10-K405

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

or

¨ 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	21-0398280
(State of Incorporation)	(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) 429-3018

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
8.25% Cumulative Quarterly Income Preferred Securities, liquidation preference $25 per preferred security issued by Atlantic Capital I	New York Stock Exchange
7 3/8% Cumulative Trust Preferred Capital Securities, liquidation preference $25 per preferred security issued by Atlantic Capital II	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  x No  ¨

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. x

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
PART I
Item 1.	Business
General		I-1
Business Segments		I-1
Regulation		I-1
Divestiture of Electric Generating Plants		I-2
Securitization		I-2
Basic Generation Service		I-2
Purchased Power		I-3
PJM Interconnection L.L.C.		I-3
Fuel Supply for Electric Generation		I-4
New Jersey Electric System Reliability Standards		I-4
Affiliate Transactions		I-4
Capital Spending and Financing Program		I-4
Environmental Matters		I-5
Air Quality Regulations		I-5
Water Quality Regulations		I-6
Hazardous Substances		I-6
Executive Officers		I-6
Item 2.	Properties	I-7
Item 3.	Legal Proceedings	I-7
Item 4.	Submission of Matters to a Vote of Security Holders	I-7
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 7A.	Quantitative and Qualitative Disclosures About Market Risk	II-14
Item 8.	Financial Statements and Supplementary Data	II-15
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	II-42
PART III
Item 10.	Directors and Executive Officers of the Registrant	III-1
Item 11.	Executive Compensation	III-1
Item 12.	Security Ownership of Certain Beneficial Owners and Management	III-6
Item 13.	Certain Relationships and Related Transactions	III-6
PART IV
Item 14.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	IV-1
Signatures		IV-4

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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). PUHCA imposes certain restrictions on the operations of registered holding companies and their subsidiaries. ACE was organized under the laws of New Jersey on April 28, 1924, by merger and consolidation of several utility companies. Effective March 1, 1998, Atlantic Energy, Inc. (Atlantic) and Delmarva Power & Light Company (DPL) consummated a series of merger transactions (the 1998 Merger) by which ACE and DPL became wholly-owned subsidiaries of Conectiv. Atlantic owned ACE prior to the 1998 Merger.

On February 9, 2001, the Boards of Directors of Conectiv and Potomac Electric Power Company (Pepco) approved an Agreement and Plan of Merger (Conectiv/Pepco Merger Agreement) under which Pepco will acquire Conectiv for a combination of cash and stock, and Conectiv and Pepco will become wholly owned subsidiaries of Pepco Holdings Inc. (Conectiv/Pepco Merger). The Conectiv/Pepco Merger was approved by the stockholders of Conectiv and Pepco during 2001. Management currently expects the Conectiv/Pepco Merger to close in the second quarter of 2002, subject to timely receipt of various statutory and regulatory approvals.

As a public electric utility, ACE supplies and delivers electricity to its customers. These businesses, which are discussed below, are weather sensitive and seasonal because sales of electricity are usually higher during the summer months due to air conditioning usage. ACE delivers electricity to approximately 508,600 customers through its transmission and distribution systems and also supplies electricity to most of its delivery customers. ACE’s regulated service area covers about 2,700 square miles within the southern one-third of New Jersey and has a population of approximately 0.9 million.

Conectiv’s service company, Conectiv Resource Partners, Inc. (CRP), provides a variety of support services to Conectiv subsidiaries. The costs of CRP are directly assigned and allocated to the Conectiv subsidiaries using CRP’s services.

ACE operates its electric distribution system under long term franchise rights granted by the municipalities within its service area. Franchises with certain municipalities are subject to renewal during the next five years. ACE expects such franchises will be renewed but cannot predict whether such renewals will occur. ACE also  possesses certain rights to provide service by virtue of state-wide grants and state-level regulation of its  businesses.

As of December 31, 2001, ACE had 680 employees, of which 513 were represented by a labor organization.

Business Segments

For other information concerning ACE’s business segments, see Note 20 to ACE’s Consolidated Financial Statements included in Item 8 of Part II.

Regulation

ACE’s electric retail utility business is subject to regulation by the New Jersey Board of Public Utilities (NJBPU), including rates charged to electric customers. The Federal Energy Regulatory Commission (FERC) also has regulatory authority over wholesale electricity sales and the transmission of electricity.

The electricity generation business of ACE was restructured in the third quarter of 1999, pursuant to New Jersey’s Electric Discount and Energy Competition Act (the New Jersey Act) and a Summary Order issued by the

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NJBPU to ACE. The restructuring provided for customer choice of electricity suppliers, rate decreases, and quantification of the recovery through customer rates of the uneconomic portion of assets and long-term contracts that resulted from restructuring (stranded costs). Based on the Summary Order, ACE determined that the requirements of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71) no longer applied to its electricity generation business and an extraordinary charge to 1999 earnings resulted. For information concerning the effects of SFAS No. 71 on ACE’s financial statements, including discontinuing the application of SFAS No. 71 to the electricity generation business, see Notes 1, 5, 6, 7 and 10 to the Consolidated Financial Statements included in Item 8 of Part II.

For information concerning changes in retail electric rates, see Note 6 to the Consolidated Financial Statements included in Item 8 of Part II.

As discussed above, as a subsidiary of a registered holding company under the PUHCA, ACE is subject to certain restrictions imposed by PUHCA on the operations of subsidiaries of registered holding companies.

Divestiture of Electric Generating Plants

ACE continued with the divestiture of its electric generating plants during 2001. The divestiture began effective July 1, 2000 with ACE’s contribution to Conectiv at net book value of its combustion turbines, which had an electric generating capacity of 502 megawatts (MW). On October 18, 2001, ACE sold its ownership interests in nuclear electric generating plants with 383 MW of capacity. As of December 31, 2001, all electric generating plants owned by ACE, which had a carrying value of $111 million and 739.7 MW of capacity, were subject to agreements for sale.

The 739.7 MW of electric generating capacity provided by the plants that are subject to agreements for sale, includes 471.0 MW from coal-fired plants, 241.0 from oil-fired plants, and 27.7 MW from combustion turbine and diesel units. 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.

See Note 9 to the Consolidated Financial Statements included in Item 8 of Part II for information concerning the divestiture of ACE’s electric generating plants, including the sale of plants during 2001 and the agreement for the sale of the electric generating plants owned by ACE as of December 31, 2001.

Securitization

For information concerning the expected securitization of stranded costs, see “Securitization” in Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), included in Item 7 of Part II and Note 6 to the Consolidated Financial Statements included in Item 8 of Part II.

Basic Generation Service

Through July 31, 2002, ACE is obligated to provide Basic Generation Service (BGS); this service entails supplying electricity to customers in ACE’s service area who do not choose an alternative supplier. The Final Decision and Order of the NJBPU concerning restructuring the electric generation business of ACE provided for the recovery through customer rates of the costs incurred by ACE in providing BGS, including an allowed return on certain electric generating plants, the above-market portion of the cost of power purchased from non-utility generators (NUGs), and the above-market portion of costs associated with generating power for BGS customers. In recognition of this cost-based, rate-recovery mechanism, when the costs incurred by ACE in providing BGS exceed the revenues from billings to ACE’s customers for BGS, the under-recovered costs are deferred as a regulatory asset.

