ML18107A188

Peco 1998 Annual Rept.

ML18107A188
Person / Time
Site:	Salem, Hope Creek
Issue date:	12/31/1998
From:	MCNEILL C A PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC
To:
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ML18107A186	List: ML18107A184 ML18107A187 ML18107A188
References
NUDOCS 9904210122
Download: ML18107A188 (206)

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Powering-I 9904210122

• 990414 PDR ADOCK 05000272 l .J PDR Comparison of 5 Year Cumulative Total Return $ 7 00 invested on 7 213 7193 in stock or index ini:luding reinvestment of dividends.

dollars 94 95 96 97 98 I PECO Energy Company S&PSOO . Dow Jones Utilities Average Financial Highlights (Thousands of Dollars) Operating Revenues Operating Expenses, excluding taxes Taxes Charged to Operations Operating Income Extraordinary Item (Net of taxes) Earnings Applicable to Common Stock (After extraordinary item) Earnings Applicable to Common Stock (Before extraordinary item) Earnings per Average Common Share (Dollars) (After extraordinary item) Cash Dividends Paid per Common Share (Dollars)

Average Shares of Common Stock Outstanding (Thousands)

Capital Expenditures Common Shareholders' Equity Book Value Per Average Common Share (Dollars) 1998 1997 % Change $ 5,210,482

$ 4,617,901 12.8% $ 3,647,653

$ 3,302, 179 10.5% $ 599,169 $ 602,860 (0.6%) $1,283,314

$ 1,005,631 27.6% $ (19,654) $ (1,833,664) 98.9% $ 499,615 $ (1,513,910)

$ 519,269 $ 319,754 62.4% $ 2.24 $ (6.80) $ 1.00 $ 1.80 (44.4%) 223,219 222,543 0.3% $ 415,331 $ 490,200 (15.3%) $ 3,057,342

$ 2,726,731 12.1% $ 13.61 $ 12.25 11.1 % PECO Energy Company is a leader in generating and marketing electricity in competitive markets across the United States. Since 1929, we have provided retail electric and natural gas service to customers in southeastern Pennsylvania, serving more than 1.5 million customers in 1998. With the advent of deregulation, we have developed a wide range of competitive businesses that build upon a broad asset base, our market knowledge and our core capabilities.

Our generation portfolio of more than 9,000 megawatts is among the most competitive in the United States. Our power marketing division, Power Team, is one of the. leading real-time deliverers of wholesale electricity operating throughout the continental United States. Through our Exelon division, we provide a variety of unregulated energy and utility infrastructure services, including electric supply to business and residential customers across Pennsylvania and competitive wireless and fiber optics-based communications services.

• • *

• ---' -I . \ \ ' I \ I \ ' \ While our performance in 1998 was impressive, we are still .

positive impact ;f ;:;Ur *.*.

vision .and w;ft are building our leadership position 1n markets by continuing to increase r ur powers of: Performance demonstrated by excellent financial and operating results in 1998 2 Vision becoming the world's leading provider of clean energy 5 Boldness aggressively growing a competitive generation portfolio 6 i Experience

' leacjin*g the industry in power marketing 8 ,. Innovation

• • \ .. ' growing and developing new ventures 10 .' .* , Alignment our people and performance to shareholder interests 12 \ ,..-=--, , r:---,\ ,'---\ 1* -: ** ----,, r , 1/ \ 1 1 1 I \ J ' / I ---I 1 / /' \ / , r 1 _ _ 1 ... ---.. ' 'I I I I I 1 I *' ___ .--" / ' / We will continue to tap these business powers to create value for our shareholders and customers that no other energy company can equal. }\

L -I I To My Fellow Shareholders:

What a difference a year makes! When I wrote my letter to you a year ago, our company was in one of its greatest periods of uncertainty.

We were facing what could have been a protracted legal challenge to an unfavorable regulatory order; Wall Street's confidence in our competitive future was weakened, and our cial results for 1997 were most pointing.

Today, that picture has matically changed for the better, and I am proud to report to you that 1998 was a year of powerful mance for PECO Energy. Among our most significant accomplishments in 1998:

• Earnings per share were $2.66 before special items, an increase of 46% over 1997 performance.

• PECO Energy's common stock ered a total annual return of 78%.

• We negotiated a fair and balanced electric deregulation plan.

• Our power marketing group, Power Team, increased sales ume 13%.

• Our unregulated energy supply business, Exelon Energy, became the most successful player in the new Pennsylvania Electric Choice program.

• AmerGen, our joint venture with British Energy, successfully ated the first-ever U.S. purchase of a nuclear generating station, scheduled for completion this year. I I I '---, ' ' J / / , 1 " \ 1, 1'1 ,: I \/ /

• PECO Energy was nqmed "Energy Company of the Year" by the Washington International Energy Group. Strong Financial Results Earnings per share in 1998, before special items, were $2.66. That sents a 46% increase over 1997 ings from operations.

After ing for an extraordinary charge ed to the redemption of higher cost debt and a year-end adjustment for the cost of our on-going workforce reduction program, earnings were $2.24 per share. Our power ing activities contributed significantly to our strong earnings performance, particularly in the third quarter when we achieved the highest quarterly earnings in our company's history. During 1998, we also benefited from lower operating and maintenance expenses, significantly lower fuel and replacement power costs following the Salem Nuclear Generating Station's full return to service in early 1998, and a lower effective income tax rate. PECO Energy Delivered Excellent Returns in 1998 PECO Energy's shares of common stock closed 1998 at $41.75, a 74% increase over the 1997 close of $24 per share. The unprecedented increase in our common stock price, combined with dividends paid, ed in a total return to our ers of 78%, winning PECO Energy the 1 number one spot in the rankings for total shareholder return among the 25 largest U.S. electric utilities.

The catalysts to our dramatically improved valuation were the able completion of our long and ficult regulatory restructuring ceeding and the p_rogress we have made in executing our competitive growth strategy.

Favorable Restructuring Plan in Place The most significant event of 1998 was the successful completion of our restructuring proceeding before the Pennsylvania Public Utility Commission (PUC). In May, the PUC approved a fair and balanced plan that on January 1, 1999 opened our electric generation business to petition.

The plan provides our tomers with guaranteed savings through across-the-board rate cuts for the next two years as well as the freedom to choose their energy plier. PECO Energy will continue to provide regulated distribution vices to all customers in our al service territory.

For PECO Energy, the restructuring plan provides a very reasonable sition to retail competition while maintaining a solid financial found. tion upon which we're building ne competitive businesses.

A central ele-ment of the plan is the allowed recovery of almost $5.3 billion in stranded investments.

On January 1, 1999, we began recovering these investments from our customers through a special transition charge that will remain in place for 12 years, while earning a 10.75% return on the balance. The plan also gives us the ability to securitize the majority of our recoverable stranded costs through he issuance of up to $4 billion of "transition bonds." The issuance of these highly rated bonds will enable us to significantly realign our capital ture, most notably through the ment of debt and preferred stock, and the repurchase of common stock. Our Vision for the Future Our business and industry are clearly moving into a vastly different and exciting era. Given the speed of this change, we think it is essential to have a clear picture of where we're going, and the kind of company we want to be when we get there. In 1998, we developed a powerful new corporate vision -To become the world's leading provider of clean energy. (Our complete vision and sion statements are presented on page 5 of this report.) This mission will guide and propel our progress for years to come, and we are uing to build the processes and struc-ures to make it a reality. Pursuing Aggressive Growth Objectives To mark our progress in achieving our long-term vision for the Company, in 1998 we lished the ing goals that we will work to meet by the year 2003:

• To retain a 3 Corbin A. McNeill, Jr., 75% market share in our traditional vice territory, achieved PECO Energy Chairman, President and Chief Executive Officer through customer retention by our local distribution company, PECO Energy Distribution, as well as market share growth by Exelon Energy.

• To nearly triple our electric ation capabilities to 25 gigawatts through acquisitions and term supply agreements by the year 2003.

• To achieve a 50% increase in our earnings per share between 1998 and 2003. To achieve these aggressive earnings and growth objectives, we will build upon our strengths in power tion and power marketing.

We will also continue to develop ventures that leverage our core business capa-bilities, and continuously work to optimize the cost efficiency of PECO Energy Distribution Company. Building a Competitive Retail Market Share Our long-term goal is to maintain a very strong market share in our tional electric service area, plus lish a significant position in other electric retail markets across Pennsylvania, and ultimately other regions of the United States. As of January 2, 1999, two-thirds of Pennsylvania's electric customers gained the ability to choose their energy suppliers.

In anticipation of the opening of retail markets, Exelon Energy conducted a marketing cam-paign in 1998 that has helped it gain more than 130,000 retail customers.

To date, Exelon Energy has lished the largest competitive market share in the state and is one of the few suppliers with customers in all of Pennsylvania's electric franchise areas. Even with the new opportunities for choice that our customers have, I am pleased to note that a large ber of our customers have opted not to switch their energy supplier and have remained with PECO Energy Distribution.

I believe this loyalty is a testament to our strong ties to the communities we serve as well as our proud history of service excellence.

Increasing PECO's Generation Capabilities We took the first important step in expanding our generation portfolio in July of 1998, when we entered into an agreement to purchase Unit 1 of Three Mile Island Nuclear Generating Station (TMI) from GPU, Inc. We will purchase the unit through AmerGen, our joint venture with British Energy, and expect to complete the transaction by mid-11999. TMI Unit 1 has one of the finest operational and safety records in the industry.

We see real nities for even stronger performance by applying the same spirit of tion and operational excellence that has earned our Peach Bottom and Limerick nuclear stations world-class status in performance, safety and cost efficiency.

Based on our latest estimates, we believe the TMI Unit 1 acquisition will make a positive tribution to earnings in its first year. The growth of our generating capacity will go hand-in-hand with the growth of Power Team's sale energy marketing operations.

Power Team has developed the expertise, market knowledge and a portfolio management strategy that consistently produce superior value for PECO Energy. In 1998, Power Team delivered 100% of the power it tracted to provide. This deliverability record was particularly impressive given the supply problems enced by other marketers during last summer's shortages in the Midwest. Managing our Businesses to Achieve Excellence Now more than ever, we need a ented and motivated workforce to help us accomplish the goals we have set. We are fulfilling that need by building an employee team which is smart, ambitious and motivated to succeed. Over the past year, we have added significantly to our talent base and have recruited leaders from a variety of competitive industries, such as oil, gas and chemicals.

I believe in challenging our force, providing the right incentives to achieve our goals and then rewarding excellent results. In 1998 we put in place a new incentive pensation system that includes stock option grants for every employee, which vest only after our stock price meets aggressive price targets. We also began offering quarterly cash bonuses to employees when their respective business units meet driven business and operational objectives.

Under this new system, employees and management will only enjoy financial rewards when we create value for our shareholders.

New Corporate Structure Proposed

• In 1999, we will be asking common shareholders to vote on a proposal to create a holding company structure for PECO Energy that, if approved, will establish a new corporate holding company named PECO Energy Corporation.

This will be the first step in establishing separate subsidiaries organized around our three key lines of business:

power generation and marketing, gas & electric distribution and unregulated energy ed businesses.

We believe that this proposed structure will give us the flexibility to compete in new markets and grow our businesses as new opportunities arise. Before closing, I want to recognize and thank fellow board member Admiral Kinnaird R. McKee, who stepped down from our Board of Directors in 1998 after completing 10 years of service. I would also like to welcome Rosemarie Greco, who joined our board in 1998. And finally, I want to thank you, our ers, for your continued support and confidence.

All of us who are a part of PECO Energy are excited about building on our competitive strengths in the coming year and beyond. Corbin A. McNeill, Jr. PECO Energy Chairman, President and

• Chief Executive Officer February 5, 1999 L_ .--.-. -, -, , r-, ', ,' ; ' ' / 1' ---j' II ,' ' ' I I I' I I IJ : \ I/ r I I I.\"'"'

I,----' "--": \_ / ' =*-j Becoming the world's leading provider of clean energy. In 1998, we developed a powerful vision statement

-to become the world's leading provider of clean energy. This vision is guiding and pelling our strategy, our actions and ultimately our success. 5 i ' I I I ', ' I I I

• We are an energy company that measures our success by our impact on the lives of others. *We will provide energy safely, reliably and affordably to power the 21st century dreams of families and businesses.

• We will create value for our shareholders and our tomers that no other energy company can equal.

• We will ensure that air and water are cleaner for generations to come.

• We will be a company ed as much for what we value as for the value we create.

.----------'r ' 'I --, I I I_,, ' ' ' ' I :__ _ _] Our key for success in lated power generation markets will be to own or control a significant amount of environmentally clean and efficient erating capacity in targeted regions of the United States. As part of our ' ' i I ( '----' I I : \ "------'!

l -I _______ .,,...' vision to become the world's leading provider of clean energy, we set a goal of increasing our generation capacity from just over 9,000 megawatts to 25,000 megawatts in the next five years. We are working to achieve this goal through an aggressive yet disciplined acquisition program, and through securing long-term supply contracts with generation

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' asset owners. ' ' \ \ ' / ' \ I I I \ 1 / I \ , \ I, J Under our acquisition program, we are targeting attractively priced, environmentally and ationally sound plants that have the potential for outstanding formance an.d strong returns. As . -* ...

I ( \ ' i i ** we make tions, we will work to develop region-al groups of graphically synergistic plants that allow us to leverage our resources and expertise in specific graphic areas. In 1998, we began expanding our Mid-Atlantic operating group, consisting of the four nuclear units we operate at Limerick and Peach Bottom tions. In October, we reached a -

We are pursuing a bold national strategy designed to nearly triple our generating capacity within five, years and strengthen our market presence throughout the United States. final agreement to purchase Unit 1 at GPU's Three Mile Island Nuclear Generating Station through AmerGen, our joint ture with British Energy. TMI Unit 1, with its strong operating record and 786 megawatts of JClear baseload capacity, will be excellent addition to our erating portfolio.

This plant has twice set world records for tinuous days of operation.

AmerGen is obtaining all sary governmental approvals and expects to complete this tion by mid-1999.

Leveraging Our Operational Excellence Good acquisitions are not enough. It is what we do with the plants after they are acquired that determines their true value. The second pillar of our tion strategy is our proven ating expertise.

Our Limerick and Peach Bottom nuclear stations are among the safest and best-erforming nuclear plants in the ustry. These facilities have ome of the highest capacity fac-Building Our Portfolio of High Performers a: :::) 0 :z: '"" '"" cc ;: 0 ... :.:: a: IU a. '"" II) 0 u CAPACITY IFACTOIR PECO is building its portfolio by targeting generating plants with potential for high capacity factors and low operating costs, and will use its operating strengths to improve performance of acquired plants. tors and lowest production costs in the nation. We are targeting additional plants with similar high performance potential.

In 1999, we plan to continue to expand our generation portfolio through a strategy that focuses first and foremost on building earnings potential and strong investment returns. We will seek out the best possible plants at competitive prices, working to create a balanced portfolio of generation assets, including nuclear, hydroelectric and burning fossil fuel plants. This strategy positions us to be a leader in power generation in North America and achieve our bold aspiration of becoming the world's leading provider of clean energy. 7 I I ! ' I I *--J I ( r_ --I, I I ' I l I \ 0 A pioneer in the industry, PECO's Power Team continues to demonstrate its leadership in marketing and delivering wholesale power throughout the United States. The expertise of our power keting group, Power Team, was again proven in 19Q8 with a record of 100% delivery in highly competitive and rapidly changing U.S. power markets. Power Team continues to use its expertise to expand its assets and markets in the United States and Canada and increase its contributions to our bottom line. At the same time, our strategy of growing our generation portfolio will provide Power Team with additional sources of low-cost power. The Value of Experience Power Team's knowledge, supply portfolio and marketing strategy have driven its rapid growth. Since pioneering the development of the wholesale power market in 1994, Power Team has nearly tripled its sales to become one of the largest "real time" deliverers of wholesale electricity in the nental United States. Today, Power Team's customer base includes municipal utilities, investor-owned utilities, rural cooperatives and marketers.

Power Team's most significant competitive advantage is a diverse portfolio of generation assets, including both erated power and a variety of long-term and short-term power purchase contracts with other suppliers.

As an early player, Power Team also established tions in generation and transmission assets across the United States that have become more valuable as competition has increased.

These assets give Power Team the flexibility to move power quickly to areas where demand is strongest.

Expanding Power Sources and Markets In 1998, Power Team continued to diversify its power sources and markets. Power Team expanded its supply portfolio by adding generating sources outside of PECO Energy's traditional service territory.

PECO-generated power accounted for only about a quarter of our total supply folio and Power Team continues to add new capacity.

For ple, through a partnership with Tenaska, Inc., Power Team will market the output of a new 800-megawatt plant, which will be the largest merchant power plant the United States when it pens in 2000. Drawing upon our broad ply portfolio, Power Team also expanded the size and scope of sales across the United States. For the first time, Power Team sold more power outside PECO's tional Mid-Atlantic service ry than inside (see chart). To respond to the more plex needs of customers in ulated markets, Power Team has created innovative solutions for customers.

For example, we developed products that enable us to serve entire municipalities in Pennsylvania and Maine. In addition, Power Team has oped arrangements that allow us to support our hydro-based tomers in periods of low power generation.

With a marketing operation that runs 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day, 7 days per week, our national transmission access and our unique and innovative delivery knowledge, we can provide power just about er and whenever it is needed. As the market becomes more crowded and competitive, our demonstrated experience will become more able. We are well tioned to take tage of emerging opportunities in retail markets as they open to tion across the country and as we add low-cost, strategically located supply to our portfolio.

Power Team's Geographic Reach and Wholesale Customers

,:,1 ]I 20% 94 95 96 97 98 I West , Southeast Midwest Northeast Mid-Atlantic 20 -o-Wholesale Customers For the first time, Power Team sold more power outside the Mid-Atlantic region than inside as we continued to grow our wholesale market. 9

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' . Under the umbrella brand of Exelon, we are developing diverse businesses that leverage our assets and skills in high-potential markets. In 1998, we increased our power of innovation by developing and expanding several new es, brought together under the umbrella brand of Exelon. These ventures, which leverage our core competencies into new areas, have high potential for future growth. Among our early achievements we have: lished ourselves as the most cessful electric generation er in Pennsylvania's Electric Choice program; signed up over 100,000 wireless phone customers; installed a telecommunications network consisting of over 27,000 fiber miles; and began to prove the viability of a new ture services business.

Leveraging Our Strengths This year, we leveraged our core strengths in operations and utility infrastructure to launch or expand several new ventures:

• Energy: Exelon Energy provides petitively priced electricity and natural gas-to residential, mercial and industrial clients in deregulated retail energy kets. Exelon has been ful in meeting the initial chal-lenge of competition, ing the largest electric tion supplier in Pennsylvania's Electric Choice program -building market share not only in our traditional service area but also in every distribution area of the state. The strong systems we developed in 1998 for customer acquisition, tomer care, energy supply and billing ensure we are well tioned for the expanded choice program in 1999. With the unique experience we've gained in Pennsylvania, we are poised to move quickly into any U.S. market where tory conditions provide open retail competition.

• Communications:

Exelon Communications is working with experienced partners to develop wireless phone networks and local fiber optics communications services in the Philadelphia region. In its first full year, Exelon's joint venture with AT&T Wireless has become a significant petitor in the region's wireless telecommunications business.

Our transmission infrastructure and skilled staff have allowed us to build wireless cell sites rapidly and efficiently, by lizing existing assets. We oped innovative approaches to piggyback antennas and cell sites on top of electrical mission poles and towers. In the first year, the joint ventu11. built a base of over 100,000 . subscribers, well above our target, and established a nificant network in the delphia area. We are well prepared to pursue the esti-mated two million new cus-tomers expected to sign up for wireless service in the region in the next five years. In partner-ship with Hyperion Communications, a leading provider of competitive munications services, we also installed 27,000 fiber miles in the PECO service territory as well as Allentown, Bethlehem, Easton and Reading. This ven-ture redeploys our strengths in building and maintaining our current power delivery net-* work to establish a new munications platform.

,. 0 *

• Infrastructure:

One of the most cre-ative ways we are lever-aging our strengths in aging complex infrastructures is a new service business we launched in 1998 to provide infrastructure construction and maintenance to other utilities.

In new residential construction I for example, electric, gas, phone and cable companies traditionally use separate vice technicians to install their lines. We are developing a ture to provide single-source service. By combining tion of electric, gas, telephone

• and cable, Exelon Infrastructure Services reduced total costs by a third in installing service to more than 8,000 homes in 1998. In addition to new struction, we began build-ing a utility infrastructure maintenance business, ing contracts to maintain street lighting in Philadelphia, vide design services in southern New Jersey and assess utility maintenance operations at a midwestern utility. As utilities face pressures to cut costs, they will find it increasingly tive to outsource many struction and maintenance functions.

We are well tioned to continue to grow 11 this market. Overall, Exelon offers a laboratory for rapidly developing new business ideas, allowing us to take advantage of fast-moving opportunities.

Exelon is oping a wide range of other seed projects and pilot grams with high future growth potential.

The flow of tive projects in the pipeline and strong early results are signs of the potential tions of the of tion to our future progress and shareholder value.

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, (-1 \(,: -\ \ I ' I I ,--__ , LJ l __ J We have refocused our performance measures and compensation systems to align our organization around aggressive goals designed to enhance shareholder value. Building Upon a Solid Foundation Our local distribution company, PECO Energy Distribution (PED), provides a strong foundation of earnings, cash flow and core expertise to support our other non-regulated growth initiatives.

In 1998, we reorganized PED to ensure we are positioned for competition and to increase alignment with shareholder ests. The changes in PED were the centerpiece of a company-wide shift in performance measures, management systems and tives to increase alignment and ownership.

With our rates for delivering energy capped by regulators through mid-2005, our greatest opportunity for optimizing the earnings contribution of PED comes from reducing our ing costs while sustaining high formance and service. We began driving down our cost of delivery in 1998, with a goal of reducing costs by nearly 20% by 2000. To achieve this goal, we restructured PED to focus on financial performance, market share, cost containment and increasing service levels to mize customer satisfaction and retention.

By the end of 2000, we expect to reduce our 1998 PED staff by more than 20%. These actions are part of an overall corporate initiative to increase performance and ment. We conducted a Cost Competitiveness Review that identified potential annual cost savings of $150 million across the entire corporation, which we are actively working to ize. Our goal in making these reductions is not only to decrease operating costs, but to do so while continuing to improve tomer-related performance through improved processes.

Promoting a Performance Ethic In 1998, we began to implement one of the most rigorous mance-based compensation and management systems in the industry.

It provides opportunities for stock ownership at all levels of the organization through stoa. option grants that vest only whe performance goals are met. It is designed to pror:note a perfor-mance ethic throughout the organization and align employ-ees' interests directly with the interests of shareholders.

We embedded our vision and objectives in a coordinated system of goals, organization, mance feedback and consequence management.

In 1998, we began implementing a new system of incentives based upon corporate and business unit performance that will be applied across all els of the organization.

We ed more compensation from base pay to performance-based pay. A new incentive plan in our nuclear division, for example, has tied

• compensation to safety and operating goals for every ee. It has been very successful in boosting performance and ing the rewards with employees.

As part of our plan to push formance incentives throughout the organization, we announced rants of options to purchase 0 shares of PECO Energy common stock to all ees by year-end 1999. But these options -like formance-based stock options granted to senior executives

-are not gifts or rewards for ty. They must be earned, vesting only when aggressive mance goals are reached. The employees win only if shareholders win. We are one of the few companies to create such a mance-based plan. These new approaches to managing the business .aave fundamentally 9shaped our culture. We have transformed a company that performed well in regional, regulated markets into an zation prepared to succeed in world-class competition.

13 14 1 I _ , ; i , I _

• JI I I : : r . *, . *performance Earnings*

and Dividends

3.0 dollars

per share 94 95 96 97* 98* I Earnings Dividends per Common Share *Before extraordinary item and special charges Total Debt and Interest Charges millions of dollars :] I*. 3000 !-!, I I

• 2000 I I 100011111 01 I I I I 94 95 96 97 98

• Total Debt -o-Interest Charges Total Electric Sales billions of kilowatthours 80 70 60 50 I ' 40 -30 .. -I . . I I 20 _.111 1: I I I I I 94 95 96 97 98 , Retail Sales

• Sales to Other Utilities and Interchange Capitalization

':11111 60%11111 40%11111 20%11111 0%11111 94 95 96 97 98 I Long Term Debt Preferred Stock & COMRPS Common Equity Gas Sales and Transported Gas billions of cubic feet 120 1:: I I .. 6011111 4011111 2011111 011111 94 95 96 97 98 Cash Flow from Operations and Capital Expenditures millions of dollars 1400 = Q D G 0 = D 1000 1 I i i th 6001 ti 4001111111.1_

2001111111111 01111111111

• 94 95 96 97 98

• ill Cash Flow from Operatio .

• Capital Expenditures Management's Discussion and Analysis of Financial Condition and Results of Operations 15 Management's Discussion and Analysis of Financial Condition and Results of Operations General The Electricity Generation Customer Choice and Competition Act {Competition Act), enacted in December 1996, provided for the restructuring of the electric utility industry in Pennsylvania, including the institution of retail competition for generation supply beginning in 1999. Pursuant to the Competition Act, in April 1997, the Company filed with the Pennsylvania Public Utility Commission

{PUC) a restructuring plan in which it identified

$7 .5 billion of retail electric tion-related stranded costs. At December 31, 1997, the Company determined that its electric generation business no longer met the criteria of Statement of Financial Accounting Standards

{SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In connection with the discontinuance of SFAS No. 71, the Company performed a market value analysis of its generation assets and wrote-off

$1.8 billion {net of income taxes) of unrecoverable electric plant costs and regulatory assets. See Note 4 of Notes to Consolidated Financial Statements.

In May 1998, the PUC entered an Opinion and Order {Final Restructuring Order) approving a joint petition and tlement of the Company's restructuring case. Under the Final Restructuring Order, the Company has received approval to cover stranded costs of $5.26 billion over 12 years begin-g January 1, 1999 with a return of 10.75%. The Final structuring Order provides for the phase-in of customer choice of electric generation suppliers

{EGS) for all tomers: One-third of the peak load of each customer class on January 1, 1999; one-third on January 2, 1999; and the remainder on January 2, 2000. The Final Restructuring Order calls for an across the board retail electric rate reduction of 8% in 1999. This rate reduction will decrease to 6% in 2000. See Note 3 of Notes to Consolidated Financial Statements.

Based on the estimated annual sales of the Company in the Final Restructuring Order, the rate reductions are ed to reduce the Company's revenues from retail electric sales by $270 million in 1999 and $200 million in 2000. The Company believes that its revenues from retail electric sales will be further reduced by competition for electric generation services within its traditional service territory.

The Company is actively participating in the competitive electric generation supply market throughout Pennsylvania.

In addition, the Company anticipates lower depreciation and amortization expense in 1999 as a result of the amortization schedule for the Company's stranded cost recovery.

In light of the expected impact on future revenues of the Final Restructuring Order and competition for electric tion services, the Company is continuing its cost management efforts through a Cost Competitiveness Review {CCR). The goal of CCR is to achieve significant cost savings while main-*ing high levels of service quality, reliability, safety and rail performance.

The cost-control targets of CCR include ucing annual operating and maintenance expense by at least $150 million by 2001. The expense reductions will be realized, in part, through the elimination of approximately 1,200 employee positions.

As part of the CCR, in April 1998, the Board of Directors authorized the implementation of a retirement incentive program and an enhanced severance benefit program to accompany targeted workforce tions. In the fourth quarter of 1998, the Company incurred an after-tax charge to earnings of $74 million to recognize costs related to the CCR workforce reduction.

Discussion of Operating Results Earnings The Company recorded basic earnings per average common share of $2.24 in 1998 as compared with a loss of $6.80 per share in 1997 and earnings per share of $2.24 in 1996. Earnings per share in 1998 reflect higher revenues net of fuel of $0.14 per share primarily attributable to sales to other ties and interchange sales; lower operating and maintenance expenses of $0.10 per share and lower fuel expenses of $0.22 per share as a result of the full return to service of Salem Nuclear Generating Station {Salem); and lower ing and maintenance expenses of $0.21 per share. In addition, earnings include the effects of a lower effective income tax rate of $0.34 per share. These increases were partially offset by higher depreciation and amortization expense of $0.17 per share; a charge of $0.33 per share related to the CCR workforce reduction program initiated in 1998; and an extraordinary charge of $0.09 per share for miums paid in connection with the redemption of higher cost long-term debt. The loss in 1997 of $6.80 per common share was marily due to an extraordinary charge of $8.24 per share reflecting the effects of the PUC Restructuring Order and deregulation of the Company's electric generation operations.

1997 earnings were also reduced by several one-time charges totaling $0.56 per share for changes in employee benefits, write-offs of information systems development charges reflecting clarification of accounting guidelines and additional reserves, including those for environmental site remediation; by $0.30 per share for higher depreciation expense resulting from a full year's increase in depreciation and amortization of assets associated with Limerick Generating Station {Limerick) and other assets; by $0.12 per share for income tax adjustments; by $0.09 per share for losses from new non-utility ventures; and by $0.05 per share for increased depreciation expense due to plant additions.

These decreases were partially offset by a one-time $0.18 per share credit relating to the settlement of litigation arising from the outage of Salem; $0.08 per share for operational efficiencies; and higher revenues net of fuel of $0.06 per share primarily due to increased sales to other utilities.

16 PECO Energy Company and Subsidiary Companies Significant Operating Items Revenue and Expense Items as a Percentage of Total Operating Revenues Percentage Dollar Changes 1998 1997 1996 1998-1997 1997-1996 92% 90% 90% Electric 15% 8% 8% 10% 10% Gas (11 %) 5% 100% 100% 100% Total Operating Revenues 13% 8% 34% 28% 23% Fuel and Energy Interchange 36% 33% 24% 31% 30% Operating and Maintenance 1'1 (12%) 12% 12% 12% 11 % Depreciation and Amortization 11 % 19% 5% 7% 7% Taxes Other Than Income (10%) 4% 75% 78% 71% Total Operating Expenses 9% 19% 25% 22% 29% Operating Income 28% (19%) (7%) (9%) (10%) Interest Expense (10%) (2%) (9%) (8%) (9%) Total Other Income and Deductions (15%) 4% 16% 14% 20% Income Before Taxes and Extraordinary Item 35% (27%) 6% 6% 8% Income Taxes 9% (14%) 10% 8% 12% Income Before Extraordinary Item 58% (35%) *1 Includes Early Retirement and Separation Programs Expense in 1998. Operating Revenues Total operating revenues increased in 1998 by $593 million to $5,210 million. This represented a $644 million increase in electric revenues and a $51 million decrease in gas revenues compared to 1997. Electric revenues increased as a result of additional sales to other utilities and interchange sales, in addition to higher wholesale prices. The decrease in gas enues was primarily attributable to lower sales to house heating, small commercial and residential customers as a result of milder weather conditions in 1998, partially offset by higher purchased gas clause revenues charged in 1998 pared to 1997. Total operating revenues increased in 1997 by $334 lion to $4,618 million. This represented a $312 million increase in electric revenues and a $22 million increase in gas revenues over 1996. The increase in electric revenues was primarily due to increased sales to other utilities.

The increase in gas enues was primarily due to higher revenues from sales to commercial, house heating and residential customers ing from higher purchased gas clause revenues charged in 1997 compared to 1996, partially offset by lower sales ing from milder weather conditions in 1997. This increase was partially offset by reduced sales to interruptible customers switching to transportation service. lncreases/(decreases) in electric sales and revenues by class of customer for 1998 compared to 1997 and 1997 pared to 1996 are set forth as follows: 1998 -1997 1997 -1996 Electric Electric Electric Electric Sales Revenues Sales Revenues (Miflions of kWh) (Millions of$) (Millions of kWh! (Millions of$) Residential 356 $ 30 (48) $ (1) House Heating (140) (10) (217) (12) Small Commercial and Industrial 203 5 194 30 Large Commercial and Industrial 644 (11) (174) (21) Other (38) 2 (61) 8 Unbilled 61 (18) 397 45 Service Territory 1,086 (2) 91 49 Interchange Sales 1,556 152 992 33 Sales to Other Utilities 8,365 494 8,650 230 Total 11,007 $ 644 9,733 $ 312 Fuel and Energy Interchange Expense Fuel and energy interchange expense increased in 1998 by $462 million to $1,752 million. The increase was primarily due to increased energy purchases associated with increased sales to other utilities and interchange sales partially offset by reduced replacement power expense related to Salem. Increases in purchases of non-utility generation also tributed to increased fuel expense in 1998. Fuel and energy interchange expense as a percentage of operating revenues .. increased from 28% to 34% principally as a result of energ purchases associated with increased sales to other utilities and interchange sales. Fuel and energy interchange expense increased in 1997 by $318 million to $1,290 million. The increase was primarily due to purchases associated with increased sales to other Management's Discussion and Analysis of Financial Condition and Results of Operations 17 utilities and a one-time billing credit in 1996 from a non-utility

• nerator. Fuel and energy interchange expense as a e of operating revenues increased from 23% to 28% principally due to purchases associated with increased sales to other utilities.

Operating and Maintenance Expense Operating and maintenance expense, inclusive of expenses associated with early retirement and separation programs, decreased in 1998 by $178 million to $1,253 million. The decrease in 1998 was primarily attributable to the full return to service of Salem which resulted in lower restart expenses, a credit to pension and benefits expense related to the formance of pension plan investments and lower property insurance and workers compensation insurance.

These decreases were partially offset by the charge associated with the CCR workforce reduction program and increased power marketing expenses.

Operating and maintenance expense increased in 1997 by $157 million to $1,431 million primarily due to several time charges totaling $187 million, including charges for changes in employee benefits, write-offs of information tems development charges reflecting clarification of accounting guidelines and additional reserves, including reserves for environmental site remediation.

These increases were partially offset by lower operating costs at operated nuclear generating stations and lower administrative and general expenses resulting from the Company's ongoing ost-control efforts. epreciation and Amortization Expense Depreciation and amortization expense increased in 1998 by $62 million to $643 million. The increase was primarily due to the amortization of Deferred Generation Costs Recoverable in Current Rates during 1998, preceding the Company's tion to market-based pricing of electric generation in 1999. Included in this amortization were charges that were included in operating and maintenance expense and interest expense in 1997. Depreciation and amortization expense increased in 1997 by $92 million to $581 million. The increase was primarily due to increased depreciation of assets associated with Limerick which became effective October 1, 1996. Depreciation and amortization expense also increased due to additions to plant in service. Interest Charges Interest charges consist of interest expense, distributions on Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COM RPS) and Allowance for Funds Used During Construction (AFUDC). Interest charges decreased in 1998 by $22 million to $358 million. The decrease was primarily due to the Company's program to reduce and/or refinance higher cost, long-term debt, lower

• riable interest rates and the discontinuance of amortization the loss on reacquired debt related to electric generation perations as of December 31, 1997. These decreases were partially offset by lower AFUDC and capitalized interest resulting from fewer projects in the construction base in 1998 and the replacement of $62 million of preferred stock with COMRPS in the third quarter of 1997. Interest charges decreased in 1997 by $9 million to $380 million. The decrease was primarily due to the Company's program to reduce and/or refinance higher-cost, long-term debt. This decrease was partially offset by the replacement of $62 million of preferred stock with COM RPS in the third quarter of 1997. Other Income and Deductions Interest Charges Other income and deductions excluding interest charges decreased in 1998 by $77 million to a deduction of $73 lion. The decrease was primarily due to the settlement of litigation arising from the shutdown of Salem recognized in

• 1997 and losses from the Company's non-utility ventures, which are accounted for under the equity method, partially offset by interest income on a gross receipts tax refund. Other income and deductions excluding interest charges increased in 1997 by $6 million to $4 million. The increase was primarily due to the settlement of litigation arising from the down of Salem, partially offset by losses from the Company's non-utility ventures.

Also offsetting the increase was the off of one of the Company's telecommunications investments as a result of the auctioning of personal communications systems "C-block" licenses by the Federal Communication Commission.

Income Taxes Income taxes increased in 1998 by $27 million to $320 lion. The Company's effective income tax rate decreased, however, from 46.5% to 37 .5% in 1998 primarily as a result of full normalization of deferred taxes associated with lated generation plant. Income taxes decreased in 1997 by $47 million to $293 million. The Company's effective income tax rate increased, however, from 39.7% to 46.5% in 1997primarily attributable to reduced tax depreciation benefits from plant and ry assets which were not fully normalized for ratemaking purposes.

Preferred Stock Dividends Preferred stock dividends decreased in 1998 by $4 million to $13 million and decreased in 1997 by $1 million to $17 million. The decreases were primarily a result of the replacement of $62 million of preferred stock with COMRPS in the third quarter of 1997. Discussion of Liquidity and Capital Resources The Company's capital resources are primarily provided by internally generated cash flows from utility operations and, to the extent necessary, external financing.

Such capital resources are used to fund the Company's capital ments, including investments in new and existing ventures, to repay maturing debt and to make preferred and common stock dividend payments . Cash flows from operations were $1,433 million in 1998 as compared to $1,038 million in 1997 and $1, 172 million in J 996. The increase in 1998 was principally attributable to improved operating results and changes in working capital.

18 Cash flows used in investing activities were $462 million in 1998 as compared to $573 million in 1997 and $663 million in 1996. Expenditures under the Company's construction program decreased to $415 million in 1998. Net funds invested in sified activities in 1998 were $47 million, consisting of $17 million for telecommunications ventures, $21 million for nuclear plant decommissioning trust funds and $9 million for other deposits and ventures.

In 1997 and 1996, funds used in similar activities were $83 million and $114 million, respectively.

Cash flows used in financing activities were $956 million in 1998 as compared to $461 million in 1997 and $501 million in 1996. The increase in 1998 was primarily attributable to increased retirement of long-term debt partially offset by lower dividends on common stock. During 1998, in tion of competition, which is expected to reduce cash flows, the Compa*ny reduced its dividend payment requirements by reducing its common stock dividend to $1 per share. The decrease in 1997 was primarily due to fewer retirements of higher-cost debt. The Company's capital expenditures are currently mated to be $440 million in 1999. Certain facilities under construction and to be constructed may require permits and licenses which the Company has no assurance will be ed. Capital expenditures do not include investments in joint ventures including investments related to the Company's strategy to expand its generation portfolio.

Expansion of Generation Portfolio." The Company may use internally generated funds or external financing or a tion of both to finance any acquisition.

The Company meets its short-term liquidity requirements primarily through the issuance of commercial paper and rowings under bank credit facilities.

The Company has a $900 million unsecured revolving credit facility with a group of banks which consists of a $450 million 364-day credit ment and a $450 million three-year credit agreement.

The Company uses the credit facility principally to support its $600 million commercial paper program. There was no debt outstanding under this credit facility at December 31, 1998. The Company had $525 million of short-term debt, consisting of $125 million of commercial paper, and a $400 million term loan, outstanding at December 31, 1998. At December 31, 1998, the Company's embedded cost of debt was 6.65% with 29% of the Company's long-term debt having floating rates. At December 31, 1998, the Company's capital structure consisted of 44.2% common equity; 8.4% preferred stock and COM RPS (which comprised 5.1 % of the Company's total capitalization structure);

and 47.4% long-term debt. In the Final Restructuring Order, the PUC authorized the Company to securitize up to $4 billion of its allowed $5.26 lion stranded cost recovery through the issuance of transition bonds (Transition Bonds). The proceeds of any securitization are required to be used by the Company principally to reduce *its stranded costs and related capitalization.

The Company currently proposes to securitize its allowed stranded asset recovery, up to the maximum amount authorized by the PUC, through the' issuance of Transition Bonds by a special pose subsidiary (SPS). The Transition Bonds will be obligations of the SPS secured by intangible transition ty (ITP). ITP represents the irrevocable right of the Company or its assignee, to collect non-bypassable charges from tomers to recover stranded costs. The Transition Bonds will PECO Energy Company and Subsidiary Companies be included in the consolidated capitalization of the Company. Because the Transition Bonds will be obligations of the SPS, payable from the ITP owned by the SPS, the Company does not expect the issuance of Transition Bonds to adversely affect the ratings on the Company's securities which remain outstanding after issuance of Transition Bonds. In anticipation of the issuance of Transition Bonds, the Company's Board of Directors authorized the repurchase of up to 25 million shares of the Company's common stock from time to time through open market, privately negotiated and/or other types of transactions.

The Company has entered into forward purchase agreements to be settled from time to time, at the Company's election on either a physical, net share or net cash basis. The amount at which these ments can be settled is dependent principally upon the market price of the Company's common stock as compared to the forward purchase price per share and the number of shares to be settled. If these agreements had been settled on a net share basis at December 31, 1998, based on the closing price of the Company's common stock on that date, the Company would have received approximately

4.6 million

shares of the Company's common stock. The Company has entered into treasury forwards and forward starting interest rate swaps to manage interest rate exposure associated with the anticipated issuance of Transition Bonds. The fair value of ($4.7 million) was based on the present value difference between the contracted rate (i.e., hedged rate) and the market rates at December 31, 1998. The aggregate change in fair value of the Transition Bo derivative instruments that would have resulted from a hyp thetical 50 basis point decrease in the spot yield at December 31, 1998 is estimated to be $128 million. If the derivative instruments had been terminated at December 31, 1998, this estimated fair value represents the amount to be paid by the Company to the counterparties.

The aggregate change in fair value of the Transition Bond derivative instruments that would have resulted from a thetical 50 basis point increase in the spot yield at December 31, 1998 is estimated to be $113 million. If the derivative instruments had been terminated at December 31, 1998, this estimated fair value represents the amount to be paid by the counterparties to the Company. Outlook The Company is entering a period of financial uncertainty as a result of the deregulation of its electric generation operations.

Under the terms of the Final Restructuring Order, revenues from regulated rates will decrease.

In addition, the Company will sell an increasing portion of its energy at market-based rates. The Company believes that the deregulation of its tric generation operations and other regulatory initiatives designed to encourage competition will increase the Company's risk profile by changing and increasing the ber of factors upon which the Company's financial results ar dependent.

This may result in more volatility in the Company's future results of operations.

The Company believes that it has significant advantages that will strengthen its position in the increasingly competitive electric generation Management's Discussion and Analysis of Financial Condition and Results of Operations 19 *environment.

These advantages include the ability to produce ectricity at a low variable-cost and the demonstrated ability market power in the competitive wholesale markets. The Company's future financial condition and results of operations are substantially dependent upon the effects of the Final Restructuring Order and retail and wholesale petition for generation services.

Additional factors that affect the Company's financial condition and results of operations include operation of nuclear generating facilities, Year 2000 issues, new accounting pronouncements, inflation, weather, compliance with environmental regulations and the ty of the Company's investments in new ventures.

Final Restructuring Order The Final Restructuring Order contains a number of sions which the Company expects will significantly impact its future results of operations and financial condition, including mandated rate reductions, extended rate caps, provisions designed to enhance competition for generation services, the amortization of the Company's stranded cost recovery and the securitization of stranded cost recovery.

The Final Restructuring Order mandates retail electric rate reductions of 8% in 1999 and 6% in 2000 from rates in existence on December 31, 1996. Based on the estimated annual sales of the Company in the Final Restructuring Order, these rate reductions will reduce the Company's revenue from retail electric sales by $270 million and $200 million in 1999 and 2000, respectively.

The Company's revenue from tail electric sales will be further reduced to the extent that stomers purchase generation service from alternate EGS. The Final Restructuring Order caps the Company's retail transmission and distribution rates at their current levels through June 30, 2005. The Final Restructuring Order also established rate caps for generation services, consisting of the charge for stranded cost recovery and a charge for energy and capacity, through 2010. The rate caps will limit the Company's ability to pass cost increases through to customers.

The Final Restructuring Order contains a number of visions which are designed to encourage competition for generation services.

The Final Restructuring Order es an above-market shopping credit for generation services, equivalent to the Company's energy and capacity charge, in order to provide an economic incentive for customers to choose an alternate EGS. If market prices of retail generation services remain below the shopping credits for generation established by the Final Restructuring Order, this economic incentive to choose an alternate EGS will continue.

If, on the other hand, market prices of retail generation services exceed the shopping credits for generation, customers will have an economic incentive to purchase generation services from the Company as the provider of last resort {PLR) at below market rates. Additionally, if on January 1, 2001 and January 1, 2003, less than 35% and 50%, respectively, of the Company's residential and commercial customers are ing generation service from alternate EGS, the non-shopping stomers will be randomly assigned to EGS, including those iliated with the Company, to meet these thresholds.

urther, on January 1, 2001, 20% of all the Company's dential customers, whether or not such customers are obtaining generation service from an alternate EGS, will be assigned to a PLR other than the Company. Such alternate supplier will be selected by a PUC-approved bidding process. The right to provide this competitive default service will be rebid annually, and if the number of residential customers served by this service falls below 17%, further random tion of customers will be assigned to achieve the 20% level. The Company's recovery of stranded costs is based on the level of transition charges established in the Final Restructuring Order and the projected annual retail sales in the Company's service territory.

Recovery of transition charges for stranded costs will be included in operating enue and are expected to be $552 million in 1999, increasing to $932 million by 2010, the final year of stranded cost ery. Amortization of the Company's stranded cost recovery, which is a regulatory asset, will be included in depreciation and amortization, beginning in 1999 at a level of ($14) million and increasing by 2010 to $879 million. The Company is allowed a 10.75% return on the unamortized balance. As a result of this amortization schedule, the Company expects its earnings to be disproportionately benefited by the recovery of stranded assets in the early years of the transition period declining over the life of the recovery as the balance of the unamortized regulatory asset is reduced. Under the Final Restructuring Order, the. Company may securitize up to $4 billion of its $5.26 billion of stranded cost recovery through the issuance of Transition Bonds. The rate reductions and rate caps of the Final Restructuring Order anticipate the benefits of securitization and no adjustment in the Company's base rates will be made upon the issuance of Transition Bonds. As a result of the 10.75% allowed return on the unamortized balance of stranded cost recovery and expected costs of securitization substantially below this allowed return, the Company anticipates that successful securitization, resulting in a reduction of its common equity, will improve the Company's future financial results. Competition The Company competes in both the retail electric generation market in Pennsylvania and the wholesale electric generation market nationally.

Competition for electric generation services is expected to create new uncertainties in the utility industry.

These uncertainties include future prices of generation vices in both the wholesale and retail markets; potential changes in the Company's customer profiles, both at the retail level where change is expected to be ongoing as a result of customer choice, and between the retail and sale markets; and supply and demand volatility.

Retail competition for generation supply commenced in January 1999, with two-thirds of Pennsylvania electric utility consumers having the right to choose their suppliers of eration service. The Company is actively competing for a share of the generation supply market in its traditional service territory through PECO Energy Distribution as the PLR for customers who do not or cahnot choose an alternate EGS and throughout Pennsylvania through Exelon Energy, the Company's new competitive supplier.

Generation services provided by PECO Energy Distribution are at the energy and capacity charge mandated by the Final Restructuring Order. Generation services offered by Exelon Energy are at tive market prices. Customers who continue to take generation service from PECO Energy Distribution may choose an alternate generation supplier at any time. As of 20 January 12, 1999, approximately 12 % of the Company's dential and small commercial customers and approximately 50% of its large commercial and industrial customers had selected an alternate EGS. As of that date, Exelon Energy is providing generation service to approximately 135,000 ness and residential customers throughout Pennsylvania.

Because the energy and capacity charge (shopping credit) established by the PUC in the Restructuring Order remains above current retail market prices for generation services, including those offered by Exelon Energy, the Company's retail revenues will be reduced to the extent customers choose an alternate EGS, including Exelon Energy. To the extent that the Company cannot replace lost retail sales through PECO Energy Distribution with retail sales by Exelon Energy, the Company will be required to sell a larger portion of its energy and capacity in the wholesale market. Since prices in the wholesale market are currently lower on average than those charged in the competitive retail market, this will adversely affect the Company's revenues and profit margins. The Company is a low variable-cost electricity producer, which puts it in a favorable position to take advantage of opportunities in the electric retail and wholesale generation markets. The Company's competitive position and its future financial condition and results of operations are dependent on the Company's ability to successfully operate its low cost power plants and market its power effectively in competitive wholesale markets. The Company competes in the wholesale market by ing the energy and capacity from the Company's installed capacity not utilized in the retail market and buying and ing energy from third parties. The Company enters into both long-term and short-term commitments to buy and sell power. Currently, the Company's long-term commitments, together with the energy the Company expects to market from the Company's installed capacity, make the Company a net power seller. This long position, however, exposes the Company to the risk of declining revenues in periods of low wholesale demand for generation services.

See Note 5 of Notes to Consolidated Financial Statements.

There is an initiative in the Pennsylvania legislature to deregulate the gas industry, which has the support of the governor.

The Company cannot predict whether the Pennsylvania legislature will enact legislation that deregulates the gas industry or whether the governor will ultimately sign into law any such legislation.

The Company cannot predict the ultimate effect of gas industry deregulation on its future financial condition or results of operatiohs.

Regulation and Operation of Nuclear Generating Facilities The Company's financial condition and results of operations are in part dependent on the continued successful operation of its nuclear generating facilities.

The Company's nuclear generating facilities represent 44% of its installed generating capacity.

Because of the Company's reliance on its nuclear generating units, any changes in regulations by the Nuclear Regulatory Commission (NRC) requiring additional ments or resulting in increased operating costs of nuclear generating units could adversely affect the Company. PECO Energy Company and Subsidiary Companies During 1998, Company-operated nuclear plants operated.

at an 86% weighted-average capacity factor and Company-owned nuclear plants operated at an 83% weighted-average capacity factor. Company-owned nuclear plants produced 39% of the Company's electricity.

Nuclear generation is cur-rently the most cost-effective way for the Company to meet customer needs and commitments for sales to other utilities.

See "Expansion of Generation Portfolio".

New Accounting Pronouncements In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," to establish accounting and reporting standards for derivatives.

The new standard requires recognizing all derivatives as either assets or ties on the balance sheet at their fair value and specifies the accounting for changes in fair value depending upon the intended use of the derivative.

The new standard is effective for fiscal years beginning after June 15, 1999. The Company expects to adopt SFAS No. 133 in the first quarter of 2000. The Company is in the process of evaluating the impact of SFAS No. 133 on its financial statements.

In November 1998, the FASB's Emerging Issues Task Force issued EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." EITF 98-1 O outlines attributes that may be indicative of an energy trading operation and gives further guidance on the ing for contracts entered into by an energy trading operation.

This accounting guidance requires mark-to-market accountin for contracts considered to be a trading activity.

EITF 98-10 i applicable for fiscal years beginning after December 15, 1998 with any impact recorded as a cumulative effect adjustment through retained earnings at the date of adoption.

At December 31, 1998, the Company has evaluated its wholesale marketing operation and related contracts under the guidance provided in EITF 98-10. For those contracts entered into in the over-the-counter market and considered to be a trading activity, the Company believes the impact to be immaterial.

However, with respect to the long-term commitments considered to be trading activities, the Company is continuing to evaluate these commitments and the impact of adopting EITF 98-10. Other Factors Annual and quarterly operating results can be significantly affected by weather. Since the Company's peak demand is in the summer months, temperature variations in summer months are generally more significant than variations during winter months. Inflation affects the Company through increased ing costs and increased capital costs for utility plant. As a result of the rate caps imposed under the Final Restructuring Order and expected price pressures due to competition, the Company may have a limited opportunity to pass the costs of inflation through to customers.

The Company's operations have in the past and may in the future require substantial capital expenditures in order t comply with environmental laws. Additionally, under federal and state environmental laws, the Company is generally liable for the costs of remediating environmental contamination of property now or formerly owned by the Company and of property contaminated by hazardous substances generated Management's Discussion and Analysis of Financial Condition and Results of Operations 21 *he Company. The Company owns or leases a number of estate parcels, including parcels on which its operations he operations of others may have resulted in tion by substances which are considered hazardous under environmental laws. The Company is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to tional proceedings in the future. The Company has identified 28 sites where former ufactured gas plant (MGP) activities have or may have resulted in actual site contamination.

The Company is presently engaged in performing various levels of activities at these sites, including initial evaluation to determine the tence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation.

The Pennsylvania Department of Environmental Protection has approved the Company's clean-up of three sites. Eight other sites are currently under some degree of active study and/or remediation.

As of December 31, 1998 and 1997, the Company had accrued $60 and $63 million, respectively, for environmental investigation and remediation costs, including

$33 and $35 million, respectively, for MGP investigation and remediation that currently can be reasonably estimated.

The Company expects to expend $3 million for environmental remediation activities in 1999. The Company cannot predict whether it will incur other significant liabilities for any additional investigation remediation costs at these or additional sites identified

• he Company, environmental agencies or others, or ether such costs will be recoverable from third parties. For a discussion of other contingencies, see Note 5 of Notes to Consolidated Financial Statements.

Year 2000 Readiness Disclosure Due to the severity of the potential impact of the Year 2000 Issue (Y2K Issue) on the electric utility industry, the Company has adopted a comprehensive schedule to achieve Y2K ness by the time specified by the NRC. The Company has dedicated extensive resources to its Y2K Project (Project) and believes the project is progressing on schedule.

The Project is addressing the issue resulting from puter programs using two digits rather than four to define the applicable year and other programming techniques that strain date calculations or assign special meanings to certain dates. Any of the Company's computer systems that have date-sensitive software or microprocessors may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a system failure or miscalculations ing disruptions of operations, including, a temporary inability to process transactions, send bills, operate generating tions, or engage in similar normal business activities.

The Company has determined that it will be required to modify, convert or replace significant portions of its software 4 a subset of its system hardware and embedded so that its computer systems will properly utilize dates and December 31, 1999. The Company presently believes t with these modifications, conversions and replacements the effect of the Y2K Issue on the Company can be mitigat-ed. If such modifications, conversions and replacements are not made, or are not completed in a timely manner, the Y2K Issue could have a material impact on the operations and financial condition of the Company. The costs associated with this potential impact are not presently quantifiable.

The Company is utilizing both internal and external resources to reprogram, or replace and test software and computer systems for the Project. The Project is scheduled for completion by July 1, 1999, except for a small number of modifications, conversions or replacements that are impacted by vendor dates and/or are being incorporated into scheduled plant outages between July and October 1999. The Project is divided into four major sections -Information Technology Systems (IT Systems}.

Embedded Technology (devices used to control, monitor or assist the operation of equipment, machinery or plant), Supply Chain (third-party suppliers and customers), and Contingency Planning.

The general phases common to all sections are: (1) inventorying Y2K items; (2) assigning priorities to identified items; (3) assessing the Y2K readiness of items determined to be material to the Company; (4) converting material items that are determined not to be Y2K ready; (5) testing material items; and (6) designing and implementing contingency plans for each critical Company process. Material items are those believed by the Company to have a risk involving the safety of individuals, may cause damage to property or the ment, or affect revenues.

The IT Systems section includes both the conversion of applications software that is not Y2K ready and the ment of software when available from the supplier.

The Company estimates that the software conversion phase was approximately 66% complete at January 27, 1999, and the remaining conversions are expected to be completed by the scheduled end date. The Company has been experiencing slippage in delivery dates of vendor supplied products which may have a minor impact on the July 1, 1999 target tion date. Contingency planning for IT Systems is scheduled to be completed by July 1, 1999 with an interim date of March 31, 1999 that addresses PUC contingency planning requirements.

The Project has identified 380 critical systems of which 238 are IT Systems. The current readiness status of IT Systems is set forth below: Number of Systems 79 Systems 65 Systems 87 Systems 7 Systems Progress Status Y2K Ready In Testing In Active Code Modification, Or Package Upgrading Not Started The Embedded Technology section consists of hardware and systems software other than IT Systems. The Company estimates that the Embedded Technology section was approximately 75% complete at January 27, 1999. The remaining conversions are on schedule to be tested and ready by July 1, 1999, except for a small number of systems which will be extended into the fall of 1999 because their final tests will occur during a planned generating plant age. Contingency planning for Embedded Technology is scheduled to be completed by July 1, 1999 with an interim date of March 31, 1999 that addresses PUC contingency planning requirements.

The Project has identified 142 critical Embedded Technology systems. The current readiness status of those systems is set forth below:

22 Number of Systems 31 Systems 29 Systems 76 Systems 6 Systems Progress Status Y2K Ready In Final Quality Review In Progress Not Started The Supply Chain section includes the process of fying and prioritizing critical suppliers and communicating with them about their plans and progress in addressing the Y2K Issue. The Company initiated formal communications with all of its critical suppliers to determine the extent to which the Company may be vulnerable to their Y2K issues. The process of evaluating these critical suppliers has menced and is scheduled to be completed by March 31, 1999. The Company, like other companies, is interconnected with many businesses, including electric utilities, natural gas pipelines and municipalities.

The Company is working with businesses where interconnections exist to determine and monitor their Y2K readiness efforts. In addition, the Company is currently developing contingency plans to address how to respond to events which may disrupt normal operations.

These plans address Y2K risk scenarios that cross mental, business unit and industry lines as well as specific risks from various internal and external sources, including supplier readiness.

Emergency plans already exist that cover various aspects of the Company's business.

These plans are being reviewed and updated, as needed, to address the Y2K Issue. The Company is also participating in industry gency planning efforts. The estimated total cost of the Project is $75 million, the majority of which will be incurred during testing. This mate includes the Company's share of Y2K costs for jointly owned facilities.

The total amount expended on the Project through December 31, 1998 was $21 million. The Company expects to fund the Project from operating cash flows. The Company's failure to become Y2K ready could result in an interruption in or a failure of certain normal business activities or operations.

In addition, there can be no ance that the systems of other companies on which the Company's systems rely or with which they communicate will be converted in a timely manner, or that a failure to vert by another company, or a conversion that is incompatible with the Company's systems, will not have a material adverse effect on the Company. Such failures could ly and adversely affect the Company's results of operations, liquidity and financial condition.

The Company is currently developing contingency plans to address how to respond to events that may disrupt normal operations, including activities with PJM Interconnection, LLC. The costs of the Project and the date on which the Company plans to complete the Y2K modifications are based on estimates, that were derived utilizing numerous tions of future events, including the continued availability of certain resources, third-party modification plans and other tors, such as regulatory requirements that impact key systems. There can be no assurance that these estimates will be achieved.

Actual results could differ materially from the projections.

Specific factors that might cause a material change include, but are not limited to, the availability and cost PECO Energy Company and Subsidiary Companies of trained personnel, the ability to locate and correct all rel. vant computer programs and microprocessors.

The Project is expected to significantly reduce the Company's level of uncertainty about the Y2K Issue. The Company believes that the completion of the Project, as scheduled, minimizes the possibility of significant tions of normal operations.

Expansion of Generation Portfolio The Company established specific goals to increase its ation capacity from 9 gigawatts to 25 gigawatts by 2003. The Company is targeting a balanced portfolio of nuclear, hydro and clean burning fossil capacity through the acquisition of plants and long-term supply agreements.

In order to meet this strategic objective the Company may require significant capital resources.

In October 1998, the Company through AmerGen Energy Company, LLC, a 50% owned joint venture with British Energy, Inc., entered into a definitive asset purchase ment with GPU, Inc. (GPU) to acquire GPU's 786 megawatt Three Mile Island Unit No. 1 Nuclear Generating Facility for approximately

$23 million in cash, $77 million for nuclear fuel payable over five years and certain contingent payments based upon future wholesale market prices. The Company currently expects the acquisition, which is subject to various regulatory approvals, to close by mid-year 1999. Corporate Restructuring In 1999, the Company's common shareholders will vote o management proposal for the formation of a holding comp ny. The holding company will be formed through the exchange of PECO Energy common stock for common stock of the holding company. As a result, the Company will become a wholly owned subsidiary of the holding company. The formation of the holding company will not affect the Company's other securities.

Management has proposed the formation of the holding company to facilitate the tion of the Company's transmission and distribution, generation and unregulated businesses and corporate central services in order to create increased financial, management and organizational flexibility.

Forward-Looking Statements Except for the historical information contained herein, certain of the matters discussed in this Report are forward-looking statements which are subject to risks and uncertainties.

The factors that could cause actual results to differ materially include those discussed herein as well as those listed in Note 5 of Notes to Consolidated Financial Statements and other factors discussed in the Company's filings with the Securities and Exchange Commission.

Readers are cautioned not to place undue reliance on these forward-looking ments, which speak only as of the date of this Report. The Company undertakes no obligation to publicly release any revision to these forward-looking statements to reflect ev. or circumstances after the date of this Report.

• Report of Independent Accountants To the Shareholders and Board of Directors of PECO Energy Company: 23 In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, cash flows and changes in common shareholders' equity and preferred stock present fairly, in all material respects, the financial position of PECO Energy Company and Subsidiary Companies at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.

These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted ing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant mates made by management and evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for the opinion expressed above. Philadelphia, Pennsylvania February 5, 1999 24 PECO Energy Company and Subsidiary Companies Consolidated Statements of Income

• For the Years Ended December 31, 1998 1997 1996 Thousands of Dollars Operating Revenues Electric $ 4,810,840

$ 4, 166,669 $ 3,854,836 Gas 399,642 451,232 428,814 Total Operating Revenues 5,210,482 4,617,901 4,283,650 Operating Expenses Fuel and Energy Interchange 1,751,819 1,290, 164 972,380 Operating and Maintenance 1,128,792 1,431,420 1,274,222 Early Retirement and Separation Programs 124,200 Depreciation and Amortization 642,842 580,595 489,001 Taxes Other Than Income 279,515 310,091 299,546 Total Operating Expenses 3,927,168 3,612,270 3,035, 149 Operating Income 1,283,314 1,005,631 1,248,501 Other Income and Deductions Interest Expense (330,842)

(372,857)

(382,443)

Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company (30,694) (28,990) (26,723) Allowance for Funds Used During Construction 3,522 21,771 19,94] Settlement of Salem Litigation 69,800 Other, net (73,268) (66,028) (1,976) Total Other Income and Deductions (431,282)

(376,304)

(391, 195) Income Before Income Taxes and Extraordinary Item 852,032 629,327 857,306 Income Taxes 319,654 292,769 340, 101 Income Before Extraordinary Item 532,378 336,558 517,205 Extraordinary Item (net of income taxes of $13,757 and $1,290,961 for 1998 and 1997, respectively}

(19,654) (1,833,664)

Net Income (Loss) 512,724 (1,497, 106) 517,205 Preferred Stock Dividends 13,109 16,804 18,036 Earnings (Loss) Applicable to Common Stock $ 499,615 $ (1,513,910)

$ 499, 169 Average Shares of Common Stock Outstanding (Thousands) 223,219 222,543 222,490 Basic Earnings per Average Common Share Before Extraordinary Item (Dollars)

$ 2.33 $ 1.44 $ 2.24 Extraordinary Item (Dollars)

$ (0.09) $ (8.24) $ Basic Earnings per Average Common Share (Dollars)

$ 2.24 $ (6.80) $ 2.24 Diluted Earnings per Average Common Share Before Extraordinary Item (Dollars)

$ 2.32 $ 1.44 $ 2.24 Extraordinary Item (Dollars)

$ (0.09) $ (8.24) $ Diluted Earnings per Average Common Share (Dollars)

$ 2.23 $ (6.80) $ 2.24 Dividends per Common Share (Dollars)

$ 1.00 $ 1.80 See Notes to Consolidated Financial Statements.

