ML18092A141

Annual Financial Rept 1983

ML18092A141
Person / Time
Site:	Salem, Hope Creek, 05000000
Issue date:	12/31/1983
From:	Feehan J ATLANTIC CITY ELECTRIC CO.
To:
Shared Package
ML18092A137	List: ML18092A136 ML18092A138 ML18092A139 ML18092A140 ML18092A141
References
HNLR-831231, NUDOCS 8404190338
Download: ML18092A141 (42)

Text

NOTICE -T HE A TTAC H ED FI LES ARE OFFICIAL RECORDS OF THE DIV I S ION OF DO CUMENT CONTROL. THEY HAVE REEN CHAR G ED TO Y OU FOR A LIMITED TIME PERIOD AND MUS T B E RETU RNED TO THE RECORDS FACILITY BRA NCH 01 6. PLEASE DO NOT SEND DOCUMENTS CHAR GED OUT THROUGH THE MAIL. REMOVAL OF ANY PAG E(S) FROM DOCUMENT FOR REPRODUCTION MUST B E R EFERRED T O F ILE PERSONNEL. w-2-72-1 tg/je)/11'{'

o? I D EADLINE RETU RN DATE

.. e R E CORDS FACILITY BRANCH OUR BUSINESS:

D To provide safe and reliable electric energy to our customers.

D To deliver our product and services at the lowest, reasonable prices. D To provide a fair return on invested capital. OUR COMMITMENT:

D To work with our customers to promote the wise use of energy and to control costly growth in peak electrical demand. D To provide employees with safe working conditions, to afford them equal opportunity for training and advancement, and to compensate them fairly on the basis of performance.

D To conduct our operations with regard for both the value of natural resources and the preservation of environmental quality. D To work, directly and indirectly, toward the economic vitality of the Company's service area. D To plan for the future in such fashion as to assure consistency of financial performance, and continuous access to additional capital at reasonable rates. The Corporate Name and Trade Name: Atlantic City Electric pany is the official name of the Company as it appears in the cles of Incorporation.

The Company also uses the registered trade name Atlantic Electric in various tions to shareholders and ers, and in its daily operations.

Corporate Address: Atlantic Electric P. 0. Box 1264 1199 Black Horse Pike Pleasantville , New Jersey 08232 Notice of Annual Meeting: The 1984 Annual Meeting of holders will be held Tuesday, April 24, 1984, at Quail Hill Inn, ville, New Jersey. A Notice of Meeting will be mailed in March to those shareholders entitled to vote. Contents Letter to Shareholders 2 The Atlantic Electric Service Area 4 Atlantic Electric's Sound Fundamentals 6 Management's Discussion and Analysis 14 Financial Statements 17 1983-1973 Statistical Review 34 Common Stock Price Range 36 Board of Directors and Officers 37 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.

0 Crm. ,,1 .g,g/fCVl/7' o? I DEADLINE RETURN DATE C 8 REGULAT9RY DOCKET FILE RECORDS FACILITY BRANCH OUR BUSINESS:

D To provide safe and reliable electric energy to our customers.

D To deliver our product and services at the lowest, reasonable prices. D To provide a fair return on invested capital. OUR COMMITMENT:

o To work with our customers to promote the wise use of energy and to control costly growth in peak electrical demand. o To provide employees with safe working conditions, to afford them equal opportunity for training and advancement , and to compensate them fairly on the basis of performance.

D To conduct our operations with regard for both the value of natural resources and the preservation of environmental qualit y. D To work, directly and indirectly, toward the economic vitality of the Company's service area. D To plan for the future in such fashion as to assure consistency of financial performance, and continuous access to additional capital at reasonable rates. The Corporate Name and Trade Name: Atl a ntic C i ty El ect ri c Co mpany is t h e offic i al n a m e of t h e Compa n y as it appea r s in t h e Art ic l es of In co r po rati o n. Th e Co m pa n y a l so u ses t h e registered t rade n ame Atlant ic E l ectr ic in va ri o us p ublit i ons to s h a r e hold e rs a nd c u s t oers, a nd in i ts d a il y ope r at i ons. Corporate Addre ss: Atla n t ic E l ectr i c P. 0. Box 1264 11 99 B l ack H orse Pike Pl easantv ill e, New J e r sey 08232 Notice of Annual Meetin g: The 1 984 Ann ua l Mee tin g of S hh o l ders w ill b e h e l d Tu es d ay, Ap r il 24, 1984, at Qu a il Hill Inn , S m it hv ill e, New J ersey. A Noti ce of M eet i ng w ill b e m a il e d in M arc h to t h ose s har e holde rs e n t i t l e d to vote. C onten ts Letter to S h areho l ders 2 The Atlantic Electric Service Area 4 Atlantic E l ectric's Sound Fundamenta l s 6 Manage m ent's Discuss i on and Analysis 1 4 Fi n anc i a l Statements 1 7 1983-1973 Statistical Review 34 Com m on Stock Price Range 36 Board of Directors and Officers 37 RESULTS OF OPERATIONS 19 83-19 8 1 % Change 1983 1983-1982 Electric Operating Revenues $ 517,142,000 16.4 Operating Expenses $ 424,040,000 11.2 Net Income $ 66,152,000 34.9 Earnings Per Common Share $ 3.48 26.l Dividends Paid Per Common Share $ 2.30 4.5 Total Assets $1,139,978,000 5.8 Cash Construction Expenditures

$ 74,457,000 (37.1) Sales of Electricity (KWH) 5,851,434,000 4.6 Price Paid Per KWH-(All Customers) 8.36¢ 3.3 Total Customer Service Installations (Year-end) 398,526 1. 7 Number of Shareholders-Common Stock (Year-end) 48,299 (1.0) Number of Employees (Year-end) 1,995 (1.3) Book Value $ 23.58 5.0 *See N ote 4 (C hang e in A cc ountin g for R eve nu es) of N otes to F in a n c ial Stat e m e nt s. EARNINGS AND DIVIDENDS PER S HARE OF COMMON STOCK (in dollar s) *Earning s *Dividends 3 2 1 74 75 76 77 7 8 7 9 80 8 1 82 83 0 MARKET PRICE PER S HARE OF COMMON STOCK (yea r-end in dollar s) 74 7 5 76 77 7 8 7 9 80 8 1 82 83 25 2 0 1 5 1 0 5 % Change 1982 1982-1981 1981 $ 444, 178,000* (5.4) $ 469,683,000

$ 381,408,000 (3.7) $ 396, 172,000 $ 49,055,000*

4.4 $ 46,988,000

$ 2.76* (8.9) $ 3.03 $ 2.20 7.8 $ 2.04 $1, 077, 969' 000 6.3 $1,013, 789,000 $ 118,460,000 4.6 $ 113,221,000 5,592, 117,000 (1.5) 5,675,367,000 8.09¢ (2.1) 8.26¢ 391,989 1.5 386,046 48,790 .8 48,424 2,022 (.6) 2,035 $ 22.45 .2 $ 22.40 TO OUR SHAREHOLDERS:

On the pages of our Annual Reports in past years, we have described developments affecting the Company, the challenges set before it, and the measures of our progress.

In many instances, our reporting has been set within the context of fundamental corporate strategies relating to: o diversity of power supply o managed growth/manageable construction programs o flexible capacity planning o financial strength and capability Put another way, realization of our strategic objectives simply means "getting the basics right." We're proud to say that these corporate tals are in place. As a result, we believe that we'll continue to be able to report on the progress of your Company. 1982 had been described as a year of transition, and 1983 as the beginning of a period of improved finan -cial and operational performance.

The improvement which we expected is being realized, as indicated by the increase in earnings per share from $2. 76 in 1982 to $3.48 in 1983. Contributing to this improvement were the effects of a December 1982 base rate increase and higher-than-expected sales of energy. With the Company's improved financial mance, the Board of Directors took action last September to raise the quarterly dividend on Common Stock from $.57 to $.59 per share. As a result, the Company's record of consecutive creases in dividends paid has been extended to 31 years. Our financial forecasts have indicated that additional base rate re l ief will be required to sustain acceptable levels of performance.

Accordingly, we filed a request with the New Jersey Board of Public Utilities in October for a base rate increase of $25 million, asking that the BPU render a decision and grant increased rates by mid-1984.

The rating agencies noted our improved financial performance, too. Standard & Poor's raised their ratings of our long-term debt and preferred stock. With S & P raising our first mortgage bond rating from A+ to AA , we have achieved double-A status with all major rating agencies.

Our goal for the past 10 years has been to establish a solid double-A rating across-the-board, and this achievement in 1983 is an important milestone in that direction.

2 During the year, Duff & Phelps also upgraded its ratings of our debentures, preferred stock and commercial paper. The Company's commercial paper, which is issued for short-term funding requirements, now has the highest possible credit ratings with all major rating agencies.

Our excellent commercial paper ratings enable us to achieve extremely favorable rates on short-term borrowings.

As you read of our progress in 1983, you'll also recognize the "story" which transcends events of any single year: The Company's consistent direction results from the steady pursuit of our long-term goals. Whether it's with regard to power supply, construction, finance or operations, each of our goals reflects a unified approach to develop fundamental strengths which will support the Company, its customers and its shareholders, in good times and in bad. This decade since the Arab oil embargo has witnessed our ability to accommodate changes in fuel supply, electrical demand and capacity ning, and has confirmed the prudence of our diversity and flexibility.

For the future, we have established capacity plans which should prove beneficial to both our holders and our customers.

Our only generating capacity under construction is Hope Creek 1, which is expected to be completed in 1986. Our 5% share of that unit will provide 53,000 kilowatts of base load capacity.

In addition, we now have arrangements for the purchase of 125,000 kilowatts of capacity and energy through the year 2000. These purchase arrangements will accommodate additional electrical energy needs by a combination of coal and nuclear sources. Our power purchases have permitted us the time to deploy effective conservation and load management practices, and to fine-tune our ment of future electricity needs before making any commitments to new major construction efforts. Our preparedness is attributable to the active interest and leadership of a very fine Board of rectors. At this year's Annual Meeting, three of our Directors will be retiring, and they deserve special mention:

E.D. H uggard, (left) Exec u tive Vice President with J.D. Feehan, Chairman and President.

Dick Wilson joined the Company in 1939 and served as an Officer from 1963 until 1981, when he retired as an employee.

Since 1977 he has served as a Director of the Company, lending to the Board his hensive experience and knowledge of the Company's operations.

Frank Wheaton will be completing over sixteen years as a Director this April. During that period he has contributed to the Board his perspective and practical knowledge as a multinational manufacturer and, since 1976, he has chaired the Corporate Development Committee.

Mack Jones has served on the Board of Directors since 1970. His background in engineering and electronics has been of great value to the Board, and he has served as Chairman of the Energy, tions and Research Committee since 1970. All of us have been beneficiaries of their time, their experience, and their concern for the prosperity of the Company. Their presence at the Board meetings will be missed, but their impression upon the shape and gTowth of the Company will long be felt. Since the last Shareholders' Meeting, we have taken several steps as part of our continuing effort to sustain our high calibre of leadership.

