the magnesium oxide regeneration facility in Claymont, Delaware at an average interest rate of 4.6% during the last four months of 1982.

In December, the Company sold $100 million of a new, tax-exempt security called a Floating Rate Monthly Demand Note.

Although the notes may remain outstanding for 30 years, they off er the Company significant savings since they carry an interest rate which fluctuates monthly tied to an index related to 30-day tax-exempt commercial paper. Interest rates on these notes are currently about one-half the rate paid on long-term, fixed-rate notes.

The Economic Recovery Tax Act of 1981 provided for special tax treatment of public utility dividends which are reinvested in qualified new-issue common stock. As a result, the Company experienced record growth in its Dividend Reinvestment and Stock Philadelphia International Airport Electric Customer Within the radar room of the new control tower at Philadelphia International Airport, an air traffic controller guides arriving and departing nights.

Boeing Vertol Company Electric and Gas Customer Final inspection of the battery compartment of a CB-47D Chinook helicopter is performed at Boeing Vertol Company's plant in Ridley Township, PA.

Vertol manufactures helicopters for both commercial and military customers. In addition, the company fabricates components and sheet metal assemblies for fixed-winged aircraft. Vertol, one of the major operating divisiom of the Boeing Company, employs approximately 4,200 people in our service territory.

Page 7

Purchase Plan (DRIP) in 1982. Over 25,000 additional shareholders enrolled in the DRU~ bringing the total participation in the Plan to 79,900, or 28% of our common stock shareholders. The total invested in the Plan during 1982, including cash purchases, amounted to $60 million, up 74% from 1981.

Our 1983 financing program will require the sale of approximately $750 million of new debt and equity securities.

Major Financings Date Millions of Dollars 2/82 Preferred Stock-300,000 Shares

$ 30 3/82 Mortgage Bonds-18% Series due 2012 100 4/82 Common Stock-6,000,000 Shares 82 6/82 Serial Notes-17% due 1986 & 1987 20 9/82 Mortgage Bonds-15:Ys% Series due 2010 100 10/82 Common Stock-6,000,000 Shares 94 12/82 Pollution Control Notes (tax exempt) 100 Common Stock Purchase Plans:

DRIP, Employee, TRASOP-5,259,801 shares 78 Total

$604

Rate Matten Rate Increases The Company must regularly raise the prices of its prod-ucts to offset the effects of inflation, to improve the Company's financial performance, to maintain the ability to attract new capital and to balance supply and demand. Rate proceedings for all energy services are summarized on the table on page 11.

On May 21, the Pennsylvania PUC approved an annual electric rate increase of $221. 7 million (12% ). The increase was 64% of the $344.4 million originally requested in July, 1981 and reflected a

17. 75% return allowance on common stock equity The majority of the disallowed revenue was related to the PUC's refusal to include Limerick construction-work-in-progress (CWIP) in rate base.

Tvvo load management incentives became effective as part of the new electric rates approved in May A time-of-day energy adjustment for large industrial or commercial customers now provides a price incentive to shift energy usage from on-peak to off-peak periods. Also, a billing credit is available for large, high-voltage customers who are willing to have part of their usage interrupted on short notice.

On June 25, the PUC authorized an annual gas rate increase of $31. 5 million (9. 5% ), representing 81 % of the $38. 7 million requested and reflecting a 16.5% return on common stock equity Limerick Investigation On March 26, 1982, the PUC's Administrative Law Judge (ALJ) issued his initial recommended decision concerning the investigation of the necessity, economic justification, and reasons for increases in costs of the Limerick Generating Station. After 39 days of evidentiary hearings and almost 4,000 pages of testimony from 37 witnesses, the ALJ concluded that, at the present time, there is no alternative available that can replace Limerick at a lower cost to the consumer and that both nuclear units should be brought on line as close as possible to the projected 1985/1987 completion dates.

Page 8

The Children's Hospital Philadelp Electric and Steam Custome Many modem hospitals serve the Greate Delaware Valley Area. This operatin room at The Children's Hospital o Philadelphia uses the latest technol including this surgical microscope use for ear, nose and throat operatio Drexel University Electric and Steam Customer Our service territory encompasses more than 50 colleges and universities. Drexel University in Philadelphia uses both elec*

tricity and steam for energy and space heating requirements. Seen from under the geodesic dome is the new library under construction (left) with the sports complex (center) and the Nesbitt College of D~sign, Nutrition, Buman Behavior, Borne Economics (right).

r M1lhon Dollars 70 60 50 40 30 20 10 Dividend Reinvestment Proceeds &

Shareholder Participation Par11c1pants 90,000 60.000 30.000 78 79 80 Bl 82 Reinvested D1v1dends (Left Scale)

Add1t1onal Cash Investments (Left Scale)

Shareholders Part1c1patmg (Right Scale)

Page 10

Page 11 Tasty Baking Company Electric Customer Tastykake "Chocolate Juniors move towud the wrapping operation at '.lasty Baking Company, Philadelphia. The corn-y bakes and sells small cakes and pies and also has cookie distribution and graphic ill'ts subsidiaries. Tasty, employ-ing about 2,200 people, has been head-quartered in Philadelphia since 1914.

Despite the AL]'s recommendation, the PUC adopted a motion on May 7, 1982, that "either the cancellation or suspension of construction at Limerick Unit No. 2 would be in the public interest."

The Commission cited its inability and unwillingness to provide the revenue necessary to complete both Llffierick units as proposed and its belief that an aggressive conservation program could substantially offset the cancellation of Limerick Unit No. 2.

On August 27, the PUC issued its final order finding that Limerick Unit No. 2 should be cancelled or suspended until Umt No. 1 is completed; that the public interest requires timely completion of Limerick Unit No. l; and that the Company must pursue an aggressive conservation program to offset the absence of Unit No. 2. The order criticized construction delays announced by the Company in 1976 and 1978. It gave the Company 120 days to respond to the order.

The Company appealed the PUC order to the Common-wealth Court and, on December 15, the Court unanimously reversed the PUC's August 27 order. The PUC and the Consumer Advocate have petitioned the Pennsylvania Supreme Court for approval to appeal the Commonwealth Court decision. The Company's studies continue to demonstrate that completion of both Limerick units is in the public interest and is the least cost alternative for meeting our customers' increasing energy demands. Construction of Unit No. 2 is continuing on a schedule for service in late 1988, the earliest feasible date. Comple-tion of Unit No. 1 has been advanced by two months and should be ready for fuel loading in the summer of 1984, with commercial opera-tion anticipated in early 1985. Tutal cost to build the Limerick project is now estimated at $5.8 billion based on the 1985/ 1988 service dates.

This cost estimate is in line with other units scheduled for completion in the same time frame.

As of December 31, 1982, the Company had invested $2. 54 billion in the Limerick project-$1.35 billion for Unit No. 1, $563 million for Unit No. 2, and $627 million for facilities common to both units.

Energy Cost Rate Reduced The Company's Electric Energy Cost Rate (ECR) was reduced twice during 1982, resulting in reductions of about $200 million per year (10%). These decreases resulted from the continued good performance of our nuclear units, economic purchases of power from other utilities and lower prices for oil than anticipated. ECR rate reductions substantially offset higher base rates for Company customers, but did not affect the Company's earnings.

1982 Retail Rate Millions of Dollars Increases Application Annual Date Approved Revenue Electric-Pennsylvania 7/29/81 5/21182

$221.7 Maryland 8/18/81 3/17/82 3.3 Maryland 1113/82 2/1183 2.5 Gas 9/28/81 6/28/82 31.5 Steam 9/28/81 1/15/82 3.4 7/29/82 Pending 8.4

Nuclear Power The Company's nuclear power plants performed superbly during 1982. The Peach Bottom and Salem plants operated at a 68%

capacity factor.

Peach Bottom Umt No. 3 produced more than 8. 5 billion kilowatthours of energy during the year. The production nearly equalled the free world record previously set by Peach Bottom Unit No. 2 in 1979, since surpassed by larger foreign units. The Peach Bottom units now hold the all-time first and second positions in the United States for annual electrical energy production by a single generating unit, either nuclear or fossil fueled. The achievement was made possible, in part, by the Company's implementation of an 18-month, rather than a 12-month, refueling cycle for its nuclear units.

This eliminated the need for refueling Unit No. 3 durmg 1982 when it experienced only three outages and was in continuous operation from May 31 to year-end.

Tutal fuel savings to Company customers from the opera-tion of both units at Peach Bottom and Salem Unit No. 1 amounted to more than $400 million in 1982.

The outstanding performance by our nuclear units was a significant factor in reducing the Company's use of fossil fuel. The Company reduced its consumption of heavy and light oil in 1982 by 40% and 32%, respectively; compared to 1981. Less than 8% of electric output in 1982 was generated by oil-burning units.

Coal-Fired Generation The completion of flue gas scrubbers at Eddystone and Cromby Stations brings these coal-fired stations into full compliance with air quality regulations. These innovative facilities were designed and constructed under a Consent Decree between the Company; the Environmental Protection Agency and the Pennsylvania Department of Environmental Resources in order to satisfy air quality standards which limit permissible levels of visible emissions, sulfur dioxide and particu-late matter emissions from the stacks of the stations. The Eddystone and Cromby scrubbers use a regenerative process which produces no sludge for disposal. Including the regeneration facilities, the total cost of the scrubbers is about $317 million.

Transmission and Distribution Electric service reliability continued at a high level in 1982.

The annual service availability of 99. 991 % was comparable to the average for the last five years. In other words, the average customer was without electric service for only 46 minutes during 1982.

The Company's 220 and 500 kV systems have proven to be very reliable. Nevertheless, the towers which support the aerial lines are vulnerable to storms and accidents. Reliable electric service at the lowest possible cost requires a dependable high-voltage transmission system. An extended line outage would be very costly; particularly if it interrupted the supply from a low-cost source of power, such as a nuclear generating station. The Company has prepared for these Page IZ Christian Schmidt Bre Kegs of beer are sealed at the Christi Schmidt Brewing Company, headquarter -

in Philadelphia. This is just one part of extensive, energy-intensive plant t produces more than 20 different kinds beer. Schmidt's employs nearly 1,20 people in our service territo

Page 1a

United States Steel Corporation Electric and Gas Customer Bot metal is poured into an open hearth steel-making furnace at United State*

Steel ColJ>Oration, Fairless Bills, PA. U.S.

Steel's Fairless Works manufactures vari-ous types of semi-finished steel products.

About 8,000 people are employed by U.S.

Steel in our service territory.

Page 14

Page 15 Southeastern Pennsylvania Transportation Authority Electric and Gas Customer Adjustments are made on a trolley car at the new maintenance facility of the Southeastern Pennsylvania Transportation Authority (SEPTA) in Philadelphia. The modem fieet of 148 electrically-powered cars has replaced 30 to 40 year-old trolleys. SEPTA is responsible for operating man transit services in the five-county southeastern Pennsylvania region. Also, new electric subway trains are currently being phased into operation along the Broad Street subway. SEPTA employs more than 7,500 people in our service territory.

contingencies by its recent design and acquisition of unique temporary towers enabling us to restore up to a mile of 500 kV line in as little as 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

Power Purchases During 1982, the Company continued to utilize its transmission interconnections to purchase economical power from the Pennsylvania-New Jersey-Maryland Interconnection (PJM) and from systems outside of PJM. The purpose of these purchases was to minimize operation of higher-priced, oil-fired generating stations. Over 3.5 billion kilowatthours of coal-fired power were imported from systems in western Pennsylvania, West Virginia, Ohio and Indiana.

Another 150 million kilowatthours of oil-fired power were purchased during peak load hours from Central Hudson Gas and Electric Corpo-ration in New York, which is permitted to burn lower-cost oil. These purchases, together with 7.2 billion kilowatthours of power purchased from PJM, produced savings to the Companys customers amounting to approximately $200 million in 1982.

Limerick Supplementary Cooling Water System Construction began in early 1983 on the Point Pleasant Water Supply System, by which the Neshaminy Water Resources Authority (NWRA) will supply water from the Delaware River for public use and also for supplementary cooling water for Limerick during periods of low flow on the Schuylkill River. NWRA will pipe the water 2Y2 miles from a pumping station.which it will construct on the Delaware River, to the Company's 70 million gallon reservoir and pumping station. The Company will then pipe water from the reservoir 6Y2 miles to the Perkiomen Creek and ultimately another 7Y2 miles to Limerick by way of another pumping station and pipeline. Construction of Company facilities, estimated to cost $22 million, is scheduled to begin in early 1983.

Record Gas Sendout On January 17, 1982, temperatures averaging minus 2 degrees produced a record gas sendout of 529 million cubic feet of natural gas. This exceeded the previous daily record by 9%.

Gas Supplies Improve Natural gas availability from pipeline suppliers continued at adequate levels in 1982. The Company increased its winter supply from underground storage by expanding its normal winter natur.al gas by 672 million cubic feet (2%) for the 1982-1983 heating season.

Gas Customers and Sales The Company added nearly 5,000 new gas customers in 1982 for a total of 298,000 customers. Despite the additional customers, gas sales decreased nearly 6% to 69 billion cubic feet due to warmer weather, conservation and the recession.

Temperature Controlled Service Winter space heating loads during cold weather cause high peak usage which must be met by relying on gas storage or alternative supplies. In addition to creating potential capacity problems, this results in higher costs. Since April 1980, gas sales to new or expanding commercial and industrial customers have been limited to assure an adequate winter supply to all existing customers.

Off-peak supplies of gas are now adequate and the Com-pany is again accepting requests for firm gas supplies from commer-cial and industrial customers for large process loads. Use of space heating by these customers will continue to be restricted by requiring large temperature-sensitive, gas-burning equipment to switch to alter-nate fuels during cold winter periods.

Page 16 Philadelphia Naval Ship Electric Custome Work on the guided missile destroye Coontz nears completion at th Philadelphia Naval Shipyard. This larg dry dock was used for refurbishing th aircraft carrier Saratoga which w completed in 1982 and will be used ag

• for work on the aircraft carrier Forrest beginning in 1983. Due to the increase activity at the Navy Yard, the work fore at the Navy Base has grown t approximately 14,000 civilian employee and about 5,500 military personne including ships' personne Scott Paper Company Electric and Gas Customer This continuous paper winding operation at Scott Paper Company, Chester, PA, produces rolls of paper towels. Scott, headquartered in Philadelphia, together with its international affiliates, is one of the world's leading producen of sanitary tissue paper products and also has expanded into many other areas. Scott employs about 3,300 people in our service territory.

Page 17

Area Development Of the many construction activities currently in progress throughout the Company's service territory, two deserve particular attention. The first is Philadelphia's $325 million Center City Commuter Connection project, the largest in the City's history, including a four-track tunnel that will link 580 miles of 13 regional electrified commuter rail lines of the former Reading and Penn Central railroads into an integrated, flexible rail transit system. Extending more than 25 blocks through central Philadelphia, it is the keystone of a master plan for the revitalization of Center City Linked with the tunnel project is the $200 million second phase of the Market Street East Redevelopment Proj-ect, comprised of two new shopping malls, a major department store and three office buildings. Work is proceeding on schedule with completion expected in late 1983. The tunnel project and Market East redevelopment are providing jobs for approximately 4,000 people.

Another important asset of the area's economy is the Philadelphia Naval Shipyard. During the past three years, 18 vessels, including the aircraft carrier Saratoga, have been rehabilitated at the yard. Eight more ships, including the carrier Forrestal, are scheduled for refitting, and the total cost of these projects will be over $2 billion.

As a result of the work, civilian employment at the Navy Yard has doubled to approximately 14,000 employees.

Residential Space Beating During 1982, 11,000 additional residential units selected Company-supplied electricity or gas for space heating. Electric space heating was installed in 5,500 units and gas space heating was installed in another 5,500 units. For new construction, 54% of residential P<<ge 18 SmithlUine Beckman Corporation Electric and Steam Customer Shown here is the modem, tablet polishing operation at SmithKline Beclanan Corporation, Philadelphia.

'Ecotrin,' an enteric-coated aspirin tablet, is in the final stage of production.

SmithKline Beckman Corporation is a health care company headquartered in Philadelphia that researches, manufactures and markets ethical pharmaceutical and proprietary medicines, animal health products, eye care products, as well as laboratory analytical instruments. SmithKline Beckman provides jobs for approximately 4,300 people in our service territory.

(Photograph supplied by Sm11hKtme Beckma

ll. E. Staley Manufacturing Company Electric and Gas Customer A. E. Staley Manufacturing Company, Morrisville, PA, is a manufacturer of high-fructose com sweetener and genetic food starches. This view shows the upper end of a mechanical recompression unit in the final stage of syrup production.

Staley is a leading processor of grain and oil seeds, ranking as a major, domestic com refiner and soybean crusher.

Page 19 customers chose electric heat and 31 % chose gas heat for a total market penetration of 85% for Company energy As part of the overall space heating activity; the Company and local industry actively promoted and marketed the installation of energy-saving heat pumps in 1982. This effective campaign resulted in more than 850 customers converting their heating systems to the heat pump in 1982. The industry's continuing activities also had an effect on the new business market. Approximately 39% of all individually-metered, new residential living units constructed in our service territory have been equipped with heat pumps which are less costly than oil-fired units and one of the most efficient systems commercially available today PE Cares PE Cares, a new person-to-person program especially for senior citizens and people receiving disability or survivor benefits, was expanded to include customers in the entire service area in July, 1982.

PE Cares is available to any Company customer who is 62 years of age or older, is permanently retired and receiving Social Security benefits, is receiving survivor benefits under Social Security or is disabled and receiving benefits under Supplemental Security Income or a similar program.

The program works through the assignment of a special PE Cares representative to each participating customer. This representa-tive is available to assess the participant's situation and provide informa-tion on both Company programs and outside agencies for assistance.

Currently, 20,000 customers are participating in the program.

Page zo Fl-anklln Mint Corporation Electric and Gas Customer Finishing touches are carefully applied to a porcelain figurine at Franklin Mint Corporation's porcelain factory near corporate headquarters in Franklin Center, PA. A division of Wamer CommmiicatiollB Inc.,

Franklin Mint produces a broad range of collectible, luxury, home decor and leisure products, including medallic art, works of silver and gold, porcelain figurines and decorative plates, sculpture, jewelry, and fine books. The mint employs about 1,800 persona in our service area.

Philadelphia Electric Company Financial Section Z1 Contents Management's Discussion and Analysis of Financial Condition and Results of Operations Consolidated Statements of Income Consolidated Balance Sheets Consolidated Statements of Retained Earnings Consolidated Statements of Changes in Financial Position Notes to Financial Statements Accountants' Report Financial Statistics Operating Statistics 21 23 24 26 26 27 35 36 38 Management's Discussion and Analysis of Financial Condition and Results of Operations General The revenue growth of recent years has been accompanied by substantial increases in operating costs and carrying charges on increased investment in plant and equipment. Any future increases in such costs and charges may be expected to affect future net income and earnings per average common share adversely unless periodic rate relief is obtained to offset them. See Note 16 of Notes to Financial Statements for the estimated effects of inflation. In addition, the capital carrying charges associated with the construction of the Limerick station which are capitalized by crediting income with an allowance for funds used during construction (AFUDC) and recovered through future depreciation now represent a major portion of net income, and will continue to increase at least until the first of the Limerick units goes into service in 1985.

Sluggish economic conditions in the Company's service area also are having an adverse effect on operating results. Although the return on average common equity has increased during the past three years, the return on investment is still substantially below what the Pennsylvania Public Utility Commission (PUC) allowed as a fair return in the Company's last rate order.

During 1982, the Company put into effect increased rates for all three services-electric, gas and steam-totaling approximately $260 million per year. On July 29, 1982, the Company filed with the PUC for an additional $8.4 million in steam revenues. The PUC has suspended the rate increase until April 28, 1983.

Electric Operating Revenue Electric Revenue Increases Millions of Dollars

'82 vs. '81

'81 vs. '80 Rate Increases

$198.2

$1484 Fuel Charges (83.0) 40.l Salem Unit No. 2 89.6 45.9 Other (25.9) 0.7

'Ibtal

$178.9

$235. 1 Increases in 1982 and 1981 reflect higher base rates and the sale of output and capacity equivalent of Salem Unit No. 2 to Jersey Central Power & Light Company Salem Unit No. 2 sales will be reduced in 1983 due to a scheduled outage for refueling, maintenance and Nuclear Regulatory Commission (NRC) mandated modifications.

Kilowatthour sales of electricity to retail customers declined slightly in 1981 and 1982.

Gas Operating Revenue Increases in 1982 over 1981 primarily reflect the recovery of higher fuel costs and higher rates. Mcf sales of gas declined 5. 7 percent in 1982 from the record high sales of 1981.

Fuel and, Energy Interchange Expense Fuel and interchange expense decreased 5.0 percent in 1982 from 1981 as lower electric fuel costs resulting from the excellent performance of our nuclear units and economic purchases of power from other utilities were partially offset by increased gas fuel expense. The 8.9 percent increase in fuel and interchange expense in 1981 over 1980 was the result of higher prices for all fuels.

Other Operation & Maintenance Expenses Other operation and maintenance expenses have increased in the last two years due to inflation and to growth in utility plant.

Depreciation Increases in depreciation in the last two years reflect additions to plant in service, primarily Salem Unit No. 2.

Taxes on Income Tuxes on operating income increased in 1982 over 1981 as the result of higher income.

Income tax credits, net, included in other income, have increased in the last two years as a result of the higher allowance for borrowed funds used during construction.

Taxes Other Than Income Tuxes, other than income, have increased due to increases in revenue, which is subject to a gross receipts tax, and due to higher realty and social security taxes.

Allowance for Funds Used During Construction The increases in AFUDC for the last two years resulted from a higher cost of capital for construction and increases in construction work in progress.

Interest Charges Interest charges on debt increased in the last two years because of additional debt outstanding. The ratio of earnings to mortgage interest, which is a measure of the Company's ability to issue additional long-term debt, increased to 2. 42 times in 1982 and remained above the minimum of 2.0 times required for the issuance of new mortgage debt.

Capital Expenditures and Changes in Financial Position The Company is carrying on a construction program which is estimated to require expenditures of

$996 million in 1983 and $2.6 billion from 1984 to 1986. A majority of these expenditures relates to the construction of the Company's two 1055 mW nuclear generating units at Limerick, PA. Successful completion of this program is dependent on the Company's ability to obtain external financing, primarily through sales of new debt and equity securities which are subject to market conditions and to meeting certain earnings tests. The program is also subject to the licensing requirements of the NRC, to financing approvals by the PUC and to change due to litigation. The Company cannot predict the outcome of Return on Ratio of Eamings Average Common to Mortgage Equity Interest Percent

'I\\mes Covered 15 2.50

-:7

.~~ i 12 2.00 9

150 6

I 00 3

50 0

0 78 79 BO 81 82 78 79 BO Bl 82 zz such regulatory reviews, but believes the safety requirements have been or will be met, the economic desirability of the program has been demonstrated and that the program will be successfully completed and approved.

During 1982 a number of events occurred regarding the PUC's investigation of the Limerick project.

On August 27, 1982, the PUC issued its final order finding that cancellation or suspension of Limerick Unit No. 2 would be in the public interest. The Company appealed the PUC order to the Pennsylvania Commonwealth Court and on December 15, Commonwealth Court reversed the PUC's August 27 order. On January 7, 1983, the PUC voted to petition the Pennsylvania Supreme Court for Approval of Appeal of the Commonwealth Court's order.

The Company estimates that the final cost of the Limerick project will be $5.8 billion when completed in late 1988.

Placing the Limerick units into service will enable the Company to retire some of its older, less efficient fossil units and to lessen its dependence on high-cost oil. In addition, when the units are completed, it is expected that the Company will realize substantial fuel savings compared to obtaining electricity from alternative generating sources.

Interim financing of the construction program is provided by commercial paper borrowings and short-and intermediate-term bank loans, which are also dependent on the Company's financial position.

Electric Sales Gas Sales (including Salem Unit No. 2) 81lhons of KWH 81lhons of Cubic Feet 30 75 25 60 20 45 15 30 10 15 5

0 78 79 BO 81 82 Salem Umt No. 2

Philadelphia Electric Company and Subsidiary Companies Consolidated Statements of Income ZS For the Year Ended December 31 Operating Revenues Electric Gas Steam Total Operating Revenues Operating Expenses Fuel and Energy Interchange Other Operation Expense Maintenance Depreciation Tuxes on Income Tuxes, Other than Income Total Operating Expenses Operating Income Other Income Allowance for Other Funds Used During Construction Income Tux Credits, net Other, net Total Other Income Income Before Interest Charges Interest Charges Long-Term Debt Short-Term Debt Allowance for Borrowed Funds Used During Construction Net Interest Charges Net Income Preferred Stock Dividends Earnings Applicable to Common Stock Average Shares of Common Stock Outstanding (Thousands)

Earnings Per Average Common Share (Dollars)

Dividends Per Common Share (Dollars)

See notes to financial statements.

1982

$2,180,960 390,427 73,366 2,644,753 1,128,498 411,753 199,747 143,848 207,669 164,511 2,256,026 388,727 65,699 75,845 (717) 140,827 529,554 308,862 32,030 (147,561) 193,331 336,223 57,600

$ 278,623 116,480

$2.39

$2.06 1982 Revenue Dollar Sources Electnc 71f 198 1 1980 (Thousands of Dollars)

$2,002,063

$1,766,956 356,431 290,743 74,931 65,695 2,433,425 2, 123,394 1,187,635 1,090,497 360,840 279,587 156,878 136,963 130,283 122,947 129,484 93,673 145,312 133,761 2, 110,432 1,857,428 322,993 265,966 65,013 50,483 63, 164 49,025 2,457 3,425 130,634 102,933 453,627 368,899 266,691 224,970 33, 155 13,865 (123,784)

(97,067) 176,062 141, 768 277,565 227,131 53,804 52, 181

$ 223,761

$ 174,950 99,557 87,302

$2.25

$2.00

$1.90

$1.80 1982 Revenue Dollar Uses Other

!Uel&

Interchange Expe..s 41' Operation & Maintenance Expenses Z7¢

Philadelphia Electric Company and Subsidiary Companies Consolidated Balance Sheets ASSETS Utility Plant, at original cost Electric Gas Steam Common, used in all services Less: Accumulated Depreciation Net Utility Plant in Service Construction Work in Progress Total Utility Plant Investments Current Assets Cash and Temporary Cash Investments Accounts Receivable Customers Other Inventories, at average cost Fuel (coal, oil and gas)

Materials and Supplies Deferred Income Tuxes Prepayments Total Current Assets Deferred Debits Total See notes to financial statements.

4 December 31 1982 1981 (Thousands of Dollars)

$4,519,544 394,876 53,998 127,304 5,095,722 1,450,149 3,645,573 2,810,014 6,455,587 91,427 50,025 284,151 58,012 97,478 45,552 43,350 7,721 586,289 24,695

$7,157,998

$4,163,088 371,239 54, 152 118,701 4,707, 180 1,330,611 3,376,569 2,337,517 5,714,086 77,780 30,678 277,292 65, 131 83,612 48,581 17,052 6,819 529, 165 31,515

$6,352,546

CAPITALIZATION AND LIABILITIES Capitalization Common Shareholders' Equity Common Stock Other Paid-In Capital Retained Earnings Preferred Stock Series Without Mandatory Redemption Requirements Series With Mandatory Redemption Requirements Long-Term Debt Total Capitalization Current Liabilities Short-Term Debt Bank Loans Commercial Paper Current Maturities of Long-Term Debt Accounts Payable Tuxes Accrued Interest Accrued Dividends Declared Deferred Fuel Credits Other Total Current Liabilities Deferred Credits Accumulated Deferred Income Tuxes Accumulated Deferred Investment Tux Credits Other Total Deferred Credits Total See notes to finandal statements.

December 31 1982 1981 (Thousands of Dollars)

$1,826,198

$1,572,388 4,641 3,888 423,596 387,251 2,254,435 1,963,527 372,472 372,472 292,290 266,929 3,028,525 2,745,723 5,947,722 5,348,651 32,200 54,225 32,500 21,280 36,062 164,419 165,485 65,954 68,421 99,764 82,294 24,167 23,380 85,379 31,299 24,734 18, 130 550,397 479,296 290,538 273,528 296,068 204,061 73,273 47,010 659,879 524,599

$7,157,998

$6,352,546

Philadelphia Electric Company and Subsidiary Companies Consolidated Statements of Retained Earnings Balance, January 1 Net Income Cash Dividends Declared Preferred Stock (at specified annual rates)

Common Stock (per share, $2.06 in 1982,

$1.90 in 1981 and $1.80 in 1980)

Expenses of Capital Stock Issues Balance, December 31 Consolidated Statements of Changes in Financial Position Sources of Funds Funds from Operations Net Income Charges (Credits) Not Affecting Funds Depreciation, Amortization and Spent Fuel Costs Deferred Income Tuxes Investment Tux Credits, net of Amortization Allowance for Other Funds Used During Construction

'Ibtal from Operations Funds from Financings Sales of Securities Long-Term Debt Preferred Stock Common Stock Change in Short-Term Debt Sale of Salem Station Nuclear Fuel Sale of Tux Benefits

'Ibtal from Financings Total Sources Uses of Funds Additions to Utility Plant Allowance for Other Funds Used During Construction Dividends on Preferred and Common Stock Retirement of Long-Term Debt Change in Other Items of Working Capital Other, net Total Uses See notes to financial statements.

'~-. -

' '*--r For the Year Ended December 31 1982 1981 1980 (Thousands of Dollars)

$ 387,251

$ 353,570

$338, 154 336,223 277,.565 227, 131 723,474 631.135 565,285 57,982 53,762 52,973 240,486 189.476 157.423 1,410 646 1,319 299,878 243,884 211.715

$ 423,596

$ 387,251

$353,570

$ 336,223

$ 277.565

$227, 131 159,668 144,031 130,354 (10,215) 2,011 (12, 121) 101,646 25,049 28,135 (65,699)

(65,013)

(50.483) 521;623 383,643 323,016 320,000 423,500 275,000 30,000 72,000 253,810 194,925 137,816 10,475 1,635 (32,597) 100, 166 53,743 614,285 773,969 452,219

$1,135,908

$1, 157,612

$775,235 870,715 787,075 579,802 (65,699)

(65,013)

(50.483) 298,468 243,238 210,396 50,183 137.470 140,671 (44,582) 19, 797 (108,750) 26,823 35,045 3,599

$1,135,908

$1, 157,612

$775,235

Philadelphia Electric Company and Subsidiary Companies Notes to Financial Statements I. Significant Accounting Policies:

General.

All utility subsidiary companies of Philadelphia Electric Company are wholly owned and are included in the consolidated financial statements. Non-utility subsidiaries are included in investments and accounted for by the equity method. The accounting policies are in accordance with those prescribed by the regulatory authorities having jurisdiction.

Revenues.

Revenues are recorded in the accounts upon billing to the customer. Rate increases are billed from dates authorized or permitted to become effective by the regulatory authorities.

Fuel Expense.

The Company recognizes fuel expense which is recoverable under energy adjustment clauses when it is billed to customers.

The Company leases nuclear fuel for use in its nuclear generating stations. Nuclear fuel costs are charged to fuel expense on the basis of the number of units of thermal energy produced as they relate to the estimated total thermal units to be produced over the life of the fuel. Commencing in May; 1981, the estimated disposal costs of spent fuel are being charged to opera-tions as permitted for rate-making purposes. Such amounts, net of related deferred income taxes, are deposited in an escrow account and invested for funding of future costs. The Company believes that any additional costs, which may be significant, would be recoverable through adjustments of rates charged to its customers.

Depreciation.