PECO Energy Company and Subsidiary Companies 25 -onsolidated Statements of Cash Flows For the Years Ended December 31, 1998 1997 1996 Thousands of Dollars Cash Flows from Operating Activities Net Income (Loss) $ 512,724 $ (1,497, 106) $ 517,205 Extraordinary Item (net of income taxes) (19,654) (1,833,664)

Income Before Extraordinary Item 532,378 336,558 517,205 Adjustments to reconcile Net Income to Net Cash provided by Operating Activities:

Depreciation and Amortization 704,718 664,294 566,412 Deferred IT)come Taxes (115,640)

(17,228) 166,770 Amortization of Investment Tax Credits (18,066) (18,201) (15,979) Early Retirement and Separation Charge 125,000 Salem Litigation Settlement 69,800 Deferred Energy Costs 5,818 (5,652) (66,151) Amortization of Leased Property 59,923 39, 100 31,400 Changes in Working Capital: Accounts Receivable 15,590 (289,610) 53,681 Inventories 14,192 28,628 (2,729) Accounts Payable 8,971 93,881 (86,765) Other Current Assets and Liabilities 54,263 58,539 (25,040) Other Deferred Credits -Other 49,948 78,846 (4,609) ther Items affecting Operations (4,190) (804) 38,050 et Cash Flows from Operating Activities 1,432,905 1,038, 151 1, 172,245 Cash Flows from Investing Activities Investment in Plant (415,331)

(490,200)

(548,854)

Increase in Other Investments (46,742) (83,261) (114, 126) Net Cash Flows from Investing Activities (462,073)

(573,461)

(662,980)

Cash Flows from Financing Activities Change in Short-Term Debt 123,500 114,000 287,500 Proceeds from Exercise of Stock Options 50,700 117 11,301 Retirement of Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (80,794) (61,895) Issuance of Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership 78,105 50,000 Issuance of Long-Term Debt 13,486 161,813 43,700 Retirement of Long-Term Debt (841,755)

(283,303)

(427,463)

Loss on Reacquired Debt 6,753 22,752 24,724 Dividends on Preferred and Common Stock (236,307)

(417,383)

(411,569)

Capital Lease Payments (59,923) (39, 100) (31,400) Other Items Affecting Financing (9,918) (7,522) 2,575 Net Cash Flows from Financing Activities (956, 153) (460,521)

(500,632)

Increase in Cash and Cash Equivalents 14,679 4,169 8,633 .ash and Cash Equivalents at beginning of period 33,404 29,235 20,602 ash and Cash Equivalents at end of period $ 48,083 $ 33,404 $ 29,235 See Notes to Consolidated Financial Statements.

26 Consolidated Balance Sheets At December 31, Assets Utility Plant Electric-Transmission

& Distribution Electric-Generation Gas Common Less Accumulated Provision for Depreciation Nuclear Fuel, net Construction Work in Progress Leased Property, net Net Utility Plant Current Assets Cash and Temporary Cash Investments Accounts Receivable, net Customers Other Inventories, at average cost Fossil Fuel Materials and Supplies Deferred Energy Costs-Gas Deferred Generation Costs Recoverable in Current Rates Other Total Current Assets Deferred Debits and Other Assets Competitive Transition Charge Recoverable Deferred Income Taxes Deferred Non-Pension Postretirement Benefits Costs Investments Loss on Reacquired Debt Other Total Deferred Debits and Other Assets Total Assets See Notes to Consolidated Financial Statements.

PECO Energy Company and Subsidiary Companies 1998 1997 Thousands of Dollars $ 3,833,780

$ 1,713,430 1,131,999 407,320 7,086,529 2,891,321 4,195,208 141,907 272,590 154,308 4,764,013 48,083 97,527 213,229 79,488 82,068 29,847 19,013 569,255 5,274,624 614,445 90,915 550,904 77, 165 107,042 6,715,095 3,617,666 1.434,895 1,071,819 302,672 6.427,052 2,690,824 3,736,228 147,359 611,204 175,933 4,670,724 33.404 173,350 139,996 84,858 90,890 35,665 424.497 20, 115 1,002,775 5,274,624 590,267 97.409 515,835 83,918 121,016 6,683,069

• $ 12,048,363

$ 12,356,568

• PECO Energy Company and Subsidiary Companies onsolidated Balance Sheets (Continued)

At December 31, Capitalization and Liabilities Capitalization Common Shareholders' Equity Common Stock Other Paid-In Capital Retained Earnings (Accumulated Deficit) Preferred and Preference Stock Without Mandatory Redemption With Mandatory Redemption Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company Long-Term Debt Total Capitalization rrent Liabilities tes Payable ng-Term Debt Due Within One Year Capital Lease Obligations Due Within One Year Accounts Payable Taxes Accrued Interest Accrued Deferred Income Taxes Other Total Current Liabilities Deferred Credits and Other Liabilities Capital Lease Obligations Deferred Income Taxes Unamortized Investment Tax Credits Pension Obligation Non-Pension Postretirement Benefits Obligation Other Total Deferred Credits and Other Liabilities Commitments and Contingencies (Note 5) .al Capitalization and Liabilities See Notes to Consolidated Financial Statements.

$ 1998 3,589,031 1,236 (532,925) 3,057,342 137,472 92,700 349,355 2,919,592 6,556,461 525,000 361,523 69,011 316,292 170,495 61,515 14,168 217,416 1,735,420 85,297 2,376,792 299,999 219,274 421,083 354,037 3,756,482 1997 Thousands of Dollars $ 3,517,731 1,239 (792,239) 2,726,731 137,472 92,700 352,085 3,853, 141 7, 162, 129 401,500 247,087 55,808 323,816 66,397 77,911 185,696 260,457 1,618,672 120, 125 2,297,042 318,065 211,596 324,850 304,089 3,575,767

$ 12,048,363

$ 12,356,568 27 28 PECO Energy Company and Subsidiary Companies Consolidated Statements of Changes in Common Shareholders' Equity and Preferred Sto Retained Other Earnings Common Stock Paid-In (Accumulated Preferred Stock All Amounts in Thousands Shares Amount Capital Deficit) Shares Amount Balance at January 1, 1996 222, 172 $ 3,506,313

$ 1,326 $ 1,023,708 2,921 $ 292,067 Net Income 517,205 Cash Dividends Declared Preferred Stock (at specified annual rates} (21,042) Common Stock ($1.755 per share} (390,527)

Expenses of Capital Stock Activity (275) Capital Stock Activity Long.:rerm Incentive Plan Issuances 370 11,301 (2,028) Balance at December 31, 1996 222,542 3,517,614 1,326 1, 127,041 2,921 292,067 Net Loss (1,497, 106) Cash Dividends Declared Preferred Stock (at specified annual rates} (16,804) Common Stock ($1.80 per share} (400,578)

Expenses of Capital Activity 97 Stock Repurchase Forward Contract (4,889) Capital Stock Activity Long-Term Incentive Plan Issuances 5 117 Preferred Stock Redemptions (87) (619) (61,895) Balance at December 31, 1997 222,547 $ 3,517,731

$ 1,239 $ (792,239) 2,302 $ 230, 172 Net Income 512,724 Cash Dividends Declared Preferred Stock (at specified annual rates} (13, 109) Common Stock ($1.00 per share} (223,198)

Expenses of Capital Stock Activity 2,731 Stock Repurchase Forward Contract (7,677) Capital Stock Activity Long-Term Incentive Plan Issuances 2,137 71,300 (3) (12, 157) Balance at December 31, 1998 224,684 $ 3,589,031

$ 1,236 $ (532,925) 2,302 $ 230,172 See Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements Notes to Consolidated Financial Statements

1. Significant Accounting Policies General The consolidated financial statements of PECO Energy Company (the Company) include the accounts of its utility subsidiary companies, all of which are wholly owned. Accounting policies for all of the Company's operations are in accordance with generally accepted accounting principles (GAAP). Accounting policies for regulated operations are also in accordance with those prescribed by the regulatory ities having jurisdiction, principally the Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory Commission (FERC). The Company has unconsolidated utility subsidiaries which are not material.

The unconsolidated subsidiaries are accounted for under the equity method. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and tions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of enues and expenses during the reporting period. Actual results could differ from those estimates.

Estimates are used by the Company in accounting for nbilled revenue, the allowance for uncollectible accounts, urchased gas adjustment clause, depreciation and ion, taxes, reserves for contingencies, employee benefits, certain fair value and recoverability determinations, and nuclear outage costs, among others. Accounting for the Effects of Regulation The Company accounts for all of its electric transmission and distribution and gas operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," requiring the Company to record the financial statement effects of the rate regulation to which such operations are currently subject. If a separable portion of the Company's business no longer meets the provisions of SFAS No. 71, the Company is required to eliminate the financial statement effects of regulation for that portion. Effective December 31, 1997, the Company determined that the electric generation portion of its business no longer met the criteria of SFAS No. 71 and, accordingly, implemented SFAS No. 101, "Regulated Enterprises

-Accounting for the Discontinuation of FASB Statement No. 71," for that portion of its business.

Revenues Electric and gas revenues are recorded as service is rendered or energy is delivered to customers.

At the end of each month, the Company accrues an estimate for the unbilled amount of *nergy delivered or services provided to customers.

urchased Gas and Energy Cost Adjustment Clauses The Company's gas rates are subject to a fuel adjustment clause designed to recover or refund the difference between the actual cost of purchased gas and the amount included in 29 base rates. Differences between the amounts billed to tomers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of tive quarterly adjustments to rates. Prior to December 31, 1996, the Company's retail tric rates were subject to an Energy Cost Adjustment (ECA) clause designed to recover or refund the difference between the actual cost of fuel, energy interchange or purchased power and the amount of such costs included in base rates. Effective December 31, 1996, the PUC approved the roll-in of electric energy costs into the base rates charged to the Company's retail electric customers and such rates are no longer subject to the ECA. Nuclear Fuel The cost of nuclear fuel is capitalized and charged to fuel expense on the unit of production method. Estimated costs of nuclear fuel disposal are charged to fuel expense as the related fuel is consumed.

The Company's nuclear fuel at Peach Bottom Atomic Power Station (Peach Bottom) and Salem Generating Station (Salem) is accounted for as a tal lease. Nuclear fuel at Limerick Generating Station (Limerick) is owned. Nuclear Outage Costs Incremental nuclear maintenance and refueling outage costs are accrued over the unit operating cycle. For each unit, an accrual for incremental nuclear maintenance and refueling outage expense is estimated based upon the latest planned outage schedule and estimated costs for the outage. Differences between the accrued and actual expense for the outage are recorded when such differences are known. Depreciation, Amortization and Decommissioning Depreciation is provided over the estimated service lives of plant on the straight-line method. Annual depreciation sions for financial reporting purposes, expressed as a percentage of average depreciable utility plant in service, were approximately 2.8% in 1998, 3.3% in 1997 and 2.9% in 1996. See note 3 for information concerning the change in 1996 to depreciation and amortization.

The Company's current estimate of the costs for missioning its ownership share of its nuclear generating stations is currently included in regulated rates and is charged to operations over the expected service life of the related plant. The amounts recovered from customers are deposited in trust accounts and invested for funding of future costs. These amounts, and realized investment earnings thereon, are ed to accumulated depreciation.

The Company believes that the amounts being recovered from customers through electric rates will be sufficient to fully fund the unrecorded portion of its decommissioning obligation.

Allowance for Funds Used During Construction (AFUDC) AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations.

AFUDC is recorded as a charge to Construction Work in Progress and as a credit to AFUDC 30 included in Other Income and Deductions.

The rates used for capitalizing AFUDC, which averaged 8.63% in 1998, 8.88% in 1997 and 9.38% in 1996, are computed under a method scribed by regulatory authorities.

AFUDC is not included in regular taxable income and the depreciation of capitalized AFUDC is not tax deductible.

Effective January 1, 1998, the Company ceased accruing AFUDC for electric generation-related construction projects and began using SFAS No. 34, "Capitalizing Interest Costs," to culate the costs during construction of debt funds used to finance its electric generation-related construction projects.

The Company recorded capitalized interest of $7 million in 1998. Gains and Losses on Reacquired Debt Prior to December 31, 1997, gains and losses on reacquired debt were deferred and amortized to interest expense over the period approved for ratemaking purposes.

Effective January 1, 1998, gains and losses on reacquired debt associated with the electric generation portion of the Company's operations are expensed as incurred.

Gains and losses on reacquired debt associated with the Company's regulated operations continue to be deferred and amortized to interest expense over the od approved for ratemaking purposes based on management's assessment of the likelihood of recovery.

Income Taxes Deferred Federal and state income taxes are provided on all significant timing differences between book bases and tax bases of assets and liabilities, transactions that reflect taxable income in a year different than book income and tax carry wards. Investment tax credits previously used for income tax purposes have been deferred on the Consolidated Balance Sheet and are recognized in book income over the life of the related property.

The Company and its subsidiaries file a Consolidated Federal income tax return. Income taxes are allocated to each of the Company's subsidiaries within the consolidated group based on the separate return method. Derivative Financial Instruments Hedge accounting is applied only if the derivative reduces the risk of the underlying hedged item and is designated at tion as a hedge, with respect to the hedged item. If a derivative instrument ceased to meet the criteria for deferral, any gains or losses would be currently recognized in income. The Company does not hold or issue derivative financial instruments for trading purposes.

Utility Plant Effective December 31, 1997, electric generation plant is ued at the lower of original cost or market pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"(SFAS No. 121 ). All other utility plant continues to be valued at nal cost. Capitalized Software Costs Software projects which exceed $5 million are capitalized.

At December 31, 1998 and 1997, capitalized software costs totaled $84 and $86 million (net of $37 and $29 million mulated amortization), respectively.

Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed ten years. PECO Energy Company and Subsidiary Companies New Accounting Pronouncements In 1998, the Company adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131). SFAS No. 131 supersedes SFAS No. 14, "Financial Reporting for Segments of a Business Enterprise," replacing the "industry segment" approach with the agement" approach.

The management approach designates the internal organization that is used by management for making operating decisions and assessing performance as the source of the Company's reportable segments.

SFAS No. 131 also requires disclosures about products and services, geographic areas and major customers.

The adoption of SFAS No. 131 did not affect the Company's financial condition or results of operations (see note 2). In 1998, the Company adopted SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," (SFAS No. 132) which revises and standardizes employers' disclosures about pension and other postretirement benefit plans but does not change the surement or recognition of those plans. The adoption of SFAS No. 132 did not affect the Company's financial condition or results of operations (see note 6). In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," (SFAS No. 133) to establish accounting and reporting standards for derivatives.

The new standard requires recognizing all derivatives as either assets or liabilities on the balance sheet at their fair value and specifies the accounting for changes in fair value depending upon the intended use of the derivative.

The new standard will be effective for fiscal years beginning after Jun 15, 1999. The Company expects to adopt SFAS No. 133 in the first quarter of 2000. The Company is in the process of evaluating the impact of SFAS No. 133 on its financial ments. In November 1998, the FASB's Emerging Issues Task Force issued EITF 98-10. "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." EITF 98-10 outlines attributes that may be indicative of an energy trading operation and gives further guidance on the ing for contracts entered into by an energy trading operation.

This accounting guidance requires mark-to-market accounting for contracts considered to be a trading activity.

EITF 98-10 is applicable for fiscal years beginning after December 15, 1998 with any impact recorded as a cumulative effect adjustment through retained earnings at the date of adoption.

At December 31, 1998, the Company has evaluated its sale marketing operation and related contracts under the guidance provided in EITF 98-10. For those contracts entered into in the over-the-counter market and considered to be a trading activity, the Company believes the impact to be immaterial.

However, due to the duration, complexity, and uncertainties surrounding the long-term commitments ered to be trading activities, the Company is continuing to evaluate these commitments and the impact of adopting EITF 98-10. Reclassifications

• Certain prior-year amounts have been reclassified for compar-ative purposes.

These reclassifications had no effect on net income or common shareholders' equity.

Notes to Consolidated Financial Statements 31 . Nature of Operations and Information about Products and Services he Company is primarily a vertically integrated public utility that provides retail electric and natural gas service to the public in its traditional service territory and retail electric generation service throughout Pennsylvania in conjunction with Pennsylvania's Customer Choice Program. The Company also engages in the wholesale marketing of electricity on a national basis. The Company participates in joint ventures which provide services such as telecommunications in the Philadelphia metropolitan area. Revenues and expenses associated with these activities, the Customer Choice Program, joint ventures and other projects are reflected in Other Income and Deductions in the Company's Consolidated Statements of Income. For the Years Ended December 31, Operating Revenues from Electric Operations Residential Small commercial and industrial Large commercial and industrial Other Unbilled Service territory Interchange sales Sales to other utilities Total operating revenues Operating Revenues from Gas Operations Residential House heating Commercial and industrial Other nbilled Subtotal Other revenues (including gas transported for customers)

Total operating revenues 3. Rate Matters Final Restructuring Order On May 14, 1998, the PUC issued a final order (Final Restructuring Order) approving a Joint Petition for Settlement (Global Settlement) filed by the Company and numerous ties to the Company's restructuring proceeding mandated by the Electricity Generation Competition and Customer Choice Act (Competition Act). The Competition Act provides for the restructuring of the electric utility industry in Pennsylvania, including the deregulation of generation operations and the institution of retail competition for generation supply ning in 1999. The Final Restructuring Order provided for the recovery of $5.26 billion of stranded costs through transition charges to distribution customers over a 12 year period beginning in 1999 with a 10.75% return on the balance and supercedes all prior orders regarding recovery of related regulatory assets and liabilities.

During the 12 year stranded cost recovery period, the Company will amortize the recoverable stranded costs in accordance with the rate schedules determined in the Final Restructuring Order. The Final Restructuring Order provided for the phase-in f customer choice of electric generation supplier (EGS) for all customers:

one-third of the peak load of each customer class on January 1, 1999; one-third on January 2, 1999; and the remainder on January 2, 2000. The Final Restructuring Order also established market share thresholds to ensure that a minimum number of residential and commercial cus-1998 1997 1996 Thousands of Dollars $ 1,377,237

$ 1,357,449

$ 1,370, 158 783,682 778,743 748,561 1,066,868 1,077,374 1,098,307 149,424 147,523 140,133 1,409 19, 130 (25,950) 3,378,620 3,380,219 3,331,209 210,965 58,614 25,991 1,221,255 727,836 497,636 $ 4,810,840

$ 4, 166,669 $ 3,854,836

$ 15,968 $ 16,852 $ 15,716 236,430 265,299 249,507 124,548 144,801 132,822 2,037 3,228 11,462 (2,960) (969) (4,250) 376,023 429,211 405,257 23,619 22,021 23,557 $ 399,642 $ 451,232 $ 428,814 tomers choose an EGS. If less than 35% and 50% of tial and commercial customers have chosen an EGS by January 1, 2001 and January 1, 2003, respectively, the ber of customers sufficient to meet the necessary threshold levels shall be randomly selected and assigned to an EGS through a PUC-determined process. Beginning January 1, 1999, electric rates will be dled into transmission and distribution components, a Competitive Transition Charge (CTC) for recovery of stranded costs and an energy and capacity charge. Eligible customers who choose an alternative EGS will not be charged the gy and capacity charge or the transmission charge and instead will purchase their electric energy supply and mission at market-based rates from their EGS. The Company will in turn be reimbursed by the EGS, via the PJM Interconnection, LLC, for the cost of the transmission service at a rate approximately equivalent to the unbundled transmission rate. Also, beginning January 1, 1999, the Company will unbundle its retail electric rates for metering, meter reading and billing and collection services to provide credits to those customers who elect to have an alternative supplier perform these services.

In accordance with the Competition Act and the Final Restructuring Order, the Company's retail electric rates are capped at the year-end 1996 levels (system-wide average of 9.96 cents/kilowatt hour (kWh)) through June 2005. The Final Restructuring Order requires the Company to reduce its retail 32 electric rates by 8% from the 1996 system-wide average rate on January 1, 1999. The rate decrease will become 6% from January 1, 2000 until January 1, 2001, when the system-wide average rate cap will revert to 9.96 cents/kWh.

The sion and distribution rate component will remain capped at a system-wide average rate of 2.98 cents/kWh through June 30, 2005. Additionally, generation rate caps, defined as the sum of the applicable transition charge and energy and ity charge, will remain in effect through 2010. The Final Restructuring Order requires that on January 1, 2001, 20% of all of the Company's residential customers, determined by random selection and without regard to whether such customers are obtaining generation service from an alternate EGS, shall be assigned to a provider of last resort default supplier other than the Company through a PUC-approved bidding process. The Final Restructuring Order authorizes the issuance of up to $4 billion of transition bonds (Transition Bonds). In

• preparation for the issuance of Transition Bonds, the Company formed a special purpose subsidiary (SPS). The ceeds of the Transition Bonds are required to be used principally to reduce recoverable stranded costs and related capitalization.

The Transition Bonds will be obligations of the SPS, secured by intangible transition property (ITP). JTP sents the irrevocable right of the Company or its assignee, to collect non-bypassable charges from customers to recover stranded costs. The Company filed complaints in federal and state courts relating to the restructuring orders issued by the PUC in December 1997, January 1998 and February 1998. In tion, numerous other parties filed appeals and cross appeals of these orders. In accordance with the terms of the Final Restructuring Order, all appeals and cross-appeals filed by the signatories to the Global Settlement have been placed in a pending but inactive status. Such appeals and cross appeals will be permanently withdrawn at such time that the Final Restructuring Order is no longer subject to administrative or judicial challenge.

In an appeal of a PUC order issued in May 1997, an venor brought an action asserting that the stranded cost recovery provisions of the Competition Act violated the Commerce Clause of the United States Constitution.

On May 7, 1998, the Commonwealth Court of Pennsylvania mously rejected the claim. The intervenor petitioned the Supreme Court of Pennsylvania for allowance of appeal. On September 29, 1998, the Pennsylvania Supreme Court denied the petition.

On December 28, 1998, the intervenor filed a petition for certiorari with the United States Supreme Court. Limerick Through 1997, the Company was recovering certain deferred Limerick costs. At December 31, 1997, the unamortized tion of these regulatory assets of $321 million was included as part of electric generation-related regulatory assets. Under its electric tariffs and ECA, the Company was allowed to retain for shareholders any proceeds above the average energy cost for sales of 399 megawatts (MW) of term excess capacity and/or associated energy and to share in the benefits which resulted from the operation of both Limerick Units No. 1 and No. 2. The Company's ECA was continued at December 31, 1996. During 1996, the Company PECO Energy Company and Subsidiary Companies recorded as revenue net of fuel costs $82 million, as a result of the sale of the 399 MW of capacity and/or associated energy and the Company's share of Limerick energy savings. Declaratory Accounting Order Pursuant to a PUC Declaratory Order, effective October 1, 1996, the Company increased depreciation and amortization on assets associated with Limerick by $100 million per year and decreased depreciation and amortization on other Company assets by $10 million per year, for a net increase in depreciation and amortization of $90 million per year. At December 31, 1997, $90 million of depreciation and tion that would have been recognized in 1998 was deferred as a regulatory asset since the Company's rates continued to be cost-based until January 1, 1999. During 1998 these amounts were amortized and recovered.

Energy Cost Adjustment (ECA) Through December 31, 1996, the Company was subject to a PUC-established electric ECA which, in addition to reconciling fuel costs and revenues, incorporated a nuclear performance standard which allowed for financial bonuses or penalties depending on whether the Company's system nuclear ty factor exceeded or fell below a specified range. For the year ended December 31, 1996 the Company recorded a bonus of $22 million. 4. Accounting Changes The Company accounts for its electric transmission and distr bution and gas operations in accordance with SFAS No. 71 which requires the Company to record the financial ment effects of the rate regulation to which the Company is subject. Use of SFAS No. 71 is applicable to the utility tions of the Company which meet the following criteria:

(1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. The Company believes that it is probable that regulatory assets associated with these tions will be recovered.

Effective December 31, 1997, the Company ued the application of SFAS No. 71 for its retail electric generation operations and adopted the provisions of SFAS No. 101 "Regulated Enterprises

-Accounting for the Discontinuation of Application of FASB Statement No. 71." As required by SFAS No. 101, at December 31, 1997, the Company performed an impairment test of its electric generation assets pursuant to SFAS No. 121, on a plant cific basis and determined that $6.1 billion of its $7.1 billion of electric generation assets would be impaired as of December 31, 1998. The Company estimated the fair value for each of its electric generating units by determining its estimated future operating cash inflows and outflows.

The net future cash flows for each electric generating plant were then compared to its net book value. For any electric ing plant with future undiscounted cash flows less than its book value, net cash flows were discounted using a discoun rate commensurate with the risk of each electric generating plant. Since the Company's retail electric rates continued to be cost-based through January 1, 1999, $333 million repre-senting depreciation expense on electric generation-related Notes to Consolidated Financial Statements

-ets in 1998 and $91 million representing amortization of er regulatory assets in 1998 were reclassified to a asset and were amortized and recovered in 1998. At December 31, 1997, the Company had total electric generation-related stranded costs of $8.4 billion, representing

$5.8 billion of net stranded electric generation plant and $2.6 billion of electric generation-related regulatory assets. The original PUC restructuring order allowed the Company to recover $5.3 billion of its generation-related stranded costs from customers.

This resulted in a net unrecoverable amount of $3.1 billion. Accordingly, the Company recorded an dinary charge at December 31, 1997 of $3.1 billion ($1.8 billion net of taxes) of electric generation-related stranded costs that will not be recovered from customers.

The Final Restructuring Order did not change the amount of allowable stranded costs. Effective December 31, 1997, the Company ued the application of SFAS No. 71 for its wholesale energy sales operations.

Based on projections of the Company's retail load growth, the Company concluded all of its owned generation capacity would be necessary to meet its electric retail load. As a result, the discontinuance of SFAS No. 71 for its wholesale energy sales operations did not result in a charge against income. 5. Commitments and Contingencies Capital Commitments The Company estimates

$440 million of capital expenditures 999. Certain facilities under construction and to be cted may require permits and licenses which the mpany has no assurance will be granted. Capital tures do not include investments in joint ventures including investments related to the Company's strategy to expand its generation portfolio.

Nuclear Insurance As of December 31, 1998, the Price-Anderson Act limited the liability of nuclear reactor owners to $9.8 billion for claims that could arise from a single incident.

The limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

The Company carries the maximum available commercial insurance of $200 million and the remaining

$9.6 billion is provided through mandatory ticipation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $88 million per reactor per incident, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue raising measures on the nuclea*r industry to pay claims. The Company carries property damage, decontamination and premature decommissioning insurance in the amount of its $2.75 billion proportionate share for each station loss resulting from damage to its nuclear plants. In the event of an accident, insurance proceeds must first be used for reac-stabilization and site decontamination.

If the decision is e to decommission the facility, a portion of the insurance oceeds will be allocated to a fund which the Company is required by the Nuclear Regulatory Commission (NRC) to maintain to provide for decommissioning the facility.

The Company is unable to predict the timing of the availability of 33 insurance proceeds to the Company for the Company's holders, and the amount of such proceeds which would be available.

Under the terms of the various insurance ments, the Company could be assessed up to $30 million for losses incurred at any plant insured by the insurance nies. The Company is self-insured to the extent that any losses may exceed the amount of insurance maintained.

Such losses could have a material adverse effect on the Company's financial condition and results of operations.

The Company is a member of an industry mutual ance company which provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The premium for this coverage is subject to assessment for adverse loss experience.

The Company's maximum share of any assessment is $10 million per year. Nuclear Decommissioning and Spent Fuel Storage The Company's current estimate of its nuclear facilities' decommissioning cost is $1.5 billion in 1997 dollars. Through 1998, this amount was being collected through electric rates over the life of each generating unit. Beginning in 1999, decommissioning costs will be recoverable through regulated rates. Under rates in effect through December 31, 1998, the Company collected and expensed approximately

$20 million annually from customers which was accounted for as a ponent of depreciation expense and accumulated depreciation.

At December 31, 1998 and 1997, $336 and $294 million, respectively, were included in accumulated tion. In order to fund future decommissioning costs, at December 31, 1998 and 1997, the Company held $378 and $320 million, respectively, in trust accounts which are ed as Investments in the Company's Consolidated Balance Sheets and include both net unrealized and realized gains. Net unrealized gains of $60 and $43 million were recognized as a Deferred Credit in the Company's Consolidated Balance Sheet at December 31, 1998 and 1997, respectively.

The Company recognized net realized gains of $12, $11 and $10 million as Other Income in the Company's Consolidated Statement of Income for the years ended December 31, 1998, 1997 and 1996, respectively.

The Company believes that the amounts being recovered from customers through regulated rates will be sufficient to fully fund the unrecorded portion of its decommissioning obligation.

In an Exposure Draft issued in 1996, the FASB proposed changes in the accounting for closure and removal costs of production facilities, including the recognition, measurement and classification of decommissioning costs for nuclear erating stations.

The FASB has expanded the scope of the Exposure Draft to include closure or removal liabilities that are incurred at any time during the operating life of the ed long-lived asset. The FASB has decided that it should proceed toward either a final Statement or a revised Exposure Draft. The timing of this project is still to be mined. If current electric utility industry accounting practices for decommissioning are changed, annual provisions for decommissioning could increase and the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation with recognition of an increase in the cost of a related regulatory asset. Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is required to begin taking possession of all spent nuclear fuel generated by the 34 Company's nuclear units for long-term storage by no later than 1998. Based on recent public pronouncements, it is not likely that a permanent disposal site will be available for the industry before 2015, at the earliest.

In reaction to ments from the DOE that it was not legally obligated to begin to accept spent fuel in 1998, a group of utilities and state government agencies filed a lawsuit against the DOE which resulted in a decision by the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) in July 1996 that the DOE had an unequivocal obligation to begin to accept spent fuel in 1998. In accordance with the NWPA, the Company pays the DOE one mill ($.001) per kilowatthour of net nuclear generation for the cost of nuclear fuel long-term storage and disposal.

This fee may be adjusted prospectively in order to ensure full cost recovery.

Because of inaction by the DOE following the D.C. Court of Appeals finding of the DOE's obligation to begin receiving spent fuel in 1998, a group of forty-two utility companies, including the Company, and forty-six state agencies, filed suit against the DOE ing authorization to suspend further payments to the U.S. government under the NWPA and to deposit such payments into an escrow account until such time as the DOE takes effective action to meet its 1998 obligations.

In November 1997, the D.C. Court of Appeals issued a decision in which it held that the DOE had not abided by its prior determination that the DOE has an unconditional obligation to begin al of spent nuclear fuel by January 31, 1998. The D.C. Court of Appeals also precluded the DOE from asserting that it was not required to begin receiving spent nuclear fuel because it had not yet prepared a permanent repository or an interim storage facility.

The DOE and one of the utility companies filed Petitions for Reconsideration of the decision which were denied, as were petitions seeking U.S. Supreme Court review of the decision.

In addition, the DOE is exploring other options to address delays in the waste acceptance schedule.

Peach Bottom has on-site facilities with capacity to store spent nuclear fuel discharged from the units through 2000 for Unit No. 2 and 2001 for Unit No. 3. Life-of-plant storage capacity will be provided by on-site dry cask storage facilities, the construction of which began in 1998. Limerick has on-site facilities with capacity to store spent nuclear fuel to 2007. Salem has on-site facilities with spent fuel storage capacity through 2008 for Unit No. 1 and 2012 for Unit No. 2. Energy Commitments The Company's electric utility operations include the sale marketing of electricity.

The Company utilized certain types of fixed-price contracts and other risk management instruments in connection with its wholesale marketing ations. These contracts include long-term contracts which commit the Company to purchase or sell energy at fixed prices in the future (i.e. fixed-price forward purchase and sales contracts), and short-term bilateral swaps and options contracted for in the over-the-counter market. Under some of these contracts, the Company may purchase at its option additional power as needed. The use of the foregoing types of contracts is so that the Company may manage and hedge its retail and wholesale commitments in coordination with the economic dispatch of the Company's installed capacity.

At December 31, 1998, the Company had long-term mitments relating to the purchase from unaffiliated utilities and others of energy associated with 632 MW of capacity in PECO Energy Company and Subsidiary Companies 1999, with 2,054 MW of capacity during the period 2000 through 2002 and with 2.431 MW of capacity thereafter.

During 1998, purchases under long-term commitments resulted in expenditures of $170 million. As of December 31, 1998, these purchase commitments result in obligations of approximately

$121 million for 1999, $526 million for 2000 through 2002 and $805 million thereafter.

These purchases will be utilized through a combination of retail sales to tomers, long-term sales to other utilities and open market sales. At December 31, 1998, the Company had entered into long-term agreements with unaffiliated utilities to sell energy associated with 5,094 MW of capacity, of which 1,030 MW of these agreements are for 1999, 2,202 MW are for 2000 through 2002 and the remaining 1,862 MW extend through 2009. At December 31, 1998, the Company had entered into term agreements with unaffiliated utilities to purchase transmission rights. These purchase commitments result in obligations of approximately

$21 million in 1999, $19 million in 2000 and $9 million per year in 2001 through 2003. Environmental Issues The Company's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under federal and state environmental laws, the Company is generally liable for the costs of remediating environmental contamination of property now or formerly owned by the Company and of property contaminated by hazardous substances generated by the Company. The Company owns or leases a number. real estate parcels, including parcels on which its operatic or the operations of others may have resulted in contamina-tion by substances which are considered hazardous under environmental laws. The Company is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to tional proceedings in the future. The Company has identified 28 sites where former ufactured gas plant (MGP) activities have or may have resulted in actual site contamination.

The Company is presently engaged in performing various levels of activities at these sites, including initial evaluation to determine the tence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation.

The Pennsylvania Department of Environmental Protection has approved the Company's clean up of three sites. Eight other sites are currently under some degree of active study and/or remediation.

As of December 31, 1998 and 1997, the Company had accrued $60 and $63 million, respectively, for environmental investigation and remediation costs, including

$33 and $35 million, respectively, for MGP investigation and remediation, that currently can be reasonably estimated.

The Company cannot reasonably estimate whether it will incur other cant liabilities for additional investigation and remediation costs at these or additional sites identified by the Compan environmental agencies or others, or whether such costs be recoverable from third parties.

Notes to Consolidated Financial Statements

• "gation

• ys Ferry Cogeneration Partnership April 9, 1998, Grays Ferry Cogeneration Partnership

{Grays Ferry). two of three partners of Grays Ferry and Trigen-Philadelphia Energy Corporation, filed a complaint in Philadelphia County qf Common Pleas against the Company for specific formance, breach of contract, fraud and breach of implied covenant of good faith and fair dealing, conversion, unjust ment, breach of fiduciary duties and tortious interference with respect to two power purchase agreements

{PPAs} that the Company had entered into with Grays Ferry. The plaintiff seeks specific performance, damages in excess of $200 million and punitive damages. A preliminary injunction was entered against the Company on May 5, 1998, enjoining the Company from minating the PPAs. On May 29, 1998, Westinghouse Power Generation filed a complaint in the Philadelphia Court of Common Pleas against the Company for tortious interference with two alleged contracts that Westinghouse has with Grays Ferry. On September 4, 1998, The Chase Manhattan Bank, as agent for a syndicate of banks that are lenders to Grays Ferry, 6. Retirement Benefits 35 filed a complaint against the Company alleging tortious ference by the Company in the credit agreements between Grays Ferry and the banks and breach of contract of a letter agreement between the Company and the banks. The Company cannot predict the outcome of these matters. Cajun Electric Power Cooperative, Inc. On May 27, 1998, the United States Department of Justice, on behalf of the Rural Utilities Service and the Chapter 11 Trustee for the Cajun Electric Power Cooperative, Inc. {Cajun), filed an action claiming breach of contract against the Company in the United States District Court for the Middle District of Louisiana arising out of the Company's termination of the contract to chase Cajun's interest in the River Bend nuclear power plant. This action seeks $67 million in damages. The Company cannot predict the outcome of this matter. The Company is involved in various other litigation matters. The ultimate outcome of such matters, while uncertain, is not expected to have a material adverse effect on the Company's financial condition or results of operations.

The Company and its subsidiaries have a defined benefit pension plan and postretirement benefit plans applicable to essentially all employees.

The following provides a reconciliation of benefit obligations, plan assets and funded status of the plans. Other Postretirement Thousands of Dollars Pension Benefits Benefits 1998 1997 1998 1997

n Benef;t Obl;gation

?enefit obligation at beginning of year $ 2,141,040

$ 1,982,915

$ 779,231 $ 662,701 vice cost 30,167 25,368 18,375 14,401 Interest cost 153,644 150,057 53,924 54, 149 Plan participants' contributions 397 Plan amendments (3,052) Actuarial

{gain}/loss 143,274 129, 148 (8,260) 85,452 Curtailments (73,330) 10,403 Settlements (46,541) Special termination benefits 114,182 29,712 Gross benefits paid (152,850)

(143,396)

(36,011) (37,472) Net benefit obligation at end of year $ 2,309,586

$ 2,141,040

$ 847,771 $ 779,231 Change in Plan Assets Fair value of plan assets at beginning of year $ 2,538,039

$ 2,302,935

$ 178,045 $ 126,661 Actual return on plan assets 343,754 377,803 23,535 22,691 Employer contributions 16,404 697 57,319 66, 165 Plan participants' contributions 397 Gross benefits paid (152,850)

(143,396)

(36,011) (37,472) Fair value of plan assets at end of year $ 2,745,347

$ 2,538,039

$ 223,285 $ 178,045 Funded status at end of year $ 435,761 $ 396,999 $ (624,486)

$ (601, 186) Unrecognized net actuarial

{gain}/loss (659,480)

(649,903) 37,617 53, 110 Unrecognized prior service cost 65,419 83, 188 Unrecognized net transition obligation{asset}

(30,512) (35.713) 165,786 223,226 t amount recognized at end of year $ (188,812)

$ (205,429)

$ (421,083)

$ (324,850) ounts recognized in the consolidated balance sheet consist of: Prepaid benefit cost $ 30,462 $ 6,167 $ N/A $ N/A Accrued benefit cost (219,274)

(211,596)

(421,083)

(324,850)

Net amount recognized at end of year $ (188,812)

$ (205,429)

$ (421,083)

$ (324,850) 36 PECO Energy Company and Subsidiary Companies Pension Benefits Other Postretirement Benefits 1998 1997 1996 1998 1997 19 Weighted-average assumptions as of December 31 Discount rate 7.00% 7.25% 7.75% 7.00% 7.25% 7.75% Expected return on plan assets 9.50% 9.50% 9.50% 8.00% 8.00% 8.00% Rate of compensation increase 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% Health care cost trend on covered charges N/A N/A N/A 6.5% 7.0% 8.0% decreasing to decreasing to decreasing to ultimate trend ultimate trend ultimate trend of 5.0% in 2002 of 5.0% in 2002 5.0% in 2002 Components of net periodic benefit cost Service cost $ 30,167 $ 25,368 $ 27,627 $ 18,375 $ 14,401 $ 11,855 Interest cost 153,644 150,057 145,570 53,924 54, 149 48,524 Expected return on assets (209,976)

(182,866)

(171,207)

(13,243) (9,984) (3,937) Amortization of: Transition obligation (asset) (4,538) (4,538) (4,538) 14,882 14,882 14,882 Prior service cost 6,441 6,441 5, 114 Actuarial (gain)loss (7,028) (3,898) 248 Curtailment charge (credit) (62,002) 52,961 Settlement charge (credit) (13,439) Net periodic benefit cost $ (106,731)

$ (9,436) $ 2,814 $ 126,899 $ 73,448 $ 71,324 Special termination benefit charge(credit)

$ 114, 182 $ $ $ 29,712 $ $ Sensitivity of retiree welfare results

• Effect of a one percentage point increase in assumed health care cost trend on total service and interest cost components

$ 10,432 on postretirement benefit obligation

$ 90,490 Effect of a one percentage point decrease in assumed health care cost trend on total service and interest cost components

$ (8,460) on postretirement benefit obligation

$ (75,599) Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. lar benefits for active employees are provided by an ance company whose premiums are based upon the benefits paid during the year. During 1998, costs were recognized for special tion benefits in connection with the retirement incentives and enhanced severance benefits provided under the Company's Workforce Reduction Program. The Company provides certain health care and life ance benefits for retired employees.

Company employees become eligible for these benefits if they retire from the Company with ten years of service. These benefits and simi-The Company sponsors a qualifying savings plan ing all employees.

Contributions made by participating employees are matched based on a specified percentage of employee contribution up to 4% of the employees' pay base. The cost of the Company's matching contribution to the ings plan totaled $7 million, $7 million and $3 million in 1998, 1997 and 1996, respectively.

Notes to Consolidated Financial Statements

-Accounts Receivable counts receivable at December 31, 1998 and 1997 unbilled operating revenues of $142 and $135 million, respectively.

The allowance for uncollectible accounts at December 31, 1998 and 1997 was $20 and $32 million, respectively.

The Company is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $425 million of designated accounts receivable until November 2000. At December 31, 1998, the Company had sold a $425 million interest in accounts receivable, consisting of a $358 8. Common Stock At December 31, 1998 and 1997, common stock without par value consisted of 500,000,000 shares authorized and 224,684,306 and 222,546,562 shares outstanding, ly. At December 31, 1998, there were 5,800,841 shares reserved for issuance under the Company's Dividend Reinvestment and Stock Purchase Plan. Stock Repurchase During 1997, the Company's Board of Directors authorized the repurchase of up to 25 million shares of its common stock from time to time through open-market, privately tiated and/or other types of transactions in conformity with the rules of the Securities and Exchange Commission.

Pursuant to these authorizations, the Company has tered into forward purchase agreements to be settled from me to time, at the Company's election, on either a physical, net share or net cash basis. The amount at which these agreements can be settled is dependent principally upon the market price of the Company's common stock as compared to the forward purchase price per share and the number of shares to be settled. If these agreements had been settled Earnings (Loss} applicable to common stock Earnings (Loss} per average common share (Dollars}

37 million interest in accounts receivable which the Company accounts for as a sale and a $67 million interest in special agreement accounts receivable which were accounted for as a long-term note payable (see note 12). The Company retains the servicing responsibility for these receivables.

The ment requires the Company to maintain the $425 million interest.

which, if not met, requires the Company to deposit cash in order to satisfy such requirements.

At December 31, 1998, the Company did not meet this requirement and was required to make a deposit of $7 million. on a net share basis at December 31, 1998, based on the closing price of the Company's common stock on that date, the Company would have received approximately

4.6 million

shares of Company common stock. Stock Option Plans The Company maintains a Long-Term Incentive Plan (LTIP) for certain full-time salaried employees of the Company. The types of long-term incentive awards which have been ed under the LTIP are non-qualified options to purchase shares of the Company's common stock and shares of restricted common stock. In 1998, the Company initiated a Broad-based Incentive Program and awarded non-qualified options to all employees except those in electric transmission and distribution system and gas operations.

The Company uses the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." If the Company elected to account for the LTIP based on SFAS No. 123, earnings applicable to common stock and earnings per average common share would have been changed to the pro forma amounts as follows: 1998 1997 Thousands of Dollars As reported $ 499,615 $ (1,513,910)

Proforma $ 493,696 $ (1,515,895)

As reported $ 2.24 $ (6.80) Proforma $ 2.20 $ (6.81) Options granted under the LTIP and the Broad-based Incentive Program become exercisable upon attainment of a target share value and/or time. All options expire 10 years from the date of grant. Information with respect to the LTIP and the Broad-based Incentive Program at December 31, 1998 and changes for the three years then ended, is as follows:

• 38 PECO Energy Company and Subsidiary Companies Weighted Weighted Weighted Average Average Ave rag Exercise Exercise Exercis Price Price Pric Shares (per share) Shares (per share) Shares (per share) 1998 1998 1997 1997 1996 1996 Balance at January 1 3,816,794

$ 26.14 2,961, 194 $ 26.68 2,591,765

$ 26.16 Options granted 2,933,540 27.74 1, 139,000 22.49 786,500 28.12 Options exercised (2, 130,744) 23.86 (369,871}

25.07 Options cancelled (91,000) 24.82 (283,400) 24.96 (47,200) 29.36 Balance at December 31 4,528,590 27.71 3,816,794 26.14 2,961, 194 26.68 Exercisable at December 31 3,462,550 23.91 2,800,794 26.65 2,192,694 26.17 Weighted average fair value of options granted during year $ 3.43 $ 2.97 $ 2.78 The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 1998, 1997 and 1996, respectively:

1998 1997 1996 Dividend yield 6.8% 6.2% 6.2% Expected volatility 21.4% 19.5% 16.6% Risk-free interest rate 5.5% 6.4% 5.5% Expected life (years} 9.5 5 5 At December 31, 1998, the option groups outstanding, based on ranges of exercise prices, were as follows: Or:itions Outstanding O[:ltions Exercisable Weighted-Average Weighted Weighte. Remaining Average Ave rag Number Contractual Life Exercise Number Exercis Range of Exercise Prices Outstanding (Years) Price Exercisable Price $15.75 -$20.00 899,700 8.71 $ 19.60 899,700 $ 19.60 $20.01 -$25.00 1,019,750 8.41 22.15 1,004,750 22.18 $25.01 -$30.00 1,510,600 5.76 27.38 1,510,600 27.38 $30.01 -$35.00 78,500 9.43 32.97 47,500 31.98 $35.01 -$50.00 1,020,040 9.87 40.48 Total 4,528,590 3,462,550 The Company issued 7,000 and 4.475 shares of restricted common stock during 1998 and 1997, respectively.

Vesting in the restricted common stock awards is over a period not to exceed 10 years from the grant date. The compensation cost associated with these awards is amortized to expense over the vesting period. Compensation cost associated with these awards is immaterial.

9. Earnings Per Share Diluted earnings per average common share is calculated by dividing earnings applicable to common stock by the weighted average shares of common stock outstanding including stock options outstanding under the Company's stock option plans sidered to be common stock equivalents.

The following table shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per average common share: Average Common Shares Outstanding Assumed Conversion of Stock Options Potential Average Dilutive Common Shares Outstanding 1998 223,219,000 685,000 223,904,000 1997 1996 222,543,000 222,490,000 222,543,000 Notes to Consolidated Financial Statements 39 *. Preferred and Preference Stock December 31, 1998 and 1997, Series Preference Stock consisted of 100,000,000 shares authorized, of which no shares were outstanding.

At December 31, 1998 and 1997, cumulative Preferred Stock, no par value, consisted of 15,000,000 shares authorized.

Current Shares Amount Redemption Outstanding Thousands of Dollars Series of Preferred Stock Price(a) 1998 1997 1998 1997 Series (without mandatory redemption)

$4.68 104.00 150,000 150,000 $ 15,000 $ 15,000 $4.40 112.50 274,720 274,720 27,472 27,472 $4.30 112.00 150,000 150,000 15,000 15,000 $3.80 106.00 300,000 300,000 30,000 30,000 $7.48 (b) 500,000 500,000 50,000 50,000 1,374,720 1,374,720 137,472 137,472 Series (with mandatory redemption)

$6.12 (c) 927,000 927,000 92,700 92,700 Total preferred stock 2,301,720 2,301,720

$ 230,172 $ 230, 172 (a) Redeemable, at the option of the Company, at the indicated dollar amounts per share, plus accrued dividends. (b) None of the shares of this series are subject to redemption prior to April 1, 2003. (c) Annual sinking fund requirements in 1999 -2003 are $18,540,000.

None of the shares of this series are subject to tion prior to August 1, 1999. 11. Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) At December 31, 1998 and 1997, PECO Energy Capital, L.P. (Partnership).

a Delaware limited partnership of which a wholly owned subsidiary of the Company is the sole general partner, had outstanding A. C and D series of COM RPS with liquidation

• lues of $25 (A and C) and $1,000 (D) per security.

Each series is supported by the Company's deferrable interest subordinated bentures, held by the Partnership, which bear interest at rates equal to the distribution rates on the related series of COMRPS. The interest expense on the debentures is included in Other Income and Deductions in the Consolidated Statements of Income and is deductible for tax purposes.

Mandatory Amount Redemption Distribution Trust Receipts Outstanding Thousands of Dollars At December 31, Date Rate 1998 1997 1998 1997 Series A 2043 9.00% 8,850,000 8,850,000

$ 221,250 $ 221,250 B (a) 2025 8.72% 3,124,183 80,835 c (b) 2037 8.00% 2,000,000 2,000,000 50,000 50,000 D (c) 2028 7.38% 78,105 78, 105 Total (a) On May 15, 1998, PECO Energy Capital Trust I redeemed all outstanding Trust Receipts, each ing an 8.72% Cumulative Monthly Income Preferred Security, Series B of PECO Energy Capital, L.P. (b) Ownership of this series is evidenced by Trust Receipts, each representing an 8.00% COMRPS, Series C, senting limited partnership interests.

The Trust Receipts were issued by PECO Energy Capital Trust II, the sole assets of which are 8.00% COM RPS, Series C. Each holder of Trust Receipts is entitled to withdraw the sponding number of 8.00% COMRPS, Series C from the

• Trust in exchange for the Trust Receipts so held . 10,928,105 13,974, 183 $ 349,355 $ 352,085 (c) Ownership of this series is evidenced by Trust Receipts, each representing an 7.38% COMRPS, Series D, senting limited partnership interests.

The Trust Receipts were issued by PECO Energy Capital Trust Ill, the sole assets of which are 7.38% COM RPS, Series D. Each holder of Trust Receipts is entitled to withdraw the sponding number of 7.38% COMRPS, Series D from the Trust in exchange for the Trust Receipts so held. This Series was issued on April 6, 1998.

40 12. Long-Term Debt At December 31, First and refunding mortgage bonds (a) Total first and refunding mortgage bonds Notes payable Pollution control notes Medium-term notes Note Payable -accounts receivable agreement Unamortized debt discount and premium, net Total long-term debt Due within one year Long-term debt included in capitalization (a) Utility plant is subject to the lien of the Company's gage.* (b) Floating rates, which were an average annual interest rate of 3.13% at December 31, 1998. (c) Floating rates, which were an average annual interest rate of 3.32% at December 31, 1998. (d) Medium-term notes collateralized by mortgage bonds. The average annual interest rate was 9.09% at December 31, 1998. (e) See note 7. (f) Long-term debt maturities, including mandatory sinking fund requirements, in the period 1999-2003 are as lows: 1999 -$361,523,000; 2000 -$74,255,500; 2001 -$337,431,500; 2002 -$507,436,500; 2003 -$406,534,500.

13. Short-Term Debt Average borrowings Average interest rates, computed on daily basis Maximum borrowings outstanding Average interest rates, at December 31 The Company has a $400 million one-year term loan ment with a group of banks, which expires on November 30, 1999. At December 31, 1998, $400 million of short-term debt was outstanding under this term loan agreement.

The Company has a $900 million unsecured revolving credit facility with a group of banks. The credit facility sists of a $450 million 364-day credit agreement and a $450 million three-year credit agreement.

The Company uses the PECO Energy Company and Subsidiary Companies Series Due 1998 199 Thousands of Dollars 5 3/8 % 1998 $ $ 225,000 7 1/2%-9 1/4% 1999 325,000 325,000 5 5/8%-7 3/8% 2001 330,000 330,000 7 1/8%-8% 2002 500,000 500,000 6 1/2%-6 5/8% 2003 450,000 450,000 6 3/8%-10 1/4 % 2004-2008 111,562 115,625 (b) 2009-2013 154,200 154,200 6 5/8%-8 3/4% 2019-2024 1,082, 130 1,607, 130 2,952,892 3,706,955 15,930 15,574 (c) 212,705 212,705 (d) 50,000 62,400 (e) 66,837 128,999 (17,249) (26,405) 3,281,115 4, 100,228 (f) 361,523 247,087 (g) $ 2,919,592

$ 3,853,141 (g) The annualized interest on long-term debt at December 31, 1998, was $222 million, of which $210 million was associated with mortgage bonds and $12 million was associated with other long-term debt. In the fourth quarter of 1998, the Company redeemed $525 million of its First Mortgage Bonds consisting of: $150 milli. of its 8 3/4% series due 2022, $125 million of its 8 5/8% series due 2022 and $250 million of its 8 1/4% series due 2022 at redemption prices of 105.75, 105.20 and 104.85 plus interest, respectively.

As a result, the Company recognized an extraordinary charge of $34 million ($20 million net of income taxes). The extraordinary charge consisted primarily of premiums and the write-off of deferred charges. 1998 1997 1996 Thousands of Dollars $ 209,261 $ 248, 111 $ 198,090 5.83% 5.83% 5.64% $ 525,000 $ 464,500 $ 369,500 6.17% 6.74% 6.90% credit facility principally to support its $600 million commer-cial paper program. There was no debt outstanding under this credit facility at December 31, 1998. At December 31, 1998, $125 million of commercial paper was outstanding.

At December 31, 1998, the Company had available formal and ;nfmmal fine' of cced;t w;th bank' aggcegafog

$100 mHfion .*

r Notes to Consolidated Financial Statements 41 *. Income Taxes ome tax expense (benefit) is comprised of the following components:

For the Years Ended December 31, 1998 1997 1996 Thousands of Dollars Included in operations:

Federal Current $ 358,051 $ 251,509 $ 126,471 Deferred (109,211)

(11,378) 154,564 Investment tax credit, net (18,066) (18,201) (15,979) State Current 95,309 76,689 62,839 Deferred (6,429) (5,850) 12,206 319,654 292,769 340, 101 Included in extraordinary item: Federal Current (10,583) (123) Deferred (987,234)

State Current (3,174) (29) Deferred (303,575)

(13,757) (1,290,961)

Total $ 305,897 $ (998, 192) $ 340, 101 total income tax provisions, excluding the extraordinary item, differed from amounts computed by applying the federal tutory tax rate to pre-tax income as follows: 1998 1997 1996 Thousands of Dollars Net Income $ 532,378 $ 336,558 $ 517,205 Total income tax provisions 319,654 292,769 340, 101 Income before income taxes $ 852,032 $ 629,327 $ 857,306 Income taxes on above at federal statutory rate of 35% $ 298,211 $ 220,264 $ 300,057 Increase (decrease) due to: Property basis differences (10,262) 40,828 9,903 State income taxes, net of federal income tax benefit 57,582 46,046 48,779 Amortization of investment tax credit (18,066) (18,201) (15,979) Prior period income taxes (12,951) (2,985) (1,707) Other, net 5,140 6,817 (952) Total income tax provisions

$ 319,654 $ 292,769 $ 340, 101 Effective income tax rate 37.5% 46.5% 39.7%

• 42 PECO Energy Company and Subsidiary Companies Provisions for deferred income taxes consist of the tax effects of the following temporary differences:

• 1998 1997 1996 Thousands of Dollars Deferred generation charges recoverable

$ (174,787)

$ $ Depreciation and amortization 140,448 57,530 42,385 Deferred energy costs (2,491) 2,256 27,374 Retirement and separation programs (51,146) (12,734) 19,746 Incremental nuclear outage costs (7,434) (981) 2,440 Uncollectible accounts 4,764 (1,710) (2,805) Reacquired debt (5,026) (8,607) (9,578) Unbilled revenue 3,579 (5, 110) 3,910 Environmental clean-up costs (3,574) (15,121) (714) Obsolete inventory 4,206 (7,074) 5,829 Limerick plant disallowances and phase-in plan (747) (747) AMT credits (42,067) 83,010 Other nuclear operating costs 9,926 (9,892) Other 7,962 (15,038) (4,080) Subtotal (115,640)

(17,228) 166,770 Extraordinary item (1,290,809)

Total $ (115,640)

$ (1,308,037)

$ 166,770 The tax effect of temporary differences giving rise to the Company's net deferred tax liability as of December 31, 1998 and 1997 is as follows: Nature of temporary difference:

Plant basis difference Deferred investment tax credit Deferred debt refinancing costs Other, net Deferred income taxes (net} on the balance sheet The net deferred tax liability show*n above as of December 31, 1998 and 1997 was comprised of $3, 123 and $3, 153 lion of deferred tax liabilities, and $432 and $352 million of deferred tax assets, respectively.

In accordance with SFAS No. 71, the Company recorded a recoverable deferred income tax asset of $614 and $586 million at December 31, 1998 and 1997, respectively.

These balances are applicable only to regulated assets, due to the discontinuance of SFAS No. 71 for the Company's electric generation operations.

These recoverable deferred income taxes include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking policies of the PUC, as well as the revenue impacts thereon, and assume recovery of these costs in future rates. Liability or (Asset) 1998 199 Thousands of Doi/a $ 2,653,760

$ 2,620,254 299,999 318,065 37,575 111,651 (300,375)

(249, 167) $ 2,690,959

$ 2,800,803 The Internal Revenue Service (IRS} has completed and settled its examinations of the Company's federal income tax returns through 1990 which resulted in a net increase of $11 million in credits available for carry forward. The 1991 through 1993 federal income tax returns have been ined and the Company and the IRS are in the process of settling the audit which will not have an adverse impact on financial condition or results of operations of the Company. The years 1994 through 1996 are currently being examined by the IRS.

• Notes to Consolidated Financial Statements

5. Taxes, Other Than Income -Operating r the Years Ended December 31, Gross receipts Capital stock Real estate Payroll Other Total 16. Leases Leased property included in utility plant was as follows: At December 31, Nuclear fuel Electric plant Gross leased property Accumulated amortization Net leased property $ $ 1998 155,663 43,754 51,313 30,068 (1,283) 279,515 $ $ $ $ 1997 163,552 48,085 69,597 25,976 2,881 310,091 1998 523,325 2,321 525,646 (371,338) 154,308 43 1996 Thousands of Dollars $ $ 160,246 41,972 69, 185 27,585 558 299,546 1997 Thousands of Dollars $ $ 521,921 2,321 524,242 (348,309) 175,933 Nuclear fuel is amortized as the fuel is consumed.

Amortization of leased property totaled $60, $39 and $31 million for the years ended December 31, 1998, 1997 and 1996, respectively.

Other operating expenses included interest on capital lease obligations of $9 million in 1998, 1997 and 1996, respectively.

inimum future lease payments as of December 31, 1998 were: For the Years Ending December 31, 1999 2000 2001 2002 2003 Remaining years Total minimum future lease payments Imputed interest (rates ranging from 6.5% to 17.0%) Present value of net minimum future lease payments $ $ $ Capital Leases 69,026 65,714 32,439 92 92 721 168,084 (13,776) 154,308 Operating Leases $ $ 48,806 45,457 42,850 42,056 49,386 511, 164 739,719 Total Thousands of Dollars $ $ 117,832 111,171 75,289 42, 148 49,478 511,885 907,803 Rental expense under operating leases totaled $69 million in 1998 and $74 million in 1997 and 1996, respectively .

• __ j I 44 PECO Energy Company and Subsidiary Companies

17. Jointly Owned Electric Utility Plant The Company's ownership interests in jointly owned electric utility plant at December 31, 1998, were as follows: Transmission Production Plants and Other Plant Peach Bottom Salem Keystone Conemaugh Public Service GPU GPU PECO Energy Electric and Generating Generating Various Operator Company Gas Company Corp. Corp. Companies Participating interest 42.49% 42.59%

20.99% 20.72% 21%to43% Company's share (Thousands of Dollars! Utility plant $ 347,001 $ 20,026 $ 118,256 $ 190,672 $ 82,078 Accumulated depreciation 183,383 12,929 73,644 91,052 32,638 Construction work in progress 22,586 1,632 1,770 3,865 1,300 The Company's participating interests are financed with Company funds and, when placed in service, all operations are ed for as if such participating interests were wholly owned facilities.

18. Cash and Cash Equivalents For purposes of the Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.

The following disclosures supplement the accompanying Statements of Cash Flows: Cash paid during the year: Interest (net of amount capitalized)

Income taxes (net of refunds) Noncash investing and financing:

Capital lease obligations incurred 19. Investments At December 31, Trust accounts for decommissioning nuclear plants Telecommunications ventures Energy services and other ventures Nonutility property Other Total 20. Financial Instruments

$ 1998 384,932 346,539 38,307 $ $ $ 1997 405,838 345,232 32,909 1998 377,970 48,391 39,359 40,456 44,728 550,904 1996 Thousands of Dollars $ 415,063 251,554 33,06 1997 Thousands of Dollars $ $ 320,442 85,601 65,578 24,697 19,517 515,835 Fair values of financial instruments, including liabilities, are estimated based on quoted market prices for the same or similar issues. The carrying amounts and fair values of the Company's financial instruments as of December 31, 1998 and 1997 were as follows: Thousands of Dollars Non-derivatives:

Assets Cash and temporary cash investments Trust accounts for decommissioning nuclear plants Liabilities Long-term debt (including amounts due within one year) Derivatives:

Treasure forwards Forward interest rate swaps Carrying Amount $ 48,083 377,970 3,281,115 1998 1997 Fair Carrying Fair Value Amount Value $ 48,083 $ 33,404 $ 33,404 377,970 320,442 320,442 3,404,250 4, 100,228 4,210,88.

(300) (4,400)

Notes to Consolidated Financial Statements ancial instruments which potentially subject the Company concentrations of credit risk consist principally of rary cash investments and customer accounts receivable.

The Company places its temporary cash investments with credit quality financial institutions.

At times, such investments may be in excess of the Federal Deposit Insurance Corporation limit. Concentrations of credit risk with respect to customer accounts receivable are limited due to the Company's large number of customers and their sion across many industries.

The fair value of derivatives generally reflects the mated amounts that the Company would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses of open contracts.

Dealer quotes are available for all of the Company's derivatives.

The anticipated issuance of Transition Bonds significantly exposes the Company to market risks of changes in interest rates. Derivative financial instruments are used by the Company to reduce these risks. The Company has entered into treasury forwards in an aggregate notional amount of $4 billion with an average est rate of 4.71 %. The Company has entered into forward 21. Early Retirement and Separation Program In April 1998, the Board of Directors authorized the tion of a retirement incentive program and an enhanced erance benefit program. The retirement incentive program wed employees age 50 and older, who have been nated as excess or who are in job classifications facing reduction, to retire from the Company. The enhanced ance benefit program provided non-retiring excess employees with fewer than ten years of service benefits equal to two weeks pay per year of service. Non-retiring excess employees with more than ten years of service receive benefits equal to three weeks pay per year of service. Through its Cost Competitiveness Review (CCR). the Company identified 1, 157 employees across the Company who were considered excess or were in job classifications facing reduction.

Of the 1, 157 employees, 711 were eligible for and agreed to take the retirement incentive program. The remaining employees are eligible for the enhanced severance benefit program. The Company has eliminated approximately 422 positions as of December 31, 1998 through both 22. Other Income and Deductions Settlement of Salem Litigation On December 31, 1997, the Company received $70 million pursuant to the May 1997 settlement agreement with Public Service Electric and Gas Company resolving a suit filed by the Company concerning the shutdown of Salem. During the *ond quarter of 1997, the Company recorded $70 million 1 million net of income taxes) as Other Income. 45 starting interest rate swaps in the aggregate notional amount of $713 million with an average interest rate of 5.72%. The notional amount of derivatives do not represent amounts that are exchanged by the parties and, thus, are not a measure of the Company's exposure.

The amounts exchanged are lated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates. The Company would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments.

The Company does not expect that counterparties to the interest rate swaps and treasury forwards will fail to meet these obligations, given their high credit ratings. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. The Company's interest-rate swaps are mented under master agreements.

Among other things, these agreements provide for a maximum credit exposure for both parties. Payments are required by the appropriate party when the maximum limit is reached. The same maximum credit exposure applies to the treasury forwards.

attrition and the early retirement and severance program. The Company expects an additional 735 positions to be ed during 1999 and 2000. The Company recorded an early retirement and tion program charge to earnings of $125 million ($74 million, net of income taxes) in the fourth quarter of 1998 to nize costs related to the CCR workforce reduction program. This charge consisted of the following:

$121 million for the actuarially determined pension and other postretirement efits costs and $4 million for outplacement services costs and the continuation of benefits for one year. Approximately

$0.8 million of the $125 million charge was related to the Company's non-utility operations and accordingly was ed in Other Income and Deductions.

All cash payments related to the early retirement and severance program are expected to be funded through the assets of the Company's Service Annuity Plan. Ventures The Company periodically reviews its investments to mine that they are properly valued in its financial statements.

Other Income and Deductions reflects write-offs of these investments of $10 million and $20 million in 1998 and 1997, respectively.