Madeline McWhinney was elected a Director of the Company at the October Board Meeting. Her expertise as president of a management consulting firm, together with prior financial and economic experience at such institutions as the Federal Reserve Bank of New York and the American Stock Exchange are most appreciated by the Board. In January 1984, the Board of Directors nominated Doug Huggard, utive Vice President of the Company, for election to the Board at the coming Shareholders' Meeting. Doug joined the Company in 1955 and has been an Officer since 1974. Hisresponsibilities have passed such corporate functions as production, electric operations, accounting and ratemaking.

Since February 1983, Doug has served as Executive Vice President and has been responsible for all aspects of the Company's operations.

We believe that his breadth of experience and knowledge of the Company will continue to be assets of great value to corporate direction.

In 1983 we introduced a new commercial logo which aptly characterizes the Company's employees as "People Meeting Your Energy Needs." At year-end, there were 1,995 people of Atlantic Electric sharing this service orientation.

They are to be commended for their dedication, concern and diligence.

The success of the Company, now and in the future, depends upon those charged \\: ith pursuing and achieving the "basics." They have exerted great effort in earning for the Company a reputation for consistency and excellence and, I trust you'll agree, their efforts are paying off. For the Board of Directors J. D. Feehan Chairman of the Board and President

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 1983, the Company served 329,914 customers in 125 palities in eight counties.

About 19% of these dwellings have tricity as their conventional heating source, 50% have tric water heaters and 62% have air-conditioning.

About 19% of all dwellings are occupied on a seasonal basis. Commercial Atlantic Electric served 43, 152 commercial customers in 1983. 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. Two additional hotel-casinos were under struction in 1983. About 1, 750 commercial ers were engaged in agricultural activities.

Industrial The Company served 1,021 industrial customers in 1983. Principal manufacturing tries included food, chemicals, rubber and plastic products, stone, clay, glass and electrical and electronic equipment.

19 83 Electric Consumption Residential customers sented 48% of the annual peak demand. The residential sector consumed 2. 5 billion hours last year or nearly 44% of total sales. The average tial customer used 7, 715 hours0.00828 days <br />0.199 hours <br />0.00118 weeks <br />2.720575e-4 months <br />. More than 5,400 new residential customers were added during the year and 54% of all new residential "connects" during the year have electric heat. Total commercial customers accounted for 37% of the annual peak demand. This sector sented 35% of total sales, suming 2. 0 billion hours. Casinos, which are part of the commercial group , accounted for about 4% of the Company's total peak demand and 5% of it s total sales. Industrial customers sented 15% of the annual peak demand. They consumed 1.2 lion kilowatt-hours, or 21 % of total sales. About 32% of all industrial sales were to the stone, clay and glass industries.

Th e ar e a outlin ed r e pr es ent s th e Atlanti c Cit y El e ctric C omp a n y se r v i ce area. Fifteen Year Outlook Residential customers are jected to comprise 47% of the total peak in 1998 and consume 3.3 billion kilowatt-hours, or 44% of total projected sales. Average residential kilowatt-hour sumption is expected to increase to 8, 100 in 1998. The residential sector is estimated to have a compound annual growth rate in peak demand of only 1.4% over the next 15 years. The commercial sector is mated to total about 39% of the total peak expected in 1998, and commercial sales are pected to increase to 2.6 bil-lion kilowatt-hours, or 37% of projected total sales. The casino portion of the commercial sector will be 5.3% of the total peak demand and 6.4% of total jected sales. The entire mercial sector is expected to experience a 1. 9% compound annual growth rate in peak demand over the 15 year period. The industrial class portion of total peak demand is forecast as 14% in 1998. Industrial sales are expected to grow to 1.4 billion kilowatt-hours or 19% of the total projected sales. The pound annual growth rate in peak demand for the industrial sector is expected to be 0. 9%. 5

Constant u pgrading of di st ribution line s h e l p s ensure r e liab l e se rvic e to the pany's c u sto m e r s. (L e ft) Mickleton Substat i on is a major p o int of int e rconnection b etwee n the Company and neighboring uti li ties. COST OF GEN E RAT IO N PER KILOWAT T-H OUR (in cents) 5 3 2 1 74 75 76 77 7 8 79 80 8 1 82 83 0 ATLANTIC ELECTRIC'S SOUND FUNDAMENTALS Power Suppl y and Operation s As reported last year, the pany had entered an Agreement with Pennsylvania Power & Light Company in 1979 for the purchase through 1991of125,000 kilowatts of capacity and energy from PP&L's two Susquehanna Units, the first of which began operation in June 1983. During 1983 the Company was able to resolve a controversy between state and federal regulators regarding the Susquehanna Agreement by negotiating a ond purchase contract with PP&L to provide a like amount of coal-fired capacity and energy from 1991 through 2000. The terms of the combined purchase arrangements were designed to produce net overall savings for the Company's customers.

The New Jersey Board of Public ities approved the 17-year plan, and granted the Company a elized rate increase designed to recover the costs associated with the first 62,500 kilowatts of the purchased capacity.

In addition, the participants in the rate case agreed that similar rate ments for the second half of the total 125,000 kilowatt purchase should be authorized by the BPU when Susquehanna Unit 2 begins commercial operation late in 1984. In July 1983, the BPU approved the Hope Creek Cost ment Agreement.

That ment, which had been signed in late 1982 by the Company as 5% owner, Public Service Electric & Gas Company as 95% owner and constructor, the New Jersey Department of Energy and the New Jersey Public Advocate, established a targeted in-service date of December 1986, and vided for earnings incentives or penalties for project costs below or above a targeted range. The Hope Creek Unit is currently more than 80% complete, and it will provide the Company with 53,000 kilowatts of base load nuclear generating capability.

The need for the purchase or construction of any additional capacity before the end of the century will depend, in part, upon the effects of conservation and load management on the growth in peak demand. Such a need could be accommodated by the construction of combustion turbines, which would not require a protracted time frame. Other sources of additional pacity may also be available at the time needed. The results of operations for 1983 demonstrate the continuing importance of power supply diversity and commitment to the service life extension program for our generating units. Over the past three years, duction costs per kilowatthour have changed only moderately, and this has contributed to the stability of rates charged our customers.

The changes in duction cost are dependent upon fuel prices and the relative mix of the various fuels used. Coal and nuclear generating units provided approximately 78% of our total energy ments in 1983, compared with our record 79% in 1982. The blend of the two sources was 7

Pictured is a new water purification system used by the Company at its BL England G e n e rating station. (Left) Coal was u s ed to produce 62% of the electricity used by our customers in 1983. AVERAGE AS-FIRED COST OF FUEL (in d o llar s p e r million btu s) *Oil *Ga s *Coal *Nucl e ar 4 i ,.. ,,/ 74 7 5 76 77 7 8 79 80 8 1 82 83 2 0 ATLANTIC ELECTRIC'S SOUND FUNDAMENTALS different, however. In 1982, the level of coal generation was diminished due, in part, to scheduled outages of the BL England coal-fired units, during which major rebuilding of the boilers was undertaken.

The increased levels of coal tion from those units after their return to service contributed to an all-time record for power eration at the BL England Station in 1983. In November 1983 the Company received a five-year renewal of its authorization from the New Jersey Department of mental Protection to burn coal in BL England Units 1 and 2. As part of the renewal, the DEP has required the Company to burn somewhat lower sulfur coal and oil at the station. The use of purchased coal-fired generation in 1983 increased over 1982 levels, primarily as the result of increased energy able from Indian River Unit 4 under our purchased power arrangement with Delmarva Power & Light Company. tional power from coal-fired sources was purchased from Allegheny Power System and Cleveland Electric Illuminating Company. We also began to take delivery of nuclear capacity and energy under the 17-year arrangement with PP&L when Susquehanna Unit 1 began mercial operation.

Nuclear production in 1983 was at a lower level than in 1982 for both the Peach Bottom and Salem Stations.

At Peach tom, piping work had to be done on both units, resulting in sions of their scheduled outages. Salem Unit 1 experienced a delay in returning to service from a scheduled outage in 1983, due to failures of certain control systems to operate as required, and also due to the subsequent investigation by the NRC of the causes of those failures.

The tems' malfunctions did not result in any damage to the unit or any release of radiation.

In October 1983, Salem 2 was removed from service to repair leaks in its (non-nuclear) generator cooling system. The effects of the outages of specific units upon our tions and the costs of supplying needed energy have been ated by the fact that our total capacity available for production is distributed among many ferent units. The overall availability of our generating capacity affects the amount of costly reserve capacity which we are required to have as members of the Pennsylvania-New Maryland Interconnection (PJM). The diversity of our erating capacity, coupled with comprehensive maintenance programs to enhance unit ability, has resulted in our sistently having one of the lowest required reserve margins of all PJM companies.

We're especially proud of one particular achievement with respect to fuel supply: We duced the use of oil-fired sources to satisfy our total energy quirements from more than 70% in 1973, at the time of the Arab oil embargo, to approximately 20% by 1983. It is currently estimated that, in 1984, coal and nuclear sources will provide 88% of the pany's total energy ments. 9

An extensive inventory of material s and s upplies must be maintained in order to meet the ne e d s of the Company's cu s tomer s. (L e ft) A Company engineer checks the progre ss of work being performed to extend the service life of a generating unit from Deepwater Station. AVERAGE ANNUAL PRICE PER KILOWATT-HOUR (in ce nt s) 1 0 8 6 4 2 74 7 5 76 77 7 8 79 80 8 1 82 83 ATLANTIC ELECTR I C'S SOUND FUNDAMENTALS Financial Developments The Company's improved credit ratings, as highlighted in the Chairman's Letter, reflect gress in achieving the financial goals which we have set for ourselves.

We have improved our common equity capitalization and our ability to cover interest charges on debt. Controlled struction expenditures in the future, with strong levels of internal cash generation, will result in manageable financing programs and modest needs for additional rate increases.

Factors contributing to the proved financial performance of the Company in 1983 are set out in detail in Management's sion and Analysis.

Among the principal factors were higher weather-related energy tion and the effects of the cember 1982 base rate increase.

The October 1983 request for an additional

$25 million in base rate revenues was based ily on increases in the amount of the Company's investment in utility property over the period from September 1982 to ber 1983. Timely recognition by the BPU of this revenue ment will help sustain acceptable levels of financial performance.

A decision on the base rate quests is expected by midyear. In October 1983 the Company requested a net increase in energy adjustment revenues of $28 million to offset the recovery of energy costs which had been experienced during the year, and to accommodate mated 1984 energy costs. The BPU granted the Company's request in January. The quality of earnings in 1983 has improved over past years. AFDC represented 14% of net income in 1983, compared with 17% in 1982. None of the dends paid during the year represented a return of capital. The increase of the dividend rate payable on Common Stock in October to an annual rate of $2.36 marks the 31st consecutive year of increases in the dividend paid, and the 65th consecutive year of dividend payments.

The Company's external ing for 1983 included the sale of $50 million of First Mortgage Bonds due 1993, and the ance of almost 652,000 shares of Common Stock for $14.3 million through the Company's Dividend Reinvestment and Employee Stock Ownership Plans. term debt was used for interim financing during the year, and it was paid off by year-end.