For financial reporting purposes, deprecia-tion is provided over the estimated service lives of the plant on the straight-line method and, for tax purposes, generally; over shorter lives on accelerated methods. The estimated decommissioning costs of portions of the nuclear plants are being charged to operations as permitted for rate-making purposes. Such amounts, net of deferred income taxes, are deposited in an escrow account and invested for funding of future costs. The Company believes that any additional costs, which may be significant, would be recoverable through adjustments of rates charged to its customers. The annual depreciation provisions, expressed as a percent of average depreciable utility plant in service, Z. Investments:

At December 31, 1982 and 1981:

Gas Exploration and Development Costs Nonutility Property Escrowed Funds for Future Decommissioning of Nuclear Plant & Disposition of Spent Nuclear Fuel Other Total P,.tc'.C c:J)C-/

/

'--, /.

-* -~'~

were approximately 3.00% for 1982, 3.01% for 1981 and 3.06% for 1980.

Income Taxes.

Deferred income taxes are provided for differences between book and taxable income to the extent permitted for rate-making purposes, Investment tax credits, other than credits resulting from contributions to the Tux Reduction Act Stock Ownership Plan for employees, which do not affect income, are deferred and amortized to income over the estimated useful lifE? of the related utility plant Allowance for Funds Used During Construction (AFUDC).

AFUDC is a non-cash item which is defined in the uniform system of accounts prescribed by regula-tory authorities as "the net cost for the period of construc-tion of borrowed funds l)Sed for construction purposes and a reasonable rate on other funds when so used." AFUDC is recorded as a charge to Construction Work In Progress, and the equivalent credits are to "Interest Charges" for the pre-tax cost of borrowed funds and to "Other Income" for the remainder as the allowance for equity funds. The rate used for capitalizing AFUDC, which averaged 9.20% in 1982, 8.65% in 1981, and 7.85% in 1980, is computed under a method prescribed by the regulatory authorities. The rate is a "net after-tax rate" and the current income tax reductions applicable to the interest charges capitalized are recorded in "Other Income." AFUDC is not included in taxable income and the depreciation of capitalized AFUDC is not a tax-deductible expense.

Retirement Plan.

The Company has a non-contributory trus-teed retirement plan applicable to all regular employees.

Pension costs include normal cost for the year and amor-tization of unfunded prior service costs, over ten to twenty-year periods. Approximately 80% of such costs were charged to operating expense and the remainder, associ-ated with construction labor, to the cost of new utility plant Gas Exploration and Development Costs.

The Company has invested in several joint ventures for exploring and drilling for gas. These costs are capitalized under the full cost method and charged to operations commensurate with the production of gas by the ventures, 1982 1981 (Thousands of Dollars)

$48,099

$46,294 15,911 15,433 15,601 11,816

$91,427 5,798 10,255

$77,780

Philadelphia Electric Company and Subsidiary Companies Notes to Financial Statements continued

3. Common Stock:

At December 31, 1982 and 1981, Common Stock, without par value, consisted of 160,000,000 shares authorized and 125,766,898 shares and 108,507,097 shares, respectively; Shares

,)*1.

outstanding. At December 31, 1982, there were 6,531,056 shares reserved for issuance under stock purchase plans.

Amounts Common Stock Issued:

1982 1981 1980 1982 1981 1980 Public Sales 12,000,000 12,800,000 Dividend Reinvestment and Stock Purchase Plan 4,019,605 2,667,081 Employee Stock Purchase Plan 453,013 407,445 Tux Reduction Act Stock Ownership Plan 787,183 Totals 17,259,801 15,874,526

4. Preferred Stock:

At December 31, 1982 and 1981, Preferred Stock, $100 par, cumulative:

Series (without mandatory redemption requirements):

9.50%

8.75%

7.85%

7.80%

7.75%

4.68%

4.4%

4.3%

3.8%

Series (with mandatory redemption requirements)

(c) and (d):

l 7.125o/o (Sold 1982) 15.25% (Sold 1980) 10% (Sold 1980) 9.52%

8.75%

7.325%

7%

Unclassified Current Redemption Price (a)

$106.50 107.00 105.00 103.00 103.00 104.00 112.50 102.00 106.00 117.125 115.25 104.44 106.25 108.75 104.69 104.00 Total Preferred Stock Refunding Restricted Prior to (b)

Authorized 750,000 650,000 500,000 750,000 200,000 150,000 274,720 150,000 300,000 3,724,720

. 5-1.-87 300,000 5-1-90 500,000 5-1-85 220,000 5-1-86 500,000 5-1-88 500,000 750,000 400,000 3, 170,000 3, 105,280' 10,000,000*

7,000,000

$175,620 2,399,418 60,399 349,937 6,677 11,114 9,749,355

$253,810 Shares Outstanding 1982 1981 750,000 750,000 650,000 650,000

. 500,000 500,000 750,000 750,000 200,000 200,000 150,000 150,000 274,720 274,720 150,000 150,000 300,000 300,000 3,724,720 3,724,720 300,000 500,000 500,000 220,000 220,000 446,830 453,920 500,000 500,000 630,000 660,000 326,070 335,370 2,922,~00 2,669,290 6,647,620 6,394,010 (Thousands of Dollars)

$i54,786

$101,360 34,809 31,593 5,330 4,863

$194,925

$137.816 Amounts 1982 1981 (Thousands of Dollars)

$ 75,000 65,000 50,000 75,000 20,000 15,000 27,472 15,000 30,000 372,472 30,000 50,000 22,000 44,683 50,000 63,000 32,607 292,290

$664,762

$ 75,000 65,000 50,000..l 75,000 20,000 15,000 27,472 15,000

. 30,000 372,472 50,000.

22,000 45,392 50,000 66,000 33,537 266,929

$639,401 (a) Redeemable, at the option of the Company, at the indicated dollar amounts per share, plus accrued dividends.

1983-1987 are as follows: 1983-$3,362,000; 1984-$8,937,000; 1985-$9, 130,000; 1986-$16,030,000; and 1987-$16,030,000.

(b) Prior to the date specified, none of the shares of each series indicated may be redeemed through refunding at an interest cost or dividend rate which is less than the dividend rate of such series.

(c) Redemption requirements (par value) in the period (d) The excess of the aggregate par value of reacquired shares, 46,390 shares in 1982, 74,010 shares in 1981 and

.45,210 shares in 1980, over the aggregate purchase price is reflected in Other Paid-In Capital: $753,000 in i982,

$1,307,000 in 1981 and $378,000 in 1980. *

, 5. Long-Term Debt:

At December 31, 1982 and 1981:

Philadelphia Electric Company First and Refunding Mortgage Bonds (a)

'Ibtal First and Refunding Mortgage Bonds Notes Payable-Banks Notes Payable-Other Pollution Control Notes Debentures Debentures Debentures Sinking Fund Debentures of Series 3Y4%

3Ys%

3Ys%

4%%

4%%

3%%-13%%

4Y2%-15W1'o 7%%-11%%

6%

-12\\.12%

9Ys%-18%%

(b) 17%

5.5% - 13%

4.85%

14Ys%

14%%

Due 1982 1981 (Thousands of Dollars) 1982 35,000 1983 20,000 20,000 1985 50,000 50,000 1986 50,000 50,000 1987 40,000 40,000 1988-1992 215,000 215,000 1993-1997 403,429 405,256 1998-2002 574,600 584,988 2003-2007 498,500 498,500 2008-2012 550,000 350,000 2,401,529 2,248,744 1984-1987 225,000 225,000 1986-1987 20,000 1984-2012 229,780 130,205 1986 21,330 22,710 1990 50,000 50,000 2005 100,000 100,000 Philadelphia Electric Power Company-a subsidiary Unamortized Debt Discount and Premium, Net 1995 18,193 (16,027) 19,356 (14,230)

'Ibtal Long-Term Debt Current Maturities included in Current Liabilities (c)

Long-Term Debt included in Capitalization (a) Utility plant is subject to the lien of the Company's mortgage.

(b) At interest rates ranging from prime rate to 107% of prime rate.

(c) Long-term debt maturities in the period of 1983-1987 are as follows: 1983-$21,280,000; 1984-$92,949,000; 1985-$160,020,000; 1986-$90,300,000, and 1987-$109,500,000.

The Company has a $400 million revolving credit and term loan agreement with a group of banks which expires

6. Short-Tenn Debt:

Average Short-Term Borrowings Average Interest Rates, Computed on Daily Basis Maximum Short-Term Borrowings Outstanding 3,049,805 2,781,785 (21,280)

(36,062)

$3,028,525

$2,745,723 in 1987, under which no amounts were outstanding as of December 31, 1982. Interest is based on the prime rate and there is an annual commitment fee of 3/s% on the unused amount. As a result of the Limerick investigation, the Company does not presently meet certain conditions for borrowing. The Company has requested and the banks have tentatively agreed to modify or waive such conditions.

1982 1981 (Thousands of Dollars)

$ 90,180

$146,273 13.13%

17.80%

$168,725

$266,512 Average Interest Rates on Short-Term Borrowings at December 31:

Bank Loans Commercial Paper-Tux Exempt Commercial Paper-Tuxable As of December 31, 1982, the Company had borrowed

$32,200,000 under lines of credit with banks aggregating 10.37%

4.92%

9.62%

16.37%

$339,175,000. The Company generally does not have formal compensating balance arrangements with these banks.

Philadelphia Electric Company and Subsidiary Companies Notes to Financial Statements continued

7. Jointly-Owned Electric Utility Plant:

The Company's ownership interests in jointly-owned utility plant at December 31, 1982 were as follows:

Peach Bottom Operator Philadelphia Electric Company Participating Interest 42.49%

Company's share of:

Utility Plant

$405,848 Accumulated Depreciation 81,664 Construction Work in Progress 8,551 The Company's participating interests are financed with Company funds and, when placed in service, all

8. Taxes on Income:

Included in operating expenses:

Current Federal Current State Total Deferred Federal Deferred State Total Investment tax credits, net of amortization-Federal

'Ibtal Federal

'Ibtal State Total Included in other income:

Current Federal Current State Total

'Ibtal income tax provisions:

Federal State Total Investment tax credits reduced Federal income taxes cur-rently payable by $108,860,000 in 1982, $29,817,000 in 1981 and $32,428,000 in 1980. Approximately $18,500,000 of addi-tional investment tax credits available in 1982 have not been realized due to limitations based on taxable income.

These credits may be used to reduce Federal income taxes in future years through 1997. Investment tax credits consist of (a) the basic credits allowable of 10% plus (b) a credit of 1W1'o resulting from the 'Tux Reduction Act Stock Ownership Plan for employees ($9,600,000 in 1982 and

$6,200,000 in 1981, and none in 1980). The additional credits which are passed on to the employees of the Company in the form of Philadelphia Electric Company Common Stock have no effect on net income.

Production Plants Transmission Plant Salem Keystone Conemaugh Public Service Pennsylvania Pennsylvania Various Electric and Electric Electric Companies Gas Company Company Company 42.59%

20.99%

20.72%

21% to 43%

(Thousands of Dollars)

$820,298

$47,481

$58,602

$69,503 78,576 21,273 18,289 8,863 23,475 3,774 904 operations are accounted for as if such participating interests were wholly-owned facilities.

1982 1981 1980 (Thousands of Dollars)

$ 71,987

$ 75,558

$ 55,416 44,251 26,866 22,243 116,238 102,424 77,659 (8,390) 6,007

( 4,653)

(l,825)

(3,996)

(7,468)

(10,215) 2,011 (12,121) 101,646 25,049 28, 135 165,243 106,614 78,898 42,426 22,870 14,775

$207,669

$129,484

$ 93,673 (60,506)

(50,299)

(39, 132)

(15,339)

(12,865)

(9,893)

$(75,845)

$(63,164)

$(49,025) 104,737 56,315 39,766 27,087 10,005 4,882

$131,824

$ 66,320

$ 44,648 In December, 1981, the Company sold the tax benefits attributable to its ownership interest in the Salem Station Unit No. 2. This transaction was structured under the safe harbor lease provisions of the Economic Recovery

'Tux Act of 1981. The proceeds from the sale, $53, 743,000, were credited to Deferred Income 'Tuxes ($24,759,000),

Deferred Investment 'Tux Credits ($21,863,000) and Other Deferred Credits ($7,121,000) and are being amortized to income over the estimated useful life of the unit.

Beginning June 1, 1982, the normalization of state income taxes associated with accelerated deprecia-tion was adopted for both accounting and rate-making purposes.

Provisions for deferred income taxes consist of the tax effects of the following timing differences between tax and book income:

1982 1981 1980 (Thousands of Dollars)

Depreciation and amortization

$ 30,042

$ 25,452

$ 25,655 Nuclear fuel disposal costs (7,865)

(4,299)

Deferred fuel credits (27,264)

(21,804)

(37,369)

Other (5,128) 2,662 (407)

Total

$ (10,215)

$ 2,011

$(12, 121)

The total income tax provisions differ from amounts computed by applying the Federal statutory tax rate to income and adjusted income before income taxes for the following reasons:

Net income

'Ibtal income tax provisions Income before income taxes Deduct-allowance for funds used during construction (non-taxable)

Adjusted income before income taxes Income taxes on above at Federal statutory rate of 46%

Increase (decrease) due to:

Depreciation timing differences not normalized State income tax, net of Federal income tax benefits Tuxes and pension costs capitalized but expensed for tax purposes Amortization of investment tax credits previously deferred Other, net Total income tax provisions Provision for income taxes as a percent of:

Income before income taxes Adjusted income before income taxes

9. Tuxes, Other than Income:

Gross receipts Capital stock Realty Other Total

10. Retirement Plan Costs:

$336,223 131,824 468,047 213;260

$254,787 117,202 10,672 14,627 (396)

(7,214)

(3,067)

$131,824 28.2%

51.7%

1982

$106,090 18,928 22,505 16,988

$164,511

$277,565

$227, 131 66,320 44,648 343,885 271,779 188, 797 147,550_

$155,088

$124,229 71,340 57, 145 (551)

(1,338) 5,436 2,636 (3,226)

(7,028)

(4,769)

( 4,293)

(1,910)

(2,474)

$ 66,320

$ 44,648

. 19.3%

16.4%

42.8%

35.9%

1981 1980 (Thousands of Dollars)

$100,912

$ 90,487 19,600 19,046 9,555 9,398 15,245 14,830

$145,312

$133,761 Retirement plan costs, which are funded as accrued, aggregated $37,800,000 in 1982, $31,700,000 in 1981, and $28,575,000 in 1980. Plan data as of the dates of the most recent actuarial reports is as follows:

Actuarial present value of accumulated plan benefits (based on 7.0% and 6.5% assumed rate of return for 1982 and 1981, respectively):

Vested Nonvested Net assets available for benefits January 1 1982 1981 (Thousands of Dollars)

$360,835 45,080

$405,915

$359,406

$326,786 38,317

$365,103

$332,027

Philadelphia Electric Company and Subsidiary Companies Notes to Financial Statements continued

11. Segment Information:

1982 Operating revenues Operating expenses, excluding depreciation Depreciation

'Ibtal operating expenses Operating income Utility plant additions December 31:

Allocable assets:

Net utility plant ( *)

Inventories Nonallocable assets Total assets 1981 Operating revenues Operating expenses, excluding depreciation Depreciation

'Ibtal operating expenses Operating income U\\ility plant additions December 31:

Allocable assets:

Net utility plant (*)

Inventories Nonallocable assets Total assets 1980 Operating revenues Operating expenses, excluding depreciation Depreciation

'Ibtal operating expenses Operating income Utility plant additions December 31:

Allocable assets:

Net utility plant ( *)

Inventories Nonallocable assets Total assets Electric

$2,180,960 1,688,365 130,225 1,818,590

$ 362,370

$ 843,371 6,097,411 105,035

$6,202,446

$2,002,063 1,586,506 117,270 1, 703, 776

$ 298,287

$ 746,535 5,372,240 101,956

$5,474, 196

$1,766,956 1,414,038 111,106 1,525, 144

$ 241,812

$ 540,628 4,867,879 102, 193

$4,970,072

(*)Includes construction work in progress and allocated common utility property.

Gas Steam

'Ibtal (Thousands of Dollars)

$390,427

$73,366

$2,644,753 354,093 69,720 2,112,178 11,916 1,707 143,848 366,009 71,427 2,256,026

$ 24,418

$ 1,939

$ 388,727

$ 27,125 219

$ 870,715 332,437 25,739 6,455,587 37,645 350 143,030

$370,082

$26,089 6,598,617 559,381

$7,157,998

$356,431

$74,931

$2,433,425 322,008 71,635 1,980, 149 11,294 1,719 130,283 333,302 73,354 2, 110,432

$ 23, 129

$ 1,577

$ 322,993

$ 40,432 108

$ 787,075 314,652 27, 194 5,714,086 29,986 251 132, 193

$344,638

$27,445 5,846,279 506,267

$6,352,546

$290,743

$65,695

$2, 123,394 258,063 62,380 1,734,481 10, 169 1,672 122,947 268,232 64,052 1,857,428

$ 22,511

$ 1,643

$ 265,966

$ 38,833 341

$ 579,802 283,414 28,748 5, 180,041 18,582 311 121,086

$301,996

$29,059 5,301, 127 401,422

$5,702,549

12. Leases:

Certain leases, including the nuclear fuel contracts for Peach Bottom and Salem, meet the criteria of a capital lease as defined by Financial Accounting Standards, but are accounted for as operating leases in accordance with the rate-making process. If these leases were capitalized they would not have a material effect on assets or liabilities, and they would have no effect on related expenses.

The minimum rental commitments under all noncancelable agreements aggregated $400,654,000 at December 31, 1982. The annual rental commitments are estimated to be $100,039,000 for 1983; $104,176,000 for 1984;

$86,084,000 for 1985; $42,375,000 for 1986; and $10,333,000 for 1987.

13. Limerick Generating Station:

The Company has under construction two nuclear units at Limerick, Pennsylvania. In the latter part of 1980, the Pennsylvania Public,Utility Commission (PUC) began an investigation into various matters concerning the Limerick Generating Station. On August 27, 1982, the PUC issued an order stating that continued construction of Unit No. 2 is not in the public interest and directing the Company to cancel or suspend construction within 120 days of the order. The Company appealed the order to the Commonwealth Court and, on December 15, 1982, Commonwealth Court reversed the PUC order. On January 14, 1983, the PUC petitioned the Pennsylvania Supreme Court to allow an appeal of the Commonwealth Court's decision.

If Unit No. 2 were ultimately cancelled, the Company would request regulatory authorities to permit the recovery of its investment, but there can be no assurance that such requests would be granted.

14. Commitments and Contingencies:

The Company has incurred substantial commitments in connection with its construction program. Construction expenditures are* estimated to be $996,000,000 for 1983 and

$2,603,000,000 for 1984-1986. These estimates are reviewed and revised periodically to reflect changes in economic conditions, revised load forecasts and other appropriate factors. Plant facilities under construction, particularly Limerick, require numerous permits and licenses, which the Company cannot be assured will be issued at comple-tion of the facilities.

The Price-Anderson Act places a "Limit of Liability" of $560,000,000 on each licensed nuclear facility for claims that could arise from an incident involving any licensed nuclear facility in the nation. The Company has insured for this exposure through a combination of private insurance and indemnity agreements with the Nuclear Regulatory Commission. In the event of such a nuclear incident, the Company could be assessed up to $8, 500, 000 per incident wlth a maximum amount of $17, 000, 000 in any one year.

Rentals charged to operating expenses were as follows:

Nuclear fuel Other Total 1982

$41,417 24,356

$65,773 1981 1980 (Thousands of Dollars)

$26, 709

$21,177 24,782 21,235

$51,491

$42,412 The Company's proportionate share of the contractual liabilities to purchase nuclear fuel under lease agreements for the Peach J3ottom Station and Salem Station as of December 31, 1982 was $225,318,000. Independent fuel companies have been authorized to acquire and own up to a maximum of $525,000,000 of nuclear fuel at any one time and have contracted to sell the energy therefrom to the Company:

The Company has completed a review of the Limerick project and believes that completion of the project is financially feasible and in the best interest of its customers. The Company has revised the schedule for the construction and completion of Limerick Unit No. 2 which is expected to be in service in late 1988. Unit No. 1 is expected to be in service in early 1985. The total final cost of the project is presently estimated at $5.8 billion-

$2. l billion for Unit No. 1, $2.4 billion for Unit No. 2 and

$1.3 billion for common plant facilities.

At December 31, 1982, engineering studies indicated Unit No. 1 and common plant facilities were approximately 83%complete and Unit No. 2 approximately 30% complete. The Company's allocated investment in Unit No. 1, Unit No. 2 and common plant facilities was $1.35 billion, $563 million, and $627 million, respectively:

The Company is insured for damage to its nuclear plant facilities for losses up to $967,000,000. Under

• the terms 'of the various insurance agreements, the Company could be assessed up.to $28,000,000 for losses incurred at any of the plants insured by the insurance companies. The Company is a self-insurer, to the extent of its ownership interests, for any property loss in excess of th.e insurance coverage.

°"'

The Company is a member of an industry mutual insurance company to provide replacement power cost insurance coverage in the event of a major outage at a nuclear station. The premium for this coverage is subject to an assessment for adverse loss experience. The Com~

pany's maximum share of any assessment is $12,860,000.

Actions have been filed in the U.S. District Court against the Company with respect to alleged discrimination in its employment or promotion practices.

Counsel is of the opinion that the ultimate outcome of these actions would not have a material adverse effect on the financial position of the Company:

Philadelphia Electric Company and Subsidiary Companies Notes to Financial Statements continued IS. Quarterly Data (Unaudited):

The data shown below includes all adjustments (consisting of normal recurring accruals) which the Company considers necessary for a fair presentation of such amounts.

Earnings Quarter Operating Applicable to Ended Revenues Net Income Common Stock (Thousands of Dollars) 1982 1981 1982 1981 1982 1981 March 31

$757,077

$647,927

$90,951

$69,904

$77,138

$56,382 June 30 592,573 543,612 63,240 58,475 48,622 45,017 September 30 661,594 620,697 100,402 79, 198 85,816 65,763 December 31 633,509 621, 189 81,630 69,988 67,047 56,599

16. Supplementary Information to Disclose the Estimated Effects of Inflation for the Year Ended December 31, 1982 (Unaudited):

Earnings Average Shares Per Average Outstanding Share (Thousands)

(Dollars) 1982 1981 1982 1981 108,593 92,706

$.71 $.61 115,289 98,383

.42

.46 117,478 99,227

.73

.66 124,378 107,749

.54

.53 The following supplementary information is supplied to exceed the original costs incurred when the facilities were show the estimated effects of inflation because the built because of the cumulative effect of inflation. These Company is required to do so, according to the Statement plant replacement costs, net of accumulated depreciation, of Financial Accounting Standards No. 33. The methods are estimated at $11,246,000,000 as restated for "constant required to develop this information are approximate and dollars" and $11,795,000,000 as restated for "current costs."

complex, and may not necessarily reflect the true effects Under the "constant dollar" method, the Company is of inflation on the Company Under existing regulatory law, required to restate the original costs in terms of dollars of the Company is permitted to recover actual operating and equal purchasing power, as measured by the Consumer capital costs incurred to serve customers and a reasonable Price Index for all Urban Consumers. The "current cost" return on investment, and the Company believes it will be method uses Handy-Whitman Indices of Public Utility allowed to recover cost increases caused by inflation as Construction Costs. Results from the two methods differ such increases are actually incurred.

because construction costs have increased more rapidly Effect of Inflation on Reported Income. In than consumer prices in general. Under the "current cost" adjusting the Consolidated Statements of Income, as shown method, the effect ($413,000,000) of general inflation in 1982 below, only depreciation expense was adjusted for the on net utility plant was less than the increase ($422,000,000) effect of inflation. The "constant dollar" and "current cost" in specific prices by $9,000,000 while the effect of general depreciation expenses were determined by applying the inflation exceeded specific prices by $197,000,000, Company's depreciation rates to restated 1982 average

$218,000,000 and $90,000,000 for 1981, 1980 and 1979, depreciable plant in service. Other Operating Expenses respectively; expressed in average 1982 dollars. In the were not required to be adjusted.

Company's opinion, the "current cost" method is more If the Company had to replace its entire appropriate for estimating the effect of inflation on utility utility plant at this time, the costs to do so would greatly plant.

Consolidated Statements of Income Adjusted for Inflation for the Year Ended December 31, 1982 (Thousands of Dollars)

Operating Revenues Depreciation Other Operating Expenses Operating Income Other Income Income Before Interest Charges And Preferred Stock Dividends Interest Charges and Preferred Stock Dividends Earnings Applicable to Common Stock*

Earnings Per Average Share (Dollars)**

• Earnings applicable to Common Stock for 1981, 1980, and 1979 restated in average 1982 dollars, amounted to $64, 707,000,

$58,379,000 and $49,617,000, respectively; for Constant Dollars and $24,427,000 for 1981 and losses of $2,461,000 and $8,903,000 for 1980 and 1979, respectively; for Current Costs.

As Adjusted For Constant Dollars Current Costs As Reported (Average 1982 Dollars)

(Average 1982 Dollars)

$2,644,753

$2,644,753

$2,644,753 143,848 334,000 374,000 2, 112, 178 2, 112, 178 2, 112, 178 388,727 198,575 158,575 140,827 140,827 140,827 529,554 339,402 299,402 250,931 250,931 250,931

$ 278,623 88,471 48,471

$2.39

$0.76

$0.42

• • Earnings per average share for 1981, 1980 and 1979, based on the restated earnings were $0.65, $0.67 and

$0.62, respectively; for Constant Dollars and $0.25, for 1981 and losses for 1980 and 1979 of $0. 03 and $0.11, respectively; for Current Costs.

Effects of Inflation on Shareholders' Equity.

The effect of inflation on the Company's actual original cost of net utility plant amounted to $223,000,000 for 1982,

($483,000,000 for 1981, $666,000,000 for 1980, and

$743,000,000 for 1979 expressed in average 1982 dollars).

These inflationary effects were not recovered because rates are based on depreciation of original cost plant. If the Company were required to charge these amounts against income in 1982, earnings applicable to common stock would have been reduced to $55,623,000, while in 1981, 1980 and 1979, earnings applicable to common stock would have become losses of$246,173,000, $461,038,000 and $544,372,000, respectively: The effect of inflation (3.9%

for 1982, 8.9% for 1981, 12.4% for 1980 and 13.3% for 1979)

Adjustment of Selected Five Year Financial Information.

In order to reflect the impact of general inflation on selected financial information for each of the years 1978

'. ~;:.

on the value of the Company's debt and preferred stock approximated $149,000,000 for 1982, $326,000,000 for 1981,

$453,000,000 for 1980 and $511.000,000 for 1979 (1981, 1980 and 1979 expressed in average 1982 dollars) and would partially offset the effect of inflation on utility plant.

If the Company had earned at the rate of inflation (3.9%) on its common shareholders' equity in 1982, earnings would have been approximately $82,000,000 compared with reported earnings of $278,623,000. Thus, reported earnings applicable to common stock in 1982 were about $197,000,000 above the level necessary to offset the impact of inflation on shareholders' equity:

through 1982, the following table shows actual data compared with data adjusted to 1982 dollars.

Five Year Summary of Selected Financial Information Showing Adjustments To Reflect Inflation Development of Adjustment Factors Consumer Price Index Average During Year Year End Consumer Price Index Multiplier A = Average (289. l -:- Index)

B = Year End (292.4 + Index)

Actual and Adjusted Financial Information Dividends Per Common Share Actual Paid Adjusted (Actual x A)

Market Price Per Common Share Actual Year End Adjusted (Actual x B)

Operating Revenues (thousands of dollars)

Actual Adjusted (Actual x A)

Common Shareholders' Equity (thousands of dollars)

Actual Year End Adjusted (Actual x B)

Accountants' Report

'Ib the Shareholders and Board of Directors Philadelphia Electric Company 1982 289.l 292.4 1.00 1.00

$2.06

$2.06

$17.00

$17.00

$2,644,753

$2,644,753

$2,254,435

$2;254,435 1981 272.4 281.5 1.06 1.04

$1.90

$2.01

$13.63

$14.18

$2,433,425

$2,579,431

$1,963,527

$2,042,068 1980 246.8 258.4 1.17 1.13

$1.80

$2.11

$12.50

$14.13

$2, 123,394

$2,484,371

$1,733,614

$1,958,984 1979 217.4 229.9 1.33 1.27

$1.80

$2.39

$13.75

$17.46

$1,578,505

$2,099,412

$1,580,004

$2,006,605 1978 195.4 202.9 1.48 1.44

$1.80

$2.66

$15.50

$22.32

$1,456,758

$2, 156,002

$1,475,276

$2, 124,397 We have examined the consolidated balance sheets of Philadelphia Electric Company and Subsidiary Companies as of December 31, 1982 and 1981, and the related consolidated statements of income, retained earnings, and changes in financial position for each of the three years in the period ended December 31, 1982. 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 consolidated financial statements referred to above present fairly the financial position of Philadelphia Electric Company and Subsidiary Companies as of December 31, 1982 and 1981, and the results of their operations and the changes in their financial position for each of the three years in the period ended December 31, 1982, in conformity with generally accepted accounting principles applied on a consistent basis.

1900 Three Girard Plaza Philadelphia, Pennsylvania February 2, 1983

'-'("~. ~*

Financial Statistics Summary of Earnings (Millions of Dollars)

For the Year Ended 1982 1981 1980 1979 1978 1977 1972 Operating Revenues (for details see pages 23 and 32)

$2,644.8

$2,433.4

$2, 123.4

$1,578.5

$1,456.8

$1,394.8

$685.0 Operating Expenses Fuel and Energy Interchange 1,128.5 1, 187.6 1,090.5 661.7 573.9 575.3 212.0 Labor 291.l 256.8 232.l 209.3 195.0 179.2 120.4 Other Materials, Supplies and Services 320.5 260.9 184.5 155.4 135.0 121.4 55.0

'Ibtal Operation and Maintenance 1,740.l 1,705.3 1,507.1 1,026.4 903.9 875.9 387.4 Depreciation 143.8 130.3 122.9 120.6 116.5 107.8 60.5 Tuxes 372.2 274.8 227.4 185.7 194.7 188.9 93.6 Total Operating Expenses 2,256.l 2, 110.4 1,857.4 1,332.7 1,215. l 1, 172.6 541.5 Operating Income 388.7 323.0 266.0 245.8 241.7 222.2 143.5 Other Income Allowance for Other Funds Used During Construction 65.7 65.0 50.5

. 46.0 37.6 36.2 21.4 Income Tux Credits, net 75,8 63.2 49.0 33.9 26.3 25.3 (0.4)

Other, net (0.7) 2.5 3.4 1.7 4.6 3.5 0.2 Total Other Income 140.8 130.7 102.9 81.6 68.5 65.0 21.2 Income Before Interest Charges 529.5 453.7 368.9 327.4 310.2 287.2 164.7 Interest Charges Long-Term Debt 308.9 266.7 225.0 193.0 176.3 161.0 73.4 Short-Term Debt 32.0 33.2 13.9 7.3 2.5 2.6 4.4 Allowance for Borrowed Funds Used During Construction (147.6)

(123.8)

(97.1)

(67.4)

(53.4)

(49.8)

(21.1)

Net Interest Charges 193.3 176.1 141.8 132.9 125.4 113.8 56.7 Net Income 336.2 277.6 227.1 194.5 184.8 173.4 108.0 Preferred Stock Dividends 57.6 53.8 52.2 44.8 43.5 40.7 21.6 Earnings Applicable to Common Stock 278.6 223.8 174.9 149.7 141.3 132.7 86.4 Dividends on Common Stock 240.5 189.5 157.4 145.0 135.7 124.9 67.7 Earnings Retained

$38.l

$34.3

$17.5

$4.7

$5.6

$7.8

$18.7 Earnings Per Average Common Share (Dollars)

$2.39

$2.25

$2.00

$1.86

$1.87

$1.87

$2.08 Dividends per Common Share (Dollan)

$2.06

$1.90

$1.80

$1.80

$1.80

$1.76

$1.64 Common Stock Equity (Per Share)

$17.93

$18.10

$18.72

$19.06

$19.28

$19.26

$20.00 Average Shares of Common Stock Outstanding (Millions) 116.5 99.6 87.3 80.5 75.4 70.8 41.5 See Page 21 for Management's Discussion and Analysis of Financial Condition and Results of Operations.