46 PECO Energy Company and Subsidiary Companies

23. Regulatory Assets and Liabilities

• At December 31, 1998 and 1997, the Company had deferred the following regulatory assets on the Consolidated Balance Shee 1998 1997 Competitive transition charge Recoverable deferred income taxes (see note 14) Deferred generation costs recoverable in current rates Loss on reacquired debt Compensated absences Deferred energy costs Non-pension postretirement benefits Total 24. Quarterly Data (Unaudited)

$ 5,274,624 614,445 77,165 4,289 29,847 90,915 $ 6,091,285 Thousands of Dollars $ 5,274,624 585,661 424,497 83,918 3,881 35,665 97,409 $ 6,505,655 The data shown below include all adjustments which the Company considers necessary for a fair presentation of such amounts: Oi:ierating Revenues Oi:ierating Income Net Income (Loss) Millions of Dollars 1998 1997 1998 1997 1998 1997 Quarter ended March 31 $* 1,173 $ 1, 163 $ 285 $ 302 $ 114 $ 113 June 30 1,207 1,032 362 250 151 123 September 30 1,774 1,278 546 388 274 158 December 31 1,056 1, 145 90 66 (26) (1,891) Earnings Applicable Average Shares Earnings to Common Stock Outstanding Per Average Share Millions of Dollars (exce t er share data) 1998 1997 1998 1997 1998 Quarter ended March 31 $ 110 $ 109 222.5 222.5 $ 0.50 $ 0.49 June 30 148 118 222.7 222.5 0.66 0.53 September 30 270 154 223.1 222.5 1.21 0.69 December 31 (28) (1,895) 224.5 222.5 (0.13) (8.51) The increase in 1998 second quarter results was primarily due to increased operating revenues net of related fuel costs. Revenues from wholesale sales increased significantly com-pared to 1997. Second quarter 1998 earnings also benefited from the full return to service of Salem which decreased the cost of fuel purchases and outage-related costs compared to 1997, from decreased operating and maintenance expense and from reduced uncollectible expenses.

The increase in 1998 third quarter results was due marily to increased operating revenues net of related fuel costs. Revenues from wholesale sales increased significantly compared to 1997. Third quarter earnings also benefited from the full return to service of Salem, reduction of operating and

• maintenance costs, reduction of uncollectible expenses and a one-time refund of gross receipts tax. The increase in the fourth quarter results was primarily due to the extraordinary charge of $8.24 per share recorded in 1997 resulting from deregulation of the Company's electric generation operations; several one-time adjustments for changes in employee benefits; write-offs of information tems development charges reflecting clarification of accounting guidelines and additional reserves to revise mates for accruals; higher income tax adjustments; and higher losses from the Company's non-utility ventures.

This increase was partially offset by an Early Retirement and Severance charge and an extraordinary charge for the ums paid in connection with the redemption of higher-cost, long-term debt recorded in the fourth quarter of 1998.

• Notes to Consolidated Financial Statements 47 --nancial Statistics Summary of Earnings and Financial Condition For the Years Ended December 31, 1998 1997 1996 1995 1994 1993 Millions of Dollars, except per share data Income Data Operating Revenues $ 5,210 $ 4,618 $ 4,284 $ 4,186 $ 4,041 $ 3,988 Operating Income 1,283 1,006 1,249 1,401 1,064 1,390 Income before Extraordinary Item 532 337 517 610 427 591 Extraordinary Item (net of income taxes) (20) (1,834) Net Income (Loss) 513 (1,497) 517 610 427 591 Earnings Applicable to Common Stock 500 (1,514) 499 587 389 542 Earnings per Average Common Share Before Extraordinary Item 2.33 1.44 2.24 2.64 1.76 2.45 Extraordinary Item (0.09) (8.24) Earnings per Average Common Share 2.24 (6.80) 2.24 2.64 1.76 2.45 Dividends per Common Share 1.00 1.80 1.755 1.65 1.545 1.43 Common Stock Equity 13.61 12.25 20.88 20.40 19.41 19.25 Average Shares of Common Stock Outstanding (Millions) 223.2 222.5 222.5 221.9 221.6 221.1 At December 31, Balance Sheet Data Net Utility Plant $ 4,610 $ 4,495 $ 10,760 $ 10,758 $ 10,829 $ 10,763 Leased Property, net 154 176 182 181 174 194 Total Current Assets 569 1,003 420 426 427 515 Total Deferred Debits and Other Assets 6,715 6,683 3,899 3,944 3,992 3,905 Total Assets $ 12,048 $ 12,357 $ 15,261 $ 15,309 $ 15,422 $ 15,377 Common Shareholders' Equity $ 3,057 $ 2,727 $ 4,646 $ 4,531 $ 4,303 $ 4,263 Preferred and Preference Stock Without Mandatory Redemption 137 137 199 199 277 423 With Mandatory Redemption 93 93 93 93 93 187 Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership 349 352 302 302 221 Long-Term Debt 2,920 3,853 3,936 4,199 4,786 4,884 Total Capitalization 6,556 7, 162 9,176 9,324 9,680 9,757 Total Current Liabilities 1,735 1,619 1, 103 1,052 850 954 Total Deferred Credits and Other Liabilities 3,757 3,576 4,982 4,933 4,892 4,666 Total Capitalization and Liabilities

$ 12,048 $ 12,357 $ 15,261 $ 15,309 $ 15,422 $ 15,377

• 48 PECO Energy Company and Subsidiary Companies Operating Statistics For the Years Ended December 31, 1998 1997 1996 1995 1994 1993 Electric Operations

• Output (Millions of Ki/owatthours)

Fossil 10,262 9,659 10,856 10,792 11,239 10,352 Nuclear 29,732 25,853 24,373 25,499 28, 195 27,026 Hydro 1,715 1,558 2,404 1,425 1,970 1,699 Pumped storage output 1,426 1,403 1,540 1,741 1,596 1,478 Pumped storage input (1,853) (1,924) (2,230) (2,507) (2,256) (2,192) Purchase and interchange 34,075 29,615 19,539 13,945 6, 164 6,447 Internal combustion 176 144 179 175 106 56 Total electric output 75,533 66,308 56,661 51,070 47,014 44,866 Sales (Millions of Kilowatthours)

Residential 10,623 10,407 10,671 10,636 10,859 10,609 Small commercial and industrial 6,888 6,685 6,491 6,200 6,150 5,769 Large commercial and industrial 15,678 15,034 15,208 15,763 15,968 15,956 Other 803 841 902 860 791 771 Unbilled 131 70 (327) 535 (205) 31 Service territory 34,123 33,037 32,945 33,994 33,563 33, 136 Interchange sales 3,483 1,927 935 496 768 457 Sales to other utilities 37,258 28,893 20,243 14,041 10,039 8,670 Total electric sales 74,864 63,857 54, 123 48,531 44,370 42,263 Number of Customers, December 31, Residential 1,343,791 1,333,861 1,324,448 1,321,379 1,350,210 1,341,873 Small commercial and industrial 145,055 144, 142 142,431 141,653 143,605 142,363 Large commercial and industrial 3,248 3,308 3,299 3,394 3,603 3,742 Other 1,150 1,094 1,051 959 944 888 Total electric customers 1,493,244 1,482,405 1,471,229 1,467,385 1,498,362 1,488,86 Operating Revenues (Millions of Dollars) Residential

$ 1,377 $ 1,357 $ 1,370 $ 1,379 $ 1,371 $ 1,351 Small commercial and industrial 784 779 749 730 710 679 Large commercial and industrial 1,067 1,077 1,098 1, 135 1, 149 1, 168 Other 150 148 140 137 136 161 Unbilled 1 19 (26) 43 (11) (1) Service territory 3,379 3,380 3,331 3,424 3,355 3,358 Interchange sales 211 59 26 17 23 14 Sales to other utilities 1,221 728 498 334 247 233 Total electric revenues $ 4,811 $ 4,167 $ 3,855 $ 3,775 $ 3,625 $ 3,605 Operating Expenses Operating expenses, excluding depreciation and amortization

$ 2,993 $ 2,698 $ 2,244 $ 2,026 $ 2,209 $ 1,894 Depreciation and amortization 611 553 462 431 416 401 Total operating expenses 3,604 3,251 2,706 2,457 2,625 2,295 Electric Operating Income $ 1,207 $ 916 $ 1, 149 $ 1,318 $ 1,000 $ 1,310 Average Use per Residential Customer (KilowatthoursJ Without electric heating 6,948 6,695 6,771 6,908 6,736 6,727 With electric heating 15,398 16,400 17,946 17, 189 17,527 17,096 All customers 7,935 7,830 8,074 8,130 8,041 7,970 Electric Peak Load, Demand (Thousands of Kilowatts) 7,108 7,390 6,509 7,244 7,227 7,10. Net Electric Generating Capacity-Year-end Summer Rating (Thousands of Kilowatts) 9,262 9,204 9,201 9,078 8,956 8,877 Cost of Fuel per Million BTU $ 0.82 $ 0.84 $ 0.93 $ 0.87 $ 0.89 $ 0.90 BTU per Net Kilowatthour Generated 10,496 10,737 10,682 10,705 11,617 10,675 Notes to Consolidated Financial Statements 49 Operating Statistics (continued)

For the Years Ended December 31, 1998 1997 1996 1995 1994 1993 .as Operations ales (Millions of Cubic Feet) Residential 1,496 1,614 1,681 1,516 1,636 1,637 House heating 28,402 32,666 35.471 30,698 32,246 30,242 Commercial and industrial 16,757 19,830 20,999 18.464 19,762 18,635 Other 554 673 2,571 1,582 7,039 9,733 Unbilled (440) 212 (1,306) 1,710 (474) 676 Total gas sales 46,769 54,995 59,416 53,970 60,209 60,923 Gas transported for customers 28,204 30,412 27,891 48,531 29,801 22,946 Total gas sales and gas transported 74,973 85,407 87,307 102,501 90,010 83,869 Number of Customers Residential 55,417 55,592 56,003 56,533 57, 122 59,573 House heating 324,081 314,335 303,996 295.481 287.481 277,500 Commercial and industrial 35,931 35,215 34, 182 33,308 32,292 31,573 Total gas customers 415,429 405,142 394, 181 385,322 376,895 368,646 Operating Revenues (Millions of Dollars) Residential

$ 16 $ 17 $ 16 $ 15 $ 16 $ 15 House heating 236 265 249 236 238 202 Commercial and industrial 125 145 133 126 128 110 Other 2 3 11 5 20 28 Unbilled (3) (1) (4) 7 (3) 5 Subtotal 376 429 405 389 399 360 Other revenues (including gas transported for customers) 24 22 24 22 17 23 Total gas revenues $ 400 $ 451 $ 429 $ 411 $ 416 $ 383 perating Expenses Operating expenses, excluding depreciation and amortization

$ 291 $ 333 $ 302 $ 302 $ 326 $ 279 Depreciation and amortization 32 28 27 26 26 24 Total operating expenses 323 361 329 328 352 303 Gas Operating Income $ 77 $ 90 $ 100 $ 83 $ 64 $ 80 Securities Statistics Ratings on PECO Energy Company's securities Mortgage Bonds Preferred Stock Date Date Agency Rating Established Rating Established Duff and Phelps, Inc. A-10/98 BBB 10/98 Fitch Investors Service, Inc. A-9/92 BBB+ 9/92 Moody's Investors Service Baa1 4/92 baa2 4/92 Standard & Poor's Corporation BBB+ 4/92 BBB-2/99 NYSE-Composite Common Stock Prices, Earnings and Dividends by Quarter (Per Share) 1998 1997 Fourth Third Second First Fourth Third Second First Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter $42-3/16 $ 36-3/4 $ 30-5/8 $24-11/16

$ 25-1/8 $24-5/16 $ 21-1/8 $ 26-3/8 w price $ 36-1/2 $ 28-1/2 $21-3/16 $ 18-7/8 $21-7/16 $ 20-3/4 $ 18-3/4 $ 20 ose $ 41-3/4 $ 36-3/4 $29-3/16 $ 22-1/8 $ 24-1/4 $23-7/16 $ 21 $ 20-3/8 Earnings $ (0.13) $ 1.21 $ 0.66 $ 0.50 $ (8.51) $ 0.69 $ 0.53 $ 0.49 Dividends

$ 0.25 $ 0.25 $ 0.25 $ 0.25 $ 0.45 $ 0.45 $ 0.45 $ 0.45 50 Board of Directors Susan W. Catherwood (55) Chairman, Trustee Board, The University of Pennsylvania Medical Center and Health System Daniel L. Cooper (63) Former Vice President and General Manager, Nuclear Services Division Gilbert/Commonwealth, Inc. M. Walter D'Alessio (65) President and Chief Executive Officer, Legg Mason Real Estate Services (Commercial mortgage banking and pension fund advisors)

G. Fred DiBona, Jr. (47)(1) President and Chief Executive Officer, Independence Blue Cross R. Keith Elliott (56) Chairman, Chief Executive Officer, Hercules, Inc. Richard H. Glanton (52)(1) Partner of the law firm Reed Smith Shaw and McClay Rosemarie B. Greco (52)(2) Former President and Chief Executive Officer, .Private Industry Council Corbin A. McNeil!, Jr. (59)(1> Chairman of the Board President and Chief Executive Officer of the Company John M. Palms, PhD. (63) President, University of South Carolina Joseph F. Paquette, Jr. (64)(1) Former Chairman of the Board of Directors of the Company Ronald Rubin (67) Chief Executive Officer, Pennsylvania Real Estate Investment Trust Robert Subin (60) Former Senior Vice President, Campbell Soup Company Officers Corbin A. McNeil!, Jr. (59) Chairman of the Board of Directors President and Chief Executive Officer Gerald R. Rainey (49)(9) President and Chief Nuclear Officer, PECO Nuclear Nancy J. Bessey (45)(6) President, Power Team Gregory A. Cucchi (49)(10) Senior Vice President, Corporate and President, PECO Energy Ventures James W. Durham (61) Senior Vice President and General Counsel Michael J. Egan (45) Senior Vice President, Finance and Chief Financial Officer Kenneth G. Lawrence (51)(10) Senior Vice President, Corporate and President, PECO Energy Distribution William H. Smith, Ill (50) Senior Vice President, Business Services Group David W. Woods (41)(14) Senior Vice President, Corporate and Public Affairs PECO Energy Company and Subsidiary Companies John B. Cotton (53)(11) Special Projects, PECO Nuclear John Doering, Jr. (55)(4) Vice President, Peach Bottom Atomic Power Station Gregory P. Dudkin (41)(6) Vice President, Operations, PECO Energy Distribution Drew B. Fetters (47)(10) Vice President, Nuclear Development, PECO Nuclear Jean H. Gibson (42)(8) Vice President and Controller Joseph J. Hagan (48)(16) Senior Vice President, Nuclear Operations, PECO Nuclear Paul E. Haviland (44)(5) Vice President, Corporate Development Thomas P. Hill, Jr. (50)(7) Vice President, Regulatory and External Affairs, PECO Energy Distribution Christine A. Jacobs (46)(13) Vice President, Support Services Suzanne L. Keenan (34)(6) Vice President, Customer & Marketing Services, PECO Energy Distribution Cassandra A. Matthews (48) Vice President, Information Technology and Chief Information Officer John P. McElwain (48)(15) Vice President, Nuclear Projects, PECO Nuclear J. Barry Mitchell (51) Vice President, Treasury and Evaluation, and Treasurer James A. Muntz (41)(16) Vice President, Fossil Operations James D. von Suskil (52)(3) Vice President, Limerick Generating Station, PECO Nuclear Richard G. White (40)(12) Vice President, Corporate Planning Katherine K. Combs (48) Corporate Secretary Edward J. Cullen, Jr. (51) Assistant Corporate Secretary Todd D. Cutler (38) Assistant Corporate Secretary Diana Moy Kelly (44) Assistant Treasurer George R. Shicora (52) Assistant Treasurer and Cash Manager (1) Member of the Executive Committee of the Board of Directors (2) Elected February 23, 1998 (3) Effective January 26, 1998 (4) Effective March 2, 1998 (5) Effective March 4, 1998 (6) Effective April 8, 1998 (7) Effective April 9, 1998 (8) *Effective May 31, 1998 (9) Effective June 1, 1998 * (10) Effective June 22, 1998 (11) Effective August 14, 1998 (12) Effective September 28, 1998 (13) Effective November 9, 1998 (14) Effective December 1, 1998 (15) Effective January 6, 1999, no longer an officer of PECO Energy (16) Effective January 26, 1999 11 . ! Shareholder Information Stock Exchange Listings Most Company securities are listed on the New York Stock Exchange and the Philadelphia Stock Exchange under PE. Dividends The Company has paid dividends on its common stock tinually since 1902. The Board of Directors normally considers common stock dividends for payment in March, June, September and December.

The Company expects that the $1.00 per share dividend paid to common shareholders in 1998 is fully taxable as dividend income for federal income tax* purposes.

Shareholders may use .their dividends to purchase additional shares of common stock through the Company's Dividend Reinvestment and Stock Purchase Plan (Plan). The Company pays all brokerage and service fees for Plan purchases.

All shareholders have the opportunity to invest additional funds in common stock of the Company, whether or not they have their dividends reinvested, with all purchasing fees paid by e Company. In 1998, over 57 percent of the Company's common holders were participants in the Plan. Information concerning the Plan may be obtained from: EquiServe, PECO Energy Company Plan, P.O. Box 2598, Jersey City, NJ 07303-2598.

Comments Welcomed The Company is always pleased to answer questions and provide information.

Please address your comments to Katherine K. Combs, Corporate Secretary, PECO Energy Company, 2301 Market Street, P.O. Box 8699, Philadelphia, PA 19101-8699.

Inquiries relating to shareholder accounting records, stock transfer and change of address should be directed to: EquiServe, P.O. Box 2500, Jersey City, NJ 07303-2500.

Toll-Free Telephone Lines Toll-free telephone lines are available to the Company's holders for inquiries concerning their stock ownership.

Calls should be directed to 1-800-626-8729.

For current Company news call 1-888-340-7326 Annual Meeting The Annual Meeting of the Shareholders of the Company will be held at the Sunnybrook Ballroom and Conference Center in Pottstown, Pennsylvania on April 27, 1999, at 9:30 AM. The record date for voting at the shareholders' meeting is March 5, 1999. Prompt return of proxies will be appreciated.

To vote your proxy over the internet visit http://www.vote-by-net.com To receive future Annual Reports and proxy statements electronically, sign-up at: http://www.

vote-by-net.

com/sign u p/peco Form 10-K Form 10-K, the annual report filed with the Securities and Exchange Commission, is available without charge to holders by calling 1-888-340-7326 or by obtaining a copy from our internet site http://www/peco.com/investor.

Shareholders The Company had 142, 794 shareholders of record of common stock as of December 31, 1998. Transfer Agents and Registrars Preferred and Common Stock Registrar and Transfer Agent: First Chicago Trust, Division of EquiServe, (1-800-626-8729)

P.O. Box 2500, Jersey City, NJ 07303-2500 First and Refunding Mortgage Bond Trustee: First Union National Bank, Corporate Trust Operations Customer Information Center Redemption Bldg 3C3 1525 West WT. Harris Blvd.Charlotte, NC 28288-1153 Internet Site Visit our internet site at http://www.peco.com General Office 2301 Market Street Philadelphia, Pennsylvania 19103 (215) 841-4000 ITT]@Q)

• UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-K IX) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 OR 0 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-1405 DELMARVA POWER & LIGHT COMPANY (Exact name of registrant as specified in its charter) Delaware & Virginia (States or other jurisdictions of incorporation or organization) 51-0084283 (I.R.S. Employer Identification No.) 800 King Street, P. 0. Box 231 Wilmington, Delaware 19899 (Address of principal executive offices) Registrant's telephone number (302) 429-3114 Securities registered pursuant to Section 12(b) of the Act: Title of each class First Mortgage Bonds (Series issued prior to 1968) Preferred Stock, Cumulative, Par Value $100.00 (Series issued prior to 1978) 8.125% Cumulative Trust Preferred Capital Securities of Delmarva Financing I (Liquidation Value of $25.00) Name of each exchange on which registered New York Stock Exchange and Philadelphia Stock Exchange Philadelphia Stock Exchange New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 121 No D Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this

• Form 10-K 121 All 1,000 issued and outstanding shares of Delmarva Power & Light Company common stock, $2.25 per share par value, are owned by Conectiv.

• Glossary PART I TABLE OF CONTENTS Page iii Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-1 Competition and Electric Utility Industry Restructuring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-2 Electric Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-2 Installed Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-2 Electricity Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-3 Pennsylvania-New Jersey-Maryland Interconnection Association . . . . . . . . . . . . . . . . . . . . . .

I-3 Purchased Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-4 Nuclear Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-4 Fuel Supply for Electric Generation

.....................

• . . . . . . . . . . . . . . . . . . . . . .

I-5 Coal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-5 Oil.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-5 Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-5 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-6 Electric Regulatory Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-6 Electric Retail Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-6 Electric Energy Adjustment Clauses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-7 Gas Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-7 Deregulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-7 Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-8 Gas Regulatory Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-8 Other Regulatory Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-8 Special Contract Rate Tariffs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-8 Cost Accounting Manual/Code of Conduct . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-8 Virginia Affiliates Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-9 Federal Decontamination

& Decommissioning Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-9 Capital Spending and Financing Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-9 Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-9 Air Quality Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-10 Water Quality Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-10 Hazardous Substances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-11 Executive Officers ..........................................

• . . . . . . . . . . . . . . . . . .

I-12 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-13 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-14 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-14 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . .

II-1 Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

II-2 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. . . II-3 Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

II-14 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . II-41 PART ID Item 10. Directors and Executive Officers of the Registrant

............................... . Item 11. Executive Compensation

.................................................. . III-1 III-2 Item 12. Item 13. PART IV Security Ownership of Certain Beneficial Owners and Management

.................. . Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page III-12 III-12 Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. . . . . . . . . . . . . . . . . . .

IV-1 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

IV-6 ii * *

• GLOSSARY The following glossary lists the abbreviations used in this report. Term 1992 Energy Act ....................... . ACE ................................ . AFUDC .............................. . Atlantic .............................. . APB ................................ . Bcf ................................. . CAM ....... * ......................... . CRP ................................. . Clean Water Act. ....................... . Debentures

............................ . D&DFund ............................ . DNREC .............................. . DOE ................................ . DPL ................................. . DPSC ................................ . DRIP ................................ . EITF ................................ . FASB ............................... . FERC ............................... . GAAP ............................... . HVAC ............................... . kWh ................................ . Litigation Reform Act . . . . . . . . . . . . . . . . . . . . .

LLRW ............................... . LMP ................................ . LTIP ................................ . Mcf ................................. . Merger ............................... . Mortgage ............................. . MPSC ............................... . MW ......................

-........... . MWH ********************************

NERC ............................... . NJPDES ............................. . NOTR ............................... . NOx ................................ . NPDES .............................. . NRC ................................ . NWPA ............................... . ODEC ............................... . Peach Bottom .......................... . PECO ............................... . PJM Interconnection

..................... . pppp ................................ . Definition National Energy Policy Act of 1992 Atlantic City Electric Company Allowance For Funds Used During Construction Atlantic Energy, Inc. Accounting Principles Board Billion Cubic Feet Cost Accounting Manual Conectiv Resource Partners, Inc. Federal Water Pollution Control Act 8.125% Junior Subordinated Debentures Decontamination

& Decommissioning Fund Delaware Department of Natural Resources and Environmental Control United States Department of Energy Delmarva Power & Light Company Delaware Public Service Commission Dividend Reinvestment and Common Share Purchase Plan Emerging Issues Task Force Financial Accounting Standards Board Federal Energy Regulatory Commission Generally Accepted Accounting Principles Heating, ventilation, and air conditioning Kilowatt-hour The Private Securities Litigation Reform Act of 1995 Low Level Radioactive Waste Locational Marginal Pricing Long-Term Incentive Plan Thousand Cubic Feet A series of merger transactions by which DPL and ACE became subsidiaries of Conectiv Mortgage and Deed of Trust Maryland Public Service Commission Megawatt Megawatt-hour North American Electric Reliability Council New Jersey Pollution Discharge Elimination System Northeast Ozone Transport Region Oxides of Nitrogen National Pollution Discharge Elimination System Nuclear Regulatory Commission Nuclear Waste Policy Act of 1982 Old Dominion Electric Cooperative Peach Bottom Atomic Power Station PECO Energy Company Pennsylvania-New Jersey-Maryland Interconnection Association Power Plant Performance Program iii Term PSE&G .............................. . PUHCA .............................. . RACT ............................... . RTP ................................. . Salem ..........................

.....

• SALP ................................ . SEC ................................. . SFAS ................................ . SFAS No. 71 SFAS No. 88 SFAS No. 128 SFAS No. 131 SFAS No. 133 S0 2 *********************************

USEPA .............................. . Vienna ............................... . VRDB ............................... . vscc ............................... . Westinghouse

.......................... . Definition Public Service Electric and Gas Company Public Utility Holding Company Act of 1935 Reasonably Available Control Technology Real Time Pricing Salem Nuclear Generating Station Systematic Assessment of Licensee Performance Securities and Exchange Commission Statement of Financial Accounting Standards SFAS No. 71, "Accounting For the Effects of Certain Types of Regulation

SFAS No. 88, "Employers' Accounting For Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits

SFAS No. 128, "Earnings Per Share" SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information

SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" Sulfur Dioxide United States Environmental Protection Agency Vienna Generating Station Variable Rate Demand Bonds Virginia State Corporation Commission Westinghouse Electric Corporation iv * *

• PART I

• Item 1. Business General Delmarva Power & Light Company (DPL) is a regulated public electric and gas utility and a subsidiary of Conectiv, which is a Delaware corporation and a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). DPL was incorporated in Delaware in 1909 and in Virginia in 1979 and holds the franchises necessary to provide regulated electric and gas service in its service territory.

DPL's electric utility business activities are primarily generating, purchasing, delivering, and selling electricity.

DPL serves approximately 455,300 electric customers within its service territory, which has a population of approximately

1.2 million

and covers an area of about 6,000 square miles on the Delmarva Peninsula, which includes Delaware, ten primarily Eastern Shore counties in Maryland, and the Eastern Shore of Virginia.

DPL also sells electricity outside its service territory (off-system) and in markets that are not subject to price regulation.

\ DPL provides regulated gas service (supply and/or transportation) to approximately 105,700 customers located in a service territory, which has a population of approximately 485,000 and covers an area of about 275 square miles in northern Delaware, including the City of Wilmington.

DPL also sells gas off-system and in markets which are not subject to price regulation.

In 1998, DPL's sources of revenues were as follows: regulated electricity sales-55.5%;

non-regulated electricity sales-14.5%;

regulated gas sales-5.6%;

non-regulated gas sales-22.5%;

and other services-1.9%.

DPL' s utility business is subject to regulation with respect to its retail electric sales by the Delaware Public Service Commission (DPSC), Maryland Public Service Commission (MPSC), and the Virginia State Corporation Commission (VSCC). The Federal Energy Regulatory Commission (FERC) also has regulatory authority over certain aspects of DPL's electric utility business, including the transmission of electricity, the sale of electricity to municipalities and electric cooperatives, and interchange and other purchases and sales of electricity involving other utilities.

DPL is also subject to regulation by the Pennsylvania Public Utility Commission in limited respects concerning property and operations in Pennsylvania.

On March 1, 1998, DPL and Atlantic City Electric Company (ACE) became wholly-owned subsidiaries of Conectiv. Before the Merger, Atlantic Energy, Inc. (Atlantic) owned ACE, an electric utility serving the southern one-third of New Jersey, and nonutility subsidiaries.

As a result of the Merger, Atlantic no longer exists and Conectiv owns, directly or indirectly, DPL, ACE, and nonutility subsidiaries formerly held separately by DPL and Atlantic.

DPL's former nonutility subsidiaries included Conectiv Services, Inc. (heating, ventilation, and air conditioning construction and services), Conectiv Communications, Inc. (local and long-distance phone service), and Delmarva Capital Investments, Inc. (various nonutility businesses).

Conectiv is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA), which imposes certain restrictions on the operations of registered holding companies and their subsidiaries.

At December 31, 1998, DPL had 1,259 employees, of which 988 were represented by collective bargaining labor organizations.

During 1998, DPL reduced its workforce by 1,461 employees, including 421 employees separated through Merger-related employee separation programs and 1,040 employees transferred to Conectiv Resource Partners, Inc. (CRP), a Conectiv subsidiary and service company established pursuant to PUHCA regulations.

CRP provides a variety of support services to Conectiv subsidiaries, and its employees are primarily former DPL and ACE employees.

The costs of CRP are directly assigned, distributed and allocated to the Conectiv subsidiaries using CRP's services, including DPL.

• For additional information about the Merger, refer to Note 4 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part II. I-1 For information concerning DPL's business segments, see Note 21 to DPL's 1998 Consolidated Financial

• Statements included in Item 8 of Part II. Competition and Electric Utility Industry Restructuring For information concerning restructuring the electric utility industry in Delaware, Maryland, and Virginia, see Note 6 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part IL Generally, with restructuring, the supply component of the price charged to a customer for electricity will be deregulated, and electricity suppliers will compete to supply electricity to customers.

Customers will continue to pay the local utility a regulated price for delivery of electricity over the transmission and distribution system. As electric utility industry restructuring is implemented in DPL's and other utilities' service territories, gross margins earned from supplying electricity are expected to decrease as competition to supply customers with electricity increases.

Delaware legislation is expected to be enacted which would begin phasing-in choice of electricity suppliers to customers beginning October 1, 1999. In Maryland, competition to supply electric customers is expected to be phased in beginning July 3, 2000, over a 3-year period. In Virginia, retail electric competition is expected to be phased-in beginning January 1, 2002. As a greater percentage of DPL's revenues become subject to competition, financial risks and rewards, and the volatility of earnings are expected to increase.

DPL's ability to continue reducing costs by streamlining operations, regulatory decisions pursuant to restructurings, retention of existing customers and the ability to gain new customers are significant determinants of DPL's future success. Electric Business Installed Capacity The megawatts (MW) of net installed summer electric generating capacity available to DPL to serve its peak load as of December 31, 1998, are presented below. See Item 2, Properties, for additional information.

% of Source of Capacity MW Total Coal-fired generating units .................................... . 1,153 33 Oil-fired generating units ..................................... . 598 17 Combustion turbines/combined cycle generating units ................ . 674 19 Nuclear generating units ...................................... . 328 9 Diesel units ............................................... . 23 Long-term purchased capacity .................................. . 237 7 Customer-owned capacity ..................................... . 57 2 Subtotal .............................................. . 3,070 87 Short-term purchased capacity ................................. . 449 13 Total ................................................ . 3,519 100 The net generating capacity available for operations at any time may be less than the total net installed generating capacity due to generating units being out of service for inspection, maintenance, repairs, or unforeseen circumstances.

As restructuring of the electric utility industry is implemented, DPL expects to sell some of its generating units. DPL has identified certain generating assets that may be sold, but has not determined when such sale, or sales, would occur. DPL also has demand-side management programs which provide DPL with the ability to reduce its peak. load by approximately 272 MW. I-2 Electricity Supply As a member of the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM tion), DPL is obligated to maintain capacity levels based on its allocated share of estimated aggregate PJM Interconnection capacity requirements. (The PJM Interconnection is discussed below.) DPL periodically updates its forecast of peak demand and PJM Interconnection reserve requirements, and re-evaluates resources available to supply projeded growth. Any short-term capacity deficiencies related to obligations to the PJM tion are expected to be satisfied through short-term capacity-only purchases.

Incremental energy supply needs are expected to be filled through purchased power. DPL's peak load in 1998 was 3,085 MW on July 23, an 8.0% increase from DPL's previous historical peak demand of 2,857 MW which occurred on July 15, 1997. DPL's capacity obligation to the PJM Interconnection, including a reserve margin, is based on normal weather conditions and full implementation of its demand-side management programs.

Under these cop.ditions, DPL's 1998 peak demand would have been approximately 2,952 MW. DPL's installed capacity of 3,481 MW at the time of the peak resulted in a reserve margin of 18%, computed under PJM Interconnection guidelines.

DPL's reserve obligation to the PJM Interconnection is approximately 18%. The sources of electricity supplied to DPL's customers in its service territory during 1998, 1997, and 1996 are shown below. Source of Electricity Generation fuel type Coal .............................................. . Oil/Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Nuclear ........................................... . Interchange and Purchased Power ............................ . Total .............................................. . Pennsylvania-New Jersey-Maryland Interconnection Association 1998 1997 1996 34% 18 16 32 35% 20 10 35 38% 29 9 24 100% 100% 100% As a member of the PJM Interconnection, DPL's generation and transmission facilities are operated on an integrated basis with other electricity suppliers in Pennsylvania, New Jersey, Maryland, and the District of Columbia, and are interconnected with other major utilities in the United States. This power pool improves the reliability and operating economies of the systems in the group and provides capital economies by permitting shared reserve requirements.

The PJM Interconnection's installed capacity as of December 31, 1998, was 57,551 MW. The PJM Interconnection's peak demand during 1998 was 48,663 MW on August 15, which resulted in a summer reserve margin of 18.2% (based on installed capacity of 57,511 MW on that date). On October 15, 1998, the PJM Interconnection began operating a centralized capacity credit market, providing a new option to participants for procuring and selling surplus capacity to meet reliability obligations within the PJM Interconnection region. Capacity is the capability to produce electric power, typically from owned generation or third-party purchase contracts and differs from the electric energy markets, which trade the actual energy being generated.

This market facilitates the selling and buying of capacity for participants by providing a single point of contact for market participants and a published capacity market clearing price.

Effective April 1, 1998, the PJM Interconnection implemented locational marginal pricing (LMP) to establish the market clearing prices for electric energy and to price electric transmission usage based upon costs associated with transmission system congestion.

When there is no congestion on the power system and energy js flowing on the grid in an unconstrained manner, energy prices are cleared at the highest bid accepted by the PJM Interconnection for the entire PJM Interconnection region. When a limit is reached on the transmission grid, the PJM Interconnection will operate generators to preserve system reliability.

LMP allows the PJM Interconnection to send price signals to raise and lower generator output when the power flows are constrained.

Different energy 1-3 market clearing prices are paid by wholesale power buyers and sellers on the power grid that reflect the value relative to a system constraint.

LMP provides for an efficient allocation of congestion costs to transmission users within the PJM InterconneCtion region. The FERC has approved the use of the LMP congestion management system to allow electric energy market participants with power contracts on neighboring electric systems to compensate the PJM Interconnection for any unintended flows on the PJM Interconnection system, rather than forcing those participants to curtail their contracts.

• Currently, the PJM Interconnection Operating Agreement requires bids to sell electricity received from generation located within the PJM Interconnection control area not to exceed the variable cost of producing such electricity.

Transactions that are bid into the PJM pool from generation located outside the PJM Interconnection control area are capped at $1,000 per megawatt hour. All power providers are paid the LMP set through power providers' bids. Certain PJM Interconnection members have requested that FERC revise the PJM Interconnection Operating Agreement to allow the submission of market based bids to the PJM Interconnection energy market. Purchased Power In conjunction with its acquisition of Conowingo Power Company in 1995, DPL purchases from PECO Energy Company (PECO) 237 MW of base-load capacity and associated energy, which increases to 279 MW by 2006 when the contract expires. DPL is also currently purchasing 105 MW of capacity under one-year contracts and 344 MW of capacity through agreements with terms of less than one year. Nuclear Power Plants DPL's nuclear capacity is provided by Peach Bottom Atomic Power Station (Peach Bottom) Units 2 and 3 and by Salem Nuclear Generating Station (Salem) Units 1 and 2. DPL jointly owns these units, as tenants in common, with PECO, ACE and Public Service Electric and Gas Company (PSE&G). The Peach Bottom units are operated by PECO and have a combined summer capacity of 2,186 MW, of which DPL is entitled to 164 MW (7.51 %). The Salem units are operated by PSE&G and have a combined summer capacity of 2,212 MW, of which DPL is entitled to 164 MW (7.41 %). DPL's ownership share in nuclear power plants provided approximately 9% of its installed capacity as of December 31, 1998. In 1998, DPL's share of output from the jointly-owned nuclear power plants provided 16% of the electricity used by DPL's customers.

See Note 9 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part II for information about DPL' s investment in jointly-owned generating stations.

The operation of nuclear generating units is regulated by the Nuclear Regulatory Commission (NRC). Such regulation requires that all aspects of plant operation be conducted in accordance with NRC safety and environmental requirements and that continuous demonstrations be made to the NRC that plant operations meet applicable requirements.

The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. As a by-product of nuclear operations, nuclear generating units produce low-level radioactive waste (LLRW). LLRW is accumulated on-site until shipped to a federally licensed permanent disposal facility.

Salem and Peach Bottom have on-site interim storage facilities with five-year storage capacities.

For a discussion of the cyde of production, use and disposal of nuclear fuel, see Nuclear

on page I-6. For a discussion of DPL's funding of its share of the estimated future cost of decommissioning the Salem and Peach Bottom nuclear reactors, see Note 8 to DPL's 1998 Consolidated Financial Statements included in Part II, Item 8. The NRC is requiring nuclear plant operators to report by July 1, 1999, that their nuclear power plants are Year 2000 ready, or will be Year 2000 ready, by January 1, 2000. PSE&G and PECO have informed DPL that they are on schedule to meet the July 1, 1999 response date and that their nuclear operations' Year 2000 programs will make Salem and Peach Bottom Year 2000 ready by January 1, 2000. I-4

• Salem Units 1 and 2 were removed from operation by PSE&G in the second quarter of 1995 due to operational problems, and maintenance and safety concerns.

Due to degradation of a significant number of tubes in the Unit 1 steam generators, PSE&G replaced the Unit 1 steam generators.

After receiving NRC authorization, PSE&G returned Unit 2 to service on August 30, 1997, and Unit 1 to service on April 17, 1998. On July 29, 1998, the NRC removed Salem from its "watch list" of troubled nuclear plants. The Salem Unit 2 steam generators will be inspected for tube degradation in upcoming outages. See Note 18 to DPL's 1998 Consolidated Financial Statements included in Part TI, Item 8, for information concerning DPL's lawsuit against Westinghouse Electric Corporation, the designer and manufacturer of the Salem steam generators, and the financial impact of the outages. Systematic Assessment of Licensee Performance (SALP) reports issued by the NRC rate licensee performance in four assessment areas: Operations, Maintenance, Engineering and Plant Support. Ratings range from a high of "1" to a low of "3." In September 1998, the NRC issued a SALP on the performance of activities at Salem for the period March 1, 1997, to August 1, 1998. Salem received a rating of 1 in Operations, a 2 in Maintenance, a 2 in Engineering, and a 1 in Plant Support. The NRC noted that the overall performance at . Salem improved, as demonstrated by a nearly event-free return of both units to operation following the extended outage. On July 17, 1997, the NRC issued a SALP report on Peach Bottom for the period October 15, 1995, to June 7, 1997. Peach Bottom received a rating of 1 in the areas of Operations, Maintenance, and Plant Support, and 2 in Engineering.

On September 16, 1998, the NRC announced that it was suspending the SALP report process until it completes a review of its nuclear power plant performance assessment process. The SALP process has not yet been resumed or replaced . Fuel Supply for Electric Generation DPL's electric generating capacity by fuel type is shown under "Installed Capacity" on page 1-2. To facilitate the purchase of adequate amounts of fuel at reasonable prices, DPL contracts with various suppliers of coal, oil, and natural gas on both a long-and short-term basis. DPL's long-term coal contracts generally contain provisions for periodic and limited price adjustments, which are based on current market prices. Oil and natural gas contracts generally are of shorter term with prices determined by market-based indices. Coal Edge Moor Units 3 and 4, and the Indian River, Keystone and Conemaugh Generating Stations.

are fired. During 1998, 47% of DPL's coal supply was purchased under contracts less than three years in duration, 48% under long-term contracts (up to ten years), and the balance on the spot market. Approximately 69% of DPL's projected coal requirements are expected to be provided under supply contracts.

DPL does not anticipate any difficulty in obtaining adequate amounts of coal at reasonable prices. Oil Currently, 100% of the residual oil used in Edge Moor Unit 5 is purchased on a spot basis. Natural gas is used when economically feasible.

A two-year residual oil supply contract that expires in 1999 provides 90% to 100% of the fuel supply requirements for the Vienna Generating Station (Vienna).

Any amount over 90% of Vienna's requirements may be purchased in the spot market. Gas Natural gas is the primary fuel for the three combustion turbines at DPL's Hay Road combustion turbines and a secondary fuel at Edge Moor Units 3, 4, and 5. Natural gas for these generating units is purchased on a 1-5 firm or interruptible basis from suppliers such as marketers, producers, and utilities.

The gas is delivered to DPL

• by interstate pipelines under a mix of firm and interruptible transportation agreements.

The secondary fuel for the Hay Road combustion turbines is low-sulfur diesel fuel, which is purchased in the spot market. Nuclear The supply of fuel for nuclear generating units involves the mining and milling of ore to uranium concentrate, conversion of the uranium concentrate to uranium hexaflouride, enrichment of the uranium hexaflouride gas, conversion of the enriched gas to fuel pellets, and fabrication of fuel assemblies.

After spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station site. The federal government has an obligation for the transportation and ultimate disposal of the spent fuel, as discussed below. PSE&G has informed DPL it has several long-term contracts with uranium ore operators, converters, enrichers and fabricators to . process uranium ore to. uranium concentrate to meet the currently projected requirements for Salem. DPL has also been advised by PECO that it has similar contracts to satisfy the fuel requirements of Peach Bottom. Currently, there is an adequate supply of nuclear fuel for Salem and Peach Bottom . . In conformity with the Nuclear Waste Policy Act of 1982 (NWPA), PSE&G and PECO have entered into contracts with the United States Department of Energy (DOE) on behalf of the joint owners providing that the federal government shall for a fee take title to, transport, and dispose of spent nuclear fuel and high level radioactive waste from the Salem and Peach Bottom reactors.

In accordance with the NWPA, DPL pays the DOE one-tenth of one cent per kWh of nuclear generation (net of station use) for the future cost of spent nuclear fuel disposal.

Under the NWPA, the DOE was to begin accepting spent fuel for permanent off-site storage no later than January 1998. However, no such repositories are in service or under construction.

The DOE has stated that it would not be able to open a permanent, high level nuclear waste storage facility until 2010, at the earliest.

Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent nuclear fuel storage installations located at or away from reactor sites for at least 30 years beyond the licensed life for operation (which may include the term of a revised or renewed license).

PSE&G has advised DPL that, as a result of reracking the two spent fuel storage pools at Salem, the availability of spent fuel storage capacity is estimated to be adequate through 2012 for Unit 1 and 2016 for Unit 2. PECO has advised DPL that spent fuel racks at Peach Bottom have adequate storage capacity until 2000 for Unit 2 and until 2001 for Unit 3. PECO has also advised DPL that it is constructing an on-site dry storage facility, which is expected to be operational in 2000, to provide additional storage capacity.

Electric Regulatory Matters For information concerning restructuring the electric utility industry in Delaware, Maryland, and Virginia, see Note 6 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part II. Electric Retail Rates DPL's base rates for retail electric service are subject to the approval of the DPSC, MPSC, and VSCC. However, the utility ratemaking process is changing in Delaware, Maryland, and Virginia, as discussed in Note 6 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part IL

• See Note 6 to DPL's 1998 Consolidated Financial Statements, included in Part II, Item 8, for information

• concerning base rate decreases related to the Merger and base rate decreases expected in connection with the electric utility industry restructuring.

I-6

• Electric Energy Adjustment Clauses DPL' s regulated retail electric tariffs include energy adjustment clauses that provide for collection from customers of fuel costs and the energy costs of purchased and net interchange power. Any under-or collection of energy adjustment clause costs in a current period is generally deferred until customers' rates are adjusted to collect or return the under-or over-collection.

Capacity costs arising from purchased power transactions are generally subject to base rate recovery.

The current status or results of significant fuel rate issues are discussed below. As of December 31, 1998, DPL's accrued liabilities included amounts which are expected to adequately provide for disallowances of energy adjustment clause costs and penalties related to the issues discussed below. Both Delaware and Maryland have programs that assess the overall performance of DPL's 15 major generating units. Under the DPSC's Power Plant Performance Program (PPPP), DPL can receive financial rewards or penalties, which will not exceed an estimated cap of $1.7 million in 1998. The 1996 and 1997 PPPP results were not material to DPL's financial position or results of operations.

If DPL does not meet an overall system performance standard set by Maryland's Generating Unit Performance Program, the MPSC can disallow certain fuel costs of units that operated.

below their individual performance standards.

DPL did not meet the 1996 or 1997 overall system standards due principally to the Salem outage. For information concerning replacement power costs not recovered through customer rates due to a prolonged outage at Salem, see Note 18 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part II. DPL's long-term purchased power agreement with PECO has previously been the subject of regulatory litigation in Delaware as the result of disallowances proposed by DPSC Staff and the Delaware Division of the Public Advocate.

No such disallowances were ordered for 1996 or 1997. Delaware's Division of the Public Advocate has proposed a total disallowance of $17.7 million for 1998 and 1999. DPL will contest the proposed disallowance.

Energy adjustment clauses are expected to be eliminated under electric industry restructuring initiatives.

Based on existing restructuring initiatives in Delaware, Maryland, and Virginia, profits or losses on the energy portion of electricity sales may affect DPL's earnings after restructuring becomes effective.

Gas Business Deregulation Effective April 1, 1996, a restructuring of natural gas pricing and service options enabled DPL's large and medium volume commercial and industrial customers to purchase gas from DPL, or directly from other suppliers and make arrangements for transporting gas purchased from these suppliers to their facilities.

DPL' s transportation customers pay a fee, which may be either fixed or negotiated, for the use of DPL's gas transmission and distribution facilities.

The restructuring mentioned above also authorized off-system gas sales and other non jurisdictional merchant sales and services.

Earnings from gas sales which are off the Delmarva Peninsula and do not use DPL's gas system assets are not shared with regulated customers through lower rates. For other off-system gas sales and nonjurisdictional merchant sales and services, 80% of the margin (revenues net of fuel costs) earned reduces energy rates charged to firm gas customers.

On December 1, 1998, DPL filed an application with the DPSC, seeking approval of a pilot program to provide transportation service and a choice of gas suppliers to a group of retail customers.

DPL proposed a year pilot program, starting November 1, 1999, open to 15% of residential customers and 15% of small commercial customers.

DPL and intervening parties are engaged in settlement discussions about the proposed pilot program. 1-7 Gas Operations DPL purchases gas supplies from marketers and producers under spot market, short-term, and long-term agreements.

As shown in the table below, DPL's maximum 24-hour system capability, including natural gas purchases, storage deliveries, and the emergency sendout capability of its peak shaving plant, is 187,074 Mcf (thousand cubic feet). Number of Expiration Daily Contracts Dates Mcf Supply .................................... . 1 2001 9,180 Transportation

.............................. . 5 2004-2016 82,810 Storage ................................... . 6 1999-2011 50,084 Local Peak Shaving (emergency capability)

..........

• 45,000 Total ................................. . 187,074 DPL experienced an all-time daily peak in combined firm sales and transportation sendout of 158,810 Mcf on January 17, 1997. DPL's peak shaving plant liquefies, stores, and re-gasifies natural gas in order to provide supplemental gas in the event of pipeline supply shortfalls or system emergencies.

Gas Regulatory Matters Similar to DPL's Delaware electric energy adjustment clause, a gas cost rate clause provides for the recovery of* gas costs from DPL' s regulated

• gas customers.

Gas costs for regulated, on-system customers are charged to operations based on costs billed to custoiners under the gas cost rate clause. Any under-or collection of gas costs in a current period is generally deferred until customers' rates are adjusted to collect or return the under-or over-collection.

In 1998, DPL implemented a DPSC-approved gas price hedging/risk management program with respect to gas supply for regulated customers.

The program seeks to limit regulated customers exposure to commodity price uncertainty.

Costs and benefits of the program are included in the gas cost rate clause, resulting in no effect on DPL's earnings.

Other Regulatory Matters Special Contract Rate Tariffs Under programs approved by the MPSC and DPSC, DPL may enter into negotiated contracts with retail electric customers in Maryland and retail electric and natural gas customers in Delaware.

Also, Real Time Pricing (RTP) tariffs are available to customers in Maryland and in Delaware, and an experimental RTP tariff is effective in Virginia.

The RTP tariffs provide additional flexibility in providing pricing and service to certain large customers.

Cost Accounting Manual/Code of Conduct

• DPL has cost *allocation and direct charging mechanisms in place to ensure that there is no subsidization of competitive activities by regulated utility activities.

In 1998, DPL made filings with the DPSC, the MPSC and VSCC to update and revise its Cost Accounting Manual (CAM) to reflect the holding company structure created in 1998. The CAM is subject to review and audit.

• DPL is also subject to various Codes of Conduct that affect the relationship between DPL's regulated and Conectiv's competitive activities.

In general, these Codes of Conduct limit information obtained through utility

• activities from being disseminated to employees engaged in non-regulated activities, require separate telephone numbers for competitive activities and restrict or prohibit sales leads, joint sales calls, or joint promotions.

1-8

• Requirements that separate operational and managerial employees be maintained, as required by the MPSC for non-regulated activities making retail sales of electricity or gas, could impact the way DPL and the Conectiv system of companies are organized and DPL's ability to capture economies of common management and deploy personnel efficiently, without duplicating personnel functions.

Prohibitions or restrictions on joint promotions may adversely impact Conectiv's competitive businesses.

Virginia Affiliates Act Certain types of transactions between DPL and its affiliates may require the prior approval qf the VSCC under the Virginia Affiliates Act. Past applications have generally been approved by the VSCC. Federal Decontamination

& Decommissioning Fund The Energy Policy Act of 1992 provided for creation of a Decontamination

& Decommissioning (D&D) Fund to pay for the future clean-up of DOE gaseous diffusion enrichment facilities.

Domestic utilities and the federal government are required to make payments to the D&D Fund until 2008 or $2.25 billion, adjusted annually for inflation, is collected.

The liability accrued for DPL's share of the D&D Fund was $5.3 million as of December 31, 1998. DPL is recovering this cost through energy adjustment clause revenues.

Capital Spending and Financing Program For financial information concerning DPL' s capital spending and financing program, refer to Liquidity and Capital Resources" in the Management's Discussion and Analysis of Financial Condition and Results of Operations, included in Item 7, of Part II and Notes 12 to 14 to DPL's 1998 Consolidated Financial Statements, included in Item 8 of Part II. DPL's ratios of earnings to fixed charges and earnings to fixed charges and preferred stock dividends under the SEC Methods for 1994-1998-are shown below. Year Ended December 31, 1998 1997 1996 1995 1994 Ratio of Earnings to Fixed Charges (SEC Method). . . . . . . . . . . . .

2.92 2.83 3.33 3.54 3.49 Ratio of Earnings to Fixed Charges and Preferred Stock Dividends (SEC Method).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.72 2.63 2.83 2.92 2.85 Under the SEC Method, earnings, including Allowance For Funds During Construction (AFUDC), have been computed by adding income taxes and fixed charges to net income. Fixed charges include gross interest expense, the estimated interest component of rentals, and dividends on preferred securities of a subsidiary trust. For the ratio of earnings to fixed charges and preferred stock dividends, preferred stock dividends represent annualized preferred stock dividend requirements multiplied by the ratio that pre-tax income bears to net income. Excluding the Merger-related pre-tax charge of $27.4 million discussed in Note 4 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part II, the 1998 ratio of earnings to fixed charges was 3.21 and the 1998 ratio of earnings to fixed charges and preferred stock dividends was 2.98. Environmental Matters DPL is subject to various federal, regional, state, and local environmental regulations, including air and water quality control, oil pollution control, solid and hazardous waste disposal, and limitation on land use. Permits are required for DPL's construction projects and the operation of existing facilities.

DPL has incurred, and expects to continue to incur, capital expenditures and operating costs because of environmental considerations and requirements.

DPL has a continuing program to assure compliance with the environmental standards adopted by various regulatory authorities.

I-9 Included in DPL's forecasted capital requirements are construction expenditures for compliance with environmental regulations, which are estimated to be $10 million in 1999. Air Quality Regulations The federal Clean Air Act requires utilities and other industries to *significantly reduce emissions of air pollutants such as sulfur dioxide (S0 2) and oxides of nitrogen (NOx)* Title IV of the Clean Air Act, the acid rain provisions, established a two-phase program which mandated reductions of S0 2 and NOx emissions from certain utility units by 1995 (Phase I) and required other utility units to begin reducing S0 2 and NOx emissions in the year 2000 (Phase II). Phase I emission reductions requirements applicable to the jointly-owned Conemaugh Power Plant have been achieved.

The remainder of DPL's wholly-and jointly-owned fossil-fuel units are expected to meet Phase II emission limits through a combination of fuel switching and S0 2 allowance trading. DPL's facilities also must comply with Title I of the Clean Air Act, the ozone nonattainment provisions, which require states to promulgate Reasonably Available Control Technology (RACT) regulations for existing sources located within ozone nonattainment areas or within the Northeast Ozone Transport Regi.on (NOTR). DPL's facilities in Delaware and Maryland are in the NOTR. To comply with RACT regulations, DPL has installed low NOx burner technology on six of its generating units. DPL's RACT compliance program has not yet received final regulatory approvals by Delaware and Maryland.

Additional "post-RACT" NOx emission regulations are being pursued by states in the NOTR. Delaware has proposed post-RACT NOx control regulations requiring attainment of summer seasonal emission reductions of up to 65% below 1990 levels by May 1999 through reduced emissions or the procurement of NOx emission allowances.

DPL's post-RACT compliance plan for its Delaware generating units includes capital expenditures of approximately

$12 million. In addition to the above requirements, summer seasonal NOx controls commensurate with reductions of up to 85% below baseline years by the year 2003 are required for areas in the NOTR, which includes Delaware.

DPL currently cannot determine the additional operating and capital costs that will be incurred to comply with these initiatives since state regulations implementing the federal requirement have not yet been promulgated.

In July 1997, the United States Environmental Protection Agency (USEPA) adopted new federal air quality standards for particulate matter and ozone. The new particulate matter standard addressed fine particulate matter. Attainment of the fine particulate matter standard may require reductions in NOx and S0 2* However, under the time schedule announced.

by the USEP A, particulate matter non-attainment areas will not be designated until 2002 and control measures to meet this standard will not be identified until 2005. Water Quality Regulations The federal Water Pollution Control Act, as amended (the Clean Water Act) provides for the imposition of effluent limitations to regulate the discharge of pollutants, including heat, into the waters of the United States. National Pollution Discharge Elimination System (NPDES) permits issued by state environmental regulatory agencies specify effluent limitations, monitoring requirements, and special conditions with which facilities discharging wastewaters must comply. To ensure that water quality is maintained, permits are issued for a term of five years and are modified as necessary to reflect requirements of new or revised regulations or changes in facility operations.

• The Clean Water Act also requires that cooling water intake structures be designed to minimize adverse environmental impact. The USEPA is required by a consent order to propose regulations in 1999 for determining

• whether cooling water intake structures represent the best technology available for minimizing adverse environmental impacts. Final action on the proposed regulations is required in 2001. I-10

• Between 1976 and 1979, DPL submitted to the Delaware Department of Natural Resources and Environmental Control (DNREC) the results of environmental impact studies which demonstrated compliance with the Clean Water Act. DNREC has required DPL to update its earlier studies to determine if the Indian River and Edge Moor power plants are still in compliance.

In addition, in 1993 DNREC promulgated increased restrictions on thermal discharges.

Studies assessing thermal water quality standards compliance will be completed in 1999 and studies assessing impacts of the cooling water intake structures will be completed in 2001. If the studies indicate an adverse environmental impact, then upgrades to the intake structures and/or environmental enhancement projects to offset adverse impacts will be required. "Impact studies would cost up to $2 million per plant. Costs for intake structure upgrades and enhancement projects would range from approximately

$1 million if little adverse impact is found, to $45 million if cooling towers are required, which DPL considers to be an unlikely potential outcome. PSE&G is implementing the 1994 New Jersey Pollution Discharge Elimination System (NJPDES) permit issued for the jointly-owned Salem facility, Which requires, among other things, water intake screen modifications and wetlands restoration.

Under the 1994 permit, PSE&G is continuing to restore wetlands and conduct the requisite management and monitoring associated with the special conditions of the 1994 permit. In 1999, PSE&G must apply to renew Salem's NJPDES permit. Hazardous Substances The nature of the electric and gas utility businesses results in the production, or handling, of various products and substances which may contain substances defined as hazardous under federal or state statutes.

The disposal of hazardous substances can result in costs to clean up facilities found to be contaminated due to past disposal practices.

Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or uncontrolled hazardous waste sites. DPL's exposure is minimized by adherence to environmental standards for DPL-owned facilities and through a waste disposal contractor screening and audit process. As of December 31, 1998, DPL's other accrued liabilities included $2 million for clean-up and other potential costs related to federal and state superfund sites. DPL does not expect such future costs to have a material effect on DPL's financial position or results of operations.

For additional information, see Note 19 to DPL's 1998 Consolidated Financial Statements included in Item 8 of Part IL I-11 Executive Officers The names, ages, and positions of all of the executive officers of DPL as of December 31, 1998, are listed below, along with their business experiences during the past five years. Officers are elected annually by Conectiv's Board of Directors.

There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was selected.

Executive Officers of DPL (As of December 31, 1998) Name, Age and Position Howard E. Cosgrove, 55 .................. . Chairman of the Board and Chief Executive Officer Meredith I. Harlacher, Jr., 56 ............... . President Barry R. Elson, 57 ........ ............. . Executive Vice President Thomas S. Shaw, 51 ..................... . Executive Vice President Barbara S. Graham, 50 ................... . Senior Vice President and Chief Financial Officer James P. Lavin, 51 ...................... . Controller and Chief Accounting Officer John C. van Roden, 49 ................... . Senior Vice President and Chief Financial Officer*

• Effective January 1999 Business Experience During Past 5 Years Elected 1998 as Chairman of the Board and Chief Executive Officer of Conectiv, Delmarva Power & Light Company, and Atlantic City Electric Company. Elected 1992 as Chairman of the Board, President and Chief Executive Officer and Director of Delmarva Power & Light Company Elected 1998 as President and Chief Operating Officer of Conectiv, and President and Chief Operating Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1993 as Senior Vice President of Atlantic Energy, Inc. Elected 1998 as Executive Vice President of Conectiv, and Executive Vice President and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1997 as Executive Vice President, Delmarva Power & Light Company. Executive Vice President, Cox Communications, Inc., Atlanta, Georgia, from 1995 to 1996. Senior Vice President, Cox Enterprises/Cox Communications, Inc., Atlanta, Georgia, from 1984 to 1995. Elected 1998 as Executive Vice President of Conectiv, and Executive Vice President and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1992 as Senior Vice President, Delmarva Power & Light Company. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv, and Senior Vice President and Chief Financial Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1994 as Senior Vice President, Treasurer and Chief Financial Officer, Delmarva Power & Light Company. Vice President and Chief Financial Officer from 1992 to 1994. Elected 1998 as Controller of Conectiv, Delmarva Power & Light Company, and Atlantic City Electric Company. Elected 1993 as Comptroller, Delmarva Power & Light Company. Elected 1998 as Senior Vice President and Chief Financial Officer, effective January 1999, of Conectiv, Delmarva Power & Light Company, and Atlantic City Electric Company. Principal, Cook and Belier, Inc. in 1998. Senior Vice President/Chief Financial Officer and Vice President/Treasurer, Lukens, Inc. from 1987 to 1998. I-12 * *

• Item 2. Properties Substantially all utility plants and properties of DPL are subject to the lien of the Mortgage under which DPL' s First Mortgage Bonds are issued. DPL's electric properties are located in Delaware, Maryland, Virginia, Pennsylvania, and New Jersey. The following table sets forth the net installed summer electric generating capacity available to DPL to serve its peak load as of December 31, 1998. Station Location Coal-Fired Edge Moor .................. . Wilmington, DE ................... . Indian River ................. . Millsboro, DE ..................... . Conemaugh

................. . New Florence, PA ................... . Keystone ................... . Shelocta, PA ...................... . Oil-Fired Edge Moor .................. . Wilmington, DE ......................

• Vienna ..................... . Vienna, MD ...................... . Combustion Turbines/Combined Cycle Hay Road ................... . Wilmington, DE ...................

Christiana . . . . . . . . . . . . . . . . . . . .

Wilmington, DE ................... . Edge Moor .................. . Wilmington, DE ................... . Madison Street ............... . Wilmington, DE ................... . West ...................... . Marshallton, DE ................... . Delaware City ................ . Delaware City, DE ................. . Indian River ................. . Millsboro, DE ..................... . Vienna ..................... . Vienna, MD ...................... . Tasley ..................... . Tasley, VA ....................... . Salem ...................... . Lower Alloways Creek Twp., NJ ....... . Nuclear Peach Bottom ................ . Peach Bottom Twp., PA ............. . Salem ...................... . Lower Alloways Creek Twp., NJ ....... . Diesel Units Crisfield

.................... . Crisfield, MD . . . . . . . . . . . . . . . . . . . . . .

Bayview .................... . Bayview, VA ..................... . Keystone ................... . Shelocta, PA ...................... . Conemaugh . . . . . . . . . . . . . . . . . .

New Florence, PA .................. . Customer-Owned Capacity . . . . . . . . .

Delaware City, DE ................. . Long-Term Capacity Purchase ........................................ . Subtotal ....................................................... . Short-Term Capacity Purchase ........................................ . Total ......................................................... . (A) DPL's portion of jointly-owned plants. Net Installed Capacity (kilowatts) 260,000 767,000 63,000(A) 63,000(A) 1,153,000 445,000 153,000 598,000 511,000 45,000 13,000 11,000 15,000 16,000 17,000 17,000 26,000 3,000(A) 674,000 164,000(A) 164,000(A) 328,000 10,000 12,000 400(A) 400(A) 22,800 57,000(B) 237,000 3,069,800 449,000 3,518,800 (B) Represents capacity owned by a refinery customer which is available to DPL to serve its peak load. DPL's electric transmission and distribution system includes 1,391 transmission poleline miles of overhead lines, 5 transmission cable miles of underground cables, 6,931 distribution poleline miles of overhead lines, and 5,540 distribution cable miles of underground cables. I-13 DPL has a liquefied natural gas plant located in Wilmington, Delaware, with a storage capacity of 3.045

• million gallons and an emergency sendout capability of 45,000 Mcf per day. DPL also owns four natural gas city gate stations at various locations in its gas service territory.

These stations have a total sendout capacity of 125,000 Mcf per day. The following table sets forth DPL's gas pipeline miles: Transmission Mains . . . . . . . . . . . . . . . . . . . . . .

Distribution Mains . . . . . . . . . . . . . . . . . . . . . . .

Service Lines .......................... . 114* 1,492 1,104

• Includes 11 miles of joint-use gas pipeline that is used 10% for gas operations and 90% for electric operations.

DPL owns and occupies office buildings in Wilmington and Christiana, Delaware and Salisbury, Maryland, and also owns elsewhere in its service area a number of properties that are used for office, service, and other purposes.

Item 3. Legal Proceedings See Note 18 to DPL's 1998 Consolidated Financial Statements included in Part II, Item 8 for information concerning DPL's lawsuit against Westinghouse Electric Corporation, the designer and manufacturer of the Salem steam generators.

Item 4. Submission of Matters to a Vote of Security Holders No matter was submitted during the fourth quarter of the fiscal year covered by this report to a vote of security holders, through the solicitation of proxies or otherwise.

I-14

• DELMARVA POWER & LIGHT COMPANY PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters All shares of DPL's cnm_morr stock are owned by Conectiv; its-parent

(;umpany.

DPL's certificate of incorporation requires payment of all preferred dividends in arrears (if any) prior to payment of common dividends to Conectiv, and has certain other limitations on the payment of common dividends.

II-I DELMARVA POWER & LIGHT COMPANY Item 6. Selected Financial Data Year Ended December 31, 1998(1) 1997 1996 1995 1994 (Dollars in Thousands, Except Per Share Amounts) Operating Results and Data Operating Revenues ............

$ 1,899,899

$ 1,415,367

$ 1,168,664

$ 1,055,725

$ 1,033,442 Operating Income .............

$ 265,427 (2) $ 226,294 $ 250,389 $ 254,425 $ 233,244 (3) Net Income ..................

$ 112,410 (2) $ 105,709 $ 116,187 $ 117,488 $ 108,310 (3) Earnings Applicable to Common Stock .....................