In 1984, we plan to issue imately $15-20 million of exempt Pollution Control Bonds in connection with the ing of a series of Pollution trol Bonds maturing May 1, 1984. With 1984 cash construction penditures estimated at $94 million and a good level of nal cash generation, we expect external financing for "new money" needs will be dated by the sale of Common Stock through the Dividend investment and Employee Stock Ownership Plans, as well as by the use of short-term debt. 11

Empl oyees o f th e Co n se rvation a nd L oad M a n age m e nt D epart m e n t r ev i ew d a t a fr o m a Res id e n t i a l Applian ce Sat ur at i o n S ur vey. (L eft) A n ew res id e ntial deve l op m e n t in t h e Co mp a n y's se r v i ce a r ea. 88% o f th e C o mp a n y's c u to m ers a r e r es id e nti a l and t h ey acco un t fo r 44% o f to t a l sa l es. ENERGY S ALES (i n b i ll i o n s o f ki l owatt-ho ur s) 6 l* 5 1.:, Li h 4 I< ,., 3 1.* 2 1 I'. ,., I' 74 75 76 77 78 79 80 8 1 82 83 ATLANTIC ELECTRIC'S SOUND FUNDAMENTALS Customers and Service Total kilowatthour sales to our customers in 1983 increased by 4. 6% over sales the previous year. The peak load recorded for the period was 1,347,000 watts, which was an increase of 6. 5% over the 1982 peak and represented a new record for the Company. Unusually warm weather conditions contributed to this new peak, which exceeds the maximum demand which had been forecast for 1987. Nevertheless, peak load is still forecast to grow at an annual rate of 1. 5% over the next fifteen years. One of the Company's major cerns for the future is to manage the costly growth in peak mand, while providing for the electricity needs of our customers. Conservation and load management programs, which will serve to constrain the need for additional generating ity, have been designed and are being implemented.

The pany's experience has been that the residential class of customers contributes most to the system peak and, consequently, provides the greatest opportunity for servation and load management programs.

Within the pattern of residential energy use, air tioners and water heaters are the major contributors to the peak demand. The Company has received approval of its Conservation, Cogeneration and Load ment Plan. It encompasses more than 20 programs designed to inform and assist customers in measures designed to make more efficient use of electrical energy. One of the new grams involves incentives to courage residential -customers to replace window and central air conditioners with units ing higher energy efficiency ratings than standard ment. Under this program, the Company provides rebates to set the added initial costs associated with the purchase of the more efficient equipment.

Implementation of the various programs within the Plan is expected to cost about $3 million per year. It is believed that these costs will be compensated for by reducing the amount of ment required for additional generating and transmission capacity in the future. A Good Neighbor Fund was established in 1983 to help income households meet their *energy expenses.

Customers may make contributions to the Fund through their bill ments. The Company matches donations, and all of the ceeds are administered by the Salvation Army. In November, Officers of the Company answered telephone calls from customers during an Executive Phone-In, responding to comments about service, answering questions about rates and providing information regarding conservation.

Based on the success of this initial effort, additional Phone-Ins are planned for the future. 1 3 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION General The Company has made an investment in property and plant of over $1.2 billion, which is employed to provide electric energy service to our customers.

The Company's ability to finance its construction program, maintain service reliability, meet its working capital requirements and provide a fair rate of return on investment to its shareholders is dependent upon adequate rate relief. Liquidity and Capital Re sources Co n st ruction Program During 1983, cash construction expenditures aggregated

$74 million, which is a decrease from the $118 million expenditure level experienced in 1982. This lower level of construction expenditures in 1983 is an indication of the progress the Company has made in the reduction of its construction program. The five year (1984-1988) cash construction expenditures are currently projected to be $425 million. This level of projected construction tures reflects the Company's revised capacity plan. The current capacity plan includes a forecast of peak load growth for the five year period 1984-1988of1.5%

per year. This forecast also reflects the expected results of an aggressive program for promoting conservation, menting effective load management techniques and promoting economic alternative energy sources. The construction program has been developed in response to the need to replace existing production plant, upgrade our transmission and distribution system and provide for projected growth. 1983 REVENUE DOLLAR Financing Program A total of $260 million was obtained during 1981 through 1983 via the capital markets from the sales of First Mortgage Bonds and Pollution Control Bonds, mediate-term borrowings, sale and leaseback of nuclear fuel and sales of Common Stock, including the issuance of Common Stock through the Company's Dividend ment and Stock Purchase Plan and Employee Stock Ownership Plan. Interim financing of our construction program and working capital needs was provided by the issuance of short-term debt. Approximately 40% of the cash requirements for construction, debt maturities and sinking fund ments during the period 1981-1983 were generated from operations after deductions for dividends and working capital needs, but exclusive of changes in temporary cash investments.

The Company estimates that, with adequate rate relief, an average of 559C of its total cash construction requirements, debt maturities and sinking fund ments will be generated internally during the five year period from 1984-1988.

The balance of the Company's cash requirements would be satisfied by means of external financing.

Capitalization ratios at December 31, 1983 were 45% long-term debt, 45% common and 10% preferred stock. The Company will continue to use short-term debt financing on an interim basis and currently maintains aggregate lines of credit of $115 million (see Note 11 of Notes to Financial Statements for additional details on short-term financing).

WHERE IT CAME FROM -----------Industrial

$.15 r-----------Residential

$.47

$.34

$.04 14 WHERE ITWENT :-----------

---Taxes $.22 _______ Fuel and Purchased Power $.32 ,-----------

---Labor $.08 ,..------------Depreciation

$.07 '----Preferred and Common Stock Dividends

$.09 $.05 -----------Reinvested

$.04 --------Other Materials and Services $.13 During 1983, the Company's financial position was evaluated by rating agencies.

The ratings of our first mortgage bonds, debentures and preferred stock were raised by Standard & Poor's Corporation; the ratings of our debentures, preferred stock and commercial paper were raised by Duff and Phelps, Inc. Results of Operations The tabulation on page 33 includes key historical tors which we believe are helpful in evaluating the performance of the Company over the past five years. Earnings Earnings per share of Common Stock, based on the weighted average number of shares outstanding, were $3.48 in 1983, compared to $2. 76 in 1982 and $3. 03 in 1981. Earnings per share for 1982 included the cumulative effect of a change in accounting method of$. 92 per share. The primary reasons for the increase in per share earnings between 1982 and 1983 are the effect of a 4. 6% increase in kilowatthour sales experienced during 1983, and the $74 million base revenue rate increase granted in December 1982. Revenues Operating revenues increased by from $470 million in 1981 to $517 million in 1983. This increase reflects the net result of base revenue increases, reductions in Levelized Energy Clause (LEC) revenues, and changes in hour sales and in 1982 a change in accounting method to record unbilled revenues.

Changes in unbilled revenues YEAR END CAPITALIZATION

• Short-term Debt

• L o n g-te rm Deb t

• Pr e f e rr e d S to ck

• Com m o n Eq ui ty (in p e r ce n t) 100 80 60 40 20 7 4 7 5 7 6 77 78 79 80 8 1 82 83 0 CASH REQUIREMENTS AND INTERNAL GENERATION OF FUNDS

• Maturiti es, Retirem e n ts a nd Sinkin g Fund s

• Co n s tru ct i o n cash r eq uir e m e n ts *In te rn a l Cash Ge ne r at i on (i n millions of d oll ar s) 150 120 90 60 30 79808 1 82838485868 7 88 0 -Projected

-are included in base revenues.

The effect of the above factors on 1983 and 1982 revenues is shown below: (Thousands of Dollars) 1983 1982 Base Revenues $ 92,643 20.8% $ 3,226 . 7 % LEC Rate Decreases (40,592) (9.0) (21,841) (4.6) Kilowatthour Sales 20,913 4.6 (6,890) (1.5) Increase (Decrease)

$ 72,964 16.4% $(25,505)

(5.4)% Future changes in operating revenues will reflect the timeliness and adequacy of rate relief, general economic conditions in our service area and the results of load management and conservation programs.

Sales Annual percentage increases (decreases) from the prior year in kilowatt hour sales by customer class were as follows: Increase (Decrease) from Prior Year Customer Class 1983 1982 1981 Residential Commercial Industrial Other Total 5.4% 6.6 .6 (4.4) 4.6 (2.6)% 2.4 (4.8) (2.7) (1.5) (1.4)% 4.6 (.5) 2.8 .7 The increases in 1983 are attributed to higher related consumption levels and improving economic tions for the residential and commercial segments of the service area. The decreases in 1982 kilowatthour sales were primarily the result of weak economic conditions PRE-TAX INTEREST COVERAGE RATIO (t im es cove rag e) 5 4 3 2 I 7 4 75 76 77 7 8 79 80 8 1 82 83 0 AFD C AS A PER C ENT OF NET INCOME 50 40 30 20 10 74 7 5 76 77 78 7 9 80 8 1 82 83 0 15 within certain segments of the Company's service area and increased customer conservation.

Operating Expenses The costs of owning the Company's investment in erty and plant (depreciation, taxes and cost of invested funds) were 43% and 38% of operating revenues in 1983 and 1982, respectively.

During 1983, net energy and purchased power costs decreased to a level of 32% of operating revenues versus 40% experienced in 1982. Labor, materials and other costs accounted for the 21 % of 1983 revenues versus 22% in 1982. The aggregate of fuel, interchange and purchased power costs have decreased by 11% since 1981, reflecting a favorable 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 the results of the Company's efforts toward greater use of lower cost fuel sources and the contribution of various fuel sources. The lower tribution by nuclear generation in 1983 is the result of planned and forced outages of the jointly-owned nuclear units. SOURCES OF ENERGY Net Interchange*

• Gas *Oil *Nuclear *Coal (in billions of kilowatt*

hours) U M W TI m 00 fil

• 1974-1981Import

, 1982-1983 Export 16 7 6 3 2 0 1983 1982 1981 % ¢/kwh % ¢/kwh % ¢/kwh Sources: Coal 62 2.0 48 2.6 45 2.2 Nuclear 16 .7 31 .5 22 .4 Oil 21 5.0 20 5.1 20 5.7 Natural Gas 2 6.6 3 5.1 4 5.2 Interchange (1) (2) 9 100 2.5 100 2.5 100 3.1 During 1983, Net Energy Costs were reduced by red Energy Costs of $15,055,000 representing fuel costs not currently recovered under the energy clause. This deferral is in contrast to 1982, when all previously recovered LEC costs were recovered and the Company had overrecovered costs resulting in Deferred Energy Revenues of $15,869,000 at December 31, 1982. The amount of $15,055,000 shown on the Balance Sheet as Deferred Energy Costs at December 31, 1983 ing this underrecovery, has been reflected in the 1984 LEC billing rate (see Note 3 of Notes to Financial Statements).

Power production operation and maintenance costs have increased, reflecting the higher cost of maintenance of both wholly and jointly-owned generating units. Other operation and maintenance costs have increased , ing increases in the price of materials, supplies and services, as well as increases in wages and employee benefits.

Increases in depreciation expense are consistent with the increased amount of electric utility plant in service as well as higher depreciation rates, authorized in December 1982, applicable to certain pollution control investments.