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ACE deferred costs related to providing BGS (“deferred electric service costs”) in the amounts of $143.2 million for 2001, $7.5 million for 2000 and $17.2 million for 1999, reflecting management’s assessment that these costs are probable of future recovery. Pursuant to the terms of the 1999 restructuring of ACE’s electric generation business, during 1999-2001, the under-recovered costs were first applied to a deferred energy cost liability which was eliminated and then a regulatory asset was established ($106.3 million as of December 31, 2001). After the initial four-year transition period ends July 31, 2003, customer rates are to be adjusted to recover the deferred cost balance over a reasonable period of time to be determined by the NJBPU. ACE’s recovery of the deferred costs is subject to review by the NJBPU.

The actual 2001 peak load (demand for electricity) associated with ACE’s BGS was 2,259 MW. Management currently forecasts a peak load of 2,243 MW for ACE’s BGS in 2002. The forecasted 2002 peak load is expected to be less than the 2001 actual peak load primarily due to hotter weather for the 2001 peak than the weather assumed for the 2002 peak load forecast.

Purchased Power

On June 29, 2001, New Jersey electric utilities, including ACE, filed a proposal with the NJBPU to use an auction process to procure electricity supply for BGS customers. ACE and the other New Jersey electric utilities proposed that the BGS supply period for which the auction be conducted be the final year of the transition period (August 1, 2002-July 31, 2003) provided for in the New Jersey Act. Under this supply arrangement, ACE, as agent for its BGS customers, will pay for electricity from the suppliers selected by the auction process and the costs associated with this supply will be subject to the regulated cost-based, rate-recovery mechanism for BGS. ACE will continue to collect BGS revenues and will continue to provide all customer-related services. On February 15, 2002, the NJBPU approved the results of the auction that was held from February 4, to February 13, 2002. As result of the auction, four suppliers will provide electricity for 1,900 MW, or about 80% of ACE’s load, at a price of 5.12 cents per kilowatt-hour (kWh) beginning on August 1, 2002. The remaining 20% of ACE’s load will continue to be supplied with power purchased under ACE’s existing purchased power contracts with NUGs. If there is a default by a supplier determined by the auction process, then the defaulted load will be offered to other winning bidders of the auction process, or if that is not possible, then ACE would purchase the electricity supply from the PJM Interconnection L.L.C.

As of December 31, 2001, ACE’s commitments under long-term purchased power contracts provided ACE 1,800 MW of capacity and varying amounts of firm electricity per hour during each month of a given year. Commitments for purchased capacity under contracts existing as of December 31, 2001 will decrease by approximately 1,300 MW in 2002, primarily due to the anticipated replacement of the capacity supplied by these contracts with the capacity and energy to be provided by the BGS suppliers selected by the auction process discussed above. ACE’s long-term purchased power contracts include 494 MW of capacity and energy purchased from NUGs, at prices which generally are above market prices. ACE purchases electricity from the NUGs as a result of legislation enacted in 1978 which requires electric utilities to purchase such power. ACE recovers the costs of these contracts through rates charged to customers for BGS.

PJM Interconnection, L.L.C.

As a result of Conectiv being a member of the PJM Interconnection, L.L.C. (PJM), the generation and transmission facilities of Conectiv’s subsidiaries 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 eastern half of 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’s installed capacity as of December 31, 2001, was 59,350 MW. The PJM’s peak demand during 2001 was 54,176 MW on August 9, 2001, which resulted in a summer reserve margin of 9.1% (based on installed capacity of 59,100 MW on that date).

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In December 1999 and February 2000, the FERC issued orders that require all public utilities to join or form a regional transmission organization (RTO) in furtherance of the FERC’s goal to increase competition in the wholesale generation market. The FERC conditionally granted RTO status to PJM on July 12, 2001. The FERC has also directed PJM “to continue its current efforts at expanding Westward and to work with New York Independent System Operator (NYISO) and ISO New England to develop a regional transmission organization that encompasses the entire Northeast.” On January 21, 2002, the PJM and the Midwest Independent Transmission System Operator, Inc. (MISO) announced that they have executed a letter of intent to develop a single wholesale market for electricity producers and consumers in all or parts of 27 Midwest and mid-Atlantic states, the District of Columbia and the Canadian province of Manitoba. MISO, including TRANSlink and the Southwest Power Pool, has approximately 125,000 MW of generating capacity.

Fuel Supply for Electric Generation

The coal used by ACE’s coal-fired electric generating plants, which are under contracts to be sold, is procured under purchase orders expiring in 2002 and 2003. ACE’s coal supply obligations for its electric generating units are expected to be assumed by NRG Energy, Inc., the party which has agreed to purchase the plants. The oil supply for ACE’s oil-fired electric generating units is purchased on the spot market. Natural gas used by ACE’s electric generating units is primarily purchased from a local gas distribution company on a semi-firm basis. Management does not anticipate any difficulty in obtaining adequate amounts of fuel for ACE’s electric generating plants.

New Jersey Electric System Reliability Standards

On November 28, 2000, the NJBPU approved interim reliability standards which are in effect through 2002 and are intended to reduce the frequency and duration of electric system outages, as well as improve maintenance and inspection of electric facilities. Final reliability standards are expected to be adopted in late-2002, after the NJBPU reviews data submitted by New Jersey utilities, including ACE. The NJBPU could fine a utility up to $50,000 per violation of these requirements.

Affiliate Transactions

On March 15, 2000, the NJBPU adopted Interim Affiliate Relations, Fair Competition and Accounting Standards and Related Reporting Requirements (Interim Standards). A compliance audit of these interim standards was conducted during 2000. On February 2, 2002, the NJBPU approved seven uncontested recommendations of the compliance audit, which ACE has complied with.

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 12 to 14 to the 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 are shown below.

	Year Ended December 31,
	2001	2000	1999	1998	1997
Ratio of Earnings to Fixed Charges (SEC Method)	2.67	2.03	2.57	1.66	2.84
Ratio of Earnings to Fixed Charges and Preferred Stock Dividends (SEC Method)	2.58	1.95	2.44	1.55	2.58

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For purposes of computing the above ratios, earnings, including Allowance For Funds During Construction, are income before extraordinary item plus income taxes and fixed charges. 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 dividends, preferred stock dividends represent preferred stock dividend requirements multiplied by the ratio that pre-tax income bears to net income.

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 limitations on land use. Permits are required for construction projects and the operation of existing and planned 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 $1 million in 2002.

Air Quality Regulations

The federal Clean Air Act required utilities and other industries to significantly reduce emissions of air pollutants such as sulfur dioxide (SO₂) and oxides of nitrogen (NO_x) by 2000. Under Title I of the Clean Air Act (Ozone Attainment), a third phase of NO_x reductions are required in the Northeast Ozone Transport Region by 2003. This requirement is expected to result in reductions of NO_x during the ozone season (May through September) of up to 85% below baseline years for a 22-state region, including New Jersey. Compliance with the emission standards may be attained through changes to electric generating units or the purchase of allowances under a market-based allowance system established by the United States Environmental Protection Agency (USEPA). New Jersey has a similar system.