$ 108,058 (2) $ 101,218 $ 107,251 $ 107,546 $ 98,940 (3) On System Electric Sales (kWh 000) (4) ..............

13,429,102 13,231,766 12,925,716 12,310,921 12,505,082 On System Gas Sold and Transported (Mcf 000) ........ 21,587 22,855 22,424 21,371 20,342 Capitalization Variable Rate Demand Bonds (VRDB) (5) ................

$ 71,500 $ 71,500 $ 85,000 $ 86,500 $ 71,500 Long-Term Debt ..............

951,911 983,672 904,033 853,904 774,558 DPL Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely DPL Debentures

....... 70,000 70,000 70,000 Preferred Stock ...............

89,703 89,703 89,703 168,085 168,085 Common Stockholder's Equity .... 851,494 954,496 934,913 923,440 884,169 Total Capitalization with VRDB ... $ 2,034,608

$ 2,169,371

$ 2,083,649

$ 2,031,929

$ 1,898,312 Other Information Total Assets .................

$ 2,904,851

$ 3,015,481

$ 2,931,855

$ 2,866,685

$ 2,669,785 Long-Term Capital Lease Obligations

................

$ 17,003 $ 19,877 $ 20,552 $ 20,768 $ 19,660 Capital Expenditures

...........

$ 114,663 $ 156,808 $ 165,595 $ 142,833 $ 166,938 Common Dividends Declared (6) .. $ 94,860 $ 94,065 $ 93,294 $ 92,686 $ 91,436 (1) As discussed in Note 4 to the Consolidated Financial Statements, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) became wholly-owned subsidiaries of Conectiv (the Merger) on March 1, 1998. The Merger also resulted in Conectiv owning the nonutility subsidiaries previously owned by DPL. Accordingly, the 1998 Consolidated Statement of Income includes 2 months of operating results for DPL's former nonutility subsidiaries.

(2) Employee separation and other Merger-related costs in 1998 decreased operating income and net income by $27.4 million and $16.6 million, respectively.

(3) An early retirement offer in 1994 decreased operating income and net income by $17.5 million and $10.7 million, respectively.

(4) Excludes interchange deliveries.

(5) Although Variable Rate Demand Bonds are classified as current liabilities, DPL intends to use the bonds as a source of long-term financing as discussed in Note 14 to the Consolidated Financial Statements.

(6) Amounts shown as total, rather than on a per-share basis, since DPL is a wholly-owned subsidiary of Conectiv.

Excludes non-cash dividend for transfer of nonutility subsidiaries to Conectiv on March 1, 1998, due to the Merger. II-2 I I _J DELMARVA POWER & LIGHT COMPANY Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Merger with Atlantic On March 1, 1998, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) became wholly-owned subsidiaries of Conectiv, a registered holding company under the Public Utility Holding Company of 1935. Each outstanding share of DPL's common stock was exchanged for one share of Conectiv's common stock. Conectiv became the owner of DPL's nonutility subsidiaries as of March 1, 1998, resulting in inclusion of two months of nonutility subsidiary operations in DPL's 1998 Consolidated Statement of Income. The Consolidated Statements of Income include revenues of $19.5 million and $113.0 million, and a net loss of $3.5 million and net income of $9.8 million, for 1998 and 1997, respectively, from the operations of these noriutility subsidiaries.

The common stockholder's equity of these nonutility subsidiaries was $123.4 million as of February 28, 1998. DPL continued to sell electricity and gas in markets not subject to price regulation subsequent to the Merger. See Note 4 to the Consolidated Financial Statements for additional information concerning the Merger. Earnings Results Summary DPL had earnings applicable to common stock of $108.1 million and $101.2 million for 1998 and 1997, respectively.

The $6.9 million earnings increase was reduced by a $16.6 million after-tax charge for costs associated with the Merger and a $13.3 million decrease in nonutility subsidiary earnings.

In 1997, nonutility subsidiary earnings included a $13.7 million gain on the sale of a landfill and waste-hauling company. Excluding the one-time Mergei,-costs and operating results of the nonutility subsidiaries, earnings were up $36.8 million in 1998. This incre.ase was primarily due to a 2.5% retail electric kilowatt-hour (kWh) sales increase and lower operation and maintenance expenses.

The earnings increase was constrained by milder winter weather's unfavorable effect on electric and gas sales. Earnings applicable to common stock, for 1997, were $101.2 million, a $6.1 million decrease from 1996. The $6.1 million decrease was primarily attributed to losses from investments in new businesses and participation in the competitive energy markets (including branding expenditures), partly offset by the gain on the sale of the landfill and waste-hauling company. Regulated utility earnings were relatively flat in 1997 primarily because higher net electric revenues and lower outage expenses for the Salem nuclear generating units were offset by anticipated higher capital costs. Electric Utility Industry Restructuring As discussed on the following pages, deregulation of the electric utility industry is underway in Delaware, Maryland, and Virginia.

Generally, with restructuring, the supply component of the price charged to a customer for electricity will be deregulated, and electricity suppliers will compete to supply electricity to customers.

Customers would continue to pay the local utility a regulated price for the delivery of the electricity over the transmission and distribution system. Stranded costs are costs which may not be recoverable in a competitive energy supply market due to lower prices or customers choosing a different supplier.

Stranded costs generally include above-market costs associated with generation facilities or long-term purchased power agreements, and regulatory assets. DPL has quantified stranded costs in its Maryland regulatory filing and has proposed a plan seeking approval for recovery of these costs from customers during the* transition to a competitive market. II-3 /

When a specific plan that deregulates electricity supply becomes final, DPL would cease applying Statement of Financial Accounting Standards (SF AS) No. 71, "Accounting for the Effects of Certain Types of Regulation," to its electricity supply business in the regulatory jurisdiction to which the plan applies. To the extent that a deregulation plan provides for recovery of stranded costs through cash flows from the regulated transmission and distribution business, the stranded costs would continue to be recognized as assets under SFAS No. 71. Any stranded costs (including regulatory assets) for which cost recovery is not provided would be expensed.

The amount of stranded costs ultimately recovered from utility customers, if any, and the full impact of legislation deregulating the electric utility industry in any of the jurisdictions in which DPL operates cannot be predicted.

Also, the quantification of stranded costs under existing generally accepted accounting principles (GAAP) differs from methods used in regulatory filings. Among other differences, GAAP precludes recognition of the gains on plants (or purchased power contracts) not impaired, but requires write down of the plants that are impaired.

Due to these considerations, market conditions, timing, and other factors, DPL's management currently cannot predict the ultimate effects that electric utility industry deregulation may have on the financial statements of DPL, although deregulation may have a material adverse effect on DPL's results of operations.

Delaware The Alliance for Fair Electric Competition Today, which includes DPL, worked with Delaware executive branch representatives and representatives of the Delaware Public Service Commission (DPSC) Staff to develop consensus restructuring legislation.

House Bill No. 10, with several amendments, passed the Delaware House of Representatives, and the Delaware Senate. The Governor of Delaware is expected to sign the legislation.

House Bill No. 10 would allow DPL's Delaware customers to choose their electricity suppliers beginning on October 1, 1999 (for customers with peak demands of 1,000 kilowatts or more), January 15, 2000 (for customers with peak demands of 300 kilowatts or more), and 18 months after the legislation is enacted (for all other customers).

House Bill No. 10 also provides for a residential rate reduction of 7.5% beginning October 1, 1999. Thereafter, except for a deferred fuel balance "true-up" and increases for extraordinary costs, residential rates may not be changed for four years; rates for customers in commercial and industrial rate classes may not be changed for three years. Under House Bill No. 10, certain low-income energy assistance and environmental programs are funded at an annual level of about $1.6 million by a charge in electric rates. Among other matters, unbundled rates to be charged by DPL during these "rate freeze" periods have been agreed upon by a number of participants in the restructuring plan proceeding contemplated by House Bill No. 10. Included within the agreement on unbundled rates, DPL would recover $16 million (Delaware retail basis) of stranded costs, and electric rates would not be changed in the event DPL sells or transfers generating assets. Maryland In 1997, the Maryland Public Service Commission (MPSC) issued two orders which provide for retail* electric competition to begin July 3, 2000, and be phased-in over a three-year period (one-third of the customers per year). Enabling legislation and resolution of complex issues such as stranded costs and utility taxation will be necessary for implementation of retail competition in Maryland.

On July 1, 1998, DPL filed with the MPSC its quantification of stranded costs and computation of unbundled rates, which are being considered in Case No. 8795. Stranded costs were estimated to be $217 million on a DPL system-wide basis ($69 million Maryland retail portion), including

$123 million attributable to generating units, $54 million associated with purchased power contracts, $21 million related to fuel inventory financing costs, and $19 million of regulatory assets. DPL proposed full recovery of the Maryland portion of the stranded costs over a three-year period, starting with the commencement of retail competition on July 3, 2000. The MPSC Staff and other parties contend that the market value of DPL's generating assets exceeds their book value and thus that DPL has negative stranded costs, or so-called "stranded benefits." Proposals for rate II-4

• reductions based on a sharing of these alleged benefits and other factors have been submitted to the MPSC in Case No. 8795. The proposed rate reductions vary widely, from 3% up to levels which, if adopted, would have a material adverse impact on DPL's results of operations.

Maryland's electric utilities, including DPL, continue to meet with the MPSC Staff and others to develop consensus enabiing restructuring and related tax legislation for possible passage in the 1999 legislative session. The MPSC is expected to issue its order on DPL's stranded cost recovery and unbundled rates by October 1, 1999. Virginia Comprehensive electric utility restructuring legislation has been introduced in the Virginia General Assembly.

Senate Bill No. 1269 and identical House Bill No. 2615, introduced on January 21, 1999, were drafted by a joint House-Senate study committee created in 1996 to consider restructuring issues. Significant provisions of these Bills provide for:

• Phase-in of retail electric competition beginning January 1, 2002

• Rates in effect on January 1, 2001 to. become "capped rates" to continue in effect through July 1, 2007, except for adjustments for changes in fuel costs and state tax rates

• Customers choosing an electricity supplier other than their incumbent utility continue to pay capped transmission and distribution rates but, instead of the capped generation rate, they would pay a wires

charge which would be the difference between the capped generation rate and projected market prices for electridty

• Just and reasonable net stranded costs, are to be recovered through capped rates and wires charges during the period January 1, 2001 through July 1, 2007 Price Regulation of Energy Revenues Through 1998, customer rates for non-energy costs have been established in past base rate proceedings before utility regulatory commissions.

Changes in non-energy (or base rate) revenues due to volume, or rate changes, generally affect the earnings of DPL. Energy costs, including fuel and purchased energy, are currently billed to rate-regulated customers under regulated energy adjustment clause rates. These energy rates are adjusted periodically for cost changes and are subject to review by regulatory commissions. "Energy revenues," or energy costs billed to customers, do not generally affect net income, because the amount of under-or over-recovered energy costs is generally deferred until it is subsequently recovered from or returned to utility customers.

Energy adjustment clauses are expected to be eliminated under electric utility industry restructuring initiatives.

Based on existing restructuring initiatives, profits or losses on the energy portion of electricity sales may affect DPL's earnings, after restructuring becomes effective.

Electric revenues also include interchange delivery revenues, which result primarily from the sale of electricity to other electricity suppliers in the Pennsylvania-New Jersey-Maryland Interconnection (PJM Interconnection), which is an electric power pool. Interchange delivery revenues are currently reflected in the calculation of rates charged to customers under energy adjustment clauses and, thus, do not affect net income. Margins from interchange delivery revenues may impact earnings after deregulation due to elimination of energy adjustment clauses. Revenues are also earned from sales not subject to price regulation.

These sales include off-system bulk commodity sales and retail energy sales. 11-5 Electric Revenues and Sales DPL's sources of electric revenues as a percentage of total electric revenues are shown in the table below. The percentage of DPL's consolidated electric revenues earned from sales not subject to price regulation has increased as DPL's participation in unregulated electricity markets has grown. Gross margin percentages earned in markets not subject to price regulation are generally lower than the gross margin percentages earned in regulated retail markets due to product differences, greater volume per customer, and unregulated pricing. However, incremental amounts of gross margin earned from sales not subject to price regulation enhance DPL's profitability.

Sources of Consolidated Electric Revenues 1998 1997 1996 Regulated retail revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

66.9% 81.0% 85.7% Resale revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

5.0% 6.3% 6.7% Interchange delivery revenues ................................ . 7.5% 3.3% 7.6% Revenues from sales not subject to price regulation

................ . 20.6% 9.4% Details of the changes in the various components of electric revenues are shown below. Comparative Increase (Decrease) from Prior Year in Electric Revenues Retail and Resale Revenues Non-Energy (Base Rate) Revenues ........................... . Energy Revenues ..............................

......... . Interchange Delivery Revenues .................................. . Revenues from sales not subject to price regulation

................... . 1998 1997 (Dollars in Millions)

$ 18.4 (16.1) 62.8 172.1 $237.2 $ 8.9 32.7 (38.8) 102.4 $105.2 Non-energy revenues increased

$18.4 million in 1998 primarily due to a 2.5% retail kWh sales increase which was attributed to favorable economic conditions and 1.6% customer growth. The retail kWh sales increase was reduced by milder winter weather's unfavorable effect on residential heating sales. The increase in energy electric revenues in 1998 was reduced by $10.7 million due to Merger-related customer base rate decreases.

For 1997 compareq to 1996, electric non-energy revenues increased

$8.9 million due to a 2.6% retail kWh sales increase, mainly attributed to favorable economic conditions and a 1.4% increase in the number of regulated retail customers.

Milder weather limited the sales increase.

In 1998 and 1997, revenues from electric sales not subject to price regulation increased

$172.1 million and $102.4 million, respectively, mainly because DPL sold more output off-system through the Merchant business.

DPL actively participates in the wholesale energy markets to support wholesale utility and competitive retail marketing activities.

Energy market participation results in exposure to commodity market risk when, at times, net open energy coillmodity positions are created or allowed to continue.

To the extent that DPL has net open positions, controls are in place that are intended to keep risk exposures within certain management approved risk tolerance levels.

• As discussed under Price Regulation of Energy Revenues,

energy' and interchange delivery revenues

• generally do not affect net income II-6

• Electric Resale Business The ability of electric resale customers to choose their electric supplier has created a competitive electric resale market. If an electric resale customer selects a supplier other than the local utility, then the local utility receives a fee for delivering the electricity to the resale customer.

DPL's contract with its largest electric resale customer, Old Dominion Electric Cooperative CODEC), is discussed below. Other electric resale customers of DPL have electricity supply contracts with DPL which expire in 2001 to 2004. Under notice provisions in its electricity supply contract, ODEC reduced its load by 60 megawatts (MW) on September 1, 1998, from approximately 200 MW to 140 MW. ODEC has also notified DPL that it will reduce its load to zero on September 1, 2001. The annualized reduction in DPL's net income expected to result from ODEC's 60 MW load reduction is approximately

$2 to $3 million. If ODEC further reduces its load to zero on September 1, 2001, then annualized net income would decrease by approximately an additional

$7 to $8 million. These projected earnings decreases are net of the expected savings from avoided capacity costs. Gas Revenues, Sales and Transportation DPL earns gas revenues from on-system sales which generally are subject to price regulation, off-system sales which are not subject to price regulation, and from the transportation of gas for customers.

Transportation customers may purchase gas from DPL or other suppliers.

• Details of the changes in the various components of gas revenues are shown below. Comparative Increase (Decrease) from Prior Year in Gas Revenues 1998 1997 (Dollars in Millions)

Non-Energy (Base Rate) Revenues ................................ . $ (4.0) $ (1.2) Energy Revenues ............................................. . . (6.0) 8.8 Revenues from sales hot subject to price regulation

.................... . 341.0 82.2 ------$331.0 $89.8 As shown in the above table, total gas revenues increased

$331.0 million in 1998 and $89.8 million in 1997 primarily due to higher volumes of gas sold in markets not subject to price regulation.

The margin earned from non-price regulated gas sales in excess of related purchased gas costs is relatively small due to the competitive nature of bulk commodity sales. The decreases in non-energy (base rate) gas revenues for 1998 and 1997 were primarily due to inilder weather during the heating seasons of both years, which resulted in lower residential gas sales (based on cubic feet sold) of 13.2% and 9.8%, respectively.

The weather-related gas revenue decrease was partly offSet by additional gas revenues from new customers.

The number of regulated gas customers served increased 2.4% in 1998 and 2.3% in 1997. As discussed under Price Regulation of Energy Revenues,

energy revenues generally do not affect net income. II-7 Other Services Revenues Other service revenues were comprised of the following:

HVAC (1) .......................................... . Operation of power plants ............................... . Landfill and waste hauling .............................. . Other (2) ........................................... . Total ........................................... . (1) Heating, ventilation, and air conditioning (HVAC). 1998 1997 1996 (Dollars in millions)

$14.6 $ 62.8 $ 7.1 2.9 23.5 21.5 17.9 $35.4 12.7 14.1 20.2 24.8 $119.2 $67.5 (2) Other includes real estate activities, value-added (energy-related) services, leveraged leasing, telecommunications and other miscellaneous services.

Total revenues from "Other Services" decreased

$83.8 million in 1998, primarily due to the transfer of DPL's nonutility subsidiaries to Conectiv on March 1, 1998, and the loss of revenue attributed to the sale of a landfill and waste-hauling operation in the fourth quarter of 1997. In 1997, other services revenues increased to $119.2 million from $67.5 million in 1996, mainly due to HV AC business acquisitions.

Electric Fuel and Purchased Energy Expenses In 1998, electric fuel and purchased energy increased

$204.4 million compared to 1997 primarily due to more energy supplied for greater volumes of electricity sold off-system and within DPL's service territory.

In 1997, electric fuel and purchased energy expenses increased

$89.2 million compared to 1996 primarily due to greater volumes of energy sold off-system and lower amounts of energy expenses deferred under energy adjustment clauses. For information concerning the Salem outage's impact on electric fuel and purchased energy expenses, see Note 18 to the Consolidated Financial Statements.

The kWh output required to serve load within DPL's service territory is substantially equivalent to total output less interchange deliveries and *off-system sales. In 1998, DPL's output for load within its service territory was provided by 34.% coal generation, 32% net purchased power, 18% oil and gas generation, and 16% nuclear generation

.. Gas Purchased Primarily due to larger volumes of gas purchased for resale off-system, gas purchased increased

$333.4 million in 1998 and $91.8 million in 1997.

• Other Services' Cost of Sales Other services' cost of sales decreased

$59.1 million in 1998 primarily due to the transfer of DPL's nonutility subsidiaries to Conectiv on March 1, 1998, and the sale of a landfill and waste-hauling operation in the fourth quarter of 1997. Other services' cost of sales increased by $29.9 million in 1997 primarily due to acquisitions of HV AC service companies.

Purchased Electric Capacity Purchased electric capacity costs increased

$10.3 million in 1998 due to a greater capacity obligation to the PJM Interconnection and a higher average cost per megawatt of purchased capacity.

II-8 l Operation and Maintenance Expenses Operation and maintenance expenses decreased to $264.6 million in 1998 from $331.8 million in 1997. The. $67 .2 million decrease was primarily due to fewer employees, the transfer of the nonutility subsidiaries to Conectiv on March 1, 1998, and the absence of last year's re-start activities at the Salem nuclear power plant. In 1997 operation and maintenance expenses increased

$53.9 million mainly due to the start-up of the HV AC, telecommunications, retail energy, and merchant businesses, and costs associated with establishing the Conectiv brand name and gaining new customers.

Lower pension cost and Salem outage expenses mitigated the total increase in operation and m_aintenance expenses.

Depreciation Expense Depreciation expense decreased

$4.4 million in 1998 due to the transfer of the nonutility subsidiaries to Conectiv on March 1, 1998, and the sale of a landfill and waste-hauling operation in the fourth quarter of 1997. These decreases were partially offset by higher utility depreciation expenses due to the completion of on-going construction projects.

Depreciation expense increased

$7.8 million in 1997 due to completion of on-going construction projects and installation of new systems. Other Income Other Income includes amounts for the nonutility subsidiaries transferred to Conectiv of $0.1 million in 1998, $33.3 million in 1997, and $8.9 million in 1996. Other income for 1997 includes a $22.9 million pre-tax gain on the sale of the Pine Grove landfill and related waste-hauling operations.

Financing Costs Financing costs reflected in tht< consolidated income statement include interest charges, allowance for funds used during construction (AFUDC), dividends on preferred securities of a subsidiary trust, and dividends on preferred stock. Financing costs decreased

$0.8 million in 1998 and increased

$9.9 million in 1997. The increase for 1997 was mainly due to long-term financing requirements associated with DPL's utility business.

Year 2000 The Year 2000 issue is the result of computer programs and embedded systems using a two-digit format, as opposed to four digfrs, to indicate the year. Computer and embedded systems with this characteristic may be unable to interpret dates during and beyond the year 1999, which could cause a system failure or other computer errors, leading to disruption of operations.

A project team, originally started in 1996 by ACE, is assisting line management in addressing the issue of computer programs and embedded systems not properly recognizing the Year 2000. A Conectiv.

corporate officer, reporting directly to the Chief Executive Officer, is coordinating all Year 2000 activities.

There are substantial challenges in identifying and correcting the many computer and embedded systems critical to generating and delivering power, delivering natural gas and providing other services to customers.

The project team is using a phased approach to managing its activities.

The first phase is inventory and assessment of all systems, equipment, and processes.

Each identified item is given a criticality rating of high, medium or low. Those items rated as high or medium are then subject to the second phase of the project. The second phase is determining and implementing corrective action for the systems, equipment and processes, and concludes with a test of the unit being remediated.

The third phase is system testing and compliance certification.

Additionally, the project team will be updating existing outage contingency plans to address Year 2000 issues .. Overall, Conectiv's Year 2000 Project covers approximately 140 different systems (some with numerous components) that had been originally identified as high or medium in criticality.

However, only 21 of those 140 systems are essential for Conectiv to provide electric and gas service to its customers.

The Year 2000 Project team will be focusing on these 21 systems, with additional work on the other systems continuing based on their relative importance to Conectiv's businesses.

ll-9 _J The following chart sets forth the current estimated completion percentage of the 140 different systems in

• the Year 2000 Project by major business group, and for the information technology systems used in managing Conectiv' s business.

Conectiv expects significant progress in remediation and testing over the next quarter based on work that is in process and material that is being ordered. Inventory and Corrective Action/ System Testing/ Assessment Unit Testing Compliance Business Group Business systems .......................... . 95% .85% 65% Power production

......................... . 95% 30% 30% Electricity distribution

...................... . 95% 10% 5% Gas delivery ............................. . 95% 60% 60% Competitive services ....................... . 90%-95% 30%-80% 30%-80% DPL is also contacting vendors and service providers to review remediation of their Year 2000 issues. Many aspects of DPL's businesses are dependent on third parties. For example, fuel suppliers must be able to provide coal or gas to allow DPL to generate electricity.

Distribution of electricity is dependent on the overall reliability of the electric grid. DPL is cooperating with the North American Electric Reliability Council (NERC) and the PJM Interconnection in Year 2000 remediation and remediation planning efforts, and has accelerated its Year 2000 Project timeline to be generally in-line with the recommendations of those groups. At this time, a few generating units are scheduled for remediation and testing in September to coincide with previously scheduled outages. Recent :r;eports issued by NERC indicate a diminished risk of disruption to the electric grid caused by Year 2000 issues. Conectiv has incurred approximately

$3 million in costs for the Year 2000 Project. Current estimates of the costs for the Year 2000 Project range from $10 million to $15 million. These estimates could change significantly as the Year 2000 Project progresses.

The costs set forth above do not include several significant expenditures covering new systems, such as Conectiv's SAP business, financial and human resources management system and an Energy Control System. While the introduction of these new systems effectively remediated Year 2000 problems in the systems they replaced, Conectiv has not previously reported the expenditures on these systems in its costs for the Year 2000 Project. Since the project team is still in the process of assessing and correcting impacted systems, equipment and processes, DPL cannot with certainty determine whether the Year 2000 issue might cause disruptions

• to its operations and have impacts on related costs and revenues.

DPL assesses the status of the Year 2000 Project on at least a monthly basis to determine the likelihood of business disruptions.

Based on its own Year 2000 program, as well as reports from NERC and other utilities, DPL;s management believes it is unlikely that significant Year 2000 related disruptions will occur. However, any substantial disruption to DPL's operations could negatively impact DPL's revenues, significantly impact its customers and could generate legal claims against DPL. DPL's results of operations and financial position would likely suffer an adverse impact if other entities, such as suppliers, customers and service providers do not effectively address their Year 2000 issues. Liquidity and Capital Resources DPL's primary sources of capital are internally generated funds (net cash provided by operating activities less common and preferred dividends) and external financings.

These resources provide capital for utility construction expenditures and other capital requirements, such as repayment of debt and capital lease obligations.

In the foreseeable future, DPL expects that incremental demand for electricity will be supplied with purchased power. Net cash inflows from operating activities increased to $246.2 million in 1998 from $221.3 million in 1997, mainly due to lower operation and maintenance expenses and higher electric revenues, net of amounts paid for electric fuel and purchased energy. Cash inflows from operating activities in 1997 remained at about the same

• level as in 1996. In 1997, cash used by new businesses offset higher cash flows from regulated energy revenues, net of amounts paid for energy. II-10 Capital expenditures decreased

$42.1.million in 1998 an.d $8.8 million in 1997. The 1998 decrease was primarily due to the transfer the nonutility subsidiaries to Conectiv on March 1, l998, and lower .utility construction expenditures.

The 1997 decrease was *principally due to a $40.5 million in utility construction expenditures, partly offset by $35.2 million of capital expenditures for expansion of Conectiv Inc.'s fiber optic network.

cash expenditures for business acquisitions of $9.0 million, $32.0 million, and $8.3 million, in 1998, . 1997, and 1996, respectively, were primarily due to the acquisition of HV AC and related businesses and direct Merger costs . . After deducting common and preferred dividend payments of $99.2 million in 1998, $98.0 million in 1997, and $102.4 million in 1996, internally generated funds were'$147.0 million in 1998, $123.2 million in 1997, and $120.3 million in 1996. Internally generated funds provided 129%, 107%, and 77% of the cash reqµired for utility consti;uction in 1998, 1997, and 1996, respectively.

• "Sales of under cash flows from investing activities includes $33.4 million of pre-tax proceeds from the 1997 sale of Pine Grove Inc.'s landfill and. WflSte-hauling operations.

' '

debt used $43.1 n:iillion of funds, financing activities (debt, preferred._equity, and common equity) provided net cash of $128.9 inillicm ($287.5 illillion of issuances net of $i58.6 ,million ciredemptions). . .. -. ' . Long-term debt issue<,i during l996 1998 to $199.2 mil1ion, which entirely of Medium Tern Notes with "interest rates ranging from 6.6% to 7.72%. and maturities ranging from 5 to 30 years .. Redemptions of long-term debt during 1996 to 1998 amounted to $62.2 million; which included $25.0 n:iimon of 5.69% Medium Term Notes, $25.0 _million of 6 3/8% First Mortgage Bonds, and $12.2 million of other debt. Scheduled maturities of long-term debt over the next five years are as follows: -1999-$31.3 million; 2000-. $1.5 million; 2001-$2.3 million; 2002-$48.1 million; 2003-$92.3 million. I ' . In October 1996, a subsidiary trust of DPL issued $70.0 million of 8.125% DPD obligated mandatorily redeemable preferred securities and loaned the proceeds.

to DPL. On a consolidated basis, these preferred

• securities provide a tax benefit equivalent to the tax effect of a deduction for distributions on the preferred secunties

.. The proceeds froin issuance of the preferred securities and additional short-terin debt were used, to reth-e $78.4 inillion of DPL's preferred stock, which had an average dividend rate of 6.9%. . '*. . . . . . . . . . . ' . . *.

• DPL's capital structure as of December 31, 1998 and 1997, expressed as a percentage of total capitalization is shown below. 1998 1997

'Long-term debt and variable rate demand bonds ......................... . 50.3% 48.6% -Preferred stock and securities . : .... *. : ............

• .. : . ; . .-.... -. ; ... -... . 7.8% 7.4% . Common stockholder's equity * ...... * ..... , * ; . , . * ..................

. : .. . 41.9% 44.0% ' . . . . . '* . DPL's estimated requirements during 1999 for capital expenditures are $138 -million.

The uncertainty of the impact of electric utility industry restructuring, and the extent to which DPLretains or. divests certain of its assets, including.

generating plants; will affect the ultimate amount of capital expenditures and the amount of external funds required in excess of internally generated funds. DPL's management expects that external funds will be derived from the _sale of long-term debt, as required.

Quantitative and Qualitative Disclosures About Market Risks , The following discussion contains * forward looking. statements.

These projected results have been prepared based. upon certain assumptions considered reasonable given the information currently available to 11-11 DPL. Nevertheless, because of the inherent unpredictability of interest rates, equity market prices, and energy commodity prices as well as other factors, actual results could differ materially from those projected in such forward-looking information.

For a description of DPL's significant accounting policies associated with these activities see Notes 1 and 7 to the Consolidated Financial Statements.

Interest Rate Risk DPL is subject to the risk of fluctuating interest rates in the normal course of business.

DPL manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. As of December 31, 1998, a hypothetical 10% change in interest rates would result in a $0.4 million change in interest costs and earnings before taxes related to short-term and variable rate debt. Equity Price Risk DPL maintains a trust fund, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear decommissioning (See Note 8 to the Consolidated Financial Statements).

The funds are invested primarily in domestic and international equity securities, fixed-rate, fixed income securities, and cash and cash equivalents.

By maintaining a portfolio that includes long-term equity investments, DPL is maximizing the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in DPL's portfolio are exposed to price fluctuations in equity markets, and the fixed-rate, fixed income securities are exposed to changes in interest rates. DPL actively monitors its portfolios by benchmarking the performance of its investments against certain indexes and by maintaining, and periodically reviewing, established target asset allocation percentages of the assets in its trust. Because the accounting for nuclear decommissioning recognizes that costs are recovered through electric rates, fluctuations in equity prices and interest rates, while affecting the carrying value of the invesments, are offset by the effects of regulation and therefore do not affect the earnings of DPL. Commodity Price Risk DPL is exposed to the impact of market fluctuations in the price and transportation costs of natural gas and electricity.

DPL engages in commodity hedging activities to minimize the risk of market fluctuations associated with the purchase and sale of energy commodities (natural gas and electricity).

Some hedging activities are conducted using energy derivatives (futures, option, and swaps). The remainder of DPL's hedging activity is conducted by backing physical transactions with offsetting physical positions. -The hedging objectives include the assurance of stable and known minimum cash flows and the fixing of favorable prices and margins when they become available.

DPL also engages in energy commodity trading and arbitrage activities, which expose DPL to commodity market risk when, at times, DPL creates net open energy commodity positions or allows net open positions to continue.

To the extent that DPL has net open positions, controls are in place that are intended to keep risk exposures within management-approved risk tolerance levels. DPL uses a value-at-risk model to assess the market risk of its electricity and gas commodity activities.

The model includes fixed price sales commitments, physical forward contracts, and commodity derivative instruments.

Value at risk represents the potential gain or loss on instruments or portfolios due to changes in market factors, for a specified time period and confidence level. DPL estimates value-at-risk across its power and gas commodity business using a delta-normal variance/covariance model with a 95 percent confidence level and assuming a five-day holding period. At December 31, 1998, DPL's calculated value at risk with respect to its commodity price exposure was approximately

$0.6 million. Forward-Looking Statements The Private Securities Litigation Reform Act of 1995 (Litigation Reform Act) provides a "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements II-12 *

• identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been made in this report. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management.

When used herein, the words "will," "anticipate," "estimate," "expect," "objective," and similar expressions are intended to identify forward-looking statements.

In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

deregulation and the unbundling of energy supplies and services; an increasingly competitive energy marketplace; sales retention and growth; federal and state regulatory actions; future litigation results; costs of construction; operating restrictions; increased costs and construction delays attributable to environmental regulations; nuclear decommissioning and the availability of reprocessing and storage facilities for spent nuclear fuel; and credit market concerns.

DPL undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

The foregoing review of factors pursuant to the Litigation Reform Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made by DPL prior to the effective date of the Litigation Reform Act. 11-13 DELMARVA POWER & LIGHT COMPANY Item 8. Financial Statements and Supplementary Data REPORT OF MANAGEMENT Management is responsible for the information and representations contained in the consolidated financial statements of Delmarva Power & Light Company (DPL). Our consolidated financial statements have been prepared in conformity with generally accepted accounting principles, based upon currently available facts and circumstances and management's best estimates and judgments of the expected effects of events and transactions.

DPL and its subsidiary companies maintain a system of internal controls designed to provide reasonable, but not absolute, assurance of the reliability of the financial records and the protection of assets. The internal control system is supported by written administrative policies, a program of internal audits, and procedures to assure the selection and training of qualified personnel.

PricewaterhouseCoopers LLP, independent accountants, are engaged to audit the financial statements and express their opinion thereon. Their audits are conducted in accordance with generally accepted auditing standards which include a review of selected internal controls to determine the nature, timing, and extent of audit tests to be applied. Conectiv's Audit Committee of the Board of Directors, composed of outside directors only, meets with management, internal auditors, and independent accountants to review accounting, auditing, ap.d financial reporting matters. The independent accountants are appointed by the Board on recommendation of the Audit Committee, subject to stockholder approval.

Isl How ARD E. CosGROVE Howard E. Cosgrove Chairman of the Board and Chief Executive Officer February 5, 1999 II-14 Isl JoHN C. v AN RODEN John C. van Roden Senior Vice President and Chief Financial Officer *

• I _J

• REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors Delmarva Power & Light Company Wilmington, Delaware In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, changes in common stockholder's equity and of cash flows present fairly, in all material respects, the financial position of Delmarva Power & Light Company (DPL) and subsidiary companies as .of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.

These financial statements are the responsibility of DPL's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for the opinion expressed above. Isl PrucEWATERHousECooPERS LLP PricewaterhouseCoopers LLP 2400 Eleven Penn Center Philadelphia, Pennsylvania February 5, 1999 II-15 DELMARVA POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME Year Ended December 31, Operating Revenues Electric ........................................... . Gas ........................................

..... . Other services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Operating Expenses Electric fuel and purchased power . . . . . . . . . . . . . . . . . . . . . . . .

Gas purchased . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Other services' cost of sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Purchased electric capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Employee separation and other merger-related costs .......... . Operation and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

Taxes other than income taxes .......................... . Operating

...................................... . Other Income Allowance for equity funds used during construction . . . . . . . . . . .

Other income ....................................... . Interest Expense Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Allowance for borrowed funds used during construction and capitalized interest ................................. . Dividends on Preferred Securities of a Subsidiary Trust . . . . . . . . .

Income Before Income Taxes ............................. . Income Taxes ......................................... . Net Income ........................................... . Dividends on Preferred Stock ............................. . Earnings Applicable to Common Stock ...................... . 1998 1997 1996 (Dollars in Thousands)

$1,329,393

$1,092,144

$ 986,921 535,082 204,057 114,284 35,424 119,166 67,459 1,899,899 1,415,367 1,168,664 621,002 416,640 327,464 486,411 153,027 61,208 26,069 85,192 55,276 38,782 28,470 32,126 27,418 264,581 331,770 277,893 131,919 136,340 128,571 38,290 37,634 35,737 1,634,472 1,189,073 918,275 265,427 226,294 250,389 2,134 1,337 1,338 3,321 36,322 14,506. 5,455 37,659 15,844 82,527 83,398 74,242 (2,019) (2,996) (3,926) 80,508 80,402 70,316 5,688 5,687 1,390 184,686 177,864 194,527 72,276 72,155 78,340 112,410 105,709 116,187 4,352 4,491 8,936 $ 108,058 $ 101,218 $ 107,251 See accompanying Notes to Consolidated Financial Statements.

Il-16 *

• DELMARVA POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 1998 1997 1996 (Dollars in Thousands)

Cash Flows From Operating Activities Net income ........................................... . $112,410 $105,709 $116,187 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .

141,669 142,734 134,109 Allowance for equity funds µsed duri,ng construction

......... . Investment tax credit adjustments, nef .................... . (2,135) (1,337) (1,338) (2,560) (2,560) (2,560) Deferred income taxes, net ............................ . 5,796 7,169 33,218 Net change in: Accounts receivable

.............................. . (74,321) (53,911) (5,030) Inventories

... : ..........

: .................... . (6,803) 4,763 (4,489) Accounts payable ................................ . 76,910 16,394 18,418 Other current assets & liabilities (1) .................. . 38,815 43,450 (48,383) Gains on sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(1,549) (22,896) (380) Other, net ......................................... . (42,027) (18,250)

(17,100) Net cash provided by operating activities

......................... . 246,205 221,265 222,652 Cash Flows From Investing Activities Acquisition of businesses, net of cash acquired ................. . (8,970) (31,994) (8,301) Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(114,663)

(156,808)

(165,595)

Investment in partnerships

................................ . (1,800) Net cash of nonutility subsidiaries transferred to Conectiv ......... . (18,138) Sales of nonutility assets .................................. . 3,805 34,880 793 Deposits to nuclear decommissioning trust funds . . . . . . . . . . . . . . . . .

(4,238) (4,240) (4,238) Other, net ............................................ . (360) 3,189 3,478 Net cash used by investing activities

............................. . (142,564)

(156,773)

(173,863)

Cash Flows From Financing Activities Common dividends paid .................................. . (94,700) (93,811) (93,290) Preferred dividends paid .................................. . (4,512) (4,233) (9,102) Issuances:

Long-term debt ............................ . 33,000 166,200 Common stock ............................. . 63 17,807 486 Preferred securities (2) ....................... . 70,000 Redemptions:

Long-term debt ............................ . (32,129) (28,540) (1,504) Variable rate demand bonds ................... . (1,800) (1,500) Common stock ............................. . (1,983) (7,323) (5,466) Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(78,383) Principal portion of capital lease payments .................... . Net change in short-term debt: ...... .' ...................... . (9,724) (6,813) (5,538) (26,975) (102,671) 86,498 Cost of issuances and refinancings . . . . . . . . . . . . . . . . . . . . . . . . . . .

(259) (4,502) (3,408) Net cash used by financing activities

............

-................ . (137,219)

(65,686) (41,207) Net change in cash and cash equivalents

... ...................... . (33,578) (1,194) 7,582 Cash and cash equivalents at beginning of period ................... . 35,339 36,533 28,951 Cash and cash equivalents at end of period ........................ . $ 1,761 $ 35,339 $ 36,533 (1) Other than debt and deferred income taxes classified as current. (2) DPL obligated mandatorily redeemable preferred securities of subsidiary trust holding solely DPL debentures.

See accompanying Notes to Consolidated Financial Statements.

II-17 DELMARVA POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS ASSETS Current Assets Cash and cash equivalents

...................................... . Accounts receivable

........................................... . Accounts receivable from associated companies

...................... . *Inventories, at average costs Fuel (coal, oil and gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

Prepayments

......................................

......... . Deferred energy costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

..; . . . . . . . . . . .

Deferred income taxes, net ...................................... . Investments Investment in leveraged leases ................................... . Funds held by trustee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Other investments

............................................ . Property, Plant and Equipment Electric utility plant ........................................... . Gas utility plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Common utility plant .......................................... . Less : Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Net utility plant in service ...................................... . Utility construction work-in-progress

.............................. . Leased nuclear fuel, at amortized cost .............................. . Nonutility property, net ........................................ . Goodwill, net ................................................ . Deferred Charges and Other Assets Prepaid employee benefits costs .................................. . Unamortized debt expense ...................................... . Deferred debt refinancing costs .........................

....... '; .. Deferred recoverable income taxes ................................ . Other ...................................................... . $

• As of December 31, 1998 1997 (Dollars in Thousands) 1,761 $ 35,339 273,531 197,561 2,325 44,212 37,425 39,323 40,518 10,735 .* 11,255 18,017 13,061 776 384,948 340,891 46,375 60,208 48,086 1,103 9,500 61,311 103,961 3,049,099 3,010,060.

249,383 241,580 158,109 154,791 3,456,591 3,406,431 1,492,182 1,373,676 1,964,409 2,032,755 138,496 93,017 28,325 31,031 4,560 74,811 71,914 92,602 2,207,704 2,324,216 94,354 58,111 12,140 12,911 16,180 18,760 82,211 88,683 46,003 67,948 250,888 246,413 Total Assets .................................................... . $2,904,851

$3,015,481 See accompanying Notes to Consolidated Financial Statements II-18 , \ ' 1 11 i i

• *

• Current Liabilities Short-term debt DELMARVA POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES Long-term debt due within one year ............................... . Variable rate demand bonds ..................................... . Accounts payable ............................................. . Taxes accrued ............................................... . Interest accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Dividends payable ............................................ . Current capital lease obligation

................................... . Deferred energy costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Accrued employee separation and other merger related costs ............. . Other .....................................

................ . Deferred Credits and Other Liabilities Deferred income taxes, net ...................................... . Deferred investment tax credits ................................... . Long-term capital lease obligation

................................ . Other ...................................................... . Capitalization Common sto,ck, $2.25 par value shares authorized:

1998-1,000,000; 1997-90,000,000 shares outstanding:

1998-1,000; 1997-61,210,262

................. . Additional paid-in-capital

....................................... . Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Treasury shares, at cost: 1997-619,237

............................ . Unearned compensation

........................................ . Total common stockholder's equity ............................ . Cumulative preferred stock ...................................... . DPL obligated mandatorily redeemable preferred securities of subsidiary trust holding solely DPL debentures

................................. . Long-term debt .............................................. . Commitments and Contingencies (Notes 16 and 19) $ As of December 31, 1998 1997 (Dollars in Thousands) 21,700 31,287 71,500 177,859 16,257 20,604 23,615 12,481 413 2,509 27,586 405,811 461,800 37,382 17,003 19,747 535,932 2 528,893 322,599 851,494 851,494 89,703 70,000 951,911 $ 23,254 33,318 71,500 103,607 10,723 19,902 23,775 12,516 35,819 334,414 492,792 39,942 19,877 30,585 583,196 139,116 526,812 300,757 966,685 (11,687) (502) 954,496 89,703 70,000 983,672 1,963,108 2,097,871 Total Capitalization and Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$2,904,851

$3,015,481 See accompanying Notes to Consolidated Financial Statements.

II-19 DELMARVA POWER & LIGHT COMPANY

• CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDER'S EQUITY Common Additional Unearned Shares Par Paid-in Retained Treasury Compen-Outstanding Value Capital Earnings Stock sation Total Balance as of January 1, 1996 ..........

60,759,365

$136,713 (Dollars in Thousands)

$506,328 $281,862 $ (30) $(1,433) $923,440 Net income .........................

116,187 116,187 Cash dividends declared Common stock .....................

(93,294) (93,294) Preferred stock . . . . . . . . . . . . . . . . . . . . .

(8,936) (8,936) Issuance of common stock Business acquisitions

................

212,350 4,396 4,396 DRIP (1) .................

• * * * * * *

• 21,465 47 388 435 Stock options ......................

2,400 5 45 50 Expenses .........................

(72) (72) Reacquired common stock ..............

(312,861) 532 (6,504) 363 (5,609) Amortization of unearned compensation

.... 687 (548) 139 Refinancing of preferred stock . . . . . . . . . . .

392 (2,215) (1,823) ---------Balance as of December 31, 1996 ........ 60,682,719 136,765 508,300 293,604 (2,138) (1,618) 934,913 Net income .........................

105,709 105,709 Cash dividends declared Common stock .....................

(94,065) (94,065) Preferred stock . . . . . . . . . . . . . . . . . . . . .

(4,491) (4,491) Issuance of common stock DRIP (1) .........................

965,655 2,173 15,485 17,658 LTIP (2) ........ * .................

71,103 160 1,200 (1,360) Stock options ......................

5,450 12 *88 100 Other issuance .....................

2,741 6 47 53

• Reacquired common stock ..............

(517,406) 230 (9,549) 2,162 (7,157) Amortization of unearned compensation

.... 1,462 314 1,776 ---Balance as of December 31, 1997 ........ 61,210,262 139,116 526,812 300,757 (11,687) (502) 954,496 Net income .........................

112,410 112,410 Cash dividends declared Common stock .....................

(94,860) (94,860) Preferred stock . . . . . . . . . . . . . . . . . . . . .

(4,352) (4,352) Issuance of common stock Business acquisitions

................

488,473 9,090 9,090 Stock options ......................

3,200 7 56 63 Reacquired common shares .............

(90,764) 50 (1,983) (1,933) LTIP (2) ...........................

(41) (41) Transfer of nonutility subsidiaries (3) ...... (132,023) 8,644 (123,379)

Change in shares outstanding due to Merger (4) ......................

(61,831,699)

(139,121) 139,121 Transfer of treasury shares to Conectiv due to Merger (5) ........................

221,528 (4,580) 4,580 Transfer of unearned compensation to Conectiv due to the Merger (5) .........

(543) 543 ---Balance as of December 31, 1998 ........ 1,000 $ 2 $528,893 $322,599 $ -$ -$851,494 ------------(1) Dividend Reinvestment and Common Share Purchase Plan (DRIP)-As part of the Merger, DPL's DRIP was transferred to Conectiv.

(2) Long-term incentive plan (LTIP). (3) On March 1, 1998, DPL's nonutility subsidiaries were transferred to Conectiv.

(4) As part of the Merger, all of DPL's outstanding shares of stock were exchanged for Conectiv shares of stock on a one to one basis. Effective March 1, 1998, DPL had 1,000 shares of stock outstanding, $2.25 par value, held by Conectiv.

(5) DPL's treasury shares and unearned compensation were transferred to Conectiv in conjunction with the Merger. See accompanying Notes to Consolidated Financial Statements.

• Il-20

• *

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies Nature of Business Effective March 1, 1998, Delmarva Power & Light Company (DPL) and Atlantic Energy, Inc. (Atlantic) consummated a series of merger transactions (the Merger) by which DPL and Atlantic City Electric Company (ACE) became wholly-owned subsidiaries of Conectiv.

As a result of the Merger, Conectiv owns DPL's former nonutility subsidiaries.

DPL's former nonutility subsidiaries included Conectiv Services, Inc. (heating, ventilation, and air conditioning construction and services), Conectiv Communications, Inc. (local and distance phone service), and Delmarva Capital Investments, Inc. (various nonutility businesses).

Refer to Note 4 to the Consolidated Financial Statements for additional information concerning the Merger. DPL provides regulated electric service (supply and delivery) to approximately 455,300 customers located on the Delmarva Peninsula, which includes Delaware, ten primarily Eastern Shore counties in Maryland, and the Eastern Shore of Virginia, encompassing an area consisting of about 6,000 square miles with a population of approximately 1.2 million. DPL also sells electricity outside its service territory (off-system) and in markets that are not subject to price regulation.

DPL provides regulated gas service (supply and/or transportation) to approximately 105,700 customers located in a service territory that covers about 275 square miles with a population of approximately 485,000 in northern Delaware, including the City of Wilmington.

DPL also sells gas off-system and in markets which are not subject to price regulation.

Regulation of Utility Operations DPL's utility business is subject to regulation with respect to its retail utility sales by the Delaware and Maryland Public Service Commissions (DPSC and MPSC, respectively) and the Virginia State Corporation Commission (VSCC), which have authority over rate matters, accounting, and terms of service. Retail gas sales are subject to regulation by the DPSC. The Federal Energy Regulatory Commission (FERC) also has regulatory authority over certain aspects of DPL's utility business, including the transmission of electricity and gas, the sale of electricity to municipalities and electric cooperatives, and interchange and other purchases and sales of electricity involving other utilities.

Excluding off-system sales not subject to price regulation, the percentage of electric and gas utility operating revenues regulated by each regulatory commission for the year ended December 31, 1998, was as follows: DPSC, 67.0%; MPSC, 25.0%; VSCC, 2.3%; and FERC, 5.7%. DPL is subject to the requirements of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). Regulatory commissions occasionally provide for future recovery from customers of current period expenses.

When this happens, the expenses are deferred as regulatory assets and subsequently recognized in the Consolidated Statement of Income during the period the expenses are recovered from customers.

Similarly, regulatory liabilities may also be created due to the economic impact of an action taken by regulatory commissions.

Refer to Note 10 to the Consolidated Financial Statements for a discussion of regulatory assets arising from the financial effects of rate regulation, and Note 6 to the Consolidated Financial Statements for a discussion of the impact and current status of electric utility industry restructuring.

II-21 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Financial Statement Presentation Due to the Merger-related restructuring discussed above, Delmarva Power Financing I (a financing subsidiary) became the only significant remaining wholly-owned subsidiary of DPL as of March 1, 1998. Accordingly, only the January and February 1998 operating results of DPL's former nonutility subsidiaries are included in the 1998 Consolidated Statement of Income. A full year's operating results of DPL's former nonutility subsidiaries are included in the 1997 and 1996 Consolidated Statements of Income. The consolidated financial statements include the accounts of DPL's wholly-owned subsidiaries.

All significant intercompany accounts and transactions are eliminated in consolidation.

Ownership interests of 20% to 50% in other entities are accounted for by the equity method of accounting.

Investments in entities accounted for under the equity method are included in "Other investments" on the Consolidated Balance Sheets. Earnings from equity method investees are included in "Other income" in the Consolidated Statements of Income. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of) contingent assets and liabilities at the-date of the financial statements and the reported amounts of revenues -and expenses during the reporting period. Actual results could differ from those -estimates and assumptions.

Revenue Recognition At the end of each month, there is an amount of electric and gas serviCe rendered from meter reading to the month-end which has not yet been billed to customers.

The non-energy (base rate) revenues associated with such unbilled services-are accrued by DPL. When interim rates are placed in effect subject to refund, DPL recognizes revenues based on expected final rates. --* * * -' ---Revenues from "Other Services" are recognized when services are performed or products are delivered.

Deferred Energy Costs _ Energy costs charged to DPL's results of operations generally are adjusted to match energy costs billed to customers (energy revenues) under tariffs for regulated energy sales. The difference between energy revenues and actual energy costs incurred is reported on the Consolidated Balance Sheets as "Deferred energy costs." The deferred balance is subsequently recovered from or returned to utility customers.

Nuclear Fuel DPL's share of nuclear fuel at the Peach Bottom Atomic Power Station (Peach Bottom) and the Salem Nuclear Generating Station (Salem) is financed through a contract which is accounted for as a capital lease. Nuclear fuel costs, including a provision for the future disposal of spent nuclear fuel, are charged to fuel expense on a unit-of-production basis. II-22

• I I ' */ , I

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Energy Trading and Risk Management Activities In December 1998, the Emerging Issues Task Force (EITF), which evaluates accounting issues under the direction of the Financial Accounting Standards Board (FASB), concluded that, effective for financial statements issued for fiscal years beginning after December 15, 1998, contracts entered into in connection with energy trading activities should be marked to market, with gains and losses (unrealized and realized) included in earnings (EITF No. 98-10). DPL uses futures, options, and swap agreements to hedge firm commitments or anticipated transactions of energy commodities and also creates net open energy commodity positions.

DPL used "hedge accounting" as subsequently described, to account for certain energy trading activities during 1996 to 1998. As discussed above, beginning January 1, 1999, EITF No. 98-10 requires mark to market accounting for energy trading contracts, including derivatives.

DPL currently uses derivatives mainly in conjunction with energy trading activities.

Under hedge accounting, a derivative, at its inception and on an ongoing basis, is expected to substantially offset adverse price movements in the firm commitment or anticipated transaction that it is hedging. Gains and losses related to qualifying hedges are deferred and are recognized in income when the underlying transaction occurs. If subsequent to being hedged, underlying transactions are no longer likely to occur or the hedge is no longer effective, the related derivatives gains or losses are recognized currently in earnings.

Gains and losses on derivatives that do not qualify for hedge accounting are recognized currently in revenues.

Premiums paid for options are included as current assets in the consolidated balance sheet until they are exercised or expire. Margin requirements for futures contracts are also recorded as current assets. Under hedge accounting, unrealized gains and losses on all futures contracts are deferred on the consolidated balance sheet as either current assets or deferred credits. The cash flows from derivatives are included in the cash flows from operations section of the cash flow statement.

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which becomes effective in the first quarter of fiscal years beginning after June 15, 1999, unless early adoption is elected. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities.

It requires that all derivatives be recognized as assets or liabilities in the balance sheet and be measured at fair value. Under specified conditions, a derivative may be designated as a hedge. The change in the fair value of derivatives, which are not designated as hedges, is recognized in earnings.

For derivatives designated as hedges of changes in the fair value of an asset or liability, or as a hedge of exposure to variable cash flows of a forecasted transaction, earnings are affected to the extent the hedge does not match offsetting changes in the hedged item. DPL currently cannot determine the effect that SFAS No. 133 will have on its financial statements.

However, the adoption of EITF 98-10 prior to the implementation of SFAS No. 133 is expected to reduce the impact of SFAS No. 133. Depreciation Expense The annual provision for depreciation on utility property is computed on the straight-line basis using composite rates by classes of depreciable property.

Accumulated depreciation is charged with the cost of depreciable property retired including removal costs less salvage and other recoveries.

The relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.6% for 1998, 3.7% for 1997, and 3.6% for 1996. Depreciation expense includes a provision for DPL's share of the estimated cost of decommissioning nuclear power plant reactors based on amounts billed to customers for such costs. Refer to Note 8 to the Consolidated Financial Statements for additional information on nuclear decommissioning.

II-23 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Nonutility property is generally depreciated on a straight-line basis over the useful lives of the assets. Income Taxes The consolidated financial statements include two categories of income taxes-current and deferred.

Current income taxes represent the amounts of tax expected to be reported on DPL's federal and state income tax returns. Deferred income taxes are discussed below. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement and tax bases of existing assets and liabilities and are measured using presently enacted tax rates. The portion of DPL' s deferred tax liability applicable to utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is shown on the Consolidated Balance Sheets as "Deferred recoverable income taxes." Deferred recoverable income taxes were $82.2 million and $88.7 million as of December 31, 1998, and 1997, respectively.

Deferred income tax expense represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. Investment tax credits from utility plant purchased in prior years are reported on the Consolidated Balance Sheets as "Deferred investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant. Debt Refinancing Costs Costs of refinancing debt are deferred and amortized over the period during which the refinancing costs are recovered in utility rates. Interest Expense The amortization of debt discount, premium, and expense, including refinancing expenses, is included in interest expense. Utility Plant and Allowance for Funds Used During Construction Utility plant is stated at original cost, including property additions.

Generally, utility plant is subject to a First Mortgage lien. Allowance for Funds Used During Construction (AFUDC) is included in the cost of utility plant and represents the cost of borrowed and equity funds used to finance construction of new utility facilities.

In the Consolidated Statements of Income, the borrowed funds component of AFUDC is reported as a reduction of interest expense and the equity funds component of AFUDC is reported as other income. AFUDC was capitalized on utility plant construction at the rates of 8.9% in 1998, 7.5% in 1997, and 6.7% in 1996. Cash Equivalents In the consolidated financial statements, DPL considers highly liquid marketable securities and debt instruments purchased with a maturity of three months or less to be cash equivalents.

Funds Held By Trustee Funds held by trustee are stated at fair market value and primarily include deposits in DPL' s external nuclear decommissioning trusts and unexpended, restricted, tax-exempt bond proceeds.

II-24

• I I l __ DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Goodwill DPL amortizes goodwill arising from business acquisitions over the shorter of the estimated useful life or 40 years. 2. Supplemental Cash Flow Information In conjunction with the Merger, ownership of DPL's former nonutility subsidiaries was transferred to Conectiv.

The assets held by the subsidiaries transferred were primarily leveraged leases, nonutility property, and goodwill.

The common stockholder's equity of these nonutility subsidiaries was $123.4 million as of the Merger. Cash Paid During the Year Interest, net of capitalized amount .......................... . Income taxes, net of refunds .............................. . 3. Income Taxes 1998 1997 1996 (Dollars in Thousands)

$76,314 $73,211 $67,596 $62,351 $53,550 $56,582 DPL, as a subsidiary of Conectiv, is included in the consolidated federal income tax return of Conectiv.

Income taxes are allocated to DPL based upon its taxable income or loss, determined on a sepdrate return basis. Components of Consolidated Income Tax Expense 1998 1997 1996 (Dollars in Thousands)

Federal: Current ...................................... . $57,533 $58,737

$40,953 Deferred ..................................... . 4,485 6,589 26,131 State: Current ...................................... . 11,504 8,810 6,729 Deferred ..................................... . 1,314 579 7,087 Investment tax credit adjustments, net ....................... . (2,560) (2,560) (2,560) $72,276 $72,155 $78,340 Reconciliation of Effective Income Tax Rate The amount computed by multiplying income before tax by the federal statutory rate is reconciled below to the total income tax expense. Statutory federal income tax expense ......... . Increase due to state income taxes, net of federal tax benefit ........................... . Other, net ............................. . Total income tax expense .............. . II-25 1998 Amount $64,640 8,330 (694) $72,276 1997 1996 Rate Amount Rate Amount Rate -(Dollars in Thousands) 35% $62,252 35% $68,084 35% 4 6,102 4 8,980 5 3,801 2 1,276 39% $72,155 41% $78,340 40%

DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Components of Deferred Income Taxes The tax effects of temporary differences that give rise to DPL's net deferred tax liability are shown below. 1998 1997 (Dollars in Thousands)

Deferred tax liabilities Plant basis differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$396,543 $409,861 Leveraged leases .................................................. . 38,288 Deferred recoverable income taxes ..................................... . 36,504 41,061 Deferred energy costs .............................................. . (5,459) 7,054 Other .......................................................... . 71,756 81,482 Total deferred tax liabilities

.......................................... . 499,344 577,746 Deferred tax assets , Deferred investment tax credits ....................................... . 13,745 14,815 Other .......................................................... . 36,860 70,915 . Total deferred tax assets ............................................ . 50,605 85,730 Total deferred taxes, net .............................................. . $448,739 $492,016 Valuation allowances for deferred tax assets were not material as of December 31, 1998 and 1997. 4. Merger with Atlantic On March 1, 1998, DPL and ACE became wholly-owned subsidiaries of Conectiv.

Before the Merger, Atlantic owned ACE, an electric utility serving the southern one-third of New Jersey, and nonutility subsidiaries.

As a result of the Merger, Atlantic no longer exists and Conectiv owns, (directly or indirectly), DPL, ACE and nonutility subsidiaries formerly held separately by DPL and Atlantic.

Conectiv holds the common stock of DPL and is a registered holding company under the Public Utility Holding Company Act of 1935. In connection with the Merger, each outstanding share of DPL's common stock, par value $2.25 per share, was exchanged for one share of Conectiv's common stock, par value $0.01 per share. Also, DPL's Board of Directors declared that a dividend consisting of the common stock of its nonutility subsidiaries be paid to Conectiv.

These nonutility subsidiaries had common stockholder's equity of $123.4 million as of February 28, 1998 and net losses of $3.5 million for January 1 to February 28, 1998. DPL recorded a $27.4 million charge ($16.6 million after taxes) in 1998 for costs of employee separation programs utilized to reduce the workforce by 421 employees and other Merger-related costs. The charge to expense was reduced by a net $45.5 million gain from curtailment and settlements of pension and postretirement health care benefits.

Of the $27.4 million of costs discussed above, $21.2 million had been paid as of December 31, 1998, $3.7 million will not require the use of operating funds, and $2.5 million remains to be paid from operating funds. 5. Sale of Pine Grove Landfill and Waste Hauling Companies In the fourth quarter 1997, a subsidiary of DPL sold the Pine Grove Landfill and its related waste-hauling

• company. The subsidiaries which were sold had a net book value of approximately

$11.3 million and reported

• revenues in 1997 of approximately

$12.7 million. Pre-tax proceeds received from the sale were $34.2 million ($33.4 million net of cash sold), resulting in a pre-tax gain of $22.9 million ($13.7 million after income taxes). 11-26

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

6. Rate Matters Merger Rate Decrease DPL is sharing a portion of the net cost savings expected to result from the Merger with its customers through reduced electric and gas retail customer base rates. DPL's total Merger-related base rate decrease of $13.0 million is being phased-in as follows: (1) $11.5 million effective March 1, 1998, (2) $1.1 million effective March 1, 1999, and (3) $0.4 million effective March 1, 2000. Electric Utility Industry Restructuring As discussed below, restructuring of the electric utility industry is underway in Delaware, Maryland, and Virginia.

Generally with restructuring, the supply component of the price charged to a customer for electricity will be deregulated, and electric suppliers would compete to supply electricity to customers.

Customers will continue to pay the local utility a regulated price for the delivery of the electricity over the transmission and distribution system. Stranded costs are costs which may not be recoverable in a competitive energy supply market due to lower prices or customers ch1:msing a different supplier.

Stranded costs generally include above-market costs associated with generation facilities or long-term purchased power agreements, and regulatory assets.

• When a specific plan that deregulates electricity supply becomes final, DPL would cease applying SF AS No. 71 to its electricity supply business in the regulatory jurisdiction to which the plan applies. To the extent that a deregulation transition plan provides for recovery of stranded costs through cash flows from the regulated transmission and distribution business, the stranded costs would continue to be recognized as assets under SF AS No. 71. Any stranded costs (including regulatory assets) for which cost recovery is not provided would be expensed.

The amount 'of stranded costs ultimately recovered from utility customers, if any, and the full impact of legislation the electric utility industry in Delaware, Maryland and Virginia cannot be predicted.

Also, the quantification of stranded costs under existing generally accepted accounting principles (GAAP) differs from methods used in regulatory filings. Among other differences, GAAP precludes recognition of the gains on plants (or purchased power contracts) not impaired, but requires write down of the plants that are impaired.

Due to these considerations, market conditions, timing and other factors, DPL currently cannot predict the ultimate effects that electric utility industry deregulation may have on its financial statements, although deregulation may have a material adverse effect on DPL's results of operations.

Delaware The Alliance for Fair Electric Competition Today, which includes DPL, worked with Delaware executive branch representatives and representatives of DPSC Staff to develop consensus restructuring legislation.

House Bill No. 10, with several amendments, passed the Delaware House of Representatives, and the Delaware Senate. The Governor of Delaware is expected to sign the legislation.

House Bill No. 10 would allow DPL's Delaware customers to choose their electricity suppliers beginning on October 1, 1999 (for customers with peak demands of 1,000 kilowatts or more), January 15, 2000 (for customers with peak demands of 300 kilowatts or more), and 18 months after the legislation is enacted (for all other customers).

House Bill No. 10 also provides for a residential rate reduction of 7.5% beginning October 1, 1999. Thereafter, except for a deferred fuel balance "true-up" and increases for extraordinary costs, residential rates may not be changed for four years; rates for customers in commercial and industrial rate classes may not be changed for three years. Under House Bill No. 10, certain low-income energy assistance and environmental programs are funded at an annual level of about $1.6 million by a charge in electric rates. II-27 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Among other matters, unbundled rates to be charged by DPL during these "rate freeze" periods have been agreed upon by a number of participants in the restructuring plan proceeding contemplated by House Bill No. 10. Included within the agreement on unbundled rates, DPL would recover $16 million (Delaware retail basis) of stranded costs, and electric rates would not be changed in the event DPL sells or transfers generating assets. Maryland In 1997, the MPSC issued two orders which provide for retail electric competition to begin July 3, 2000, and be phased-in over a three-year period (one-third of the customers per year). Enabling legislation and resolution of complex issues such as stranded costs and utility taxation will be necessary for implementation of retail competition in Maryland.

On July 1, 1998, DPL filed with the MPSC its quantification of stranded costs and computation of, unbundled rates, which are being considered in Case No. 8795. The MPSC is expected to issue its order on DPL's stranded cost recovery and unbundled rates by October 1, 1999. DPL estimated stranded costs to be $217 million on a DPL system-wide basis ($69 million Maryland retail portion), including

$123 million attributable to generating units, $54 million associated with purchased power contracts, $21 million related to fuel inventory financing costs, and $19 million of regulatory assets. DPL proposed full recovery of the Maryland portion of the stranded costs over a three-year period, starting with the commencement of retail competition on July 3, 2000. The MPSC Staff and other parties contend that the market value of DPL's generating assets exceeds their book value and thus that DPL has negative stranded costs, or so-called

stranded benefits.