Ratings on Philadelphia Electric Company's Securities Mortgage Bonds Debentures Preferred Stock Agency Rating Date Established Rating Date Established Rating Date Established Duff and Phelps, Inc.

9 3180 10 3/80 11 2/83 Fitch Investors Service BBB 9/82 BBB-9/82 BB+

9/82 Moody's Investors Service Baa3 1/83 Bal 1183 bal 1183 Standard and Poor's Corporation BBB-9/82 BB+

9/82 BB 9/82

~J.J*71;:\\

?;c;;--*

~),J Summary of Financial Condition December 31 (Millions of Dollars) 1982 1981 1980 1979 1978 1977 1972 Assets Utility Plant, at original cost

$7,905.7

$7,044.7

$6,415.7

$5,885.5

$5,502.5

$5, 121.1

$3,222.6 Less: Accumulated Depreciation 1,450.l 1,330.6 1,235. 7 1,144.l 1,053.3 955.3 624.2 Net Utility Plant 6,455.6 5,714.1 5, 180.0 4,741.4 4,449.2 4, 165.8 2,598.4 Investments 91.4 77.8 58.7 47.4 30.0 27.4 9.5 Current Assets Cash and Temporary Cash Investments 50.0 30.7 6.7 10.6 38.6 30.8 55.8 Accounts Receivable 342.2 342.4 300.3 230.9 223.5 184.0 72.l Inventories 143.0 132.2 121.1 110.0 93.3 102.3

.38.8 Deferred Fuel Expense 11.0 83.5 4.2 23.0 Deferred Income Tuxes 43.4 17.0 Other 7.7 6.8 6.2 4.6 4.3 3.8 2.8 Deferred Debits 24.7 31.5 18.5 12.9 7.5 10.9 7.5 Total

$7,158.0

$6,352.5

$5,702.5

$5,241.3

$4,850.6

$4,548.0

$2,784.9 Capitalization and Liabilities Common Stock

$1,826.2

$1,572.4

$1,377.4

$1,239.6

$1,139.7

$1,106.7

$622.5 Other Paid-In Capital 4.6 3.9 2.6 2.2 2.0 1.8 1.2 Retained Earnings 423.6 387.2 353.6 338.2 333.6 328.7 271.0 Common Shareholders' Equity 2,254.4 1,963.5 1,733.6 1,580.0 1,475.3 1,437.2 894.7 Preferred Stock:

Series Without Mandatory Redemption Requirements 372.5 372.5 372.5 372.5 372.5-372.5 297.5 Series With Mandatory Redemption Requirements 292.3 266.9 274.3 206.8 210.9 161.7 40.0 Long-Term Debt 3,028.5 2,745.7 2,371.9 2,241.9 2, 173.2 2,078.3 1,287.2

'Ibtal Capitalization 5,947.7 5,348.6 4,752.3 4,401.2 4,231.9 4,049.7 2,519.4 Current Liabilities Short-Term Debt 64.7 54.2 52.6 85.2 16.2 14.9 103.8 Current Maturities of Long-Term Debt 21.3 36.l 130.8 127.8 52.9 28.7 13.5 Accounts Payable and Dividends Declared 188.5 188.9 187.6 133.5 120.3 92.4 49.5 Tuxes Accrued and Deferred 66.0 68.4 77.8 65.l 44.5 36.7 18.4 Interest Accrued 99.8 82.3 64.9 58.l 51.0 48.6

18. l Deferred Fuel Credits 85.4 31.3 Other 24.7

18. l 17.4 13.9 7.9 4.1 5.6 Deferred Credits 659.9 524.6 419.l 356.5 325.9 272.9 56.6 Total

$7,158.0

$6,352.5

$5,702.5

$5,241.3

$4,850.6

$4,548.0

$2,784.9

P':1';~_

L --*,, r;:;*-l Operating Statistics

~Jc£~

ELECTRIC OPERATIONS 1982 1981 1980 1979 1978 1977 1972 Output (millions of kilowatthours)

Steam 8,598 9,931 11,234 11,279 13, 160 11,468 20, 181 Nuclear 10,743 7,464 7,333 7, 104 7,769 4,596 97 Hydraulic 1,581 1,397 1,240 2,155 1,700 1,991

. 2,242 Pumped Storage Output 1,126 1, 101 1,050 1,270 1, 109 1,223 1,430 Pumped Storage Input (l,665)

(1,624)

(1,526)

(1,847)

(1,606)

(1, 761)

(2,018)'

Purchase and Net Interchange 11,120 11,173 9,973 9,180 6,651 9,759 3,472 Internal Combustion 178 283 442 454 704 847 946 Other 528 716 1

Total Electric Output 31,681 30,253 29,746 29,595 29,487 28,845 26,351 Sales (millions of kilowatthours)

Residential 7,877 8,014 8,341 7,968 7,875 8,110 6,856 Small Commercial and Industrial 3,142 3, 115 3,065 2,928 2,888 2,825 2,503 Large Commercial and Industrial 14,178 14,916 15,056 15,428 15,302 14,912 14,011 Jersey Central Power & Light (Salem #2) 3,352 1,218 All Other 1,012 1,005 1, 159 1,277 1,329 1,350.

l, 136 Total Electric Sales 29,561 28,268 27,621 27,601 27,394 27, 197 24,506 Number of Customers, December 31 Residential 1,206,944 1,200,238 1, 190,312 l, 173,514 1, 158,853 1, 148, 171 1,090,921 Small Commercial and Industrial 118,407 117,016 116,808 115,724 115,945 115,883 118,522 Large Commercial and Industrial 5,616 5,790 5,820 5,798 5,780 5,772 5,645 All Other 762 746 736 1,919 2,413 2,381 2,163 Total Electric Customers 1,331,729 1,323,790 1,313,676 1,296,955 1,282,991 1,272,207 1,217,251 Operating Revenues (millions of dollars)

Residential

$ 694.4

$ 643.7

$ 607.8

$ 461.0

$ 430.8

$ 427.6

$ 222.7 Small Commercial and Industrial 310.6 285.9 249.8 189.0 176.5 168.4 88.l Large Commercial and Industrial 922.3 917.1 813.9 587.4 544.0 513.4 228.6 Jersey Central Power & Light (Salem #2) 135.4 45.9 All Other 118.3 109.5 95.4 74.5 73.l 68.3 35.0 Total Electric Revenues

$2,181.0

$2,002.1

$1,766.9

$1,311.9

$1,224.4

$i,177.7

$ 574.4 Operating Expenses (millions of dollars)

Operating expenses excluding depreciation

$1,688.4

$1,586.5

$1,414.0

$ 975.4

$ 896.3

$ 881.2

$ 392.3 Depreciation 130.2 117.3 111.1 110.0 106.3 97.9 54.3 Total Operating Expenses

$1,818.6

$1,703.8

$1,525. l

$1,085.4

$1,002.6

$ 979.l

$ 446.6 Electric Operating Income (millions of dollars)

$ 362.4

$ 298.3

$ 241.8

$ 226.5

$ 221.8

$ 198.6

$ 127.8 Net Electric Utility Plant (millions of dollars)

$6,097.4

$5,372.2

$4,867.9

$4,449.5

$4, 167.1

$3,883.9

$2,330.5 Average Use per Residential Customer (kilowatthours)

Without Electric Heating 5,875 6,022 6,411 6,227 6,290 6,584 6,082 With Electric Heating 16,813 18,054 19,482 20,760 21,884 23,593 27,029

'Ibtal 6,544 6,699 7,058 6,829 6,833 7,097 6,317 Electric Peak Load, Demand (thous. kW) 5,691 5,731 6,095 5,641 5,667 5,888 5,313 Net Electric Generating Capacity Year End Summer rating (thous. kW) 8,006 8,006 7,698 7,727 7,727 8, 198 6,348 Cost of Fuel per Million Btu

$1.57

$2.10

$1.90

$1.55

$1.29

$1.40

$0.62 Btu per Net Kilowatthour Generated 10,918 10,930 10,787 10,810 10,773 10,882 10,666

P<::c;e

?~J(?1

-0*-J1 I

~

r

._ _ _J GAS OPERATIONS 1982 1981 1980 1979 1978 1977 1972 Sales (millions of cubic feet)

Residential 2,442 2,446 2,461 2,327 2,316 2,394 2,418 House Heating 24,237 24,675 23,671 23,593 24,974 26,335 26,026 Commercial and Industrial 41,660 45,670 42,890 37,452 32,784 31,017 41,490 All Other 422 127 92 93 94 86 104 Total Gas Sales 68,761 72,918 69,114 63,465 60, 168 59,832 70,038 Number of Customers, December 31 Residential 76,638 78,426 81,346 85,315 87,715 88,775 94,035 House Heating 198,910 193,038 182,246 168,905 163,469 162,978 159,780 Commercial and Industrial 22,324 21,578 20, 197 19,065 19,207 19,422 20,312 Total Gas Customers 297,872 293,042 283,789 273,285 270,391 271,175 274, 127 Operating Revenues (millionS of dollars)

Residential

$ 18.l

$ 15.4

$ 14.0

$ 10.7

$ 9.9

$ 9.6

$ 6.2 House Heating 147.l 128.5 108.5 91.2 86.6 84.l 48.4 Commercial and Industrial 221.l 209.7 166.7 118.4 92.2 80.4 38.2 All Other 1.8 0.5 0.3 0.2 0.2 0.2

0. 1 Subtotal

$388.l

$354. 1

$289.5

$220.5

$188.9

$174.3

$ 92.9 Other Revenues 2.3 2.3 1.2 0.6 0.6 0.5 0.4 Total Gas Revenues

$390.4

$356.4

$290.7

$221.1

$189.5

$174.8

$ 93.3 Operating Expenses (millions of dollars)

Operating expenses excluding depreciation

$354.l

$322.0

$258.0

$194.4

$163.0

$145.7

$ 73.9 Depreciation 11.9 11.3 10.2 8.9 8.6 8.2

5. 1 Total Operating Expenses

$366.0

$333.3

$268.2

$203.3

$171.6

$153.9

$ 79.0

\\ Gas Operating Income (millions of dollars)

$ 24.4

$ 23.l

$ 22.5

$ 17.8

$ 17.9

$ 20.9

$ 14.3 Net Gas Utility Plant (millions of dollars)

$332.4

$314.7

$283.4

$261.7

$250.5

$248. 1

$239.7 STEAM OPERATIONS Sales (millions of pounds) 5,086 5,484 6,044 6,581 7,336 7,165 8,328 Number of Customers, December 31 571 593 618 638 660 670 737 Operating Revenues (millions of dollars)

$ 73.4

$ 74.9

$ 65.8

$ 45.5

$ 42.9

$ 42.3

$ 17.3 Operating Expenses (millions of dollars)

Operating expenses excluding depreciation

$ 69.8

$ 71.6

$ 62.4

$ 42.3

$ 39.3

$ 38.0

$ 14.8 Depreciation 1.7 1.7 1.7 1.7 1.6 1.6 1.1 Total Operating Expenses

$ 71.5

$ 73.3

$ 64.1

$ 44.0

$ 40.9

$ 39.6

$ 15.9 Steam Operating Income (millions of dollars)

$ 1.9 1.6 1.7 1.5

$ 2.0

$ 2.7 1.4 Net Steam Utility Plant (millions of dollars)

$ 25.8

$ 27.2

$ 28.7

$ 30.2

$ 31.6

$ 33.8

$ 28.2

Shareholder Information Stock Exchange Listings.

Most PECo Securities are listed on the New York Stock Exchange and the Philadelphia Stock Exchange. Philadelphia Electric Power Company Deben-tures are listed on the Philadelphia Stock Exchange.

Dividends.

The Company has paid dividends on its common stock continually since 1902. The Board of Direc-tors normally considers common stock dividends for pay-ment in March, June, September and December.

The Company estimates that the $2.06 per share dividend paid to common shareholders in 1982 is fully taxable as dividend income for Federal income tax purposes.

Dividend Reinvestment and Stock Purchase Plan.

All common and preferred shareholders may use their dividends to purchase additional shares of com-mon stock through the Company's Dividend Reinvestment and Stock Purchase Plan. The Company absorbs all fees for purchases under the Plan.

Shareholders have the opportunity to invest additional funds in common stock of the Company; whether or not they have their dividends reinvested-also with all fees borne by the Company.

The Plan has been amended to enable eligi-ble individual participants in the Plan to elect to defer Federal income tax on up to $1,500 of reinvested dividends per year as provided by the Economic Recovery Tux Act of 1981 for a joint return.

More than 28% of the common shareholders are participants. In 1982, they invested more than $60 mil-lion through the Plan, including cash payments. Informa-tion concerning this Plan may be obtained from M. W.

Rimerman, Treasurer, Philadelphia Electric Company; 2301 Market Street, PO. Box 8699, Philadelphia, PA 19101.

Comments Welcomed.

The Company always is pleased to answer questions and provide information. Please address your comments to Mrs. L. S. Binder, Secretary; Philadelphia Electric Company; 2301 Market Street, PO. Box 8699, Philadelphia, PA 19101.

Inquiries relating to shareholder accounting records, stock transfer and change of address should be directed to Philadelphia Electric Company; 2301 Market Street, PO. Box 8699, Philadelphia, PA 19101, Attn: Stock Transfer Section. (215) 841-5795.

Annual Meeting.

The Annual Meeting of the Shareholders of the Company will be held on April 13, 1983, at 10:30 AM at the Franklin Plaza Hotel, 17th & Race Streets, Philadelphia, PA.

Common stock shareholders of record at the close of business on March 4, 1983 are entitled to vote at this meeting.

Notice of the meeting, proxy statement, and proxy will be mailed under separate cover. Prompt return of the proxies will be appreciated.

Form 10-K.

Form 10-K, the annual report filed with the Securities and Exchange Commission, is available without charge to shareholders upon written request to Philadelphia Electric Company; 2301 Market Street, PO. Box 8699, Philadelphia, PA 19101, Attn: Financial Division.

Shareholders.

The Company has 283,438 shareholders of record of common stock, a 21 % increase in 5 years.

Transfer Agents and Registrars.

PHILADELPHIA ELECTRIC COMPANY-Preferred and Common Stocks Registrars:

Girard Bank, One Girard Plaza, Philadelphia, PA 19101 Transfer Agents:

Morgan Guaranty Trust Co. of NY, 30 W. Broadway; NY, NY 10015 Philadelphia Electric Company; 2301 Market St., Phila., PA 19101 Morgan Guaranty Trust Co. of NY, 30 W. Broadway; NY, NY 10015 PHILADELPHIA ELECTRIC COMPANY-First and Refunding Mortgage Bonds Trustee:

The Fidelity Bank, Broad & Walnut Sts.,

Phila., PA 19109 New York Morgan Guaranty Trust Co. of NY, Agent:

23 Wall Street, NY, NY 10015 PHILADELPHIA ELECTRIC COMPANY-Debentures PHILADELPHIA ELECTRIC POWER COMPANY (A Subsidiary)-Debentures Trustee:

The Philadelphia National Bank, Broad & Chestnut Sts., Phila., PA 19101 New York Irving Trust Co., One Wall Street, Agent:

NY, NY 10015 General Office.

2301 Market Street, PO." Box 8699, Phila., PA 19101. (215) 841-4000.

NYSE-Composite Common Stock Prices, Earnings and Dividends by Quarters (Per Share) 1982 1981 Fourth Third Second First Fourth Third Second First Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter High Price

$171/s

$16%

$15%

$141/a

$14Y4

$14%

$13%

$14 Low Price

$151/s

$131/z

$13

$131/s

$12\\12

$12\\14

$11%

$11Ys Earnings 54¢ 73¢ 42¢ 71¢ 53¢ 66¢ 46¢ 61¢ Dividends 53¢ 53¢ 50¢ 50¢ 50¢ 50¢ 45¢ 45¢

NOTICE -

THE ATTACHED FILES ARE OFFICIAL RECORDS OF THE DIVISION OF DOCUMENT CONTROL. THE'/ HAVE BEEN CHARGED TO YOU FOR A LIMITED TIME PERIOD AND MUST BE RETURNED TO THE RECORDS FACILITY BRANCH 016.

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DEADLINE RETURN DATE cPJaf;lOOt/67 La.,;( tf,,_ ~l~~--

RECORDS FACILITY BRANCH

Financial Highlights Revenues Net Income Earnings Per Share Dividends Declared Common Stock Outstanding Average Shares Common Stock Book Value Construction Expenditures Internally Generated Funds Electric Sales Electric Customers (Average)

Average Residential Usage Gas Sales Gas Customers (Average)

Average Residential Usage 1982 1981 Percent Increase (Decrease) 636.7 million million 608.5 million 4.6 73.6 58.7 million 25.4 2.13 1.78 19.7 1.595 1.535 3.9 28,488,623 16.11 110.6 77.1 million million 25,747,441 15.66 84.2 72.3 10.6 2.9 million 31.4 million 6.6 7.25 billion kwh 288,607 7.40 billion kwh (2.0) 280,769 2.8 7,860 kwh 7,967 kwh (1.3) 15.60 million mcf 74,209 16.52 million mcf(5.5) 73,299 1.2 86.5 mcf 89.4 mcf (3.2)

Contents 2

Letter to Stockholders 4

Switching Away from Oil 6 Reducing Costs 8

Increasing Customer Satisfaction 10 Looking Toward the Future 12 Our Service Territory 13 Financial Section 14 Selected Financial Data 15 Financial Review and Analysis 19 Report of Management 20 Quarterly Common Stock Dividend and Price Ranges 21 Reportoflndependent Accountants 22 Consolidated Statements 28 Notes to Consolidated Financial Statements 40 Consolidated Statistics 42 Board of Directors 43 Officers 44 General Information 1

Letter to Stockholders T

his was a good year for both stockholders and customers. Significant achievements were:

~ Earnings increased to $2.13 per share from $1.78 per share, or 19.7%, despite a 2% decline in electric sales and a 5.5% decline in gas sales. This was accomplished through continued tight cost con-trol and rate relief. Dividends were increased to 41 cents per share quarterly-a n indicated annual rate of $1.64.

~ The price of electricity has been less volatile because of the program to switch away from oil as a prime generating fuel and a more stable worldwide fuel market. For most of our residential customers, the price of electricity was less in December, 1982, than it was in the previous January.

Major decisions made in 1982 to keep this momentum going included:

~ The postponement of construc-tion of the Vienna 9 generating station for five years (until 1995) as part of a thorough review of the demand for electricity on the Delmarva Peninsula. This means stockholders will not need to support a substantial construction program until at least the late 1980s.

~ The consolidation of five district offices and seven storerooms to streamline operations and reduce future costs.

2

~ The beginning of additional, innovative programs designed to increase productivity.

~ The re-opening of gas service to new industrial customers as well as residential customers.

We believe these results and action plans demonstrate that your company is financially strong and positioned well for the 1980's.

Financial rating agencies agree.

Three such companies, Standard

& Poors Corp., Moody's Investors Service, Inc., and Duff and Phelps, Inc., upgraded Delmarva Power's credit rating on first mortgage bonds.

In the equivalent language of each of these companies, Delmarva's rating climbed from A to AA minus. The company's common stock price also increased 29.7%

in 1982.

These achievements result pri-marily from a strategic plan devel-oped several years ago to make electric rates more competitive regionally and, at the same time, to improve the return on your investment.

Key components of the plan were to reduce fuel costs and operate plants more efficiently; to minimize new capital investment and utilize existing assets more fully; and to reduce operating and maintenance costs and increase employee effectiveness.

Progress was made in each of these areas in 1982. That progress is highlighted here and detailed in the body of this report.

Raw material-fuel-represents 38% of our costs. In October, the conversion of the Edge Moor 4 generating unit from oil to coal was completed. Fuel savings from the conversion enabled the price of electricity to be reduced for customers throughout the service territory.

Capital costs represent 35% of total expenses. The most significant decision made in 1982 to minimize capital costs was to delay until 1995 the next major generating plant

-the 500 megawatt, coal-fired Vienna 9 unit. Virtually all capital spending on the project has ceased.

This decision is based on present forecasts. If they should change, there is ample time to accelerate the timetable if needed. Reduced sales forecasts also mean that ad-ditions to and upgrading of the transmission and distribution system can be deferred.

Finally, operating, maintenance, and other expenses represent 27%

of total costs.

Since the company had been pre-pared for a higher rate of growth than now forecast, management decided to reduce the workforce by

165 positions by March 31, 1983.

Current plans are to meet that goal through attrition and an early re-tirement program.

Other important areas for cost-savings indude improvement in productivity and continued utilization of the latest technology available. In 1982, a program was introduced to help managers in-crease the involvement of employees in the decisions affecting their jobs. We have also strengthened the commitment to safety and the reduction of job-related accidents.

Additional effort was made to use the results of industry research.

Left: Nevius M.

Curtis, president and chief executive officer; right:

Robert D. Weimer, chairman of the board.

We are pleased that this strategic plan is helping our customers in the form of stabilized rates and our stockholders in the form of increased earnings. This mutual benefit is essential to our success in an industry where sources of income are changing.

For several decades, growth was obtained through technology advancements and increased sales.

However, the shock of the Arab oil embargo and subsequent steep price increases for energy brought about the need for new business strategies. Customers found ways to use less energy. These included choosing kerosene and wood for heating. Thus, large growth rates are no longer projected. Price and consumer attitudes, while always important, have become more dom-inant in decision making. In this atmosphere, tighter cost control, utilization of the latest technology and increased productivity are critical.

While several programs respon-sive to customer needs have been developed, we think the key to customer satisfaction will be to keep increases in the price of electricity and natural gas as small as possible.

That's why our strategic plan is so important.

With the near completion of our program to switch away from oil, the absence of a major construction program, excellent generation and transmission facilities in place, and a highly competent and dedicated employee team, we are in position to achieve this goal.

Success depends on the contin-ued hard work of the 2,697 people who make up the Delmarva Power team. We thank them for the prog-ress made so far and the progress we expect in the future for you and our customers.

Robert D. Weimer Chairman of the Board

~C,t:*

Nevius M. Curtis President and Chief Executive Officer February 4, 1983 3

Switching Away from Oil D

elmarva Power's pro-gram to reduce fuel costs worked its way to the customers' pocketbook during 1982. The price of electricity was less in December than it was the previous January for many resi-dential customers, mainly because of lower fuel costs.

The company has been working on a strategy to switch away from oil wherever possible.

In 1980, the 400-megawatt, coal-fired Indian River 4 plant was com-pleted and in 1981, the Salem 2 nuclear power plant became operational.

The key events of 1982 were the completion of the conversion of the 167-megawatt Edge Moor 4 generat-ing unit from oil to coal and the first full year's operation of the Salem 2 nuclear power plant (Delmarva Power owns 82 megawatts).

This program will be completed in early 1983 when the conversion of the 82-megawatt Edge Moor 3 is finished. In 1984, the company will have reduced its dependence on foreign oil to 11 % from 53% in 1979.

Oil consumption will have been reduced from 8 million barrels an-nually to 2 million barrels annually.

4

Joseph H. Merkel Senior Fuel Equip-ment Operator, Edge Moor Power Station "I know this job.

This is where my heart is," says Joe Merkel who moves coal from the train to the boiler. Del-marva Power has nearly completed its program to switch away from foreign oil.Joe worked at his job for 11 years until 1971 when the m-iginal Edge Moor coal plants were converted to oil which then was cleaner and cheaper.

He moved inside, but when some of the units were converted back to coal, he volun-teered to go back into the yard. "It's the job I like."

Since coal and nuclear fuel are substantially less expensive than oil, savings in fuel costs can be passed on to the customer. When each new plant became operational or when each conversion was com-pleted, the company lowered the price of electricity for the customer and earned a return on the invest-ment for the shareholder. The company expects this to occur again when Edge Moor 3 is converted.

While investors are still not earn-ing the full amount authorized by regulators, the near completion of the construction program puts the company in position to make prog-ress on achieving that full return.

In addition to changing the fuel mix, the company has been able to import coal-fired electricity from the Midwest where the recession in the auto and steel industries has reduced industrial demand.

Also, the company sold some of its oil-fired generation to the PJM power pool.

In 1982, Delmarva Power saved about $25 million for customers by purchasing power from the Mid-west and through its association inPJM.

5

Reducing Costs G

rowth characteristics of the Delmarva peninsula are changing. Company managers see more new activity in the commercial sector during the mid 1980s than in the industrial sector. This growth is not expected to be as energy intensive.

The company had been prepared to serve an anticipated demand which is not materializing. In 1982, the company was approaching a decision point when capital expen-ditures would rapidly escalate in order to build Vienna 9 by 1990.

Thus, a thorough review of the Vienna 9 project and growth projections was undertaken.

Here are the conclusions:

Flat sales growth of the last four years has demonstrated that the previous projections of sales were not being achieved. There was no new record set in 1982 for single-hour electrical use. The recession was worse and more prolonged than expected. Other forces which could not be anticipated were cutting into a key area which had provided growth in the past-the industrial sector. For example, a petrochemical plant was destroyed by fire and was not replaced.

The prognosis is that flat to low sales growth in this sector is likely to be a way of life as long as the economy remains sluggish.

6 While industrial growth is slow, there is considerable activity in the commercial sector-new office buildings in Wilmington to house banks moving to Delaware; a new hospital in Stanton, Delaware; large insurance office buildings in the Wilmington suburbs; and condo-minium development in Ocean City, Maryland.

Delmarva Power managers see emphasis towards such commercial development in the peninsula's short-term economic future. How-ever, they also see a lower overall rate of growth in energy demand

( 1.6%) than previously projected.

In view of the reduced forecast and significant amount of gener-ation capacity now available, the company decided to postpone-from 1990 until 1995-the com-mercial operating date of Vienna 9 and to stop all current capital invest-ment on the project.

Another significant result of this growth analysis was a review of the company's commitment to load man-agement-shifting the demand for electricity away from peak periods.

The company committed itself to finding ways to move to off-peak hours, 100 megawatts of power which otherwise would have been demanded at peak times in the early 1990s. Instituting a load man-agement program in the late 1980s,

Christopher A. Smith Power Engineer, Marketing, Southern Division General Office "Sal.es growth is being abl.e to introduce a busi-nessman to new ways he can use el.ectricity," says Chris Smith, power engineer.

Studies compl.eted in 1982 show that substantial growth is not expected in the energy-intensive industrial sector as wngasthe economy remains sluggish. Sales growth is expected to come through the commercial sector. And, it can come through the efforts of Smith and others to show businessmen how electricity can increase their profits.

when the technology is more full y developed, will be a cost-effective method of postponing generating capacity needs.

Since the company was staffed for larger growth and sales than are now anticipated, the company's management decided to reduce the workforce to meet current work needs. The goal is to reduce employment by 165 positions by March 31, 1983, through attrition and an early retirement program.

In another cost-cutting move, the company announced plans to consolidate five district offices, two line crews, and seven storerooms.

To avoid misunderstanding, several points must be stressed:

~ These actions do not imply financial weakness. The company is financially strong. With the near completion of the program to switch away from oil and the delay in con-struction of Vienna 9, the resulting reduced construction program will increase financial strength.

~ These actions will not affect the reliability of service. There is now a substantial reserve of generation capacity. The company will be flex-ible to accelerate the construction of capacity should demand increase.

~ These actions will not affect the quality of service to customers.

7

Increasing Customer Satisfaction H

el ping customers use energy wisely and solve energy problems are major, on-going efforts. The com-pany continued successful programs in 1982 and began several new ones.

The following are examples.

There are many programs designed to help customers who can't pay their bills because of unusual circumstances. Customer information specialists work with human service agencies to discover who in the community needs assis-tance. Delmarva Power customer service representatives can help by arranging installment payments of previous bills, setting up budget billing, alerting a friend if service is about to be disconnected, and keeping power on where life sup-port systems or medical emergencies exist. Special efforts are made to inform senior citizens of these programs.

Operators of Delmarva's radio-equipped vehicles are helping to solve a community problem-crime in neighborhoods.

They participate in Radio Watch, a program developed to help increase police effectiveness. Employees driving company radio-equipped vehicles report suspicious events, crimes in progress, or other emer-gency conditions. These vehicles are marked with decals easily visible to the people in the community who may ask company employees to relay emergency messages.

8

Deborah]. Lanier Customer Informa-tion Specialist, Wilmington Offu:e "Listening. First and foremost, that is the most impor-tant thing I can do," says Debbie Lanier, customer information spe-cialist. Debbie is one of many employees who concentrate on matching Delmarva Power's numerous customer service programs and pol-icies to the needs of a diverse range of customers includ-ing homeowners, businessmen, farm-ers, senior citizens, and summer resi-dents. "I look at my job as a liaison between my cus-tomers and my company. I enjoy that."

Also, the company installed special electronic equipment to communicate with customers with speech or hearing impairments.

The company has several pro-grams designed to help customers make wise energy choices.

The Super E+ program was developed to encourage the con-struction and purchase of homes designed to use energy efficiently.

These homes offer energy cost savings without substantially increas-ing construction costs. More than 64 builders on the peninsula are participating in this program.

In order to help customers make their homes more energy efficient, Delmarva Power has conducted more than 9,300 comprehensive home energy audits throughout the Delmarva Peninsula since the pro-gram began in 1981. The most common, cost-effective recommen-dations include wrapping water heaters with insulation and install-ing insulation in the attic and under the first floor of a home. Follow-up surveys show that more than 90%

of customers are pleased with the audit. The Department of Energy says the response rate for Delmarva Power's service is one of the highest in the country.

9

Looking Toward the Future F

inding ways to improve power production technology is crucial for providing energy in the future.

During 1982, Delmarva Power invested $1.2 million in the utility industry research pool, the Electric Power Research Institute (EPRI).

Forty-four percent of the company's funds went for genera-tion research to improve existing fossil-fired and nuclear generation systems. The company is following closely EPRI projects to mix coal and other fossil fuels with limestone to allow their combustion in environmentally acceptable ways.

The company is also interested in research in load management and computerized transmis-sion design.

The company also sponsors local research on the Delmarva Pen-insula such as the study of off-peak electric heating of chicken houses.

Looking ahead in another area, the company is expanding its safety program. This effort grew out of a concern for the well-being of the families of employees as well as the employees themselves.

An aggressive program was begun in 1982 not only to provide the tools to do the job safely and to increase the awareness of potential 10 hazards, but also to improve the attitude toward safety both on and off the job.

Another important effort for the future is to encourage employees to become more involved in deci-sions affecting their jobs.

Employees have many good ideas. For example, one employee recently suggested a new way to compute more accurately the bills of about 500 large customers. T he idea saves the company about

$50,000 annually.

In 1982, the company's man-agement renewed its commitment to get such ideas out from behind the workbench and desk. The long-term goal is to intensify an envi-ronment at Delmarva Power where the ideas of the individual are respected, where j udgement is exercised, and where decisions can be made as close to the local situation as feasible.

A key part of this training is the teaching of how to set effective and easily understood measurements of job performance so accou ntability goes hand-in-hand with passing decisions downward.

Special efforts are being made to include more peo-ple in decisions affecting their jobs.