On January 31, 2002, ACE notified the New Jersey Department of Environmental Protection (NJDEP) that it was unable to procure all of the 2001 Discrete Emission Reductions (DERs) required by January 30, 2002 under New Jersey’s NO_x Reasonably Available Control Technology (RACT) rules. The deficiency is related to the removal of Public Service Electric & Gas Company’s DER credits from the market under a January 2002 consent decree. Management has initiated discussions with the NJDEP about this matter but is unable to predict the outcome of those discussions or the impact (if any) of the unavailability of New Jersey NO_x DERs on the operation of ACE-owned electric generating units requiring such credits.

Under Title III of the Clean Air Act, the USEPA is currently developing MACT (Maximum Achievable Control Technology) standards for several listed chemicals, including mercury from coal-fired plants and nickel from oil-fired plants. Regulations are scheduled to be drafted by the end of 2002 and promulgated in 2003, with compliance anticipated three years later. A plan for compliance will be developed when the rules are final.

The USEPA requested data from a number of electric utilities regarding older coal-fired units in order to determine compliance with the regulations for the Prevention of Significant Deterioration of Air Quality (PSD). A number of settlements of litigation brought as a result of such inquires alleging violations of so-called new source standards have been announced. Beginning on February 23, 2000, ACE received a number of requests for data from the USEPA and the NJDEP on coal-fired operations at the Deepwater and B.L. England electric generating stations. In response to USEPA and NJDEP requests, data was submitted throughout 2000 and 2001 and continues to be submitted. At this time it is not possible to predict the impact of these data requests, if any, on Deepwater or B.L. England operations.

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On July 11, 2001, the NJDEP denied ACE’s request to renew a permit variance, effective through July 30, 2001, that authorized Unit 1 at the B.L. England station to burn coal containing greater than 1% sulfur. ACE has appealed the denial. The NJDEP has issued a stay of the denial to authorize ACE to operate Unit 1 with the current fuel until June 30, 2002 and an addendum to the permit/certificate to operate authorizing a trial burn of coal with a sulfur content less than 2.6%. Management is not able to predict the outcome of ACE’s appeal.

Water Quality Regulations

The Clean Water Act imposes 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 waste-waters 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.

ACE holds New Jersey Pollution Discharge Elimination System (NJPDES) permits issued by the NJDEP for the Deepwater and B.L. England power stations. The NJPDES permit for the Deepwater Station expired in 1991. The permit has been administratively extended and the plant continues to operate under the conditions of the existing permit while negotiations are underway for permit renewal. The NJPDES permit for the B.L. England station expired in December 1999, but has been administratively extended and the plant continues to operate under the conditions of the existing permit until a renewal permit is issued by NJDEP.

Hazardous Substances

See “Environmental Matters” in Note 19 to the Consolidated Financial Statements included in Item 8 of Part II for information concerning hazardous substances.

Executive Officers

The names, ages, and positions of all of the executive officers of ACE as of December 31, 2001, are listed below, along with their business experiences during the past five years. Officers of ACE are elected annually by ACE’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, 2001)

Name, Age and Position	Business Experience During Past 5 Years
Joseph M. Rigby, 45 President	Elected 2000 as Senior Vice President of Conectiv and President of ACE. 1999, Vice President, Electric Delivery, Conectiv. 1998, Vice President, Gas Delivery, Conectiv. 1997, Vice President, Merger Integration Team, Conectiv.
John C. van Roden, 52 Chief Financial Officer	Elected 2000 as Senior Vice President and Chief Financial Officer of Conectiv and Chief Financial Officer of ACE. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv. Principal, Cook and Belier, Inc. in 1998. Senior Vice President/Chief Financial Officer and Vice President/Treasurer, Lukens, Inc. from 1987 to 1998.
James P. Lavin, 54 Controller and Chief Accounting Officer	Elected 1998 as Controller of Conectiv and ACE. Elected 1993 as Comptroller, Delmarva Power & Light Company.

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ITEM 2.     PROPERTIES

Electric Generating Station	Location	Generating Capacity (kilowatts)
Coal-Fired
B L England	Beesley’s Pt., NJ	284,000
Conemaugh	New Florence, PA	65,000	*
Keystone	Shelocta, PA	42,000	*
Deepwater	Pennsville, NJ	80,000
		471,000
Oil-Fired
B L England	Beesley’s Pt., NJ	155,000
Deepwater	Pennsville, NJ	86,000
		241,000
Combustion Turbines
Deepwater	Pennsville, NJ	19,000
Diesel Units
B L England	Beesley’s Pt., NJ	8,000
Keystone	Shelocta, PA	300	*
Conemaugh	New Florence, PA	400	*
		8,700
Total Electric Generating Capacity		739,700

* Represents ACE’s ownership interest in jointly-owned plants.

The electric generating plants shown in the table above were subject to agreements for sale as discussed in Note 9 to the Consolidated Financial Statements included in Item 8 of Part II.

Substantially all utility plants and properties of ACE are subject to the lien of the Mortgage under which First Mortgage Bonds are issued.

The electric transmission and distribution systems of ACE includes 1,231 transmission poleline miles of overhead lines, 7,901 distribution poleline miles of overhead lines, and 2,283 distribution cable miles of underground cables.

ITEM 3.     LEGAL PROCEEDINGS

Information reported under the heading “Other” in Note 19 to the Consolidated Financial Statements, included in Item 8 of Part II, concerning an action filed in a New Jersey Superior Court by the City of Vineland, is incorporated by reference.

Information reported under the heading “Environmental Matters,” “Air Quality Regulations” included in Item 1 of Part I is incorporated by reference.

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.

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ATLANTIC CITY ELECTRIC COMPANY

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

All 18,320,937 shares of ACE’s common stock outstanding are owned by Conectiv, its parent company.

ACE’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.

As a subsidiary of a registered holding company under PUHCA, ACE can pay dividends only to the extent of its retained earnings unless SEC approval is obtained.

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ATLANTIC CITY ELECTRIC COMPANY

ITEM 6.     SELECTED FINANCIAL DATA

	Year Ended December 31,
	2001		2000		1999(1)			1998(2)		1997(3)
	(Dollars in Thousands)
Operating Results
Operating Revenues	$	1,041,171	$	960,862	$	1,059,415		$	1,039,750	$	1,084,890
Operating Income		179,741		166,524		171,931			108,868		190,052
Income Before Extraordinary Item		75,476		54,434		63,930			30,276		85,747
Extraordinary Item, Net of Income Taxes of $40,474 (4)		—		—		(58,095	)		—		—
Net Income		75,476		54,434		5,835			30,276		85,747
Earnings Applicable to Common Stock		73,793		52,302		3,703			29,385		80,926
Capitalization
Common Stockholder’s Equity	$	621,309	$	580,119	$	677,951		$	730,093	$	783,033
Preferred Stock
Not Subject to Mandatory Redemption		6,231		6,231		6,231			6,231		30,000
Subject to Mandatory Redemption		12,450		23,950		23,950			23,950		33,950
Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely company debentures		95,000		95,000		95,000			95,000		70,000
Variable Rate Demand Bonds (VRDB) (5)		22,600		22,600		22,600			22,600		22,600
Long-Term Debt		636,303		857,653		954,752			791,127		811,144
Total Capitalization with VRDB	$	1,393,893	$	1,585,553	$	1,780,484		$	1,669,001	$	1,750,727
Other Information
Total Assets	$	2,432,330	$	2,481,382	$	2,654,659		$	2,367,222	$	2,436,755
Long-Term Capital Lease Obligations		—		12,872		14,911			19,523		24,077
Capital Expenditures		70,023		53,717		48,931			71,342		80,896
Common Dividends Declared (6)		32,603		67,309		55,845			81,450		80,857

(1) Atlantic City Electric Company (ACE) and Delmarva Power & Light Company (DPL) became wholly-owned subsidiaries of Conectiv ( the 1998 Merger) on March 1, 1998. In 1999, special charges for employee separations, additional costs related to the 1998 Merger, and other non-recurring costs reduced operating income by $12.3 million and income before extraordinary item, net income, and earnings applicable to common stock by $7.3 million.