Proposals for rate reductions based on a sharing of these alleged benefits and other factors have been submitted to the MPSC in Case No. 8795. The proposed rate reductions vary widely, from 3% up to levels which, if adopted, would have a material adverse impact on DPL's results of operations.

Maryland's electric utilities, including DPL, continue to meet with the MPSC Staff and others to develop consensus enabling restructuring and related tax legislation for possible passage in the 1999 legislative session. Virginia Comprehensive electric utility restructuring legislation has been introduced in the Virginia General Assembly.

Senate Bill No. 1269 and identical House Bill No. 2615, introduced on January 21, 1999, were drafted by a joint House-Senate study committee created in 1996 to consider restructuring issues. Significant provisions of these Bills provide for:

• Phase-in of retail electric competition beginning January 1, 2002

• Rates in effect on January 1, 2001 to become "capped rates" to continue in effect through July 1, 2007, except for adjustments for changes in fuel costs and state tax rates

• Customers choosing an electricity supplier other than their incumbent utility continue to pay capped transmission and distribution rates but, instead of the capped generation rate, they would pay a wires

charge which would be the difference between the capped generation rate and projected market prices for electricity

• Just and reasonable net stranded costs are to be recovered through capped rates and wires charges during the period January 1, 2001 through July 1, 2007 7. Energy Hedging and Trading Activities

• DPL actively participates in the wholesale energy markets to support its wholesale utility and competitive retail marketing activities.

DPL engages in commodity hedging activities to minimize the risk of market

• fluctuations associated with the purchase and sale of energy commodities (natural gas and electricity).

Some II-28

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued) hedging activities are conducted using energy derivatives.

The remainder of DPL's hedging activity is conducted by backing physical transactions with offsetting physical positions.

The hedging objectives include the assurance of stable and known minimum cash flows and the fixing of favorable prices and margins when they become available.

DPL also engages in energy commodity trading and arbitrage activities, which expose DPL to commodity market risk when, at times, DPL creates net open energy commodity positions or allows net open positions to continue.

To the extent that DPL has net open positions, controls are in place that are intended to keep risk exposures within management-approved risk tolerance levels. DPL utilizes futures, options, and swap agreements to manage risk. Futures help manage commodity price risk by fixing purchase or sales prices. Options provide a floor or ceiling on future purchases or sales prices while allowing DPL to benefit from favorable price movements.

Swaps are structured to provide the same risk protection as futures and options. Basis swaps are used to manage risk by fixing the basis differential that exists between a delivery location index and the commodity futures price. Exposed commodity positions may be "long" or "short." A long position indicates that DPL has an excess of the commodity available for sale. A short position means DPL will have to obtain additional commodity to fulfill its sales requirements.

A "delta" position is the conversion of an option into futures contract equivalents.

The option delta is dependent upon the strike price, volatility, current market price and time-value of the option. Natural Gas Activities At December 31, 1998, there were 1,314 (2,697 long, 1,383 short) net open futures contracts, representing a notional quantity of 13.l billion cubic feet (Bet) through February of 2001. In addition, DPL had a net long commodity swap position equivalent to 459 futures contracts (4.6 Bet) and a net long basis swap position equivalent to 531 futures contracts (5.3 Bet). DPL entered into 1,474 of the net long open futures contracts in order to hedge the gas marketing activities of various units. Other gas commodity hedges at December 31, 1998 included a net long commodity swap position equivalent to 262 futures contracts and a net long basis swap position equivalent to 471 futures contracts.

During the year ended December 31, 1998, $4.0 million of losses were recognized on the settlement of natural gas futures, swaps and options hedging contracts for the unregulated business units. These losses were offset by gains on the physical commodity transactions being hedged: A total of $8.6 million of unrealized losses were deferred in the Consolidated Balance Sheet as of December 31, 1998. These losses are offset by gains on the physical commodity being hedged.

During the year ended December 31, 1998, a trading gain of $0.2 million was realized on natural gas financial derivative activities that were not classified as hedges. Unrealized gains in forward gas trading positions (physical and financial) totaled $0.8 million at December 31, 1998. The annual average unrealized loss on trading activities, based on month-end averages, was $0.1 million. At December 31, 1997, there were 220 open futures contracts and 30 open options contracts to purchase natural gas, representing a notional quantity of 2.5 Bcf through October of 1999 and 60 open options contracts, to sell natural gas, representing a notional quantity of 0.6 Bcf through July of 1998. A total of $0.5 million of unrealized losses were deferred in the Consolidated Balance Sheet as of December 31, 1997. Electricity Activities At December 31, 1998, DPL had a total short exposure of 102,400 megawatt-hours (MWH) (84,700 on peak, 17,700 off-peak) through December 1999. The overall position included a long option delta exposure of 2,300 MWH. The remaining exposure was comprised of forward contracts.

II-29 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

During the year ended December 31, 1998, a net-gain of $0.1 million was recognized on the settlement of electric hedging options and swaps. This gain was offset by losses on the physical commodity transactions being hedged. A total of $0.3 million of umealized losses were deferred in the Consolidated Balance Sheet as of December 31, 1998.

During the year ended December 31, 1998 realized gains of $10.2 million were recorded on power trading activities (physical and financial) not classified as hedges. At December 31, 1998 umealized gains on power trading activities amounted to $1.2 million. The annual average umealized gain on trading activities, based on month-end averages, was $1.3 million. At December 31, 1997, there was one swap contract to sell electricity, representing a notional quantity of 68,000 MWH, through August of 1998. A total of $0.2 million of umealized losses were deferred on the Consolidated Balance Sheet as of December 31, 1997. Credit Exposure Counterparties to its various hedging and trading contracts expose DPL to credit losses in the event of nonperformance.

Management has evaluated such risk and implemented credit checks and has established reserves for credit losses. A large portion of the hedging and trading activities are conducted on national exchanges backed by exchange clearinghouses.

Management believes that the overall business risk is minimized as a result of these procedures.

8. Nuclear Decommissioning DPL records a liability for its share of the estimated cost of decommissioning the Peach Bottom and Salem nuclear reactors over the remaining lives of the plants based on amounts collected in rates charged to electric customers.

For utility rate-setting purposes, DPL estimates its share of future nuclear decommissioning costs ($157 million) based on Nuclear Regulatory Commission (NRC) regulations concerning the minimum financial assurance amount for nuclear decommissioning.

DPL's accrued nuclear decommissioning liability, which is reflected in the accumulated reserve for depreciation, was $69.5 million as of December 31, 1998. The provision reflected in depreciation expense for nuclear decommissioning was $4.2 million in 1998, $4.2 million in 1997, and $4.2 million in 1996. External trust funds established by DPL for the purpose of funding nuclear decommissioning costs had an aggregate book balance (stated at fair market value) of $57.7 million as of December 31, 1998. Earnings on the trust funds are recorded as an increase to the accrued nuclear decommissioning liability, which, in effect, reduces the expense recorded for nuclear decommissioning.

The ultimate cost of nuclear decommissioning for the Peach Bottom and Salem reactors may exceed the current estimates which are updated periodically.

The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including DPL, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities.

In February 1996, the FASB issued the Exposure Draft, "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets," which proposed changes in the accounting for closure and removal costs of long-lived assets, including the recognition, measurement, and classification of decommissioning costs for nuclear generating stations.

If the proposed changes were adopted: (1) annual provisions for decommissioning

• would increase, (2) the estimated cost for decommissioning would be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trusts would be reported

• as investment income rather than as a reduction of decommissioning expense. The FASB is expected to issue a revised Exposure Draft in the second quarter of 1999. II-30 I J

,-*

• I_ DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

9. Jointly Owned Plant DPL's Consolidated Balance Sheets include its proportionate share of assets and liabilities related to jointly owned plant. DPL' s share of operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in the Consolidated Statements of Income. DPL is responsible for providing its share of financing for the jointly-owned facilities.

Information with respect to DPL's share of jointly owned plant as of December 31, 1998 was as follows: Nuclear Peach Bottom ...................... . Salem ........................... . Coal-Fired Keystone ......................... . Conemaugh

....................... . Transmission Facilities

................... . Other Facilities

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

• Excludes nuclear decommissioning reserve. 10. Regulatory Assets Megawatt Ownership Capability Plant in Accumulated Share Owned Service Depreciation (Dollars in Thousands) 7.51% 164 MW $136,044 $ 63,040* 7.41% 164 MW 247,095 89,025* 3.70% 63MW 20,781 9,245 3.72% 63MW 33,207 11,710 Various 4,567 2,407 Various 2,159 295 $443,853 $175,722 Construction Work in Progress $13,950 5,050 18 245 4,340 $23,603 In conformity with generally accepted accounting principles, DPL's accounting policies reflect the financial effects of rate regulation and decisions issued by regulatory commissions having jurisdiction over DPL's utility business.

In accordance with the provisions of SPAS No. 71, DPL defers expense recognition of certain costs and records an asset, a result of the effects of rate regulation.

Except for deferred energy costs, which are classified as a current asset or liability, these "regulatory assets" are included on DPL's Consolidated Balance Sheets under Deferred Charges and Other Assets.

The costs of these assets are either being recovered or are probable of being recovered through customer rates. Generally, the costs of these assets are recognized in operating expenses over the period the cost is recovered from customers.

See Note 6 to the Consolidated Financial Statements for information about the impact of electric utility restructuring on the accounting for regulatory assets. DPL's regulatory assets and liabilities as of December 31, 1998 and 1997 are shown in the following table: 1998 1997 (Dollars in millions)

Deferred energy costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ (0.4) $ 18.0 Deferred debt refinancing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

16.2 18.8 Deferred recoverable income taxes .......................................... . 82.2 88.7 Deferred recoverable plant costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7.6 7.8 Deferred costs for nuclear decontamination/decommissioning

....................... . 5.7 6.3 Deferred demand-side management costs ..................................... . 5.6 6.2 Other ................................................................ . 2.2 1.9 Total ................................................................ . $119.1 $147.7 Il-31 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Deferred Energy Costs: Represents the difference between fuel revenues and actual fuel costs incurred.

The deferred balance is generally recovered from or returned to utility customers within one year. Deferred Debt Refinancing Costs: Represents the costs of refinancing debt of the utility business which are deferred and amortized over the period recovered in customer rates, which is generally the life of the new debt. Deferred Recoverable Income Taxes: Represents the portion of DPL's deferred tax liability applicable to utility operations that has not been recovered from utility customers and is recoverable in the future. As temporary differences between the financial statement and tax bases of assets reverse; deferred recoverable income taxes are amortized.

Deferred Recoverable Plant Costs: Represents utility plant construction costs excluded from plant service which are being recovered over 21 remaining years. Deferred Costs for Nuclear Decontamination/Decommissioning:

Represents amounts being recovered through fuel adjustment clause revenues for DPL's liability under the Energy Policy Act of 1992 for clean-up of gaseous diffusion enrichment facilities of the U.S. government.

Deferred Demand-Side Management Costs: Represents deferred costs of programs that allow DPL to reduce the peak demand for power. These costs are being recovered over 5 years. 11. Common Stock The public holders of DPL's common stock prior to the Merger exchanged each share of DPL's common stock for one share of Conectiv common stock. Effective with the Merger, Conectiv owns all 1,000 outstanding shares of DPL's common stock ($2.25 par value per share). See Note 4 to the Consolidated Financial Statements for additional information concerning the Merger. Also see the Statement of Changes in Common Stockholder's Equity for information about changes in common stock during 1998, 1997, and 1996. DPL's certificate of incorporation requires payment of all preferred dividends in arrears (if any) prior to payment of common dividends to Conectiv.

12. Cumulative Preferred Stock DPL has $1, $25 and $100 par value per share preferred stock for which 10,000,000, 3,000,000 and 1,800,000 shares are authorized, respectively.

No shares of the $1 par value per share preferred stock are outstanding.

Shares outstanding for each series of the $25 and $100 par value per share preferred stock are listed below. Redemptions of preferred stock in 1996 are discussed in Note 13 to the Consolidated Financial Statements.

II-32 * *

• I J I -I I

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Series $25 per share par value 7% % ................... . $100 per share par value 3.70%-5% ............................. . 6%o/o ................................. . Adjustable rate(3) ........................ . Auction rate(4) .......................... . Current Redemption Price (1) $103-$105 (2) $100 $100 (1) Redeemable beginning September 30, 2002, at $25 per share. (2) Redeemable beginning November 1, 2003, at $100 per share. (3) Average dividend rates were 5.5 % during 1998 and 1997. (4) Average dividend rates were 4.2 % during 1998 and 1997. Shares Outstanding 1998 1997 316,500 316,500 181,698 181,698 35,000 35,000 151,200 151,200 450,000 450,000 Amount 1998 1997 (Dollars in Thousands)

$ 7,913 $ 7,913 18,170 18,170 3,500 3,500 15,120 15,120 45,000 45,000 $89,703 $89,703 13. .DPL Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely DPL Debentures A wholly owned subsidiary trust (Delmarva Power Financing I) was established in 1996 as a financing subsidiary of DPL for the purposes of issuing common and preferred trust securities and holding 8.125% Junior Subordinated Debentures (the Debentures).

The Debentures held by the trust are its only assets. The trust uses interest payments received on the Debentures it holds to make cash distributions on the trust securities.

The combination of the obligations of DPL pursuant to the Debentures, and DPL's guarantee of distributions with respect to trust securities, to the extent the trust has funds available therefor, constitute a full and unconditional guarantee by DPL of the obligations of the trust under the trust securities the trust has issued. DPL is the owner of all of the common securities of the trust, which constitute approximately 3% of the liquidation amount of all of the trust securities issued by the trust. In October 1996, the trust issued $70 million in aggregate liquidation amount of 8.125% Cumulative Trust Preferred Capital Securities (representing 2,800,000 preferred securities at $25 per security).

At the same time, $72.165 million in aggregate principal amount of 8.125% Junior Subordinated Debentures, Series I, due 2036 were issued to the trust. For consolidated financial reporting purposes, the Debentures are eliminated in consolidation against the trust's investment in the Debentures.

The preferred trust securities are subject to mandatory redemption upon payment of the Debentures at maturity or upon redemption.

The Debentures are subject to redemption, in whole or in part at the option of DPL, at 100% of their principal amount plus accrued interest, after an initial period .during which they may not be redeemed and at ,any time upon the occurrence of certain events. In October 1996, DPL used part of the proceeds received from the trust to purchase and retire $32.1 million of its $25 par value, 7.75% series preferred stock, and $31.3 million of various series of its $100 par value preferred stock which had an average dividend rate of 5.68%. In December 1996, DPL redeemed its entire 7.52% preferred stock series which had a total par value of $15.0 million. II-33 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

14. Debt Substantially all utility plant of DPL is subject to the lien of the Mortgage and Deed of Trust collateralizing DPL's First Mortgage Bonds. DPL funds its interim financing requirements by issuing commercial paper and borrowing against bank credit lines (at December 31, 1998, total borrowing capacity under these facilities was $225 million, and $203.3 million was available for borrowing).

The weighted average interest rates on short-term debt outstanding as of December 31, 1998 and 1997 were 5.2% and 6.6%, respectively.

Maturities oflong-term debt and sinking fund requirements during the next five years are as follows: 1999-$31.3 million; 2000-$1.5 niillion; 2001-$2.3 million; 2002-$48.1 million; 2003-$92.3 million. In December 1998, DPL redeemed $6.0 million of 5.75% Pollution Control Bonds at maturity.

In June 1998, DPL repaid at maturity $25.0 million of 5.69% Medium-Term Notes and $1.0 million of 6.95% Amortizing First Mortgage Bonds. In January 1998, DPL issued $33.0 million of 6.81 % unsecured Medium-Term Notes which mature in 20 years. DPL used $25.4 million of the proceeds to refinance short-term debt. In recognition of this refinancing

$25.4 million of short-term debt was reclassified to long-term debt on the Consolidated Balance Sheet as of December 31, 1997. In the fourth quarter of 1997, DPL issued $42.0 million of unsecured Medium-Term Notes with maturities of 5 to 9 years and interest rates of 6.6% to 6.8%. The proceeds were used to refinance short-term debt. In September 1997, DPL redeemed $25.0 million of 6%% First Mortgage Bonds at maturity through the issuance of short-term debt. In February 1997, DPL issued $124.2 million of unsecured Medium-Term Notes with maturities of 10 to 30 years and interest rates of 7.06% to 7.72%. The proceeds were used to refinance short-term debt. II-34 *

• _,

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Long-term debt outstanding as of December 31, 1998 and 1997 is presented below: First Mortgage Bonds Amortizing First Mortgage Bonds Total First Mortgage Bonds Pollution Control Notes: Series 1973 Series 1976 Medium-Term Notes: Other Obligations:

Unamortized premium and discount, net Current maturities of long-term debt Total long-term debt Variable Rate Demand Bonds (2) Total long-term debt and Variable Rate Demand Bonds Interest Rates Due 1998 (Dollars in Thousands) 6.95% 6.40% 7.15%-8.15%

5.90%-7.60%

6.85%-8.50%

6.05% 6.95% 5.75% 7.125%-7.25%

5.69% 7.50% 6.59%-9.29%

8.30% 6.94% 6.84% 7.06%-8.125%

7.54%-7.62%

6.81% 7.61 %-9.95% 7.72% 6.00%-9.50%

8.00% 9.65% 2002 $ 30,000 2003 90,000 2011-2015 115,500 2017-2021 163,200 2022-2025 165,000 2032 15,000 1998-2008 24,149 602,849 1998 1999-2006 2,800 1998 1999 30,000 2002 16,000 2004 35,000 2005 10,000 2006 20,000 2007 91,500 2017 40,700 2018 33,000 2019-2021 73,000 2027 30,000 (1)

(1) (1) (1,651) (31,287) 951,911 71,500 $1,023,411 (1) Debt of former subsidiaries which was transferred to Conectiv in the Merger. 1997 $ 30,000 90,000 115,500 163,200 165,000 15,000 25,103 603,803 6,000 2,900 25,000 30,000 16,000 35,000 10,000 20,000 91,500 40,700 25,430 73,000 30,000 232 3,660 5,354 (1,589) (33,318) 983,672 71,500 $1,055,172 (2) DPL's debt obligations included Variable Rate Demand Bonds (VRDB) in the amount of $71.5 million as of December 31, 1998 and 1997. The VRDB are classified as current liabilities because the VRDB are due on demand by the bondholder.

However, bonds submitted to DPL for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects that bonds submitted for purchase will continue to be remarketed successfully due to DPL's credit worthiness and the interest rates being set at market. DPL also may utilize one of the fixed rate/fixed term conversion options of the bonds. Thus, DPL considers the VRDB to be a source of long-term financing.

The $71.5 million balance of VRDB outstanding as of December 31, 1998, matures in 2017 ($26.0 million), 2028 ($15.5 million), and 2029 ($30.0 million) . Average annual interest rates on the VRDB were 3.5% in 1998 and 3.8% in 1997. II-35 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

15. Fair Value of Financial Instruments The year-end fair values of certain financial instruments are listed below. The fair values were based on quoted market prices of DPL's securities or securities with similar characteristics.

Funds held by trustee . . . . . . . . . . . . .

.. . . . . . . . .

DBL Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely DPL Debentures

........ . Long-Term Debt ........................ . 16. Commitments Carrying Amount $ 60,208 $ 70,000 $951,911 1998 Fair Carrying Value Amount (Dollars in Thousands)

$ 60,208 $ 71,764 $1,041,895

$ 48,086 $ 70,000 $983,672 1997 Fair Value $ 48,086 $ 72,464 $1,053,810 DPL's expected capital and acquisition expenditures are estimated to be approximately

$138 million in 1999. As of December 31, 1998, DPL's commitments under long-term purchased power contracts included 237 megawatts (MW) of capacity and 100 MW of energy. Historical information is presented below for these contracts and a 48 MW capacity contract which was suspended in October 1996. 1998 1997 1996 Percent of system capacity ...................................... . 6.7% 6.4%

6.4% Percent of energy output ........................................ . 18.5% 12.1%

10.6% Capacity charges ($in millions)

................................... . $38.8 $28.5

$32.1 Energy charges($

in millions)

...............

• ..................... . $57.7 $38.1 $32.5 Based on existing contacts as of December 31, 1998, DPL's future commitments for capacity and energy under long-term purchased power contracts are estimated to be $84.2 million in 1999; $91.1 million in 2000; $94.1 million in 2001; $97.7 million in 2002, and $99.3 million in 2003. Due to the uncertainties surrounding restructuring of the electric utility industry, DPL has not forecasted its long-term purchased power commitments beyond 2003. DPL's share of nuclear fuel at Peach Bottom and Salem is financed through a nuclear fuel energy contract, which is accounted for as a capital lease. Payments under the contract are based on the quantity of nuclear fuel burned by the plants. DPL's obligation under the contract is generally the net book value of the nuclear fuel financed, which was $28.3 million as bf December 31, 1998. DPL leases an 11.9% interest in the Merrill Creek Reservoir.

The lease is considered an operating lease and payments over the remaining lease term, which ends in 2032, are $150.5 million in aggregate.

DPL also has long-term leases for certain other facilities and equipment.

Minimum commitments as of December 31, 1998 under the Merrill Creek Reservoir lease and all other noncancelable lease agreements (excluding payments under the nuclear fuel energy contract which cannot be reasonably estimated) are as follows: 1999-$6.2 million; 2000 * -$5.1 million; 2001-$5.2 million; 2002-$4.5 million; 2003-$6.5 million; after 2003-$131.2 million; total * -$158.7 million. Approximately 95% of the minimum lease commitments shown above are payments due under the Merrill Creek Reservoir lease. II-36 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Rentals Charged To Operating Expenses The following amounts were charged to operating expenses for rental payments under both capital and operating leases. 1998 1997 1996 (Dollars in Thousands)

Interest on capital leases ................................... . $ 1,467 $ 1,548 $ 1,628 Amortization of capital leases* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

9,838 6,499 5,653 Operating leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

13,190 11,590 13,795 $24,495 $19,637 $21,076 17. Pension and Other Postretirement Benefits 1998 1997 1996 Assumptions Discount rates used to determine projected benefit obligation as of December 31 .. . 6.75% 7.00% 7.50% 9.00% 9.00% 9.00% 4.50% 5.00% 5.00% 7.00% 7.50% 8.00% Expected long-term rates of return on assets ............................ . Rates of increase in compensation levels . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Health care cost trend rate on covered charges . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The health-care cost trend rate, or the expected rate of increase in health-care costs, is assumed to gradually decrease to 5.0% by 2002. Increasing the health-care cost trend rates of future years by one percentage point would increase the accumulated postretirement benefit obligation by $8.5 million and would increase annual aggregate service and interest costs by $0.5 million. Decreasing the health-care cost trend rates of future years by one percentage point would decrease the accumulated postretirement benefit obligation by $7 .5 million and would decrease annual aggregate service and interest costs by $0.5 million. The following schedules reconcile the beginning and ending balances of the pension and other postretirement benefit obligations and related plan assets. Other postretirement benefits include medical benefits for retirees and their spouses and retiree life insurance.

Change in Benefit Obligation Benefit obligation at beginning of year ............ . Service cost ..............................

)( : Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

.* *. . Plan participants' contributions

.................. . Plan amendments

............................ . Actuarial (gain) loss .......................... . Special termination benefits ....... : ............ . Curtailment (gain) loss ........................ . Settlement (gain) loss ......................... . Benefits paid ............................... . Benefit obligation at end of year ................. . II-37 Pension Benefits Other Postretirement Benefits 1998 $ 515,590 1*2,635 31,138 (10,770) 45,884 47,764 (6,373) (45,609) (142,510)

$ 447,749 1997 1998 (Dollars in Thousands)

$450,640 $80,500 12,779 2,185 34, 173 6,289 40,492 (22,494) $515,590 497 3,960 1,412 17 6,457 (4,278) $97,039 1997 '$73,841 2,393 5,547 304 4,781 (6,366) $80,500 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Coritinued)

Change in Plan Assets Pension Benefits Other Postretirernent Benefits 1998 1997 1998 1997 Fair value of assets at beginning of year .................. . Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Employer contributions

............................... . Plan participant contributions . . . . . . . . . . . . . . . . . . . . . . . . . . .

Benefits paid ...................................... . $ 771,257 107,887 (142,510) (Dollars in Thousands)

$676,189 $48,591 117,562 5,551 14,598 497 (22,494) (4,278) $36,075 9,984 8,594 304 (6,366) Fair value of assets at end of year . . . . . . . . . . . . . . . . . . . . . . . .

$ 736,634 $771,257 $64,959 $48,591 Reconciliation of Funded Status of the Plans Pension Benefits 1998 1997 Other Postretirernent Benefits 1998 1997 (Dollars in Thousands)

Funded status at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . $

288,885 $ 255,667 $(32,080) $(31,909)

Unrecognized net actuarial gain ....................... . (196,927)

(205,732)

(5,992) (18,238) Unrecognized prior service cost ....................... . 12,204 26,945 248 317 Unrecognized net transition (asset) obligation

............. . (15,773) (23,199) 43,787 54,259 Net amount recognized at end of year .................. . $ 88,389 $ 53,681 $ 5,963 $ 4,429 Based on fair values as of December 31, 1998, the pension plan assets were comprised of publicly traded equity securities

($493.5 million or 67%) and fixed income obligations

($243.1 million or 33%). Based on fair values as of December 31, 1998, the other postretirement benefit plan assets included equity securities

($43.4 million or 67%) and fixed income obligations

($21.6 million or 33%). Components of Net Periodic Benefit Cost Pension Benefits Other Postretirernent Benefits 1998 1997 1996 1998 1997 1996 (Dollars in Thousands)

Service cost ..........................

$ 12,635 $ 12,779 $ 13,172 $ 2,185 $ 2,393 $ 2,512 Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . .

31,138 34,173 32,531 6,289 5,547 5,213 Expected return on assets ................

(64,247) (60,020) (54,485) (4,000) (2,580) (1,722) Amortization of: Transition obligation (asset) ..........

(2,764) (3,314) (3,314) 3,244 3,617 3,617 Prior -service cost . . . . . . . . . . . . . . . . . .

1,911 2,035 2,048 50 53 53 Actuarial gain . . . . . . . . . . . . . . . . . . . . .

(9,163) (7,814) (4,573) (566) (712) (500) Cost before items below ..........

$(30,490)

$(22,161)

$(14,621)

$ 7,202 $ 8,318 $ 9,173 Special termination benefits . . . . . . . . . . . . . .

47,764 1,412 Curtailment (gain) loss ..................

(6,373) 17 Settlement (gain) loss ...................

(45,609) 6,457 Total net periodic benefit cost .........

$(34,708)

$(22,161)

$(14,621)

$15,088 $ 8,318 $ 9,173 Portion of net periodic benefit cost included in results of operations . . . . . . . . .

$(26,996)

$(16,621)

$(10,966)

$14,368 $ 6,239 $ 6,880 II-38 ;

• I I I I

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

The special termination benefits and curtailment and settlement gains and losses shown in the preceeding table for 1998 resulted from Merger-related employee separation programs discussed in Note 4 to the Consolidated Financial Statements.

Effective January 1, 1999, DPL's covered employees began participating in a "cash balance" pension plan adopted by Conectiv.

Contributions, which vary based on the employee's age and years of service, are made to individual employee accounts provided for under the plan. The "cash balance" of each employee's account increases based on employer contributions and interest income credited.

to the accounts.

The aggregate of the employee's accounts will be DPL's pension obligation.

Conectiv maintains 401(k) savings plans for covered employees.

Prior to the Merger, DPL provided 401(k) plans with benefit levels similar to the Conectiv 401(k) plans. Conectiv contributes to the plans, in the form of Conectiv stock, at varying levels up to $0.50 for each dollar contributed by covered employees, for up to 6% of employee base pay. The amount expensed for Conectiv's matching contributions was $2.7 million in 1998, $3.0 million in 1997, and $2.4 million in 1996. 18. Salem Nuclear Generating Station DPL owns 7.41 % of Salem, which consists of two pressurized water nuclear reactors operated by Public Service Electric & Gas Company (PSE&G). Salem Units 1 and 2 were removed from operation by PSE&G in the second quarter of 1995 due to operational problems, and maintenance and safety concerns.

After receiving NRC authorization, PSE&G returned Unit 2 to service on August 30, 1997, and returned Unit 1 to service on April 17, 1998. The net increase in fuel expenses due to unrecovered replacement power and other costs, net of the benefit of lawsuit settlement proceeds received in 1997 was $2.4 million in 1998, $3.1 million in 1997, and $10.1 million in 1996. The outages also caused increases in operation and maintenance costs of approximately

$4 million in 1997 and $9 million in 1996. As previously reported, on February 27, 1996, the co-owners of Salem, including DPL, filed a complaint in the United States District Court for New Jersey against Westinghouse Electric Corporation (Westinghouse), the designer and manufacturer of the Salem steam generators.

The complaint, which sought to recover from Westinghouse the costs associated with and resulting from the cracks discovered in Salem's steam generators and with replacing such steam generators, alleges violations of federal and New Jersey Racketeer Influenced and Corrupt Organizations Acts, fraud, negligent misrepresentation and breach of contract.

On November 4, 1998, the Court granted Westinghouse's motion for summary judgement with regard to the federal Racketeer Influenced and Corrupt Organizations Act claim, and dismissed the remaining state law claims without prejudice.

On November 18, 1998, the co-owners re-filed their state law claims against Westinghouse in the Superior Court of New Jersey. The co-owners also filed an appeal of the District Court's dismissal with the United States Court of Appeals for the Third Circuit. 19. Contingencies Environmental Matters DPL is subject to regulation with respect to the. environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitation on land use by various federal, regional, state, and local authorities.

Costs may be incurred to clean up facilities found to be contaminated due to past disposal practices.

Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or uncontrolled hazardous waste sites. DPL is currently a potentially responsible party at three federal superfund sites and is alleged to be a third-party contributor at three other federal superfund sites. DPL also has two former coal gasification sites in Delaware and one former coal gasification site in Maryland, each of which is a state superfund site. In addition, on August 11, 1998, the Delaware Department of Natural Resources and Environmental Control notified DPL that it is a potentially responsible party liable for clean-up of the Wilmington Public Works Yard as a former owner of the property.

There is $2 million included 11-39 DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued) in DPL's current liabilities as of December 31, 1998 and 1997, for clean-up and other potential costs related to these sites. DPL does not expect such future costs to have a material effect on the financial position or results of their operations.

Nuclear Insurance In conjunction with DPL's ownership interests in Peach Bottom and Salem, DPL could be assessed for a portion of any third-party claims associated with an incident at any commercial nuclear power plant in the United States. Under the provisions of the Price Anderson Act, if third-party claims relating to such an incident exceed $200 million (the amount of primary insurance), DPL could be assessed up to $26.3 million on an aggregate basis for such third-party claims. In addition, Congress could impose a revenue-raising measure on the nuclear industry to pay such claims. The co-owners of Peach Bottom and Salem maintain property insurance coverage of approximately

$2.8 billion for each unit for loss or damage to the units, including coverage for decontamination expense and premature decommissioning.

In addition, DPL is a member of an industry mutual insurance company, which provides replacement power cost coverage in the event of a major accidental outage at a nuclear power plant. Under these coverages, DPL is subject to potential retrospective loss experience assessments of up to $4.0 million on an aggregate basis. 20. Quarterly Financial Information (unaudited)

The quarterly data presented below reflect all adjustments necessary in the opinion of DPL for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations, differences between summer and winter rates, the timing of rate orders, and the scheduled downtime*

and maintenance of electric generating units. Quarter Ended 1998 March 31 ...................................... . June 30 ........................................ . September 30 ................................... . December 31 ..................

.-................ . 1997 March 31 ...................................... . June 30 ....................................... . September 30 ................................... . December 31 ................................... . II-40 Operating Revenue $ 416,110 362,378 598,888 522,523 $1,899,899

$ 346,079 310,968 400,502 357,818 $1,415,367 Net Applicable Operating Income to Common Income (Loss) Stock (Dollars in 'fhousands)

$ 13,089 $ (4,856) $ (5,942) 78,337 33,075 31,989 129,076 66,737 65,650 44,925 17,454 16,361 $265,427 $112,410 $108,058 $ 63,150 $ 25,793 $ 24,578 51,376 17,997 16,913 85,509 39,411 38,319 26,259 22,508 21,408 $226,294 $105,709 $101,218

• I I _j

• DELMARVA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Employee separation programs for DPL employees and other Merger-related costs expensed in 1998 (as discussed in Note 4 to the Consolidated Financial Statements) had the effects shown below on 1998 quarterly operating results. 1998 Quarter Ended March 31 ........................................................ . June 30 .......................................................

• *

• September 30 ..................................................... . December 31 ..................................................... . Operating Income Net Income (Dollars in Millions)

$(40.3) $(24.4) 14.3 8.6 (0.7) (0.4) (0.7) (0.4) $(27.4) $(16.6) As discussed in Note 5 to the Consolidated Financial Statements, in the fourth quarter of 1997, net income was increased by $13.7 million due to the sale of the Pine Grove Landfill and its related waste-hauling company. 21. Segment Information Conectiv's organizational structure and management reporting information is aligned with Conectiv's business segments, irrespective of which subsidiary, or subsidiaries, a business is conducted through. Businesses are managed based on lines of business, not based on legal entity. Business segment information is not produced, or reported, on a subsidiary by subsidiary basis. Thus, as a Conectiv subsidiary, no business segment information (as defined by SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information")

is available for DPL on a stand-alone basis. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. II-41

• [THIS PAGE INTENTIONALLY LEFT BLANK] * * -

• PART ID Item 10. Directors and Executive Officers of the Registrant Directors As of December 31, 1998 Howard E. Cosgrove, 55, ................. . Chairman of the Board Business Experience during Past 5 Years Elected 1998 as Chairman of the Board and Chief Executive Officer of Conectiv, Delmarva Power & Light Company, and Atlantic City Electric Company. Elected 1992 as Chairman of the Board, President and Chief Executive Officer and Director of Delmarva Power & Light Company. Meredith I. Harlacher, Jr., 56, . . . . . . . . . . . . . . .

Elected 1998 as President and Chief Operating Officer of Director Conectiv, and President and Chief Operating Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1993 as Senior Vice President of Atlantic Energy, Inc. Thomas S. Shaw, 51, . . . . . . . . . . . . . . . . . . . . .

Elected 1998 as Executive Vice President of Conectiv, and Director Executive Vice President and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1992 as Senior Vice President, Delmarva Power. & Light Company. Barry R. Elson, 57, Director Barbara S. Graham, 50, Director Audrey K. Doberstein, 66, Director Elected 1998 as Executive Vice President of Conectiv, and Executive Vice President and Director of Delmarva Power . & Light Company and Atlantic City Electric Company . Elected 1997 as Executive Vice President, Delmarva Power & Light Company. Executive Vice President, Cox Communications, Inc., Atlanta, Georgia, from 1995 to 1996. Senior Vice President, Cox Enterprises/Cox Communications, Inc., Atlanta, Georgia, from 1984 to 1995. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv, and Senior Vice President and Chief Financial Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1994 as Senior Vice President, Treasurer, and Chief Financial Officer, Delmarva Power & Light Company. Vice President and Chief Financial Officer from 1992 to 1994. Director of Delmarva Power & Light Company since 1992. Elected 1998, Director of Conectiv.

President of Wilmington College, New Castle, Delaware.

Dr. Doberstein also serves as a member of the Board of Directors of Blue Cross/Blue Shield of Delaware and Mellon Bank Delaware (N.A.), Wilmington, Delaware.

Jerrold L. Jacobs, 59, . . . . . . . . . . . . . . . . . . . . .

Elected 1998, Director of Conectiv and Delmarva Power Director & Light Company. Director of Atlantic Energy since Executives 1990. Retired, Chairman of the Board and Chief Executive Officer of Atlantic Energy and of Atlantic City Electric Company. Information about DPL's executive officers is included under Item 1. IIl-1 Item 11. Executive Compensation As previously noted, DPL is a wholly owned electric utility subsidiary of Conectiv.

The Chief Executive Officer and the four most highly compensated executive officers of Conectiv maintain the same position at both DPL and ACE. In 1998, the salaries and other compensation awarded to the Chief Executive Officer and the four most highly compensated executive officers of DPL were paid by Conectiv for their service as executive officers of Conectiv, DPL and ACE. The Board Personnel

& Compensation Committee Report was provided initially in the Conectiv Proxy Statement and is enclosed herein for the purpose of providing additional informational.

The following tables show information concerning the total compensation paid or awarded to DPL's Chief Executive Officer and each of the four most highly compensated executive officers for the fiscal year ended December 31, 1998. BOARD PERSONNEL

& COMPENSATION COMMITTEE REPORT Principles of Executive Compensation Program The Personnel

& Compensation Committee of the Board of Directors is comprised of four non-employee Directors.

The Committee provides an independent review of the Company's performance objectives and executive compensation.

Overall Objectives The Company's philosophy is to link compensation to business strategies and results, to align total compensation of executives with the long-term interests of stockholders, to motivate its senior execµtives to meet the challenging objectives established for the Company and to create an urgency for success in the newly-formed Company. The Company's executive compensation program is designed to: provide total compensation that emphasizes long-term performance which creates stockholder value; facilitate the rapid transition to a competitive business environment; reflect the market conditions for attracting and retaining high-quality executives and ensure that such executives have a continuing stake in the long-term success of the Company; and create significant levels of stock ownership.

The elements of the executive compensation program are: total compensation levels that are competitive with those provided by the competitive market, defined as a blend of companies in the utility and industrial markets; base compensation levels related to responsibility level and individual performance; annual variable compensation that varies based on corporate, unit and individual performance; and, long-term variable compensation based on long-term increases in stockholder value. Total Compensation Total compensation opportunities are developed for Company executives by Watson Wyatt, the firm that provides executive compensation consulting services to the Company. This is done using several published compensation survey sources and public proxy data to define the competitive market. Overall, the total compensation structure for executives is targeted at the median for similar positions at companies of similar size, including both utilities and industrial companies (Compensation Comparison Group)1* Individual reward levels

• 1. The Compensation Comparison Group does not include all of the same companies as the published industry indices in the Comparison

• of 10 Month Cumulative Total Return chart included in this Proxy Statement.

However, 34 of the 85 companies included in the EEI Executive Compensation Report, which is one element of the Compensation Comparison Group, are also part of either the Dow Jones Electric Utilities Index or the S&P 500 Index. ill-2 I I __ _____J

• vary based on individual contributions and performance.

Total compensation includes three components:

base compensation, annual variable compensation and long-term variable compensation.

The targets for each component of the executive compensation program are reviewed on an annual basis to ensure alignment with the Company's compensation philosophy and a proper balance between short-and long-term objectives.

Base Compensation Base compensation for executive officers is determined by evaluating the responsibilities of the positions held and the experience of the individuals, coupled with a review of compensation for comparable positions at other companies.

Base compensation is reviewed on an annual basis and adjustments are based on the performance of the Company and each executive officer. Annual base compensation increases reflect the individual's performance and contribution over several years in addition to the results for a single year. Following the 1998 increases, the overall base compensation level for the five named executive officers was slightly below the median of the base compensation targeted levels defined by the surveys and proxies. Annual Variable Compensation The Company's annual variable compensation is designed to motivate participants to accomplish stretch financial and individual goals and to increase the sense of urgency to deliver significant results on an annual basis. Annual variable compensation target opportunities are designed to be at or above the median of the blended utility and industrial market and for the named executive officers vary from 40% to 50% of base compensation, with maximum awards of 60% to 75% of base compensation.

Annual variable compensation is paid in a combination of cash (80%) and restricted stock units (20%) and is based on the achievement of predetermined corporate and individual goals. The plan for 1998 provides that payouts will occur only after a specified earnings target is achieved . For 1998, each individual covered by the plan was eligible to earn a variable compensation award between 0% and 150% of target. The portion of each individual award attributable to corporate, line of business, and group performance were determined and specific measures were developed at the beginning of the year. These measures were primarily financial for 1998 to accelerate the transition of the Company to a more competitive environment and included corporate measures of earnings, cash flow return on capital employed and cash flow. Each business group and line of business also developed specific financial measures to support their business plans. The Management Stock Purchase Program (MSPP) was designed as a means to promote significant executive stock ownership in the new company and to help meet stock ownership guidelines.

The program requires that 20% of the individual's earned annual variable compensation must be used to acquire restricted stock units (RSUs). Individuals may also voluntarily use up to an additional 30% (for a total of 50%) of their earned annual variable compensation to acquire RSUs. All RSUs are acquired at a 20% discount from Fair Market Value on the date paid. Each RSU is a proxy for one share of Common Stock, has a value equal to one share and earns at the rate *of the Common Stock dividend.

RSUs are restricted from sale or use for a 3-year period and are distributed in shares of Common Stock. Long-Term Variable Compensation The Company's long-term variable compensation reinforces the importance of providing stockholders with a competitive return on their investment.

Lohg-term variable compensation awards also strengthen the ability of the Company to attract, motivate and retain executives of superior capability and more closely align the interests of management with those of stockholders.

Long-term grants for Conectiv executives are determined by setting a target percentage of base compensation based on median data in the Compensation Comparison Group and converting the target amounts to actual grants using the "Black-Scholes Model" for options and time and forfeiture discount methods for the other elements of the long-term grants. ill-3 Long-term awards granted in 1998 consisted of non-qualified stock options, dividend equivalent units and

• performance accelerated restricted stock. Non-qualified stock options and dividend equivalent units were awarded to provide approximately two-thirds of the targeted value of the grant while the other one-third of the targeted value was provided through performance accelerated restricted stock. This stock vests as unrestricted Common Stock seven years from the award date. However, vesting may be accelerated if the price of Common Stock reaches certain predetermined levels prior to the seven years. All stock options were granted with exercise prices equal to the fair market value of Common Stock at the time of the grant. Performance accelerated restricted stock granted to the CEO and three other named executive officers is also subject to an additional condition tied to Total Shareholder Return over the seven year period. Failure to meet a predetermined Total Shareholder Return level over the restriction period will result in total forfeiture of their shares granted. The CEO and three other named executive officers also were given a special grant of performance accelerated stock options to increase emphasis on creating long-term shareholder value. All performance accelerated stock options were granted with exercise prices equal to the fair market value of Common Stock at the time of grant. These options do not vest and.cannot be exercised for 9-1/2 years from the date of their grant unless the stock price increases to predetermined levels. Absent accelerated vesting at these predetermined stock prices, the shares will become exercisable in 9-1/2 years with expiration occurring at 10 years. This special grant resulted in the long-term variable compensation component and total compensation exceeding the targeted median values for these four executives for 1998 using the Black-Scholes valuation methodology.

Stock Ownership Guidelines To further reinforce the interests of stockholders, stock ownership guidelines have been established for the Board of Directors, Company officers, and other Company management.

These guidelines require the individuals covered by the guidelines to have beneficial ownership of Common Stock, or securities convertible into Common Stock, with an aggregate value equal to certain multiples of each individual's salary (or annual retainers in the case of outside directors).

Multiples range from five times to one times salary. The Chief Executive Officer's multiple is set at five times salary and outside Directors' multiples are set at three times the annual retainer.

Internal Revenue Code Section 162(m) The Committee considers the tax deductibility of compensation paid to executive officers and the impact of Section 162(m) of the Internal Revenue Code of 1986, as amended (the "Code"), on the Company. This provision limits the amount of compensation that the Company may deduct from its taxable income for any year to $1 million for any of its five most highly compensated executive officers, unless certain requirements are met. The Committee has taken actions to limit the impact of the Code in the event that compensation paid to a named executive officer might otherwise not be deductible.

The Committee will continue to seek ways to limit the impact of the Code; however, the Committee believes that the tax deduction limitation should not compromise the Company's ability to create incentive programs that support the business strategy and also attract and retain the executive talent required to compete successfully.

Accordingly, achieving the desired flexibility in the design and delivery of compensation may periodically result in some compensation that is not deductible for federal income tax purposes.

Summary of Actions Taken by the Personnel

& Compensation Committee The Personnel

& Compensation Committee, consisting entirely of outside directors, provides direction and oversight to the Company's executive compensation plans, establishes the Company's compensation philosophy and assesses the effectiveness of the program as a whole. This includes activities such as reviewing the design of

• various plans and assessing the reasonableness of the total program consistent with the total compensation philosophy.

ill-4 Annual Variable Compensation To provide clear focus on increasing stockholder value through the successful completion of the Merger and growing the new Conectiv businesses, Mr. Cosgrove received additional levels of long-term awards in place of an annual variable opportunity for 1997. Therefore, there is no annual variable pay for 1997 reflected in 1998 compensation.

Mr. Cosgrove's annual variable compensation target opportunity for 1998 was set at 50% of base compensation, with a minimum payout of 0% and a maximum payout of 75% of base compensation.

Payment of any award requires achieving a predetermined level of 1998 earnings established by this Committee.

Performance measures for 1998, predetermined by this Committee, included earnings available for common stock, cash flow return on capital employed and cash flow. Awards for 1998 for Mr. Cosgrove and the four other named executive officers have not been determined.

Long-Term Variable Compensation Long-term incentive grants are a critical component of the Conectiv executive compensation philosophy, since they align executive interests very clearly with increased stockholder value. For 1998, Mr. Cosgrove received grants of non-qualified stock options, dividend equivalent units, performance accelerated restricted stock, and performance accelerated stock options (reflected in the Compensation Tables). The regular grants of non-qualified stock options, dividend equivalent units and performance accelerated restricted stock provided a long-term variable compensation opportunity approximately at the median of the defined competitive market. The special, non-recurring grant of performance accelerated stock options was awarded to create additional emphasis on achieving higher levels of stockholder value. In order for Mr. Cosgrove to receive any value from this grant prior to vesting at nine and one-half years, there must be a significant increase in stockholder value. Such increases prior to nine and one-half years will result in accelerated vesting of this grant in increments of one-third.

The first third would vest when stockholder value increases by $400,000,000, at which time Mr. Cosgrove's options would vest at a value of $1,200,000, or .3% of the increase in stockholder value. The entire grant would vest if stockholder value increases by $800,000,000, at which time Mr. Cosgrove's options would vest at a value of $2,400,000 or .3% of the increase in stockholder value. Only under results that yield increases in stockholder value and trigger ,accelerated vesting of this grant would Mr. Cosgrove's 1998 compensation exceed the median target compensation level. Personnel

& Compensation Committee S.I. Gore, Chairperson M.B. Emery R.B. McGlynn B.J. Morgan III-6 The Committee also assists in *administering key aspects of the Company's annual compensation program and variable compensation plan, such as reviewing annual compensation budgets and setting targets and corporate performance measures for the annual and long-term variable compensation plans. Finally, the Committee specifically implements the Company's executive compensation program as it directly pertains to the Chief Executive Officer and the Company's four other most highly compensated executives, i.e., the five "named executive officers." The Committee has determined that in an environment where competition is increasing, it is essential that the Company have the ability to attract, motivate and retain high quality executives from within and outside the utility industry.

Because of the extremely compeht1ve market for executive talent, the Personnel

&

• Compensation Committee has adopted a compensation structure based on a blend of utility and general competitive industry markets. The structure is also flexible to allow setting salaries at pure general industry levels where that may be necessary to attract certain specific skills and experience.

Consistent with this approach, the total compensation program relies on competitive base compensation generally at or below the median of the market with annual and long-term variable compensation opportunities generally above the median of the market. This places a much greater emphasis on variable compensation that aligns executive and stockholder interests.

This tofal compensation philosophy is important to the success of the Company because the Company is facing increasing competition and related risks. The Company is not simply a utility anymore, but is rapidly becoming part of the general competitive industry market and, therefore, just as strategies for success must change, the compensation to drive success must also change. Prior to the Merger involving Atlantic Energy and Delmarva and during 1998, this compensation philosophy enabled the Company to attract several key executives with experience and skills critical to the emerging competitive environment.

These executives would not have been available under a traditional utility compensation philosophy.

Significant actions by the Committee for fiscal year 1998 included adoption of the new Conectiv executive plans (Conectiv Variable Compensation Plan, Deferred Compensation Plan, Supplemental Executive Retirement Plan [SERP], and Change In Control Agreements) and other compensation and benefit plans for Conectiv employees.

The Committee also sets base compensation, annual variable targets and performance measures and long-term grants under the various executive programs, including special awards of performance accelerated stock options to the CEO and the three other named executive officers described above. Chief Executive Officer Compensation Mr. Cosgrove's compensation reflects Conectiv's compensation philosophy.

His base compensation, annual and regular long-term variable compensation place him at total compensation levels consistent with the median level of other CEO's at similarly-sized utility and manufacturing companies represented in the Compensation Comparison Group. Additional emphasis on achieving increased stockholder value has been created with a special grant of performance accelerated stock options. This special grant will cause his long term compensation . and total compensation to exceed the median targets for 1998. Base Compensation Action Conectiv was formed by a Merger involving Delmarva and Atlantic Energy in early 1998. Mr. Cosgrove's base compensation was set during the Merger process to reflect the size of Conectiv and the increasing competitive environment in which Conectiv does business.

His 1998 base compensation is at the median target level developed through a comparison of other Chief Executive Officers of similarly-sized corporations using a blend of utilities and general industry.

His salary for 1999 will remain the same as in 1998. ill-5 * *

• r -*

• Personnel

& Compensation Committee Interlocks and Insider Participation The Personnel

& Compensation Committee is comprised solely of non-officer directors.

Logical Business Solutions, which is owned by Mr. Emery's son-in-law, Paul Kleiman, had contracts with Conectiv Resource Partners, Inc., a subsidiary of the Company, with a gross value of $227,000 during 1998 for information technology consulting services.

Except as described in the preceding sentence, there are no Personnel

& Compensation Committee interlocks.

Table 1 -Summary Compensation Table Long-Term Compensation Annual Compensation Awards Payouts Variable Securities LTIP All Other Annualized Compensation Other Annual Restricted Underlying Payouts Compensation Name and Principal Position Year (1) Salary (Bonus)(2)

Compensation Stock Options (3) (4) H.E. Cosgrove, ...........

1998 $ 600,000 0 0 0 360,000 $572,134 $12,329 Chairman of the Board and 1997 $ 400,000 0 0 0 0 0 $18,981 Chief Executive Officer 1996 $ 400,000 0 0 0 0 0 $18,115 M.I. Harlacher, ...........

1998 $340,000 0 0 0 0 0 $ 3,742 President B.R. Elson, ..............

1998 $ 325,000 0 0 0 170,000 $ 21,560 $ 4,074 Executive Vice President T.S. Shaw, ..............

1998 $ 325,000 0 0 0 170,000 $155,267 $ 9,478 Executive Vice 1997 $ 219,249 $27,100 0 0 0 0 $ 6,563 President 1996 $ 180,000 $52,300 0 0 0 0 $ 6,333 B.S. Graham, ............

1998 $ 250,000 0 0 0 170,000 $155,267 $ 5,308 Senior Vice President 1997 $ 184,000 $27,100 0 0 0 0 $ 3,390 1996 $ 180,000 $92,300 0 0 0 0 $ 5,529 (1) Base salary is shown as an annualized amount. Other items of compensation reflect the full calendar 1998 compensation received from Conectiv and either Delmarva or Atlantic City Electric Company. (2) The 1998 bonus, which is an annual variable award, has not yet been determined.

The target award is 50% of annualized salary for Mr. Cosgrove and 40% for Messrs. Harlacher, Elson and Shaw and Mrs. Graham. (3) During* 1998 all restrictions lapsed on the performance-based restricted stock granted in 1995 and 1996 under the Delmarva LTIP due to the Merger involving Delmarva and Atlantic Energy. Under the "change in control" provisions, the awards fully vested resulting in a payout to Mr. Cosgrove of 21,160 shares (11,570 for 1995 and 9,590 for 1996) valued at $454,940; to Mr. Shaw of 5,450 shares (2,870 for 1995 and 2,580 for 1996) valued at $117,175; and to Mrs. Graham of 5,450 shares (2,870 for 1995 and 2,580 for 1996) valued at $117,175.

Shares were valued at $21.50 at the time of payout. Dividends on shares of restricted stock and dividend equivalents are accrued at the same rate as that paid to all holders of Common Stock. As of December 31, 1998; Mr. Cosgrove held 45,520 shares of restricted stock (35,520 for 1997 and 10,000 for 1998) and 30,000 Dividend Equivalent Units ("DEU's");

Mr. Elson held 4,000 shares of restricted stock for 1998 and 10,000 DEU's; Mr. Shaw held 12,010 shares of restricted stock (8,010 for 1997 and 4,000 for 1998) and 10,000 DEU's; Mrs. Graham held 12,010 shares of restricted stock (8,010 for 1997 and 4,000 for 1998) and 10,000 DEU's. Holders of restricted stock are entitled to receive dividends as declared.

(4) The amount of All Other Compensation for each of the named executive officers for fiscal year 1998 include the following:

Mr. Cosgrove, $2,125 in Company matching contributions to the Company's Savings and Investment Plan, $10,000 in Company matching contributions to the Company's Deferred Compensation Plan and $204 in term life insurance premiums paid by the Company; for Mr. Shaw, $2,630 in Company III-7 l matching contributions to the Company's Savings and Investment Plan, $6,644 in Company matching

• contributions to the Company's Deferred Compensation Plan and $204 in term life insurance premiums paid by the Company; for Mrs. Graham, $2,604 in Company matching contributions to the Company's Savings and Investment Plan, $2,500 in Company matching contributions to the Company's Deferred Compensation Plan and $204 in term life insurance premiums paid by the Company; for Mr. Elson, $2,969 in Company matching contributions to the Company's Savings and Investment Plan and $1,105 in term life insurance premiums paid by the Company; and for Mr. Harlacher, $3,300 in Company matching contributions to the Company's Savings and Investment Plan and $442 in term life insurance premiums paid by the Company. Table 2 -Option Grants in Last Fiscal Year (1) % of Total Number of Options Granted Securities Underlying to Employees in Exercise Expiration Grant Date Name Options Granted (#) Fiscal Year Price ($/Sh) Date Present Value(4) H.E. Cosgrove . . . . . . . . . . . . . . 300,000(2) 29% $22.84375 112/08 $385,831 60,000(3) 6% $22.84375 112/08 $137,063 M.I. Harlacher

..............

0% 0% B.R. Elson .................

150,000(2) 14% $22.84375 112/08 $192,915 20,000(3) 2% $22.84375 112/08 $ 45,688 T.S. Shaw .................

150,000(2) 14% $22,84375 112/08 $192,915 20,000(3) 2% $22.84375 112/08 $ 45,688 B.S. Graham ...............

150,000(2) 14% $22.84375 112/08 $192,915 20,000(3) 2% $22.84375 112/08 $ 45,688 (1) Currently, Delmarva does not grant stock appreciation rights. The options reflected in this table are for

• payouts in shares of Conectiv Common Stock. (2) Denotes Performance Accelerated Stock Options ("PASO's")

which were granted on a one-time basis. PASO's have a ten-year term and vest and are first exercisable 9 and 112 years from date of grant without regard to stock price performance.

Exercise date will accelerate for favorable stock price performance (i.e., first 1/3, second 113 and third 113 of PASO's vest after stock trades at $26, $28 or $30 per share, respectively, for ten consecutive trading days). There is a minimum holding period of three years from date of grant during which these options are not exercisable.

(3) Denotes Nonqualified Stock Options. One-half of such Options vest and are exercisable at end of second year from date of grant. Second one-half vest and are exercisable at end of third year from date of grant. (4) Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise price of $22.84375, equal to the Fair Market Value ("FMV") as of date of grant; (b) an option term of ten years; (c) risk-free rate of return of 6.00%; (d) volatility of 20.00%; and (e) dividend yield of 7.00%. For valuation purposes, PASO's are valued as a premium-priced stock option as of the date of grant with an exercise price of $30 a FMV of $22.84375.

III-8

• 1-* Table 3 -Aggregated Option Exercises in Last Fiscal Year and FY-End Option Values Shares Value Number of Securities Underlying Unexercised Options Acquired Name on Exercise Realized ($)(1) at FY-End(2)

Exercisable/Unexercisable Value of Unexercised In-the-Money Options at FY-End(l)

H. E. Cosgrove. . ................... . 0 0 M. I. Harlacher

..................... . 0 0 B. R. Elson ....................... . 0 0 T. S. Shaw ........................ . 0 0 B. S. Graham ....................... . 0 0 14,400/360,000 0/170,000 0/170,000 0/170,000

$51,225/$596,250

$ $ $ $ 0/$281,563 0/$281,563 0/$281,563 (1) The closing price for Conectiv's common stock as reported by the New York Stock Exchange on December 31, 1998 was $24.50. Any value in the options would be based on the difference between the exercise price of the options and the value at the time of the exercise (e.g., $24.50 as of close of business on 12/31/98), which difference would be multiplied by the number of options exercised.

(2) Only 14,400 stock options of Mr. Cosgrove are currently exercisable.

None of the remaining options may be exercised earlier than two years from date of grant for regular, non-performance based options and nine and one half years from date of grant for performance based options (subject to accelerated vesting for favorable stock price performance).

Table 4 -Long-Term Incentive Plans-Awards in Last Fiscal Year Name H. E. Cosgrove ................

...................... . M. I. Harlacher

....................................... . B. R. Elson .......................................... . T. S. Shaw .......................................... . B. S. Graham ........................................ . Number of Restricted Shares/Dividend Equivalent Units (#)(1) 10,000 shs/30,000 units 4,000 shs/10,000 units 4,000 shs/10,000 units 4,000 shs/10,000 units Performance Period Until Maturation or Payout(2) 312105 312105 3/2/05 3/2/05 (1) In addition, Mr. Cosgrove held 35,520 performance shares (valued at $870,240) and Mr. Shaw and Mrs. Graham held 8,010 performance shares (valued at $196,245) from a 1997 award with a four year performance cycle under the Delmarva Power Long Term Incentive Plan. (2) Awards of Restricted Shares (Performance Accelerated Restricted Stock or "PARS") and Dividend Equivalent Units ("DEU's")

were made to four of the named executive officers.

The payout of shares of PARS may potentially be "performance accelerated." Restrictions may lapse any time after 3 years (i.e., after March 1, 2001) upon on achievement of favorable stock price performance goals. In the absence of such favorable performance, restrictions lapse after 7 years (i.e., March 2, 2005) provided that at least a defined level of average, total return to shareholders is achieved.

As of December 31, 1998, Mr. Cosgrove's 10,000 Restricted Shares were valued at $245,000 and Messrs. Elson and Shaw and Mrs. Graham's 4,000 PARS were valued at $98,000. These values for both Restricted Shares and performance shares are based on the December 31, 1998 closing stock price of $24.50. For Dividend Equivalent Units, one DEU is equal in value to the regular quarterly dividend paid on one share of Conectiv common stock. The Dividend Equivalent Units shown are payable in cash for twelve quarters over a three year period ending with the quarterly dividend equivalent payable January 31, 2001. At that point, the 1998 DEU award lapses. III-9 Pension Plan The Conectiv Retirement Plan includes the Cash Balance Pension Plan and grandfathered proviSions relating to the Delmarva Retirement Plan and the Atlantic Retirement Plan that apply to employees who had either 20 years of service or were age 50 on the effective date of the Cash Balance Pension Plan (January 1, 1999). Certain executives whose benefits from the Conectiv Retirement Plan are limited by the application of Federal tax laws also receive benefits from the Supplemental Executive Retirement Plan. Cash Balance Pension Plan The named executive officers participate in the Conectiv Retirement Plan and earn benefits that generally become vested after five years of service. On an annual basis, a recordkeeping account in a participant's name is credited with an amount equal to a percentage of the participant's total pay, including base salary, overtime and bonuses, depending on the employee's age at the end of the plan year, as follows: Age at end of Plan Year Under 30 ......................................................

-'* .. 30 to 34 ......................................................... . 35 to 39 40 to 44 45 to 49 50 and over ....................................................... . % of Pay 5 6 7 8 9 10 These accounts also receive interest credits based on average U.S. Treasury Bill .rates for the year. In addition, certain annuity benefits earned by participants under the former Delmarva and Atlantic Retirement Plans are fully protected as of December 31, 1998, and will be converted to an equivalent cash amount and included in each employee's initial cash balance account. When an employee terminates employment, the amount credited to his or her account is converted into an annuity or paid in a lump sum. Supplemental Retirement Benefits Supplemental retirement benefits are provided to certain employees, including each executive officer, whose benefits under the Conectiv Retirement Plan are limited by type of compensation or amount under applicable Federal tax laws and regulations.

Designated employees may also receive an annual benefit at retirement equal to a percentage of final average compensation multiplied by years of service reduced by the amount of all benefits received under the Conectiv Retirement Plan and other n()nqualified arrangements.

III-10 Estimated Retirement Benefits Payable to Named Executive Officers The following table shows the estimated retirement benefits, including supplemental retirement benefits under the plans applicable to the named executive officers, which would be payable if he or she were to retire at normal retirement age, which is age 65, at 1998 compensation, expressed in the form of a lump sum payment. Years of service credited to each named executive officer as of his or her normal retirement date are as follows: Mr. Cosgove, 42; Ms. Graham, 30; Mr. Shaw, 40; Mr. Elson, 16 (8 of which are additional years of service for purposes of the supplemental retirement benefits), and Mr. Harlacher, 43. Estimated Retirement Benefits Name Year of 65th Birthday Lump Sum Value H. E. Cosgrove ............................... . B. S. Graham ................................ . T. S. Shaw ...............................

• ... . B. R. Elson .................................. . M. I. Harlacher

............................... . 2008 2013 2012 2006 2007 $2,993,000(2) 1,540,000(1) 1,789,000(2) 1,213,000(2) 2,323,000(2)

(1) Amounts include (i) interest credits for cash balances projected to be 5.01 % per annum on annual salary credits and prior service balances, if any, and (ii) accrued benefits as of December 31, 1998 under retirement plans then applicable to the named executive officer. Benefits are not subject to any offset for Social Security payments or other offset amounts and assume no future increases in base salary or total pay. (2) Under the Conectiv Retirement Plan's grandfather provisions, employees who participated in the Delmarva or Atlantic Retirement Plans and who met certain age and service requirements as of December 31, 1998, will have retirement benefits for all years of .service up to retirement calculated according to their original final pay formula benefit. This benefit will be compared to the cash balance account and the employee will receive whichever is greater. Estimated benefits are b!lsed on the Delmarva Retirement Plan for Messrs. Cosgrove, Shaw and Elson, the Cash Balance Pension Plan for Mrs. Graham and the Atlantic Retirement Plan for Mr. Harlacher.

The amount of benefit under such grandfathering is illustrated in the following tables applicable to the Delmarva and Atlantic Retirement Plans, respectively:

Delmarva Retirement Plan Pension Plan Table Annual Retirement Benefits in Specified Remuneration and Years of Service Classifications Average Annual Earnings for the 5 Consecutive Years of Earnings that Result in the Highest Average 15 Yrs. 20 Yrs. 25 Yrs. 30 Yrs. $125,000 ......................

28,599 38,132 47,665 57,198 200,000(1)

....................

46,599 62,132 77,665 93,198 300,000(1)

....................

70,599 94,132 117,665 141,198(2) 400,000(1)

....................

94,599 126,132 157,665(2) 189,198(2) 500,000(1)

....................

118,599 158,132(2) 197,665(2) 237,198(2)

(1) Effective January 1, 1998, annual compensation recognized may not exceed $160,000.

(2) For 1998, the limit on annual benefits is $130,000.