Heather Dougherty, daughter of Philip L. Dougherty, Ekctric Utility Serviceman, Northern Division General Office "My dad (Phil, kjt) makes sure peopk have ekctricity and natural gas.

That's important.

But what's more important to me is that he comes home each night to talk and help me with my school work;'

says Heather Dougherty. The company has al-ways had a strong on-the-job safety program. This year, special ef forts were made to increase aware-ness of safety at home as well as at work. The com-pany is concerned about the families of all its empwyees as well as the em-pwyees themselves.

Delmarva Power also encourages the installation of heat pumps throughout the service territory.

Heat pumps provide the company with increased kilowatt hour sales during off-peak hours. This leads to increased sales without building new power plants-another bene-fit both to the custo mer and the stockholder.

Another mutual benefit is the re-opening of the natural gas busi-ness for commercial and industrial customers and customers who require extension of gas mains.

Finall y, Delmarva employees are leaders in the community through service, educational, and non-profit organizations. Employees contrib-ute their time and energy to help organizations such as the United Way, Junior Achievement, Leader-ship Delaware, and the Boy Scouts of America grow and prosper.

With the utilization of the latest technology available, the beginning of innovative programs designed to increase productivity, and con-tinued tight cost control, the com-pany expects to produce benefits for both customers and stockholders.*

11

Our Service Territory P

roduction and distribu-tion of safe, reliable, and economical energy for the people, businesses, and industries of the Delmarva Penin-sula is Delmarva Power's business.

To service a diverse area, Delmarva maintains an electric system with 2,365 megawatts of generation capacity, 1,338 miles of transmission lines, 10,830 miles of distribution lines and a natural gas system with 1,022 miles of gas main.

Delmarva Power owns and operates four major fossil fuel power plants within the service territory and shares ownership of two coal plants and two nuclear plants outside the service territory.

Our 292,000 electric customers and 75,000 natural gas customers are served by 2,697 employees working in 25 customer service locations on the peninsula, division headquarters in Christiana, Dela-ware, and Salisbury, Maryland, and corporate headquarters in Wilmington, Delaware.

12 The Delmarva Peninsula stands out as one of the most distinctive geographical features on the East Coast.

Centrally wcated within the major East Coast mar-kets and.financial centers from New York to Richmond, the Peninsula has a uni,que b/,end of industrial, agricultural, commercial, and recreational ac-tivities. Living and working here is a pleasure.

Pennsylvania j ~ Maryland

/ -

. 7 Baltimore W~hin~~ ~

~

-~

R ichmond

-;r" Virginia I

Delmarva Power & Light Company Selected Financial Data (Dollars in Thousands)

For the Years Ended December 31 1982 1981 1980 1979 1978 Operating Operating Revenues $ 636,666

$ 608,504

$ 520,470

$ 424,699

$ 378,702 Operating Income 116,573 107,325 80,716 74,859 71,563 Net Income 73,571 58,711 48,957 53,376 47,448 Earnings and Dividends Earnings Per Share 2.13 1.78 1.60 1.91 1.85 Dividends Declared on Common Stock 1.591/z 1.531/z 1.49 1.40V2 1.301/z Average Shares Outstanding (000) 28,489 25,747 24,682 23,215 21,582 Total Assets 1,471,457 1,445,694 1,380,922 1,249,606 1,120,305 Construction Expendituresrn 110,646 84,206 110,739 112,061 130,272 Internal Generation of Funds 77,061 72,346 37,866 53,435 41,900 Capitalization Long Term Debt<2>

592,615 596,219 569,724 536,779 478,955 Preferred Stock without mandatory redemption 105,000 105,000 105,000 105,000 105,000 Preferred Stock with mandatory redemption 50,000 50,000 50,000 20,000 20,000 Common Equity 468,073 437,080 395,546 385,616 343,257 Total

$ 1,215,688

$ 1,188,299

$ 1, 120,270

$ 1,047,395

$ 947,212 Capitalization Ratios Long Term Debt 49%

50%

51%

51%

51%

Preferred Stock without mandatory redemption 9%

9%

9%

10%

11%

Preferred Stock with mandatory redemption 4%

4%

5%

2%

2%

Common Equity 38%

37%

35%

37%

36%

Tutal 100%

100%

100%

100%

100%

Electric/Gas Sales Electric Sales (Kwh 000) 7,249,442 7,395,324 7,460,380 7,491,800 7,248,249 Gas Sales (Mcf 000) 15,604 16,520 15,693 13,962 13, 172 rnExcludes Allowance for Funds Used Duling Construction.

c2>Includes long-term debt due within one year.

14

Delmarva Power & Light Company Financial Review and Analysis Results of Operations Earnings and Dividends Declared (cents) 250 -------

7B 79 BO Bl B2

• Dividends Earnings Earnings Earnings per share of common stock were $2.13 in 1982 compared with $1.78 in 1981 and $1.60 in 1980. This improvement in financial performance is also reflected in an improved return on average common equity to 13.3% in 1982 from 11.2% in 1981 and 10.0% in 1980. However, it is still below the rate of return authorized by the company's regulatory authorities. In addition, the quality of the company's earnings continues to improve because of higher internally generated funds and a modest construction program. AFUDC, a non-cash earnings item which is affected by the level of construction expenditures, has decreased to 8% of net income in 1982 when compared to 12% in 1981 and 38% in 1980.

The increase in 1982 earnings, despite a decline in sales, can be attributed primarily to (1) timely and significant rate relief, (2) continuing tight cost controls and (3) lower financing costs and debt levels. With substantially reduced capital requirements in the future, the company believes it will be able to maintain this improved financial position.

Dividends In December, the quarterly dividend on common stock was increased to 41¢ per share from 391/z¢ per share. This increase reflects a dividend policy which is designed to gradually increase dividends on an annual basis, earnings permitting and thus provide stockholders with a fair and competitive return on their investment. The current indicated annual dividend rate is $1.64 per share.

Electric Sales and Revenue Electric revenues, net of fuel costs, increased by $51.3 million in 1982 and by $71.7 million in 1981. The principal factor affecting these net revenue increases was rate relief in all jurisdictions. See the accompanying text, "Rate Matters" and the chart "Status ofRate Cases for additional information concerning rate case filings. kWh sales decreased slightly in 1982 and 1981 by 2.0% and 0.9%, respectively, due to a recessionary economy, customer conservation and price elasticity. In 1982, lower industrial sales of 8.1 % have been the direct result of reduced industrial activity throughout the company's service area, whereas residential and commercial sales have increased 1.5% and 4.2%, respectively, due primarily to customer growth. Future electric sales will continue to be affected by the overall economic situation and level of business activity in the company's service territory, as well as by weather conditions, use of alternative fuels for heating and cus-tomer conservation efforts. Electric sales have been forecasted to increase approximately 2.0% annually through 1987.

Gas Sales Gas sales decreased 5.5% in 1982 compared to a 5.3% increase in 1981. The decline in 1982 sales was due to a substantial decrease in usage by industrial customers and warmer winter weather which reduced gas sales for heating. The increase in 1981 sales reflected greater usage by industrial customers due to the improved availability of gas. Future gas sales will be affected by the availability of gas, the deregulation of gas prices and the price of alternative fuels for which gas is a substitute.

15

Delmarva Power & Light Company Financial Review and Analysis 16 Generation Fuel Mix (percent) 79 81 82 83 84

• Coal Nuclear OOil Rate Matters The company is subject to regulation with respect to its retail sales of electricity by the Delaware and Maryland Public Service Commissions, and the Virginia State Corporation Commission, which have broad powers over rate matters, accounting and terms of service. The Federal Energy Regulatory Commission (FERC) exercises jurisdiction with respect to the company's accounting systems and policies and the transmission and sale at wholesale (resale) of electric energy in interstate commerce.

The company has been filing rate increase applications on an annual basis in an effort to have rates set that more closely reflect current costs. Rate cases were filed in all jurisdictions in 1982 and were structured to recover the capital and operating costs for the conversion to coal of Edge Moor units 3 and 4, to recover increases in operating and maintenance costs, and to improve the return on utility investment. A summary of the status of these filings is found in the table below.

Status of the 1982 Rate Cases (Dollars in Thousands)

Requested Jurisdiction Virginia Maryland Delaware FERC Amount

$ 2, 139 16,168 42,797 6,242

• Case still pending. Interim rates placed into effect on 2/8/83.

• • Effective 11/1/82, subject to refund.

Fuel Mix Date 4/15/82 5114182 71 9/82 8/31/82 Granted Amount Date 863 9/12/82 5,620 12/15/82 24,628*

To further reduce its dependency on oil, the company converted from oil to coal unit 4 at the Edge Moor plant in October, 1982. Unit 3 is scheduled to be converted by April, 1983.

With the conversion of these two units, the company's portion of total generation provided from oil-fired plants is expected to be reduced from 53% in 1979 to 11 % in 1984. For years 1982 and 1981 the percentage of oil-fired generation was 27% and 35%, respectively. The predominant fuel sources are now coal and uranium. As a result of the changing fuel mix, the effective customer fuel costs, including net interchange credits, have declined from 2.80 C/kwh in 1980 to 2.32 C/kwh in 1982.

Operating Expenses Other operation, maintenance and depreciation expenses have increased since 1980 primarily as a result of higher payroll and related costs, general inflation and increased production expenses associated with the commercial operation of Indian River coal unit 4 and Salem nuclear unit 2, which were placed in service in October 1980 and September

• 1981, respectively. Taxes on income increased because of increased taxable income and an increase in the effective tax rate. Interest charges decreased in 1982 primarily due to lower interest rates and reduced debt levels.

Delmarva Power & Light Company Financial Review and Analysis Impact of Inflation Liquidity and Capital Resources Ratio of Earnings to Fixed Interest Charges (SEC method) 4.0 -------

78 79 80 81 82 Inflation continues to have an adverse impact on the company because rates are gen-erally set on a historical basis. The company is addressing inflation in the ratemaking process by utilizing a forecast test year' ' and attrition allowances in its rate filings, where permitted, so that rates will reflect costs anticipated for the period that they are in effect. For a further discussion of the effects of inflation on the company, see Note 12 of the Financial Statements.

Financing and Capitalization The company is committed to improving its financial strength and financing flexibility and believes that it is important to have a strong capital structure and manageable levels of debt. At December 31, 1982, the company's capitalization goals were 48-50% long-term debt, 10-12% preferred stock and 38-40% common equity. These goals have been attained by increasing common equity and by reducing the relative proportions of debt and pre-ferred stock. See "Selected Financial Data" for the actual capitalization ratios.

Credit ratings on the company's first mortgage bonds were upgraded by Duff and Phelps, Moody's Investors Service and Standard & Poor's. The rating was raised from A to AA minus by Standard & Poor's, as well as the equivalent upgrading by both Moody's and Duff and Phelps. The upgradings are primarily due to the company's improved return on equity, substantially increased internal generation of funds, increased equity capitalization and reduced future external financing requirements.

The Ratio of Earnings to Fixed Interest Charges, which is influenced by the extent and stability of pre-tax earnings as related to fixed interest charges, showed significant improvement in the last two years and is expected to continue to rise, although more moderately. This ratio, as computed on the SEC method, for 1982 was 3.5 as compared to

2. 7 in 1981 and 2.2 in 1980. Improved interest coverage ratios are another indicator of the company's improved credit position.

The financing program for 1982 consisted of $15.7 million raised by issuance of shares of common stock in accordance with the company's Dividend Reinvestment and Common Share Purchase Plan and through the TRASOP. Also, in November, the Delaware Eco-nomic Development Authority sold $11 million of short-term tax-exempt revenue notes pursuant to an existing agreement with the company at an average annual rate of 4 % %.

These tax-exempt notes, together with a previous issue of $12 million in short-term tax-exempt notes and a $10 million tax-exempt note due August, 1984, will ultimately be refinanced on a more permanent basis.

With a reduced construction program (see Capital and Construction Requirements' '

below) and assuming reasonable rate treatment, the company does not expect any further external long-term financings before 1987 except for the aforementioned refinancing and through issuance of common stock under the Dividend Reinvestment Plan and PAYSOP.

17

Delmarva Power & Light Company Financial Review and Analysis Construction Expenditures and Internally Generated Funds (millions of dollars) 125 -------

100 75 50 25 0

18

-~ >-

1:

f;

~ -

81 82 83 84 85

• Construction Expenditures (excluding AFUDC)

• Internally Generated Funds Capital and Construction Requirements For the period 1980-1982, the company had total capital requirements of $370.9 million, including $305.6 million for construction (excluding AFUDC). During the same period

$187.3 million was generated internally which represents 50% of the capital requirements and 61 % of the construction requirements. Capital requirements for the period 1983-1985 are estimated to be $266.5 million, including $222.3 million for construction (excluding AFUDC). Assuming timely and adequate rate relief and continued improvements in the level and quality of earnings, the company presently anticipates that, for the period 1983-1985, internally generated funds will be $332.4 million which equals 125% of the total capital requirements and 150% of its construction requirements.

The company has delayed the construction schedule for the 500-megawatt, coal-fired Vienna 9 generating unit by five years to 1995. The decision is based on the company's current load forecast, which indicates a lower rate of growth in the coming decade. The deferral also reflects a program of load management to be instituted in the late 1980's when it may be cost-effective for Delmarva and the technology may be more fully developed. As a result of these actions, the company's construction budget will be reduced through at least 1986.

The construction program and related expenditures may vary from the estimates set forth above as a result of, among other factors, higher than anticipated inflation, regulation and legislation, rates of load growth, licensing and construction delays, results of rate proceed-ings, as well as the cost and availability of capital.

Working Capital Working capital increased by $13.2 million in 1982, decreased by $48.6 million in 1981 and increased by $5.3 million in 1980. See page 23, Statement of Sources of Funds for Construction Expenditures for the components of and the changes in working capital. The company issues commercial paper supported by adequate bank lines of credit to meet seasonal fluctuations in working capital requirements as well as the interim financing necessary for construction projects. Additional cash requirements will result from the payment of the Summit state tax liability (see Notes 2 and 7 of Financial Statements) and the future repayment of the over-recovered deferred fuel costs.

Delmarva Power & Light Company Report of Management on the Financial Statements Report of Management The consolidated financial statements of Delmarva Power & Light Company have been prepared by Company personnel in conformity with generally accepted accounting principles, based upon currently available facts and circumstances and management's best estimates and judgements of the expected effects of events and transactions. It is the responsibility of management to assure the integrity and objectivity of such financial statements and to assure that these statements fairly report the financial position of the Company and the results of its operations.

Delmarva Power & Light Company maintains a system of internal controls designed to provide reasonable, but not absolute, assurance of the reliability of the financial records and the protection of assets. The internal control system is supported by written administrative policies, a program of internal audits, and procedures to assure the selection and training of qualified personnel.

These financial statements have been examined by Coopers & Lybrand, independent certified public accountants. Their examination was conducted in accordance with generally accepted auditing standards which include a review of internal accounting controls to determine the nature, timing and extent of auditing procedures, as well as such other procedures they deem necessary to produce reasonable assurance as to the fairness of the Company's financial statements and to enable them to express an opinion thereon.

The audit committee of the Board of Directors, composed of outside Directors only, meets with management, internal auditors and the independent accountants to review accounting, auditing and financial reporting matters. The independent accountants are appointed by the Board on recommendation of the audit committee, subject to shareholder approval.

~C~*

Nevius M. Curtis President and Chief Executive Officer 1iwJt?.~

Howard E. Cosgrove Vice President and Chief Financial Officer 19

Delmarva Power & Light Company Quarterly Common Stock Dividends and Price Ranges Common Stock The company's common stock is listed on the New York and Philadelphia Stock Exchanges and has unlisted trading privileges on the Cincinnati, Midwest and Pacific Stock Exchanges.

The company had 67,059 holders of common stock as of December 31, 1982.

The company's Certificate of Incorporation and the Mortgage and Deed of Trust securing the company's outstanding bonds contain restrictions on the payment of dividends on common stock which would become applicable if its capital and retained earnings fall below certain specified levels or if preferred stock dividends become in arrears.

The retained earnings available for dividends on common stock as of December 31, 1982 were approximately $75,300,000 under the most restrictive of these provisions.

1982 1981 Dividend Price Price Dividend Price Price Declared High Low Declared High Low First Quarter

$.395 14%

111/z

$.38 12%

11Ys Second Quarter

.395 15 131/z

.38 125/s 101/z Third Quarter

.395 151/a 13%

.38 123/a 11 Fourth Quarter

.41 161/z 13%

.395 12%

111/a Withholding Tax on Dividends The Tax Equity and Fiscal Responsibility Act of 1982 requires the company to withhold taxes at the rate of 10% from each dividend payment on or after July 1, 1983. However, certain exemptions are allowed, provided that the shareholder requests and qualifies for such exemption. Exemptions will be allowed for individuals who paid no more than $600

($1,000 on a joint return) of Federal income tax for the prior year. Individuals 65 or older who paid no more than $1,500 ($2,500 on a joint return) of Federal income tax for the prior year also would be exempt. Certain other recipients of dividends, including corporations, governments, certain securities dealers, money market funds, tax-exempt organizations and certain nominees or custodians will also qualify for exemption.

20 Dividends reinvested in a qualified dividend reinvestment plan, such as Delmarva Power's Dividend Reinvestment and Common Share Purchase Plan, are automatically exempt from withholding.

It will not be necessary for you to call the company to request an exemption form. Exemp-tion certificates and instructions will be sent to all stockholders on or about April 25, 1983.

Delmarva Power & Light Company Report of Independent Certified Public Accountants Tu the Board of Directors and Stockholders Delmarva Power and Light Company Wilmington, Delaware We have examined the consolidated balance sheets and statements of capitalization of Delmarva Power & Light Company and subsidiary companies as of December 31, 1982 and 1981, and the related consolidated statements of income, changes in common stockholders' equity and sources of funds for construction expenditures for each of the three years in the period ended December 31, 1982. 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 consolidated financial position of Delmarva Power & Light Company and subsidiary companies at December 31, 1982 and 1981, and the consolidated results of their operations and sources of funds for construction expenditures for each of the three years in the period ended December 31, 1982, in conformity with generally accepted accounting principles applied on a consistent basis.

COOPERS & LYBRAND 1900 Three Girard Plaza Philadelphia, Pennsylvania February 4, 1983 21

Delmarva Power & Light Company Consolidated Statements of Income (Dollars in Thousands)

For the Years Ended December 31 1982 1981 1980 Operating Revenues Electric

$ 534,770

$ 504,119

$ 443,927 Gas 84,747 83,070 59,040 Steam 17, 149 21,315 17,503 636,666 608,504 520.470 Operating Expenses Operation:

Fuel for electric generation 239,965 284,646 236, 139 Net interchange and purchased power (79,678)

(97,950)

(24,178)

Purchased gas 58,690 56,662 42,252 Deferral of energy costs 20,837 18,679

( 3.173)

Other operation 100,956 89,172 79,569 Maintenance 43,947 37,316 33,986 Depreciation 49,929 46,833 37,955 Taxes on income 58,500 39,903 14.483 Taxes other than income 26,947 25,918 22,721 520,093 501, l 79 439,754 Operating Income 116,573 107,325 80,716 Other Income Allowance for other funds used during construction 4,548 4,090 12,540 Other, net 2,015 1,250 569 6,563 5,340 13, 109 Income Before Interest Charges 123, 136 112,665 93,825 Interest Charges Long-term debt 48,895 51,622 46,997 Short-term debt and other 2,181 5,355 3,862 Allowance for borrowed funds used during construction

( 1,511)

( 3,023)

( 5,991) 49,565 53,954 44,868 Earnings Net Income 73,571 58,711 48,957 Dividends on Preferred Stock 12,818 12,818 9.427 Earnings Applicable to Common Stock

$ 60,753

$ 45,893

$ 39,530 Common Stock Average shares outstanding (thousands) 28,489 25,747 24,682 Earnings per average share 2.13 1.78 1.60 Di_vidends declared per share 1.591/z $

1.531/z $

1.49 See accompanying Notes to Consolidated Financial StatemP.nts.

22

Delmarva Power & Light Company Consolidated Statements of Sources of Funds for Construction Expenditures Sources of Funds Construction Expenditures Decrease (increase) in working capital*

(Dollars in Thousands)

For the years ended December 31 Provided from operations:

Net income Less-Preferred dividends declared

-Common dividends declared Earnings reinvested during the year Items not requiring (providing) funds:

Depreciation Amortization of nuclear fuel Allowance for funds used during construction Investment tax credit adjustments, net Deferred income taxes, net Funds provided from operations External financing:

Long-term debt:

First mortgage bonds Term loan Common stock Preferred stock Change in short-term debt Redemption of long-term debt Externally financed funds Other sources (uses):

Decrease (increase) in working capital*

Net decrease (increase) in pollution control funds held by trustee Credit arising from sale of contracts Other, net Other (uses)

(excluding allowance for funds used during construction)

Accounts receivable Deferred fuel costs, net Inventories Accounts payable Tuxes accrued Interest accrued Other, net Total 1982 1981 1980

$ 73,571

$ 58,711

$ 48,957 12,818 12,818 9,427 45,471 39,857 36,805 15,282 6,036 2,725 49,929 46,833 37,955 6,192 3,187 1,549

( 6,059)

( 7,113)

(18,531) 5,718 17,198 1,795 5,999 6,205 12,373 77,061 72,346 37,866 50,000 45,000

( 3,550)

(23,450) 15,711 35,521 7,730 30,000 (28,475) 11,525 (12,000) 12,161 33,596 82,255 (13, 172) 48,604

( 5,266) 32,507 (35,422)

( 3,463)

(

970)

(36,088) 99 3,059 1,170 752) 21,424 (21,736)

( 9,382)

$ 110,646

$ 84,206

$ 110,739 679 (15,064)

$ ( 9,064) 21,374 18,781

( 3,173)

( 9,516) 11,482 (20,603)

( 3,607)

( 7,896) 19,634 (21,877) 34,386 5,347

( 9,265) 15,082 3,322 9,040

( 8,167)

(

729)

$ (13, 172)

$ 48,604

$ ( 5,266)

• Other than short-term debt, long-term debt due within one year and current deferred income taxes relating to deferred fuel costs.

See accompanying Notes to Consolidated Financial Statements.

23

Delmarva Power & Light Company Consolidated Balance Sheets (Dollars in Thousands)

ASSETS As of December 31 1982 1981 Utility Plant-Electric

$ 1,459,713

$ 1,364, 113 at original cost Gas 69,083 66,031 Steam 24,023 24,008 Common 59,522 46,194 1,612,341 1,500,346 Less: Accumulated depreciation 405,830 362,270 Net utility plant in service 1,206,511 1, 138,076 Construction work in progress 59,054 64,915 Nuclear fuel, at amortized cost 13,272 15,252 1,278,837 1,218,243 Nonutility Property and Net nonutility property-at cost 3,281 3,324 Other Investments Pollution control funds held by trustee 9,604 42,111 Other 8

25 12,893 45,460 Current Assets Cash 21,889 15,474 Marketable securities 2,035 Accounts Receivable:

Customers 43,090 43,001 Other 19,681 20,449 Deferred fuel costs, net (26,006)

( 4,632)

Inventories, at average cost:

Fuel (coal, oil and gas) 57,921 50,164 Materials and supplies 22,732 20,973 Prepayments 3,968 3,683 145,310 149,112 Deferred Charges and Refundable taxes and interest 27,531 25,877 Other Assets Unamortized debt expense 5,162 5,415 Other 1,724 1,587 34,417 32,879 Total

$ 1,471,457

$ 1,445,694 See accompanying Notes to Consolidated Financial Statements.

24

LIABILITIES Capitalization (see Statements of Capitalization)

Current Liabilities Deferred Credits Other (Dollars in Thousands)

As of December 31 Common stock Additional paid-in capital Retained earnings Total common stockholders' equity Preferred stock:

Without mandatory redemption With mandatory redemption Long-term debt Long-term debt due within one year Accounts payable Tuxes:

Accrued Deferred Interest accrued Dividends declared Other Credit arising from sale of contracts Accumulated deferred income taxes, net Accumulated deferred investment tax credits Other Commitments and Contingencies (Notes 6 and 10)

Total See accompanying Notes to Consolidated Financial Statements.

1982 98,039 215,397 154,637 468,073 105,000 50,000 562,515 1, 185,588 30,100 24,116 18,282 (12,308) 20,305 11,910 13,046 105,451 39,790 66,200 59,638 14,790 180,418 1981 94, 191 203,534 139,355 437,080 105,000 50,000 596,219 1, 188,299 27,723 40,159 (10,203) 29,570 11,024 4,454 102,727 40,760 49,799 53,920 10, 189 154,668

$ 1,471,457

$ 1,445,694 25

Delmarva Power & Light Company Consolidated Statements of Capitalization (Dollars in Thousands)

As of December 31 1982 1981 Common Stockholders' Common stock, par value $3.375 per share Equity authorized 35,000,000 shares, outstanding 29,048,445 and 27,908,345 shares 98,039 94,191 Additional paid-in capital 215,397 203,534 Retained earnings 154,637 139,355 Total Common Stockholders' Equity 468,073 38%

437,080 37%

Cumulative Preferred Par value $25 per share, 3,000,000 shares authorized, none outstanding Stock Par value $100 per share, 1,800,000 shares authorized Without Mandatory Redemption:

Series Outstanding 3.70%-4.56%

240,000 shares 24,000 24,000 5.00%-7.84%

330,000 shares 33,000 33,000 7.88%-8.96%

480,000 shares 48,000 48,000 105,000 9%

105,000 9%

With Mandatory Redemption:*

9.00% Series 200,000 shares 20,000 20,000 12.56% Series 300,000 shares 30,000 30,000 50,000 4%

50,000 4%

Long-Term Debt First Mortgage and Collateral 'Itust Bonds:

Maturity Interest Rates Jan. 1, 1983 93/s%

30,000 30,000 May 1, 1984 31/s%

10,000 10,000 Aug.1, 1984 9112%

10,000 10,000 Dec. 1, 1985 3112%

10,000 10,000 Jun. 1, 1988 3%%

25,000 25,000 1994-1997 4%%-6%%

50,000 50,000 1998-2002 7%-113/4 %

158, 100 158, 100 2003-2007 6.6%-11%

121,250 121,250 2008-2011 9%%-12%

111,900 111,900 526,250 526,250 Pollution Control Notes:

Series 1973, 5.9% effective rate, due 1983-1998 8,000 8,000 Series 1976, 7.3% effective rate, due 1992-2006 34,500 34,500 42,500 42,500 Term Loan, due 1987, interest at prime rate 23,000 26,550 Unamortized premium and discount, net 865 919 592,615 49%

596,219 50%

Long-term debt due within one year (30, 100)

Total Long-Term Debt 562,515 596,219 Total Capitalization

$ 1, 185,588 100%

$ 1,188,299 100%

• Redemption prices at December 31, 1982 are $110 (9% Series) and $113 (12.56% Series).

See accompanying Notes to Consolidated Financial Statements.

26

Delmarva Power & Light Company Consolidated Statements of Changes in Common Stockholders' Equity (Dollars in Thousands)

Additional For the Three Years Ended Common Par Paid-in Retained December 31, 1982 Shares Value Capital Earnings Total Balance as of January 1, 1980 24,300,758

$ 82,015

$ 173,007

$ 130,594

$ 385,616 Net income 48,957 48,957 Cash dividends declared:

Common stock ($1.49)

(36,805)

(36,805)

Preferred stock

( 9,427)

( 9,427)

Issuance of common stock:

Dividend Reinvestment and Common Share Purchase Plan 630,248 2,127 5,603 7,730 Capital stock expense:

Common 127) 127)

Preferred 398) 398)

Balance as of December 31, 1980 24,931,006 84,142 178,085 133,319 395,546 Net income 58,711 58,711 Cash dividends declared:

Common stock ($1.53Yz)

(39,857)

(39,857)

Preferred stock (12,818)

(12,818)

Issuance of common stock:

Public offering 2,200,000 7,425 20,350 27,775 TRASOP 101,947 344 882 1,226 Dividend Reinvestment and Common Share Purchase Plan 675,392 2,280 5,460 7,740 Capital stock expense:

Common (1,220)

( 1,220)

Preferred

(

23)

(

23)

Balance as of December 31, 1981 27,908,345 94, 191 203,534 139,355 437,080 Net income 73,571 73,571 Cash dividends declared:

Common stock ($1.59Yz)

(45,471)

(45,471)

Preferred stock (12,818)

(12,818)

Issuance of common stock:

TRASOP 290,671 981 3,346 4,327 Dividend Reinvestment and Common Share Purchase Plan 849,429 2,867 8,767 11,634 Capital stock expense:

Common

( 250) 250)

Balance as of December 31, 1982 29,048,445

$ 98,039

$ 215,397

$ 154,637

$ 468,073 See accompanying Notes to Consolidated Financial Statements.

27

Delmarva Power & Light Company Notes to Consolidated Financial Statements

1. Significant Accounting Policies 28 Financial Statements The consolidated financial statements include the accounts of the company and its totally-held subsidiaries, Delmarva Energy Company and Delmarva Industries Inc. (formed in 1981). Accounting policies are in accordance with those prescribed by the regulatory commissions having jurisdiction with respect to accounting matters.

Revenues Revenues are recorded at the time billings are rendered to customers on a monthly cycle basis and include rate increases permitted to be billed subject to refund pending final approval. At the end of each month, there is an amount of unbilled electric and gas service which has been rendered from the last meter reading to the month-end.

Fuel Costs Fuel costs (electric and gas) are deferred and charged to operations on the basis of fuel costs included in customer billings under the company's tariffs, which are subject to periodic regulatory review and approval.

The company's share of nuclear fuel costs relating to jointly-owned nuclear generating stations (including estimated costs of storing spent fuel) is charged to fuel expense on a unit of production basis.

Depreciation and Maintenance The annual provision for depreciation is computed on the straight-line basis using composite rates by classes of depreciable property. Provision for decommissioning costs relating to jointly-owned nuclear generating units is made to the extent of the net cost of removal allowed for rate purposes (approximately 20% of the plant cost). The relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.6% for 1982, 3.5% for 1981and3.2% for 1980.

The cost of maintenance and repairs, including renewals of minor items of property, is charged to operating expenses. A replacement of a unit of property is accounted for as an addition to and a retirement from utility plant. The original cost of the property retired is charged to accumulated depreciation together with the net cost of removal. For income tax purposes, the cost of removing retired property is deducted as an expense.

Delmarva Power & Light Company Notes to Consolidated Financial Statements

1. Significant Accounting Policies (continued)

2. Taxes on Income Income Taxes Deferred income taxes result from timing differences in the recognition of certain expenses for tax and financial accounting purposes. The principal items accounting for deferred income taxes are: (1) use of the Accelerated Cost Recovery System and other accelerated depreciation methods for income tax purposes, (2) unbilled fuel and gas purchased costs deducted currently for income tax purposes, and (3) other timing differences involving spent nuclear fuel storage costs and the capitalization of certain taxes and overhead costs.

Investment tax credits utilized to reduce federal income taxes are deferred and generally amortized over the useful lives of the related utility plant. An additional investment tax credit of 1112 % ( 1 % in 1980) related to the Tax Credit Employees Stock Ownership Plan (a TRASOP plan) does not affect net income and is recorded as a liability until the contribution is made to the TRASOP Plan.

Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) is a non-cash item and is defined in the regulatory system of accounts as "the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds so used." AFUDC is segregated into two components: (1) the interest on debt component

("allowance for borrowed funds used during construction"), which is net of taxes and classified as a credit to interest charges, and (2) the common stock equity and preferred dividend component ("allowance for other funds used during construction"), which is classified as an item of other income. AFUDC is considered a cost of utility plant with a concurrent credit to income. It is excluded from taxable income for tax purposes. The rate used in determining AFUDC, which includes semi-annual compounding, was 9.1 % in 1982, 8.7% in 1981and8.0% in 1980.