Net interest expenses have decreased 11 % since 1981, reflecting a reduction in the use of short-term ings, as well as a decline in short-term interest rates during that period. The Company has made every effort to maintain financing flexibility in support of our reduced construction program. Pollution control financing and the intermediate term variable rate debt have been used to dampen the effect of refinancing maturing debt at higher prevailing rates. The embedded cost of long-term debt has risen from 8.54% in 1981 to 9.19% in 1983. Inflation Supplementary unaudited financial information showing the estimated effects of inflation on the Company's operations is shown on pages 31 through 33. This data should be viewed as estimates of the approximate effects of inflation, rather than as precise measures.

Trends demonstrated reflect the need to control costs and point out the responsibility for regulatory agencies to provide timely and adequate rate relief.

REPORT OF MANAGEMENT The management of Atlantic City Electric Company is responsible for the financial statements presented herein. These financial statements were prepared by ment in conformity with generally accepted accounting principles applicable to public utilities which are tent in all material respects with the accounting prescribed by the State of New Jersey , Board of Public Utilities and the Federal Energy Regulatory sion. In preparing the financial statements, management made informed judgements and estimates relating to events and transactions being reported.

The Company has established a system of internal counting and financial controls and procedures designed to insure that the financial records reflect the tions of the Company and that assets are safeguarded. 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 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 cedures believed by them to provide reasonable assurance that the financial statements are not misleading and include a review of the Company's system of internal accounting and financial controls and a test of actions. The Board of Directors has oversight responsibility for determining that management has fulfilled its obligation in the preparation of financial statements and the going examination of the Company's system of internal accounting controls.

The Audit Committee, which is composed solely of outside 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 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.

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 the Atlantic City Electric Company: We have examined the balance sheets of Atlantic City Electric Company as of December 31, 1983 and 1982 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, 1983. 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, 1983 and 1982 and the results of its operations and the changes in its financial position for each of the three years in the period ended December 31, 1983, 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, 1984 17 STATEMENT OF INCOME AND RETAINED EARNINGS For the Years Ended December 31 1983 1982 1981 (Thousands of Dollars Except Per Share Amounts) Operating Revenues-Electric (Notes 1, 3 and 4) $517,142 $444,178 $469,683 Operating Expenses:

Energy: Fuel 167,988 153 , 986 154,652 (1,697) (7,459) 39,312 Deferred osts (15,055) 23,273 14,043 Net Energy 151,236 169,800 208,007 Purchased Power-Exclusive of Fuel 12,435 7,482 7,238 Power Production-Operation and Maintenance 48,794 44,650 36,206 Other Operation and Maintenance 62,800 55,648 50,107 Depreciation and Amortization 38,383 30,216 25,420 Tuxes Other Than Federal Income Tuxes (Note 14) 61,664 60,548 44,200 Federal Income Tux Expense (Note 2) 48,728 13,064 24,994 Total Operating Expenses 424,040 381,408 396,172 Operating Income 93,102 62,770 73,511 Other Income: Allowance for Equity Funds Used During Construction 4,320 3,354 6,045 Miscellaneous Income-Net 833 3,571 3,684 Total Other Income 5,153 6,925 9,729 Income Before Interest Charges 98,255 69,695 83,240 Interest Charges: Interest on Long Term Debt 33,795 36,650 30,831 Interest on Short Term Debt 2,669 2,362 8,150 Other Interest Expense 535 633 1,323 Total Interest Charges 36,999 39,645 40,304 Allowance for Borrowed Funds Used During Construction (4,896) (5,079) (4,052) Net Interest Charges 32,103 34,566 36,252 Income Before Cumulative Effect of Change in Accounting Method 66,152 35,129 46,988 Cumulative Effect of Change in Accounting Method (Note 4) 13,926 Net Income 66,152 49,055 46,988 Retained Earnings at Beginning of Year 128,825 121,078 108,977 194,977 170,133 155,965 Dividends Declared:

On Cumulative Preferred Stock 7,171 7,353 7,508 On Common Stock 39,352 33,955 27,379 Total Dividends Declared 46,523 41,308 34,887 Retained Earnings at End of Year $148,454 $128,825 $121,078 Earnings for Common Stock: Net Income $ 66,152 $ 49,055 $ 46,988 Less Preferred Dividend Requirements 7,201 7,368 7,531 Balance Available for Common Stock $ 58,951 $ 41,687 $ 39,457 Average Number of Shares of Common Stock Outstanding (in thousands) 16,923 15,116 13,034 Per Common Share: Earnings Before Cumulative Effect of in Accounting Method $ 3.48 $ 1.84 $ 3.03 Cumulative Effect of Change in Accounting ethod .92 Total Earnings $ 3.48 $ 2.76 $ 3.03 Dividends Declared $ 2.32 $ 2.24 $ 2.08 Dividends Paid $ 2.30 $ 2.20 $ 2.04 The accompanying Notes to Financial Statements are an integral part of these statements.

18 STATEMENT OF CHANGES IN FINANCIAL POSITION For the Years Ended December 31 1983 1982 1981 (Thousands of Dollars) Source of Funds: Funds from Operations:

$ 66,152 Income Before Cumulative Effect of Change in Accounting Method $ 35,129 $ 46,988 Principal Non-Cash Charges (Credits) to Income: Depreciation and Amortization 38,383 30,216 25,420 Amortization of Nuclear Fuel 4,863 2,951 Allowance for Funds Used During Construction (9,216) (8,433) (10,097) Deferred Federal Income Taxes-Net 16,382 11,427 14,648 Investment Tux Credit Adjustments-Net 6,114 12,547 7,141 Other-Net 1,353 396 199 Total Funds from Operations 119,168 86,145 87,250 Cumulative Effect of Change in Accounting Method 13,926 Funds from Outside Sources: Long Term Debt 50,000 45,000 60,000 Pollution Control Funds (Held) Released by Trustees 7,885 15,098 (27,874) Subtotal 57,885 60,098 32,126 Sale of Common Stock 15,060 41,166 32,441 Sale of Nuclear Fuel 21,140 Increase (Decrease) in Short Term Debt (25,825) 10,525 Total Funds from Outside Sources 72,945 96,579 75,092 Other-Net (1,524) 3,287 (3,355) Total Source of Funds $190,589 $199,937 $158,987 Application of Funds: Gross Additions to Utility Plant $ 83,673 $126,893 $123,318 Property Abandonment Costs --(15,956) Allowance for Funds Used During Construction (9,216) (8,433) (10,097) Net 74,457 118,460 97,265 Dividends on Preferred Stock 7,171 7,353 7,508 Dividends on Common Stock 39,352 33,955 27,379 Retirement and Maturity of Loefc Term Debt 50,300 28,996 5,682 U nrecovered Purchased Power osts 7,152 Property Abandonment Costs 15,956 Conversion of Preferred Stock 711 847 1,993 Redemption of Preferred Stock 2,100 800 800 Increase in Working Capital* 9,346 9,526 2,404 Total Application of Funds $190,589 $199,937 $158,987 Increase (Decrease) in Working Capital* Cash and Cash Items $(11,616)

$ 13,286 $ 3,845 Accounts Receivable 7,312 (7,275) 10,740 Unbilled Revenues 5,671 18,994 -Fuel (5,146) (2,645) 5,890 Materials and Suptlies 974 (420) 2,365 Deferred osts and Revenues 30,924 (39,046) (14,104) Accounts Payab e (1,647) 3,923 2,959 Tuxes Accrued (3,831) 8,512 (5,285) Deferred Tuxes (9,534) 7,508 3,894 Other (3,761) 6,689 (7,900) Increase in Working Capital $ 9,346 $ 9,526 $ 2,404 *Excludes Short Turm Debt, Notes and Current Maturities of Long Turm Debt and Cumulative Preferred Stock Subject to Mandatory Redemption.

The accompanying Notes to Financial Statements are an integral part of these statements.

19 BALANCE SHEET December 31, (Thousands of Dollars) Assets Electric Utility Plant (Notes 1 and 6): In Service: Production Transmission Distribution General Total Less Accumulated Depreciation Net Construction Work in Progress Nuclear Fuel Electric Utility Plant-Net Non Utility Property and Investments (Note 7) Pollution Control Construction funds (Note 10) 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 (Note 1) Unrecovered Purchased Power Costs (Notes 1 and 3) Unrecovered Nuclear Fuel Disposal Costs (Note 6) Unamortized Debt Expense Other Total Deferred Debits Total Assets The accompanying Notes to Financial Statements are an integral part of these statements. 20 1983 1982 $ 509,192 $ 492,415 184,184 170,297 308,352 300,079 44,243 37,632 1,045,971 1,000,423 274,362 247,008 771,609 753,415 179,162 152,403 557 495 951,328 906,313 7,981 6,432 4,891 12,776 3,285 3,752 7,100 18,249 33,950 25,967 7,666 8,037 (1,500) (1,200) 24,665 18,994 21,785 26,931 17,195 16,221 10,944 9,382 15,055 140,145 126,333 18,352 19,680 7,152 4,802 3,163 3,257 2,164 3,178 35,633 26,115 $1,139,978

$1,077,969 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) Accounts Payable Taxes Accrued Interest Accrued Dividends Declared Deferred Energy Revenues (Notes 1 and 3) Customer Deposits Deferred Taxes (Notes 1 and 2) Other Total Current Liabilities Deferred Credits: Deferred Investment Tax Credits (Notes 1 and 2) Deferred Income Taxes (Notes 1 and 2) Nuclear Fuel Disposal Costs (Note 6) Other (Note 6) Total Deferred Credits Commitments and Contingent Liabilities (Notes 12 and 13) Total Liabilities and Capitalization 1983 1982 $ 51,753 $ 49,722 208,279 195,293 72 48 (1,637) (1,738) 148,454 128,825 406,921 372,150 41,973 42,684 52,050 54,150 380,266 368,220 881,210 837,204 1,050 1,050 26,000 39,050 24,124 22,477 8,299 4,468 10,658 5,800 11,940 11,278 15,869 2,618 2,757 18,271 8,737 4,079 4,137 107,039 115,623 55,386 49,272 81,318 64,936 10,888 4,137 10,934 151, 729 125,142 $1,139,978

$1,077,969 21 NOTES TO FINANCIAL STATEMENTS Note 1. Significant Accounting Policies:

Regulation-The accounting policies and rates of the Company are subject to the regulations of the State of New Jersey, 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 dered to our 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 ment 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 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 1983 and 1982, as ordered by the BPU, and 8% for 1981. Such rates are less than the maximum allowed by FERC. Deferred Energy Costs and Revenues-The Company has a Levelized Energy Clause (LEC) which is based on 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 nized in the Statement of Income during the period in which they are subsequently recovered through the clause. 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 average 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. 7% for 1983 and 3.3% for 1982 and 1981. Accumulated depreciation is charged with the cost of 22 depreciable property retired together with removal costs less salvage and other recoveries.

Nuclear Fuel-Fuel costs associated with the Company's participation in jointly-owned nuclear generating stations (including a provision for estimated spent fuel disposal costs) are charged to Fuel Expense based on the units of thermal energy produced.