III-11 35 Yrs. 66,732 108,732 164,732(2) 220,732(2) 276,732(2)

Benefits are payable in the form of a 50% joint and surviving spouse annuity or lump sum and earnings

• include base salary, overtime and bonus. Atlantic Retirement Plan Pension Plan Table Annual Retirement Benefits in Specified Remuneration and Years of Service Classifications Average Annual Earnings for the 5 Consecutive Years of Earnings that result in the Highest Average $125,000 .................... . 200,000(1)

.................. . 300,000(1)

.................. . 400,000(1)

.................. . 500,000(1)

.................. . 15 Yrs. 30,000 48,000 72,000 96,000 120,000 20 Yrs. 25 Yrs. 40,000 50,000 64,000 80,000 96,000 120,000 128,000 160,000(2) 160,000(2) 200,000(2) 30 Yrs. 35 Yrs. 60,000 70,000 96,000 112,000 144,000(2) 168,000(2) 192,000(2) 224,000(2) 240,000(2) 280,000(2)

(1) Effective January 1, 1998, annual compensation recognized may not exceed $160,000.

(2) For 1998, the limit on annual benefits is $130,000.

Benefits are paid in the form of a life annuity or lump sum and earnings include base salary and bonus. Change in Control Severance Agreements And Other Provisions Relating to Possible Change in Control Conectiv has entered into change in control severance agreements with Messrs. Cosgrove, Elson and Shaw and Mrs. Graham and two other senior executives.

The agreements are intended to encourage the continued dedication of members of Conectiv's senior management team. These agreements provide potential benefits for such executives upon actual or constructive termination of employment (other than for cause) following a change

• in control of Conectiv, as defined in such agreements.

Each affected executive would receive a severance payment equal to three times Base Salary and Bonus and Conectiv-paid medical, dental, vision, group life and disability benefits during the three years after termination of employment, and a cash payment equal to the actuarial equivalent of accrued retirement pension credits equal to 36 months of additional service. In the event of a change in control, the Variable Compensation Plan provides that outstanding options become exercisable in full immediately, all conditions to the vesting of PARS are deemed satisfied and shares will be fully vested and nonforfeitable, DEU's will become fully vested and be immediately payable, variable compensation deferred under the Management Stock Purchase Program will be immediately distributed, and payment of variable compensation, if any, for the current year will be decided by the Board's Personnel

& Compensation Committee.

For the Deferred Compensation Plan, the Committee may decide to distribute all deferrals in cash immediately or continue the deferral elections of participants in which event Conectiv will fully fund a springing rabbi trust to satisfy the obligations.

An independent institutional trustee will maintain any such trust established by reason of this provision.

Item 12. Security Ownership of Certain Beneficial Owners and Management All shares of DPL's common stock are owned by Conectiv, DPL's parent company. Item 13. Certain Relationships and Related Transactions None. ill-12 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: 1. Financial Statements-The following financial statements are contained in Item 8 of Part II. Page No. Report of Independent Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

II-15 Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996. . . . II-16 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997, and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

II-17 Consolidated Balance Sheets as of December 31, 1998 and 1997. . . . .. . . . . . . . . . . . . . . . . . . .

II-18 Consolidated Statements of Changes in Common Stockholder's Equity for the years ended December 31, 1998, 1997, and 1996...........................................

II-20 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

II-21 2. Financial Statement Schedules-No financial statement schedules have been filed since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the respective financial statements or the notes thereto. 3. Schedule of Operating Statistics for the tlu:ee years ended December 31, 1998 can be found on pages IV-4 and IV-5 of this report. 4. Exhibits Exhibit Number 2 3-A 3-B 3-C 3-D 3-E 3-F 3-G Amended and Restated Agreement and Plan of Merger, dated as of December 26, 1996, between DPL, Atlantic Energy, Inc., Conectiv, Inc. and DS Sub, Inc. (Filed with Registration Statement No. 333-18843.)

Copy of the Restated Certificate and Articles of Incorporation effective as of April 12, 1990. (Filed with Registration Statement No. 33-50453.)

Copy of DPL's Certificate of Designation and Articles of Amendment establishing the 7%% Preferred Stock-$25 Par. (Filed with Registration Statement No. 33-50453.)

Copy of DPL' s Certificate of Designation and Articles of Amendment establishing the 6% % Preferred Stock. (Filed with Registration Statement No. 33-53855.)

A copy of DPL's Certificate of Amendment of Restated Certificate and Articles of Incorporation, filed with the Delaware Secretary of State, effective as of June 7, 1996. (Filed with Registration No. 333-07281.) *-r A copy of DPL's Articles of Amendment of Restated Certificate and Articles of Incorporation, filed with the Virginia State Corporation Commission, effective as of June 7, 1996. (Filed with Registration No. 333-07281.)

A copy of DPL' s Certificate and Articles of Amendment of Restated Certificate and Articles of Incorporation, filed with the Delaware Secretary of State, effective as of March 2, 1998 (filed with DPL's Current Report on Form 8-K dated March 4, 1998; File No. 1-1405). A copy of DPL's Articles of Amendment of Restated Certificate and Articles of Incorporation, filed with the Virginia State Corporation Commission, effective as of March 2, 1998 (filed with DPL's Current Report on Form 8-K dated March 4, 1998; File No. 1-1405). IV-1 Exhibit Number 3-H Certificate of Merger of DS Sub, Inc., a Delaware Corporation with and into DPL, filed with the Delaware Secretary of State, effective as of March 1, 1998 (filed with DPL's Current Report on Form 8-K dated March 4, 1998; File No. 1-1405). 3-I Certificate of Merger of DS Sub, Inc., a Delaware Corporation with and into DPL, filed with the Virginia State Corporation Commission, effective as of March 1, 1998 (filed with DPL's Current Report on Form 8-K dated March 4, 1998; File No. 1-1405). 3-J Copy of DPL's By-Laws as amended March 2, 1998 (filed with DPL's Current Report on Form 8-K dated March 4, 1998; File No. 1-1405). 4-A Copy of the Mortgage and Deed of Trust of Delaware Power & Light Company to the New York Trust Company, Trustee, (the Chase Manhattan Bank, successor Trustee) dated as of October 1, 1943 and copies of the First through Sixty-Eighth Supplemental Indentures thereto. (Filed with Registration Statement No. 33-1763.)

4-B Copy of the Sixty-Ninth Supplemental Indenture. (Filed with Registration Statement No. 33-39756.)

4-C Copies of the Seventieth through Seventy-Fourth Supplemental Indentures. (Filed with Registration Statement No. 33-24955.)

4-D Copies of the Seventy-Fifth through the Seventy-Seventh Supplemental Indentures. (Filed with Registration Statement No. 33-39756.)

4-E Copies of the Seventy-Eighth and Seventy-Ninth Supplemental Indentures. (Filed with Registration Statement No. 33-46892.)

4-F Copy of the Eightieth Supplemental Indenture. (Filed with Registration Statement No. 33-49750.)

4-G Copy of the Eighty-First Supplemental Indenture. (Filed with Registration Statement No. 33-57652.)

4-H Copy of the Eighty-Second Supplemental Indenture. (Filed with Registration Statement No. 33-63582.)

4-I Copy of the Eighty-Third Supplemental Indenture. (Filed with Registration Statement No. 33-50453.)

4-J Copies of the Eighty-Fourth through Eighty-Eighth Supplemental Indentures. (Filed with Registration Statement No. 33-53855.)

4-K Copies of the Eighty-Ninth and Ninetieth Supplemental Indentures. (Filed with Registration Statement No. 333-00505.)

4-L A copy of the Indenture between DPL and The Ch_ase Manhattan Bank (ultimate successor to Manufacturers Hanover Trust Company), as Trustee, dated as of November 1, 1988. (Filed with Registration Statement No. 33-46892.)

4-M A copy of the Indenture (for Unsecured Subordinated Debt Securities relating to Trust Securities) between DPL and Wilmington Trust Company, as Trustee, dated as of October 1, 1996. (Filed with Registration Statement No. 333-20715.)

4-N A copy of the Officer's Certificate dated October 3, 1996, establishing the 8.125% Junior Subordinated Debentures, Series I, Due 2036. (Filed with Registration Statement No. 333-20715.)

4-0 A copy of the Guarantee Agreement between DPL, as Guarantor, and Wilmington Trust Company, as Trustee, dated as of October 1, 1996. (Filed with Registration Statement No. 333-20715.)

4-P A copy of the Amended and Restated Trust Agreement between DPL, as Depositor, and Wilmington Trust Company, Barbara S. Graham, Edric R. Mason and Donald P. Connelly, as Trustees, dated as of October 1, 1996. (Filed with Registration Statement No. 333-20715.)

4-Q A copy of the Agreement as to Expenses and Liabilities dated as of October 1, 1996, between DPL and Delmarva Power Financing I. (Filed with Registration Statement No. 333-20715.)

10-A Copy of the Supplemental Executive Retirement Plan, revised as of October 29, 1991. (Filed with Form 10-K for the year ended December 31, 1992, File No. 1-1405.) IV-2

• Exhibit Number 10-B Copies of amendments to the Supplemental Executive Retirement Plan, effective June 15,'

1994, and November 1, 1994. (Filed with Form 10-K for the year ended December 31, 1994, File No. 1-1405.) 10-C Copy of the Long Term Incentive Plan amended and restated as of January 1, 1996. (Filed with Form 10-K for the year ended December 31, 1996, File No. 1-1405.) 10-D Copies of amendments to the Long Term Incentive Plan, effective January 1, 1997, and January 30, 1997. (Filed with Form 10-K for the year ended December 31, 1996, File No. 1-1405.) 10-E Copy of the severance agreement with members of management. (Filed with Form 10-K for the year ended December 31, 1994, File No. 1-1405.) 10-F Copy of the current listing of members of management who have signed the severance agreement. (Filed with Form 10-K for the year ended December 31, 1996, File No. 1-1405.) 10-G Copy of the Management Life Insurance Plan amended and restated as of January 1, -1992. (Filed with Form 10-K for the year ended December 31, 1996, File No. 1-1405.) 10-H Copy of the Deferred Compensation Plan, effective as of January 1, 1996. (Filed with the Form 10-K for the year ended December 31, 1995, File No. 1-1405.) 12-A Computation of ratio of earnings to fixed charges. 12-B Computation of ratio of earnings to fixed charges and preferred dividends.

23 Consent of Independent Accountants.

27 Financial Data Schedule. (b) No Reports on Form 8-K were filed during the fourth quarter of 1998. On January 26, 1999, DPL filed a Report on Form 8-K under Item 5, Other Events, concerning proposed legislation in Delaware to restructure the electric utility industry.

IV-3 DELMARVA POWER & LIGHT COMPANY SCHEDULE OF OPERATING STATISTICS FOR THE THREE YEARS ENDED DECEMBER 31, 1998 The table below sets forth selected financial and operating statistics for DPL's electric and gas businesses for the three years ended December 31, 1998. 1998 1997 1996 ELECTRIC:

Electricity generated and purchased (MWH): Generated

..................................... . 9,657,472 9,067,236 10,307,299 Purchased

.................................... . 6,510,738 5,908,796 6,195,720 Interchange deliveries

........................... . (1,968,200)

(1,078,471)

(2,855,109)

Total system output for load .................... . 14,200,010 13,897,561 13,647,910 Nonregulated purchases

........................ . 7,324,399 4,201,619 -Total output .................................... . 21,524,409 18,099,180 13,647,910 Electric sales (MWH): Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . 4,183,854 4,097,773 4,262,710 Commercial

.................................. . 4,288,876 4,091,636 4,018,120 Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3,645,901 3,598,006 3,331,175 Resale ...................................... . 1,236,489 1,335,226 1,333,268 Other sales (1) ................................ . 73,983 109,124 (19,557) Total service territory sales ..................... . 13,429,103 13,231,765 12,925,716 Merchant sales (2) ............................. . 7,713,418 4,201,619 Total sales excluding interchange

................. . 21,142,521 17,433,384 12,925,716 Losses and miscellaneous system uses . . . . . . . . . . . . . . . . . .

381,888 665,796 722,194 Total disposition of energy ..................... . 21,524,409 18,099,180 13,647,910 Operating revenue (thousands):

Residential

... : ............................... . $ 378,515 $ 377,528 $ 378,520 Commercial

.................................. . 304,477 299,649 286,438 Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

169,174 173,413 156,329 Resale ...................................... . 67,104 68,315 65,989 Miscellaneous revenues (3) ....................... . 36,478 34,451 24,344 Total service territory

......................... . 955,748 953,356 911,620 Interchange deliveries

........................... . 99,182 36,430 75,301 Merchant revenues (2) ........................... . 274,463 102,358 Total revenues ............................... . $ 1,329,393

$ 1,092,144

$ 986,921 Number of customers (end of period): Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

402,536 396,798 391,611 Commercial

.................................. . 51,454 50,216 49,165 Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

657 672 683 Resale ...................................... . 12 12 12 Other ....................................... . 647 624 645 Total customers (4) ........................... . 455,306 448,322 442,116 (Table continued on next page) IV-4 r -DELMARVA POWER & LIGHT COMPANY SCHEDULE OF OPERATING STATISTICS-(Continued)

FOR THE THREE YEARS ENDED DECEMBER 31, 1998 GAS: Gas sales and gas transported (Met): Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Commercial

........................................ . Industrial

.......................................... . Interruptible, transportation and other . . . . . . . . . . . . . . . . . . . . . .

Total service territory

............................... . Merchant sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total ........................................... . Operating revenue (thousands):

Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Commercial

........................................ . Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Interruptible, transportation and other ..................... . Total service territory

............................... . Merchant revenues ................................... . Total ........................................... . Number of customers (end of period): Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Commercial

........................................ . Industrial

.......................................... . Interruptible, transportation and other ..................... . Total customers (4) ................................. . (1) Includes unbilled sales. (2) Offsystem, competitive sales and other services.

(3) Includes unbilled revenues and other miscellaneous revenue's.

(4) Service territory only. IV-5

• 1998 6,812 4,705 2,751 7,319 21,587 156,741 178,328 $ 57,809 31,954 11,311 6,113 107,187 427,895 $535,082 97,558 7,975 123 105,656 1997 1996 7,844 8,692 5,313 5,724 2,772 2,696 6,926 5,312 22,855 22,424 27,216 1,733 50,071 24,157 $ 63,937 $ 60,017 34,895 32,191 12,582 12,349 5,776 5,085 117,190 109,642 86,867 4,642 $204,057 $114,284 95,295 93,149 7,793 7,615 128 139 1 103,216 100,904

,--------SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 26, 1999. DELMARVA POWER & LIGHT COMPANY (REGISTRANT)

By: ____ l_s_l_J_oHN

__ c_._v_A_N_R_o_D_E_N

____ (John C. van Roden, Senior Vice President and Chief Financial Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated, on March 26, 1999. Signature Isl How ARD E. COSGROVE (Howard E. Cosgrove)

Isl JoHN C. v AN RODEN (John C. van Roden) Isl JAMES P. LAVIN (James P. Lavin) Isl MEREDITH I. HARLACHER, JR. **************************************************************************** (Meredith I. Har/acher, Jr.) Isl THOMAS S. SHAW (Thomas S. Shaw) Isl BARRY R. ELSON (Barry R. Elson) Isl BARBARA S. GRAHAM (Barbara S. Graham) Isl AUDREY K. DOBERSTEIN (Audrey K. Doberstein)

Isl JERROLD L. JACOBS (Jerrold L. Jacobs) Title Chairman of the Board and Chief Executive Officer Senior Vice President and Chief Financial Officer Controller and Chief Accounting Officer Director Director Director Director Director Director IV-6 *

• I -i * [THIS PAGE INTENTIONALLY LEFT BLANK]

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 OR 0 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-3559 ATLANTIC CITY ELECTRIC COMPANY (Exact name of registrant as specified in its charter) New Jersey (State of Incorporation) 21-0398280 (I.R.S. Employer Identification No.) 800 King Street, P.O. Box 231 Wilmington, Delaware 19899 * (Address of principal executive offices) Registrant's telephone number (302) 429-3114 Securities registered pursuant to Section 12(b) of the Act: Title of each class 8.25% Cumulative Quarterly Income Preferred Securities, liquidation preference

$25 per preferred security issued by Atlantic Capital I 7% % Cumulative Trust Preferred Capital Securities, liquidation preference

$25 per preferred security issued by Atlantic Capital II Name of each exchange on which registered New York Stock Exchange New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 1ZJ No D Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 1Zi All 18,320,937 issued and outstanding shares of Atlantic City Electric Company common stock, $3 per share par value, are owned by Conectiv.

• TABLE OF CONTENTS Page Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

ii PART I Item 1. Business General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1-1 Competition and Electric Utility Industry Restmcturing

......................................

• . I-1 Installed Capacity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-2 Electricity Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-2 Pennsylvania-New Jersey-Maryland Interconnection Association . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-3 Purchased Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-3 Nuclear Power Plants....................................................................

I-4 Fuel Supply for Electric Generation........................................................

I-5 Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-5 Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-5 Gas.................................................................................

I-6 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-6 Regulatory Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-6 Electric Retail Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-6 Off-Tariff Rates ..................................................

• ....................

I-7 Levelized Energy Adjustment Clause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-7 Electric Distribution Service Reliability and Quality Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-7 Other Regulatory Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-8 Capital Spending and Financing Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-8 Environmental Matters...................................................................

I-9 Air Quality Regulations................................................................

I-9 Water Quality Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-9 Hazardous Substances

.....................................

• ............................

I-10 Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-11 Item 2. Properties.....................................................................

I-12 Item 3. Legal Proceedings..............................................................

I-13 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I-13 PARTil Item 5. Item 6. Item 7. Item 8. Item 9. Market for Registrant's Common Equity and Related Stockholder Matters .............. . Selected Financial Data ......................................................... . Management's Discussion and Analysis of Financial Condition and Results of Operations

.. Financial Statements and Supplementary Data ...................................... . Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

.. PART ID Item 10. Directors and Executive Officers of the Registrant

................................... . Item 11. Executive Compensation

........................................................ . Item 12. Security Ownership of Certain Beneficial Owners and Management

.................... . Item 13. Certain Relationships and Related Transactions

..................................... . PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K .................... . Signatures

.............................................................................. . II-1 Il-2 II-3 II-11 II-37 III-1 III-2 III-11 III-11 IV-1 IV-5 GLOSSARY The following glossary lists the abbreviations used in this report. Term 7% % Debentures

........................ . 8.25% Debentures

....................... . 1992 Energy Act ........................ . ACE .................................. . the Act ................................ . AFUDC ................................ . Atlantic ...........

.................... . ALJ .........................

• .......... . BGS ................................... . Clean Water Act ........................ . CRP ................................... . D&D Fund ............................. . DOE .................................. . DPL ................................... . DSM .................................. . FASB ................................. . FERC ................................. . GAAP ................................. . Hope Creek ............................. . IPP .................................... . kWh ................................... . LEC ................................... . Litigation Reform Act .................... . LLRW ................................. . LMP .................................. . MD&A ................................ . Merger ................................. . Mortgage ............................... . MW ................................... . NERC ................................. . NJBPU ................................ . NJDEP ................................ . NJPDES ............................... . NOTR ................................. . NOX ************************************

NPDES ................................ . NRC .................................. . NWPA ................................. . Peach Bottom ........................... . PECO ................................. . PJM Interconnection

..................... . PSE&G ................................ . PUHCA ................................ . Definition 7% % Junior Subordinated Debentures 8.25% Junior Subordinated Deferrable Interest Debentures National Energy Policy Act of 1992 Atlantic City Electric Company The Electric Discount and Energy Competition Act Allowance For Funds Used During Construction Atlantic Energy, Inc. Administrative Law Judge Basic Generation Service

• Federal Water Pollution Control Act Conectiv Resource Partners, Inc. Decontamination

& Decommissioning Fund United States Department of Energy Delmarva Power & Light Company Demand Side Management Plan Financial Accounting Standards Board Federal Energy Regulatory Commission Generally Accepted Accounting Principles Hope Creek Nuclear Generating Station Independent Power Producer Kilowatt-hour Levelized Energy Clause The Private Securities Litigation Reform Act of 1995 Low Level Radioactive Waste Locational Marginal Pricing Management's Discussion and Analysis of Financial Condition and Results of Operations A series of merger transactions by which DPL and ACE became subsidiaries of Conectiv Mortgage and Deed of Trust Megawatt North American Electric Reliability Council New Jersey Board of Public Utilities New Jersey Department of Environmental Protection New Jersey Pollution Discharge Elimination System Northeast Ozone Transport Region Oxides of Nitrogen National Pollution Discharge Elimination System Nuclear Regulatory Commission Nuclear Waste Policy Act of 1982 Peach Bottom Atomic Power Station PECO Energy Company Pennsylvania-New Jersey-Maryland Interconnection Association Public Service Electric and Gas Company Public Utility Holding Company Act of 1935 ii -1 * *

• I _J

'** *

• Term PURPA ................................ . RACT ................................. . RISC .................................. . RTP ................................... . Salem ................................. . SALP .................................. . SEC ................................... . SFAS .................................. . SFAS No. 71 ........................... . SFAS No. 88 SFAS No. 128 SFAS No. 131 SFAS No. 133 S0 2 ***********************************

TEFA ................................. . USEPA ................................ . VRDB ................................. . Westinghouse

........................... . Definition Public Utility Regulatory Policy Act of 1978 Reasonably Available Control Technology Rate Intervention Steering Committee Real Time Pricing Salem Nuclear Generating Station Systematic Assessment of Licensee Performance Securities and Exchange Commission Statement of Financial Accounting Standards SFAS No. 71, "Accounting For the Effects of Certain Types of Regulation" SFAS No. 88, "Employers' Accounting For Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits

SFAS No. 128, "Earnings Per Share" SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities

Sulfur Dioxide Transitional Energy Facility Assessment Tax United States Environmental Protection Agency Variable Rate Demand Bonds Westinghouse Electric Corporation ill

---i I ! * [THIS PAGE INTENTIONALLY LEFT BLANK] *

• PART I Item 1. Business.

General Atlantic City Electric Company (ACE) is a regulated public electric utility and a subsidiary of Conectiv, which is a Delaware corporation and a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). ACE was organized under the laws of New Jersey on April 28, 1924 by merger and consolidation of several utility companies.

ACE holds the franchises necessary to provide regulated electric service in its service territory.

ACE is primarily engaged in generating, purchasing, delivering, and selling electricity.

ACE serves approximately 488,800 customers in its service territory which covers an area of about 2,700 square miles in the southern one-third of New Jersey and has a population of approximately 850,000. ACE's customer base is comprised primarily of residential and commercial customers.

In 1998, the percentages of retail electric revenues contributed by customer class were as follows: residential-47.3%;

commercial-41.1

%; and industrial I other-11.6%. ACE's utility business is subject to regulation with respect to its retail electric sales by the New Jersey Board of Public Utilities (NJBPU). The Federal Energy Regulatory Commission (FERC) also has regulatory authority over certain aspects of ACE's electric utility business, including the transmission of electricity, the sale of electricity tO municipalities and electric cooperatives, and interchange and other purchases and sales of electricity involving other utilities.

ACE is also subject to regulation by the Pennsylvania Public Utility Commission in limited respects concerning property and operations in Pennsylvania.

On March 1, 1998, ACE and Delmarva Power & Light Company (DPL) became wholly-owned subsidiaries of Conectiv (the Merger). Before the Merger, ACE was owned by Atlantic Energy, Inc. (Atlantic).

As a result of the Merger, Atlantic no longer exists and Conectiv owns, directly or indirectly, ACE, DPL and the nonutility subsidiaries formerly held separately by Atlantic and DPL. Conectiv is a registered holding company under PUHCA, which imposes certain restrictions on the operations of registered holding companies and their subsidiaries.

As of December 31, 1998, ACE had 857 employees, of which 524 were represented by a collective bargaining labor organization.

During 1998, ACE reduced its workforce by 573 employees, including 354 employees separated through Merger-related employee separation programs and 219 employees transferred to Conectiv Resource Partners, Inc. (CRP), a Conectiv subsidiary and service company established pursuant to PUHCA. CRP provides a variety of support services to Conectiv subsidiaries, and its employees are primarily former DPL and ACE employees.

The costs of CRP are directly assigned, distributed and allocated to the Conectiv subsidiaries using CRP' s services, including ACE. For additional information about the Merger, refer to Note 4 to ACE's 1998 Consolidated Financial Statements included in Item 8 of Part II. For information concerning ACE's business segments, refer to Note 18 to ACE's 1998 Consolidated Financial Statements included in Item 8 of Part II. Competition and Electric Utility Industry Restructuring For information concerning restructuring the electric utility industry in New Jersey and the Electric Discount and Competition Act (the Act), see Note 5 to ACE's 1998 Consolidated Financial Statements included in Item 8 of Part IL Under the Act, New Jersey electric customers may choose an electricity supplier beginning August 1, 1999. Customers will continue to pay the local utility a regulated price for delivery of electricity over the transmission and distribution system. As electric utility industry restructuring is implemented in ACE's and other utilities' service territories, gross margins earned from supplying electricity are expected to decrease as I-1 competition to supply customers with electricity increases.

As a greater percentage of ACE's revenues become subject to competition, financial risks and rewards, and the volatility of earnings are expected to increase.

ACE's ability to continue reducing costs by streamlining operations, regulatory decisions pursuant to restructuring under the Act, retention of existing customers and the ability to gain new customers are significant determinants of ACE's future success. Installed Capacity The megawatts (MW) of net installed summer electric generating capacity available to ACE to serve its peak load as of December 31, 1998, are presented below. See Item 2, Properties, for additional information.

% of Source of Capacity MW Total Coal-fired generating units ............................................... . 471 19 Oil-fired generating units ................................................ . 295 12 Combustion turbines/combined cycle generating units ........................ . 524 21 Nuclear generating units ................................................. . 380 15 Diesel units ........................................................... . 9 Long-term purchased capacity ............................................ . 828 33 Subtotal ............................................................... . 2,507 100 Short-term purchased capacity ............................................ . __ 9 Total ................................................................. . 2,516 100 ---The net generating capacity available for operations at any time may be less than the total net installed

• generating capacity due to generating units being out of service for inspection, maintenance, repairs, or unforeseen circumstances.

As restructuring of the electric utility industry is implemented, ACE expects to sell some of its generating units. ACE has identified certain generating assets that may be sold, but has not determined when such sale, or sales, would occur. Electricity Supply As a member of the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM Interconnection), ACE is obligated to maintain capacity levels based on its allocated share of estimated aggregate PJM Interconnection capacity requirements. (The PJM Interconnection is discussed on page I-3.) ACE periodically updates its forecast of peak demand and PJM Interconnection reserve requirements, and re-evaluates resources available to supply projected growth. Any short-term capacity deficiencies related to obligations to the PJM Interconnection are expected to be satisfied through short-term capacity-only purchases.

Incremental energy supply needs are expected to be filled through purchased power. ACE experienced it highest historical peak demand of 2,162 MW on July 22, 1998, which was 1.6% above the previous peak demand of 2,127 MW recorded on August 16, 1997. ACE's capacity obligation to the PJM Interconnection, which includes a reserve margin, is based on normal weather conditions and full implementation of its demand-side management programs.

Under these conditions, ACE's 1998 peak demand would have been approximately 2,115 MW. ACE's installed capacity of 2,501 MW at the time of the peak resulted in a reserve

• margin of 18%, computed under PJM Interconnection guidelines.

ACE's reserve obligation to the PJM Interconnection is approximately 20%. I-2

• *

• The sources of the electricity supplied to ACE's customers during 1998, 1997, and 1996 are shown below: Source of Electricity 1998 1997 1996 Generation fuel type Coal ............................................................ . 26% 26% 28% Nuclear .......................................................... . 29 18 15 Oil/N"atural Gas ................................................... . 4 3 2 Interchange and Purchased Power ...................................... . 12 30 35 Nonutility Purchased Power .......................................... . 29 23 20 Total ............................................................ . 100% 100% 100% Pennsylvania-New Jersey-Maryland Interconnection Association As a member of the PJM Interconnection, ACE's generation and transmission facilities are operated on an integrated basis with other electricity suppliers in Pennsylvania, New Jersey, Maryland, and the District of Columbia, and are interconnected with other major utilities in the United States. This power pool improves the reliability and operating economies of the systems in the group and provides capital economies by permitting shared reserve requirements.

The PJM Interconnection's installed capacity as of December 31, 1998, was 57,551 MW. The PJM Interconnection peak's demand during 1998 was 48,663 MW on August 15, which resulted in a summer reserve margin of 18.2% (based on installed capacity of 57,511 MW on that date). On October 15, 1998, the PJM Interconnection began operating a centralized capacity credit market, providing a new option to participants for procuring and selling surplus capacity to meet reliability obligations within the PJM Interconnection region. Capacity is the capability to produce electric power, typically from owned generation or third-party purchase contracts and differs from the electric energy markets, which trade the actual energy being generated.

This market facilitates the selling and buying of capacity for participants by providing a single point of contact for market participants and a published capacity market clearing price . Effective April 1, 1998, the PJM Interconnection implemented locational marginal pricing (LMP) to establish the market clearing prices for electric energy and to price electric transmission usage based upon costs associated with transmission system congestion.

When there is no congestion on the power system and energy is flowing on the grid in an unconstrained manner, energy prices are cleared at the highest bid accepted by the PJM Interconnection for the entire PJM Interconnection region. When a limit is reached on the transmission grid, the PJM Interconnection will operate generators to preserve system reliability.

LMP allows the PJM Interconnection to send price signals to raise and lower generator output when the power flows are constrained.

Different energy market clearing prices are paid by wholesale power buyers and sellers on the power grid that reflect the value relative to a system constraint.

LMP provides for an efficient allocation of congestion costs to transmission users within the PJM Interconnection region. The FERC has approved the use of the LMP congestion management system to allow electric energy market participants with power contracts on neighboring electric systems to compensate the PJM Interconnection for any unintended flows on the PJM Interconnection system, rather than forcing those participants to curtail their contracts.

Currently, the PJM Interconnection Operating Agreement requires bids to sell electricity received from generation located within the PJM Interconnection control area not to exceed the variable cost of producing such electricity.

Transactions that are bid into the PJM pool from generation located outside the PJM Interconnection control area are capped at $1,000 per megawatt hour. All power providers are paid the LMP set through power providers' bids. Certain PJM Interconnection members have requested that FERC revise the PJM Interconnection Operating Agreement to allow the submission of market based bids to the PJM Interconnection energy market. Purchased Power The Public Utility Regulatory Policy Act of 1978 (PURPA) established a class of nonutility power suppliers, known as independent power producers (IPPs), and required electric utilities to purchase the excess power from IPPs. As a result of PURPA, ACE has long-term contracts with four IPPs for the purchase of 659 MW of capacity and energy. In view of electric utility industry restructuring, various parties continue to seek the repeal of PURPA; however, federal action with regard to PURPA is not likely to affect ACE's IPP contracts.

1-3 ACE's NJBPU-approved IPP contracts are shown below. MW Date of Project Location Fuel Type Provided Commercial Operation Chester, Pennsylvania

........................... . solid waste 75 September 1991 Pedricktown, New Jersey ........................ . gas 116 March 1992 Carney's Point, New Jersey ...................... . coal 249 March 1994 Logan Township, New Jersey ..................... . coal 219 September 1994 Total ................................. . 659 ACE is also currently purchasing 125 MW of capacity and energy from PECO Energy Company (PECO) under a contract which ends May 31, 2000. This agreement replaced a terminated agreement with Pennsylvania Power & Light Company, effective March 1998. ACE also contracts with other electric suppliers on an as-needed basis for the purchase of short-term generating capacity, energy and transmission capacity.

Nuclear Power Plants ACE owns 5% of the 1,031 MW, Hope Creek Nuclear Generating Station (Hope Creek) and 7.41 % of the 2,212 MW, Salem Nuclear Generating Station (Salem). The Hope Creek Unit and Salem Units 1 and 2 are located adjacent to each other in Salem County, New Jersey, and are operated by Public Service Electric & Gas (PSE&G). ACE also owns 7.51 % of the 2,186 MW, Peach Bottom Atomic Power Station (Peach Bottom), which has Units 2 and 3, is located in York County, Pennsylvania, and is operated by PECO. ACE's ownership share in nuclear power plants provided approximately 15% of its installed capacity as of December 31, 1998. In 1998, ACE's share of output from the jointly-owned nuclear power plants provided 29% of the electricity used by ACE's customers.

See Note 7 to ACE's 1998 Consolidated Financial Statements included in Item 8 of Part II for information about ACE's investment in jointly-owned generating stations.

The operation of nuclear generating units is regulated by the Nuclear Regulatory Commission (NRC). Such regulation requires that all aspects of plant operation be conducted in accordance with NRC safety and environmental requirements and that continuous demonstrations be made to the NRC that plant operations meet applicable requirements.

The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. As a by-product of nuclear operations, nuclear generating units produce low-level radioactive waste (LLRW). LLRW is accumulated on-site until shipped to a federally licensed permanent disposal facility.

Salem, Hope Creek, and Peach Bottom have on-site interim storage facilities with five-year storage capacities.

For a discussion of the cycle of production, use and disposal of nuclear fuel, see Nuclear

on page I-6. For a discussion of ACE's funding of its share of the estimated future cost of decommissioning the Hope Creek, Peach Bottom, and Salem nuclear reactors, see Note 15 to ACE's 1998 Consolidated Financial Statements included in Part II, Item 8. The NRC is requiring nuclear plant operators to report by July 1, 1999, that their nuclear power plants are Year 2000 ready, or will be Year 2000 ready, by January 1, 2000. PSE&G and PECO have informed ACE that they are on schedule to meet the July 1, 1999 response date and that their nuclear operations' Year 2000 programs will make Salem, Hope Creek, and Peach Bottom Year 2000 ready by January 1, 2000. Salem Units 1 and 2 were removed from operation by PSE&G in the second quarter of 1995 due to operational problems, and maintenance and safety concerns.

Due to degradation of a significant number of tubes in the Unit 1 steam generators, PSE&G replaced the Unit 1 steam generators.

After receiving NRC authorization,

• PSE&G returned Unit 2 to service on August 30, 1997, and Unit 1 to service on April 17, 1998. On July 29,

• 1998, the NRC removed Salem from its "watch list" of troubled nuclear plants. The Salem Unit 2 steam generators will be inspected for tube degradation in upcoming outages. 1-4

• *

• See Note 13 to ACE's 1998 Consolidated Financial Statements included in Part II, Item 8, for information concerning ACE's lawsuit against Westinghouse Electric Corporation, the designer and manufacturer of the Salem steam generators, and the financial impact of the outages. Systematic Assessment of Licensee Performance (SALP) reports issued by the NRC rate licensee performance in four assessment areas: Operations, Maintenance, Engineering and Plant Support. Ratings range from a high of "l" to a low of "3." In September 1998, the NRC issued a SALP Report on the performance of activities at Salem for the period March 1, 1997, to August 1, 1998. Salem received a rating of 1 in Operations, a 2 in Maintenance, a 2 in Engineering, and a 1 in Plant Support. The NRC noted that the overall performance at Salem improved, as demonstrated by a nearly event-free return of both units to operation following the extended outage. On June 8, 1998, the NRC issued a SALP report on Hope Creek for the period November 10, 1996, to May 16, 1998. Hope Creek received a rating of 2 in the areas of Operations, Maintenance, and Engineering, and a rating of 1 in the area of plant support. The NRC noted improved performance in all functional areas during the period. On July 17, 1997, the NRC issued a SALP report on Peach Bottom for the period October 15, 1995, to June 7, 1997. Peach Bottom received a rating of 1 in the areas of Operations, Maintenance, and Plant Support, and 2 in Engineering.

On September 16, 1998, the NRC announced that it was suspending the SALP report process until it completes a review of its nuclear power plant performance assessment process. The SALP process has not yet been resumed or replaced.

Fuel Supply for Electric Generation ACE's electric generating capacity by fuel type is shown under "Installed Capacity" on page 1-2. To facilitate the purchase of adequate amounts of fuel at reasonable prices, ACE contracts with various suppliers of coal, oil, and natural gas on both a long-and short-term basis. Prices under oil and natural gas contracts are generally determined by market-based indices. Coal B.L. England Units 1 and 2, Deepwater Unit 6, and the Keystone and Conemaugh Generating Stations are coal-fired.

During 1998, 92% of ACE's coal supply for these units was purchased under two long-term contracts, which expire in April 1999 and June 2001, and the balance was purchased on the spot market. Approximately 56% of ACE's projected coal requirements are expected to be provided under supply contracts.

ACE does not anticipate any difficulty in obtaining adequate amounts of coal at reasonable prices. Oil Currently, 100% of the residual oil used in B.L. England Unit 3 and Deepwater Unit 1 is supplied under a three-year contract that expires October 31, 2000. Another three-year contract which expires October 31, 2000, provides all of the distillate oil supply for ACE's combustion turbines.

1-5 Gas Natural gas is the primary fuel for six of ACE's combustion turbines and a secondary fuel at Deepwater Units 1 and 6. Natural gas for ACE's gas-fired generating units is purchased primarily from the local gas distribution company on a firm basis and is also purchased from other suppliers, such as marketers, producers, and utilities.

The gas is delivered under contract through the interstate pipeline system. Nuclear The supply of fuel for nuclear generating units involves the mining and milling of uranium ore to uranium concentrate, conversion of the uranium concentrate to uranium hexafiouride, enrichment of the uranium hexafiouride gas, conversion of the enriched gas to fuel pellets, and fabrication of fuel assemblies.

After spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station ,site. The federal government has an obligation for the transportation and ultimate disposal of the spent fuel, as discussed below. PSE&G has informed ACE it has several long-term contracts with uranium ore operators, converters, enrichers and fabricators to process uranium ore to uranium concentrate to meet the currently projected requirements for Salem and Hope Creek. ACE has also been advised by PECO that it has similar contracts to satisfy the fuel requirements of Peach Bottom. Currently, there is an adequate supply of nuclear fuel for Salem, Hope Creek, and Peach Bottom. In conformity with the Nuclear Waste Policy Act of 1982 (NWPA), PSE&G and PECO have entered into contracts with the United States Department of Energy (DOE) on behalf of the joint owners providing that the

• federal government shall for a fee take title to, transport, and dispose of spent nuclear fuel and high level radioactive waste'from the Salem, Hope Creek, and Peach Bottom reactors.

In accordance with the NWPA, ACE

• pays the DOE one-tenth of one cent per kilowatt-hour (kWh) of nuclear generation (net of station use) for the future cost of spent nuclear fuel disposal.

Under the NWPA, the DOE was to begin accepting spent fuel for permanent off-site storage no later than January 1998. However, no such repositories are in service or under construction.

The DOE has stated that it would not be able to open a permanent, high level nuclear waste storage facility until 2010, at the earliest.

Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent nuclear fuel storage installations located at or away from reactor sites for at least 30 years beyond the licensed life for operation (which may include the term of a revised or renewed license).

PSE&G has advised ACE that, as a result of reracking the two spent fuel storage pools at Salem, the availability of spent fuel storage capacity is estimated to be adequate through 2012 for Unit 1 and 2016 for Unit 2. PSE&G has also advised ACE that the Hope Creek pool is also fully racked and it is expected to provide adequate storage capacity until 2006. PECO has advised ACE that spent fuel racks at Peach Bottom have storage capacity until 2000 for Unit 2 and until 2001 for Unit 3. PECO has also advised ACE that it is constructing an on-site dry storage facility, which is expected to be operational in 2000, to provide additional storage capacity.

Regulatory Matters For information concerning restructuring the electric utility industry in New Jersey, see Note 5 to ACE's 1998 Consolidated Financial Statements included in Item 8 of Part II. Electric Retail Rates ACE's base rates for retail electric service are subject to the approval of the NJBPU. However, the utility ratemaking process is changing in New Jersey, as discussed in Note 5 to ACE's 1998 Consolidated Financial

• Statements included in Item 8 of Part IL I-6

• For information concerning base rate increases and decreases affecting the 1996-1998 results of operations, including the Merger-related base rate decrease and base rate decreases expected in connection with the electric utility industry restructuring, see Notes 3, 5 and 13 to ACE's 1998 Consolidated Financial Statements included in Item 8 of Part IL Off-Tariff Rates Legislation enacted in New Jersey in July 1995 allows the NJBPU, upon petition from any electric or gas utility, to adopt a plan of regulation other than the traditional rate-base/rate-of-return regulation.

In addition, on a case-by-case basis, the law allows utilities to petition the NJBPU for the right to offer customers, who meet certain conditions, off-tariff, discounted rates. Off-tariff pricing arrangements with certain ACE customers have been arranged.

Refer to "Electric Revenues" in ACE's Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) herein for further information regarding off-tariff rates (OTRAs). Levelized Energy Adjustment Clause Information concerning the Levelized Energy Adjustment Clause (LEC) is included in the Notes to ACE's 1998 Consolidated Financial Statements (Part II, Item 8) as follows: (i) the operation of the LEC and deferred energy accounting are discussed under "Deferred Energy Costs" in Note 1, (ii) the nuclear performance standard is discussed under "Other Rate Matters" in Note 5, and (iii) the financial impact of extended outages at Salem is discussed in Note 13. In January 1999, ACE filed with the NJBPU a petition requesting that the estimated cost of oxides of nitrogen (NOJ allowances in 1999 of $4.8 million be included in LEC rates. A ruling on this matter is expected during 1999. For information concerning NOx emission regulations, see "Air Quality Regulations" on page I-9. On April 11, 1997, the Rate Intervention Steering Committee (RISC) submitted its brief on its appeal to the Superior Court of New Jersey in response to the NJBPU's decision which provided for ACE's recovery (through LEC rates) of the cost of power purchased from IPPs. In May 1998, the Superior Court of New Jersey rejected RISC' s appeal and upheld the NJBPU' s decision providing for LEC recovery of IPP purchased power costs. In May 1998, RISC appealed the Superior Court's decision to the Supreme Court of New Jersey, which denied RISC's_ appeal in July 1998. The LEC is expected to be superceded by provisions contained in the Act which permit Basic Generation Service (BGS) suppliers full and timely recovery of their costs. The Act also authorizes the NJBPU to allow the deferral and subsequent recovery of BGS costs if necessary for attainment of the rate reductions required by the Act. Regulations governing BGS are expected to be promulgated by the NJBPU prior to beginning retail choice of electricity suppliers in New Jersey. Electric Distribution Service Reliability and Quality Standards On December 30, 1997, the NJBPU directed its Staff to initiate an inquiry into establishing measurable performance and reliability standards for New Jersey electric and gas utilities.

The Staff's most recent draft proposal does not propose monetary penalties, but does require establishment of utility specific standards and contains potentially costly and burdensome reporting requirements.

The NJBPU is expected to review this matter in 1999. I-7 Other Regulatory Matters The 1992 Energy Act provided for creation of a Decontamination

& Decommissioning (D&D) Fund to pay for the future clean-up of DOE gaseous diffusion enrichment facilities.

Domestic utilities and the federal government are required to make payments to the D&D Fund until 2008 or $2.25 billion, adjusted annually for inflation, is collected.

The liability accrued for ACE's share of the D&D Fund was $5.7 million as of December 31, 1998. ACE is recovering this cost through LEC revenues.

ACE has cost allocation and direct charging mechanisms in place to ensure that there is no subsidization of its competitive activities by regulated utility activities.

In accordance with the NJBPU's order which approved the Merger, ACE filed Conectiv's Cost Accounting Manual and the Service Agreement between ACE and CRP with the NJBPU on October 28, 1998. Certain types of transactions between ACE and its affiliates may require prior approval of the NJBPU. The New Jersey Public Utility Fault Determination Act requires the NJBPU to make a determination of fault with regard to any past or future accident at any electric generating or transmission facility, prior to granting a utility's request for a rate increase to cover accident-related costs in excess of $10 million. However, the law allows a utility to file for non-accident related rate increases during such fault determination hearings and to recover contributions to federally mandated or voluntary cost-sharing plans. The law further allows the NJBPU to authorize the recovery of certain fault-related repair, cleanup, replacement power or damage costs, if appropriate.

Capital Spending and Financing Program For financial information concerning ACE's capital spending and financing program, refer to "Liquidity and Capital Resources" in the MD&A included in Item 7 of Part II and Notes 8 and 9 to ACE's 1998 Consolidated Financial Statements, included in Item 8 of Part II. ACE's ratios of earnings to fixed charges and earnings to fixed charges and preferred stock dividends under the Securities and Exchange Commission (SEC) Methods for 1994-1998 are shown below. Year Ended December 31, 1998 1997 1996 1995 1994 Ratio of Earnings to Fixed Charges (SEC Method) ...............

1.66 2.84 2.59 3.19 3.07 Ratio of Earnings to Fixed Charges and Preferred Stock Dividends (SEC Method) ...........................................

1.55 2.58 2.16 2.43 2.26 Under the SEC Method, earnings, including Allowance For Funds Used During Construction (AFUDC), have been computed by adding income taxes and fixed charges to net income. Fixed charges include gross interest expense, the estimated interest component of rentals, and dividends on preferred securities of subsidiary trusts. For the ratio of earnings to fixed charges and preferred stock dividends, preferred stock dividends represent annualized preferred stock dividend requirements multiplied by the ratio that pre-tax income bears to *

• net income. Excluding Merger-related pre-tax charges of $79.1 million in 1998 and $22.2 million in 1997, the

• Ratio of Earnings to Fixed Charges was 2.74 in 1998 and 3.15 in 1997, and the Ratio of Earnings to Fixed Charges and Preferred Stock Dividends was 2.55 in 1998 and 2.86 in 1997. I-8 I

• Environmental Matters

• ACE is subject to various federal, regional, state, and local environmental regulations, including air and water quality control, oil pollution control, solid and hazardous waste disposal, and limitation on land use. Permits are required for ACE's construction projects and the operation of existing facilities.

ACE has incurred, and expects to continue to incur, capital expenditures and operating costs because of environmental considerations and requirements.

ACE has a continuing program to assure compliance with the environmental standards adopted by various regulatory authorities.

Included in ACE's forecasted capital requirements are construction expenditures for compliance with environmental regulations, which are estimated to be $2 million in 1999. Air Quality Regulations The federal Clean Air Act requires utilities and other industries to significantly reduce emissions of air pollutants such as sulfur dioxide (S0 2) and oxides of nitrogen (NOJ. Title IV of the Clean Air Act, the acid rain provisions, established a two-phase program which mandated reductions of S0 2 and NOx emissions from certain utility units by 1995 (Phase I) and required other utility units to begin reducing S0 2 and NOx emissions in the year 2000 (Phase II). Phase I emission reduction requirements have been achieved by the jointly-owned Conemaugh generating station and B.L. England Units 1 and 2. The remainder of ACE's wholly-and owned fossil-fuel units are required to comply with Phase II emission limits. ACE's facilities must also comply with Title I of the Clean Air Act, the ozone nonattainment provisions, which require states to promulgate Reasonably Available Control Technology (RACT) regulations for existing sources located within ozone nonattainment areas or within the Northeast Ozone Transport Region (NOTR). In accordance with New Jersey Department of Environmental Protection (NJDEP) regulatory requirements, ACE has submitted and received NJDEP's approval of ACE's RACT compliance plan. Additional "post RACT" NOx emission regulations are being pursued by states in the NOTR. In New Jersey, post-RACT NOx control regulations require attainment of summer seasonal emission reductions of up to 65% below 1990 levels by May 1999 and 90% by 2003 through reduced emissions or the procurement of NOx .emission allowances.

ACE anticipates spending approximately

$5 to $8 million over the next five years to achieve compliance with post-RACT NOx regulations.

In addition to the above requirements, the United States Environmental Protection Agency (USEPA) has proposed summer seasonal NOx controls commensurate with reductions of up to 85% below baseline years by the year 2003 for a 22 state region; including Delaware and New Jersey. Since New Jersey will require a greater percent reduction than EPA, the ACE facilities will most likely achieve compliance with the EPA requirement by 2003. In July 1997, the USEPA adopted new federal air quality standards for particulate matter and ozone. The new particulate matter standard addressed fine particulate matter. Attainment of the fine particulate matter standard may require reductions in NOx and S0 2. However, under the time schedule announced by the USEP A, particulate matter non-attainment areas will not be designated until 2002 and control measures to meet this standard will not be identified until 2005. Water Quality Regulations The federal Water Pollution Control Act, as amended (the Clean Water Act) provides for the imposition of effluent limitations to regulate the discharge of pollutants, including heat, into the waters of the United States. National Pollution Discharge Elimination System (NPDES) permits issued by state environmental regulatory agencies specify effluent limitations, monitoring requirements, and special conditions with which facilities discharging wastewaters must comply. To ensure that water quality is maintained, permits are issued for a term of five years and are modified as necessary to reflect requirements of new or revised regulations or changes in facility operations.

1-9 ACE holds New Jersey Pollution Discharge Elimination System (NJPDES) permits issued by the NJDEP

• for the Deepwater and B.L. England power stations.

The NJDEP has issued a draft revised NJPDES permit for the Deepwater station which is currently under review. The NJPDES permit for the B.L. England station will expire in December 1999. Application for renewal will be submitted, as required, in June 1999. The Clean Water Act also requires that cooling water intake structures be designed to minimize adverse environmental impact. The USEPA is required by a consent order to propose regulations in 1999 for determining whether cooling water intake structures represent the best technology available for minimizing adverse environmental impacts. Final action on the proposed regulations is required in 2001. PSE&G is implementing the 1994 NJPDES permit issued for the jointly-owned Salem facility which requires, among other things, water intake screen modifications and wetlands restoration.

Under the 1994 permit, PSE&G is continuing to restore wetlands and conduct the requisite management and monitoring associated with the special conditions of the 1994 permit. In 1999, PSE&G must apply to renew Salem's NJPDES permit. Hazardous Substances The nature of the electric utility business results in the production, or handling, of various by-products and substances which may contain substances defined as hazardous under federal or state statutes.

The disposal of hazardous substances can result in costs to clean up facilities found to be contaminated due to past disposal practices.

Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or uncontrolled hazardous waste sites. ACE's exposure is minimized by adherence to environmental standards for ACE-owned facilities and through a waste disposal contractor screening and audit process. ACE has accrued a $1.0 million liability for potential future remediation costs associated with certain hazardous waste sites. In 1991, the NJDEP identified ACE as one of a number of parties allegedly responsible for the placement

• of certain hazardous substances in a sanitary landfill in Atlantic County, New Jersey. Pursuant to an action in 1992 by the USEPA, ACE was named as one of several defendants in connection with the alleged release of hazardous substances at a site located in Gloucester County, New Jersey. ACE's cumulative contributions to the remediation and clean-up of these sites have been approximately

$0.4 million. 1-10 *

• *

• Executive Officers The names, ages, and positions of all of the executive officers of ACE as of December 31, 1998, are listed below, along with their business experiences during the past five years. Officers are elected annually by Conectiv's Board of Directors.

There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was selected.

Executive.Officers of ACE (As of December 31, 1998) Name, Age and Position Business Experience During Past 5 Years Howard E. Cosgrove, 55, . . . . . . . . . . . . . . . . . . . . .

Elected 1998 as Chairman of the Board and Chief Executive Chairman of the Board and Officer of Conectiv, Delmarva Power & Light Company, Chief Executive Officer and Atlantic City Electric Company. Elected 1992 as Chairman of the Board, President and Chief Executive Officer and Director of Delmarva Power & Light Company. Meredith I. Harlacher, Jr., 56, . . . . . . . . . . . . . . . . . .

Elected 1998 as President and Chief Operating Officer of President Conectiv, and President and Chief Operating Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1993 as Senior Vice President of Atlantic Energy, Inc. Barry R. Elson, 57, . . . . . . . . . . . . . . . . . . . . . . . . . .

Elected 1998 as Executive Vice President of Conectiv, and Executive Vice President Thomas S. Shaw, 51, ........................ . Executive Vice President Barbara S. Graham, 50, ...................... . Senior Vice President and Chief Financial Officer James P. Lavin, 51 .......................... . Controller and Chief Accounting Officer John C. van Roden, 49 ....................... . Senior Vice President and Chief Financial Officer*

• Effective January 1999 Executive Vice President and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1997 as Executive Vice President, Delmarva Power & Light Company. Executive Vice President, Cox Communications, Inc., Atlanta, Georgia, from 1995 to 1996 . Senior Vice President, Cox Enterprises/Cox Communications, Inc., Atlanta, Georgia, from 1984 to 1995. Elected 1998 as Executive Vice President of Conectiv, and Executive Vice President and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1992 as Senior Vice President, Delmarva Power & Light Company. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv, and Senior Vice President and Chief Financial Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1994 as Senior Vice President, Treasurer and Chief Financial Officer, Delmarva Power & Light Company. Vice President and Chief Financial Officer of Delmarva Power & Light Company from 1992 to 1994. Elected 1998 as Controller of Conectiv, Delmarva Power & Light Company, and Atlantic City Electric Company. Elected 1993 as Comptroller, Delmarva Power & Light Company. Elected 1998 as Senior Vice President and Chief Financial Officer, effective January 1999, of Conectiv, Delmarva Power & Light Company, and Atlantic City Electric Company. Principal, Cook and Belier, Inc. in 1998. Senior Vice President/Chief Financial Officer and Vice President/Treasurer, Lukens, Inc. from 1987 to 1998. I-11 Item 2. Properties Substantially all utility plants and properties of ACE are subject to the lien of the Mortgage under which First Mortgage Bonds are issued. The following table sets forth the net installed summer electric capacity available to ACE to serve its peak load as of December 31, 1998. Station Location Coal-Fired BL England .................... . Beesley's Pt., NJ ...................... . Conemaugh

..................... . New Florence, PA .................... . Keystone ....................... . Shelocta, PA ......................... . Deepwater

...................... . Pennsville, NJ ........................ . Oil-Fired BL England . . . . . . . . . . . . . . . . . . . . .

Beesley's Pt., NJ ...................... . Deepwater . . . . . . . . . . . . . . . . . . . . . . .

Pennsville, NJ ........................ . Combustion Turbines/Combined Cycle Cumberland

..................... . Millville, NJ ......................... . Sherman A venue ................. . Vineland, NJ ......................... . Middle ......................... . Rio Grande, NJ ....................... . Caril's Comer ................... . Upper Deerfield Twp, NJ ............... . Cedar .......................... . Cedar Run, NJ ........................ . Missouri A venue ................. . Atlantic City, NJ ...................... . Mickleton

....................... . Mickleton, NJ ........................ . Deepwater

...................... . Pennsville, NJ ........................ . Salem .......................... . Lower Alloways Creek Twp., NJ ......... . Nuclear Peach Bottom . . . . . . . . . . . . . . . . . . . .

Peach Bottom Twp., PA ............... . Salem . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lower Alloways Creek Twp., NJ ........ . Hope Creek . . . . . . . . . . . . . . . . . . . . . .

Lower Alloways Creek Twp., NJ ........ . Diesel Units BL England .................... . Beesley's Pt., NJ ...................... . Keystone ....................... . Shelocta, PA ......................... . Conemaugh

..................... . New Florence, PA .............. , ..... . Net Installed Capacity (kilowatts) 284,000 65,000 (A) 42,000 (A) 80,000 471,000 155,000 140,000 295,000 84,000 81,000 77,000 73,000 68,000 60,000 59,000 19,000 3,000 (A) 524,000 164,000 (A) 164,000 (A) 52,000 (A) 380,000 8,000 300 (A) 400 (A) 8,700 Long-term Capacity Purchases . * . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

828,000 Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,506,700 Short-term Capacity Purchases................................................

9,500 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,516,200 (A) ACE's portion of jointly-owned plants. I-12 I I * *

• I ___J ACE's electric transmission and distribution system includes 1,231 transmission poleline miles of overhead lines, 9,419 distribution poleline miles of overhead lines, and 1,198 distribution cable miles of underground cables. Under New Jersey law, the State of New Jersey owns in fee simple for the benefit of the public schools all lands now or formerly flowed by the tide up to the mean high-water line, unless it has made a valid conveyance of its interests in such property.

In 1981, because of uncertainties raised as to possible claims of State ownership, the New Jersey Constitution was amended to provide that lands formerly tidal-flowed, but which were not then tidal-flowed at any time for a period of 40 years, were not to be subject to State claim unless the State has specifically defined and asserted a claim within one year period ending November 2, 1982. As a result, the State published maps of the eastern (Atlantic) coast of New Jersey depicting claims to portions of many properties, including certain properties owned by ACE. ACE believes it has good title to such properties and will defend its title, or will obtain such grants from the State as may ultimately be required.

The cost to acquire any such grants may be covered by title insurance policies.

Assuming that all of such State claims were determined adversely to ACE, they would relate to land, which, together with the improvements thereon, would amount to less than 1 % of net utility plant. No maps depicting State claims to property owned by ACE on the western (Delaware River) side of New Jersey were published within one year period mandated by the constitutional amendment.

Nevertheless, ACE believes it has obtained all necessary grants from the State for its improved properties along the Delaware River. Item 3. Legal Proceedings See Note 13 to ACE's 1998 Consolidated Financial Statements included in Part II, Item 8, for information concerning ACE's lawsuit against Westinghouse Electric Corporation, the designer and manufacturer of the Salem steam generators.

Item 4. Submission of Matters to a Vote of Security Holders A special meeting of ACE shareholders was held on October 14, 1998 to approve an amendment to ACE's Charter. Shareholders voted to eliminate paragraph (7)(B)(c) of Article III of the Charter, removing a restriction on the amount of securities representing unsecured indebtedness issuable by ACE. Votes cast on the proposal were as follows: Number of Shares Outstanding For Against Abstain Common Securities:

18,320,937 18,320,937 Preferred Securities:

Cumulative Preferred Stock ($100 Par Value) 4% Series .............................................. . 77,000 59,223 232 150 4.10% Series ........................................... . 72,000 71,496 4.35% Series ........................................... . 15,000 12,183 4.35% 2nd Series ....................................... . 36,000 35,672 4.75% Series ........................................... . 50,000 45,550 5.00% Series ........................................... . 50,000 46,455 100 No Par Preferred Stock $7.80 Series ............................................ . 239,500 239,500 I-13

• [THIS PAGE INTENTIONALLY LEFT BLANK]

• I _J

• *

• ATLANTIC CITY ELECTRIC COMPANY PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All shares of ACE's common stock are owned by Conectiv, its parent company. ACE is subject to certain limitations on the payment of dividends to Conectiv.

Whenever full dividends on preferred stock have been paid for all past periods, ACE may pay dividends on its common stock from funds legally available for such purpose. Until all cumulative dividends have been paid upon all series of preferred stock and until certain required sinking fund redemptions of such preferred stock have been made, no dividend or other distribution may be paid or declared on the common stock of ACE. In addition, as long as any preferred stock is outstanding, ACE may not pay dividends to Conectiv if, after giving effect to such payment or distribution, the capital of ACE represented by its common stock, together with its surplus as then stated on its books of account, shall in the aggregate, be less than the involuntary liquidation value of the then outstanding shares of preferred stock. II-1

-1 ATLANTIC CITY ELECTRIC COMPANY ITEM 6. SELECTED FINANCIAL DATA 1998(1) 1997(2) 1996 1995 (Thousands of Dollars) Operating Results and Data Operating Revenues ....................

$1,037,613

$1,084,890

$ 989,647 $ 954,783 Operating Income ......................

$ 108,868 $ 190,052 $ 165,120 $ 194,687 Net Income ...........................

$ 30,276 $ 85,747 $ 75,017 $ 98,752 Earnings Applicable to CoIDIDon Stock .... $ 29,385 $ 80,926 $ 65,113 $ 84,125 Capitalization Variable Rate Demand Bonds (VRDB)(4)

.. $ 22,600 $ 22,600 Long-term Debt ........................

791,127 811,144 802,245 802,356 Preferred Stock of Subsidiaries Subject to Mandatory Redemption

...... 118,950 . 103,950 113,950 114,750 Not Subject to Mandatory Redemption

.. 6,231 30,000 30,000 40,000 CoIDIDon Stockholder's Equity ...........

730,093 783,033 778,425 796,042 Total Capitalization with VRDB ..........

$1,669,001

$1,750,727

$1,724,620

$1,753,148 Other Information Total Assets ...........................

$2,367,222

$2,436,755

$2,460,741

$2,459,104 Long-term Capital Lease Obligations

...... $ 19,523 $ 24,077 $ 24,212 $ 25,277 Capital Expenditures

....................

$ 71,342 $ 80,896 $ 88,914 $ 100,904 CoIDIDon Dividends Declared(5)

..........

$ 81,450 $ 80,857 $ 82,163 $ 81,239 1994(3) $ 913,226 $ 135,660 $ 93,174 $ 76,458 763,289 149,250 40,000 796,260 $1,748,799

$2,418,784

$ 26,102 $ 119,961 $ 83,482 (1) As discussed in Note 4 to ACE's 1998 Consolidated Financial Statements, in 1998, employee separation and other Merger-related charges reduced operating income $79.1 million and net income $47.2 million. (2) In 1997, employee separation and other Merger-related charges reduced operating income $22.6 million and net income $15.6 million. (3) In 1994, employee separation programs reduced operating income $26.6 million and net income $17.3 million. (4) Although Variable Rate Demand Bonds are classified as current liabilities, ACE intends to use the bonds as a source of long-term financing as discussed in Note 9 to ACE's 1998 Consolidated Financial Statements.

(5) Amounts shown as total, rather than on a per-share basis, since ACE is a wholly-owned subsidiary of Conectiv.

II-2 * * *

• ATLANTIC CITY ELECTRIC COMPANY ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Merger On March 1, 1998, Atlantic City Electric Company (ACE) and Delmarva Power & Light Company (DPL) became wholly-owned subsidiaries of Conectiv (the Merger). Before the Merger, Atlantic Energy, Inc. (Atlantic) owned ACE and nonutility subsidiaries.

As a result of the Merger, Atlantic no longer exists and Conectiv owris (directly or indirectly)

ACE, DPL and the nonutility subsidiaries formerly held separately by Atlantic and DPL. Conectiv is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). In 1998, enhanced retirement offers and other employee separation programs were utilized to reduce the workforce by 354 positions.

The employee separation programs and other Merger-related costs resulted in a $61.1 million pre-tax charge to expense (or $36.6 million after taxes) in 1998 and a $22.2 million pre-tax charge to expenses (or $15.6 million after taxes) in 1997. Certain of ACE's operational and administrative facilities are being sold due to consolidation of ACE's and DPL's facilities pursuant to the Merger. The estimated fair market value of the assets held for sale is $18,0 million less than their aggregate carrying value of $32.7 million at December 31, 1998. In accordance with Statement of Financial Accounting Standards (SFAS) No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," ACE has recorded an estimated impairment loss of $18.0 million ($10.6 million net of taxes). Earnings Results Summary ACE's earnings applicable to common stock were $29.4 million for 1998, compared to $80.9 million for 1997, a $51.5 million decrease. Excluding the Merger-related charges discussed above, ACE earned $76.6 million in 1998 compared to $96.5 million in 1997. This $19.9 million earnings decrease was primarily attributed to higher operations and maintenance expenses.

Excluding the Merger-related charge of $15.6 million in 1997, earnings increased to $96.5 million in 1997 from $65.1 million in 1996. The $31.4 million earnings increase was due to lower operations and maintenance expenses and higher electric revenues, net of fuel, energy and capacity costs. In 1997, ACE's share of operations and maintenance expenses associated with an extended outage at Salem Nuclear Generating Station (Salem) was limited by an agreement which settled ACE's related suit against the Salem operator, Public Service Electric & Gas (PSE&G). Electric Utility Industry Restructuring As discussed below, the electric utility industry is being deregulated in New Jersey. Generally, the restructuring will deregulate the supply component of the price charged to a customer for electricity, and electricity suppliers will compete to supply electricity to customers.

Customers will continue to pay the local utility a regulated price for the delivery of the electricity over the transmission and distribution system. Stranded costs are costs which may not be recoverable in a competitive energy supply market due to lower prices or customers choosing a different supplier.

Stranded costs generally include above-market costs associated with generation facilities or long-term purchased power agreements, and regulatory assets. ACE has quantified stranded costs in a New Jersey regulatory filing and has proposed a plan seeking approval for recovery of those costs from customers during the transition to a competitive market. When the New Jersey Board of Public Utilities (NJBPU) issues an order specifically addressing deregulation in ACE's service territory, ACE will cease applying SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation,

to its electricity supply business.