Income tax expense for 1982, 1981and1980 is as follows:

(Dollars in Thousands) 1982 1981 1980 Operations:

Federal:

Current

$ 37,508

$ 10,234

$ (1,351)

Deferred 4,700 5,301 10,439 State:

Current 7,672 4,936 441 Deferred 1,363 1,048 1,934 Investment tax credit adjustments, net 7,257 18,384 3,021 Other income:

Current 2,046 1,654 693 Deferred (64)

(144)

Total

$ 60,482

$ 41,413

$15,177 Investment tax credits utilized to reduce federal income taxes payable amounted to

$10,445,000 in 1982, $20,917,000 in 1981 and $5,516,000 in 1980. The amounts for 1982 and 1981 include TRASOP credits of$1,553,000 and $3,281,000, respectively.

29

Delmarva Power & Light Company Notes to Consolidated Financial Statements

2. Taxes on Income (continued) 30 The following is a reconciliation of the difference between income tax expense and the amount computed by multiplying income before tax by the federal statutory rate:

(Dollars in Thousands) 1982 1981 1980 Amount Rate Amount Rate Amount Rate Statutory income tax expense

$ 61,664 46% $ 46,057 46% $ 29,502 46%

Reduction in taxes resulting from:

Exclusion of AFUDC for income tax purposes (2,787)

(2)

(3,272)

(3)

(8,524)

(13)

Excess of tax depreciation over book depreciation not normalized 443 (1,349)

(1)

(3,324)

( 5)

Investment tax credits amortized to income (3, 188)

(2)

(2,533)

(3)

(2,495)

( 4)

State income taxes, net of federal tax benefit 5,065 4

3,365 3

1,295 2

Other, net (715)

(1)

( 855)

(1)

(1,277)

( 2)

Income tax expense

$ 60,482 45% $ 41,413 41% $15,177 24%

The components of deferred income taxes relate to the following tax effects of timing differences between book and tax income:

(Dollars in Thousands) 1982 1981 1980 Depreciation

$ 18,493

$ 14,951

$ 10,097 Deferred fuel costs (10,402)

(9,352) 1,656 Capitalized overhead costs 926 992 1,176 Nuclear fuel storage costs

( 2,054)

(1,332)

(997)

Other, net

(

964) 946 441 Total

$ 5,999

$ 6,205

$ 12,373 The company's federal income tax returns have been examined for the years 1975 through 1979. The company has been assessed additional taxes and interest resulting predominantly from the taxability, on an ordinary income basis, of the net proceeds from the sale of contracts for a nuclear steam supply system (See Note 7). The assessment would result in net additional federal and state income taxes of approximately $20.3 mil-lion and interest of $18.9 million. These amounts are net of anticipated refunds that result from the reversal of the previous tax treatment applied to the sale of the contracts. The company is appealing the taxability of the net proceeds. In the opinion of management and tax counsel, it appears probable that this issue will ultimately be resolved as taxable in an amount which approximates taxes on a capital gains basis. Accordingly, in 1981, the company accrued a net tax liability on a capital gains basis.

During 1982, the company made federal tax and interest payments totalling $28.5 million, on a capital gains basis, to prevent the compounding of interest on the tax deficiency. The ultimate disposition of this issue will not have a material effect on the company's fL.11ancial position or results of operations.

Delmarva Power & Light Company Notes to Consolidated Financial Statements

3. Taxes Other Than Income

4. Pension Plan

5. Capitalization (Dollars in Thousands) 1982 1981 1980 Delaware utility

$ 11,733

$ 11,437

$ 9,873 Property 6,129 5,811 5,550 Other gross receipts 3,601 3,444 3,068 Payroll 3,558 3,216 2,598 Franchise and other 1,926 2,010 1,632 Total

$ 26,947

$ 25,918

$ 22,721 The company has a trusteed noncontributory pension plan covering all regular employees.

Pension contributions for 1982, 1981 and 1980 were $4,895,000, $4,371,000 and $6,421,000 including $914,000, $717,000 and $1,253,000 charged to construction, respectively. The contributions provide for normal cost and amortization of prior service costs over periods of ten to twenty-five years. Net income for 1981 and 1980 was increased by approximately

$938,000 (4¢ per share) and $603,000 (2¢ per share), respectively, principally as a result of changed actuarial assumptions.

The actuarial present value of accumulated plan benefits, determined as of January 1, 1982 was $60,862,000 for vested benefits and $12,769,000 for accrued nonvested benefits.

The net assets, at market value, available for plan benefits were $125,050,000. The actu-arial present value of accumulated plan benefits, determined as of January 1, 1981 was

$51, 175,000 for vested benefits and $8,915,000 for accrued nonvested benefits. The net assets, at market value, available for 1981 plan benefits were $121,957,000. The assumed rate of return used in determining the actuarial present value of accumulated plan benefits was 8.0% for 1982 and 1981.

Common Stock At December 31, 1982 there were 2,315,763 shares of common stock reserved for issuance under the Dividend Reinvestment and Common Share Purchase Plan and the TRASOP.

Retained Earnings The current first mortgage bond indenture restricts the amount of consolidated retained earnings available for cash dividend payments on common stock to $35,000,000 plus accumulations after June 30, 1978, which available amount at December 31, 1982 was approximately $75,300,000.

Preferred Stock The annual preferred dividend requirements on all outstanding preferred stock at December 31, 1982 are $12,818,000. If preferred dividends are in arrears the company may not declare common stock dividends or acquire its common stock.

Without Mandatory Redemption These series may be redeemed at the option of the company at any time, in whole or in part, at the various redemption prices fixed for each series (ranging from $103 to $106 at December 31, 1982).

31

L Delmarva Power & Light Company Notes to Consolidated Financial Statements

5. Capitalization (continued) 32 Preferred Stock (continued)

With Mandatory Redemption (1) The 9% series, issued in 1978, has a sinking fund requirement, commencing in December, 1984, to redeem 8,000 shares annually at $100 per share plus accrued and unpaid dividends. At the option of the company, an additional 8,000 shares may be redeemed on any sinking fund date, without premium. (2) The 12.56% series, issued in 1980, has a sinking fund requirement, commencing in December, 1986, to redeem 9,000 shares annually at $100 per share plus accrued and unpaid dividends. At the option of the company, an additional 9,000 shares may be redeemed on any sinking fund date, without premium. (3) Under certain conditions, these series may also be redeemed at the option of the company. (4) Aggregate mandatory sinking fund redemptions during the next five years are $800,000 in 1984 and 1985 and $1,700,000 in 1986 and 1987.

Capital Stock Expenses Capital stock expenses relating to the issuance of common and preferred stock have been reflected as a reduction of additional paid-in capital.

Long-Term Debt (1) Sinking fund provisions with respect to substantially all issues of the First Mortgage and Collateral Trust Bonds require that there be deposited annually with the Trustee cash equal to one percent (1%) of the greatest aggregate principal amount at any one time outstanding. There shall be credited against such cash requirements (a) an amount not exceeding sixty percent (60%) of the bondable value of property additions which the company then elects to make the basis of this credit, and (b) the aggregate principal amount of bonds which might then be made the basis of the authentication and delivery of bonds and which the company then elects to make the basis of this credit. For the years 1980-1982, the company elected to certify property additions to satisfy its sinking fund requirements equal to 1 % of each series as permitted by the indenture. (2) Substantially all utility plant of the company now or hereafter owned is subject to the lien of the related Mortgage and Deed of Trust. (3) Pursuant to a bank loan agreement the company has a

$25,000,000 revolving credit commitment through December 31, 1984, convertible into a term loan due December 31, 1987. Any loan may be prepaid at any time without penalty and would bear interest at the prime rate through December 31, 1983 and 105% of prime rate thereafter, and a commitment fee of 3/s% on any unused portion of the revolving credit.

From time to time, the company issues commercial paper to repay borrowings under the revolving credit commitment. In 1981and1982, the company sold $12 million and

$11 million, respectively, of short-term tax-exempt revenue notes. In recognition of the long-term financing commitment, these borrowings have been classified as long-term debt.

(4) Maturities of long-term debt during the next five years are 1983-$30, 100,000; 1984-

$20,100,000; 1985-$10,100,000; 1986 and 1987-$150,000. (5) The annual interest require-ments on all borrowings classified as long-term debt at December 31, 1982 are $45,586,000.

Unamortized Debt Discount, Premium and Expense These amounts are amortized on a straight-line basis over the lives of the long-term debt issues to which they pertain.

Delmarva Power & Light Company Notes to Consolidated Financial Statements

6. Commitments

7. Sale of Contracts for Nuclear Plant The company estimates that approximately $90,440,000, excluding AFUDC, will be expended for construction purposes in 1983, in connection with which substantial commitments have been incurred. The company also has commitments under long-term fuel supply contracts.

Minimum commitments as of December 31, 1982 under all non-cancellable lease agreements are as follows:

1983 1984 1985 1986 1987 Remainder Total

$ 8,206,000 7, 196,000 6,854,000 6,527,000 579,000 5,095,000

$ 34,457,000 The total minimum rental commitments are applicable to the following types of property:

company's share of Peach Bottom nuclear fuel, $22,310,000; railroad coal cars, $2,150,000; distribution facilities, $5,498,000; other, principally computer equipment, $4,499,000.

Rentals charged to operating expenses aggregated $13,949,000 in 1982, $9,986,000 in 1981 and $9,463,000 in 1980 including $7,112,000, $5,282,000 and $5,357,000 for nuclear fuel, respectively.

The company has certain leases for property and equipment which meet the criteria for capitalization, but in accordance with rate-making treatment are accounted for as operating leases. The capitalization of such leases would not have a significant effect on assets, liabilities or expenses.

In 1973, the company entered into an agreement providing for the availability of fuel storage and pipeline facilities through 1999. Under the agreement, the company must make specified minimum payments monthly, which totaled $2,454,000 in 1982, $2,941,000 in 1981 and $2,747,000 in 1980. The amount of required payments is $2,240,000 in 1983,

$2,038,000 in 1984, $1,793,000 in 1985, $2,137,000 in 1986, $1,813,000 in 1987 and

$15,047,000 between 1988 and 1999.

The proceeds received by the company for the sale in 1975 of the contracts for a nuclear steam supply system and related fuel, net of related plant expenditures which are consid-ered of no future value to the company, are classified as a deferred credit in the balance sheet. The credit has been reduced by applicable income taxes and related interest (See Note 2). The company has obtained regulatory approval for this accounting treatment.

Subject to regulatory approval, the net credit will be amortized to income, or alternatively used to reduce the cost of subsequent replacement plant capacity.

For ratemaking purposes, the net credit has been reflected as a reduction in rate base.

However, in 1982, the company received a revenue order from the Maryland Public Service Commission which required the company to amortize the Maryland portion of the credit (approximately $5,960,000) over a five-year period and reduce the company's rate base by the unamortized portion of the credit. The company amortized $1, 192,000 of the credit in 1982. This amortization of the net credit will not have a material effect on the company's financial position or results of operations.

33

I Delmarva Power & Light Company Notes to Consolidated Financial Statements

8. Short-Term Debt and Lines of Credit

9. Jointly-Owned Plant

10. Contingencies 34 As of December 31, 1982, the company had unused bank lines of credit of$58,000,000 and is generally required to pay commitment fees for these lines. Such lines of credit are periodically reviewed by the company, at which time they may be renewed or cancelled.

Information with respect to the company's share of jointly owned plant, including nuclear fuel for the Salem plant, as of December 31, 1982 is as follows:

(Dollars in Thousands)

Construction Ownership Plant in Accumulated Work in Share Service Depreciation Progress Nuclear:

Peach Bottom 7.51%

$ 71,983

$ 18,806

$ 1,125 Salem 7.41%

165, 172 31,895 10,626 Coal-Fired:

Keystone 3.70%

8,349 3,509 709 Conemaugh 3.72%

12,789 4,303 164 Total

$ 258,293

$ 58,513

$ 12,624 The company provides its own financing during the construction period for its share of jointly-owned plant. In addition, the company is a joint guarantor of loans ($1,075,000 proportionate share) advanced for operating of the coal mines that supply the Keystone plant. The company's share of operating and maintenance expenses of the jointly-owned plant is included in the corresponding expenses in the statements of income.*

See Note 2 for possible payment of taxes.

In January 1983, the company reached a settlement with four Delaware municipal electric wholesale customers who had filed anti-trust suits against the company in 1977.

The settlement of this suit, which is subject to FERC and District Court approval, did not have a material impact on the company's results of operations.

Based upon settlements with resale customers, revenues recorded pursuant to interim rate increases effective December 1, 1978, December 1, 1980, December 29, 1981 and November 1, 1982, are approximately $6.5 million, $6.9 million, $2.0 million and

$.6 million, respectively. These increases are subject to refund pending FERC approval, and the company believes that substantially all such revenues will be realized.

The company is involved in certain other legal and administrative proceedings before various courts and governmental agencies concerning rates, environmental issues, taxes, licensing, fuel contracts and other matters. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on the financial position or results of operations of the company.

The company is a member of Nuclear Electric Insurance Limited (NEIL) which provides insurance coverage against the extra expense incurred in obtaining replacemenL power during prolonged accidental outages of nuclear power units. After the deductible period of 26 weeks, weekly indemnity of up to $2.5 million is provided for 52 weeks and $1.25 million for an additional 52 weeks, for each insured unit. Insured members are contingently liable

Delmarva Power & Light Company Notes to Consolidated Financial Statements

10. Contingencies (continued) for payment of a retrospective premium adjustment of up to five times the annual pre-mium iflosses exceed accumulated funds available to NEIL. The company's maximum share of retrospective premium adjustments currently approximates $2.3 million.

The Price-Anderson Act places a limit of liability of $560 million on each nuclear generating facility for public liability claims that arise from a nuclear incident. Public liability insurance on the nuclear generating units in which the company has an ownership participation is currently provided by a combination of private insurance and indemnity agreements with an agency of the federal government. Under the indemnity agreements, the company, to the extent of its ownership participation, could be assessed

$5 million per incident for each nuclear operating unit, subject to a maximum of $10 million per licensed reactor in any one year. The company is currently a joint owner of 4 reactors and its maximum assessment would be $1.5 million per incident and $3.0 million in any one year.

For property damage to the Peach Bottom nuclear plant facilities, the company and its co-owners have private insurance up to $460 million. The company and the Salem nuclear facility co-owners are members of Nuclear Mutual Limited (NML), which provides insurance coverages up to $500 million for property damage to nuclear plant facilities.

In the event of losses at any plant covered by NML, the company would be subject to a maximum assessment of fourteen times its annual premium. Such maximum assessment would currently approximate $3.9 million. In addition, each of the facilities are insured for

$400 million by Nuclear Electric Insurance Limited (NEIL II) for losses in excess of $500 million. In the event of losses at any plant covered by NEIL II, the company would be subject to a maximum assessment of seven and a half times the annual premiums. Such maximum assessment would currently approximate $1.1 million for both plants. The company is a self-insurer, to the extent of its ownership interest, for any property loss in excess of the aforementioned amounts.

The company has entered into a five-year contract, effective October 1, 1980, with Atlantic City Electric Company to sell one-eighth of the electricity generated by Indian River unit 4. The major provisions of the contract allow for the company to receive, irrespective of the availability of electric generation, one-eighth of all operation and maintenance expenses incurred and a fixed return on the plant investment. Approval of this agreement was received from the FERC and the Delaware Public Service Commission (DPSC) in 1980. In connection with the decision of the DPSC, it was determined that profits from the contract up to the company's projection of $8.6 million be passed on to the customers, any losses be absorbed by the stockholders and profits above $8.6 million be passed to the stockholders. In July 1982, the DPSC recognized that the expected value of this contract may not be ascertainable and postponed the final issuance of their Order to permit further investigation of this matter during the remaining time of the operation of the contract. As of December 31, 1982, the company believes that profits on the contract will be substantially in excess of the initial projection of $8.6 million.

The company's coal-buying practices and contracts associated with the Indian River unit 4 became the subject of an investigation in 1982 fuel adjustment hearings before the DPSC. The Commission initially assessed damages to the company for $3.9 million which was reduced to $2.9 million. Once an order is received, the company intends to appeal the case to the Delaware Superior Court.

In 1982, the company delayed the construction schedule for the 500-megawatt, coal-fired Vienna 9 generating unit. The plant is now scheduled to begin commercial operation in 1995. The decision is based on the company's current load forecast, which indicates a lower rate of growth in the coming decade than had previously been projected. The net investment, including AFUDC, at December 31, 1982, is $13.4 million, which is anticipated to be recoverable at the rescheduled in-service date.

35

Delmarva Power & Light Company Notes to Consolidated Financial Statements

11. Segment Information 36 Segment information with respect to electric, gas and steam operations was as follows:

(Dollars in Thousands) 1982 1981 1980 Operating Revenues:

Electric 534,770 504, 119 443,927 Gas 84,747 83,070 59,040 Steam 17,149 21,315 17,503 Total 636,666 608,504

$ 520,470 Operating Income:

Electric 109,620 100,836 74,461 Gas 5,800 5,294 5,155 Steam 1,153 1,195 1,100 Total 116,573 107,325 80,716 Utility Plant: w <2>

Electric

$ 1,226,140

$ 1, 166,376

$ 1,132,992 Gas 47,044 45,608 45,711 Steam 5,653 6,259 6,959 1,278,837 1,218,243 1, 185,662 Other Identifiable Assets:

Electric 81,155 120,914 93,060 Gas 10, 172 13, 160 10,005 Steam 455 420 343 91,782 134,494 103,408 Assets Not Allocated 100,838 92,957 91,852 Total Assets

$ 1,471,457

$ 1,445,694

$ 1,380,922 Depreciation Expense:

Electric 46,084 43,238 34,321 Gas 2,950 2,703 2,775 Steam 895 892 859 Total 49,929 46,833 37,955 Construction Expenditures: <3>

Electric 107,533 81,651 107,063 Gas 3,019 2,531 3,500 Steam 94 24 176 Total 110,646 84,206 110,739 corncludes construction work in progress and allocation of common utility property.

c2lstated net of the respective accumulated provisions for depreciation.

cs)Excludes allowance for funds used during construction.

Operating income by segments is reported in accordance with generally accepted accounting and ratemaking practices within the utility industry and, accordingly, includes each segment's proportionate share of taxes on income and general corporate expenses.

Delmarva Power & Light Company Notes to Consolidated Financial Statements

12. Supplementary Information to Disclose the Effects of Changing Prices (Unaudited)

The following supplementary financial information, as prescribed by the Financial Accounting Standards Board in Statement No. 33, is supplied for the purpose of providing information about the effects of changing prices on the company's operations. The information 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.

Current cost amounts reflect the change in specific prices of plant from the date the plant was acquired to the present and differ from constant dollar amounts to the extent that specific prices have increased more or less rapidly than prices in general. The current cost of utility plant represents the estimated cost of replacing existing plant assets and was determined by indexing existing plant by the Handy-Whitman Index of Public Utility Construction Costs.

Supplementary Financial Data Adjusted for the Effects of Changing Prices (Dollars in Thousands)

For the Year ended December 31, Historical Cost Operating Revenues Operating Expenses:

Operation and Maintenance Depreciation Taxes Other Income-Net Interest Charges Net Incomem Earnings per common share (after preferred dividend requirements)<2)

Increase in current cost of utility plant held during the year<3l Adjustment to net recoverable cost Effect of increase in general price level Excess of increase in current costs after adjustment to net recoverable cost over increase in general price level Purchasing power gain on net amounts owed Net

$ 636,666 384,717 49,929 85,447 (6,563) 49,565

$ 73,571

$ 2.13 Constant Dollar Current Cost (Average 1982 Dollars)

$ 636,666 384,717 95,939 85,447 (6,563) 49,565

$ 27,561

$.52

$ (1,452) 22,679

$ 21,227

$ 636,666 384,717 101,010 85,447 (6,563) 49,565

$ 22,490

$.34

$ 116,311 (24,036)

(88,656) 3,619 22,679

$ 26,298 m Including the adjustment to net recoverable cost, the income (loss) on a constant dollar and current cost basis for 1982 would have been $26, 109 and $(1,546), respectively.

<2> Excluding adjustment to net recoverable cost.

<3> At December 31, 1982, current cost of net utility plant was $2,402,922 while historical cost was $1,278,837.

37

Delmarva Power & Light Company Notes to Consolidated Financial Statements

12. Supplementary Information (continued) 38 Supplementary Five-Year Comparison of Selected Financial Data Adjusted for the Effects of Changing Prices (In Thousands'0 of Average 1982 Dollars)

For the Years ended December 31 1982 1981 1980 1979 1978 Operating revenues Historical cost dollars

$ 636,666 $ 608,504 $ 520,470 $ 424,699 $ 378,702 Constant dollars 636,666 645,805 609,679 564,765 560,290 Net income Constant dollars 27,561 21,576 18,767 38,703 Current costs 22,490 15,948 9,796 26,630 Earnings per common share Constant dollars

.52

.31

.32 1.14 Current costs

.34

.10

(.05)

.63 Net assets at year end<2 >

Historical cost dollars 573,073 542,080 500,546 490,616 Constant dollars and current costs 566,597 556,715 560,015 616,951 Excess of increase in general price level over increase in current costs<3>

3,619 (63,900)

(109,614)

(130,721)

Purchasing power gain on net amounts owed 22,679 53,105 73,009 79,215 Cash dividends declared per common share Historical cost dollars 1.591/z $

1.531/z $

1.49 1.401/z $

1.301/z Constant dollars 1.591/z 1.63 1.741/z 1.87 1.93 Market price per common share at year-end Historical cost dollars 16.38 12.63 11.75 12.63 13.25 Constant dollars 16.20 12.97 13.15 15.88 18.88 Average Consumer Price Index (1967 = 100) 289.1 272.4 246.8 217.4 195.4 mExcept per share amounts.

'2>At net recoverable cost.

'3>After adjustment to net recoverable cost.

As required by Statement No. 33, the current provisions for depreciation on the constant dollar and current cost amounts of utility plant were determined by applying the com-pany's depreciation rates to the indexed plant amounts, even though depreciation is limited to recovery of historical costs as further discussed below. Other operating expenses were either not required to be adjusted or were not adjusted due to rate-making considerations.

The company, by holding monetary assets such as cash and receivables, loses purchasing power during periods of inflation because these items can purchase less at a future date.

Conversely, by holding monetary liabilities, primarily long-term debt, payments in the future will be made with dollars having less purchasing power. For the years 1979-1982, the company's monetary liabilities exceeded monetary assets which resulted in a purchasing povver gain on net amounts owed during the year.

~

~

Delmarva Power & Light Company Notes to Consolidated Financial Statements

12. Supplementary Information (continued)

13. Quarterly Financial Information (Unaudited)

The rate regulatory process limits the company to the recovery of the historical cost of plant. Therefore, the excess of the cost of plant stated in terms of constant dollars or current cost over the historical cost of plant is not presently recoverable in rates as depreciation and is reflected as a reduction to net recoverable cost. Based on past practices, however, the company believes it will be allowed to earn on the increased cost of its facilities when replacement actually occurs.

Since the gain from the decline in purchasing power is attributable to long-term debt which has been used to finance utility plant, the reduction of utility plant to net recoverable amount is netted against the purchasing power gain on net amounts owed during the year.

The quarterly data presented below reflect all adjustments necessary in the opinion of the company for a fair presentation of the interim results. Quarterly data normally vary seasonably with temperature variations, differences between summer and winter rates, the timing of rate increases and the scheduled downtime and maintenance of electric generating units.

Earnings Earnings Applicable Average per Quarter Operating Operating Net to Common Shares Average Ended Revenue Income Income Stock Outstanding Share (Dollars in Thousands) 1982 March 31

$ 179,138 $ 31,174

$ 20,512

$ 17,308 28,104

$.62 June 30 144, 106 24,657 13,948 10,743 28,302

.37 September 30 166,382 36,123 25,303 22,099 28,516

.78 December 31 147,040 24,619 13,808 10,603 29,033

.36

$ 636,666 $ 116,573

$ 73,571

$ 60,753 28,489

$ 2.13 1981 March 31

$ 160,919

$ 27,061

$ 14,266

$ 11,062 25,078

$.44 June 30 137,445 24,547 12,098 8,893 25,247

.35 September 30 164,359 31,464 19,772 16,568 25,514

.65 December 31 145,781 24,253 12,575 9,370 27,150

.34

$ 608,504 $ 107,325

$ 58,711

$ 45,893 25,747

$ 1.78 39

Delmarva Power & Light Company Consolidated Statistics 10 Years of Review 1982 1981 1980 1979 Electric Revenues (thousands):

Residential

$ 183,258

$ 164,919

$ 144,637

$ 115,381 Commercial 137,434 123,099 112, 166 91,798 Industrial 127,441 129,601 116,401 98,023 Other utilities, etc.

73,469 73,602 63,698 53,782 Miscellaneous revenues 13,168 12,898 7,025 4,682 Total electric revenues

$ 534,770

$ 504,119

$ 443,927

$ 363,666 Electric Sales (1,000 kilowatt-hours):

Residential 2,026,398 1,996,647 2,046,546 1,968,452 Commercial 1,729,863 1,660, 147 1,648,776 1,598,299 Industrial 2,255,673 2,454,685 2,429,842 2,624,438 Other utilities, etc.

1,237,508 1,283,845 1,335,216 1,300,611 Total electric sales 7,249,442 7,395,324 7,460,380 7,491,800 Electric Customers (end of period):

Residential 260,371 255,646 246,887 242,745 Commercial 29,966 29,450 28, 162 27,998 Industrial 741 788 821 874 Other utilities, etc.

434 434 440 478 Total electric customers 291,512 286,318 276,310 272,095 Gas Revenues (thousands):

Residential

$ 36,505

$ 34,123

$ 26,525

$ 25,719 1

Commercial 15,792 14,344 10,342 8,954 Industrial 20,112 22,259 12,404 9,884

~

Interruptible 11,733 11,711 9,293 4,440 Other utilities, etc.

53 61 46 55 Miscellaneous revenues 552 572 430 270 Tutal gas revenues

$ 84,747

$ 83,070

$ 59,040

$ 49,322 Gas Sales (million cubic feet):

Residential 6,062 6,193 6,321 6,423 Commercial 2,768 2,704 2,683 2,415 Industrial 4,108 4,809 3,937 3,388 Interruptible 2,656 2,802 2,738 1,720 Other utilities, etc.

10 12 14 16 Total gas sales 15,604 16,520 15,693 13,962 Gas Customers (end of period):

Residential 70,356 69,865 69,024 67,823 Commercial 4,057 3,967 3,846 3,712 Industrial 166 167 155 131 Interruptible 18 16 16 16 Other utilities, etc.

1 1

1 1

Total gas customers 74,598 74,016 73,042 71,683 Refinery Service Electricity delivered 322,804 343,063 328,420 262, 159 (1,000 kilowatt-hours)

Steam delivered 7,778,929 7,673,420 7,570,944 6,378,705 (1,000 pounds) 40

Average Annual Compound%

1978 1977 1976 1975 1974 1973 1972 Rate of Growth

$ 105,237

$ 97,691

$ 80,416

$ 77,069

$ 68,730

$ 51,799

$ 43,878 15.37 82,796 74,641 60, 111 58, 169 51, 192 37,888 31,810 15.76 83,972 76,801 64,458 64, 141 66,381 41,284 35,962 13.49 40,840 38,974 34,896 35,606 32,976 21,518 16,833 15.88 5,261 3,461 2,398 4,370 9,194 5,287 2,857 16.51

$ 318, 106

$ 291,568

$ 242,279

$ 239,355

$ 228,473

$ 157,776

$ 131,340 15.07 1,979,624 1,924,723 1,787,663 1,672, 180 1,597,472 1,629,641 1,463,821 3.31 1,568,600 1,495,796 1,412,259 1,359,673 1,303,053 1,360,216 1,227,230 3.49 2,418,527 2,277,630 2,260,661 2,142,151 2,461,303 2,512,877 2,412,239 (0.67) 1,281,498 1,207,941 1, 199, 155 1,218,785 1,230,528 1,252,977 1,137,272 0.85 7,248,249 6,906,090 6,659,738 6,392,789 6,592,356 6,755,711 6,240,562 1.51 237,925 233, 106 230,579 221,780 215,516 208,073 200,595 2.64 28,421 29,648 28,345 27,345 27,132 26,708 25,856 1.49 858 921 1,002 923 891 867 869 (1.58) 480 561 550 545 501 506 496 (1.33) 267,684 264,236 260,476 250,593 244,040 236,154 227,816 2.50

$ 28,370

$ 21,829

$ 18,826

$ 15,365

$ 14,298

$ 13,018

$ 12,944 10.92 10,154 7,133 6,062 4,676 4,201 3,715 3,532 16.16 10, 191 6,950 5,984 4,343 3,726 3,505 3,265 19.94 716 169 1,301 1,211 1,532 1,363 1,035 27.48 93 49 44 33 26 30 25 7.80 116 103 31 45 96 22 18 40.82

$ 49,640

$ 36,233

$ 32,248

$ 25,673

$ 23,879

$ 21,653

$ 20,819 15.07 6,941 6,751 6,956 6,540 6,863 7,134 7,737 (2.41) 2,593 2,439 2,586 2,429 2,526 2,614 2,696 0.26 3,290 2,811 3,264 2,849 3,215 3,653 3,875 0.59 319 81 953 1,073 2,257 2,346 2,134 2.21 29 17 20 18 16 23 20 (6.70) 13, 172 12,099 13,779 12,909 14,877 15,770 16,462 (0.53) 67,550 67,400 68,978 69,418 69,525 69,833 69,891 0.07 3,773 3,738 4,154 4,189 4,356 4,418 4,407 (0.82) 163 163 198 198 195 197 195 (1.60) 21 21 21 21 21 21 21 (1.53) 1 1

1 1

1 1

1 71,508 71,323 73,352 73,827 74,098 74,470 74,515 0.01 270,006 289,049 318,389 297,282 350,021 341,700 295,236 0.90 6,016,095 4,888,366 5,301,421 5,517,000 5,921,000 5,926,000 7,261,000 0.69 41

Delmarva Power & Light Company Board of Directors Board of Directors 42 Werner C. Brown Director and Retired Chairman of the Board of Hercules, Incorporated (chemical manufacturer)

Wilmington, Delaware Mrs. Henry P. Cannon, II Director of H. P. Cannon & Son, Inc.

(food processing firm)

Bridgeville, Delaware Oscar L. Carey President and Director of Larmar Corporation (general real estate and home builders)

Salisbury, Maryland Frank A. Cook Vice President of the Company John R. Cooper Manager of Environmental Affairs and Occupational Health, Petrochemicals Department ofE. I. du Pont de Nemours &

Company (chemical manufacturer)

Wilmington, Delaware Nevius M. Curtis President and Chief Executive Officer of the Company Sally V. Hawkins Director and President of Delaware Broadcasting Company and General Manager of Station WILM (radio broadcasting),

Wilmington, Delaware William G. Sirneral Director and Executive Vice President and a member of the Executive Committee ofE. I. du Pont de Nemours & Company (chemical manufacturer)

Wilmington, Delaware Dr. E. Arthur Trabant President of the University of Delaware Newark, Delaware Robert D. Weimer Chairman of the Board of the Company

Delmarva Power & Light Company Officers Officers Robert D. Weimer Chairman of the Board Nevius M. Curtis President and Chief Executive Officer H. Ray Landon Senior Vice President Harland M. Wakefield, Jr.