See also Notes 6 and 13. Federal Income Taxes-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) 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, accrual of unbilled revenues, as well as unrecovered purchased power and nuclear fuel disposal costs. ment Tax Credits are deferred on the balance sheet and are recognized in book 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 a noncontributory 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 offshore nuclear units which were cancelled in 1978. The Hope Creek No. 2 investment of $15,956,476 is being amortized over a 15-year period beginning in 1983. The offshore nuclear units are being amortized over a 20-year period. Unrecovered Purchased Power Costs-These represent purchased capacity costs, relative to a specific purchased power agreement, which are not being recovered rently, but for which recovery has been specifically provided in a levelized component of future rates (See Note 3). Other-Capital Stock expense is being amortized on a ratable basis over 20 years. 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) Net Income Federal Income Tux Expense (as below) Book Income Subject to Tux Income Tax at Statutory Rate (46%) Adjustments for items for which deferred taxes are not provided:

Tux Depreciation less than Book Depreciation Allowance for Funds Used During Construction Capitalized Overheads Investment Tux Credits Other Total Federal Income Tux Expense Components of Federal Income Tux Expense: Federal Income Tuxes Currently Payable Deferred Federal Income Tuxes: Liberalized Depreciation Unbilled Revenues Property Abandonment Costs U nrecovered Purchased Power Costs Unrecovered Nuclear Fuel Disposal Costs Deferred Energy Costs and Revenues Gains on Reacquired Debt and Purchased Tux Benefits Other Deferred Investment Tax Credits Employee Stock Ownership Plan Credits Tutal Deferred Federal Income Tux Expense Less: Federal Income Taxes-Other Income Deferred Federal Income Tuxes on the Cumulative Effect of Change in Accounting Method Federal Income Tuxes included in Operating Expenses The Company has purchased tax benefits on equipment having an aggregate tax basis of approximately

$10,400,000, $2,900,000 and $2,600,000 in 1983, 1982 and 1981, respectively. Such tax benefits include 6% ment tax credit and an ACRS life of 3 years. The Company's federal income tax returns for 1979 and prior years have been examined by the Internal Revenue Service (IRS) and the Company's federal income tax Debt premium, discount and expenses are amortized over the life of the related debt. All gains and losses relating to reacquired debt are recognized currently.

Certain 1982 and 1981 amounts have been reclassified to conform with 1983 presentations. the statutory rate on book income subject to tax for the following reasons: 1983 1982 1981 $ 66,152 $ 49,055 $ 46,988 49,061 27,004 27,332 $115,213 $ 76,059 $ 74,320 $ 52,998 $ 34,987 $ 34,187 1,896 808 212 (4,211) (3,879) (4,645) (1,245) (1,301) (1,242) (1, 775) (1,485) (1,075) 1,398 (2,126) (105) $ 49,061 $ 27,004 $ 27,332 $ 15,072 $ (1,672) $ 13,950 11,013 9,879 6,195 2,609 8,737 (520) (74) 6,626 3,290 2,209 6,925 (5,904) (8,698) 713 2,319 1,512 (323) (697) 315 6,114 12,547 7,141 1,959 1,869 291 33,989 28,676 13,382 49,061 27,004 27,332 333 2,077 2,338 11,863 $ 48,728 $ 13,064 $ 24,994 liabilities for all years through 1976 have been determined and settled. The IRS has proposed certain deficiencies in tax for the years 1977 through 1979. The Company has protested 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.

23 Note 3. Rate Matters: During the three year period ended December 31, 1983 base rate increases have been approved by the BPU as Date of Amount Da te Petition Requested Effective (millions) August 1981 $ 14.4 (1) Jan. 29, 1982 February 1982 172.4 Dec. 14, 1982 January 1983 30.8 Oct. 7, 1983 follows, based in each case on the applicable test year indicated:

Amount Increase Te st Apr.roved In Revenue Year (million s) $ 11.3 2.4% June 30, 1980 73.7 16.3 Sept. 30, 1982 24.5 4.5 Sept. 30 , 1982 (1) The Company's request was to recognize the cost of its share of the Salem Nuclear Generating Station Unit No. 2. In December 1982, the New Jersey Board of Public Utilities (BPU) granted the Company an increase of $73, 700,000 in base rates. In reaching its decision, the BPU computed the Company's revenue requirement as if the Company recorded unbilled revenues on its books and 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 granted a second phase of the base rate proceeding to review the Company's load forecast and capacity plans and the revenue requirements ated with the performance under a Capacity and Energy Sales Agreement dated September 24, 1979 (the quehanna Agreement), which provided for the purchase by the Company through September 30, 1991of5.94%

of the net capacity and energy output of each of nia Power & Light Company (PP & L)'s two 1,050 megawatt Susquehanna nuclear units, the first of which was declared in commercial operation on June 8, 1983. In January, 1983, the Company requested the rate relief required to perform under the Susquehanna Agreement.

In March, 1983, the BPU disapproved that request based on a finding that the Susquehanna Capacity and Energy Agreement was not needed and not economic.

In April, 1983, FERC accepted the Susquehanna Agreement for filing. The Company and PP&L conducted negotiations in an effort to resolve the dispute, due to conflicting regulatory orders, relating to the purchase of capacity and energy from PP&L's Susquehanna Units. As a result of the negotiations, the Company and PP&L reached agreement on a new 17-year arrangement providing for the pany's purchase of 125,000 kilowatts of capacity and the associated energy from the Susquehanna units through September 30, 1991 and thirteen wholly-owned PP&L coal-fired units from October 1, 1991 through September 30, 2000. Based on the new 17-year arrangement, the Company in July, 1983, updated its filing before the BPU, requesting revenues to recover the first year of costs associated with the purchase of capacity and energy under the arrangement.

During the course of the hearings in the 24 proceeding, the BPU Staff, the Department of the Public Advocate, Division of Rate Counsel, the New Jersey Energy Users Association and the Company, held a series of discussions with a view toward settling the matter. These discussions resulted in a joint stipulation which was presented to the BPU. On September 29, 1983, the BPU announced that it had approved the 17-year chase power arrangement, accepted the joint stipulation and had granted the Company a net annual increase in revenues of $12,400,000 designed to recover the estimated net costs associated with the purchase of 62,500 kilowatts from Susquehanna Unit No. 1 and from coal generation under the 17-year arrangement.

The net increase reflects a $24,500,000 increase in base rates and a $12,100,000 crease in energy clause rates. The net increase was made effective for service rendered on or after October 7, 1983. Under the BPU Order and stipulation, the annual costs to be recovered through the increased base rates reflect a levelization of estimated costs over the 17-year period of the arrangement.

During the period June 8, 1983 through September 30, 1991, the estimated costs to be incurred by the Company for purchases of capacity and associated energy from Susquehanna Unit No. 1 will exceed the levelized costs to be recovered by the Company from its customers. Such unrecovered costs will be accumulated and deferred.

The net covered costs to the Company as of December 31, 1983 aggregate

$7,152,000.

Such costs are included in the Balance Sheet as Unrecovered Purchased Power Costs, along with the related provision for deferred taxes of $3,290,000.

The level of rates approved by the BPU is designed to enable the Company to recover these deferred costs and associated carrying charges during the balance of the 17-year period. The stipulation provides that any difference between actual costs incurred by the Company under the arrangement and the estimated costs on which the increased rates were based will be nized in future base rate proceedings if such costs are not found to be unreasonable.

The BPU order prescribes a revenue reduction formula in the event that both Susquehanna Units fail to meet a combined minimum performance standard established by the stipulation which could subject the Company , under the most adverse circumstances, to a revenue reduction no t to exceed $15,000,000 per unit per year. The stipulation also recognizes that increased rates to recover the net levelized costs associated with the remaining 62,500 kilowatts to be purchased from quehanna Unit No. 2 and from coal generation should be authorized by the BPU upon the commercial operation of Susquehanna Unit No. 2. On October 14, 1983 the Company filed a request with the BPU for a $53,400,000 (10.8%) increase in total revenues.

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. Previously, 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 $6,563,000, $5,908,000 and $5,476,000 in 1983, 1982 and 1981, respectively. imately 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: The Company's request consisted of a net $28,100,000 increase in energy clause revenues to become effective January 1, 1984 and a $25,300,000 increase in base revenues to become effective no later than mid-1984.

The BPU has approved a $28,100,000 increase in energy clause revenues, effective January 20, 1984, and accepted a joint stipulation regarding that filing. The Company cannot presently predict the final outcome of the base revenue request proceedings or the effect, if any, on the Company. with service rendered from the time the meters were last read to the end of the period. The cumulative effect of this change as of January 1, 1982 was $13,926,000 (after the related provisions for federal income taxes of $11,863,000) and is separately identified in the 1982 Statement of Income and Retained Earnings.

January 1 (Thousands of Dollars) Actuarial present value of accumulated plan benefits:

Vested Nonvested Total Net Assets available for benefits 1983 $79,111 1,124 $80,235 $99,100 1982 $72,156 1,495 $73,651 $85,823 The weighted average assumed rate of return used in determining the actuarial present value of accumulated plan benefits was 7% for 1983 and 1982. The Company's Plan is in compliance with the Employee Retirement Income Security Act of 1974. Note 6. Jointly-Owned Generating Stations and Nuclear Fuel: The Company participates with other utilities in the The amounts shown represent the Company's share of construction and operation of several jointly-owned elec-each jointly-owned plant at December 31, and include an tric production facilities.

allowance for funds used during construction.

Electric Plant Construction Energy Company's in Service Work in Progress Generation Station Source Share 1983 Keystone Coal 2.47% $ 6 , 313 Conemaugh Coal 3.83 11,600 Peach Bottom Nuclear 7.51 74,055 Salem Nuclear 7.41 152,639 Hope Creek Nuclear 5.00 The operators of the Salem and Peach Bottom Nuclear Generating Stations entered into contracts with the $ 1982 1983 1982 1983 1982 (Thousands of Dollars) (KWHs) 5,808 $ 590 $ 495 244,672 261,237 11,547 127 92 400,441 273,738 72,584 6,358 1,587 513,629 996,769 145,505 3,111 4,140 452,691 883,903 130,390 99,555 United States Department of Energy for spent nuclear fuel disposal.

These contracts require the payment of a 25 one-time fee related to the Company's ownership interest in the Salem and Peach Bottom Stations through April 6, 1983, as well as quarterly charges after April 6, 1983. At December 31, 1983 the Company's liability for its share of the one-time fee related to nuclear fuel disposal costs is $10,888,000, of which $4,802,000 remains to be recovered from customers.

Previous recoveries of nuclear fuel disposal costs of $5,650,000 were included in Other Deferred Credits at December 31, 1982. The Company, in its energy clause effective in January 1984 (see Note 3), 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 $3,291,000 at December 31, 1983 and $2,841,000 at December 31, 1982. 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 (after deducting contract charges) are charged to the Company. These costs are Note 8. Common Stock: As of December 31, 1983 and 1982, the Company's Common Stock included 25,000,000 authorized shares 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 1983 and 1982 with $12,986,000 and $34,793,000, respectively, senting the excess of proceeds over the par value of shares of Common Stock issued, sold and converted.