To the extent that the NJBPU' s order provides for recovery of II-3 stranded costs through cash flows from the regulated transmission and distribution business, the stranded costs would continue to be recognized as assets under SFAS No. 71. Any stranded costs (including regulatory assets) for which cost recovery is not provided would be expensed.

The amount of stranded costs ultimately recovered from utility customers, if any, and the full impact of New Jersey legislation deregulating the electric utility industry, as discussed below, cannot be predicted.

Also, the quantification of stranded costs under existing generally accepted accounting principles (GAAP) differs from methods used in regulatory filings. Among other differences, GAAP precludes recognition of the gains on plants (or purchased power contracts) not impaired, but requires write down of the plants that are impaired.

Due to these considerations, market conditions, timing and other factors, ACE's management currently cannot predict the ultimate effects that electric utility industry deregulation may have on the financial statements of ACE, although deregulation may have a material adverse effect on ACE's results of operations.

New Jersey Legislation The Electric Discount and Energy Competition Act (the Act) was signed into law by the Governor of New Jersey on February 9, 1999. The Act provides for retail choice of electricity suppliers; deregulation of electric rates and other competitive services, such as metering and billing; separation of competitive and regulated services; unbundling of rates for electric service; and licensing of electric and gas suppliers.

August 1, 1999 is the effective starting date for each utility to provide retail choice of electricity suppliers to all of its customers.

The Act requires each electric utility to reduce its rates by at least 5% at the start of retail choice and by 10% within 36 months of the start of choice. If the NJBPU determines that a rate decrease of more than 10% is warranted, a just and reasonable

financial test is applied. The mandated rate reductions must be sustained

• through the end of the 48th month after choice begins. The Act requires that the rate reductions be measured

• against the rates in effect on April 30, 1997. The rate reductions mandated by the Act could have a material adverse effect upon the results of operations of ACE. In connection with the deregulation of electric rates, the Act authorizes the NJBPU to permit electric public utilities to recover the full amount of their stranded costs through a non-bypassable market transition charge, as long as the mandated rate reductions are achieved.

The NJBPU will determine the utility's stranded cost amount. The NJBPU-determined stranded cost amount will be subject to periodic recalculation and true-up over the recovery period. The Act establishes an 8-year recovery period for stranded costs associated with owned generation.

The recovery period can be extended by the NJBPU so as to allow for the full recovery of the stranded costs and the meeting of mandated rate reductions.

The recovery period for stranded costs associated with purchased power contracts is to be the remainder of the contract term. In addition, the Act would allow for the issuance of transition bonds to finance portions of a given utility's stranded costs, as determined to be appropriate by the NJBPU. All savings generated through the use of such transition bonds are to be provided to the customers through rate reductions.

The Act establishes the current incumbent utility as the provider of default service

or Basic Generation Service (BGS) for a period of 3 years. Future proceedings will be held to determine if the provision of BGS should be made competitive.

The Act contains numerous provisions regarding the providing of competitive services by each utility. The primary focus is to ensure that there is no cross subsidization from the utility to competitive entities.

The NJBPU also is required to develop fair competition standards and conduct an audit to determine that the utilities are in compliance with those standards.

The Act gives the NJBPU the authority to order a utility to divest its generating assets if it is determined through a hearing that competition or customers are being adversely affected by plant location, market power or non-competitive rates. The NJBPU may require that the generation function be separated from a utility's non-competitive functions.

The NJBPU is authorized to establish standards for the licensing of energy suppliers, standards for switching

• customers from one supplier to another, and standards for issues such as credit and collections.

The Act also contains provisions for protecting workers displaced by the impacts of the restructuring of the utility industry.

II-4

• Stranded Cost Filing Electric utilities in New Jersey, including ACE, previously filed stranded cost estimates and unbundled rates, as required by the NJBPU. On August 19, 1998, an Administrative Law Judge (ALJ) from the New Jersey Office of Administrative Law issued an initial decision on ACE's stranded costs and unbundled rate filing. The ALJ, in reviewing ACE's filing, recognized that ACE's stranded costs were $812 million for nonutility generation contracts and $397 million for owned generation.

The ALJ made no specific recommendations on rate issues. A final NJBPU decision on this filing is expected by mid-1999.

Price Regulation of Energy Revenues Through 1998, customer rates for non-energy costs have been established in past base rate proceedings before the. NJBPU. Changes in non-energy

.(or base rate) revenues due to volume, or rate changes, generally affect the earnings of ACE. Energy costs, including fuel and purchased energy, are currently billed to ACE's rate-regulated customers under ACE's Levelized Energy Clause (LEC) rates. These energy rates are adjusted annually for cost changes and are subject to review by the NJBPU. Energy revenues,

or energy costs billed to customers, do not generally affect net income, because the amount of under-or over-recovered energy costs is generally deferred until it is subsequently recovered from or returned to ACE's rate-regulated customers.

The LEC is expected to be superceded by provisions contained in the Act which permit BGS suppliers full and timely recovery of their costs. The Act also authorizes the NJBPU to permit deferral and subsequent recovery of BGS costs if necessary for attainment of the rate reductions required by the Act. Regulations governing BGS are expected to be promulgated by the NJBPU prior to beginning retail of electricity suppliers in New Jersey. Electric revenues also include interchange delivery revenues, which result primarily from the sale of electricity to other electricity suppliers in the Pennsylvania-New Jersey-Maryland Interconnection, which is an electric power pool. Interchange delivery revenues are currently reflected in the calculation of rates charged to customers under the LEC and, thus, do not affect net income. Revenues are also earned from sales not subject to price regulation.

These sales include off-system bulk commodity sales and retail energy sales. Electric Revenues In 1998, the percentage of electric retail revenues contributed by the various retail customer classes were as follows: residential 47.3%; commercial 41.1 %; industrial 11.0%; and other 0.6%. Details of the changes in .the various components of electric revenues, from prior years, are shown below. 1998 1997 (dollars in millions)

Variance Variance Non-energy (base rate) revenues:

Change in New Jersey tax law ............................. . $(54.1) $ Merger-related base rate decrease ........................... . (13.3) Other postretirement benefits (OPEB) costs base rate increase ... . 5.0 All other variances

..................

...................... . 1.3 4.9 --Subtotal .........................................

• ..... . (61.1) 4.9 Energy revenues ........................................... . 22.4 13.0 Interchange revenues ........................................ . 45.5 (3.9) Revenues not subject to price regulation

....................... . (40.4) 70.2 --Total ................................................. . $(33.6) $84.2 --II-5 The $54.1 million decrease in electric revenues which was due to changes in the New Jersey tax law related

• to sales of electricity did not affect earnings due to corresponding reductions in taxes other than income taxes. Sales and use taxes billed to customers in 1998 are recorded as a current liability, whereas in prior years, certain other state taxes (which were replaced, in part, by the sales and use taxes) were recorded as revenues.

The $13.3 million Merger-related base rate decrease shown above resulted from sharing with utility customers the expected Merger-related cost savings, as discussed under "Other Rate Matters" in Note 5 to the Consolidated Financial Statements.

The $5.0 million base rate increase for OPEB is for recovery of the non-cash portion of OPEB costs deferred during 1993-1997.

'"'All other variances" in electric non-energy revenues primarily reflect growth in retail kilowatt-hour (kWh) sales and the number of customers.

Total retail kWh sales increased 3.4% in 1998. Sales growth in 1998 was particularly strong in the commercial and industrial sectors, with increases of 5.3% and 4.4%, respectively.

Lower "other electric revenues" in 1998 partly offset the additional revenues from sales growth. Other electric revenues are primarily from non-regulated energy-related activities, such as, indoor and outdoor lighting programs, appliance warranty programs and other energy services, which are now being conducted through other Conectiv subsidiaries.'

The 1997 increase for "All other variances" primarily reflects a 1996 $13.0, million refund to customers, which resulted from a stipulation agreement related to Salem (as discussed in Note 13 to the Consolidated Financial Statements), which was substantially offset by ACE's NJBPU-approved Off-Tariff Rate Adjustments (OTRAs). OTRAs are special reduced rates offered by ACE to large customers, which aggregated

$10.5 million for 1997. As discussed under "Price Regulation of Energy Revenues," energy and interchange delivery revenues generally do not affect net income. Revenues not subject to price regulation decreased

$40.4 million in 1998 because non-price regulated bulk power sales have been conducted solely through DPL subsequent to the Merger in order to achieve synergies.

In 1997,"revenues from non-price regulated sales increased

$70.2 million because ACE entered the bulk power market in late-1996 and expanded sales during 1997. The margin provided by the wholesale market revenues in excess of the related energy costs is relatively small due to the competitive nature of bulk power sales. Other Services Revenues Other services revenues represent non-regulated energy related services, including energy management services.

Effective with the Merger, most of these services are being provided by other Conectiv subsidiaries.

Operation and Maintenance Expenses Operation and maintenance expenses increased

$29.1 million for 1998. An actuarial valuation of ACE's pension plan liability based on updated assumptions and data resulted in a $5.9 million pension expense increase; the remaining increase in operation and maintenance expenses was due primarily to lower capitalized expenses and increased contracted services.

In 1997, operation and maintenance expenses decreased

$27.7 million primarily due to reduced Salem outage expenses.

An agreement which settled ACE's lawsuit against PSE&G limited ACE's 1997 share of Salem's operation and maintenance expenses.

Depreciation Expense In 1998, ACE began amortizing OPEB costs deferred during 1993-1997 and depreciating new assets, including business, financial, and human resource management systems. Primarily due to these factors, depreciation expense increased

$12.3 million in 1998. Taxes Other Than Income Taxes

• Taxes other than income ,taxes decreased

$65.2 million for 1998 due primarily to the changes in the New

• Jersey tax laws which eliminated the state gross receipts and franchise tax. Earnings generally were not affected II-6 _J r--------* I I

• by this decrease due to related reductions in electric revenues resulting from the tax law change. See Note 3 to the Consolidated Financial Statements for further details on the tax law change. Gain on Preferred Stock Redemption In October 1998, ACE purchased and retired 237,232 shares, or $23.7 million of various series of mandatorily redeemable preferred stock, which had an average dividend rate of 4.4%. ACE purchased these shares at a discount, which resulted in a gain of $2.5 million that is included in ACE's 1998 results of operations.

Year 2000 The Year 2000 issue is the result of computer programs and embedded systems using a two-digit format, as opposed to four digits, to indicate the year. Computer and embedded systems with this characteristic may be unable to interpret dates dming and beyond the year 1999, which could cause a system failure or other computer errors, leading to disruption of operations.

A Conectiv project team, originally started in 1996 by ACE, is assisting line management in addressing the issue of computer programs and embedded systems not properly recognizing the Year 2000. A Conectiv corporate officer, reporting directly to the Chief Executive Officer, is coordinating all Year 2000 activities.

There are substantial challenges in identifying and correcting the many computer and embedded systems critical to generating and delivering power and providing other services to customers.

The project team is using a phased approach to managing its activities.

The first phase is inventory and assessment of all systems, equipment, and processes.

Each identified item is given a criticality rating of high, medium or low. Those items rated as high or medium are then subject to the second phase of the project. The second phase is determining and implementing corrective action for the systems, equipment and processes, and concludes with a test of the unit being remediated.

The third phase is system testing and compliance certification.

Additionally, the project team will be updating existing outage contingency plans to address Year 2000 issues. Overall, Conectiv's Year 2000 Project covers approximately 140 different systems (some with numerous components) that had been originally identified as high or medium in criticality.

However, only 21 of those 140 systems are essential for Conectiv to provide electric and gas service to its customers

.. The Year 2000 Project team will be focusing on these 21 systems, with additional work on other systems continuing based on their relative importance to Conectiv's business.

The following chart sets forth the cmTent estimated completion percentage of the 140 different systems in the Year 2000 Project by major business group, and for the information technology systems used in managing Conectiv's businesses.

Conectiv expects significant progress in remediation and testing over the next quarter based on work that is in process and material that is being ordered. Corrective Inventory and Action/Unit System Testing/ Business Group Assessment Testing Compliance Business systems ............................ . 95% 85% 65% Power production

............................ . 95% 30% 30% Electricity distribution

........................ . 95% 10% 5% Gas delivery ................................ . 95% 60% 60% Competitive services ......................... . 90%-95% 30%-80% 30%-80% ACE is also contacting vendors and service providers to review remediation of their Year 2000 issues. Many aspects of ACE's businesses are dependent on third parties. For example, fuel suppliers must be able to provide coal or gas to allow ACE to generate electricity.

Distribution of electricity is dependent on the overall reliability of the electric grid. ACE is cooperating with the North American Electric Reliability Council (NERC) and the PJM Interconnection in Year 2000 remediation and remediation planning efforts, and has accelerated its Year 2000 Project timeline to be generally in-line with the recommendations of those groups. At this time, a few generating units are scheduled for remediation and II-7 testing in September to coincide with previously scheduled outages. Recent reports issued by the NERC indicate

• a diminished risk of disruption to the electric grid caused by Year 2000 issues. Conectiv has incurred approximately

$3 million in costs for the Year 2000 Project. Current estimates of the costs for the Year 2000 Project range from $10 million to $15 million. These estimates could change significantly as the Year 2000 Project progresses.

The costs set forth above do not include several significant expenditures covering new systems, such as ACE's SAP business, financial and human resources management system and an Energy Control System. While the introduction of these new systems effectively remediated Year 2000 problems in the systems they replaced, ACE has not previously reported the expenditures on these systems in its costs for the Year 2000 Project. Since the project team is still in the process of assessing and correcting impacted systems, equipment and processes, ACE cannot currently determine whether the Year 2000 issue might cause disruptions to its operations and have impacts on related costs and revenues.

ACE assesses the status of the Year 2000 Project on at least a monthly basis to determine the likelihood of business disruptions.

Based on its own Year 2000 Project, as well as, reports from NERC and other utilities, ACE's management believes that it is unlikely that significant Year 2000 related disruptions will occur. However, any substantial disruption to ACE's operations could negatively impact ACE's revenues, significantly impact its customers and could generate legal claims against ACE. ACE's results of operations and financial position would likely suffer an adverse impact if other entities, such as suppliers, customers and service providers do not effectively address their Year 2000 issues. Liquidity and Capital Resources ACE's principal sources of capital are internally generated funds (net cash provided by operating activities, less common and preferred dividends) and external funds. The principal capital requirements of ACE are construction expenditures, the repayment of debt and capital lease obligations.

Internally generated funds were $157.7 million for 1998, $87.0 million for 1997 and $127.4 million for 1996. The yearly fluctuations in internally generated funds were primarily due to changes in working capital and in fuel revenues, net of energy and capacity costs. Internally generated funds provided 221 %, 108%, and 143%, respectively, of the cash required for construction expenditures for 1998, 1997 and 1996. Cash construction expenditures were $71.3 million for 1998, $80.9 million for 1997 and $88.9 million for 1996. On an interim basis, ACE finances construction costs and other capital requirements in excess of internally generated funds through the issuance of unsecured short-term debt, consisting of commercial paper and notes from banks. As of December 31, 1998, ACE had authority to issue $150 million in short-term debt, all of which was available.

ACE also has two separate uncommitted lines of credit in the amount of $25 million and $20 million, respectively.

The facilities are renewable annually and bear interest at variable rates. Common dividends paid to Conectiv in 1998 were $81.5 million. Common dividends paid to Atlantic in 1997 and 1996 were $80.9 million and $82.2 million, respectively.

Presented below are sources and uses of capital from ACE's debt and equity securities.

1998 1997 1996 DebUEquity Issued Redeemed Issued Redeemed Issued Redeemed (dollars in millions)

Short term debt .................. $ $ (72.1) $ 7.2 $ $ 34.4 $ Long term debt ..................

85.0 (58.6) 87.6 (74.1) (12.3) Preferred stock & securities

........ 25.0 (33.8) (20.0) 70.0

$110.0 $(164.5) $94.8 $(94.1) $104.4 $(111.2) ------------Il-8 * *

' \ -.1 *

• In January 1998, ACE issued $85 million of medium-term notes and used $50 million of the proceeds to redeem medium-term notes, which matured in January 1998. In May 1998, ACE repaid at maturity $6.0 million of 5.5% Medium-Term Notes and $2.5 million of 7.25% Debentures.

In August 1998, ACE redeemed 100,000 shares of its $8.20 No Par Preferred Stock at $100 per share, or $10.0 million in total (the book value of the preferred stock). In October 1998, ACE redeemed $23.7 million of preferred stock not subject to mandatory redemption, which had an av,erage dividend rate of 4.4%. In November 1998, a subsidiary trust of ACE issued $25 million of 7 3/8% preferred securities subject to mandatory redemption.

On a consolidated basis, Conectiv receives a tax benefit, which is equivalent to the tax effect of a deduction for the trust's distributions on the preferred securities.

The scheduled maturities and sinking fund requirements of debt and preferred securities for the next five years are presented below. Year 1999 ................................................ . 2000.; ............................................... . 2001 ................................................ . 2002 ................................................ . 2003 ................................................ . Debt Preferred Securities Total (Dollars in Thousands)

$30,075 $30,075 $46,075 $46,075 $40,075 $11,500 $51,575 $50,075 $11,500 $61,575 $70,075 $ 950 $71,025 ACE's capital structure.as of December 31, 1998 and 1997, expressed as a percentage of total capitalization is shown below. 1998 1997 Long-term debt and variable rate demand bonds ............ . 48.8% 47.6% Preferred securities

..................................... . 7.5% 7.7% Common stockholder's equity ............................ . 43.7% 44.7% ACE's estimated requirements during 1999 for capital expenditures are $85 million. The uncertainty of the impact of electric utility industry restructuring, and the extent to which ACE retains or divest certain of its assets, including generating plants, will affect the ultimate amount of capital expenditures and the amount of external funds required in excess of internally generated funds. ACE's management expects that external funds will be derived from the sale of long-term debt, as required.

Quantitative and Qualitative Disclosures About Market Risks The following discussion contains forward looking statements.

These projected results have been prepared based upon certain assumptions considered reasonable given the information currently available to ACE. Nevertheless, because of the inherent unpredictability of interest rates and equity market prices as well as other factors, actual results could differ materially from those projected in such forward-looking information.

Interest Rate Risk ACE is subject to the risk of fluctuating interest rates in the normal course of business.

ACE manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. As of December 31, 1998, a hypothetical 10% change in interest rates would not have a material impact on the results of operations of ACE. II-9 Equity Price Risk ACE maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear decommissioning. (See Note 15 to the Consolidated Financial Statements.)

These funds are invested primarily in domestic and international equity securities, fixed-rate, fixed income securities, and cash and cash equivalents.

By maintaining a portfolio that includes long-term equity investments, ACE is maximizing the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in ACE's portfolio are exposed to price fluctuations in equity markets, and the fixed-rate, fixed income securities are exposed to changes in interest rates. ACE actively monitors its portfolio by benchmarking the performance of its investments against certain indexes and by maintaining, and periodically reviewing, established target asset allocation percentages of the assets in the trusts. Because the accounting for nuclear decommissioning recognizes that costs are recovered through electric rates, fluctuations in equity prices and interest rates; while affecting the carrying value of the investments, are offset by the effects of regulation and therefore do not affect earnings.

Commodity Price Risk Due to the LEC, as discussed under "Price Regulation of Energy Revenues" and in Note 1 to the Consolidated Financial Statements, ACE's exposure to commodity price risk is immaterial to ACE's results of operations.

Forward-Looking Statements The Private Securities Litigation Reform Act of 1995 (Litigation Reform Act) provides a "safe harbor" for -1

• forward looking statements to encourage such disclosure without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.

Forward-looking statements have been made in this report. Such statements are based on

• management's beliefs, as well as, assumptions made by and information currently available to management.

When used herein, the words "will," "anticipate," "estimate," "expect," "objective," and similar expressions are intended to identify forward-looking statements.

In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

deregulation and the unbundling of energy supplies and services; an increasingly competitive energy marketplace; sales retention and growth; federal and state regulatory actions; costs of construction; operating restrictions; increased cost and construction delays attributable to environmental regulations; nuclear decommissioning and the availability of reprocessing and storage facilities for spent nuclear fuel; and credit market concerns.

ACE undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

The foregoing review of factors pursuant to the Litigation Reform Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made by ACE prior to the effective date of the Litigation Reform Act. II-10 *

• ATLANTIC CITY ELECTRIC COMPANY ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF MANAGEMENT Management is responsible for the information and representations contained in the consolidated financial statements of Atlantic City Electric Company (ACE). Our consolidated financial statements have been prepared in conformity with generally accepted accounting principles, based upon currently available facts and circumstances and management's best estimates and judgments of the expected effects of events and transactions.

ACE and its subsidiary companies maintain a system of internal controls designed to provide reasonable, but not absolute, assurance of the reliability of the financial records and the protection of assets. The internal control system is supported by .written administrative policies, a program of internal audits, and procedures to assure the selection and training of qualified personnel.

PricewaterhouseCoopers LLP, independent accountants, are engaged to audit the financial statements and express their opinion thereon. Their audits .are conducted in accordance with generally accepted auditing standards which include a review of selected internal controls to determine the nature, timing, and extent of audit tests to be applied. Conectiv's Audit Committee of the Board of Directors, composed of outside directors only, meets with management, internal auditors, and independent accountants to review accounting, auditing, and financial reporting matters. The independent accountants are appointed by the Board on recommendation of the Audit Committee, subject to stockholder approval . Isl Howard E. Cosgrove HOWARD E. COSGROVE Chairman of the Board and Chief Executive Officer February 5, 1999 II-11 Isl John C. van Roden JOHN C. VAN RODEN Senior Vice President and Chief Financial Officer REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors Atlantic City Electric Company Wilmington, Delaware In our opinion, the consolidated financial statements listed in the accompanying index appearing under Item 14(a)(l) on page IV-1 present fairly, in all material respects, the financial position of Atlantic City Electric Company and subsidiary companies as of December 31, 1998, and the results of their operations and their cash flows for the year ended December 31, 1998, in conformity with generally accepted accounting principles.

In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 14(a)(2) on page IV-1 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.

We believe that our audit provides a reasonable basis for the opinion expressed above. Isl PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP 2400 Eleven Penn Center Philadelphia, Pennsy 1 vania February 5, 1999 11-12 * * *

• REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors Atlantic City Electric Company Wilmington, Delaware We have audited the accompanying consolidated balance sheet of Atlantic City Electric Company and subsidiary as of December 31, 1997 and the related consolidated statements of income, changes in common stockholder's equity, and cash flows for each of the two years in the period ended December 31, 1997, Our audits also included the financial statement schedule for years ended December 31, 1997 and 1996 listed in the Index as Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management.

Our responsibility is to express an opinion on, these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards.

Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Atlantic City Electric Company and subsidiary at December 31, 1997 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedule for the years ended December 31, 1997 and 1996, when considered fo relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

• Isl DELOITTE & ToucHE LLP Deloitte & Touche LLP February 2, 1998 (March 1, 1998, as to Note 4) Parsippany, New Jersey II-13 ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)

For the Year Ended December 31, 1998 1997 1996 Operating Revenues Electric ................................................. . $1,034,894

$1,068,534

$984,360 Other Services .......................................... . 2,719 16,356 5,287 1,037,613 1,084,890 989,647 Operating Expenses Electric Fuel and Purchased Power ......................... . 308,943 293,457 225,185 Cost of Sales-Other Services ...... ; ...................... . 5,465 13,566 6,742 Purchased Electric Capacity ...........

................... . 173,741 180,250 179,282 Employee Separation and Other Merger-Related Costs ........ . 61,091 22,246. Merger-Related Impairment Loss on Assets Held for Sale ...... . 18,000

• Operation and Maintenance

............... ............... . 206,951 177,875 205,615 Depreciation

............................................ . 112,711 100,412 97,262 Taxes Other Than Income Taxes ........................... . 41,843 107,032 . 110,441 928,745 894,838 824,527 Operating Income ...................................... . . 108,868 190,052 165,120 Other Income Allowance for Equity Funds Used During Construction

........ . 593 815 879 Other 'Income ......................

• ..................... . 8,028 14,595 11,275 8,621 15,410 12,154 Interest Expense Interest Charges ......................................... . 63,940 64,501 64,847 Allowance for Borrowed Funds Used During Construction and Capitalized Interest .................................... . (957) (1,003) . (976) 62,983 63,498 63,871 Dividends on Preferred Securities of Subsidiary Trusts ..... . 6,052 5,775 1,428 Income Before Income Taxes ............................ . 48,454 136,189 111,975 Income Taxes .......................................... . 18,178 50,442 36,958 Net Income ............................................ . 30,276 85,747 75,017 Dividends on Preferred Stock ............................ . 3,436 4,821 9,904 Gain on Preferred Stock Redemption

..................... . 2,545 Earnings Applicable to Common Stock ................... . $ 29,385 $ 80,926 $ 65,113 See accompanying Notes to Consolidated Financial Statements.

II-14 ----------

--*

• I

• ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)

For the Year Ended December 31, Cash Flows from Operating Actvities Net Income .................................................. . Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and Amortization

............................... . Investment Tax Credit Adjustments, Net ....................... . Deferred Income Taxes, Net ................................. . Deferred Energy Costs ...................................... . Prepaid State Sales Taxes .................................... . Prepaid State Excise Taxes .................................. . Unrecovered State Excise Taxes .............................. . Employee Separation and Merger-Related Costs ................. . Net Change in: Accounts Receivable

.... , ................................... . Inventories

................................................ . Accounts Payable .......................................... . Other Current Assets and Liabilities (1) ........................ . Impairment Loss on Assets Held for Sale ........................ . Other, Net ................................................... . Net Cash Provided by Operating Activities

....................... . Cash Flows from Investing Activities Capital Expenditures

.......................................... . Nuclear Decommissioning Trust Fund Deposits ................... . Other, Net. ....... * ........................................... . Net Cash Used by Investing Activities

........................... . Cash Flows from Financing Activities Dividends:

Common Stock ............................................ . Preferred Stock ............................................ . Issuances:

Long-term Debt ............................................ . Preferred Securities

......................................... . Redemptions:

Long-term Debt ............................................ . . Preferred Stock ............................................ . Principal Portion of Capital Lease Payments ...................... . Net Change in Short-term Debt ................................. . Other, Net ................................................... . Net Cash Used by Financing Activities

.......................... . Net Change in Cash and Cash Equivalents

....................... . Cash and Cash Equivalents at Beginning of the Year ............... . Cash and Cash Equivalents at End of the Year .................... . (1) Other than debt and deferred income taxes classified as current. 1998 $ 30,276 117,285 (1,690) (37,915) 43,001 (19,522) 3,248 9,560 16,147 (500) 5,077 18,765 19,198 18,000 21,687 242,617 (71,342) (6,424) (1,040) (78,806) (81,450) (3,436) 85,000 25,000 (58,575) (33,769)

(12,295) (72,100) (4,184) (155,809) 8,002 20,765 $ 28,767 See accompanying Notes to Consolidated Financial Statements.

11-15 1997 1996 $85,747 $ 75,017 109,000 104,408 (2,534) (2,534) 3,330 3,982 6,105 (2,095) 3,321 3,628 9,560 9,560 (5,536) 5,795 3,365 (2,523) (14,370) 2,814 (10,245) (2,525) (15,052) 23,960 172,691 219,487 (80,896) (88,914)

(6,424) (6,424) 2,916 (9,283) (84,404) (104,621)

(80,857) (82,163) (4,821) (9,904) 87,600 70,000 (74,066) (12,266)

(20,000) (98,876) (8,588) (7,146) 7,150 34,405 2,616 (3,879) (90,966) (109,829)

(2,679) 5,037 23,444 18,407 $20,765 $ 23,444 Current Assets ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)

ASSETS Cash and Cash Equivalents

............................................ . Accounts Receivable

................................................ . Allowance for Doubtful Accounts ...................................... . Inventories, at Average Cost: Fuel (Coal and Oil) ................................................ . Materials and Supplies ............................................. . Deferred Energy Costs ............................................... . Prepaid New Jersey Sales and Excise Tax ............................... . Deferred Income Taxes, Net ........................................... . Other Prepayments

.................................................. . Investments Funds Held by Trustee ............................................... . Other Investments

................................................... . Property, Plant, and Equipment Electric Utility Plant ................................................. . Less: Accumulated Depreciation

....................................... . Net Utility Plant in Service ........................................... . Utility Construction Work-in-Progress

.................................. . Leased Nuclear.Fuel, at Amortized Cost ................................ . Nonutility Property, Net .............................................. . Deferred Charges and Other Assets Unrecovered Purchased Power Costs ................................... . Deferred Recoverable Income Taxes .................................... . Unrecovered State Excise Taxes ....................................... . Deferred Debt Refinancing Costs ....................................... . Deferred Other Postretirement Benefit Costs ............................. . Unamortized Debt Costs .............................................. . Prepaid Pension Benefit .............................................. . Other .....................................................

Total Assets ........................................................ . December 31, 1998 1997 $ 28,767 $ 20,765 130,148 129,648 (3,500) (3,500) 27,233 29,159 21,296 20,893 27,424 20,078 3,804 7,735 4,420 3,949 236,177 232,142 102,765 88,743 112 9 102,877 88,752 2,600,699 2,591,825 1,007,106 945,921 1,593,593 1,645,904 97,955 106,806 35,003 38,795 8,207 8,517 1,734,758 1,800,022 48,274 66,264 102,223 85,858 35,594 45,154 28,043 30,002 34,978 37,476 14,141 13,416 8,390 30,157 29,279 293,410 315,839 $2,367,222

$2,436,755 See accompanying Notes to Consolidated Financial Statements.

II-16 * * *1* *

• Current Liabilites ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)

CAPITALIZATION AND LIABILITIES Short-term Debt ..................................................... . Long-term Debt Due Within One Year .................................. . Variable Rate Demand Bonds ......................................... . Accounts Payable .................................................... . Interest Accrued ..................................................... . Dividends Payable ................................................... . Taxes Accrued ...................................................... . Current Capital Lease Obligation

....................................... . Accrued Employee Separation

& Other Merger-related Costs ............... . Deferred Energy Costs ............................................... . Deferred Income Taxes, Net ........................................... . Other .............................................................. . Deferred Credits and Other Liabilities Deferred Income Taxes, Net. .......................................... . Deferred Investment Tax Credits ....................................... . Long-term Capital Lease Obligation

.................................... . Pension Benefit Obligation

............................................ . Other Postretirement Benefit Obligation

................................. . Other .............................................................. . Capitalization Common Stock, $3 Par Value; 25,000,000 Shares Authorized; Shares Outstanding; 1998 and 1997 18,320,937

.............................. . Additional Paid-in Capital ............................................ . Retained Earnings ................................................... . Total Common Stockholder's Equity ................................... . Preferred Stock Subject to Mandatory Redemption

........................ . Preferred Stock Not Subject to Mandatory Redemption

.................... . ACE Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely ACE Debentures

............................... . Long-term Debt Commitments and Contingencies (Notes 11 & 12) Total Capitalization and Liabilities

................................... . December 31, 1998 1997 $ $ 55,675 30,075 22,600 22,600 54,315 37,779 14,774 19,562 22,236 21,215 22,916 5,922 15,728 15,653 9,554 15,577 9,974 28,771 37,226 236,546 225,606 343,429 354,127 42,142 44,043 19,523 24,077 10,477 44,607 37,476 24,097 23,299 484,275 483,022 54,963 54,963 493,007 493,161 182,123 234,909 730,093 783,033 23,950 33,950 6,231 30,000 95,000 70,000 791,127 811,144 1,646,401 1,728,127

$2,367,222

$2,436,755 See accompanying Notes to Consolidated Financial Statements.

II-17 ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDER'S EQUITY (Dollars in Thousands)

Additional Paid-in Capital Premium Contri-Capital Common Capital buted Stock Retained Stock Stock Capital Expense Earnings Balance, December 31, 1995 ............

$54,963 $231,081 $259,645 $(2,131) $252,484 Net Income ...........................

75,017 Capital Stock Expense ..................

486 (486) Capital Contributed from Parent, Net ...... (567) Less Dividends:

Preferred Stock ......................

(9,904) Common Stock ......................

(82,163) Balance, December 31, 1996 ............

54,963 231,081 259,078 (1,645) 234,948 Net Income ...........................

85,747 Capital Stock Expense ..................

108 (108) Capital Contributed from Parent, Net ...... 4,539 Less Dividends:

Preferred Stock ......................

(4,821) Common Stock .............

........ (80,857) Balance, December 31, 1997 ............

54,963 231,081 263,617 (1,537) 234,909 Net Income .. , ........................

30,276 Preferred Stock Redemption

.............

(64) 199 1,824 Capital Contributed from Parent, Net ...... (289) Less Dividends:

Preferred Stock ......................

(3,436) Common Stock ......................

(81,450) Balance, December 31, 1998 ............

$54,963 $231,017 $263,328 $(1,338) $182,123 As of December 31, 1998, ACE had 25 million authorized shares of common stock at $3 par value. Shares outstanding at December 31, 1998, 1997 and 1996 were 18,320,937.

See accompanying Notes to Consolidated Financial Statements.

II-18 * * *

• ATLANTIC CITY ELECTRIC COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES Nature of Business As discussed in Note 4 to the Consolidated Financial Statements, effective March 1, 1998, Atlantic Energy, Inc. (Atlantic), and Delmarva Power & Light (DPL) consummated a series of merger transactions (the Merger) by which Atlantic City Electric Company (ACE) and DPL became wholly-owned subsidiaries of Conectiv.

ACE is a public utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity.

Sales of electricity include sales at regulated retail and unregulated wholesale levels. Subsequent to the Merger, unregulated wholesale or bulk power sales have been transacted through DPL, in order to achieve Merger synergies.

ACE serves approximately 488,800 customers within its service territory, which covers an area of approximately 2,700 square miles within the southern one-third of New Jersey and has a population of approximately 850,000. The majority of customers are residential and commercial.

Principles of Consolidation The consolidated financial statements include the accounts of ACE and its wholly-owned subsidiaries.

All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates and assumptions.

Reclassifications Certain prior year amounts have been reclassified to conform to the current year reporting of these items. Regulation of Utility Operations ACE is subject to regulation with respect to retail electric sales by the New Jersey Board of Public Utilities (NJBPU). The Federal Energy Regulatory Commission (FERC) also has regulatory authority over certain aspects of ACE's business, including the transmission of electricity, the sale of electricity to municipalities and electric cooperatives, and interchange and other purchases and sales of electricity involving other utilities.

ACE is subject to the requirements of Statement of Financial Accounting Standards (SPAS) No. 71, Accounting for the Effects of Certain Types of Regulation.

The NJBPU occasionally provides for future recovery from customers of current period expenses.

When this happens, the expenses are deferred as regulatory assets and subsequently recognized in the Consolidated Statement*

of Income during* the period the utility expenses are recovered from customers.

Similarly, regulatory liabilities may also be created due to the economic impact of an action taken by the NJBPU. See Notes 3, 5 and 14 to the Consolidated Financial Statements for additional information. Revenue Recognition At the end of each month, there is an amount of electric service rendered from the last meter reading to the month-end, which has not yet been billed to customers.

The revenues associated with such unbilled services are 11-19 accrued by ACE and the accrued amounts receivable for unbilled electric service were $29.7 million as of December 31, 1998 and $36.9 million as of December 31, 1997. When interim rates are placed in effect subject to refund, ACE recognizes revenues based on expected final rates. Revenues from "Other services" are recognized when services are performed or products are delivered.

Nuclear Fuel ACE's share of nuclear fuel at the Peach Bottom Atomic Power Station (Peach Bottom), the Salem Nuclear Generating Station (Salem), and the Hope Creek Nuclear Generating Station (Hope Creek) is financed through contracts accounted for as capital leases. Nuclear fuel costs, including a provision for the future disposal of spent nuclear fuel, are charged to fuel expense on a unit-of-production basis. Electric Utility Plant and Allowance for Funds Used During Construction Electric utility plant is stated at original cost, including property additions.

Generally, utility plant is subject to a First Mortgage lien. Allowance for Funds Used During Construction (AFUDC) is included in the cost of utility plant and represents the cost of borrowed and equity funds used to finance construction of new utility facilities.

In the Consolidated Statements of Income, the borrowed funds component of AFUDC is reported as a reduction of interest expense and the equity funds component of AFUDC is reported as other income. AFUDC has been calculated using a semi-annually compounded rate of 8.25% for all periods. Depreciation ACE provides for straight-line depreciation based on the following:

transmission and distribution estimated remaining life; nuclear property-remaining life of the related plant operating license in existence at the time of the last base rate case; other depreciable property-estimated average service life. Depreciation expense includes a provision for ACE's share of the estimated cost of decommissioning nuclear power plant reactors based on site-specific studies. Refer to Note 15 to the Consolidated Financial Statements for additional information on.nuclear decommissioning.

ACE's overall composite rate of depreciation was 3.9% for 1998 and 3.3% for 1997 and 1996. Accumulated depreciation is charged with the cost of depreciable property retired including removal costs less salvage and other recoveries.

Funds Held by Trustee Funds held by trustee are stated at fair market value and primarily include deposits for nuclear decommissioning costs. Deferred Energy Costs As approved by the NJBPU, ACE has a Levelized Energy Clause (LEC) through which energy and related costs (energy costs) are charged to customers.

LEC rates are based on projected energy costs and prior period underrecoveries or overrecoveries.

Generally, energy costs are recovered through levelized rates over the period of projection, which is usually a 12-month period. In any period, the actual amount of LEC revenues recovered from customers may be greater or less than the recoverable amount of energy costs incurred in that period. Electric Fuel and Purchased Power expenses are adjusted to match the associated LEC revenues.

Any underrecovery (an asset representing energy costs incurred that are to be collected from customers) or overrecovery (a liability representing previously' collected energy costs to be returned to customers) of costs is deferred on the Consolidated Balance Sheet as Deferred Energy Costs. These deferrals are recognized in the Consolidated Statement of Income during the period in which they are subsequently included in the LEC rates. Income Taxes The consolidated financial statements include two categories of income taxes-current and deferred.

Current income taxes represent the amounts of tax expected to be reported on ACE' s federal and state income tax returns. Deferred income taxes are discussed below. 11-20 * *

• Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement and tax bases of existing assets and liabilities and are measured using presently enacted tax rates. The. portion of ACE' s deferred tax liability applicable to utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is shown on the Consolidated Balance Sheets as "Deferred recoverable income taxes." Deferred recoverable income taxes were $102.2 million and $85.9 million as of December 31, 1998, and 1997, respectively.

Deferred income tax expense represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes. Investment tax credits from utility plant purchased in prior years are reported on the Consolidated Balance Sheets as Deferred investment tax credits.

These investment tax credits are being amortized to income over the useful lives of the related utility plant. Energy Trading and Risk Management Activities Since the Merger, ACE has not used derivative financial instruments because ACE ceased its unregulated.

electricity trading activities.

In 1997, to minimize the risk of market fluctuations associated with unregulated electricity trading, ACE entered into various transactions involving derivative financial instruments for hedging purposes.

Gains or losses associated with the derivative transactions were recognized in operations in the period the derivative instrument was terminated or extinguished or ceased to be qualified as a hedge. In June 1998, the Financial Accounting Standards Board (FASB) issued SPAS No. 133, " Accounting for Derivative Instruments and Hedging Activities," which becomes effective in the first quarter of fiscal years beginning after June 15, 1999, unless early adoption is elected. SPAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities.

It requires that all derivatives be recognized as assets or liabilities in the balance sheet and be measured at fair value. Under specified conditions, a derivative may be designated as a hedge. The change in the fair value of derivatives which are not designated as hedges is recognized in earnings.

For derivatives designated as hedges of changes in the fair value of an asset or liability, or as a hedge of exposure to variable cash flows of a f9recasted transaction, earnings are affected to the extent the hedge does not match offsetting changes in the hedged item. ACE currently cannot determine the effect that SPAS No. 133 will have on its financial statements:

Cash Equivalents ACE considers all highly liquid investments and debt securities*

purchased with a maturity of three months or less to be cash equivalents.

• *

• Debt Costs Debt premium, discount and expense are amortized over the life of the related debt. Costs associated with refinancing debt are deferred and amortized over the life of the new debt. 2. SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the year (Dollars in Thousands)

Interest .............................................. . Taxes, net of refunds II-21 1998 $68,278 $48,215 1997 1996 $64,966 $65,269 $48,400 $36,937

3. INCOME TAXES ACE, as a subsidiary of Conectiv, is included in the consolidated federal income tax return of Conectiv.

Income taxes are allocated to ACE based upon its taxable income or loss, determined on a separate return basis. The components of income tax expense for the years ended December 31, 1998, 1997, and 1996 are as follows: (Dollars in Thousands)

Federal: Current ............................................ . Deferred ........................................... . State: Current ............................................ . Deferred ........................................... . Investment tax credit adjustments

........................ . 1998 $43,133 (27,694) 14,650 (10,221) (1,690) $18,178 1997 1996 $49,646 $35,510 3,330 3,982 (2,534) (2,534) $50,442 $36,958 The amount computed by multiplying income before tax by the federal statutory rate is reconciled below to the total income tax expense. 1998 1997 1996 (Dollars in Thousands)

Amount Rate Amount Rate Amount Rate Statutory federal income tax expense ...............

$16,959 35% $47,666 35% $39,191 35% State income taxes, net of federal tax benefit ....... 2,878 6 Plant basis differences

..... 3,767 8 4,952 4 3,096* 3 Amortization of investment tax credits .............

(1,690) (3) (2,534) (2) (2,534) (2) Other, net ................

(3,736) (8) 358 (2,795) (3) Total income tax expense ... $18,178 38% $50,442 37% $36,958 33% -Effective January 1, 1998, New Jersey eliminated the Gross Receipts and Franchise Tax paid by electric, natural gas and telecommunication public utilities.

In its place, utilities are now subject to the state's corporate business tax. In addition, the state's existing sales and use tax was expanded to include retail sales of electric power and natural gas. A Transitional Energy* Facility As.sessment Tax (TEFA) on electric and natural gas utilities will be phased-out over a five-year period. On January 1, 1999, and each of the four years thereafter, the TEFA will be reduced by 20%. When fully implemented, the tax law changes will reduce ACE's effective state tax rate from 13% to approximately 7%. Savings from these changes in New Jersey tax law will be passed through to ACE's customers.

II-22 * *

• *

• Items comprising deferred tax balances as of December 31, 1998 and 1997 are as follows: (Dollars in Thousands)

Deferred tax liabilities:

Utility plant basis differences

.................................. . Deferred recoverable income taxes ............................. . Unrecovered purchase power costs ............................. . State excise taxes ............................................ . Other ...................................................... . Total deferred tax liabilities

............................... . Deferred tax assets: Deferred investment tax credits ................................ . Other ...................................................... . Total deferred tax assets .................................. . Total deferred taxes, net 4. MERGER 1998 $274,773 35,944 12,239 12,822 31,852 367,630 22,749 9,187 31,936 $335,694 1997 $302,238 30,050 16,813 16,326 34,190 399,617 23,775 11,741 35,516 $364,101 On March 1, 1998, ACE and DPL became wholly-owned subsidiaries of Conectiv (the Merger). Before the Merger, Atlantic owned ACE and nonutility subsidiaries.

As a result of the Merger, Atlantic no longer exists and Conectiv owns (directly or indirectly)

ACE, DPL and the nonutility subsidiaries formerly held separately by Atlantic and DPL. Conectiv is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). The Merger was accounted for under the purchase method, with DPL as the acquirer.

ACE's financial statements do not reflect push-down

accounting-the adjustment of the values of assets and liabilities as of the Merger date and recording of goodwill.

Push-down accounting was not used because ACE had preferred stock and public debt outstanding as of the Merger date. Under the terms of the agreement, Atlantic stockholders received 0.75 shares of Conectiv's common stock and 0.125 shares of Conectiv's Class A common stock for each share of Atlantic stock held. DPL stockholders received one share of Conectiv's common stock for each share of DPL common stock held. ACE has recorded the financial effects of enhanced retirement offers and other employee separation programs utilized to reduce the workforce by 354 positions.

The employee separation programs and other Merger-related costs resulted in a $61.1 million pre-tax charge to expense (or $36.6 million after taxes) for the year ended December 31, 1998 and a $22.2 million pre-tax charge to expenses (or $15.6 million after taxes) for the year ended December 31, 1997. The pre-tax expenses are shown on the Statement of Income as "Employee separation and other merger-related costs." As of December 31, 1998, $35.4 million of the $61.1 million expense for the year ended December 31, 1998 had been paid, $16.l million will not require the use of operating funds, and $9.6 million remains to be paid from operating funds. As part of the Merger, ACE has consolidated its operational and administrative facilities throughout its regulated service territory, causing certain assets to be held for sale. The estimated fair market value of these assets is $18.0 million less than their aggregate carrying value of $32.7 million as of December 31, 1998. In accordance with, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," ACE recorded in the fourth quarter of 1998 an estimated impairment loss of $18.0 million ($10.6 million net of taxes). NOTE 5. RATE MATTERS Electric Utility Industry Restructuring As discussed below, the electric utility industry is being deregulated in New Jersey. Generally, the restructuring will deregulate the supply component of the price charged to a customer for electricity, and II-23 electricity suppliers will compete to supply electricity to customers.

Customers will continue to pay the local utility a regulated price for the delivery of the electricity over the transmission and distribution system.

• Stranded costs are costs which may not be recoverable in a competitive energy supply market due to lower prices or customers choosing a different supplier.

Stranded costs generally include above-market costs associated with generation facilities or long-term purchased power agreements, and regulatory assets. ACE has quantified stranded costs in a New Jersey regulatory filing and has proposed a plan seeking approval for recovery of those costs from customers during the transition to a competitive market. When the NJBPU issues an order specifically addressing deregulation in ACE's service territory, ACE will cease applying SFAS No. 71 to its electricity supply business.

To the extent that the NJBPU's order provides for recovery of stranded costs through cash flows from the regulated transmission and distribution business, the stranded costs would continue to be recognized as assets under SFAS No. 71. Any stranded costs (including regulatory assets) for which cost recovery is not provided would be expensed.

The amount of stranded costs ultimately recovered from utility customers, if any, and the full impact of New Jersey legislation deregulating the electric utility industry, as discussed below, cannot be predicted.

Also, the quantification of stranded costs under existing GAAP differs from methods used in regulatory filings. Among other differences, GAAP precludes recognition of the gains on plants (or purchased power contracts) not impaired, but requires write down of the plants that are impaired.

Due to these considerations, market conditions, timing and other factors, ACE's management currently cannot predict the ultimate effects that electric utility industry deregulation may have on the financial statements of ACE, although deregulation may have a material adverse effect on ACE's results of operations.

New Jersey Legislation The "Electric Discount and Energy Competition Act" (the Act) was signed into law by the Governor of New Jersey on February 9, 1999. The Act provides for retail choice of electricity suppliers; deregulation of electric rates and other competitive services, such as metering and billing; separation of competitive and regulated services; unbundling of rates for electric service; and licensing of electric and gas suppliers.

August 1, 1999 is the effective starting date for each utility to provide retail choice of electricity suppliers to all of its customers.

The Act requires each electric utility to reduce its rates by at least 5% at the start of retail choice and by 10% within 36 months of the start of choice. If the NJBPU determines that a rate decrease of more than 10% is warranted, a "just and reasonable" financial test is applied. The mandated rate reductions must be sustained through the end of the 48th month after choice begins. The Act requires that the rate reductions be measured against the rates in effect on April 30, 1997. The rate reductions mandated by the Act could have a material adverse effect upon the results of operations of ACE. In connection with the deregulation of electric rates, the Act authorizes the NJBPU to permit electric public utilities to recover the full amount of their stranded costs through a non-bypassable market transition charge, as long as the mandated rate reductions are achieved.

The NJBPU will determine the utility's stranded cost amount. The NJBPU-determined stranded cost amount will be subject to periodic recalculation and true-up over the recovery period. The Act establishes an 8-year recovery period for stranded costs associated with owned generation.

The recovery period can be extended by the NJBPU so as to allow for the full recovery of the stranded costs and the meeting of mandated rate reductions.

The recovery period for stranded costs associated with purchased power contracts is to be the remainder of the contract term. In addition, the Act would allow for the issuance of transition bonds to finance portions of a given utility's stranded costs, as determined to be appropriate by the NJBPU. All savings generated through the use of such transition bonds are to be provided to the customers through rate reductions.

• The Act establishes the current incumbent utility as the provider of default service

or Basic Generation

• Service (BGS) for a period of 3 years. Future proceedings will be held to determine if the provision of BGS II-24

• *

• should be made competitive.

The Act contains numerous provisions regarding the providing of competitive services by each utility. The primary focus is to ensure that there is no cross subsidization from the utility to competitive entities.

The NJBPU also is required to develop fair competition standards and conduct an audit to determine that the utilities are in compliance with those standards.

The Act gives the NJBPU the authority to order a utility to divest its generating assets if it is determined through a hearing that competition or customers are being adversely affected by plant location, market power or non-competitive rates. The NJBPU may require that the generation function be separated from a utility's non-competitive functions.

The NJBPU is authorized to establish standards for the licensing of energy suppliers, standards for switching customers from one supplier to another, and standards for issues such as credit and collections.

The Act also contains provisions for protecting workers displaced by the impacts of the restructuring of the utility industry.

Stranded Cost Filing Electric utilities in New Jersey, including ACE, previously filed stranded cost estimates and unbundled rates, as required by the NJBPU. On August 19, 1998, an Administrative Law Judge (ALJ) from the New Jersey Office of Administrative Law issued an initial decision on ACE's stranded costs and unbundled rate filing. The ALJ;in

• reviewing ACE's filing, recognized that ACE's stranded costs were $812 million for nonutility generation contracts and $397 million for owned generation.

The ALJ made no specific recommendations on rate issues. A final NJBPU decision on this filing is expected by mid-1999.

Other Rate Matters ACE is sharing a portion of the net cost savings expected to result from the Merger (see Note 4 to the Consolidated Financial Statements) with its customers through reduced electric retail customer base rates. ACE's total Merger-related electric base rate decrease of $15.7 million was phased-in as follows: (1) $5.0 million effective January 1, 1998 coincident with a $5.0 million increase for recovery of deferred other postretirement benefit costs (OPEB); (2) $9.9 million effective March 1, 1998, and (3) $0.8 million effective January 1, 1999. ACE is subject to a performance.

standard for its five jointly-owned nuclear units. Under the standard, the composite target capacity factor for such units is 70%, based upon the maximum dependable capacity of the units. The zone of reasonable performance (deadband) is between 65% and 75%. Penalties or rewards are based on graduated percentages of estimated costs of replacement power. LEC rates are adjusted annually to include any penalty or reward resulting froin the nuclear unit performance standard.

Pursuant to a December 1996 stipulation agreement, the performance of Salem Units 1 and 2, during prolonged outages which began in the second quarter of 1995, is not included in the calculation of a nuclear performance penalty. ACE was not subject to a nuclear performance penalty in 1996, 1997 or 1998. Refer to Note 3 to the Consolidated Financial Statements for information concerning rate changes related to changes in the New Jersey tax laws. ACE submitted its second Demand Side Management (DSM) Plan for the period from September 1997 through August 1998 in April 1997. The DSM Plan includes programs that address energy conservation needs of the residential, commercial and industrial markets. During the course of DSM Plan proceedings, New Jersey's Division of the Ratepayer Advocate (Ratepayer Advocate) alleged that ACE has been recovering more in rates for DSM programs than it is spending on such programs.

ACE's position is that the level of DSM expenditures cannot be viewed in isolation, but must be considered in light of both the overall history of DSM expenditures under current rates, as well as ACE's overall revenue requirement needs in a rate proceeding.

The Ratepayer Advocate contends that any over-recovery and treatment of such over-recovery should be addressed outside the context of a base rate proceeding.

The NJBPU has not yet taken any action on this matter. ACE cannot predict the outcome of this matter. II-25 _/

NOTE 6. PENSION AND OTHER POSTRETIREMENT BENEFITS Assumptions 1998 1997 1996 Discount rates used to determine projected benefit obligation as of December 31 ................................. . 6.75% 7.00% 7.50% Rates of increase in compensation levels ................. . 4.50% 3.50% 3.50% Expected long-term rates of return on pension assets ...... . 9.00% 9.00% 8.50% Expected long-term rates of return on other postretirement benefit assets ...................................... . 9.00% 7.00% 7.00% Health care cost trend rate on covered charges ............ . 7.00% 7.50% 8.00% The health-care cost trend rate, or the expected rate of increase in health-care costs, is assumed to continue to gradually decrease to 5.0% by 2002. Increasing the health-care cost trend rates of future years by one percentage point would increase the accumulated postretirement benefit obligation by $11.8 million and would increase annual aggregate service and interest costs by $1.5 million.

Decreasing the health-care cost trend rates of future years by one percentage point would decrease the accumulated postretirement benefit obligation by $10.4 million and would decrease annual aggregate service and interest costs by $1.3 million. The following schedules reconcile the beginning and ending balances of the pension and other postretirement benefit obligations and related plan assets. Other postretirement benefits include medical benefits for retirees and their spouses and retiree life insurance.

Change in Benefit Obligation (Dollar in Thousands)

Benefit obligation at beginning of year ...... . Service cost ............................. . Interest cost ............................. . Plan amendments

........................ . Actuarial (gain) loss ...................... . Special termination benefits ............... . Curtailment (gain) loss .................... . Settlement (gain) loss ..................... . Benefits paid ............................ . Pension Benefits 1998 $239,000 7,558 20,583 (10,622) 90,862 11,846 (3,883) 318 (54,722) 1997 $207,340 6,763 15,840 25,122 4,475 (20,540) Benefit obligation at end of year. . . . . . . . . . . . .

$300,940 $239,000 Change in Plan Assets Pension Benefits (Dollars in Thousands) 1998 1997 Fair value of assets at beginning of year ...... $259,500 $236,000 Actual return on plan assets ................

10,062 35,414 Employer contributions

....................

8,626 Benefits paid .............................

(54,722) (20,540) Fair value of assets at end of year ...........

$214,840 $259,500 II-26 Other Postretirement Benefits 1998 1997 $103,824 $107,105 3,643 2,531 8,816 6,843 15,460 (7,955) 1,270 6,597 (4,275) (4,700) $135,335 $103,824 Other Postretirement Benefits 1998 1997 $ 20,100 $ 18,000 1,119 800 13,261 6,000 (4,275) (4,700) $ 30,205 $ 20,100 * * *

• *

• Reconciliation of Funded Status of the Plans Other Postretirement Pension Benefits Benefits (Dollars in Thousands) 1998 1997 1998 1997 Funded status at end of year .........

$(86,100)

$20,500 $(105,130)

$(83,724)

Unrecognized net actuarial (gain) loss * ...........................

86,070 (10,810) 27,886 4,727 Unrecognized prior service cost ...... (10,447) 232 Unrecognized net transition (asset) obligation

......................

(1,532) 32,637 41,521 Net amount recognized at end of year ....................

• ....... $(10,477)

$ 8,390 $ (44,607) $(37,476) . Based on fair values as of December 31, 1998, the pension plan assets were comprised of publicly traded equity securities

($143.9 million or 67%) and fixed income obligations

($70.9 million or 33%). As of December 31, 1998, the other postretirement benefit plan assets were comprised entirely of fixed income securities.

Components of Net Periodic Benefit Cost Pension Benefits Other Postretiremerit Benefits (Dollars in Thousands) 1998 1997 1996 1998 1997 1996 Service cost .....................

$ 7,558 $ 6,763 $ 6,870 $ 3,643 $2,531 $2,688 Interest cost .....................

20,583 15,840 14,569 8,816 6,843 7,482 Expected return on assets ..........

(20,414) (20,160) (17,376) (1,015) (1,275) (1,122) Amortization of: Transition obligation (asset) ...... (41) 24 24 2,404 2,768 2,768 Prior service cost ...............

20 (172) (172) 50 Actuarial loss ..................

2,131 263 204 710 566 Cost before items below ....... 9,837 2,558 4,119 14,608 10,867 12,382 Special termination benefits ........ 11,846 1,270 Curtailment (gfiln) loss ............

(3,883) 5,932 6,597 Settlement loss ...................

318 330 Total net periodic benefit cost .... $ 18,118 $ 8,820 $ 4,119 $ 22,475 $ 10,867 $ 12,382 Portion of net periodic benefit cost included in results of operations

.. $15,514 $ 8,162 $ 3,040 $19,553 $3,640 $3,104 The components of 1998 and 1997 pension and other postretirement periodic benefit costs attributed to special benefits, curtailment (gain) loss, and settlement loss resulted from the enhanced retirement offer and other employee separation programs associated with the Merger. Other postretirement benefit costs in excess of the amount recovered in customer rates were deferred from 1993 to 1997, including

$4.9 million in 1997 and $6.4 million in 1996. ACE began to recover these costs, through customer rates, over a 15 year period beginning in 1998. See Note 5 and Note 14 to the Consolidated Financial Statements for additional information . Effective January 1, 1999, ACE's covered employees began participating in a "cash balance" pension plan adopted by Conectiv.

Contributions, which vary based on the covered employee's age and years of service, will II-27 be made to individual employee accounts provided for under the plan. The "cash balance" of each employee's

• account increases based on employer contributions and income credited to the account. The aggregate of the employee's accounts will be ACE's pension obligation.

During 1998, ACE's covered employees began participating in the Conectiv 401(k) plans. Conectiv contributes to the plans, in the form of Conectiv stock, at varying levels up to. $0.50 for each dollar contributed by covered employees, for up to 6% of employee base pay. Prior to the Merger, ACE had 401(k) plans for its employees, under which ACE contributed up to $0.50 for each dollar contributed by covered employees, for up to 6% of employee base pay. The cost of the plans for 1998, 1997, and 1996 was $1.9 million, $2.0 million and $1.9 million, respectively.

7. JOINTLY-OWNED GENERATING STATIONS ACE owns jointly with other utilities several electric generating facilities.

ACE is responsible for its pro-rata share of the costs of construction, operation and maintenance of each facility.

ACE provides financing during the construction period for its share of the jointly-owned facilities and includes its share of direct operations and maintenance expenses in the Consolidated Statements of Income. The amounts shown below represent ACE's share of each facility at, or for the year ended, December 31, 1998, including AFUDC as appropriate.

Cone-Peach Hope (Dollars in Thousands)

Keystone ma ugh Bottom Salem Creek Energy Source .................................. . Coal Coal Nuclear Nuclear Nuclear Ownership Share ................................ . 2.47% 3.83% 7.51% 7.41% 5.00% MW Capability Owned .......................... . 42 65 164 164 52 Electric Plant in Service .......................... . $13,640 $33,956 $135,775 $245,628 $241,062 Accumulated Depreciation*

....................... . $ 3,815 $ 8,310 $ 62,688 $ 90,120 '$ 82,854 Construction Work in Progress .................... . $ 104 $ 456 $ 13,037 $ 7,260 $ 1,251

• Excludes Nuclear Decommissioning Reserve. 8. CUMULATIVE PREFERRED SECURITIES ACE has authorized 799,979 shares of Cumulative Preferred Stock, $100 Par Value, two million shares of No Par Preferred Stock and three million shares of Preference Stock, No Par Value. If preferred dividends are in arrears for at least a full year, preferred stockholders have the right to elect a majority of directors to the Board of Directors until all dividends in arrears have been paid. Preferred Stock Subject to Mandatory Redemption 1998 1997 Series Shares (000) Shares (000) -$8.20, no par value ........................................... . $ 100,000 $10,000 $7.80, no par value ........... .............................. . 239,500 23,950 239,500 23,950 Total ....................................................

• • • • 239,500 $23,950 339,500 $33,950 Beginning May 1, 2001, 115,000 shares of the remaining

$7.80 No Par Preferred Stock must be redeemed annually through the operation of a sinking fund at a redemption price of $100 per share. ACE has the option to redeem up to an additional 115,000 shares without premium on any annual sinking fund date. ACE redeemed its $8.20 No Par Preferred Stock ($100 per share stated value) as follows: 100,000 shares in August 1998; 200,000 shares in August 1997, and 200,000 shares in August 1996. In September 1996, ACE 11-28 * /

• redeemed the remaining 50,000 shares of its $8.25 Preferred Stock ($100 per share stated value). In August 1996, . ACE repurchased 460,500 shares of its $7.80 No Par Preferred Stock ($100 per share stated value). In February 1996, ACE redeemed the remaining 120,000 shares of its $8.53 No Par Preferred Stock ($100 per share stated value). Preferred Stock Not Subject to Mandatory Redemption Series 4%, $100 par value ................................ . 4.1 %, $100 par value .............................. . 4.35%, $100 par value ............................. . 4.35%, $100 par value ............................. . : 4.75%, $100 par value ............................. .

• 5%, $100 par value ................................ . Total ........................................ . 1998 Shares (000) 24,268 20,504 3,102 1,680 8,631 4,120 62,305 $2,427 2,051 310 168 863 412 $6,231 1997 Shares 77,000 72,000 15,000 36,000 50,000 50,000 300,000 (000) $ 7,700 7,200 1,500 3,600 5,000 5,000 $30,000 Current Redemption Price $105.50 101.00 101.00 101.00 101.00 100.00 Cumulative Preferred Stock Not Subject to Mandatory Redemption is redeemable solely at the option of ACE. In October 1998, ACE purchased and retired 237,695 shares, or $23.77 million of various series of mandatorily redeemable preferred stock, which had an average dividend rate of 4.4%. ACE realized a $2.5 million gain on this preferred stock redemption which is presented as Gain on Preferred Stock Redemption within the 1998 Consolidated Statement of Income. In September 1996, ACE redeemed 100,000 shares of its 7.52% Preferred Stock $100 Par Value. ACE Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of ACE In November 1998, Atlantic Capital II, a wholly-owned subsidiary financing trust, issued $25 million in aggregate liquidation amount of 7%% Cumulative Trust Preferred Capital Securities (representing 1,000,000 preferred securities at $25 per security).

At the same time, $25.8 million in aggregate principal amount of 73/s % Junior Subordinated Debentures, Series I, due 2028 (7%% Debentures) were issued to Atlantic Capital II. For consolidated financial reporting purposes, the 73/s % Debentures are eliminated in consolidation against the trust's investment in the 73/s % Debentures.

The preferred trust securities are subject to mandatory redemption upon payment of *the 73/s % Debentures at maturity or upon redemption.

The 73/s % Debentures are subject to redemption, in whole or in part at the option of ACE, at 100% of their principal amount plus accrued interest, after an initial period during which they may not be redeemed and at any time upon the occurrence of certain events. The combination, of the obligations of ACE, pursuant to the 73/s % Debentures and ACE' s guarantee of distributions with respect to trust securities, to the extent the trust has funds available therefor, constitute a full and unconditiol).al guarantee by ACE of the obligations of the trust under the trust securities that the trust has issued. ACE is the owner of all of the common securities of the trust, which constitute approximately 3% of the liquidation amount of all of the trust securities issued by the trust. Atlantic Capital I is a wholly-owned subsidiary financing trust which is structured similarly to Atlantic Capital II (discussed above). In October 1996, Atlantic Capital I, issued $70 million (2,800,000 shares) of 8.25% Cumulative Quarterly Income ACE Obligated Mandatorily Redeemable Preferred Securities with a stated liquidation preference of $25 each. Atlantic Capital I's sole investment is in ACE's 8.25% Junior Subordinated Deferrable Interest Debentures (8.25% Debentures).