Senior Vice President Frank A. Cook Vice President Howard E. Cosgrove Vice President and Chief Financial Officer Donald E. Cain Division Vice President, Northern Division Wayne A. Lyons Division Vice President, Southern Division Paul S. Gerritsen Vice President, Regulatory Practices Alfred C. Thawley, Jr.

Secretary and Treasurer Charles Marchyshyn Comptroller Executive Committee Robert D. Weimer, Chairman; Werner C. Brown; Oscar L. Carey; Nevius M. Curtis; Dr. E. Arthur Trabant Audit Committee Oscar L. Carey, Chairman; Werner C. Brown; John R. Cooper Nominating Committee Dr. E. Arthur Trabant, Chairman; Sally V. Hawkins; Robert D. Weimer Compensation Committee Werner C. Brown, Chairman; Oscar L. Carey; Nevius M. Curtis; William G. Simeral 43

Delmarva Power & Light Company General Information General Information 44 Trustees First Mortgage and Collateral Trust Bonds, Chemical Bank, New York, New York.

Pollution Control Revenue Bonds, Girard Bank Delaware, Wilmington, Delaware, Bank of Dela-ware, Wilmington, Delaware, and Wilmington Trust Company, Wilmington, Delaware.

Transfer Agents and Registrars Preferred Stock-Wilmington Trust Company, Wilmington, Delaware.

Common Stock-Wilmington Trust Company, Wilmington, Delaware, and Manufacturers Hanover Trust Company, New York, New York.

Stock Symbol Common Stock, DEW-listed on the New York and Philadelphia Stock Exchanges.

Regulatory Commissions Federal Energy Regulatory Commission, 825 North Capitol Street, N.E.,

Washington, D.C. 20426.

Delaware Public Service Commission, 1560 S. du Pont Highway, Dover, Delaware 19901.

Maryland Public Service Commission, American Building, 231 East Baltimore Street, Baltimore, Maryland 21202.

Virginia State Corporate Commission, P.O. Box 1197, Richmond, Virginia 23209.

Corporate Address Delmarva Power, 800 King Street, P.O. Box 231, Wilmington, Delaware 19899.

Telephone (302) 429-3011 Annual Meeting The Annual Meeting will be held on April 26 at 12:30 p.m., in the Grand Opera House, 818 Market Street Mall, Wilmington, Delaware.

Additional Reports 1b supplement information in this Annual Report, a Financial and Statistical Review (1972-1982) and the Form 10-K are available upon request.

Please write to Stockholder Relations, Delmarva Power, 800 King Street, P.O. Box 231.

Wilmington, Delaware 19899

I i

l

.Delmarva Power 800 King Street 0P. O. Box 231 Wilmington, DE 19899

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DEADLINE RETURN DATE RECORDS FACILITY BRANCH

Results of Operations 1982-1981 1982 1981 Change Electric Operating Revenues

$ 444,178,000 $ 469,683,000 (5.4)

Operating Expenses

$ 381,408,000 $ 396,172,000 (3.7)

Net Income*

49,055,000 $

46,988,000 4.4 Earnings Per Common Share*

2.76 $

3.03 (8.9)

Dividends Paid Per Common Share $

2.20 $

2.04 7.8 Total Assets

$1,077,969,000 $1,013,789,000 6.3 Cash Construction Expenditures

$ 118,460,000 $ 113,221,000 4.6 Sales of Electricity (KWH) 5,592,117,000 5,675,367,000

( 1.5)

Total Customer Service Installations (Year-end) 391,989 386,046 1.5 Number of Shareholders-Common Stock (Year-end) 48,790 48,424

.8 Number of Employees (Year-end) 2,022 2,035

(.6)

Book Value 22.45 $

22.40

.2

• See Note 4 (Change in Accounting for Revenues) of Notes to Financial Statements.

Dividends Per Share of Common Stock (in dollars) 2.50 2.00 1.50 f--

1.00 f--

f--

.so 0

79 80 81 82 Earnings Per Share of Common Stock (in dollars) 3.75 3.00 2.25 1.50

.75 0

78 79 80 81 82

2 President John D. Feehan listens to a customer's viewpoint during a Consumer Roundtable, a forum for open discussion of Atlantic Electric's operations and service.

To Our Shareholders, Customers and Employees:

uring the past year the measure of our finan-cial performance was influenced by two critical factors: timely and adequate rate relief and the cost of financing the Company's substantial construction program. These major challenges were announced well in advance of last year and 1982 was accurately predicted to be a period of transition.

For 1982 earnings per share were

$2.76, a decline of9% from 1981.

Dividends, however, increased to an annual rate of $2.28 as a result of a four cents per share quarterly increase. This marked the 30th con-secutive year of increases in the dividend paid. Included in reported earnings were 68 cents per share due to an accounting change that incorpo-rated unbilled revenues into reported revenue starting in 1982. (Note 4 to Financial Statements, page 29).

The timing of rate relief had by far the most significant impact on the year's results. A February 1982 filing to the New Jersey Board of Public Utilities (BPU) requesting a $172.4 million rate increase resulted in lengthy proceedings and the granting of a $73.7 million increase in Decem-ber. Unfortunately, this decision will not permit the Company to achieve the 15% return on common equity that the BPU specified. Atlantic Electric will be seeking additional revenues through a continuation of our last filing allowed by the BPU.

This continuation will deal primarily with our contract with Pennsylvania Power & Light Company for 62 mega-watts of their Susquehanna Unit No. I. This unit is expected to go into service in May, 1983. Timely and ful'I recovery of the cost of this energy will prevent an adverse effect on financial performance in 1983.

Major Gains. Despite this setback in rate relief, positive financial develop-ments occurred during 1982 that contributed to the Company's pres-ent and future health. They were:

D U nrecovered fuel costs, which reached a peak of $62 million in 1981, were fully recovered from our cus-tomers in 1982.

D Financing for the $118 million con-struction and modernization program was successfully obtained at a rea-sonable cost; we ended the year without any short-term borrowings.

D Fuel cost charges to customers, a reflection of energy expenses, were reduced by $159 million, calculated on an annual basis, through three separate decreases in the Energy Adjustment.

D The price of electricity to custom-ers was stabilized by increased use of coal, continued reliability of nuclear generating units and by importing low-cost energy from utilities with excess capacity.

Planned Growth. The New Direction program, announced at the 1981 Annual Meeting, began to show results. This program is designed to limit future construction costs by aggressively promoting conservation, efficient energy use, and alternative electric sources. The reduction in the forecasted annual growth rate of the peak demand, from 2.4% to 1.6%,

reflects the expected impact of the program over the next 15 years. The immediate impact was the lowering of planned construction expenditures for the 1983 to 1987 period to $382 million from the previously projected

$716 million.

In Appreciation. The Company's shareholders deserve a well-earned "thank you" for their support and encouragement during 1982. One of the toughest years in recent times was weathered, while plans that will provide the basis for our future per-formance were put in place. These achievements would also not have been possible without the contribu-tions of the Company's 2,022 dedicated and loyal employees.

On December 31, 1982, Alfred C.

Linkletter relinquished his position as Chairman of the Board, in anticipa-tion of his retirement as a Director this April. The five years during which Alfred Linkletter served as Chairman have brought significant changes for the Company with respect to regulation, financing and long-term planning. During these years, his leadership, experience and integrity have enabled the Company to meet its challenges and to plan a course for successful management in the future.

For the Board of Directors J. D. Feehan Chairman of the Board and President 3

Alfred C. Linkletter, former Chairman of the Board, discusses the future of Atlantic Electric.

4

A Look at Yesterday, Today and Tomorrow:

his year's Annual Meet-ing will be my last as a member of the Atlantic Electric Board of Directors. During my 12 years as a Member of the Board and five years as Chair-man, I have been privileged to be a part of a challenging period in Atlan-tic Electric 's long history.

On the occasion of my retirement, I have been asked to present my thoughts about our Company during my tenure.

Yesterday. Recently, I was asked what my impressions were when I joined the Board in 1970. Immediately, I recalled my first meetings with the management team. They clearly dem-onstrated that they were knowledge-able and upbeat. As an engineer, I knew the importance of planning and anticipation, particularly in the areas of new construction and mainte-nance. From the first day, I was aware that thi s Company was actively preparing for the future.

In the years that followed, my initial impressions were reinforced many times. Two events stand out among many. The first was the world-wrenching Arab oil embargo in 1973.

We take great pride in having been the first utility to convert back to coal, a feat that was possible only because our coal handling and burn-ing equipment had not been cast aside years before when we were fo rced to convert to low sulfur oil.

Instead, it was ready for use, in case of just such an emergency.

The second event was the Com-pany's winning the Outstanding Electric Utility of the Year Award in 198 1. This National Award was given by Electric Light & Power Magazine and the selection was made by an independent panel of judges. It was proof-positive that we were succeed-ing in our efforts to excel.

Today. Our efforts have produced the desired results, placing us, I believe, in an excellent position. Our generat-ing capacity is now extensively diversified, which protects our cus-tomers from loss of power should an emergency knock out any one gener-ator. Our management team is stronger and deeper than ever before.

We have youth, experience and lead-ership potential at all levels, an unusual circumstance for a utility of our size. Our shareholders support us because we have continued a remark-able record of dividend payments and increases. Our communications efforts, including our New Direction program, have earned a better understanding of the long-term considerations in providing electric power to a diverse service area.

Tomorrow. While we have come a long distance, there is still much to accomplish. A high priority has to be given to more efficient rate regula-tion. The process must be stream-lined and insulated from the political arena. Too much time and money are put into a never-ending series of rate hearings and appeals. Everyone would be better served by rate adjustments that are fairer to the Company and take less time to complete.

This Nation must set its energy pri-orities now. Looking beyond the electrical generating capacity cur-rently under construction, abundant American coal should be the major fuel source. But many environmental issues must still be resolved. The cost of constructing any type of new generating capacity is extremely high and shows no signs of declining.

Conservation and energy-efficient appliances must be part of the solu-tion. Efforts to remove emotionalism from energy issues, and to balance immediate needs against future needs, are urgently required.

I leave the Board of Atlantic Electric confident that steps will be taken to meet these challenges, just as con-tinuing needs such as recruiting and retaining outstanding people, stream-lining operations and increasing efficiency will be met.

I wish to add that, after this year's Annual Meeting, I will remain as a private shareholder. Like all of us, I will closely follow the progress of "Our Company. " I am confident that our concerns will be minimal and that our rewards will increase yearl y.

ac. ~

A. C. Linkletter 5

Mickleton Station SALEM 0 Hope Creek Carlis Corner Station CUMBERLAND Delaware Bay

• Steam Electric Generating Station A. Combustion Turbine Generating Station e Jointly Owned Nuclear Generating Station O Jointly Owned Nuclear Generating Station Under Construction 6

Other Ownership Interests (All located in Pennsylvania)

Conemaugh Generating Station Keystone Generating Station Peach Bottom Atomic Power Station BURLINGTON ATLANTIC B.L. England Station CAPE MAY Cedar Station Atlantic Ocean

At a Glance: The Atlantic Electric Service Area Atlantic Electric serves over one million people in a 2,700 square mile area in Southern New Jersey. It is a region diverse in economic activity within close proximity to Philadelphia, New York, Baltimore and Washington. Tourism plays a significant role in the economy of the coastal areas while the inland is agricultural and industrial.

Customer Base Residential In 1982, the Company served over 324,000 customers in 129 municipalities in eight counties.

About 20% of these dwellings have electricity as their conventional heating source. 50% have electric water heaters and 60% have air-conditioning. About 18% of all dwellings are currently occupied on a seasonal basis.

Commercial Atlantic Electric served 42,885 commercial customers in 1982. The highest concentrations of commercial activity are along the eastern seashore resort areas and in Camden, Gloucester and Cumberland Counties.

At year-end, the Company served nine hotel-casinos in Atlantic City. A tenth was under construction.

Also, 1,700 commercial customers were engaged in agricultural activities.

Industrial The Company served an average of 1,018 industrial customers in 1982.

Principal manufacturing industries included food, chemicals, rubber and plastic products, stone, clay, glass and electrical and electronic equipment.

1982 Electric Consumption Residential customers represented 49% of the annual peak demand. The residential sector consumed nearly 2.4 billion kilowatt-hours last year or 43% of total sales. The average residential customer used 7,444 kilowatt-hours. More than 4,400 new residential customers were added during the year and 50% of all new residential "connects" during the year had electric heat.

Total commercial customers accounted for 36% of the annual peak demand. This sector represented 34%

of total sales, consuming 1.9 billion kilowatt-hours. Casinos, which are part of the commercial group, were 3% of the total peak demand and 5%

of total sales.

Industrial customers represented 15%

of the annual peak demand. They consumed 1.2 billion kilowatt-hours, or 22% of total sales. About 34% of all industrial sales were to the stone, clay and glass industries.

Fifteen Year Outlook Residential customers are projected to comprise 47% of the total peak in 1997 and consume 3.2 billion kilowatt-hours, or 43% of total projected sales. Average residential kilowatt-hour consumption is ex-pected to increase to 7,900 in 1997.

The residential sector is estimated to have a compound growth rate in peak demand of only 1.2% over the next 15 years.

The commercial sector is estimated to comprise about 39% of the total peak expected in 1997 and commercial sales are expected to increase to 2.6 billion kilowatt-hours, or 36% of projected total sales. The casino portion of the commercial sector will be 3.2% of the total peak demand and 4.4% of total projected sales. The entire commercial sector is expected to experience a 2.3%

compound growth rate in peak demand over the 15 year period.

The industrial class portion of total peak demand is forecast as 14% in 1997. Industrial sales are expected to grow to 1.5 billion kilowatt-hours or 20% of the total projected sales. The compound growth rate in peak demand for the industrial sector is expected to be 0.9%.

7

00

Managed Growth he golden days of rapid growth, cheap fuels, low-cost borrowing and infre-quent rate increases are long past. Today, the faltering economy, high prices and expensive energy are mak-ing growth a difficult and expensive process. This Company understands the challenge of growing while meet-ing its obligations to shareholders, customers, employees, regulators and the environment.

Management is able to respond rapidly to these challenges because improvements and programs are in place that permit the Company to meet the future with assurance.

Atlantic Electric is proud of its repu-tation of being innovative, aggressive and unconventional. During 1982, the future availability of safe and ade-quate electrical service was ad-vanced by these actions:

D Refining corporate strategy D Identifying critical issues for the future D Strengthening planning and forecasting D Developing additional managerial skills and depth Corporate Strategy. The Company's overriding objective has been to pre-dict the future demands for electricity and to prepare to meet these needs.

The problems dealt with, included the very high cost of constructing new facilities while keeping elec-tricity affordable and maintaining earnings. At the conclusion of 1982, the strategies were developed and in place to more effectively manage load growth and energy consumption, raise necessary capital and keep future earnings at an acceptable level.

Critical Issues. Atlantic Electric fur-ther defined its obligations, setting these priorities for the near future.

D Increased public acceptance of the Company's efforts to provide neces-sary energy and encourage ~on servation.

D Longer-range preparedness for developments beyond the Company's control in load growth and regulatory actions.

D Improved profitability and internal cash generation.

Planning and Forecasting. A quiet, but significant development during 1982 was the additional application of sophisticated computer programs to the Company's planning and fore-casting tools. It is now possible to more effectively monitor economic and demographic conditions. It is also possible to analyze complex interrelationships which can alter electrical demands and have a finan-cial impact on the Company. In addition, Atlantic Electric's planning horizon has been extended beyond 15 years through the use of this new technology.

Managerial Skills and Depth.

"Planned Diversity" is a strength that the Company has advocated over the years. Nowhere is it more applicable than in the area of developing mana-gerial skills and depth. In recent years, senior managers have exchanged responsibilities for major operating segments of the Company.

Annual management conferences and regular strategic planning meetings bring different points of view together for open discussion and resolution.

9

10 Ernest D. Huggard, Executive Vice President, inspects a turbine rotor being prepared for installation in a coal-fired generator at the B. L. England Generating Station at Beesley's Point.

Production Cost Per Kilowatt Hour (in cents)

~

~

1--

~ -

~~

~

1--

1--

t--

1--

1-- -

'78 79 80 81 82 4.0 3.2 2.4 1.6

.8 0

Operating Efficiency roductivity and cost con-tainment were two areas on which the Company concentrated its efforts during 1982. As a result, Atlantic Electric was able to produce electric power at 15%

less per kilowatt hour than in 1981.

This reduction was due, in part, to greater availability of economical generating capacity, both within the Company and from utilities outside the service area. Overall, operating efficiency was improved by more effective use of resources in these areas:

D Energy production D System operations D Corporate administration Energy Production. The use of lower-cost fuels was enhanced by installing more efficient pollution control equipment, which permitted greater burning of coal. This included two new electrostatic precipitators ($30 million) at the B. L. England Station and a new system to clean exhaust gas ($19 million) on Unit #6 at the Deepwater Station. Two coal-fired boilers at B.L. England were also rebuilt ($11 million), to increase relia-bility and extend useful life.

In addition, the Company was able to purchase economical coal-produced electricity from other utility systems.

Significant sources in 1982 were the Delmarva Power & Light Company and the Allegheny Power System.

System Operations. A measure of efficiency that Atlantic Electric con-siders critical is the mandated level of its reserve generating capacity. We have shown a consistency of per-formance in terms of avoiding breakdowns, or forced outages, because of on-going preventive main-tenance programs. The Company, as a member of the Pennsylvania-New Jersey-Maryland (PJM) Interconnec-tion, is required to maintain a much smaller generating capacity reserve than the PJM system-wide average.

This translates into a substantial savings in construction costs for gen-erating capacity additions.

Improvements were also made in the transmission and distribution net-works within the Atlantic Electric service area. Work was performed to raise the voltage on distribution lines and to increase the efficiency of other components of the electrical system.

Corporate Administration. The con-solidation of 800 management and administrative personnel into the new Administrative Complex in Pleas-antville was completed in November.

This modern, energy-efficient com-plex is projected to satisfy office space needs at least through 1990.

During 1982, the scope of the training effort was increased, offering instruc-tion in communication skills, time management and decision making, as well as courses in long-established areas such as leadership, instructor development and supervision. Con-solidation and expansion were assisted by new computer technology that resulted in increased productiv-ity and a decrease in the number of employees. Office automation now includes electronic word processing and message transmission, and the new corporate forecasting system was designed to permit transfer of massive amounts of data between computer-based models.

11

12 Frank J. Ficadenti, Senior Vice President-Engineering and Construction, visits the recently completed exhaust-gas cleaning system at Deepwater Generating Station.

Cash c.onsttuction Expenditures (in millions of dollars) 78 '19 80 81 82 83 84 85 86 87 125 100 75 50 25 System Flexibility he electric energy needs of the Atlantic Electric service area are di-verse. In order to meet the needs of our cus-tomer base, we have built a flexible and responsive gener-ating and delivery system. The em-phasis during 1982 was in these areas:

D Adjusting to changing growth patterns D Joint participation in new generat-ing units D Diversifying fuel and energy sources Changing Growth Patterns. Designing and building an electric system that is geared to any eventuality is the chal-lenge; construction of new base load generating capacity can take 8 to 10 years to complete. At the close of 1982, the projected annual growth rate over the next 15 year period for the Atlantic Electric service area was lowered to 1.6% from the previously projected 2.4%. Effective programs of load management, conservation initiatives, aided by basic demo-graphic changes in our service area, should prove to be effective responses to the dilemmas posed by high interest rates and spiraling con-struction costs. At the same time, the Company retains its ability to meet the future needs of customers.

Joint Participation. One effective means of minimizing risk and im-proving system reliability has been through joint participation in new generating units built by other utilities.

Future base load capacity additions of 178 megawatts will come from contracted purchases from the Penn-sylvania Power & Light Company's Susquehanna Station, expected to start service during 1983, and by a 5% ownership in Hope Creek Nuclear Generating Station, sched-uled for service in 1986.

Diversifying Energy Sources. The variety of generating facilities, and the types of fuels consumed, are key elements in the Company's program of diversifying its sources of energy.

Existing capacity is located through-out the service area and in adjacent states and spread over seven coal-fired units, four residual oil-fired units, four nuclear units and 12 com-bustion-turbine peaking generators.

The largest amount of capacity in a single unit accounts for only about 10% of the total system capacity.

Therefore, the unexpected loss of any generating unit within the Atlan-tic Electric system does not have a major impact on performance.

Those generating units capable of burning more than one type of fuel have the conversion equipment avail-able should an unexpected change occur in the availability or cost of a particular fuel.

Fuel sources last year were 48% coal,

31% nuclear and 20% oil, with natural gas and interchange with other util-ities constituting the remainder.

During 1982, coal and nuclear were again the two most economical sources of power. Oil costs did level off, but remained high, and the price of natural gas was on the rise.

Atlantic Electric has built a flexible generating system, one that is designed to minimize the Company's dependence on imported oil. In 1973, at the time of the Arab oil embargo, over 70% of our customers' electrical needs came from oil. As a result of our aggressive conversion program, in 1983 we expect that less than 15% of these needs will come from oil.

13

14 Jerrold L. Jacobs, Senior Vice President-Finance, on Wall Street, en route to a meeting with a financial analyst.

Market Price Per Share of c.ommon Stock (year-aid)

(mdollars) 25 20 1S 10 5

0 Financial Stability he importance to the Company of adequate and timely rate relief was demonstrated dur-ing 1982 by the decline in earnings, but that issue should not overshadow other events. Atlantic Electric continues its efforts to improve financial stability by:

D Diversifying financing sources D Increasing the equity base D Seeking rate relief D Improving dividend performance Financing Sources. Construction requirements for 1982 were $118 million, up from $113 million the previous year. A significant positive development was that 42% of these needs were generated internally. The remainder of necessary capital was raised from a number of sources, including the sale of 2.1 million shares of common stock, floating rate notes and leasing of nuclear fuel.

Increased Equity. The long-term objective of reaching a minimum common equity ratio of 41% was achieved during 1982. One of the factors in reaching this important goal was the retirement (through repurchase) of $9.4 million of our outstanding Bonds. These purchases were made early in the year when interest rates were at peak levels.

The Company paid an average 57¢ on the dollar for these Bonds.

At year-end the Company had no outstanding short-term debt. Among the reasons for this were the recovery of deferred energy costs from cus-tomers, the public sale of common stock and the receipt of $21 million as a result of leasing our nuclear fuel.

In addition, we replaced some of our short-term debt with an issue of $45 million of floating-rate notes. The floating rate feature enabled the Company to reduce interest expense when market rates fell. Tax benefits on $2.9 million of assets were pur-chased from an unrelated company, which had a positive impact on Federal taxes paid. Sale of common stock included a public offering of 1.5 million shares and the issuance of over 487,000 shares through the Com-pany's Dividend Reinvestment and Stock Purchase Plan. Over 128,000 shares were sold through the Employee Stock Ownership Plan.

Rate Relief. Shortly after the deci-sion, in January 1982, of the last base-rate case, the Company filed for an additional base-rate increase of

$172.4 million. This request incorpo-rated the changes in our cost of service since 1980 and a number of forecasted items intended to reduce or eliminate regulatory lag. This would provide us with an opportunity to earn an appropriate rate of return.

The rate case proceeding lasted* most of the year, requiring extensive testi-mony to support our position and address current ratemaking policy issues. The decision by the BPU in December to grant us an increase of

$73.7 million fell short ofour needs.

Because that decision was based essentially upon the Company's financial performance during the period ending September 30, 1982 and did not include the items necessary to eliminate regulatory lag, we will not be able to earn the allowed 15%

return on common equity in 1983.

Dividend Performance. In June, 1982 the Board of Directors increased the dividend per share to 57¢ from 53¢ a quarter. This was the 30th year of paying higher dividends and marked the 64th year of dividend payments, accomplishments that are rivaled by few companies.

15

16 Michael A. Jarrett, Senior Vice President-Corporate Services, answers questions from customers during a radio talkshow.

Corporate Involvement ommunicating with the more than one million people who live and work in the Atlantic Electric service area continued to be of great importance. Regulators and leg-islators were key audiences. All three groups hold great influence over Atlantic Electric's future. During 1982, corporate involvement pro-grams were expanded in these areas:

D Residents of the service area D Government officials D Employees Residents. The indispensable nature of electricity and the increases in its cost in recent years have resulted in greater involvement by customers in the ratemaking process. They bring great pressure to bear on the regula-tors who make rate relief decisions.

For these reasons, the Company con-tinued and expanded its programs of citizen roundtable discussions, elec-tric safety and energy efficiency presentations, the Speakers' Bureau, student telephone conferences, media appearances and interviews.

A precedent-setting move during 1982 was the decision to commit $3.7 million to promoting energy conser-vation. This action grew out of rate relief proceedings before the Board of Public Utilities. The funds will be used to expand home and business energy audits, develop time-of-use pricing structures, finance rebates to consumers who purchase energy-effi-cient appliances and provide low-cost loans for home conservation improvements.

Regulators and Legislators. The pro-duction, cost and use of electrical energy is now an important social as well as an economic issue. Taking an active part in regulatory and legisla-tive developments has become a growing responsibility. For example, during 1982, legislation was consid-ered in New Jersey that would require a certification of need for new generating capacity. Atlantic Electric officers and managers contributed their expertise and opinions to the shaping of this bill, suggesting changes that would serve consumers as well as the utility industry.

Public involvement also crossed state lines. National matters relating to utilities range from Federal income tax benefits for dividend reinvest-ment plans, to environmental issues surrounding the generation of power, to technical aspects of disposing of spent nuclear fuel.

Employees. All of the Company's employees are encouraged to address issues involving their profession and Company. Many do so by writing letters to the media and government officials, providing testimony and participating in community organiza-tions. They act as private citizens, but are highly knowledgeable about the energy field.

" Breakfast with the President" has been the newest effort in the Com-pany's continuing programs to keep its workers well informed and moti-vated. The "Speak-up" program offers employees unrestricted oppor-tunities to voice their opinions and provide suggestions that are responded to by Management.

Corporate involvement is the catalyst for bringing all aspects of the Com-pany's activities to the attention of those who need, judge, regulate, operate and support Atlantic Elec-tric. During 1982, these audiences were reached with greater effective-ness and responded with increased understanding. For everyone, the result was greater efficiency, flexibil-ity, strength and involvement.

17

~anag~ment's J?~scussion and Analysis of Fmanc1al Condition and Results of Operations General As an investor-owned electric utility, Atlantic Electric is a participant in a capital intensive industry. In order to provide electric energy service to our customers, the Company has made an investment in property and plant of more than $1 billion. Electric energy rates to support the costs of owning, operating and maintaining this investment are regulated by the New Jersey Board of Public Utilities (BPU). Additional rate relief will be necessary to finance the Company's capacity and construction program, maintain service reliability and provide a fair rate of return on investment to our shareholders.

Liquidity and Capital Resources During 1980 through 1982, approximately 38% of the cash requireme.nts for construction, debt maturities and sinking fund requirements were generated from operations exclusive of unbilled revenues, after deductions for dividends, and working capital needs but exclusive of cha.nges in temporary cash investments. During the same penod a total of $290 million was obtained from the sales of First Mortgage Bonds and Pollution Control Bonds intermediate term borrowings, sale and leaseback of '

nuclear fuel, sales of common stock and preferred stock as 1982 Revenue Dollar Year to Date-December 31, 1982 well as issuance of common stock through the Company's Dividend Reinvestment and Stock Purchase Plan and Employee Stock Ownership Plan. Interim financing was provided by the issuance of short-term debt.

During 1982, cash construction expenditures aggregated

$1 18 million which is the highest ever experienced by the Company. However, the Company has made significant progress in the reduction of our construction program. The five year (1983-1987) cash construction expenditures are currently projected to be $382 million, reduced from the previously projected $716 million. This reduced level of projected construction expenditures is a direct result of the Company's revised capacity plan. Our current forecast of peak load growth for the period 1983-1997 is 1.6% per year.

This forecast reflects an aggressive program of promoting conservation, implementing effective load management techniques and promoting economic alternative energy

~ource s. The current construction program was developed m response to the need to replace existing plant, upgrade our transmission and distribution system, and provide for projected growth. Due to inflation and changes in technology, depreciation accruals are not adequate to fund the replacement of existing utility plant when necessary (see supplementary information concerning the effects of inflation, page 35).

Assuming adequate rate relief, our estimates indicate that over the five year period from 1983 to 1987 an average of at least 45% of our total cash construction requirements, debt Where It Came From

--------------- Industrial $.16

---

Residential $.47

---

Commercial $.35

_______________ Other $.02 Where It Went

~---------------Taxes $.17

- ------ Material and Supplies

$.13

---

Labor $.09

---

*----- Interest $.07 Preferred and Common Stock Dividends $.08

'---------------- Depreciation

$.06

---

Fuel and Purchased Power $.40

maturities and sinking fund requirements will be generated internally. The additional cash requirement will be raised through the capital markets with the objective of main-taining a capital structure of less than 48% long-term debt,

a minimum of 41% common equity with the balance com-posed of preferred stock. Our current capitalization ratios are 47% long-term debt, 42% common and 11% preferred stock. We will continue to use short-term financing on an interim basis and currently maintain total lines of credit of

$115,000,000. Refer to Note II of Notes to Financial Statements for additional details on short-term financing.

The tabulation on page 37 includes key indicators which we believe are helpful in evaluating the performance of the Company over the past five years. The tabulation also includes certain unaudited supplementary information showing estimates of the effects of changing prices. This data, which should be viewed as estimates of the approx-imate effects of inflation rather than as precise measures, is expressed in the dollars of the earliest comparative year (1978). The trends demonstrated reflect the need to control costs and point out the responsibility of regulatory agencies to provide timely and adequate rate relief. Additional supplementary information concerning the effects of changing prices is included on page 35.

Year-End Capitalization (%)

• Common Equity

• Preferred Stock

• Long term debt.

73 74 75 76 77 78 79 Results of Operations The costs of owning the Company's over $1 billion investment (original cost before accumulated depreciation) in property and plant (depreciation, taxes and cost of invested funds) were equivalent to 38% of operating revenues in 1982. Net energy and purchased power costs were 40% of operating revenues with labor, materials and other costs accounting for the remaining 22%.

Revenues Operating revenues have increased from $358 million in 1980 to $444 million in 1982. This increase reflects the net result of base rate increases, changes in the Levelized Energy Clause (LEC), the recording of unbilled revenue and a net decrease in kilowatt-hour sales. The effect of the above factors on 1982 and 1981 revenues is shown below:

(Thousands of Dollars) 1982 1981 Base Rate Increases

$ 10,021 2.1% $ 37,977 10.6%

LEC Rate Increase (Decrease)

(21,841) (4.6) 70,677 19.8 Kilowatt-hour Sales Increase (Decrease)

(6,890) (1.5) 2,638 0.7 Unbilled Revenues Current Year (6,795) (1.4)

($25,505) (5.4%)

$111,292 31.1 %

Additional changes in operating revenues will reflect general economic conditions in our service area, the timeliness and adequacy of rate relief and the results of load management and conservation programs.

100 80 60 40 20 0

19

Operating Expenses The aggregate of fuel, interchange and purchased power costs have decreased by 23% during 1982 reflecting the availability of lower cost nuclear generation, a shift in the Company's interchange power position and favorable purchases of capacity from other utilities which have resulted in less use of more expensive generation facilities and sources.

The following presents our progress toward greater use of lower cost energy sources:

1982 1981 1980 Sources:

¢/kwh

¢/kwh

¢/kwh Coal 48 2.573 45 2.177 37 1.504 Nuclear 31

.518 22

.384 21

.379 Oil 20 5.137 20 5.7 11 24 4.783 Natural Gas 3

5.133 4

5.249 8

4.191 Interchange (2)

(4.985) 9 7.529 10 5.987 100 2.457 100 3.083 100 2.73 1 Net Deferred Energy Costs of $23,273,000 in 1982 and

$14,043,000 in 1981 represent the recognition via increased revenues of unrecovered fuel costs which were deferred during 1980 and 1981. At December 31, 1982, all previously unrecovered LEC costs had been recovered. The amount of $15,869,000 shown on the Balance Sheet as Deferred Energy Revenues at December 31, 1982 represents an over-recovery of energy costs which is reflected in the current LEC billing rate (see Note 3 of Notes to Financial Statements).