(2) In 1998, special charges for the costs of 1998 Merger-related employee separations and relocations and other 1998 Merger-related charges reduced operating income by $61.1 million and income before extraordinary item, net income, and earnings applicable to common stock by $36.6 million. Also, in 1998, the write-down to fair value of certain operational and administrative facilities to be sold due to the 1998 Merger reduced operating income by $18.0 million and income before extraordinary item, net income, and earnings applicable to common stock by $10.6 million.

(3) In 1997, special charges for 1998 Merger-related employee separation benefits reduced operating income by $22.6 million and income before extraordinary item, net income, and earnings applicable to common stock by $15.6 million.

(4) As discussed in Note 5 to the Consolidated Financial Statements, the extraordinary item in 1999 resulted from the restructuring of the electric utility industry and discontinuing the application of Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”

(5) 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 14 to ACE’s Consolidated Financial Statements.

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

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ATLANTIC CITY ELECTRIC COMPANY

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 “intend,” “will,” “anticipate,” “estimate,” “expect,” “believe,” 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: the effects of deregulation of electricity generation, including securitization of stranded costs, and the unbundling of delivery services; the ability to purchase power on acceptable terms; volatility in market demand and prices for energy, capacity, and fuel; changes in weather and economic conditions affecting energy usage; operating performance of power plants; competition; asset sales; energy sales retention and growth; federal and state regulatory actions and legislation affecting the energy industry; future litigation results; costs of construction; operating restrictions; effects of environmental regulations on operations and construction; and interest rate fluctuations 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 list of factors pursuant to the Litigation Reform Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made prior to the effective date of the Litigation Reform Act.

OVERVIEW

ACE is a subsidiary of Conectiv, which is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On March 1, 1998, Conectiv was formed (the 1998 Merger) through an exchange of common stock with Atlantic Energy, Inc. and Delmarva Power & Light Company (DPL).

On February 9, 2001, the Boards of Directors of Conectiv and Potomac Electric Power Company (Pepco) approved an Agreement and Plan of Merger (Conectiv/Pepco Merger Agreement) under which Pepco will acquire Conectiv for a combination of cash and stock, and Conectiv and Pepco will become wholly owned subsidiaries of Pepco Holdings Inc. (Conectiv/Pepco Merger). The Conectiv/Pepco Merger was approved by the stockholders of Conectiv and Pepco during 2001. Management currently expects the Conectiv/Pepco Merger to close in the second quarter of 2002, subject to timely receipt of various statutory and regulatory approvals.

ACE is a public utility which supplies and delivers electricity to its customers under the trade name Conectiv Power Delivery. ACE delivers electricity within its service area to approximately 508,600 customers through its transmission and distribution systems and also supplies electricity to most of its electricity delivery customers, who have the option of choosing an alternative supplier.

The electricity generation business of ACE was restructured in the third quarter of 1999, pursuant to New Jersey’s Electric Discount and Energy Competition Act (the New Jersey Act) and a Summary Order issued by the New Jersey Board of Public Utilities (NJBPU) to ACE. The restructuring provided for customer choice of electricity suppliers, rate decreases, and quantification of the recovery through customer rates of the uneconomic portion of assets and long-term contracts that resulted from restructuring (stranded costs). Based on the Summary Order, ACE determined that the requirements of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71) no longer applied to its electricity

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generation business and an extraordinary charge to 1999 earnings resulted, as discussed below and in Notes 1, 5, 6, 7 and 10 to the Consolidated Financial Statements.

As discussed in Note 9 to the Consolidated Financial Statements, ACE continued the divestiture of its electric generating plants during 2001. The divestiture began effective July 1, 2000 with ACE’s contribution to  Conectiv at net book value of its combustion turbines, which had an electric generating capacity of 502  megawatts (MW). On October 18, 2001, ACE sold its ownership interests in nuclear electric generating plants with 383 MW of capacity. As of December 31, 2001, all of ACE’s remaining electric generating plants, which had a carrying value of $117 million and 739.7 MW of capacity, were subject to agreements for sale.

ACE’s exit from the business of electricity production is expected to cause a decrease in ACE’s earnings capacity.

BASIC GENERATION SERVICE

Through July 31, 2002, ACE is obligated to provide Basic Generation Service (BGS); this service entails supplying electricity to customers in ACE’s service area who do not choose an alternative supplier. The Final Decision and Order of the NJBPU concerning restructuring the electric generation business of ACE provided for the recovery through customer rates of the costs incurred by ACE in providing BGS, including an allowed return on certain electric generating plants, the above-market portion of the cost of power purchased from non-utility generators (NUGs), and the above-market portion of costs associated with generating power for BGS customers. In recognition of this cost-based, rate-recovery mechanism, when the costs incurred by ACE in providing BGS exceed the revenues from billings to ACE’s customers for BGS, the under-recovered costs are deferred as a regulatory asset.

ACE deferred costs related to providing BGS (“deferred electric service costs”) in the amounts of $143.2 million for 2001, $7.5 million for 2000 and $17.2 million for 1999, reflecting management’s assessment that these costs are probable of future recovery. If management had been unable to conclude that recovery of these costs in the future is probable, then net income would have decreased by approximately $84.7 million for 2001, $4.4 million for 2000, and $10.2 million for 1999. The increase in deferred expenses for 2001 reflects the cumulative effect of rate decreases and more electricity purchased, partly due to “Wholesale Transaction Confirmation Letter Agreements” under which ACE sold its interest in the kilowatt-hour (kWh) output of nuclear electric  generating plants. Pursuant to the terms of the 1999 restructuring of ACE’s electric generation business, during 1999-2001, the under-recovered costs were first applied to a deferred energy cost liability which was eliminated and then a regulatory asset was established ($106.3 million as of December 31, 2001). After the initial four-year transition period ends July 31, 2003, customer rates are to be adjusted to recover the deferred cost balance over a reasonable period of time to be determined by the NJBPU. ACE’s recovery of the deferred costs is subject to review by the NJBPU.