The 8.25% Debentures and Preferred Securities mature in 2026. II-29

9. DEBT December 31,

• Maturity Secured debt Date 1998 1997 (Dollars in Thousands)

Medium Term Notes Series B (6.28%) ........................... . 2/111998 $ $ 56,000 Medium Term Notes Series A (7.52%) ........................... . 1999 30,000 30,000 Medium Term Notes Series B (6.83%) ........................... . 2000 46,000 46,000 Medium Term Notes Series C (6.86%) ........................... . 2001 40,000 40,000 Medium Term Notes Series C (7.02%) ........................... . 2002 30,000 30,000 Medium Term Notes Series B (7.18%) ........................... . 2003 20,000 20,000 Medium Term Notes Series D (6.00%) ........................... . 2003 20,000 Medium Term Notes Series A (7.98%) ........................... . 2004 30,000 30,000 Medium Term Notes Series B (7.125%) .......................... . 2004 28,000 28,000 Medium Term Notes Series C (7.15%) ........................... . 2004 9,000 9,000 Medium Term Notes Series B (6.45%) ........................... . 2005 40,000 40,000 Medium Term Notes Series D (6.19%) ........................... . 2006 65,000 63/s % Pollution Control Series ................................... . 12/1/2006 2,350 2,425 Medium Term Notes Series C (7.15%) ........................... . 2007 1,000 1,000 Medium Term Notes Series B (6.76%) ........................... . 2008 50,000 50,000 Medium Term Notes Series C (7.25%) ........................... . 2010 1,000 1,000 6% % First Mortgage Bonds .................................... . 8/1/2013 75,000 75,000 Medium Term Notes Series C (7.63%) ........................... . 2014 7,000 7,000 Medium Term Notes Series C (7.68%) ........................... . 2015 15,000 15,000 Medium Term Notes Series C (7.68%) ........................... . 2016 2,000 2,000 6.80% Pollution Control Series A ................................ . 7% First Mortgage Bonds ...................................... . 5.60% Pollution Control Series A ................................ . 3/1/2021 38,865 38,865

• 9/1/2023 75,000 75,000 11/1/2025 4,000 4,000 7% First Mortgage Bonds ...................................... . 8/1/2028 75,000 75,000 6.15% Pollution Control Series A ................................ . 6/1/2029 23,150 23,150 7 .20% Pollution Control Series A ................................ . 11/1/2029 25,000 25,000 7% Pollution Control Series B .................................. . 11/1/2029 6,500 6,500 758,865 729,940 Unsecured debt 6.46% Medium Term Notes Series A ............................. . 4/1/2002 20,000 20,000 6.63% Medium Term Notes Series A ............................. . 6/2/2003 30,000 30,000 7.52% Medium Term Notes Series A ............................. . 4/2/2007 5,000 5,000 7.50% Medium Term Notes Series A ............................. . 4/2/2007 10,000 10,000 65,000 65,000 7w% Debentures

............................................. . 5/111998 2,500 Unamortized Premium and Discount-Net

.......................... . (2,663) (2,721) Total Long Term Debt ......................................... . 821,202 794,719 Add: Short Term Debt to be Refinanced

.......................... . 16,425 Less: Current Portion of Long-Tem1 Debt ......................... . (30,075) Total Long Term Debt ......................................... . 791,127 811,144 Variable Rate Demand Bonds, Pollution Control Series A ........... . 2014 18,200 18,200 V aiiable Rate Demand Bonds, Pollution Control Series B ........... . 2017 4400 4,400 Total Long Term Debt & Variable Rate Demand Bonds ............. . $813,727 $833,744 11-30

• Substantially all of ACE's utility plant is subject to the lien of the Mortgage and Deed of Trust dated January 15, 1937, as amended and supplemented, collateralizing ACE's First Mortgage Bonds and Secured Medium Term Notes. Variable Rate Demand Bonds (VRDB) are classified as current liabilities because the VRDB are due on demand by the bondholder.

However, bonds submitted to ACE for purchase are remarketed by a remarketing agent on a best efforts basis. ACE expects that bonds submitted for purchase will continue to be remarketed successfully due to ACE's credit worthiness and the bonds' interest rates being set at market. ACE also may utilize one of the fixed rate/fixed term conversion options of the bonds. Thus, ACE considers the VRDB to be a source of long-term financing.

Average interest rates on the VRDB were 3.2% for 1998 and 3.6% for 1997. ACE funds its interim financing requirements by issuing commerCial paper and borrowing against bank credit lines. At December 31, 1998, ACE had no outstanding short-term debt and had total bank credit lines of $195 million, all of which was available for borrowing.

ACE's weighted daily average interest rate on short-term debt outstanding at December 31, 1997 was 5.8%. On January 12, 1998, ACE issued $85 million of Secured Medium Term Notes, Series D maturing in January 2003 and January 2006 (6.1 % average interest rate). The net proceeds received by ACE from the issuance of the Medium Term Notes was used to repay short-term debt and long-term debt (see schedule below) and $10 million of $8.20 No Par Preferred Stock in 1998. The following schedule shows debt redemptions made, at maturity in 1998. Series (Dollars in Thousands) 6.35% Medium-Term Notes .................................. . 6.37% Medium-Term Notes .................................. . 7.25% Debentures

....................... , .................. . 5.50% Medium-Term Notes .................................. . 6.375% Pollution Control Bonds* ............................. .

• Annual sinking fund requirement on bonds due December 1, 2006. Maturity Date Principal 1/26/98 1127/98 5/01/98 5/14/98 12/01/09 $ 4,000 46,000 2,500 6,000 75 $58,575 Maturities and Sinking Fund Requirements for Long-Term Debt (Dollars in thousands) 1999 .......................... . 2000 ......................

• .... . 2001 .......................... . 2002 .......................... . 2003 .......................... . 10. COMMON STOCKHOLDER'S EQUITY $30,075 46,075 40,075 50,075 70,075 For information concerning changes to the common equity accounts of ACE, see the Consolidated Statements of Changes in Common Stockholder's Equity. Effective March 1, 1998, all of the outstanding shares of ACE were acquired by Conectiv, pursuant to the Merger, as discussed in Note 4 to the Consolidated Financial Statements.

Under ACE's certificate of incorporation, ACE is subject to certain limitations on the payment of dividends to Conectiv, which is the holder of all of ACE's common stock. When full dividends have been paid on the Preferred Stock Securities of ACE for all past dividend periods, dividends may be declared and paid by ACE on II-31 its common stock, as determined by the Board of Directors of ACE, out of funds legally available for the payment of dividends.

11. COMMITMENTS Construction Program Capital expenditures for 1999 are estimated to approximately

$85.4 million. Purchased Capacity and Energy Arrangements ACE arranges with various providers of bulk energy to obtain sufficient supplies of capacity and energy. Terms of the arrangements vary in length to enable ACE to optimally manage its supply portfolio in response to changing market conditions.

At December 31, 1998, ACE has contracted for 828 megawatts (MWs) of purchased capacity with terms remaining of 1 to 26 years. Information regarding these arrangements relative to ACE was as follows: Percentage of MW capacity ..............................

_ ...... . Percentage of energy output .................................... . Capacity charges (millions)

..................................... . Energy charges (millions)

...................................... . 1998 1997 1996 33% -41% $173 $126 29% 30% 54% 55% $180 $179 $137 $145 Electric capacity purchased from certain nonutility suppliers is recoverable through the LEC, which amounted to

$166.9 million, $166.8 million and $165.3 million in 1998, 1997 and 1996, respectively.

Based on

• existing contracts as of December 31, 1998, ACE's future commitments for capacity and energy _under long-term purchased power contracts are estimated to be $269 million in 1999; $275 million in 2000; $266 million in 2001; * $266 million in 2002; $268 million in 2003. Due to uncertainties surrounding restructuring of the electric utility industry, ACE has not forecasted its long-term purchased power commitments beyond 2003. Leases ACE has a contractual obligation to obtain nuclear fuel for the Salem, Hope _Creek and Peach Bottom stations.

The asset and related obligation for the leased fuel are reduced as the fuei is burned and are increased as additional fuel purchases are made. ACE's obligation under the contract is generally the net book value of the nuclear fuel financed, which was $35.0 million as of December 31, 1998. Operating expenses for 1998, 1997 and 1996 include leased nuclear fuel costs of $11.7 million, $9.8 million and $8.7 million, respectively.

ACE also leases other types of property and equipment for use in its operations.

Amounts charged to operating expenses for these leases were $4.6 million in 1998, $2.4 million in 1997 and $2.6 million in 1996. Future minimum rental payments for all non-cancellable lease agreements, excluding nuclear fuel, are less than $3.0 million per year for each of the next five years. 12. CONTINGENCIES Environmental Matters ACE is subject to regulation with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitation on land use by various federal, regional, state, and local authorities.

Costs may be incurred to clean up facilities found to be contaminated due to past disposal practices.

Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or uncontrolled hazardous waste sites. ACE is a potentially responsible party at a state superfund site and has agreed, along with other responsible parties, to remediate the site pursuant to an

• Administrative Consent Order with the New Jersey Department of Environmental Protection.

ACE is also a II-32

• defendant in an action to.recover costs at a federal superfund site in Gloucester, New Jersey. There is $1.0 million included in ACE's current liabilities as of December 31, 1998, for remediation activities at these sites. ACE does not expect such future costs to have a material effect on its financial position or results of operations.

Nuclear Insurance In conjunction with ACE's ownership interests in Peach Bottom, Salem, and Hope Creek, ACE could be assessed for a portion of any third-party claims associated with an incident at any commercial nuclear power plant in the United States. Under the provisions of the Price Anderson Act, if third party claims relating to such an incident exceed $200 million (the amount of primary insurance), ACE could be assessed up to $30.7 million on an aggregate basis for such third-party claims. In addition, Congress could impose a revenue-raising measure on the nuclear industry to pay such claims The co-owners of Peach Bottom, Salem, and Hope Creek maintain property insurance coverage of approximately

$2.8 billion for each unit for loss or damage to the units, including coverage for decontamination expense and premature decommissioning.

• In addition, ACE is a member of an industry mutual insurance company, which provides replacement power cost coverage in the event of a major accidental outage at a nuclear power plant. Under these coverages, ACE is subject to potential retrospective loss experience assessments of up to $5.4 million. 13. SALEM NUCLEAR GENERATING STATION In December 1996, the NJBPU issued an Order approving a stipulation of settlement reached among the parties settling the issues primarily regarding replacement power costs related to an extended Salem outage, which began in the second quarter of 1995. The stipulations.provided for recovery through LEC rates of ACE's replacement power costs for the Salem outage, up to each Salem Unit's agreed-upon return-to-service date (June 30, 1997 for Unit 1 and December 31, 1996 for Unit 2). The Salem Units returned to service in August 1997 (Unit 2) and April 1998 (Unit 1). As a result, unrecovered purchased power costs of $2.1 million in 1998 and $10.2 million in 1997 were expensed.

The stipulation of settlement approved by the NJBPU in December 1996 also provided customers with a $13 million base rate credit, primarily for resolution of issues associated with the extended Salem outage. ACE accrued the $13 million base rate credit in 1996 as a reduction of electric revenues.

As previously reported; on February 27, 1996, the co-owners of Salem, including ACE and DPL, filed a complaint in the United States District Court for New Jersey against Westinghouse Electric Corporation (Westinghouse), the designer and manufacturer of the Salem steam generators.

The complaint, which sought to recover from Westinghouse the costs associated with and resulting from the cracks discovered in Salem's steam generators and with replacing such steam generators, alleged violations of federal and New Jersey Racketeer Influenced and Corrupt Organizations Acts, fraud, negligent misrepresentation and breach of contract.

On November 4, 1998, the Court granted Westinghouse's motion for summary judgment with regard to the federal Racketeer Influenced and Corrupt Organizations Act claim, and dismissed the remaining state law claims without prejudice.

On November 18, 1998, the co-owners re-filed their state law claims against Westinghouse in the Superior Court of New Jersey. The co-owners also filed an appeal of the District Court's dismissal with the United States Court of Appeals for the Third Circuit. 14. REGULATORY ASSETS In conformity with generally accepted accounting principles, ACE's accounting policies reflect the financial effects of rate regulation and decisions issued by the NJBPU and the FERC. In accordance with the provisions 11-33 of SFAS No. 71, ACE defers expense recognition of certain costs and records an asset, as a result of the effects of rate regulation.

Except for deferred energy costs, which are classified as a current asset or liability, these "regulatory assets" are included on ACE's Consolidated Balance Sheets under "Deferred Charges and Other Assets.

The costs of these assets are either being recovered or are probable of being recovered through customer rates. Generally, the costs of these assets are recognized in operating expenses over the period the cost is recovered from customers.

For information about the impact of electric utility industry restructuring on accounting for regulatory assets, see Note 5 to the Consolidated Financial Statements.

The table shown below details total regulatory assets as of December 31, 1998 and 1997. (Dollars in Thousands)

Deferred recoverable income taxes Unrecovered purchased power costs: Capacity costs ..................

• .............................. . Contract renegotiation costs .................................... . Unrecovered state excise taxes .................................... . Deferred debt refinancing costs ................................... . Under (Over) recovered deferred energy costs ....................... . Deferred other postretirement benefit costs .......................... . Asbestos removal costs .......................................... . Nuclear decontamination and decommissioning of federally-owned nuclear units ..................................

." .............. . Other ......................................................... .

• From December 31, 1998 1998 $102,223 30,608 17,666 35,594 28,043 (15,577) 34,978 8,546 6,217 10,253 $258,551 1997 $ 85,858 48,038 18,226 45,154 30,002 27,424 37,476 8,816 5,032 10,789 $316,815 Remaining Amortization/

Recovery Period* (A) 2 years 16 years 4 years 1-28 years (B) 14 years 31 years 10 years 1-5 years (A) Amortized as temporary differences between the financial statement and tax bases of assets and liabilities reverse. (B) Recovered from or credited to customers over annual LEC Period. Deferred .recoverable income taxes represent the portion of ACE's deferred tax liability applicable to utility operations that has not been recovered from customers and is recoverable in the future. Unrecovered purchased power capacity costs represent prior deferrals of capacity costs which had exceeded the related cost recovery from customers.

Unrecovered purchased power contract renegotiation costs were incurred through renegotiation of a long-term capacity and energy contract with a certain independent power producer.

Unrecovered state excise taxes represent additional amounts paid as a result of prior legislative changes in the computation of state excise taxes. Deferred debt refinancing costs represent costs incurred to refinance debt and are amortized over the life of the related new debt. Deferred other postretirement benefit costs represent the non-cash portion of OPEB costs deferred during 1993-1997.

Asbestos removal costs were incurred to remove asbestos insulation from a wholly-owned generating station. II-34 *

• Nuclear decontamination and decommissioning costs represent costs associated with decommissioning and decontaminating United States Department of Energy gaseous diffusion enrichment facilities.

Other includes certain amounts being recovered over periods of one to five years. 15. NUCLEAR PLANT DECOMMISSIONING ACE has a trust to fund the future costs of decommissioning each of the five nucleqr units in which it has an ownership interest.

The current annual funding amount, as authorized by the NJBPU, totals $6.4 million and is provided for in rates charged to customers.

The funding amount is based on estimates of the future cost of decommissioning each of the units; the dates that decommissioning activities are expected to begin and the return expected to be earned by the assets of the fund. The present value of ACE's nuclear decommissioning obligation is estimated to be $185 million based on site specific studies filed with and approved by the NJBPU. Decommissioning activities as approved by the NJBPU are expected to begin in 2006 and continue through 2032. ACE's accrued nuclear decommissioning liability, which is reflected in the accumulated reserve for depreciation, was $98.2 million as of December 31, 1998. The provision reflected in depreciation expense for nuclear decommissioning was $6.4 million annually for 1998, 1997 and 1996. External trust funds established by ACE for the purpose of funding nuclear decommissioning costs had an aggregate book balance (stated at fair market value) of $98.2 million as of December 31, 1998. Earnings on the trust funds are recorded as an increase to the accrued nuclear decommissioning liability, which, in effect, reduces the expense recorded for nuclear decommissioning.

The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including ACE, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities.

In February 1996, the FASB issued the Exposure Draft, "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets,

which proposed changes in the accounting for closure and removal costs of long-lived assets, including the recognition, measurement, and classification of decommissioning costs for nuclear generating stations.

If the proposed changes were adopted: (1) annual provisions for decommissioning would increase, (2) the estimated cost for decommissioning would be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trusts would be reported as investment income rather than as a reduction of decommissioning expense. The FASB expects to issue a revised Exposure Draft in the second quarter of 1999. 16. FAIR VALUE OF FINANCIAL INSTRUMENTS A number of items within Current Assets and Current Liabilities on the Consolidated Balance Sheet are considered to be financial instruments because they are cash or are to be settled in cash. Due to their short-term nature, the carrying values of these items approximate their fair market values. Accounts Receivable-Utility Service and Unbilled Revenues are subject to concentration of credit risk because they pertain to utility service conducted within a fixed geographic region. 11-35 The year-end fair value of certain financial instruments are listed below. The fair values were based on quoted market prices of ACE's securities or securities with similar characteristics.

• Funds Held By Trustee ................... . Long Term Debt ........................ . Preferred Stock Subject to Mandatory Redemption

.......................... . Preferred Securities*

..................... . Carrying Value $102.8 791.1 24.0 95.0 1998 1997 Fair Value Carrying Value (Dollars in Millions)

$102.8 $88.7 832.6 811.1 24.1 34.0 98.3 70.0 Fair Value $88.7 836.9 37.0 72.3 ACE Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of ACE 17. QUARTERLY FINANCIAL RESULTS (UNAUDITED)

Quarterly financial data, reflecting all adjustments necessary in the opinion of management for a fair presentation of such amounts, are presented below. Certain prior year amounts have been reclassified, not affecting net income, to conform to the current year reporting of these items. Third quarter results generally exceed those of other quarters due to increased sales and higher residential rates. Earnings(Loss)

Applicable to Quarter Operating Operating Net Common Ended Revenues Income/(Loss)

Income/(Loss)

Stock (Dollars in Thousands) 1998 March 31 ............................

$ 237,949 $ (17,823) $(20,737)

$(21,737)

June 30 .............................

241,883 46,028 19,314 18,314 September 30 ........................

331,403 87,761 41,550 40,687 December 31 .........................

226,378 (7,098) (9,851) (7,879) $1,037,613

$108,868 $ 30,276 $ 29,385 1997 March 31 ............................

$ 243,422 $ 47,378 $ 20,371 $ 18,961 June 30 .............................

242,475 45,011 18,676 17,266 September 30 ........................

338,162 89,580 47,541 46,541 December 31 .........................

260,831 8,083 (841) (1,842) $1,084,890

$190,052 $ 85,747 $ 80,926 As discussed in Note 4 to the Consolidated Financial Statements, ACE recorded an impairment loss on assets held for sale in the fourth quarter of 1998 which reduced operating income $18.0 million and net income $10.6 million. Il-36 -I I *

• Employee separation programs and other Merger-related costs recorded in 1998 (as discussed in Note 4 to Consolidated Financial Statements) had the effects shown below on 1998 quarterly operating results. Quarter Ended March 31 June 30 ....................................... . September 30 .................................. . December 31 .................................. . Operating Incomne/(Loss)

Earnings(Loss)

Applicable to Net Common Income/(Loss)

Stock (Dollars in Thousands) $(51,479) $(30,946) $(30,946) 3,361 1,987 1,987 (1,014) (600) (600) (11,959) (7,074) (7,074) $(61,091) $(36,633) $(36,633)

Due to the Merger, various pension and compensation plans were terminated in the fourth quarter of 1997, resulting in a $22.2 million decrease in operating income and a $15.6 million decrease in net income. 18. BUSINESS SEGMENTS Conectiv's organizational structure and management reporting information is aligned with Conectiv's business segments, irrespective of which subsidiary, or subsidiaries, a business is conducted through. Businesses are managed based on lines of business, not based on legal entity. Business segment information is not produced, or reported, on a subsidiary by subsidiary basis. Thus, as a Conectiv subsidiary, no business segment information (as defined by SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information")

is available for ACE on a stand-alone basis. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Reference is made to Item 4 of Report on Form 8-K filed March 5, 1998. II-37

• *

• PART ID ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Directors As of December 31, 1998 Howard E. Cosgrove, 55, ................. . Chairman of the Board Business Experience During Past 5 Years Elected 1998 as Chairman of the Board and Chief Executive Officer of Conectiv, Delmarva Power & Light Company, and Atlantic City Electric Company. Elected 1992 as Chairman of the Board, President and Chief Executive Officer and Director of Delmarva Power & Light Company. Meredith I. Harlacher, Jr., 56,...............

Elected 1998 as President and Chief Operating Officer of Director Conectiv, and President and Chief Operating Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1993 as Senior Vice President of Atlantic Energy, Inc. Barry R. Elson, 57, Director Elected 1998 as Executive Vice President of Conectiv, and Executive Vice President and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1997 as Executive Vice President, Delmarva Power & Light Company. Executive Vice President, Cox Communications, Inc., Atlanta, Georgia, from 1995 to 1996. Senior Vice President, Cox Enterprises/Cox Communications, Inc., Atlanta, Georgia, from 1984 to 1995. Thomas S. Shaw, 51,......................

Elected 1998 as Executive Vice President of Conectiv, Director and Executive Vice President and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1992 as Senior Vice President, Delmarva Power & Light Company. Barbara S. Graham, 50,....................

Elected 1998 as Senior Vice President and Chief Director Financial Officer of Conectiv, and Senior Vice President and Chief Financial Officer and Director of Delmarva Power & Light Company and Atlantic City Electric Company. Elected 1994 as Senior Vice President, Treasurer and Chief Financial Officer, Delmarva Power & Light Company. Vice President and Chief Financial Officer of Delmarva Power & Light Company from 1992 to 1994. Executives Information about ACE's executive officers is included under Item 1. III-1 . '*

ITEM 11. EXECUTIVE COMPENSATION As previously noted, ACE is a wholly owned electric utility subsidiary of Conectiv.

The Chief Executive Officer and the four most highly compensated executive officers of Conectiv maintain the same position at both ACE and DPL. In 1998, the salaries and other compensation awarded to the Chief Executive Officer and the four most highly compensated executive officers of ACE were paid by Conectiv for their service as executive officers of Conectiv, ACE and DPL. The Board Personnel

& Compensation Committee Report was provided initially in the *Conectiv Proxy Statement and is enclosed herein for the purpose of providing additional informational.

The following tables show information concerning the total compensation paid or awarded to ACE's Chief Executive Officer and each of the four most highly compensated executive officers for the fiscal year ended December 31, 1998. Board Personnel

& Compensation Committee Report Principles of Executive Compensation Program The Personnel

& Compensation Committee of the Board of Directors is comprised of four non-employee Directors.

The Committee provides an independent review of the Company's performance objectives and executive compensation.

Overall Objectives The Company's philosophy is to link compensation to business strategies and results, to align total compensation of executives with the long-term interests of stockholders, to motivate its senior executives to meet the challenging objectives established for the Company and to create an urgency for success in the newly-formed Company. The Company's executive compensation program is designed to: provide total compensation that emphasizes long-term performance which creates stockholder value; facilitate the rapid transition to a competitive business environment; reflect the market conditions for attracting and retaining high-quality executives and ensure that such executives have a continuing stake in the long-term success of the Company; and create significant levels of stock ownership.

The elements of the executive compensation program are: total compensation levels that are competitive with those provided by the competitive market, defined as a blend of companies in the utility and industrial markets; base compensation levels related to responsibility level and individual performance; annual variable compensation that varies based on corporate, unit and individual performance; and, long-term variable compensation based on long-term increases in stockholder value. Total Compensation Total compensation opportunities are developed for Company executives by Watson Wyatt, the firm that provides executive compensation consulting services to the Company. This is done using several published compensation survey sources and public proxy data to define the competitive market. Overall, the total compensation structure for executives is targeted at the median for similar positions at companies of similar size, including both utilities and industrial companies (Compensation Comparison Group)'. Individual reward levels vary based on individual contributions and performance.

Total compensation includes three components:

base compensation, annual variable compensation and long-term variable compensation.

The targets for each component of the executive compensation program are reviewed on an annual basis to ensure alignment with the Company's compensation philosophy and a proper balance between short-and long-term objectives.

1.

• The Compensation Comparison Group does not include all of the same companies as the published industry indices in the Comparison of 10 Month Cumulative Total Return chart included in this Proxy Statement.

However, 34 of the 85 companies included in the EEI

• Executive Compensation Report, which is one element of the Compensation Comparison Group, are also part of either the Dow Jones Electric Utilities Index or the S&P 500 Index. III-2

• . Base Compensation 1

• Base compensation for executive officers is determined by evaluating the respqnsibilities of the positions

• held and the experience of the individuals, coupled with a review of compensation for comparable positions at other companies.

Base compensation is reviewed on an annual basis and adjusrments are based on the performance of the Company and each executive officer. Annual base compensation increases reflect the individual's performance and contribution over several years in addition to the results for a single year. Following the 1998 increases, the overall base compensation level for the five named executive officers was slightly below the median of the base compensation targeted levels defined by the surveys and proxies. Annual Variable Compensation The Company's annual variable compensation is designed to motivate participants to accomplish stretch financial and individual goals and to increase the sense of urgency to deliver significant results on an annual basis. Annual variable compensation target opportunities are designed to be at or above the median of the blended utility and industrial market and for the named . executive officers vary from 40% to 50% of base compensation, with maximum awards of 60% to 75% of base compensation.

Annual variable compensation is paid in a combination of cash (80%) and restrieted stock units (20%) and is based on the achievement of predetermined corporate and individual goals. The plan for 1998 provides that payouts will occur only after a specified earnings target is achieved.

For 1998, each individual covered by the plan was eligible to earn a variable compensation award between 0% and 150% of target. The portion of each individual award attributable to corporate, line of business, and group performance were determined and spedfic measures were developed at the beginning of the year. These measures were primarily financial for 1998 to accelerate the transition of the Company to a more competitive environment and included corporate measures of earnings, cash flow return on capital employed and cash flow . Each business group and line of business also developed specific financial measures to support their business plans. The Management Stock Purchase Program (MSPP)

• was designed as a means to promote significant executive stock ownership in the new company and to help meet stock ownership guidelines.

The program requires that 20% of the individual's earned annual variable compensation must be used to acquire restricted stock units (RSUs). Individuals may also voluntarily use up to an additional 30% (for a total of 50%) of their earned annual variable compensation to acquire RSUs. All RSUs are acquired at a 20% discount from Fair Market Value on the date paid. Each RSU is a proxy for one share of Common Stock, has a value equal to one share and earns at the rate of the Common Stock dividend.

RSUs are restricted from sale or use for a 3-year period and are distributed in shares of Common Stock. Long-Term Variable Compensation The Company's long-term variable compensation reinforces the importance of providing stockholders with a competitive return on their investment.

Long-term variable compensation awards also strengthen the ability of the Company to attract, motivate and retain executives of superior capability and more closely align the interests of management with those of stockholders.

Long-term grants for Conectiv executives are determined by setting a target percentage of base compensation based on median data in the Compensation Comparison Group and converting the target amounts to actual grants using the "Black-Scholes Model" for options and time and forfeiture discount methods for the other elements of the long-term grants. Long-term awards granted in 1998 consisted of non-qualified stock options, dividend equivalent units and performance accelerated restricted stock. Non-qualified stock options and dividend equivalent units were awarded to provide approximately two-thirds of the targeted value of the grant while the other one-third of the III-3 *: .. :.

I I i;\ ,Y ,y '\: ' I' '1:, ; r \,, targeted value was provided through p¢i:formance accelerated restricted stock. This stock vests as unrestricted Commqn Stock seven years from the award 4.ate. However, vesting may be accelerated if the price of Common Stock re_aches certain predetermined leve.ls pnor to the seven years. All stock options were granted with exercise prices equal to the fair market value of Stock at the time of the grant. -' Performance accelerated restricted stock) granted to the CEO and three other named executive officers is also subject to an additional condition tied td Total Shareholder Return over the seven year pe1iod. Failure to meet a predetermined Total Shareholder

\Return level over the restriction period will result in total forfeiture of their shares granted. , 1 The CEO and three other named executive officers also. were given a special grant of performance accelerated stock options to increase emphasis on creating long-term shareholder value. All performance accelerated stock options were granted with prices equaHo the fair market value of Common Stock at the time of grant. These options do not vest ahd cannot be exercised for 9-112 years from the date of their grant unless_ thy stock price increases to predetermi4ed levels. Absent accelerated vesting at these predetermined stock prices, shares will become exercisable in years with expiration occurring at 10 years. This special grant resulted in the long-term variable compensation component and total compensation exceeding the targeted median values for these four executives for 1998 using the Black-Scholes valuation methodology.

Stock Ownership Guidelines To further reinforce the interests of stockholders, stock ownership guidelines have been established for the Board of Directors, Company officers, and other Company management.

These guidelines require the individuals covered by the guidelines to have beneficial ownership of Common Stock, or securities convertible into Common Stock, with an aggregate value equal to certain multiples of each individual's salary (or annual retainers in the

• case of outside directors).

Multiples range from five times to one times salary. The Chief Executive Officer's multiple is set at five times salary and outside .Directors' multiples are set at three times the annual retainer.

Internal Revenue Code Section I62(m) The Committee considers the tax deductibility of compensation paid to executive officers and the impact of Section 162(m) of the Internal Revenue Code of 1986, as amended (the "Code"), on the Company. This provision limits the amount of compensation that the Company may deduct from its taxable income for any year to $1 million for any of its five most highly compensated executive officers, unless certain requirements are met. The Committee has taken actions to limit'. the impact of the Code in the event that compensation paid to a named executive officer might otherwise not be deductible.

The Committee will continue to seek ways to limit the impact of the Code; however, the Committee believes that the tax deduction limitation should not compromise the Company's ability to create inc;'entive programs that support the business strategy and also attract and retain the executive talent required to compete successfully.

Accordingly, achieving the desired flexibility in the design and delivery of compensation may periodically result in some compensation that is not deductible for federal income tax purposes.

Summary of Actions Taken by the Personnel:&

Compensation Committee The Personnel

& Compensation Committee, consisting entirely of outside directors, provides direction and oversight to the Company's executive plans, establishes the Company's compensation philosophy and assesses the effectiveness of the program as a whole. This includes activities such as reviewing the design of

• various plans and assessing the reasonableness of the total program consistent with the total compensation philosophy.

III-4

• The Committee also assists in administering key aspects of the Company's annual compensation program and variable compensation plan, such as reviewing annual compensation budgets and setting targets and corporate performance measures for the annual and long-term variable compensation plans. Finally, the Committee specifically implements the Company's executive compensation program as it directly pertains to the Chief Executive Officer and the Company's four other most highly compensated executives, i.e., the five named executive officers.

The Committee has determined that in an environment where competition is increasing, it is essential that the Company have the ability to attract, motivate and retain high quaiity executives from within and outside the utility industry.

Because of the extremely competitive market for executive talent, the Personnel

& Compensation Committee has adopted a compensation structure based on a blend of utility and general competitive industry markets. The structure is also flexible to allow setting salaries at pure general industry levels where that may be necessary to attract certain specific skills and experience.

Consistent with this approach, the total compensation program relies on competitive base compensation generally at or below the median of the market with annual and long-term variable compensation opportunities generally above the median of the market. This places a much greater emphasis on variable compensation that aligns executive and stockholder interests.

This total compensation philosophy is important to the success of the Company because the Company is facing increasing competition and related risks. The Company is not simply a utility anymore, but is rapidly becoming part of the general competitive industry market and, therefore, just as strategies for success must change, the compensation to drive success must also change. Prior to the merger involving Atlantic Energy and Delmarva and during 1998, this compensation philosophy enabled the Company to attract several key executives with experience and skills critical to the emerging competitive environment.

These executives would not have been available under a traditional utility compensation philosophy.

Significant actions by the Committee for fiscal year 1998 included adoption of the new Conectiv executive plans (Conectiv Variable Compensation Plan, Deferred Compensation Plan, Supplemental Executive Retirement Plan [SERP], and Change In Control Agreements) and other compensation and benefit plans for Conectiv employees.

The Committee also sets base compensation, annual variable targets and performance measures and long-term grants under the various executive programs, including special awards of performance accelerated stock options to the CEO and the three other named executive officers described above. Chief Executive Officer Compensation Mr. Cosgrove's compensation reflects Conectiv's compensation philosophy.

His base compensation, annual and regular long-term variable compensation place him at total compensation levels consistent with the median level of other CEO's at similarly-sized utility and manufacturing companies represented in the Compensation Comparison Group. Additional emphasis on achieving increased stockholder value has been created with a special grant of performance accelerated stock options. This special grant will cause his long term compensation and total compensation to exceed the median targets for 1998. Base Compensation Action Conectiv was formed by a merger involving Delmarva and Atlantic Energy in early 1998. Mr. Cosgrove's base compensation was set during the merger process to reflect the size of Conectiv and the increasing competitive environment in which Conectiv does business.

His 1998 base compensation is at the median target level developed through a comparison of other Chief Executive Officers of similarly-sized corporations using a blend of utilities and general industry.

His salary for 1999 will remain the same as in 1998. III-5 Annual Variable Compensation

• To provide clear focus on increasing stockholder value through the successful completion of the merger and growing the new Conectiv businesses, Mr. Cosgrove received additional levels of long-term awards in place of an annual variable opportunity for 1997. Therefore, there is no annual variable pay for 1997 reflected in 1998 compensation.

Mr. Cosgrove's annual variable compensation target opportunity for 1998 was set at 50% of base compensation, with a minimum payout of 0% and a maximum payout of 75% of base compensation.

Payment of any award requires achieving a predetermined level of 1998 earnings established by this Committee.

Performance measures for 1998, predetermined by this Committee, included earnings available for common stock, cash flow return on capital employed and cash flow. Awards for 1998 for Mr. Cosgrove and the four other named executive officers have not been determined.

Long-Term Variable Compensation Long-term incentive grants are a critical component of the Conectiv executive compensation philosophy, since they align executive interests very clearly with increased stockholder value. For 1998, Mr. Cosgrove received grants of non-qualified stock options, dividend equivalent units, performance accelerated restricted stock, and performance accelerated stock options (reflected in the Compensation Tables). The regular grants of non-qualified stock options, dividend equivalent units and performance accelerated restricted stock provided a long-term variable compensation opportunity approximately at the median of the defined competitive market. The special, non-recurring grant of performance accelerated stock options was awarded to create additional emphasis on achieving higher levels of stockholder value. In order for Mr. Cosgrove to receive any. value from this grant prior to vesting at nine and one-half years, there must be a significant increase in stockholder value. Such increases prior to nine and one-half years will result in accelerated vesting of this grant in increments of one-third.

The first third would vest when stockholder increases by $400,000,000, at which time Mr. Cosgrove's options would vest at a value of $1,200,000, or .3% of the increase in stockholder value. The entire grant would vest if stockholder value increases by $800,000,000, at which time Mr. Cosgrove's options would vest at a value of $2,400,000 or .3% of the increase in stockholder value. Only under results that yield increases in stockholder value and trigger accelerated vesting of this grant would Mr. Cosgrove's 1998 compensation exceed the median target compensation level. Personnel

& Compensation Committee S.I. Gore, Chairperson M.B. Emery RB. McGlynn B.J. Morgan Personnel

& Compensation Committee Interlocks and Insider Participation The Personnel

& Compensation Committee is comprised solely of non-officer directors.

Logical Business Solutions, which is owned by Mr. Emery's son-in-law, Paul Kleiman, had contracts with Conectiv Resource Partners, Inc., a subsidiary of the Company, with a gross value of $227,000 during 1998 for information technology consulting services.

Except as described in the preceding sentence, there are no Personnel

& Compensation .Committee interlocks.

Ill-6 _J Summary Compensation Table Table 1-

SUMMARY

<:;OMPENSATION TABLE Long-Term Compensation Annual Compensation Awards Payouts Variable Securities LTIP All Other Annualized Compensation Other Annual Restricted Underlying Payouts Compensation Salary (Bonus)(2)

Compensation Stock(S) Options (3) (4,6) Name and Principal Position Year(l) H.E. Cosgrove, ....... 1998 $600,000 360,000 572,134 $ 12,329 Chairman of the Board and Chief Executive Officer M.I. Harlacher, ....... 1998 $340,000 $ 3,742 President 1997 $224,525 $96,800 $814,696 $3,208,196 1996 $215,317 $27,500 $ 8,527 $305,138 15,800 10,429 $ 7,413 B.R. Elson, ..........

1998 $325,000 170,000 21,560 $ 4,074 Executive Vice President T.S. Shaw, ..........

1998 $325,000 170,000 155,267 $ 9,478 Executive Vice President B.S. Graham, ........ 1998 $250,000 170,000 155,267 $ 5,308 Senior Vice President (1) Base salary is shown as an annualized amount. Other items of compensation reflect the full calendar 1998* compensation received from Conectiv and either Delmarva or Atlantic City Electric Company. (2) The 1998 bonus, which is an annual variable award, has not yet been determined.

The target award is 50% of annualized salary for Mr. Cosgrove and 40% for Messrs. Harlacher, Elson and Shaw and Mrs. Graham. (3) During 1998 all restrictions lapsed on the performance-based restricted stock granted in 1995 and 1996 under the Delmarva LTIP due to the merger involving Delmarva and Atlantic Energy. Under the "change in control" provisions, the awards fully vested resulting in a payout to Mr. Cosgrove of 21,160 shares (11,570 for 1995 and 9,590 for 1996) valued at $454,940; to Mr. Shaw of 5,450 shares (2,870 for 1995 and 2,580 for 1996) valued at $117,175; and to Mrs .. Graham of 5,450 shares (2,870 for 1995 and 2,580 for 1996) valued at $117,175.

Shares were valued at $21.50 at the time of payout. Dividends on shares of restricted stock and dividend equivalents are accrued at the same rate as that paid to all holders of Common Stock. As of December 31, 1998; Mr. Cosgrove held 45,520 shares of restricted stock (35,520 for 1997 and 10,000 for 1998) and 30,000 Dividend Equivalent Units ("DEU's");

Mr. Elson held 4,000 shares of restricted stock for 1998 and 10,000 DEU's; Mr. Shaw held 12,010 shares of restricted stock (8,010 for 1997 and 4,000 for 1998) and 10,000 DEU's; Mrs. Graham held 12,010 shares of restricted stock (8,010 for 1997 and 4,000 for 1998) and 10,000 DEU's. Holders of restricted stock are entitled to receive dividends as declared. ( 4) The amount of All Other Compensation for each of the named executive officers for fiscal year 1998 include the following:

Mr. Cosgrove, $2,125 in Company matching contributions to the Company's Savings and Investment Plan, $10,000 in Company matching contributions to the Company's Deferred Compensation Plan and $204 in term life insurance premiums paid by the Company; for Mr. Shaw, $2,630 in Company matching contributions to the Company's Savings and Investment Plan, $6,644 in Company matching contributions to the Company's Deferred Compensation Plan and $204 in term life insurance premiums paid by the Company; for Mrs. Graham, $2,604 in Company matching contributions to the Company's Savings and Investment Plan, $2,500 in Company matching contributions to the Company's Deferred Compensation Plan and $204 in term life Insurance premiums paid by the Company; for Mr. Elson, $2,969 in Company matching contributions to the Company's Savings and Investment Plan and $1,105 in term life insurance premiums paid by the Company; and for Mr. Harlacher, $3,300 in Company matching contributions to the Company's Savings and Investment Plan and $442 in term life insurance premiums paid by the Company. (5) Pursuant to the change-of-control provisions*

of Atlantic Energy's equity based long term incentive plan for executives

("EIP"), Mr. Harlacher elected to receive the cash equivalent of the restricted stock which had been awarded under the plan. (6) The amount of All Other Compensation for Mr. Harlacher for the fiscal year ended 1997 include the following:

$4,750 in Company matching contributions to the Atlantic City Electric Company 40l(k) Savings and Investment Plan; $1,986 in Company matching contributions to the Atlantic City Electric Company Deferred Compensation Plan; $1,065 in term life insurance premiums paid by Atlantic City Electric Company; $996,238 in payouts under the Atlantic City Electric Company supplemental executive retirement plan; $674,340 cash payout for restricted stock awarded under the Atlantic Energy EIP which vested due to change-in-control;

$1,358,817 in excess retirement benefits from the Atlantic City Electric Company Retirement Plan; $171,000 adjustment to compensate Mr. Harlacher for certain economic disadvantages associated with the payout of benefits in 1997 rather than in 1998. III-7 Table 2 -Option Grants in Last Fiscal Year (1) Number %of of Securities Total Options Underlying Granted Grant Date Options to Employees Exercise Price Expiration Present Name Granted(#)

in Fiscal Year ($/Sh) Date Value(4) H.E. Cosgrove ..............................

300,000(2) 29% $22.84375 1/2/08 $385,831 60,000(3) 6% $22.84375 1/2/08 $137,063 M.I. Harlacher

.............................

0% 0% B.R. Elson ................................

150,000(2) 14% $22.84375 1/2/08 $192,915 20,000(3) 2% $22.84375 1/2/08 $ 45,688 T.S. Shaw .................................

150,000(2) 14% $22.84375 1/2/08 $192,915 20,000(3) 2% $22.84375 1/2/08 $ 45,688 B.S. Graham ...............................

150,000(2) 14% $22.84375 1/2/08 $192,915 20,000(3) 2% $22.84375 1/2/08 $ 45,688 (1) Currently, Delmarva does not grant stock appreciation rights. The options reflected in this table are for payouts in shares of Conectiv Common Stock. (2) Denotes Performance Accelerated Stock Options ("PASO's")

which were granted on a one-time basis. PASO's have a ten-year term and vest and are first exercisable 9 and 1/2 years from date of grant without regard to stock price performance.

Exercise date will accelerate for favorable stock price performance (i.e., first 113, second 1/3 and third 1/3 of PASO's vest after stock trades at $26, $28 or $30 per share, respectively, for ten consecutive trading days). There is a minimum holding period of three years from date of grant during which these options are not exercisable.

(3) Denotes Nonqualified Stock Options. One-half of such Options vest and are exercisable at end of second year from date of grant. Second one-half vest and are exercisable at end of third year from date of grant. (4) . Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise price of $22.84375, equal to the Fair Market Value ("FMV") as of date of grant; (b) an option term of ten years; (c) risk-free rate of return of 6.00%; (d) volatility of 20.00%; and (e) dividend yield of 7.00%. For valuation purposes, PASO's are valued as a premium-priced stock option as of the date of grant with an exercise price of $30 on a FMV of $22.84375.

Table 3 -Aggregated Option Exercises in Last Fiscal Year and FY-End Option Values Shares Acquired V aloe Realized Number of Securities Underlying Unexercised Options at FY-End(2)

Value ofUnexercised the-MoneyOptions at End(l) Name on Exercise ($)(1) Exercisable/Unexercisable Exercisable/Unexercisable H. E. Cosgrove. . ............ . 0 0 M. I. Harlacher

.............. . 0 0 B. R. Elson ................. . 0 0 T. S. Shaw ................. . 0 0 B. S. Graham ................ . 0 0 14,400/360,000 0/170,000 0/170,000 0/170,000

$51,225/$596,250

$ $ $ $ 0/$281,563 0/$281,563

0/$281,563 (1) The closing price for Conectiv's common stock as reported by the New York Stock Exchange on December 31, 1998 was $24.50. Any value in the options would be based on the difference between the exercise price of the options and the value at the time of the exercise (e.g., $24.50 as of close of business on 12/31/98), which difference would be multiplied by the number of options exercised.

(2) Only 14,400 stock options of Mr. Cosgrove are currently exercisable.

None of the remaining options may be exercised earlier than two years from date of grant for regular, non-performance based options and nine and one half years from date of grant for performance based options (subject to accelerated vesting for favorable stock price performance).

III-8

• Table 4 -Long-Term Incentive Plans-Awards in Last Fiscal Year Name H. E. Cosgrove ....................

-.................... . M. I. Harlacher

........................................ . B. R. Elson ............................................ . T. S. Shaw ............................................ . B. S. Graham .......................................... . Number of Restricted Shares/Dividend Equivalent Units (#)(1) 10,000 shs/30,000 units 4,000 shs/10,000 units 4,000 shs/10,000 units 4,000 shs/10,000 units Performance Period Until Maturation or Payout(2) 3/2/05 3/2/05 3/2/05 3/2/05 (1) In addition, Mr. Cosgrove held 35,520 shares (valued at $870,240) and Mr. Shaw and Mrs. Graham held 8,010 performance shares (valued at $196,245) from a 1997 award with a four year performance cycle under the Delmarva Power Long Term Incentive Plan. (2) Awards of Restricted Shares (Performance Accelerated Restricted Stock or "PARS") and Dividend Equivalent Units ("DEU's")

were made to four of the named executive officers.

The payout of shares of PARS may potentially be performance accelerated.

Restrictions may lapse any time after 3 years (i.e., after March 1, 2001) upon on achievement of favorable stock price performance goals. In the absence of such favorable performance, restrictions lapse after 7 years (i.e., March 2, 2005) provided that at least a defined level of average, total return to shareholders is achieved.

As of December 31, 1998, Mr. Cosgrove's 10,000 Restricted Shares were valued at $245,000 and Messrs. Elson and Shaw and Mrs. Graham's 4,000 PARS were valued at $98,000. These values for both Restricted Shares and performance shares are based on the December 31, 1998 closing stock price of $24.50. For Dividend Equivalent Units, one DEU is equal in value to the regular quarterly dividend paid on one share of Conectiv common stock. The Dividend Equivalent Units shown are payable in cash for twelve quarters over a three year period ending with the quarterly dividend equivalent payable January 31, 2001. At that point, the 1998 DEU award lapses. Pension Plan The Conectiv Retirement Plan includes the Cash Balance Pension Plan and grandfathered provisions relating to the Delmarva Retirement Plan and the Atlantic Retirement Plan that apply to employees who had either 20 years of service or were age 50 on the effective date of the Cash Balance Pension Plan (January 1, 1999). Certain executives whose benefits from the Conectiv Retirement Plan are limited by the application of Federal tax laws also receive benefits from the Supplemental Executive Retirement Plan. Cash Balance Pension Plan The named executive officers participate in the Conectiv Retirement Plan and earn benefits that generally become vested after five years of service. On an annual basis, a recordkeeping account in a participant's name is credited with an amount equal to a percentage of the participant's total pay, including base salary, overtime and bonuses, depending on the employee's age at the end of the plan year, as follows: % of Age at end of Plan Year Pay Under 30 ......................................................

• ..................

5 30 to 34....................................................

... . . . . . . . . . . . . . . . . . . . 6 35 to 39.........................................................................

7 40to44 .........................................................................

8 45 to 49.........................................................................

9 50 and over......................................................................

10 These accounts also receive interest credits based on average U.S. Treasury Bill rates for the year. In addition, certain annuity benefits earned by participants under the former Delmarva and Atlantic Retirement Plans are fully protected as of December 31, 1998, and will be converted to an equivalent cash amount and included in each employee's initial cash balance account. When an employee terminates employment, the amount credited to his or her account is converted into an annuity or paid in a lump sum. III-9 Supplemental Retirement Benefits Supplemental retirement benefits are provided to certain employees, including each executive officer, whose benefits under the Conectiv Retirement Plan are limited by type of compensation or amount under applicable Federal tax laws and regulations.

Designated employees may also receive an annual benefit at retirement equal to a percentage of final average compensation multiplied by years of service reduced by the amount of all benefits received under the Conectiv Retirement Plan and other nonqualified arrangements.

Estimated Retirement Benefits Payable to Named Executive Officers The following table shows the estimated retirement benefits, including supplemental retirement benefits under the plans applicable to the named executive officers, which would be payable if he or she were to retire at normal retirement age, which is age 65, at 1998 compensation, expressed in the form of a lump sum payment. Years of service credited to each named executive officer as of his or her normal retirement date are as follows: Mr. Cosgove, 42; Ms. Graham, 30; Mr. Shaw, 40; Mr. Elson, 16 (8 of which are additional years of service for purposes of the supplemental retirement benefits), and Mr. Harlacher, 43. Estimated Retirement Benefits Name Year of 65th Birthday Lump Sum Value H. E. Cosgrove ....................................... . B. S. Graham ........................................ . T. S. Shaw ........................................... . B. R. Elson .......................................... . M. I. Harlacher

....................................... . 2008 2013 2012 2006 2007 $2,993,000(2) 1,540,000(1)

1,789,000(2)

1,213,000(2) 2,323,000(2)

(1) Amounts include (i) interest credits for cash balances projected to be 5.01 % per annum on annual salary credits and prior service balances, if any, and (ii) accrued benefits as of December 31, 1998 under retirement plans then applicable to the named executive officer. Benefits are not subject to any offset for Social Security payments or other offset amounts and assume no future increases in base salary or total pay. (2) Under the Conectiv Retirement Plan's grandfather provisions, employees who participated in the Delmarva or Atlantic Retirement Plans and who met certain age and service requirements as of December 31, 1998, will have retirement benefits for all years of service up to retirement calculated according to their original final pay formula benefit. This benefit will be compared to the cash balance account and the employee will receive whichever is greater. Estimated benefits are based on the Delmarva Retirement Plan for Messrs. Cosgrove, Shaw and Elson, the Cash Balance Pension Plan for Mrs. Graham and the Atlantic Retirement Plan for Mr. Harlacher.

The amount of benefit under such grandfathering is illustrated in the following tables applicable to the Delmarva and Atlantic Retirement Plans, respectively:

Delmarva Retirement Plan PENSION PLAN TABLE Annual Retirement Benefits in Specified Remuneration and Years of Service Classifications Average Annual Earnings for the 5 Consecutive Years of Earnings that Result in the Highest Average IS Yrs. 20 Yrs. 25 Yrs. $125,000 ........................

28,599 38,132 47,665 200,000(1)

.......................

46,599 62,132 77,665 300,000(1)

.......................

70,599 94,132 117,665 400,000(1)

.......................

94,599 126,132 157,665(2) 500,000(1)

.......................

118,599 158,132(2) 197,665(2)

(1) Effective January 1, 1998, annual compensation recognized may not exceed $160,000.

(2) For 1998, the limit on annual benefits is $130,000.

30 Yrs. 35Yrs. 57,198 66,732 93,198 108,732 141,198(2) 164,732(2) 189,198(2) 220,732(2) 237,198(2) 276,732(2)

Benefits are payable in the form of a 50% joint and surviving spouse annuity or lump sum and earnings include base salary, overtime and bonus. III-10

• Atlantic Retirement Plan PENSION PLAN TABLE Annual Retirement Benefits in Specified Remuneration and Years of Service Classifications (1) (2) Average Annual Earnings for the 5 Consecutive Years of Earnings that result in the Highest Average lSYrs. 20Yrs. 25 Yrs. $125,000 ........................

30,000 40,000 50,000 200,000(1)

.......................

48,000 64,000 80,000 300,000(1)

.......................

72,000 96,000 120,000 400,000(1)

.......................

96,000 128,000 160,000(2) 500,000(1)

.......................

120,000 160,000(2) 200,000(2)

Effective January 1, 1998, annual compensation recognized may not exceed $160,000.

For 1998, the limit on annual benefits is $130,000.

30 Yrs. 35Yrs. 60,000 70,000 96,000 112,000 144,000(2) 168,000(2) 192,000(2) 224,000(2) 240,000(2) 280,000(2)

Benefits are paid in the form of a life annuity or lump sum and earnings include base salary and bonus. Change in Control Severance Agreements And Other Provisions Relating to Possible Change in Control Conectiv has entered into change in control severance agreements with Messrs. Cosgrove, Elson and Shaw and Mrs. Graham and two other senior executives.

The agreements are intended to encourage the continued dedication of members of Conectiv's senior management team. These agreements provide potential benefits for such executives upon actual or constructive termination of employment (other than for cause) following a change in control of Conectiv, as defined in such agreements.

Each affected executive would receive a severance payment equal to three times Base Salary and Bonus and Conectiv-paid medical, dental, vision, group life and disability benefits during the three years after termination of employment, and a cash payment equal to the actuarial equivalent of accrued retirement pension credits equal to 36 months of additional service. In the event of a change in control, the Variable Compensation Plan provides that outstanding options become exercisable in full immediately, all conditions to the vesting of PARS are deemed satisfied and shares will be fully vested and nonforfeitable, DEU's will become fully vested and be immediately payable, variable compensation deferred under the Management Stock Purchase Program will be immediately distributed, and payment of variable compensation, if any, for the current year will be decided by the Board's Personnel

& Compensation Committee.

For the Deferred Compensation Plan, the Committee may decide to distribute all deferrals in cash immediately or continue the deferral elections of participants in which event Conectiv will fully fund a springing rabbi trust to satisfy the obligations.

An independent institutional trustee will maintain any such trust established by reason of this provision.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT All shares of ACE's common stock are owned by Conectiv, ACE's parent company. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None III-11 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report. 1. Financial Statements-The following financial statements are contained in Item 8 of Part II. Report of Independent Accountants

...................................................... . Consolidated Statements of Income for the years ended December 31, 1998, 1997, and 1996 ...... . Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997, and 1996 .. . Consolidated Balance Sheets as of December 31, 1998 and 1997 ............................. . Consolidated Statements of Changes in Common Stockholder's Equity for the years ended December 31, 1998, 1997, and 1996 ................................................... . Notes to Consolidated Financial Statements

............................................... . 2. Financial Statement Schedules Page No. II-12, 13 II-14 II-15 II-16,17 II-18 II-19 Schedule II-Valuation and Accounts for each of the three years in the period ended December 31, 1998, is presented below. No other financial statement schedules have been filed since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the respective financial statements or the notes thereto. Schedule II-Valuation and Qualifying Accounts Years Ended December 31, 1998, 1997, 1996 (Dollars in thousands)

ColumnB Column C Additions Balance at Charged to beginning cost and Charged to Description of period expenses other accounts 1998 Allowance for doubtful accounts ...............

$3,500 $ 5,003 Merger-related impairment loss on assets held for sale .....................................

$18,000 1997 Allowance for doubtful accounts ...............

$3,500 $ 3,935 1996 Allowance for doubtful accounts ...............

$3,300 $ 5,359 (A) Accounts receivable written off. Column D ColumnE Balance at end of Deductions period $5,003(A)

$ 3,500 $18,000 $3,935(A)

$ 3,500 $5,159(A)

$ 3,500 3. Schedule of Operating Statistics for the three years ended December 31, 1997 can be found on page IV-4 of this report. IV-1

4. Exhibits Exhibit Number 2 Amended and Restated Agreement and Plan of Merger, dated as of December 26, 1996, between DPL, Atlantic Energy, Inc., Conectiv, Inc. and DS Sub, Inc. (Filed with Registration Statement No. 333-18843) 3-A A Restated Certificate oflncorporation of Atlantic Energy, Inc. (File No. 1-9760, Form 10-Q for quarter ended September 30, 1987-Exhibit 4(a)); Certificate of Amendment to restated Certificate of Incorporation of Atlantic Energy, Inc. dated April 15, 1992. File No. 33-53511, Form S-8 dated May 6, 1994--Exhibit No. 3(ii). 3-B By Laws of Atlantic Energy, Inc. as amended July 13, 1995 (File No. 1-9760, Form 10-Q for the quarter ended June 30, 1995-Exhibit 3b(l). 3-C Agreement of Merger between Atlantic City Electric Company and South Jersey Power & Light Company filed June 30, 1949, and Amendments through May 3, 1991 (File No. 2-71312-Exhibit No. 3(a); File No. 1-3559, Form 10-Q for quarter ended June 30, 1982-Exhibit No. 3(b); Form 10-Q for quarter ended March 31, 1985-Exhibit No. 3(a); Form 10-Q for quarter ended March 31, 1987-Exhibit No. 3(a): Form 8-K dated October 12, 1988-Exhibit No. 3(a); Form 10-K for fiscal year ended December 31, 1990-Exhibit No. 3c; and Form 10-Q for quarter ended September 30, 1991-Exhibit No. 3c). 3-D Certificate of Merger of Atlantic Energy, Inc. with and into Conectiv, Inc. filed with Delaware Secretary of State, effective as of March 1, 1998, filed herewith.

3-E 3-F 3-G Certificate of Merger of Atlantic Energy, Inc. with and into Conectiv, Inc. filed with New Jersey Department of State, effective as of March 1, 1998, filed herewith.

Certificate to change name from Conectiv, Inc., to Conectiv filed with the Delaware Secretary of State pursuant to Section 102(a) of the Delaware General Corporation Law, filed herewith.

By-Laws of Atlantic City Electric Company, as amended April 24, 1989 (File No. 1-3559, Form 10-Q for the quarter ended September 31, 1989-Exhibit No. 3). 4-A Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York (formerly Irving Trust Company) and Supplemental Indentures through November 1, 1994 (File No.

No. 2(b); File No. 1-3559, Form 10-K for year ended December 31, 1980-Exhibit No. 4(d); Form 10-Q for quarter ended June 30, 1981-Exhibit No. 4(a); Form 10-K for year ended December 31, 1983-Exhibit No. 4(d); Form 10-Q for quarter ended March 31, 1984-Exhibit No. 4(a); Form 10-Q for quarter ended June 30, 1984-Exhibit 4(a); Form 10-Q for quarter ended September 30, 1985-Exhibit 4; Form 10-Q for quarter ended March 31, 1986-Exhibit No. 4; Form 10-K for year ended December 31, 1987-Exhibit No. 4(d); Form 10-Q for quarter ended September 30, 1989-Exhibit No. 4(a); Form 10-K for year ended December 31, 1990-Exhibit No. 4(c); File No. 33-49279-Exhibit No. 4(b); File No. 1-3559, Form 10-Q for the quarter ended September 30, 1993-Exhibits 4(a) & 4(b); Form 10-K for the year ended December 31, 1993-Exhibit 4c(i); File no. 1-3559, Form 10-Q for the quarter ended June 30, 1994-Exhibit 4(a); File No. 1-3559, Form 10-Q for the quarter ended September 30, 1994--Exhibit_

4(a); Form 10-K for year ended December 31, 1994-Exhibit 4(c)(l). 4-B Indenture dated as of March 1, 1997 between Atlantic City Electric Company and The Bank of New York filed on Form 8-K, dated March 24, 1997, File No. 1-3559-Exhibit 4(e). 4-C Indenture Supplemental dated as of March 1, 1997 to Mortgage and Deed of Trust dated January 15, 1937 between Atlantic City Electric Company and The Bank of New York filed on Form 8-K dated March 24, 1997, File No 1-3559, Exhibit 4(b). IV-2 *

• 4-D 4-E 4-F 4-G 4-H 4-I Amended and Restated Trust Agreement, dated as of October 1, 1996, by and among Atlantic City Electric Company, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware) as Delaware Trustee and the Administrative Trustees Named Therein, (File No. 1-9760, Form 10-K for year ended December 31, 1996-Exhibit No. 4f(7)). Junior Subordinated Indenture, dated as of October 1, 1996, by and between Atlantic City Electric Company and The Bank of New York, as Trustee, (File No. 1-9760, Form 10-K for year ended December 31, 1996-Exhibit No. 4f(8)). Guarantee Agreement, dated as of October 1, 1996, by and between Atlantic City Electric Company as Guarantor, and The Bank of New York as Guarantee Trustee, (File No. 1-9760, Form 10-K for year ended December 31, 1996-Exhibit No. 4f(9)). Amended and Restated Trust Agreement, dated as of October 1, 1998, by and among Atlantic City Electric Company, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware) as Delaware Trustee and the Administrative Trustees Named Therein, filed herewith.

Junior Subordinated Indenture, dated as of October 1, 1998, by and between Atlantic City Electric Company and The Bank of New York, as Trustee, filed herewith.

Guarantee Agreement, dated as of October 1, 1998, by and between Atlantic City Electric Company as Guarantor, and The Bank of New York as Guarantee Trustee, filed herewith.

10-A Termination dated August 14, 1997 between Atlantic Energy, Inc. and Michael J. Chesser. (Filed with Form 10-K for the year ended December 31, 1997, File No. 1-3559). 10-B Agreement as to ownership as tenants in common of the Salem Nuclear Generating Station Units 1, 2, and 3, dated November 24, 1971, and of Supplements, dated as of September 1, 1975, and as of January 26? 1977 (File No. 2-43137-Exhibit No. 5(p); File No. 2-60966-Exhibit No. 5(m); and File No. 2-58430-Exhibit No. 5(o)). 10-C Agreement as to ownership as tenants in common of the Peach Bottom Atomic Power Station Units 2 and 3, dated November 24, 1971 and of Supplements dated as of September 1, 1975 and as of January 26, 1977 (File No. 2-43137-Exhibit No. 5(o); File No. 2-60966-Exhibit No. 5G); File No. 2-58430-Exhibit No. 5(m)). 10-D Owners Agreement, dated April 28, 1977 between Atlantic City Electric Company and Public Service Electric & Gas Company for the Hope Creek Generating Station Units No. 1 and 2 (File No. 2-60966-Exhibit No. 5(v)). 10-E Amendment to Owners Agreement for Hope Creek Nuclear Generating Station, dated as of December 23, 1981, between Atlantic City Electric Company and Public Service Electric & Gas Company (File No. 1-3559, Form 10-K for year ended December 31, 1983-Exhibit No. 10b(3-2)).

12-A Computation of ratio of earnings to fixed charges. 12-B Computation of ratio of earnings to fixed charges and preferred dividends.

23 Consent Independent Accountants.

27 Financial Data Schedules. (b) Reports on Form 8-K: On December 7, 1998, ACE filed a report on Form 8-K under Item 5, Other Events, regarding proposed legislation for restructuring the electric utility industry in New Jersey. On February 17, 1999, ACE filed a report on Form 8-K under Item 5, Other Events, regarding the New Jersey Electric Discount and Energy Competition Act. IV-3 ATLANTIC CITY ELECTRIC COMPANY SCHEDULE OF OPERATING STATISTICS FOR THE THREE YEARS ENDED DECEMBER 31, 1998 The table below sets forth selected financial and operating statistics for ACE's electric business for the years ended December 31, 1998, 1997, and 1996. Electricity generated and purchased (MWH): Generated

........................................... . Purchased

........................................... . Interchange deliveries

................................. . Total system output for load ......................... . Electric sales (MWH): Residential . ........................................ . Commercial

......................................... . Industrial

........................................... . Resale .............................................. . Other sales, losses and miscellaneous system uses (1) ...... . Total disposition of energy .......................... . Electric operating revenue (thousands):

Residential

.......................................... . Commercial

......................................... . Industrial

........................................... . Resale ............................................... . Miscellaneous revenues (2) ............................ .

• Total service territory

............................... . Interchange deliveries

................................. . Merchant revenues (3) ................................ . Total electric revenues .............................. . Number of customers (end of period): Residential

.......................................... . Commercial

......................................... . Industrial

........................................... . Resale .............................................. . Other ............................................... . Total customers (4) ................................. . (1) Includes unbilled sales. (2) Includes unbilled revenues and other miscellaneous revenues.

(3) Offsystem and competitive sales. (4) Service territory only. N-4 1998 5,499,473 3,881,906 (86,432) 9,294,947 3,544,048 3,724,853 1,308,826 404,883 312,337 9,294,947

$ 435,710 378,777 108,042 4,513 7,053 934,095 69,161 31,638 $1,034,894 429,720 57,499 1,003 522 488,744 1997 1996 4,664,548 4,775,306 5,409,378 5,905,566 (793,102)

(1,006,516) 9,280,824 9,674,356 3,454,705 3,587,352 3,538,414 3,493,694 1,253,347 1,214,005 317,824 811,467 716,534 567,838 9,280,824 9,674,356

$ 446,917 $ 448,738 382,812 369,364 110,469 105,734 7,949 19,052 24,685 12,065 972,832 954,953 23,657 27,539 72,045 1,868 $1,068,534

$ 984,360 425,036 420,499 56,816 55,580 1,023 1,013 523 519 483,398 477,611 *

/ SIGNATURES Pursuant 'to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 26, 1999. ATLANTIC CITY ELECTRIC COMPANY (Registrant) (John C. van Roden, Senior Vice President and Chief Financial Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated, on March 26, 1999. Signature Isl How ARD E. CosGROVE (Howard E. Cosgrove)

Isl J oHN C. v AN RoDEN (John C. van Roden) Isl JAMES P. LAVIN (James P. Lavin) Isl MEREDITH I. HARLACHER, JR. (Meredith I. Harlacher, Jr.) Isl THOMAS S. SHAW (Thomas S. Shaw) Isl BARRY R. ELSON (Barry R. Elson) Isl BARBARA S. GRAHAM (Barbara S. Graham) IV-5 Title Chairman of the Board and Chief Executive Officer Senior Vice President and Chief Financial Officer Controller and Chief Accounting Officer Director Director Director Director -_I