At December 31, 1983 there were 517,554 and 107,494 shares of Common Stock authorized for issuance pursuant to Note 9. Cumulative Preferred Stock: The Company has authorized 799,979 shares of tive Preferred Stock, $100 Par Value, 2,000,000 shares of No Par Preferred Stock, and 3,000,000 shares of ence Stock, No Par Value. Unissued shares may, or may not, possess mandatory redemption characteristics upon 26 has received approval for recovery of unrecovered nuclear fuel disposal costs over a two year period. Current rates are adequate to recover costs since April 6, 1983. 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 (see Note 13). included in the Company's accounts classified as to operation, maintenance and taxes. The Company also has an investment in Atlantic ing, Inc. (Housing), a wholly-owned subsidiary.

Housing's principal investment is a 20% undivided interest as tenant in common in a future generating station and industrial site, the amount of which is not material to the Company. of Common Stock ($3 par value). Shares issued and outstanding:

1983 16,574,021 535,614 116,347 24,900 17,250,882

$51, 752,646 1982 14,427,990 1,500,000 487,601 128,797 29,633 16,574,021

$49, 722,063 1981 12,538,880 1,500,000 302, 726 16,641 69,743 14,427,990

$43,283,970 the Dividend Reinvestment and Stock Purchase Plan and the Employee Stock Ownership Plan, respectively.

At December 31, 1983, 69,070 shares of Common Stock were reserved for the conversion of 5%% Convertible Series of Preferred Stock. issuance.

In certain circumstances, if dividends on issued 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

Current Cumulative Preferred Stock Not Subject to Mandatory Redemp-Redemption is redeemable solely at the option of the ti on December 31 Price Company upon payment of the redemption price plus 1983 1982 Per accumulated and unpaid dividends to the date fixed for ___________ (T_h_o_u_s_an_d_s_o_f_D_o_lla_r_s)

__ Sh_a_re redemption. Premium on such Preferred Stock was $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 5 Vs% Convertible Series: 19,729 Shares (1983) 26,844 Shares (1982) 7.52% 100,000 Shares Total Note 9(B). $ 7,700 7,200 1,500 3,600 5,000 5,000 1,973 10,000 $41,973 $ 7,700 7,200 1,500 3,600 5,000 5,000 2,684 10,000 $42,684 $105.50 101.00 101.00 101.00 101.00 100.00 101.50 104.89 $93,000 at December 31, 1983 and 1982. The 5%% Convertible Series, of which 7,115 and 8,469 shares were converted in 1983 and 1982, 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.

Cum u lative Preferred Stock Subject To Mandatory Redemption

December 31 Current Refunding Restricted Prior to Par 1983 1982 Redemption Value (Thousands of Dollars) Price Per Share Shares Issued and Outstanding:

Series: 8.40% 100,000 Shares $100 $10,000 9.96% 136,000 Shares (1983) 100 13,600 152,000 Shares (1982) 100 $8.25 95,000 Shares (1983) None 9,500 100,000 Shares (1982) None $9.45 200,000 Shares None 20,000 53,100 Less Portion due within one year 1,050 Total $52,050 On August 1, 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 16,000 and 8,000 shares at par in 1983 and 1982, respectively.

On November 1, 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. T h e Company redeemed 5,000 shares at par in 1983. On February 1, 1985, and annually thereafter, 4,000 $10,000 $115.00 106.78 August 1 , 1984 15,200 106.99 November 1, 1987 10,000 20,000 55,200 1,050 $54,150 shares of the 8.40% 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 4,000 shares may be redeemed on any sinking fund date without premium, up to 32,000 shares in the aggregate.

On November 1, 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.

The minimum sinking fund provisions of the above series aggregate

$1,050,000 in 1984, $1,450,000 in 1985, and $5,450,000 in 1986, 1987 and 1988. 27 Note 10. Long Term Debt: Deposits in sinking funds for retirement of debentures December 31 , 1983 1982 are required on February 1 of each year through 1995 for (Thousands of Dollars) the 5Y4% debentures, and on May 1 of each year through First Mortgage Bonds: 1997 for the 7Y4% debentures in amounts in each case 3 V 4% Series due (January 1) 1983 $ $ 4,050 sufficient to redeem $100,000 principal amount plus, at 9%% Series due (May 1) 1983 35,000 the election of the Company, up to an additional

$100,000 3% Series due (March 1) 1984 5,000 5,000 principal amount in each year. At December 31, 1983 the 9% Pollution Control Series due Company had reacquired and cancelled

$1,433,000 and (May 1) 1984 21,000 21,000 $1,281,000 principal amount of the 5Y4% and 7%% deben-3 1/4% Series due (March 1) 1985 10,000 10,000 tures, respectively, toward its requirements for 1984 and 4 1 12% Series due (January 1) 1987 10,000 10,000 3 7/s% Series due (April 1) 1988 10,000 10,000 subsequent periods. 4 1/2% Series due (April 1) 1989 2,775 2,775 A sinking fund requirement of $3,000,000 each year 4 1/2% Series due (March 1) 1991 10,000 10,000 4 1/2% Series due (July 1) 1992 10,350 10,350 relative to the 12%% First Mortgage Bonds begins in 1986 4%% Series due (March 1) 1993 9,540 9,540 and continues through 2010. At December 31, 1983 the 11'1/s% Series due (November

1) 1993 50,000 Company had reacquired and cancelled

$11,250,000 princi-5 1/s% Series due (February

1) 1996 9,980 9,980 pal amount of the 12 5/s% Series toward its requirements 8'1/s% Series due (September

1) 2000 19,000 19,000 for 1986 and subsequent periods. Current sinking fund 8% Series due (May 1) 2001 27,000 27 , 000 7 V2% Series due (April 1) 2002 20,000 20,000 requirements of $900,000 in connection with certain First 7%% Series due (June 1) 2003 29,976 29,976 Mortgage Bonds outstanding, are being satisfied by 7%% Pollution Control Series due certification of property additions as provided for in the (January 1) 2005 6,500 6,500 related mortgage indentures.

6%% Pollution Control Series due (December

1) 2006 2,500 2,500 During 1983 and 1982 the Company reacquired, at 12%% Series due (January 1) 2010 63,750 75,000 amounts at or below par value, $11,250,000 and 11 %% Pollution Control Series due (May 1) 2011 39,000 39,000 $9 , 209,000, respectively, principal amount of First Mort-356,371 356,671 gage Bonds. These reacquisitions resulted in a loss in Debentures:

1983 and a gain in 1982, both net of Federal income taxes 5%% Sinking Fund Debentures due and expenses, of $8,000 and $1,816,000, respectively. (February

1) 1996 2,267 2,267 The aggregate amount of debt maturities in addition to 7 1 14% Sinking Fund Debentures due sinking fund requirements of all long term debt outstand-(May 1) 1998 2,619 2,619 ing at December 31, 1983 are $26,000,000 in 1984, 4,886 4 , 886 $10,000,000 in 1985, $45,000,000 in 1986, $10,000,000 in Notes: 1987 and 1988. Variable Rate Notes due (April 30) 1986 45,000 45,000 The amounts of $3,254,000 and $2, 785,000 as of December 45,000 45 , 000 31, 1983 and 1982, respectively, which represent the Unamortized Premium and accumulated investment earnings on the net available Discount-Net 9 713 proceeds of certain pollution control financings, are 406,266 407 , 270 included in Miscellaneous Accounts Receivable.

Such Deduct Long Term Debt amounts are restricted for use on the related pollution due within one y ear (26,000) (39 , 050) control projects.

$380,266 $368,220 2 8 Note 11. Short Term Debt and Compensating Balances:

As of December 31, 1983, the Company had bank lines of credit available for use of $115,000,000.

The Company is required, with respect to $20,000,000 of these credit lines, to maintain average compensating balances of $800,000.

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, the Company pays commitment fees (currently l4%) which aggregated

$269,000 for 1983, $390,000 for 1982 and $401,000 for 1981. Certain other information regarding short term debt follows: (Thousands of Dollars) 1983 1982 1981 For the year ended-Maximum amount of total short term debt at any month-end:

Commercial Paper Notes Payable to Banks Average amount of short term debt (based on daily ing balances):

Commercial Paper Notes Payable to Banks Weighted daily average interest rates on short term debt: Commercial Paper Notes Payable to Banks As of end of year-Weighted average interest rate for short term debt outstanding:

Commercial Paper Notes Payable to Banks $50,000 $22,000 $ 7,000 $ 3,000 $23,954 $10,550 $ 2,567 $ 4,497 9.0% 12.8% 9.3% 13.7% Note 12. Commitments and Contingencies:

$62,475 $ 7,500 $43,284

$ 3,661 16.4%

16.7% 12.2% 12.8% Total construction expenditures for 1984 are estimated at approximately

$94,000,000, which includes $36,679,000 for jointly-owned facilities.

Current commitments for the construction of major production and transmission ties amount to approximately

$48,000,000 of which it is estimated approximately

$22,000,000 will be expended in 1984. These amounts exclude allowance for funds used during construction.

The Company is a member of certain insurance programs which provide coverage for property damage to members' nuclear generating plants. Facilities at the Peach Bottom and Salem Stations are insured against property damage losses up to $1.0 billion per site under these programs.

The Company is also a member of an insurance program which provides insurance coverage for the cost of ment power during prolonged outages of nuclear units caused by certain specific conditions.

Under the property and replacement power insurance programs, the pany could be assessed retrospective premiums in the event the insurers' losses exceed their reserves.

As of December 31, 1983, the maximum amount of retrospective premiums the Company could be assessed for losses during the current policy year was $7.9 million under these programs.

In the event of a nuclear incident at any of the facilities covered by the federal government's third-party liability indemnification program, the Company could be assessed up to $1.5 million per incident, but not more than $3.0 million in a calendar year in the event more than one incident is experienced.

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 has an agreement with Allegheny Power System (APS) which entitles the Company to 50 MW of coal-fired capacity from the APS Pleasants Station through 1985. This agreement was modified for the years 1983 and 1984 to provide the Company access to a cogeneration source on an APS subsidiary's operating system. The Company has also agreed to purchase certain capacity and energy output from PP&L under the Susquehanna and Coal Units Agreements (see Note 3). In July 1983 the BPU approved an Agreement between the Company, Public Service Electric and Gas Company (PSE&G), the New Jersey Department of Energy (DOE) and the New Jersey Department of the Public Advocate (PA) which establishes an incentive program to contain the continuing construction costs of Hope Creek Unit No. 1, which is currently 80% complete and scheduled for completion in 1986. Under the Agreement, if the final cost of the facility is less than $3.55 billion, the Company's shareholders could share in the savings. On the other hand, if the final cost of the unit exceeds $3. 7952 billion, the Company could be penalized by not being able to earn a return on the entire amount of the cost overrun. As a part of this Agreement, the DOE and the PA have agreed not to challenge the need for the unit in which the Company has a 5% ownership interest.

29 During February 1983, while Unit No. 1 of the Salem Nuclear Generating Station, which is operated by PSE&G, was in a low power restart phase, automatic shutdown controls failed to operate upon signal. The Unit was shutdown manually in accordance with established procedure, without further incident.