On June 29, 2001, New Jersey electric utilities, including ACE, filed a proposal with the NJBPU to use an auction process to procure electricity supply for BGS customers. ACE and the other New Jersey electric utilities proposed that the BGS supply period for which the auction be conducted be the final year of the transition period (August 1, 2002-July 31, 2003) provided for in the New Jersey Act. Under this supply arrangement, ACE, as agent for its BGS customers, will pay for electricity from the suppliers selected by the auction process and the costs associated with this supply will be subject to the regulated cost-based, rate-recovery mechanism for BGS. ACE will continue to collect BGS revenues and will continue to provide all customer-related services. On February 15, 2002, the NJBPU approved the results of the auction that was held from February 4, to February 13, 2002. As result of the auction, four suppliers will provide electricity for 1,900 MW, or about 80% of ACE’s load, at a price of 5.12 cents per kWh beginning on August 1, 2002. The remaining 20% of ACE’s load will continue to be supplied with power purchased under ACE’s existing purchased power contracts with NUGs. If there is a default by a supplier determined by the auction process, then the defaulted load will be offered to other winning bidders of the auction process, or if that is not possible, then ACE would purchase the electricity supply from the PJM Interconnection L.L.C.

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EARNINGS SUMMARY

Earnings applicable to common stock increased by $21.5 million to $73.8 million for 2001, from $52.3 million for 2000. The $21.5 million earnings increase was mainly due to higher volumes of regulated electricity sales and deliveries, reflecting higher electricity usage related to warmer summer weather and growth in the number of customers. Due to increased volumes of purchased power, ACE incurred higher average energy costs in serving its BGS customers; however, earnings were unaffected because, to the extent costs exceeded revenues from billings to ACE’s customers for BGS, costs were deferred as a regulatory asset. The earnings increase also reflects lower depreciation and amortization expenses and lower interest expense. The variances that positively affected earnings were partly offset by the loss of earnings attributed to the transfer of the combustion turbine electric generating units to Conectiv on July 1, 2000.

Earnings applicable to common stock were $52.3 million for 2000, compared to $3.7 million for 1999. In 1999, earnings applicable to common stock of $3.7 million included (i) a $58.1 million extraordinary charge, after income taxes of $40.5 million, for discontinuing the application of SFAS No. 71 to ACE’s electricity generation business, and (ii) $7.3 million of special charges, net of taxes, primarily for the costs of 1998 Merger-related employee separations and relocations and other 1998 Merger-related costs. For additional information concerning deregulation and the extraordinary charge to earnings, see Notes 1, 5, 6, 7 and 10 to the Consolidated Financial Statements.

Earnings of $52.3 million for 2000 represent a $16.8 million decrease from earnings of $69.1 million for 1999, adjusted to exclude the $58.1 million extraordinary charge and $7.3 million of special charges. The $16.8 million decrease in earnings (excluding the 1999 extraordinary and special charges) was primarily due to lower electricity sales during the summer when average rates are higher, lower customer rates related to electric utility industry restructuring, and higher interest expense, partly offset by the benefit of lower operating expenses and a lower effective income tax rate.

SECURITIZATION

In mid-May 2001, the NJBPU issued a Final Decision and Order to ACE containing details about restructuring ACE’s electric utility business, pursuant to the New Jersey Act that was enacted February 9, 1999.

As of December 31, 2001, the balance for ACE’s pre-tax recoverable stranded costs was $930 million, which is approximately $550 million on an after-tax basis.

Under the New Jersey Act, up to 100% of recovery-eligible stranded costs related to electric generating plants and the costs to effect buyouts or buydowns of NUG contracts may be recovered through customer rates. Also, the New Jersey Act permits securitization of stranded costs through the issuance of transition bonds in the amount approved by the NJBPU. More specifically, the New Jersey Act provides for securitization of: (a) up to 75% of recovery-eligible stranded costs related to electric generating plants, over a period not to exceed 15 years, and (b) 100% of the costs to effect NUG contract buyouts or buydowns, over a period not to exceed the remaining term of the restructured contracts. The principal of and interest on transition bonds is to be collected from customers through a transition bond charge over the securitization term. Also, customer rates are to include a separate market transition charge for recovery of the income tax expense associated with the revenues from transition bond charges. The ability to issue transition bonds depends on approval of the NJBPU and conditions in the relevant capital markets at the times of the offerings.

On June 25, 2001, ACE filed a petition with the NJBPU, seeking the authority to: (i) issue through a special purpose entity up to $2 billion in transition bonds in one or more series; (ii) collect from ACE’s customers a non-bypassable, per kWh delivered, transition bond charge (TBC) sufficient to fund principal and interest payments on the bonds and related expenses and fees; (iii) collect from ACE’s customers a separate non-bypassable, per kWh delivered, charge for recovery of the income tax expense associated with the revenues from the TBC; and (iv) sell “bondable transition property,” which is the irrevocable right to collect TBC, to a special purpose financing entity.

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The transition bonds are expected to be issued after the NJBPU issues a bondable stranded costs rate order (Financing Order) establishing “bondable transition property,” as provided for in the New Jersey Act. To facilitate the issuance of transition bonds, ACE formed Atlantic City Electric Transition Funding LLC (ACE Transition Funding) during 2001. Assuming that the NJBPU issues a Financing Order containing terms and conditions satisfactory to ACE, subsequent to issuance of such order, ACE Transition Funding is expected to issue transition bonds and use the proceeds to purchase the bondable transition property from ACE. When issued, the transition bonds of ACE Transition Funding will be included in ACE’s Consolidated Balance Sheet. The New Jersey Act requires utilities, including ACE, to use the proceeds from the sale of bondable transition property to redeem debt or equity or both, restructure NUG purchased power contracts, or otherwise reduce costs in order to decrease regulated electricity rates.

The balance for ACE’s pre-tax recoverable stranded costs of $930 million as of December 31, 2001, primarily includes the $228.5 million payment in December 1999 to terminate ACE’s contract with Pedricktown (a NUG) and stranded costs related to electric generating plants. On November 10, 1999, the NJBPU issued a Decision and Order, which found that ACE is entitled to recover from customers and securitize the Pedricktown contract termination payment and related transaction costs. On September 17, 2001, the NJBPU issued a Decision and Order that determined the amount eligible for recovery by ACE of stranded costs associated with ACE’s former ownership interests in nuclear electric generating plants to be approximately $298 million, after income taxes, (or $504 million before income taxes) as of December 31, 1999, subject to further adjustments. As discussed below, on February 20, 2002, the NJBPU issued a Decision and Order approving the sale of ACE’s fossil fuel-fired electric generating plants and determined the amount eligible for recovery by ACE of stranded costs associated with such plants to be approximately $101 million after income taxes (or $171 million before income taxes) as of December 31, 1999, subject to further adjustment. The amount of ACE’s recoverable stranded costs remains subject to adjustment based on the actual gain or loss which may be realized on the expected sale of ACE’s fossil fuel-fired electric generating plants (see “Agreements for the Sales of Electric Generating Plants” below), additional buyouts or buydowns of NUG contracts, and the final amount determined by the NJBPU to be recoverable through customer rates under the New Jersey Act. ACE expects that securitization of ACE’s stranded costs will occur during 2002.