Increases in power production and other operation and maintenance costs reflect increases in the price of materials, supplies and services as well as increases in wages and employee benefits.

Increases in depreciation expense reflect increased investment in depreciable plant.

New Jersey gross receipts taxes have increased in 1982 reflecting 1981 revenue increases. Such taxes are recognized as expenses in the year of payment.

Other Expenses Interest expenses have increased 38% since 1980 as a result of the continuation of historically higher interest rates.

Recent debt financing has been of an intermediate term in an effort to maintain financing flexibility in support of our reduced construction program. Even though we have made use of pollution control financing and intermediate term variable rate debt, the embedded cost of long term debt has risen, reflecting the refinancing of maturing debt at higher prevailing rates, from 8.01% in 1980 to 8.86%

in 1982.

Sources of Energy

(% of utility system)

Average Cost of Fuel in Cents Per Gallon Month of December (in billions of kilowatt-hours) 7.5

• Oil

• Gas

• Coal

• Nuclear 90

• Interchange

• Coal

• Gas

• Nuclear

• Oil 6.0 72 4.5 54 3.0 36 1.5 18 0

0 78 79 80 81 82

• Exported energy 20

Report of Management The financial statements presented herein have been prepared by management in conformity with Generally Accepted Accounting Principles applicable to rate-regulated public utilities. Such Accounting Principles are consistent in all material respects with the accounting prescribed by the Federal Energy Regulatory Commission and the New Jersey Department of Energy, Board of Public Utilities. In preparing the financial statements, management makes informed judgments and estimates relating to events and transactions that are currently being reported. The Company has established a system of internal accounting and financial controls and procedures designed to insure that the books and records reflect the transactions of the Company and that established policies and procedures are followed. This system is examined by management on a continuing basis for effectiveness and efficiency and is reviewed on a regular basis by an internal audit staff that reports directly to the Audit Committee of I the Board of Directors.

The financial statements have been examined by Deloitte Haskins & Sells, Certified Public Accountants. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of reported operating results and financial condition. Their examination includes procedures believed by them to provide reasonable assurance that the financial statements are not misleading and includes a review of the Company's system of internal accounting and financial controls and a test of transactions.

The Board of Directors has oversight responsibility for

' determining that management has fulfilled its obligation in the preparation of financial statements and the ongoing 1 examination of the Company's system of internal

• accounting control. The Audit Committee, which is composed solely of outside directors and reports to the Board of Directors, meets regularly with management, Deloitte Haskins & Sells and the internal audit staff to discuss accounting, auditing and financial reporting matters. The Audit Committee reviews the program of 1 audit work performed by the internal audit staff. To insure auditor independence, both Deloitte Haskins & Sells and the internal audit staff have complete and free access to

' the Audit Committee.

I Auditors' Opinion Deloitte Haskins & Sells Certified Public Accountants One World Trade Center New York, New York 10048 To the Shareholders and the Board of Directors of Atlantic City Electric Company:

We have examined the balance sheets of Atlantic City Electric Company as of December 31, 1982 and 1981 and the related statements of income and retained earnings and of changes in financial position for each of the three years in the period ended December 31, 1982. 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 accompanying financial statements present fairly the financial position of the Company at December 31, 1982 and 1981 and the results of its oper-ations and the changes in its financial position for each of the three years in the period ended December 31, 1982, in conformity with generally accepted accounting principles applied on a consistent basis, except for the change in 1982, with which we concur, in the method of accounting for unbilled revenues, as described in Note 4 to the financial statements.

January 31, 1983 21

Statement of Income and Retained Earnings For the Years Ended December 31 (Thousands of Dollars Except Per Share Amounts) 1982 1981 1980 Operating Revenues-Electric (Notes 3 and 4)

$444,178

$469,683

$358,391 Operating Expenses:

Energy Fuel 153,986 154,652 131,894 Interchange (7,459) 39,312 38,029 Deferred Costs 23,273 14,043 (20,281)

Net Energy 169,800 208,007 149,642 Purchased Power-Exclusive of Fuel 7,482 7,238 1,827 Power Production-Operation and Maintenance 44,650 36,206 28,819 I Other Operation and Maintenance 55,902 50,366 44,890 Depreciation 29,962 25, 161 23,593 Taxes Other Than Federal Income Taxes (Note 14) 60,548 44,200 35,546 Federal Income Tax Expense (Note 2) 13,064 24,994 17,841 I Total Operating Expenses 381,408 396,172 302,158 Operating Income 62,770 73,5 11 56,233 Other Income:

Allowance for Equity Funds U sect During Construction 3,354 6,045 4,997 Miscellaneous Income-Net 3,571 3,684 2,609 Total Other Income 6,925 9,729 7,606 Income Before Interest Charges 69,695 83,240 63,839 Interest Charges:

Interest on Long Term Debt 36,650 30,831 26,762 Interest on Short Term Debt 2,362 8,150 1,573 Other Interest Expense 633 1,323 321 Total Interest Charges 39,645 40,304 28,656 Allowance for Borrowed Funds U sect During Construction (5,079)

(4,052)

(3,355)

Net Interest Charges 34,566 36,252 25,301 Income Before Cumulative Effect of Change in Accounting Method 35,129 46,988 38,538 Cumulative Effect to January 1, 1982 of Change in Accounting Method, Net of Federal Income Taxes ($11,863) (Note 4) 13,926 Net Income 49,055 46,988 38,538 Retained Earnings at Beginning of Year 121,078 108,977 100,697 170,133 155,965 139,235 Dividends Declared:

On Cumulative Preferred Stock 7,353 7,508 6,340 On Common Stock 33,955 27,379 23,918 Total Dividends Declared 41,308 34,887 30,258 Retained Earnings at End of Year

$128,825

$121,078

$108,977 Earnings for Common Stock:

$ 38,538 I Net Income

$ 49,055

$ 46,988 Less Preferred Dividend Requirements 7,368 7,531 6, 161 Balance Available for Common Stock

$ 41,687

$ 39,457

$ 32,377 Average Number of Shares of Common Stock Outstanding (Thousands) 15,116 13,034 12,372 Per Common Share:

Earnings Before Cumulative Effect of Change in Accounting Method 1.84 3.03 2.62 Cumulative Effect to January 1, 1982 of Change in Accounting Method

.92 Total Earnings 2.76 3.03 2.62 '

Dividends Declared 2.24 2.08 1.93 Dividends Paid 2.20 2.04 1.90 The accompanying Notes to Financial Statements are an integral part of these statements.

22

Statement of Changes in Financial Position For the Years Ended December 31 (Thousands of Dollars) 1 Source of Funds:

1 Funds from Operations:

Income Before Cumulative Effect of Change in Accounting Method Principal Non-Cash Charges (Credits) to Income:

Depreciation Amortization of Nuclear Fuel Allowance for Funds Used During Construction Deferred Federal Income Taxes-Net Investment Tax Credit Adjustments-Net Other-Net Funds from Operations Cumulative Effect of Change in Accounting Method

' Funds from Outside Sources:

Long Term Debt Pollution Control Funds (Held) Released by Trustees Subtotal Sale of Common Stock Sale of Preferred Stock Sale of Nuclear Fuel Increase (Decrease) in Short Term Debt Funds from Outside Sources 1 Other-Net Total Source of Funds I Application of Funds:

Gross Additions to Utility Plant Property Abandonment Costs 1 Allowance for Funds Used During Construction Net Dividends on Preferred Stock Dividends on Common Stock Retirement and Maturity of Long Term Debt Property Abandonment Costs Conversion of Preferred Stock I Redemption of Preferred Stock Investments in Subsidiary Companies Increase (Decrease) in Working Capital*

Total Application of Funds Increase (Decrease) in Working Capital*

Cash and Cash Items Accounts Receivable Unbilled Revenues Fuel Materials and Supplies Deferred Energy Costs and Revenues Accounts Payable

• Taxes Accrued Accumulated Deferred Taxes Other Increase (Decrease) in Working Capital 1982 1981

$ 35,129

$ 46,988 29,962 25,161 4,863 2,951 (8,433)

(10,097) 11,427 14,648 12,547 7,141 650 458 86,145 87,250 13,926 45,000 60,000 15,098 (27,874) 60,098 32,126 41,166 32,441 21,140 (25,825) 10,525 96,579 75,092 3,413 (3,451)

$200,063

$158,891

$126,893

$123,318 (15,956)

(8,433)

(10,097) 118,460 97,265 7,353 7,508 33,955 27,379 28,996 5,682 15,956 847 1,993 800 800 126 (96) 9,526 2,404

$200,063

$158,891

$ 13,286

$ 3,845 (7,275) 10,740 18,994 (2,645) 5,890 (420) 2,365 (39,046)

(14, 104) 3,923 2,959 8,512 (5,285) 7,508 3,894 6,689 (7,900)

$ 9,526

$ 2,404

• Excludes Short Term Debt, Notes and Current Maturities of Long Term Debt and Cumulative Preferred Stock Subject to Mandatory Redemption.

The accompanying Notes to Financial Statements are an integral part of these statements.

1980

$ 38,538 23,593 1,595 (8,539) 6,158 5,045 422 66,812 75,000 75,000 6,514 20,000 (24,175) 77,339 (717)

$143,434

$ 97,330 (8,539) 88,791 6,340 23,918 23,847 877 1,600 320 (2,259)

$143,434 (889) 6,727 1,422 1,500 18,741 (11,202)

(4,587)

(6,500)

(7,471)

$ (2,259) 23

Balance Sheet December 31 (Thousands of Dollars)

Assets Electric Utility Plant (Note 6):

In Service:

Production Transmission Distribution General Total Less Accumulated Depreciation Net Construction Work in Progress Nuclear Fuel (Notes 1 and 6)

Less Accumulated Amortization Net Electric Utility Plant-Net Non Utility Property and Investments (Note 7)

Pollution Control Construction Funds Unexpended-Held by Trustees Current Assets:

Cash and Working Funds (Note 11)

Temporary Cash Investments Accounts Receivable:

Utility Service Miscellaneous Allowance for Doubtful Accounts Unbilled Revenues (Note 4)

Fuel (at average cost)

Materials and Supplies (at average cost)

Prepayments Deferred Energy Costs (Notes 1 and 3)

Total Current Assets Deferred Debits:

Property Abandonment Costs (Notes 1 and 12)

Unamortized Debt Expense Other Total Deferred Debits Total Assets The accompanying Notes to Financial Statements are an integral part of these statements.

24 1982 1981

$ 492,415

$ 422,162 170,297 154,418 300,079 280,842 37,632 20,274 1,000,423 877,696 247,008 225,372 753,415 652,324 152.403 158,995 495 28,237 7,692 495 20,545 906,313 831,864 6,432 5,537 12,776 27,874 3,752 2,915 18,249 5,800 25,967 35,410 8,037 5,669 (1,200)

(1,000) 18,994 26,931 29,576 16,221 16,641 9,382 3,771 23,177 126,333 121,959 19,680 19,934 3,257 3,598 3,178 3,023 26,115 26,555

$1,077,969

$1,013,789

December 31 (Thousands of Dollars)

Liabilities and Capitalization Capitalization:

Common Shareholders' Equity:

Common Stock (Note 8)

Premium on Capital Stock Capital Stock Purchase Plan Capital Stock Expense Retained Earnings Total Common Shareholders' Equity Cumulative Preferred Stock Not Subject to Mandatory Redemption (Note 9)

Cumulative Preferred Stock Subject to Mandatory Redemption (Note 9)

Long Term Debt (Note 10)

Total Capitalization Current Liabilities:

Current Portion:

Cumulative Preferred Stock Subject to Mandatory Redemption (Note 9)

Long Term Debt (Note 10)

Notes Payable to Banks (Note 11)

Commercial Paper (Note 11)

Accounts Payable Taxes Accrued Interest Accrued Dividends Declared Deferred Energy Revenues (Notes I and 3)

Customer Deposits Accumulated Deferred Taxes (Notes l and 2)

Other Total Current Liabilities Deferred Credits:

Accumulated Deferred Investment Tax Credits (Notes l and 2)

Accumulated Deferred Federal Income Taxes (Notes I and 2)

Other Total Deferred Credits Commitments and Contingent Liabilities (Note t 2)

Total Liabilities and Capitalization 1982 1981 49,722 43,284 195,293 160,499 48 78 (1,738)

(1,730) 128,825 121,078 372,150 323,209 42,684 43,531 54,400 55,200 368,220 371,769 837,454 793,709 800 800 39,050 19,620 7,500 18,325 21,946 25,869 4,468 12,980 5,800 5,757 11,278 9,509 15,869 2,757 2,810 8,737 16,245 4,668 7,505 115,373 126,920 49,272 36,725 64,936 53,509 10,934 2,926 125,142 93, 160

$1,077,969

$1,013,789 25

Notes to Financial Statements Note 1. Significant Accounting Policies:

Regulation. The accounting and rates of the Company are subject to the regulations of the State of New Jersey, Department of Energy, Board of Public Utilities (BPU) and in certain respects to the Federal Energy Regulatory Commission (FERC). All significant accounting policies and practices used in the determination of rates are also used for financial reporting purposes. The financial statements are prepared on the basis of the Uniform System of Accounts prescribed by FERC.

Operating Revenues. Prior to 1982, revenues were recognized when electric energy service bills were rendered to customers. As of January 1, 1982 the Company changed its method of accounting to recognize revenues for services rendered subsequent to the last billing cycle and prior to the end of the period. See Note 4 for additional.information concerning this accounting change.

Electric Utility Plant. Property is stated at original cost.

Generally the plant is subject to a first mortgage lien. The cost of property additions, including replacement of units of property and betterments, is capitalized. Included in certain additions is an Allowance for Funds Used During Construction (AFDC) which is defined in the applicable regulatory systems of accounts as the net cost during the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. AFDC has been calculated using a rate of 8.5% for 1982, as ordered by the BPU (See Note 3), and 8%

for 1981 and 1980. Such rates are less than the maximum allowed by the FERC.

Deferred Energy Costs and Revenues. The Company has a Levelized Energy Clause (LEC) which utilizes projected energy costs and includes a provision for prior period under or over recoveries. The recovery of energy costs is made through levelized monthly charges over the period of projection. Any under or over recoveries are deferred in balance sheet accounts as a current asset or current liability as appropriate. Such deferrals are recognized in the Statement of Income in the period in which they are subsequently recovered through the LEC.

Depreciation and Maintenance. The Company provides for straight-line depreciation based on the estimated remaining life of transmission and distribution property and, based on the estimated service life, for all other depreciable property. Depreciation applicable to nuclear plant includes certain amounts for decommissioning. The overall composite rate of depreciation was approximately 3.3% for 1982, 1981 and 1980. Accumulated depreciation is charged with the cost of depreciable property units retired together with removal costs less salvage and other recoveries.

26 Nuclear Fuel. The Company's amortization of Salem Units No. 1 & 2 nuclear fuel is based on a rate using the number of units of thermal energy produced during the life of the fuel, plus a factor representing the estimated future costs of storage and disposal of spent nuclear fuel (See Note 6).

Nuclear fuel requirements for Peach Bottom Units No. 2 and 3 are being provided by the operating company for Peach Bottom through a fuel purchase contract. The Company is responsible for payment of its proportionate interest of the cost of the fuel consumed during the term of the contract. Beginning in 1982, amounts were provided for a portion of the estimated future costs of storage and disposal of spent nuclear fuel.

Federal Income Taxes. Deferred Federal Income Taxes are provided on depreciable property added after 1973, but before January 1, 1981, for the difference between tax accelerated and tax straight-line depreciation under the ADR system. Tax reductions relating to the difference between tax straight-line and book depreciation are reflected currently (flowed-through) in Federal Income Tax Expense as allowed by the BPU.

For all property placed in service after December 31, 1980, the Company provides deferred Federal Income Taxes for the difference between tax depreciation computed using the Accelerated Cost Recovery System (ACRS) under the Economic Recovery Tax Act of 1981, and tax straight-line depreciation computed using book lives.

In addition, the Company provides deferred Federal Income Taxes relating to the deferral of energy costs, unbilled revenues and, up to December 31, 1980, the use of the repair allowance provisions of ADR. Investment Tax Credits are deferred on the balance sheet and are restored to income over the life of the related property.

Gains on reacquired debt are recognized currently for book purposes and as a reduction of property accounts for tax purposes. Therefore, such gains result in reduced tax depreciation expense over the lives of the property.

Accordingly, the Company provides related deferred Federal Income Taxes on its books.

Retirement Plan. The Company has in effect a non-contributory defined benefit retirement plan covering all regular employees. Concurrent with a 1979 amendment, the Board of Directors established a funding policy providing for direct payment, from plan assets, of retirement benefits relating to services on or subsequent to January 1, 1979. (Benefits were previously provided by the purchase of individual annuities upon the retirement of Plan participants.) Such funding arrangements were also

extended to service prior to January 1, 1979 for those employees consenting to the change. Costs of the plan are

, determined under the aggregate cost method.

Property Abandonment Costs. These costs consist of the Company's unamortized investment in Hope Creek Unit No. 2, a nuclear generating unit which was cancelled in December, 1981, and four off-shore nuclear units which were cancelled in December, 1978.

Note 2. Federal Income Taxes:

Federal income tax expense applicable to current operations is less than the amount computed by applying Years Ended December 31 (Thousands of Dollars) 1 Net Income Federal Income Tax Expense (as below)

Book Income Subject to Tax Income Tax at Statutory Rate (46%)

Less:

Allowance for Funds Used During Construction Capitalized Overheads Investment Tax Credits-Used Other Total Federal Income Tax Expense Federal Income Tax Expense is comprised of the following:

Federal Income Tax Currently Payable 1 Deferred Federal Income Taxes (as below)

Investment Tax Credit-Earned Investment Tax Credit-Used Federal Income Tax Expense included in Operating Expenses Deferred Federal Income Taxes on the Cumulative Effect of Change in Accounting Method (as below)

Federal Income Tax Expense Federal Income Tax-Other Income:

Currently Payable Deferred (as below)

Total Total Federal Income Tax Expense Deferred Federal Income Taxes result from the following timing differences:

Liberalized Depreciation Repair Allowance Amortization-Accelerated Depreciation, Repair Allowance and Property Abandonment Costs Property Abandonment Costs Gains on Reacquired Debt and Purchased Tax Benefits Other Total Current Liabilities:

Deferred Energy Costs Deferred Revenue Unbilled Revenues Total Deferred Federal Taxes The Hope Creek No. 2 investment will be amortized over a 15 year period beginning in 1983. The off-shore nuclear units are being amortized over a 20 year period.

Other. Capital Stock expense is being amortized on a ratable basis over 20 years.

Debt premium, discount and expenses are amortized over the life of the related debt.

the statutory rate on book income subject to tax for the following reasons:

1982 1981 1980

$49,055

$46,988

$38,538 27,004 27,332 19,700

$76,059

$74,320

$58,238

$34,987

$34,187

$26,789 3,879 4,645 3,842 1,301 1,242 1, 179 1,485 1,075 914 1,318 (107) 1,154

$27,004

$27,332

$19,700

$ (1,430)

$13,124

$ (667) 78 4,438 12,657 15,901 8,507 6,765 (1,485)

(1,075)

(914) 13,064 24,994 17,841 11,863 24,927 24,994 17,841 (242) 826 1,859 2,319 1,512 2,077 2,338 1,859

$27,004

$27,332

$19,700

$ 9,879

$ 6,195

$ 4, 189 2,551 (692)

(708)

(625) 6,700 2,319 1,512 (79) 949 43 11,427 14,648 6, 158 (10,661)

(6,488) 8,620 4,757 (2,210)

(2, 121) 8,737

$14,260

$ 5,950

$12,657 27

28 Financial Notes continued Investment tax credit earned in 1982, 1981 and 1980 includes $1,869,000, $291,000 and $806,000 respectively, representing the Company's use of the additional investment tax credit available under the Tax Reduction Act of 1975.

The Company has purchased tax benefits on equipment having an aggregate tax basis of approximately $2,900,000 in 1982 and $2,600,000 in 1981. Such tax benefits include 6% investment tax credit and an ACRS life of 3 years.

Note 3. Rate Increases:

During the three year period ended December 31, 1982 base rate increases have been approved by the BPU as follows, based in each case on the applicable test year indicated:

Amount Date Req_uested Date Petition (millions)

Effective November 1979

$ 85.7(1)

Sept. 26, 1980 August 1981 Jan. 29, 1982 February 1982 172.4(2)

Dec. 14, 1982 (I) The Company's request included $16, 100,000 (including disposal co ts) to recognize the cost of owning and operating its share of the Salem Unit No. 2 Nuclear Generating Station. This amount was revised to 14,400,000 (excluding disposal costs) in August 1981 during a second On December 6, 1982 the BPU granted the Company an increase of $73,700,000 in base rates. The increase is equivalent to approximately 16% of the Company's 1982 revenues. The BPU decision granted an overall return of 11.7% with a return on common equity of 15% and allowed the Company to amortize the abandonment costs associated with Hope Creek No. 2 ratably over a 15 year period without a return on the unamortized balance. In reaching its decision the BPU computed the Company's revenue requirement by reducing the Company's rate base to reflect deferred taxes associated with unbilled revenues as if the Company had accrued unbilled revenues on its books during the test year. This rate base reduction lowered the rate increase granted to the Company.

Further, the BPU directed the company to change its accounting treatment to record unbilled revenues as of the time service is furnished (See Note 4). In addition,the BPU increased the Company's AFDC rate from 8% to 8.5%.

The BPU has granted a second phase of the base rate proceeding to review the Company's load forecast and capacity plans and the revenue requirements associated with the Company's purchase of capacity and energy from Pennsylvania Power & Light's Susquehanna Unit No. I, which is expected to begin commercial service in May 1983. The second phase would also review residential customer service charges and revenue requirements associated with land held for future use. The Company The Company's federal income tax returns for 1979 and prior years have been examined by the Internal Revenue Service and the Company's federal income tax liabilities for all years through 1976 have been determined and settled. In January 1983, the Company received a revenue agent's report in which certain deficiencies in tax have been proposed for the years 1977 through 1979. The Company intends to protest the proposed deficiencies and is of the opinion that the final settlement of its federal income tax liabilities for these years will not have a material adverse effect on its results of operations or financial position.

Amount Approved Increase Test (millions)

In Revenue Year

$50.6 16.0%

June30, 1980 11.3 June 30, 1980 73.7 15.0%

Sept. 30, 1982 phase of the case.

(2) The request was updated to $162.500,000 after the actual data for the test year was reported.

cannot presently predict the final outcome of these proceedings or the effect, if any on the Company.

Effective October I, 1981 the BPU ordered a separate base rate and a separate marginal energy adjustment clause (MEC) for casino hotels in Atlantic City. The effect of this change by the BPU is to increase the rates for such customers with a corresponding reduction in the rates paid by all other customers. The casino hotels are seeking further proceedings before the BPU and have filed appeals in the courts on this issue. The Company cannot presently predict the final outcome of these proceedings or the effect, if any, on the Company.

In December 1981, the Company proposed a reduction in its LEC based on declining unrecovered energy costs and a slight decrease in the projected 1982 total cost of energy.

During 1982 the BPU ordered reductions in the Company's annual LEC revenues of approximately $159,000,000. The BPU also ordered an interim annual reduction in MEC revenues of approximately $2,000,000 in January 1982, followed by an annual increase of approximately

$5,000,000 in August 1982. The combination of the LEC decreases, the MEC net increase and the January, 1982 base rate increase of $11,300,000 resulted in a $145,000,000 aggregate annual reduction in the Company's rates in 1982.

On January 13, 1983, the BPU ordered a 1983 reduction in MEC revenues of approximately $6,000,000 on an annual basis and a continuation of the LEC at its present level.

Note 4. Change in Accounting for Revenues:

As a part of the December, 1982 rate decision (See Note 3) the BPU directed the Company to adopt a policy of recording revenues based on service rendered to the end of the period. The Company adopted this accounting change in 1982.

As required by generally accepted accounting principles, the adoption of this change in accounting has been effected as of the beginning of the accounting period (January I, 1982). Prior to this change, the Company recognized revenues when bills were rendered to customers based on monthly cycle meter readings. In recording unbilled

• revenues, the Company estimates the revenues associated Note 5. Retirement Plan:

The cost to the Company in providing a retirement plan for its employees was $5,908,000, $5,476,000 and $4,652,000 in 1982, 1981 and 1980, respectively. Approximately 80% of these costs were charged to operating expense and the remaining 20%, which was associated with construction labor, was charged to the cost of new utility plant.

A comparison of accumulated plan benefits and plan net assets (including purchased annuity contract amounts) for the Company's Plan, as of the most recent actuarial valuation dates, is as follows:

Note 6. Jointly-Owned Generating Stations and Nuclear Fuel:

The Company participates with other utilities in the construction and operation of several jointly-owned electric production facilities.

with service rendered from the time the meters were last read to the end of the period. The implementation of this change in accounting reduced the current year's income before the cumulative effect of such change by $3,669,000

($.24 per share) after the related income taxes of

$3,126,000. See Note 15 for restated 1982 quarterly earnings. The cumulative effect of this change as of January I, 1982 amounts to $13,926,000 (after the related provision for federal income taxes of $11,863,000) and is separately identified in the 1982 Statement of Income and Retained Earnings. Allocation of the cumulative effect to prior years would not materially change previously reported earnings for 1981 or 1980.

January I (Thousands of Dollars) 1982 1981 Actuarial present value of accumulated plan benefits:

Vested

$72,156

$67,810 Non vested 1,495 1,370 Total

$73,651

$69, 180 Net Assets available for benefits

$85,823

$83,989 The weighted average assumed rate of return used in determining the actuarial present value of accumulated plan benefits was 7%. The Company's Plan is in compliance with the Employee Retirement Income Security Act of 1974.

The amounts shown represent the Company's share of each jointly-owned plant at December 31, and includes an allowance for funds used during construction.

Electric Plant Construction Energy Company's in Service Work in Progress Generation Station Source Share 1982 1981 1982 1981 1982 1981 (Thousands of Dollars)

(KWHs)

Keystone Coal 2.47%

$ 5,808

$ 5,752 495 173 261,237 213,104 Conemaugh Coal 3.83 11,547 11,189 92 165 273,738 290,209 Peach Bottom Nuclear 7.51 72,584 63,778 1,587 7,438 996,769 730,034 Salem( I)

Nuclear 7.41 145,505 140,849 4,140 3,647 883,903 577,113 Hope Creek(2)

Nuclear 5.00 99,555 72,207 (I) Salem Unit 2 was placed in commercial operation in October, 1981.

(2) Hope Creek Unit 2 was cancelled in December 1981 (See Note 12).

29

Financial Notes continued The Company provides its own financing during the construction period for its share of the jointly-owned plants and includes its share of direct operations and maintenance expenses in its Statement of Income.

In November 1982 the Company sold, at no gain or loss, nuclear fuel materials, which were in use or in preparation for use at the Salem and Hope Creek generating stations, aggregating $21, 140,000 to a lessor for subsequent Note 7. Investment in Subsidiary Companies:

The Company's investment in Deepwater Operating Company (Deepwater), a wholly-owned subsidiary which operates generating and process steam units owned by the Company, was $2,841,000 at December 31, I 982 and 1981.

The principal asset of Deepwater is working capital in which the equity of the Company is fairly represented by its investment. The net production costs of Deepwater Note 8. Common Stock:

As of December 31, 1982 and 1981, the Company's Common Stock included 25,000,000 and 18,000,000 Beginning of Year Sale of Common Stock Dividend Reinvestment and Stock Purchase Plan Employee Stock Ownership Plan Conversion of Preferred Stock Shares at end of year At $3 Par Value Premium on Capital Stock was credited in 1982, 1981 and 1980 with $34,793,441, $26,785,552 and $5,428,822 respectively representing the excess of proceeds over the par value of shares of Common Stock issued, sold and converted. At December 31, 1982 there were 1,053,168 shares of Common Stock authorized for issuance pursuant Note 9. Cumulative Preferred Stock:

The Company has authorized 799,979 shares of Cumulative Preferred Stock, $100 Par Value, 2,000,000 shares of Cumulative Preferred Stock, No Par Value, and 3,000,000 shares of Preference Stock, No Par Value. Unissued 30 leaseback. Energy production based lease payments of

$522,736 were charged to fuel expense for November and December, 1982. Under this agreement, the Company continues to have responsibility for management of the fuel. Under certain conditions of termination, the Company will be required to purchase all nuclear fuel then existing at a price which will allow the lessor to recover its net investment costs.

(after deducting contract charges) are charged to the Company. These costs are included in the Company's accounts classified as to operation, maintenance and taxes. '

The Company also has an investment in Atlantic Housing, Inc. (Housing), a wholly-owned subsidiary, which amounted to $946,987 and $820,538 at December 31, 1982 and 198 I, respectively. Housing's principal investment is a 20% undivided interest as tenant in common in a future generating station and industrial site.

authorized shares of Common Stock ($3 par value),

respectively. Shares issued and outstanding:

1982 1981 1980 14,427,990 12,538,880 12, 196,486 1,500,000 I,500,000 487,601 302,726 257,095 128,797 16,641 54,616 29,633 69,743 30,683 16,574,021 14,427,990 12,538,880

$49,722,063

$43,283,970

$37,616,640 to its Dividend Reinvestment and Stock Purchase Plan which became effective in 1976 and 223,841 shares of Common Stock authorized for issuance pursuant to its Employee Stock Ownership Plan. At December 31, 1982 93,970 shares of Common Stock were reserved for the conversion of S7/s% Convertible Series of Preferred Stock.

shares may, or may not, possess mandatory redemption characteristics upon issuance. In certain circumstances, if dividends on issued Cumulative Preferred Stock are in arrears voting rights for the election of a majority of the Board of Directors becomes operative.

Note 9(A).

Cumulative Preferred Stock Not Subject To Mandatory Redemption:

December 31

$100 Par Value-Cumulative and Non-participating shares issued and outstanding:

Series:

4%

77,000 Shares 4.10% 72,000 Shares 4.35%

15,000 Shares 4.35% 36,000 Shares 4.75% 50,000 Shares 5.0%

50,000 Shares S7/s% Convertible Series:

26,844 Shares (1982) 35,313 Shares (1981 )

7.25% 100,000 Shares Total Note 9(B).

Current Redemp-tion Price 1982 198 1 Per Share (Thousands of Dollars)

$ 7,700

$ 7,700

$105.50 7,200 7,200 101.00 1,500 1,500 101.00 3,600 3,600 101.00 5,000 5,000 101.00 5,000 5,000 100.00 2,684 103.00 3,531 10,000 10,000 104.89

$42,684

$43,531 Cumulative Preferred Stock Not Subject to Mandatory Redemption is redeemable solely at the option of the Company upon payment of the redemption price plus accumulated and unpaid dividends to the date fixed for redemption. Premium on such Preferred Stock was $93,000 at December 31, 1982 and 1981.

The 5Vs% Convertible Series, of which 8,467, 19,927 and 8,767 shares were converted in 1982, 1981 and 1980 respectively, is convertible (subject to adjustment in certain events) into Common Stock at the rate of 3.5 shares of Common Stock for each share of Preferred.