While Unit No. 1 was shutdown, PSE&G, as recommended by the Nuclear Regulatory Commission (NRC), performed the necessary corrective maintenance and reverifications of the ability of the Unit's safety-related systems. As authorized by the NRC, such performance enabled Unit No. 1 to return to service in May 1983. In proceedings before the BPU, PSE&G has maintained that its additional replacement power costs associated with the extended outage of Salem Unit No. 1 will be offset by extending the period during which the unit will be operated prior to the next scheduled refueling outage. The Company has also incurred replacement energy costs associated with the extended outage of Salem Unit No. 1, and cannot predict what action may be ultimately taken by the BPU with respect to the Company's replacement energy costs. The Company cannot predict the final outcome or the effect of the final outcome, if any, of these matters on the Company or its operations.

Note 13. Leases: The Company has certain obligations related to the use of nuclear fuel, property and equipment which, in dance with criteria established by the Financial Accounting Standards Board (FASB), are capital leases, but are accounted for as operating leases in accordance with the ratemaking treatment.

An accounting standard issued by the FASB in December 1982 requires that the Company record such leases on its balance sheet by 1987. Recording capital leases would not have a material effect on assets or liabilities, and would not affect income, since the total amortization of the leased assets and the interest on the lease ob l igation would equal the rental expense currently allowed for ratemaking purposes.

Rentals charged to operating expenses were as follows: (Thousands of Dollars) 1983 1982 1981 Nuclear Fuel $ 6,364 $ 6 , 090 $4,002 Other 5,268 5,940 5,652 Total $11,632 $12,030 $9,654 30 The Company's contractual liability to purchase nuclear fuel under a nuclear fuel agreement for Salem and Hope Creek Generating Stations as of December 31, 1983 was approximately

$28,000,000.

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. Nuclear fuel requirements for Peach Bottom Generating Station are being prov i ded by the operating company through a fuel purchase contract. The Company is responsible for payment of its share of fuel consumed and interest expense. Such costs have been included in the above nuclear fuel rental expense. The future minimum rental commitments under all noncancelable lease agreements are not significant.

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 (Thousands of Dollars) Tuxes Other Than Federal Income Tuxes: State Gross Receipts and Franchise Tuxes Real and Personal Property Taxes Payroll Tuxes-Federal and State Miscellaneous State and Local Tuxes Total Maintenance Expense 1983 $55 , 324 1,947 2,755 1,638 $61,664 $35,066 1982 1981 $58,064 $39,914 1,633 918 2,455 2,078 (1,604) 1,290 $60,548 $44,200 $30,313 $28,087 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 necessary in the opinion of the Company for a fair (which consist of only normal recurring accruals) presentation of such amounts are as follows: Operating Operating Earnings For Earnings Quarter Revenues Income Income Common Stock Per Share (Thousands of Dollars) 1983 1st $121,977 $21,469 2nd 119,476 18,640 3rd 157,450 37,356 4th 118,239 15,637 $517,142 $93,102 1982 1st $128,259 $13,875 2nd 103,044 14,464 3rd 115, 794 22,080 4th 97,081 12 ,35 1 $444,178 $62,770 1981 1st $112,762 $18,969 2nd 101,908 15,194 3rd 133,552 24,963 4th 121,461 14,385 $469,683 $73,511 (1) The individual quarters may not add to the total due to the increasing average number of common shares outstanding at the end of each quarter. (2) Results for 1982 do not include the cumulative effect on net income and earnings for common stock of $13,926,000 (net of tax) or on earnings per share of $.92 ($.96 based on average s hare s outstanding in the first $14,526 $12,705 $ .76 11,874 10,057 .60 30,597 28,808 1. 70 9,155 7 ,38 1 .43 $66,152 $58,951 $3.48 (I) $ 7,191 (2) $ 5,337 (2) $ .37 (2) 8,52 1 6,668 .46 13 ,788 11,938 .81 5,629 3,818 .23 $35,129 (2) $27,761 (2) $1.84 (I) (2) $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 (I) quarter) of a 1982 accounting change to record unbilled revenues (See Note 4). 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 ent methods. 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 lars). 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 tion. 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.

31 STATEMENT OF INCOME FROM CONTINUING OPERATIONS ADJUSTED FOR CHANGING PRICES Year Ended December 31, 1983 (In Average 1983 Dollars) In Constant At Current Results of Operations: (Thousands of Dollars) Historical Dollars Cost Operating Revenues Operating Expenses:

Operation and Maintenance Expenses Depreciation and Amortization Expense Federal Income Tax Expense Other Income from Continuing Operations Depreciation and amortization expense expressed in constant dollar and current cost amounts were mined using the rates and methods used for computing book depreciation and amortization applied to utility plant balances reexpressed 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 ratably over the year. Accordingly, the stated amounts already reflect, in effect, average 1983 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. fore, the Company's effective tax rate rises from 42.6% under the historical cost basis to 72.6% and 75.6% 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 14 of the annual report. Current Year Effect of Increased Price Levels: (Thousands of Dollars) Increases in General Price Levels on Utility Plant Held $63,838 Increase in Specific Prices on Utility Plant Held 63,520 Excess of Increase in General Price Levels Over Increases in Specific Prices $ 318 At December 31, 1983 the cost of utility plant, net of accumulated depreciation was $1, 726,832,000 on a stant dollar basis and $1, 764,301,000 on a current cost basis, while historical cost was $951,328,000.

The lated provisions for depreciation and amortization under both constant dollar and current cost methods were estimated for each major class of utility plant (production; transmission; distribution and general plant) by multiply-32 $517,142 $517,142 $517,142 336,929 336,929 336,929 38,383 79,076 82,787 48,728 48,728 48,728 26,950 26,950 26,950 $ 66,152 $ 25,459 $ 21,748 ing the respective cost data by a percentage representing the expired life of existing facilities of each class at December 31, 1983. Fuel inventories, the cost of fossil fuels used in tion, 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 sions to which the Company is subject, only the historical cost of utility plant is recoverable in revenues as ation. 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 ing prices must be considered in terms of its net able cost which is historical cost. While the rate making process gives no recognition to the current cost of placing 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 $18,572,000.

During a period of flation, holders of monetary assets such as cash and ceivables 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 datory 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 making 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 1979 Dollars) Years Ended December 31 1983 1982 1981 1980 Operating Revenue -historical

$ 517,142 $ 444,178 $ 469,683 $358,391 -in constant dollars Ca) 376,639 333,786 374,850 315,697 Income from Continuing Operations -historical

$ 66,152 $ 49,055 $ 46,988 $ 38,538 -in constant dollars Ca) 18,542 3,998 6,223 7,592 -at current cost Ca) 15,839 3,036 6,104 4,884 Income from Continuing Operations per Share of Common Stock Cb) -historical

$ 3.48 $ 2.76 $ 3.03 $ 2.62 -in constant dollars .79 (.10) .01 .18 -at current cost .63 (.17) .01 (.03) Effective Income Tux Rate -historical 42.6% 35.5% 36.8% 33.8% -constant dollar basis 72.6 87.1 81.5 72.2 -current cost basis 75.6 89.9 81.7 80.1 Excess of Increases in General Price Levels Over Increases in Specific Prices (a) $ 232 $ (5,366) $ (20,115) $ 38,368 Decline in Purchasing Power of Amount Owed <a> $ 13,526 $ 16,282 $ 31,582 $ 39,654 Net Assets at Year End -historical

$ 448,894 $ 414,834 $ 338,846 $324,127 -in constant dollars (avg.) 320,913 306,335 261,688 272,699 Net Income as a Percent of Operating Revenue -historical 12.79% 11.04% 10.00% 10.75% -trended in 1979 dollars 9.32 8.30 7.98 9.47 Earned Rate of Return on Shareholders' Equity -historical 14.49% 11.20% 12.21% 11.62% -trended in 1979 dollars 10.55 8.41 9.74 10.24 Tutal Assets at Year End-historical

$1,139,978

$1,077,969

$1,013,789

$879,795 Long Term Debt and Cumulative Preferred Stock Subject to Mandatory Redemption -historical

$ 459,366 $ 462,470 $ 447,389 $394,288 Dividends Declared per Share of Common Stock -historical

$ 2.32 $ 2.24 $ 2.08 $ 1.93 -in constant dollars 1.69 1.68 1.66 1.70 Market Price per Common Share at Year End -historical

$ 23.25 $ 20.75 $ 17.25 $ 15.70 -in constant dollars 16.93 15.59 13.77 13.87 Average Consumer Price Index 298.5 289.3 272.4 246.8 1979 $283,106 283,106 $ 34,307 12,168 6,989 $ 2.36 .51 .08 35.5% 60.8 73.0 $ 45,257 $ 47,313 $310,231 293,444 12.12% 12.12 10.70% 10.70 $779,026 $324,848 $ 1.79 1.79 $ 17.235 17.235 217.4 Certain comparative per share data trended in average 1983 dollars (without adjustment of earnings for the pro forma effects of inflation on depreciation amounts) are as follows: Earnings Cb) $ 3.48 $ 2.85 $ 3.32 $ 3.17 $ 3.24 Dividends Declared 2.32 2.31 2.28 2.33 2.46 Market Price (Year End) 23.25 21.41 18.90 19.05 23.51 (a) These amounts will differ from those shown for constant dollar and current costs in Statement of Income From Continuing Operations Adjusted for Changing Prices because a different base year has been used in the data presented above (1979) and in the Changing Price information (1983) 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).