AGREEMENTS FOR THE SALES OF ELECTRIC GENERATING PLANTS

Agreements between ACE and NRG Energy, Inc. (NRG) provide for the sale by ACE to NRG of fossil fuel-fired electric generating plants that include Deepwater Station, B.L. England Station, and interests in Conemaugh and Keystone Stations. As of December 31, 2001, ACE’s fossil fuel-fired plants that were under agreements for sale had an agreed-upon total sales price of approximately $178 million (before certain adjustments and expenses), a net book value of approximately $117 million and electric generating capacity of 739.7 MW. Due to the terms of ACE’s electric utility restructuring in 1999 and expected sales proceeds, (i) the loss expected to be realized on the sale of the Deepwater Station was included in the extraordinary charge to earnings in 1999, (ii) the loss expected to be realized on the sale of the B.L. England Station is included in recoverable stranded costs, and (iii) any net gain that may be realized on the sale of ACE’s interests in Conemaugh and Keystone Stations is expected to reduce the amount of stranded costs to be recovered from ACE’s utility customers.

As discussed above, on February 20, 2002, the NJBPU issued a Decision and Order approving the sale of ACE’s fossil fuel-fired electric generating plants. The agreements between ACE and NRG for the sale of the fossil fuel-fired electric generating plants remain in effect, but, after February 28, 2002, are subject to termination by either party, by giving notice. Neither party has terminated the agreements. The appeal period for the Decision and Order that was issued by the NJBPU to approve the plant sales expires in early-April 2002. ACE cannot predict whether or not any or all of the plants will be sold, but ACE is endeavoring to close the sales on mutually-acceptable terms and timetable.

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OPERATING REVENUES

	2001		2000		1999
	(Dollars in millions)
Regulated electric revenues	$	1,026.7	$	909.3	$	1,031.4
Non-regulated electric revenues		8.9		40.7		19.9
Other revenues		5.6		10.9		8.1
Total operating revenues	$	1,041.2	$	960.9	$	1,059.4

The table above shows the amounts of electric revenues earned which are subject to price regulation (regulated) and which are not subject to price regulation (non-regulated). “Regulated electric revenues” include revenues for delivery (transmission and distribution) service and BGS.

The gross margin earned from total electric revenues is equal to revenues decreased by “electric fuel and purchased energy and capacity” expenses and increased by “deferred electric service costs.” The gross margin earned from total electric revenues was $542.2 million in 2001, $536.7 million in 2000, and $588.2 million in 1999. Gross margin increased by approximately $5.5 million in 2001 and decreased by approximately $51.5 million in 2000. The decrease in the 2000 gross margin primarily reflects the effects of lower customer rates.

In 2001, “regulated electric revenues” increased by $117.4 million to $1,026.7 million, from $909.3 million for 2000. In 2000, “regulated electric revenues” decreased by $122.1 million to $909.3 million, from $1,031.4 million for 1999. Details of the variances in “regulated electric revenues” are shown below.

	Increase (Decrease) in Regulated Electric Revenues
	2001 compared to 2000			2000 compared to 1999
	(Dollars in millions)
Customers choosing alternative electricity suppliers (1)	$	53.8		$	(86.0	)
Decrease in retail rates from electric utility industry restructuring (2)		(10.0	)		(38.9	)
Variance in volumes of interchange sales		37.6			4.0
Retail sales volume, sales mix, and all other (3)		36.0			(1.2	)
	$	117.4		$	(122.1	)

(1) The $53.8 million increase for 2001 represents customers returning to ACE from alternative suppliers and the $86.0 million decrease for 2000 represents customers choosing alternative suppliers.

(2) Electric rate decreases were implemented as a result of electric utility restructuring. In addition to the rate decreases which have already been implemented, ACE’s rates are expected to be reduced by about $30 million on an annualized basis by August 1, 2002.

(3) Regulated retail electricity delivery sales increased 2.4% in 2001 and 0.5% in 2000. Although regulated electricity sales increased in 2000, a $1.2 million revenue decrease resulted due to lower sales during the summer when customer rates are higher.

“Non-regulated electric revenues” include revenues from the combustion turbine electric generating units and Deepwater electric generating plant which became deregulated on August 1, 1999. Upon the transfer of the combustion turbines to Conectiv on July 1, 2000, “non-regulated electric revenues” (and expenses) from these units were excluded from ACE’s results of operations. ACE’s non-regulated electricity generation business will end upon completion of the sale of the Deepwater electric generating plant.

“Non-regulated electric revenues” decreased $31.8 million for 2001 mainly due to the transfer of the combustion turbine electric generating units to Conectiv, effective July 1, 2000. “Non-regulated electric revenues” increased $20.8 million for 2000 compared to 1999, mainly due to the timing of deregulation which resulted in a longer period of deregulated power plant operations in 2000.

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OPERATING EXPENSES

Electric Fuel and Purchased Energy and Capacity

“Electric fuel and purchased energy and capacity” increased $215.8 million for 2001 compared to 2000 mainly due to increased volumes of electricity purchased, partly due to ACE’s Wholesale Transaction  Confirmation Letter Agreements, under which ACE sold its interest in the kWh output of nuclear electric  generating plants. “Electric fuel and purchased energy and capacity” decreased $59.6 million for 2000 compared to 1999 mainly due to lower average costs, reflecting termination of the Pedricktown purchased power agreement in December 1999 and other favorable variances.

Special Charges

ACE’s operating expenses for 1999 include special charges of $12.3 million before taxes ($7.3 million after taxes) for employee separation and other costs related to the 1998 Merger and certain other nonrecurring costs.

Operation and Maintenance Expenses

In 2001, operation and maintenance expenses increased $5.6 million due to increased allowances for  uncollectible accounts receivable and higher costs for pension and other postretirement benefits, partly offset by a decrease from the sale of ACE’s interests in nuclear electric generating units on October 18, 2001. In 2000, operation and maintenance expenses decreased $10.3 million primarily due to lower costs for pension and other postretirement benefits.

Depreciation and amortization

In 2001, depreciation and amortization expenses decreased $16.8 million mainly due to expiration of the amortization of a regulatory asset and the sale of ACE’s interests in nuclear electric generating plants.

In 2000, depreciation and amortization expenses decreased $12.2 million mainly due to the contribution of the combustion turbines to Conectiv on July 1, 2000 and the 1999 write-downs of electric generating plants in connection with restructuring the electric utility industry in New Jersey. Depreciation expense for capital  improvements to the electric transmission and distribution systems and amortization of “Recoverable stranded costs” partly offset the decrease from lower depreciation of power plants.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $8.4 million in 2000 mainly due to the phasing-out of  New Jersey’s transitional energy facility assessment.

Deferred Electric Service Costs

For information about “Deferred Electric Service Costs,” see “Basic Generation Service” above in  Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).

OTHER INCOME

Other income increased $3.7 million in 2001 mainly due to a higher average investment balance in  Conectiv’s money pool, which Conectiv subsidiaries invest in and borrow from, depending on cash needs.

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INTEREST EXPENSE

Interest expense, net of amounts capitalized, decreased $14.1 million in 2001 due to lower interest rates on ACE’s term loan that funded the Pedricktown contract buyout, debt redemptions, and less interest expense on the deferred energy cost liability that was eliminated in 2001 by under-recoveries of costs related to providing BGS.

In 2000, interest charges, net of amounts capitalized, increased $15.8 million primarily due to interest charges on $228.5 million borrowed in December 1999 to finance the payment to terminate the Pedricktown contract buyout.