Cumulative Preferred Stock Subject To Mandatory Redemption:

Par December 31 Current Redemption Price Per Share Refunding Restricted Prior to Value 1982 1981 (Thousands of Dollars)

Shares Issued and Outstanding:

Series:

8.40%

100,000 Shares

$100

$10,000 9.96%

152,000 Shares (1982) 100 15,200 160,000 Shares (1981 )

100

$8.25 100,000 Shares None 10,000

$9.45 200,000 Shares None 20,000 55,200 Less Portion due within one year 800 Total

$54,400 On August I, annually 8,000 shares of the 9.96% Series must be redeemed through the operation of a sinking fund at a redemption price of $100 per share. At the option of the Company, an additional 8,000 shares may be redeemed on any sinking fund date, without premium, up to 40,000 shares in the aggregate. The Company redeemed 8,000 shares at par in both 1982 and 1981.

On November I, 1983, and annually thereafter, 2,500 shares of the $8.25 No Par Preferred Stock Series must be redeemed through the operation of a sinking fund at a redemption price of $100 per share. At the option of the Company, an additional number of shares not to exceed 2,500 may be redeemed on any sinking fund date without premium.

$10,000

$115.00 107.14 August I, 1984 16,000 10,000 20,000 107.20 November 1, 1987 November 1, 1989 56,000 800

$55,200 On February I, 1985, and annually thereafter, 4,000 shares of the 8.40% Series must be redeemed throught the operation of a sinking fund at a redemption price of $100 per share. At the option of the Company, an additional 4,000 shares may be redeemed on any sinking fund date without premium, up to 32,000 shares in the aggregate.

On November I, 1986, and annually thereafter, 40,000 shares of the $9.45 No Par Preferred Stock Series must be redeemed through the operation of a sinking fund at a redemption price of $100 per share. At the option of the Company, an additional 40,000 shares may be redeemed on any sinking fund date, without premium, up to 50,000 shares in the aggregate.

31

Financial Notes continued The minimum sinking fund provisions of the above series aggregate $1,050,000 in 1983 and 1984, $1,450,000 in 1985, and $5,450,000 in 1986 and 1987.

Note 10. Long Term Debt:

December 31 (Thousands of Dollars) 1982 1981 First Mortgage Bonds:

31/4% Series due (March I) 1982

$ 4,620 3V4% Series due (January I) 1983 4,050 4,050 91/4% Series due (May I) 1983 35,000 35,000 3% Series due (March I) 1984 5,000 5,000 9% Pollution Control Series due (May I) 1984 21,000 21,000 3V4% Series due (March I) 1985 10,000 10,000 4V2% Series due (January I) 1987 10,000 10,000 37/s% Series due (April I) 1988 10,000 10,000 4V2% Series due (April I) 1989 2,775 5,000 4V2% Series due (March I) 1991 10,000 10,000 41/2% Series due (July I) 1992 10,350 12,350 43/s% Series due (March I) 1993 9,540 13,500 5Vs% Series due (February I) 1996 9,980 9,980 87/s% Series due (September I) 2000 19,000 20,000 8% Series due (May I) 2001 27,000 27,000 7'/2% Series due (April I) 2002 20,000 20,000 7314% Series due (June I) 2003 29,976 30,000 75/s% Pollution Control Series due (January I) 2005 6,500 6,500 63/s% Pollution Control Series due (December I) 2006 2,500 2,500 125/s% Series due (January I) 2010 75,000 75,000 I P/s% Pollution Control Series due (May I) 2011 39,000 39,000 356,671 370,500 Debentures:

5V4% Sinking Fund Debentures due (February 1) 1996 2,267 2,267 7V4% Sinking Fund Debentures due (May I) 1998 2,619 2,786 4,886 5,053 Notes-7.90% Notes due (December

15) 1982 15,000 Variable Rate Notes due (April 30) 1986 45,000 45,000 15,000 Unamortized Premium and Discount-Net 713 836 407,270 391,389 Deduct First Mortgage Bonds and Notes due within one year (39,050)

(19,620)

$368,220

$371,769 32 Deposits in sinking funds for retirement of debentures are required on February l of each year through 1995 for the 5Y4% debentures, and on May l of each year through 1997 for the 7Y4% debentures in amounts in each case sufficient to redeem $100,000 principal amount plus at the election of the Company, up to an additional $100,000 principal amount in each year. At December 31, 1982 the Company had reacquired and cancelled $1,533,000 principal amount of the 5Y4% debentures and $1,381,000 principal amount of the 7Y4% debentures toward its requirements for 1983 and subsequent periods. During 1982 the Company reacquired,

at amounts below par value, $9,376,000 principal amount of First Mortgage Bonds and Debentures. This reacquisition resulted in a gain, net of Federal income taxes and expenses, of $1,816,000.

The aggregate amount of debt maturities and sinking fund requirements of all First Mortgage Bonds outstanding at December 31, 1982 are $39,050,000 in 1983, $26,000,000 in 1984, $10,000,000 in 1985, $48,000,000 in 1986 and

$13,000,000 in 1987. Current sinking fund requirements of

$940,500 in connection with certain first mortgage bonds outstanding are being satisfied by certification of property additions as provided for in the related mortgage indentures.

The amounts of $2,785,000 and $1,537,000 as of December 31, 1982 and 1981, respectively, which represent unexpended investment earnings on pollution control construction funds held by trustees, are included in Miscellaneous Accounts Receivable. Such amounts are restricted for use on the related pollution control projects.

Note 11. Short Term Debt and Compensating Balances:

As of December 31, 1982, the Company had bank lines of credit available for use of $115,000,000. The Company is required, with respect to $17,000,000 of these credit lines, to maintain average compensating balances of $850,000 plus an equivalent additional amount if these lines are fully utilized. These compensating balances are maintained in demand deposits which are not legally restricted. The Company is in compliance with such compensating balance arrangements. With respect to the remaining available credit lines of $98,000,000 the Company pays commitment fees ranging from 3/s% to Y2% which aggregated $390,000 for 1982 and $401,000 for 1981. Certain other information regarding short term debt follows:

(Thousands of Dollars) 1982 1981 1980

' As of end of year-Weighted average interest rate for short term debt outstanding:

Commercial Paper 12.2%

18.3%

Notes Payable to Banks 12.8%

19.3%

For the year ended-Maximum amount of total short term debt at any month-end:

Commercial Paper

$22,000

$62,475

$16,725 Notes Payable to Banks

$ 3,000

$ 7,500 $ 3,500 Average amount of short term debt (based on daily outstanding balances):

Commercial Paper

$10,550 $43,284

$ 8,879 Notes Payable to Banks

$ 4,497

$ 3,661

$ 1,810 Weighted daily average interest rates on short term debt:

Commercial Paper 12.8%

16.4%

11.4%

Notes Payable to Banks 13.7%

16.7%

13.1%

Note 12. Commitments and Contingencies:

Total construction expenditures for 1983 are estimated at approximately $84,000,000. Commitments for the construction of major production and transmission facilities amount to approximately $145,000,000 of which it is estimated approximately $24,000,000 will be expended in 1983. These amounts exclude allowances for funds used during construction.

The Company's insurance coverages applicable to its participation in four nuclear units are as follows:

Type and Source of Coverage Public Liability:

Private Federal government (I)

Property Damage:

Nuclear Mutual Limited (4)

Nuclear Electric Insurance Limited (4)

Replacement Power:

Nuclear Electric Insurance Limited (4)

Maximum Retrospective Maximum Assessment for a Coverage single incident (Millions of Dollars)

$160 None 400

$1.5 (2)

$560 (3)

$500

$4.2

$400

$1.4

$ 2.5 (5)

$2.3 (I) Retrospective premium program under the Price-Anderson liability provisions of Atomic Energy Act of 1954 as amended. Subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States.

(2) Maximum assessment would be $3,000,000 in the event of more than one accident in any year.

(3) Limit of liability under the Atomic Energy Act of 1954 for each nuclear incident.

(4) Utility-owned mutual insurance company of which the Company is a member. Subject to retrospective assessment with respect to loss at any nuclear generating station insured by the mutual insurance company.

(5) Maximum weekly indemnity for 52 weeks which commences after the first 26 weeks of an outage. Also provides $1,250,000 weekly for an additional 52 weeks.

The Company has a five-year agreement expiring May 31, 1985, with Delmarva Power & Light (DP&L) for the purchase of 50 MW of power from the output of DP&L's coal-fired Indian River Unit No. 4. The Company and Pennsylvania Power & Light Company (PP&L), have entered into an agreement whereby the Company will purchase 5.94% of the net capacity and energy output of 33

Financial Notes continued each of two PP&L 1050 MW nuclear generating units scheduled to be placed in service in the second quarter of 1983 and the fourth quarter of 1984, respectively. The purchase of power from PP&L will commence with commercial operation of the units and continue through September 30, 1991.

In 1981, the Company entered into an agreement with the Allegheny Power System (APS) which entitles the Company to 50 MW of coal-fired capacity from the APS Pleasants Station in St. Mary's, West Virginia for the years 1982 through 1985. This agreement has been modified for the years 1983 and 1984 to provide the Company access to a cogeneration source on an APS subsidiary's operating system. In addition, the Company has a commitment from Public Service Electric and Gas Company (PSE&G) to provide up to 125 MW of power for the years 1992 through 1995.

The Company's planned $770 million, 290 MW coal-fired Cumberland Unit No. I, which was to go in service in the fall of 1991, has been deferred beyond the Company's planning horizon as a result of a revised load forecast which reflected a reduction in the summer peak demand growth rate from 2.4% to 1.6% over the long term.

The Company had planned to participate as a 5% owner in the construction of two 1,067 MW nuclear units, known as Hope Creek Units No. I and 2 to be located in Salem County, New Jersey. In December 1981, PSE&G, who owns 95% of the project, announced the cancellation of Hope Creek Unit No. 2. Accordingly, the Company cancelled its 5.0% share of Hope Creek Unit No. 2 in December 1981. The Company's investment in Hope Creek Unit No. 2 was written off for federal income tax purposes in 1981. However, for book purposes, the Company's investment of $15,956,476, including $2,390,676 of AFDC, has been transferred from Construction Work in Progress to Property Abandonment Costs and an appropriate amount of deferred federal income taxes has been provided. Amortization of the book basis investment over a 15 year period will begin in January, 1983 (See Note 3).

In August 1982, the Company signed an Agreement with PSE&G, the New Jersey Department of Energy and the New Jersey Department of the Public Advocate which, if approved by the BPU, would establish an incentive program to contain the continuing construction cost of Hope Creek Unit No. I, which is currently planned for completion in.1986. Pursuant to terms of the incentive program, if the final cost of the facility is less than the 34 agreed amount, the Company's Shareholders could share in the savings. On the other hand, under certain conditions, if the final cost of the unit exceeds the agreed amount, the Company could be penalized by not being able to earn a return on the entire amount of the cost overrun.

If the BPU approves the Agreement, the New Jersey Department of Energy and the New Jersey Department of the Public Advocate would not challenge the need for the unit.

Note 13. Leases:

The Company has certain leases for property and equipment, including the nuclear fuel lease arrangement mentioned in Note 6, which meet the criteria for capitalization, but in accordance with rate making treatment are accounted for as operating leases. The capitalization of such leases would not have a significant effect on assets, liabilities or operating expenses.

Note 14. Supplementary Income Statement Information:

Operating expenses include taxes and other items not separately identified in the Statement of Income as follows:

Year Ended December 31 (Thousandsof Dollars)

Taxes Other Than Federal Income Taxes:

1982 Real and Personal Property Taxes

$ 1,027 State Gross Receipts, Sales, Excise and Franchise Taxes and 1981 918 1980 944 Miscellaneous State and Local Taxes 57,066 41,204 32,924 Payroll Taxes-Federal and State 2,455 2,078 1,678 Total

$60,548 $44,200 $35,546 Maintenance Expense

$30,313 $28,087 $24,251 Charges to income for royalties and advertising are less than 1% of gross revenue.

Note 15. Quarterly Financial Results (Unaudited):

Quarterly financial data which reflect all adjustments (which consist of only normal recurring accruals)

Operating Operating Quarter Revenues Income (Thousand 1982 I st (I)

$128,259

$13,875 2nd (I) 103,044 14,464 3rd (I) 115,794 22,080 4th 97,081 12,351

$444, 178

$62,770 1981 I st

$112,762

$18,969 2nd 101,908 15,194 3rd 133,552 24,963 4th 121,461 14,385

$469,683

$73,511 (I) Results for the first three quarters of 1982 have been restated from amounts previously reported to reflect the change in accounting method (See Note 4). Net income and earnings per share of common stock as reported prior to the accounting change were $10,701,000 ($.61 per share),

$6,911,000 ($.35 per share) and $14,666,000 ($.87 per share), for the quarters ended March 31, June 30 and September 30, 1982, respectively.

(2) Restated earnings for the first quarter exclude the cumulative effect of the accounting change on net income and on earnings for common stock necessary in the opinion of the Company for a fair presentation of such amounts are as follows:

Before Cumulative Effect Earnings For Earnings Income Common Stock Per Share of Dollars)

$ 7, 191 (2)

$ 5,337 (2)

$.37 (2) 8,521 6,668

.46 13,788 11,938

.81 5,629 3,818

.23

$35,129

$27,761

$1.84 (3)

$13,760

$11,856

$.94 8,739 6,845

.54 17,499 15,627 1.22 6,990 5,129

.36

$46,988

$39,457

$3.03 (3) of $13,926,000 (net of tax) and on earnings per share of $.96 (based on average shares outstanding in the first quarter).

(3) The individual quarters do not add to the total due to the increasing average number of Common shares outstanding at the end of each quarter.

The revenues of the Company are subject to seasonal fluctuations due to increased sales and higher residential rates during the summer months.

Supplementary Information Concerning The Effects Of Changing Prices (Unaudited)

The following supplementary information about the effects of changing prices is calculated under two different methods. The cumulative effect of a change in accounting described in Note 4 has been excluded from the following supplemental information.

The first method, which uses the Consumer Price Index for All Urban Customers (CPI-U), adjusts data for general inflation, providing financial information in dollars of equivalent value or purchasing power (constant dollars).

The purpose of this method is to make financial data more comparable by reporting the financial statement effects of the Company's investment in Utility Plant over a period of time in terms of a common unit of purchasing power.

The second method adjusts the financial data for changes in specific prices of the components of the Company's utility plant by applying the Handy-Whitman Index of Public Utility Construction Costs to historical cost by vintage years, reflecting the current cost of replacing resources actually used in the Company's operations (current costs).

Constant dollar amounts differ from current cost amounts because, over the period utility plant is held, specific prices increase more or less rapidly than general inflation.

Both of these methods involve the use of assumptions, approximations and estimates and therefore the resulting measurements should be viewed in that context and not as precise indicators of the effects of inflation.

35

Statement of Income From Continuing Operations Adjusted for Changing Prices Year Ended December 31, 1982 (In Average 1982 Dollars)

Results of Operations:

In Constant At Current (Thousands of Dollars)

Historical Dollars Cost Operating Revenues

$444,178

$444, 178

$444, 178 Operation and Maintenance Expenses 338,382 338,382 338,382 Depreciation and Amortization Expense 29,962 73,698 74,987 Federal Income Tax Expense 13,064 13,064 13,064 Other 27,641 27,641 27,641 Income from Continuing Operations (a)

$ 35,129

$ (8,607)

$ (9,896)

(a) Before cumulative effect of change in accounting method (See Note 4 of Notes to Financial Statements).

Depreciation and amortization expense expressed in constant dollar and current cost amounts were determined using the rates and methods used for computing book depreciation and amortization applied to utility plant balances re-expressed in terms of constant dollars and current costs.

Only depreciation and amortization of nuclear fuel have been specifically adjusted for inflation in the above schedule. Operating revenues and other operating expenses were generally incurred rateably over the year, accordingly, the stated amounts already reflect, in effect, average 1982 dollars.

Significant to this data is the impact of a fixed income tax rate. Income taxes were not adjusted because the present tax laws do not allow a deduction for depreciation and amortization adjusted for the impact of inflation.

Therefore, the Company's effective tax rate rises from 35.5% under the historical cost basis to 146.8% and 157.8%

under the respective constant dollar and current cost basis.

This supplementary information should not be used to assess the probability of future cash flows when existing utility plant is replaced. The estimates do not reflect the effects of the regulatory process nor the specific plans of the Company for the replacement or modernization of utility plant. A meaningful estimate of the estimated level of future capital expenditures is set forth on page 18 of the annual report.

Current Year Effect of Increased Price Levels:

(Thousands of Dollars)

Increase in Specific Prices on Utility Plant Held Increases in General Price Levels on Utility Plant Held Excess of Increase in Specific Prices Over Increases in General Price Levels

$66,684 59,543

$ 7,141 At December 31, 1982 the cost of utility plant, net of accumulated depreciation was $1,657,601,000 on a constant dollar basis and $1,701,498,000 on a current cost basis, while historical cost was $906,313,000. The accumulated provisions for depreciation and amortization under both constant dollar and current cost methods were estimated for each major class of utility plant (production; 36 transmission; distribution and general plant) by multiplying the respective cost data by a percentage representing the expired life of existing facilities of each class at December 31, 1982.

Fuel inventories, the cost of fossil fuels used in generation, have not been restated from their historical cost. New Jersey regulation controls fuel costs, through the operation of a levelized energy clause, such that recovery is ultimately limited to actual cost. For this reason fuel inventories are effectively monetary assets.

Net Utility Plant Costs Recoverable:

Under rate making prescribed by the regulatory commissions to which the Company is subject, only the historical cost of utility plant is recoverable in revenues as depreciation. Therefore, the excess of the cost of utility plant stated in terms of constant dollars or current cost over the historical cost of plant is not presently recoverable. Due to this feature, the value of utility plant and its effect on income from continuing operation adjusted for changing prices must be considered in terms of its net recoverable cost which is historical cost. While the rate making process gives no recognition to the current cost of replacing utility plant, based on past practices the Company believes it will be allowed to earn on the increased cost of its net investment when replacement of facilities actually occurs.

Current Year Decline in Purchasing Power of Net Amounts Owed:

The current year decline in purchasing power of net amounts owed was $21,666,000. During a period of inflation, holders of monetary assets such as cash and receivables suffer a loss of general purchasing power while holders of monetary liabilities, generally long term debt, experience a gain because debt will be repaid in dollars having less purchasing power. The Company's gain from the decline in purchasing power of its net amounts owed is primarily attributable to the substantial amount of debt and cumulative preferred stock subject to mandatory redemption which has been used to finance utility plant.

This gain, however, should not be considered as providing funds to the Company, since the Company is limited under rate procedure to the recovery only of its embedded cost of debt.

Five-Year Comparison Of Selected Financial Data Including Unaudited Supplementary Data Adjusted For Changing Prices (In Thousands of Dollars Except Per Share Amounts-Constant Dollar and Current Cost Amounts Expressed in 1978 Dollars)

Years Ended December 31 1982 1981 Operating Revenue

-historical

$ 444,178

$ 469,683

-in constant dollars (a) 300,008 336,917 Income from Continuing Operations (b)

-historical 49,055 46,988

-in constant dollars (a) 3,593 5,593

-at current cost (a) 2,729 5,486 Income from Continuing Operations per Share of Common Stock (b)

-historical 2.76 3.03

-in constant dollars

(.09)

.OJ

-at current cost

(.15)

.01 Effective Income Tax Rate

-historical 35.5%

36.8%

-constant dollar basis 88.3 83.0

-current cost basis 90.8 83.3 Excess of Increases in General Price Levels Over Increases in Specific Prices (a)

(4,823)

$ (18,079)

Decline in Purchasing Power of Amount Owed (a) 14,634 28,386 Net Assets at Year End

-historical

$ 414,834

$ 338,846

-in constant dollars (average) 275,335 235,206 Net Income as a Percent of Operating Revenue (b)

-historical 11.04%

10.00%

-trended in 1978 dollars 7.46 7.17 Earned Rate of Return on Shareholders' Equity

-historical 11.20%

12.21%

-trended in 1978 dollars 7.56 8.76 Total Assets at Year End-historical

$1,077,969

$1,013,789 Long Term Debt and Cumulative Preferred Stock Subject to Mandatory Redemption

-historical

$ 462,470

$ 447,389 Dividends Declared per Share of Common Stock

-historical 2.24 2.08

-in constant dollars 1.51 1.49 Market Price per Common Share at Year End

-historical 20.75 17.25

-in constant dollars 14.02 12.37 Average Consumer Price Index 289.3 272.4 1980 1979 1978

$358,391

$283, 106

$255,058 283,750 254,457 255,058

$ 38,538

$ 34,307

$ 30,064 6,824 10,882 4,390 6,25 1 2.62 2.36 2.21

.16

.46

(.03)

.06 33.8%

35.5%

38.8%

74.3 63.3 81.8

75. l

$ 34,485

$ 40,677

$ 35,641

$ 42,525

$324, 127

$310,231

$279,897 245,103 262,421 308,916 10.75%

12.12%

11.79%

8.52 10.89 11.79%

11.62%

10.70%

10.26%

9.20 9.62 10.26%

$879,795

$779,026

$699,861

$394,288

$324,848

$329,781 1.93 l.79 1.70 1.53 1.61 1.70 15.75

$ 17.125 $

18.00 12.47 15.40 18.00 246.8 217.4 195.4 Certain comparative per share data trended in average 1982 dollars (without adjustment of earnings for the pro forma effects of inflation on depreciation amounts) are as follows:

Earnings (b) 2.76 3.22 3.07 3.14 3.27 Dividends Declared 2.24 2.21 2.26 2.38 2.52 Market Price (Year End) 20.75 18.32 18.46 22.79 26.65 (a) These amounts will differ from those shown for constant dollar and current costs in Statement of Income From Continuing Operations Adjusted for Changing Price because a different base year has been used (1978) in the data presented above and (1982) in the Changing Price information in order to illustrate the impact of changing prices in alternative forms.

(b) Income from Continuing Operations, Net Income and Earnings Per Share data for 1982 include the cumulative effect of change in accounting method (See Note 4 of Notes to Financial Statements).

37

Statistical Review 1982-1972 Facilities for Service 1982 1981 1980 1979 Total Utility Plant (Thousands)

$1,153,321

$1,064,928

$ 962,052

$ 870,075 Gross Additions to Utility Plant (Thousands)

$ 126,893

$ 123,318 97,330 72,773 Pole Miles of Transmission and Distribution Lines 6,918 6,910 6,879 6,831 Generating Capacity (Kilowatts) (a) (b) 1,531,200 1,524,600 1,434,700 1,384,700 Maximum Utility System Demand-Kw 1,264,200 1,263,000 1,261,700 1,192,600 Margin of Reserve at Times of Peak (% of Avail. Gen.)

17.4%

17.1%

12.1%

13.9%

Energy Supply (Thousands of Kwh)

Net Generation 5,676,118 5,302,023 5,533,178 5,397,338 Purchased and Interchanged-Net 466,667 946,241 643,106 464,143 Total System Load 6,142,785 6,248,264 6,176,284 5,861,481 Electric Sales (Thousands of K wh)

Residential 2,415,292 2,480,225 2,514,738 2,411,732 Commercial 1,894,535 1,849,863 1,769,208 1,580,384 Industrial 1,218,520 1,279,724 1,286,205 1,255,304 I

All Others 63,770 65,555 63,753 60,799 Total 5,592,117 5,675,367 5,633,904 5,308,219 '

Residential Electric Service (Average per Customer)

Amount of Electricity used during the year (K wh) 7,444 7,751 8,003 7,849 Amount paid for a year's service 644.77 670.66 536.99 439.92 Price paid per Kilowatt-hour 8.66¢ 8.65¢ 6.71¢ 5.61¢ Customer Data (Average)

Residential With Electric Heating 59,319 56,100 52,225 48,339 Residential Without Electric Heating 265,124 263,904 261,988 258,941 Total Residential 324,443 320,004 314,213 307,280 Commercial 42,885 43,219 43,267 43,219 Industrial 1,018 1,032 1,041 1,048 Other 627 634 654 667 Total Customers 368,973 364,889 359,175 352,214 ~

Total Service Locations 391,989 386,046 379,242 371,362 Population Served 1,069,000 1,056,000 1,037,000 1,015,000 Financial Data (Thousands of Dollars)

Energy Sales Residential

$ 209,191

$ 214,614

$ 168,733

$ 135,178 Commercial 154,792 156,624 115,973 88,819 Industrial 71,255 82,908 60,512 47,590 All Others 9,255 9,700 7,836 6,624 Total Energy Sales-Billed 444,493 463,846 353,054 278,211 Unbilled Revenues-Net (6,795)

Other Electric Revenue 6,480 5,837 5,337 4,895 Total

$ 444,178

$ 469,683

$ 358,391

$ 283,106 Investor Information Earnings per Average Common Share 2.76(c) $

3.03 2.62 2.36 Average Number of Shares Outstanding (In Thousands) 15,116 13,034 12,372 11,980 Dividends Paid on Common Stock (Cash) 2.20 2.04 1.90 1.765 Dividend Payout Ratio 80%

67%

73%

75%

Book Value Per Share (Year End) 22.45 22.40 22.22 21.63 Price Earnings Ratio (Year End) 8 6

6 7

Times Fixed Charges Earned (before income taxes) 2.27(c) 2.84 3.03 3.62 Shareholders and Employees (Year End)

Common shareholders 48,790 48,424 47,762 48, 194 Employees 2,022 2,035 1,968 1,903 (a) Excludes capacity allocated to a large industrial customer.

(b) Includes unit purchase of capacity 50,000 kilowatts under contract with Delmarva Power and Light Company.

(c) Earnings calculation includes the cumulative effect of an accounting change. Financial ratio is computed excluding the cumulative effect.

38

1978 1977 1976 1975 1974 1973 1972

$ 802,473

$ 753,269

$ 710,343

$ 675,617

$ 637,250

$ 572,555

$ 511,274 58,073 48,733 41,702 46,745 71,200 67,864 58,434 6,786 6,735 6,696 6,645 6,580 6,506 6,408 1,414,700 1,414,700 1,334,700 1,334,700 1,278,700 1,013,500 965,900 1,177,400 1,176,000 1,030,300 1,069,400 1,004,400 1,051,400 920,400 16.7%

16.9%

22.8%

19.9%

21.5%

4.7%

5,625,988 5,293,019 4,918,906 4,715,357 4,651,334 4,236,083 4,071,225 130,037 224, 169 324, 196 190,852 229,197 665,558 458,050 5,756,025 5,517' 188 5,243, 102 4,906,209 4,880,531 4,901,641 4,529,275 2,377,202 2,221,250 2,070,766 1,938,724 1,882,560 1,899,122 1,741,895 1,586,097 1,478,559 1,392,029 1,346,216 1,298,858 1,351,974 1,183,668 1,250,636 1,220,260 1,143, 170 1,036,755 1, 136,935 1, 119,478 1,061,932 60,705 58,866 57,667 56,465 57,477 58, 129 64,531 5,274,640 4,978,935 4,663,632 4,378,160 4,375,830 4,428,703 4,052,026 7,951 7,653 7,320 7,018 6,982 7,303 7,008 406.18 378.36 349.64 329.25 291.21 230.19 207.37 5.11¢ 4.94¢ 4.78¢ 4.69¢ 4.17¢ 3.15¢ 2.96¢ 44,387 40,318 37,581 35,235 32,215 28,627 25,105 254,592 249,927 245,296 241,019 237,397 231,408 223,449 298,979 290,245 282,877 276,254 269,612 260,035 248,554 42,672 42,033 41,170 40,608 40,351 39,810 38,009 1,034 1,047 1,071 1,100 1,080 948 1,011 673 676 681 684 679 678 757 343,358 334,001 325,799 318,646 311,722 301,471 288,331 362, 131 352,205 343, 147 336, 105 330,758 320,834 309,393 990,000 961,000 937,000 915,000 894,000 865,000 828,000

$ 121,440

$ 109,818 98,904 90,956 78,512 59,856 51,544 80,539 73,354 66,354 63,544 55,713 42,804 35,868 42,185 40,885 36,438 34,974 33,565 22,008 19,350 5,973 5,630 5,406 4,881 4,207 3,861 3,763 250, 137 229,687 207,102 194,355 171,997 128,529 110,525 4,921 5,308 4,925 4,724 4,614 4,365 4,128

$ 255,058

$ 234,995

$ 212,027

$ 199,079

$ 176,611

$ 132,894

$ 114,653 2.21 2.06 2.60 2.41 2.54 2.40 2.26 10,791 10,630 9,747 9,490 8,973 8,453 7,810 1.67 1.62 1.56 1.51 1.50 1.4688 1.4144 76%

79%

60%

63%

59%

61 %

63%

21.27 20.71 20.25 19.34 18.45 17.85 16.77 8

11 9

7 5

7 10 3.62 3.17 3.14 2.88 2.33 2.62 2.70 44,490 43,826 42,516 39,232 39,054 36,835 35,549 1,797 1,739 1,714 1,741 1,811 1,810 1,743 This Annual Report has been prepared for the purpose of providing general and statistical information concerning the Company and not in connection with any sale, offer for sale or solicitation of an offer to buy any ecurities.

39

Common Stock Price Range and Dividends The high and low sales prices of the Common Stock as reported in the Wall Street Journal as New York Stock Exchange-Composite Transactions for the periods indicated were as follows:

Dividends Paid 1982 1981 Per Share High Low High Low 1982 1981 First Quarter 18Ys 16%

17 Y4 15 Y4

$.53

$.49 Second Quarter 18%

17 181/4 15 l/4

$.53

$.49 Third Quarter 20Y2 17 17%

161/s

$.57

$.53 Fourth Quarter 2l3/s 19 181/4 16

$.57

$.53 For your convenience, listed below are the proposed 1983 record dates and payable dates, for dividends on Common Stock:

Record Dates March 17, 1983 June 16, 1983 September 15, 1983 December 15, 1983 Payable Dates April 15, 1983 October 15, 1983 July 15, 1983 January 15, 1984 Investor Records: Communications regarding stock transfer requirements or lost certificates should be directed to the appropriate Transfer Agent. Changes of address, inquiries on dividends or matters concerning the Dividend Reinvestment and Stock Purchase Plan should be addressed to:

Atlantic City Electric Company Investor Records Department P.O. Box 1334 Pleasantville, New Jersey 08232 or telephone Area Code 609/645-4506 or 4507.

40 Corporate Data Dividend Reinvestment and Stock Purchase Plan The Company continues to offer a Dividend Reinvestment and Stock Purchase Plan which enables shareholders and employees to automatically invest their cash dividends in Company stock, and also make optional cash payments without paying brokerage commissions or service charges.

Over 487,000 shares were purchased through the Plan in 1982 with pro-ceeds to the Company in excess of $9 million. There were 15,737 participants in the Plan at year-end.

To enroll, please contact our Investor Records Department. See address on this page.

Share Listings Common Stock of the Company is listed on the New York Stock Exchange, the Philadelphia Stock Exchange and the Pacific Stock Exchange. The 57/s% Cumulative Convertible Preferred Stock of the Company is listed on the New York Stock Exchange.

10-K Report Available The annual report to the Securities and Exchange Commission on Form 10-K is available to shareholders and may be obtained by writing to the Company, Attention: Mr. M. R.

Meyer, Secretary. See address on this page.

Transfer Agents For Common and Preferred Stock Morgan Guaranty Trust Company of New York 30 West Broadway New York, New York 10015 For Common Stock First National State Bank of South Jersey Atlantic City, New Jersey 08404 New Corporate Address Atlantic Electric P.O. Box 1264 1199 Black Horse Pike Pleasantville, New Jersey 08232

0 Atlantic Electric 1199 Black Horse Pike Pleasantville, NJ 08232 Atlantic Electric's new Administrative Complex in Pleasantville was completed in November, 1982.

Bulk Rate U.S. Postage PAID Atlantic City Electric Company