33 STATISTICAL REVIEW 1983-1973 Facilities for Service 1983 1982 1981 1980 Total Utility Plant (Thousands)

$1,225,690

$1,153,321

$1,064,928

$ 962,052 Gross Additions to Utility Plant (Thousands)

$ 83,673 $ 126,893 $ 123,318 $ 97,330 Pole Miles of Transmission and Distribution Lines 6,925 6,918 6,910 6,879 Generating Capacity (Kilowatts)

(a) (b) 1,594,200 1,531,200 1,524,600 1,434,700 Maximum Utility System Demand-Kw 1,346,700 1,264,200 1,263,800 1,261,700 Capacity Reserve at Time of Peak (% of Instal. Gen.) 15.5% 17.4% 17.1% 12.1% Energy Supply (Thousands of Kwh) Net Generation 5,913,196 5,676,118 5,302,023 5,533,178 Purchased and Interchanged-Net 579,488 466,667 946,241 643,106 Total System Load 6,492,684 6,142,785 6,248,264 6,176,284 Electric Sales (Thousands of Kwh) Residential 2,545,351 2,415,292 2,480,225 2,514,738 Commercial 2,019,468 1,894,535 1,849,863 1,769,208 Industrial 1,225,637 1,218,520 1,279,724 1,286,205 All Others 60,978 63,770 65,555 63,753 Total 5,851,434 5,592,117 5,675,367 5,633,904 Residential Electric Service (Average per Customer)

Amount of Electricity used during the year (Kwh) 7,715 7,444 7,751 8,003 Amount paid for a year's service $ 735.66 $ 644.77 $ 670.66 $ 536.99 Price per Kilowatt-hour 9.54¢ 8.66¢ 8.65¢ 6.71¢ Customer Data (Average)

Residential With Electric Heating 62,272 59,319 56,100 52,225 Residential Without Electric Heating 267,642 265,124 263,904 261,988 Total Residential 329,914 324,443 320,004 314,213 Commercial 43,152 42,885 43,219 43,267 Industrial 1,021 1,018 1,032 1,041 Other 549 627 634 654 Total Customers 374,636 368,973 364,889 359,175 Total Service Locations 398,526 391,989 386,046 379,242 Population Served 1,092,000 1,069,000 1,056,000 1,037,000 Financial Data (Thousands of Dollars) Energy Sales Residential

$ 242,705 $ 209,191 $ 214,614 $ 168,733 Commercial 175,520 154,792 156,624 115,973 Industrial 76,109 71,255 82,908 60,512 All Others 10,133 9,255 9,700 7,836 Total Energy Sales-Billed 504,467 444,493 463,846 353,054 Unbilled Revenues-Net 5,671 (6,795) Other Electric Revenue 7,004 6,480 5,837 5,337 Total $ 517,142 $ 444,178 $ 469,683 $ 358,391 Investor Information Earnings per Average Common Share $ 3.48 $ 2.76 (c) $ 3.03 $ 2.62 Average Number of Shares Outstanding (In Thousands) 16,923 15,116 13,034 12,372 Dividends Paid on Common Stock $ 2.30 $ 2.20 $ 2.04 $ 1.90 Dividend Payout Ratio 66% 80% 67% 73% Book Value Per Share (Year End) $ 23.58 $ 22.45 $ 22.40 $ 22.22 Price Earnings Ratio (Year End) 7 8 6 6 Times Fixed Charges Earned (before income taxes) 4.11 2.27 (c) 2.84 3.03 Shareholders and Employees (Year End) Common shareholders 48,299 48,790 48,424 47,762 Employees 1,995 2,022 2,035 1,968 (a) Excludes capacity allocated to a large industrial customer. (b) Includes unit purchase of capacity under contracts with Delmarva Power & Light Company and Pennsylvania Power and Light Company, commencing in 1980 and 1983 , respectively. (c) Earnings calculation includes the cumulative effect of an accounting change. Financial ratio is computed excluding the cumulative effect. 34 1979 1978 1977 1976 1975 1974 1973

$ 870,075 $ 802,473 $ 753,269 $ 710,343 $ 675,617 $ 637 , 250 $ 572,555 $ 72,773 $ 58,073 $ 48,733 $ 41 , 702 $ 46 , 745 $ 71,200 $ 67,864 6,831 6,786 6,735 6 , 696 6 , 645 6,580 6,506 1,384,700 1,414,700 1,414,700 1,334 , 700 1,334,700 1,278 , 700 1,013,500 1 , 192,600 1,177,400 1,176,000 1,030,300 1,069,400 1,004,400 1,051,400 13.9% 16.7% 16.9% 22.8% 19.9% 21.5% 5,397,338 5,625,988 5,293,019 4,918,906 4,715,357 4,651,334 4,236,083 464,143 130 , 037 224,169 324,196 190,852 229,197 665,558 5,861,481 5,756,025 5,517,188 5,243,102 4 , 906,209 4,880,531 4,901,641 2,411,732 2,377,202 2,221,250 2,070,766 1 , 938 , 724 1 , 882,560 1,899,122 1,580,384 1,586,097 1,478,559 1,392,029 1,346,216 1,298,858 1,351,974 1,255,304 1,250,636 1,220,260 1,143,170 1,036,755 1,136,935 1,119,478 60,799 60,705 58,866 57,667 56,465 57,477 58,129 5,308,219 5,274,640 4,978,935 4,663,632 4,378,160 4,375,830 4,428,703 7,849 7,951 7,653 7,320 7,018 6,982 7,303

$ 439.92 $ 406.18 $ 378.36 $ 349.64 $ 329.25 $ 291.21 $ 230.19 5.61¢ 5.11¢ 4.94¢ 4.78¢ 4.69¢ 4.17¢ 3.15¢ 48,339 44,387 40,318 37,581 35,235 32,215 28,627 258,941 254,592 249,927 245,296 241,019 237,397 231,408 307,280 298,979 290,245 282,877 276,254 269,612 260,035 43,219 42,672 42,033 41,170 40,608 40,351 39 , 810 1,048 1,034 1,047 1,071 1,100 1,080 948 667 673 676 681 684 679 678 352,214 343,358 334,001 325,799 318,646 311,722 301,471 371,362 362,131 352,205 343 , 147 336,105 330,758 320,834 1,015,000 990,000 961,000 937,000 915,000 894 , 000 865,000 $ 135,178 $ 121,440 $ 109,818 $ 98,904 $ 90 , 956 $ 78 , 512 $ 59,856 88,819 80,539 73,354 66,354 63,544 55,713 42,804 47,590 42,185 40,885 36 , 438 34,974 33,565 22,008 6,624 5,973 5,630 5,406 4,881 4,207 3,861 278,211 250,137 229 , 687 207,102 194,355 171,997 128,529 4,895 4,921 5,308 4,925 4,724 4,614 4,365

$ 283,106 $ 255,058 $ 234,995 $ 212,027 $ 199,079 $ 176,611 $ 132,894 $ 2.36 $ 2.21 $ 2.06 $ 2.60 $ 2.41 $ 2.54 $ 2.40 11,980 10, 791 10,630 9 , 747 9,490 8,973 8,453

$ 1.765 $ 1.67 $ 1.62 $ 1.56 $ 1.51 $ 1.50 $ 1.4688 75% 76% 79% 60% 63% 59% 61% $ 21.63 $ 21.27 $ 20.71 $ 20.25 $ 19.34 $ 18.45 $ 17.85 7 8 11 9 7 5 7 3.62 3.62 3.17 3.14 2.88 2.33 2.62 48,194 44,490 43,826 42,516 39,232 39,054 36 , 835 1,903 1 ,797 1,739 1,714 1,741 1,811 1,810 Thi s Annual Report ha s b ee n pr e pared for the purp ose o f pro v iding g e n e ral and s ta ti st ical information c o n c ernin g the C o mp a ny a nd n o t in connection with any s ale , offer for s al e or s olicitation of an off er t o buy a n y se curiti es. 3 5 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 1983 1982 Per Share High Low High Low 1983 1982 First Quarter 23 Y2 20 3/s 18 Ys 16% $.57 $.53 Second Quarter 23:Ys 20 3/i 18% 17 $.57 $.53 Third Quarter 23 20% 20 Y2 17 $.57 $.57 Fourth Quarter 25 1/s 22 5/s 21% 19 $.59 $.57 For your convenience, listed below are the proposed 1984 record dates and payable dates, for dividends on Common Stock: Record Dates Payable Dates March 15 , 1984 September 20, 1984 April 16 , 1984 October 15, 1984 June 21, 1984 December 20, 1984 July 16, 1984 January 15, 1985 Investor Records: Communications regardirg 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. 0. Box 1334 Pleasantville, New Jersey 08232 or telephone Area Code 609/645-4506 or 4507. 36 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 535,000 shares were purchased through the Plan in 1983 with proceeds to the Company in excess of $11. 7 million. There were 17,100 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 5Y'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 BOARD OF DIRECTORS (Left) Eleanor S. Danie l , Se lf employed.

Vice President a nd Director of several rea l estate corporations. (Right) Richard M. Dicke, Counselor at law. Partner of the law firm of Simpson Thacher and Bartlett.

(L eft) John D. feehan, Chai rman of the Board, President and C hi ef Executive Officer. (Right) J os. Mi c ha e l Galvin, Jr., President and C hi ef Executive Offi ce r of Sa l em Co un ty rial H ospital. (L eft) Gera ld A. H ale, President, H ale Resources, I nc., an industriaVnatural resou r ce investment and management pany. (Right) Matthew H olden, Jr., Professo r of Government and foreign Affairs, University of Virginia.

(L e ft) Ma ck C. Jones, Engineer.

Retired. (Ri ght) Ir v in g K. K ess l er, R et ir ed. Former Executive Vi ce P r es i de n t, R CA Co r poration.

(L eft) M adeline H. McWhinney, President, Dale, Elliott & Company, I nc., management consu l tants for the banking t r y. (R i ght) John M. Miner , Senior Vice President of Crocker National Bank. (L e f t) fr a nk H. Wh eato n , Jr., President of Wh eato n I ndustries.

M anufacture r of g la ss and p l astic containers. (Right) Ri cha r d M. Wil son, Retired. for m er Senior Vice President of the Company. OFFICERS John D. Feehan Chairman of the Board, President and Chief Executive Officer Ernest D. Huggard Executive Vice President Frank J. Ficadenti Senior Vice Pre s ident Engineering and Construction Jerrold L. Jacobs Senior Vice President Operations Michael A. Jarrett Senior Vice President Corporate Services David V. Boney Vice President Customer and Communit y Services John F. Born Vice President Electric Operation s Thomas E. Freeman Vice President Human Re so urce s Meredith I. Harlacher, Jr. Vice Pre s ident Engineerin g Brian A. Parent Vice Pre sident and Treasurer Joseph G. Salomone Vice President Control Henry C. Schwemm, Jr. Vice Pre s id ent Production Martin R. Meyer Secretary and Assistant Trea s urer Lance E. Cooper Controller Joseph T. Kelly, Jr. Assistant Vice President Operations and Assistant Secretary COMMITTEE LISTINGS Mr. Feehan, Chairman of the Board and President, serves as an ex officio member of all committees, except the Audit Committee.

Audit Committee John M. Miner , Chairman Eleanor S. Daniel Jos. Michael Galvin, Jr. Mack C. Jone s Irving K. Ke ss ler Corporate Development Committee Frank H. Wheaton , Jr., Chairman Eleanor S. Daniel Gerald A. Hale Matthew Holden, Jr. Mack C. Jone s John M. Miner Energy, Operations and Research Committee Mack C. Jone s, C h air man Richard M. Dick e Jos. Michael Galvin, Jr. Gerald A. Hale Matthew Holden , Jr. Irving K. Kessler Madeline H. McWhinney Richard M. Wil son Finance Committee John M. Miner, Chairman Eleanor S. Dani e l Richard M. Di cke Gerald A. Hal e Mack C. Jone s Irving K. Kessler Madeline H. McWhinne y Richard M. Wilson Pension and Insurance Committee Richard M. Dick e, Chairman Matthew Hold en, Jr. John M. Miner Frank H. Whea ton, Jr. Richard M. Wilson Personnel Committee Jos. Michael Galvin, Jr., Chairman Eleanor S. Daniel Richard M. Dicke Ir ving K. Ke ss l er Frank H. Wheaton, Jr. Shareholder, Community and Government Relations Committee Eleanor S. Daniel, Chairman Jos. Michael Galvin, Jr. Matthew Holden, Jr. Madeline H. McWhinney Frank H. Wheaton , Jr. Richard M. Wilson

@ATLANTIC ELECTRIC 1199 Black Horse Pike Pleasantville , N.J. 08232 B ul k Rate U.S. Postage PAID Atlantic City Electric Company