INCOME TAXES

Income taxes increased $10.0 million in 2001 mainly due to higher pre-tax income, partly offset by a lower effective income tax rate. Income taxes decreased $12.6 million in 2000, primarily due to lower pre-tax income and also due to a lower effective income tax rate.

CRITICAL ACCOUNTING POLICIES

ACE’s accounting policies are disclosed in Note 1 to the Consolidated Financial Statements. “Critical accounting policies” are those that are considered important to the portrayal of ACE’s financial condition and results, and require exercise of judgment by management. The critical accounting policy concerning “Accounting for the Effects of Certain Types of Regulation” is discussed below.

Accounting for the Effects of Certain Types of Regulation

The requirements of SFAS No. 71 apply to ACE’s electric delivery business and to BGS, because certain aspects of these businesses are subject to regulation. When utility revenues are insufficient to recover current period expenses from customers, the NJBPU may provide for future recovery from customers of such current period expenses. In accordance with SFAS No. 71, when future recovery is probable for current under-recoveries of utility expenses, 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 a regulatory commission. As of December 31, 2001, ACE had $1.1 billion of regulatory assets, under the jurisdiction of the NJBPU, including $930.0 million of pre-tax stranded costs and $106.3 million of deferred electric service costs. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. Should existing facts or circumstances change in the future to indicate that a regulatory asset is not probable of recovery, then the regulatory asset would be charged to earnings. For additional information, see (i) “Basic Generation Service” above within the MD&A, (ii) “Securitization” above within the MD&A, and (iii) Notes 6 and 10 to the Consolidated Financial Statements.

NEW ACCOUNTING STANDARDS

On July 20, 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 141 requires that business combinations initiated after June 30, 2001 be accounted for under the purchase method of accounting. SFAS No. 142 became effective January 1, 2002. The adoption of SFAS No. 141 and SFAS No. 142 is not expected to immediately affect ACE’s financial statements.

On August 9, 2001, the FASB issued SFAS No. 143, “Accounting For Asset Retirement Obligations,” which establishes the accounting requirements for asset retirement obligations (ARO) associated with tangible long-lived assets. If a legal obligation for an ARO exists, then SFAS No. 143 requires recognition of a liability,

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capitalization of the cost associated with the ARO, and allocation of the capitalized cost to expense. The initial measurement of an ARO is based on the fair value of the obligation, which may result in a gain or loss upon the settlement of the ARO. If the requirements of SFAS No. 71 are met, a regulated entity shall also recognize a regulatory asset or liability for timing differences between financial reporting and rate-making in the recognition of the period costs associated with an ARO. SFAS No. 143 will be effective January 1, 2003 for companies with a calendar fiscal year, including ACE. Upon adoption of SFAS No. 143, the difference between the net amount recognized in the balance sheet under SFAS No. 143 and the net amount previously recognized in the balance sheet will be recognized as the cumulative effect of a change in accounting principle. ACE is currently evaluating SFAS No. 143 and cannot predict the impact that this standard may have on its financial position or results of operations; however, any such impact could be material.

On October 3, 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” which requires that one accounting model be used for long-lived assets to be disposed of by sale and broadens discontinued operations to include more disposal transactions. Under SFAS No. 144, operating losses of discontinued operations are recognized in the period in which they occur; future operating losses are not accrued upon discontinuation of the business operation. SFAS No. 144 became effective on January 1, 2002. ACE does not expect the adoption of SFAS No. 144 will materially affect its financial position or results of  operations.

LIQUIDITY AND CAPITAL RESOURCES

General

ACE’s capital structure as of December 31, 2001 and 2000, expressed as a percentage of total capitalization is shown below.

	December 31, 2001	December 31, 2000
Common stockholder’s equity	37.4%	34.5%
Preferred stock	1.1%	1.8%
Preferred trust securities	5.8%	5.6%
Long-term debt and variable rate demand bonds	39.7%	52.3%
Short-term debt and current maturities of long-term debt	16.0%	5.8%

ACE borrowed $228.5 million through a bank term loan on December 28, 1999 to finance a cash payment for termination of a NUG purchased power contract with Pedricktown, as discussed in Note 7 to the Consolidated Financial Statements. On December 20, 2001, ACE repaid $57.1 million of the term loan balance; the remaining $171.4 million balance is due December 20, 2002.

ACE’s term loan contains financial and other covenants which, if not met, could result in the acceleration of repayment obligations under the agreement or restrict ACE’s ability to borrow under the agreement. The term loan requires a ratio of total indebtedness to total capitalization of 65% or less. As of December 31, 2001, the ratio was 56%, computed in accordance with the terms of the agreement. The term loan also contains a number of events of default that could be triggered by the acceleration of indebtedness under certain other borrowing arrangements, bankruptcy actions or judgments or decrees against ACE, as well as by a change of control of ACE, such as the Conectiv/Pepco Merger. ACE plans to request a waiver of its term loan change of control provisions so the term loan will continue after the Conectiv/Pepco Merger. ACE plans to repay this debt with proceeds from the expected issuance of transition bonds, which are discussed in Note 6 to the Consolidated Financial Statements and under “Securitization” above.

Credit ratings assigned to securities of ACE by Moody’s Investor Service (Moody’s) and Standard & Poor’s (S&P) are shown in the table below. These security ratings are not a recommendation to buy, sell or hold securities.

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The ratings are subject to revision or withdrawal at any time by the respective rating agencies. Each rating should be evaluated independently of any other rating.

Type of Security	Moody’s	S&P
Senior secured debt	A2	A-
Senior unsecured debt	A3	BBB+
Short-term debt	P-1	A-2
Preferred stock	a3	BBB
Preferred trust securities	a3	BBB

As of December 31, 2001, provisions of certain contracts under which ACE procures electricity for BGS would require ACE to provide cash collateral of $42.1 million, if ACE’s credit ratings were downgraded below investment grade. The cash collateral required in the event of a credit rating downgrade fluctuates based on energy market conditions. Changes in credit ratings could also affect ACE’s cost of capital and access to capital markets. Credit rating agencies are paying increased attention to issuer companies, including ACE, given changes in the structure of the energy industry and the bankruptcy of Enron. ACE’s future credit ratings may be affected by many factors including rating agency standards, utility and energy industry conditions, legislative changes impacting the electric or gas industry, general economic conditions, decisions of regulatory commissions, and the capital structure, financial coverage ratios, and operating results of ACE.

ACE’s operating results are expected to continue to be affected by the implementation of electric utility industry restructuring in New Jersey, including (i) an expected $30 million annualized decrease in ACE’s electric rates scheduled to become effective by August 1, 2002, (ii) the planned securitization of ACE’s stranded costs, and (iii) the planned sale of ACE’s interests in fossil fuel-fired electric generating plants, which may decrease ACE’s earnings capacity. Also, as discussed in Note 19 to the Consolidated Financial Statements, the City of Vineland, New Jersey, has initiated an action to acquire by eminent domain the electric distribution facilities of ACE located within the City. In addition, weather and general economic conditions affect the level of electricity sales and earnings realized by ACE. Due to the various factors which may affect ACE’s earnings, past results are not an indication of future business prospects or financial results of ACE.

The cash required by ACE’s contractual obligations as of December 31, 2001 and certain reasonably likely construction expenditures are summarized in the table below.

	Payments Due by Period
Contractual obligations*	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(Dollars in Millions)
Short-term debt	$	45.0	$	45.0	$	—	$	—	$	—
Variable rate demand bonds		22.6		—		—		—		22.6
Long-term debt		857.8		221.5		137.2		106.9		392.2
Preferred stock subject to mandatory redemption		12.5		11.5		1.0		—		—
Preferred trust securities		95.0		—		—		—		95.0
Capital and operating leases		41.0		8.2		16.4		16.4		—
Purchased power contracts		1,182.0		297.0		420.0		465.0		—
Construction expenditures *		320.5		84.0.		138.3		98.2		—
Total	$	2,576.4	$	667.2	$	712.9	$	686.5	$	509.8

* Construction expenditures include amounts which are not contractual commitments but are reasonably likely to occur based on ACE’s obligation to serve utility customers. For after 5 years, construction expenditures have not been forecasted, but are expected to continue for ACE’s electric delivery business. The future level of capital expenditures may change depending upon growth in demand for electricity, construction scheduling, permitting, state and federal legislation, and other factors.

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ACE’s contractual obligations shown above for purchased power are funded with operating cash flow associated with cash collected from electric service customers. ACE’s capital requirements generally include construction expenditures for the electric delivery business and electric generating units, repayment of debt, preferred stock, preferred trust securities, and capital lease obligations. ACE’s primary sources of capital are cash flow from operating activities and external financings. As discussed under “Securitization,” capital is also expected to be raised in 2002 through the securitization of ACE’s stranded costs, after the NJBPU issues a Financing Order containing terms and conditions satisfactory to ACE. In addition, as discussed under “Agreements For The Sales Of Electric Generating Plants,” ACE plans to sell electric generating units with 739.7 MW of capacity in 2002 for approximately $178 million, before certain adjustments and selling expenses.

Summary of Cash Flows

ACE’s cash flows for 2001, 2000, and 1999 are summarized below.

	Cash Provided (Used)
	2001			2000			1999
	(Dollars in Millions)
Operating Activities	$	44.0		$	282.6		$	(33.3	)
Investing Activities		(45.4	)		(49.9	)		(48.1	)
Financing Activities		(140.4	)		(158.0	)		134.1
Net change in cash and cash equivalents	$	(141.8	)	$	74.7		$	52.7

Cash Flows From Operating Activities

Cash flow from operating activities decreased $238.6 million to $44.0 million for 2001, from $282.6 million for 2000. The decrease in net cash from operating activities was primarily due to higher amounts of electricity purchased during 2001 (as discussed above under “Basic Generation Service” and income tax refunds received during 2000.

In 1999, cash flow from operating activities used $33.3 million of cash due to the $228.5 million payment by ACE in December 1999 to terminate its purchased power contract with Pedricktown. Excluding the $228.5 million contract termination payment, operating activities provided net cash of $195.2 million in 1999, compared to $282.6 million for 2000. This $87.4 million increase in cash flow for 2000 compared to 1999 was due to a $170.9 million decrease in income tax payments, partly offset by the effects of higher interest expense payments, rate decreases and other items.

Cash Flows From Investing Activities

The most significant items included in cash flows from investing activities during 2001, 2000, and 1999 are summarized below.

	Cash Provided (Used)
	2001			2000			1999
	(Dollars in Millions)
Capital expenditures	$	(70.0	)	$	(53.7	)	$	(48.9	)
Sale of electric generating plants		29.6			—			—
All other investing cash flows, net		(5.0	)		3.8			0.8
Net cash used by investing activities	$	(45.4	)	$	(49.9	)	$	(48.1	)

Capital expenditures were $70.0 million in 2001, $53.7 million in 2000, and $48.9 million in 1999. ACE’s capital expenditures are primarily for ACE’s electric transmission and distribution systems.

II-12

On October 18, 2001, ACE sold for $29.6 million its ownership interests in nuclear electric generating plants (383 MW of capacity) and the related nuclear fuel to the utilities which operate the plants. ACE’s trust funds and obligation for decommissioning the plants were transferred to the purchasers in conjunction with the sale. The 2001 Consolidated Statement of Cash Flows excludes the assumption of former nuclear decommissioning liabilities of ACE by the purchasers and also excludes the transfer of nuclear decommissioning trust funds to the purchasers. The fair value of the nuclear decommissioning trust funds that were transferred in 2001 was $115.8 million. The net assets that were sold had a carrying value of $27.3 million, which reflects a write-down in 1999 related to discontinuing SFAS No. 71. ACE used $20.5 million of the proceeds to repay the lease obligations related to the nuclear fuel. Repayment of the lease obligation is included in financing activities within the Consolidated Statement of Cash Flows. There was a $2.4 million pre-tax gain on the sale, which did not affect earnings due to the terms of the 1999 restructuring of the electricity generation business of ACE; instead, the pre-tax gain on the sale decreased the balance of deferred recoverable stranded costs. The sale of ACE’s ownership interests in nuclear electric generating plants is also discussed in Note 9 to the Consolidated Financial  Statements.

The non-cash investing and financing transaction involving the contribution to Conectiv during 2000 of combustion turbines with 502 MW of electric generating capacity is excluded from the 2000 Consolidated Statement of Cash Flows. This transaction resulted in an $83 million decrease in ACE’s common stockholder’s equity. Also, see Note 9 to the Consolidated Financial Statements and the Consolidated Statement of Changes in Common Stockholder’s Equity for information concerning this transaction.

Cash Flows From Financing Activities

ACE pays a common dividend each quarter to Conectiv. Common dividends paid were $44.2 million in 2001, $67.3 million in 2000, and $59.3 million in 1999. As a subsidiary of a registered holding company under PUHCA, ACE can pay dividends only to the extent of its retained earnings unless SEC approval is obtained.

On May 1, 2001 ACE redeemed 115,000 shares of its $7.80 annual dividend rate preferred stock at the $100 per share stated value or $11.5 million in total. ACE’s other external financing activities during 2001, 2000, and 1999, primarily involved debt. Cash flows from debt financing activity are summarized below.

	Cash Provided (Used)
	2001			2000			1999
	(Dollars in millions)
Long-term debt
Issuances	$	—		$	—		$	228.5
Purchases and redemptions		(97.2	)		(46.1	)		(48.9	)
Net		(97.2	)		(46.1	)		179.6
Net change in short-term debt		45.0			(30.0	)		30.0
Net financing activity for long- and short-term debt	$	(52.2	)	$	(76.1	)	$	209.6

During 2001, ACE redeemed at maturity $40 million of 6.81%-7.0%, Medium Term Notes and repaid $57.1 million of its bank term loan. ACE also borrowed $45.0 million on a short-term basis during 2001.

ACE redeemed $46.0 million of 6.83% Medium Term Notes at maturity on January 26, 2000. ACE also repaid in 2000 the $30 million it borrowed on a short-term basis during 1999.

During 1999, ACE borrowed $228.5 million under a credit facility that was converted in 2000 to a term loan and repaid $48.9 million of long-term debt, including $30.0 million of Medium Term Notes (7.52% average interest rate) and $18.9 million of First Mortgage Bonds (6.87% average interest rate).

II-13

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, 2001 and 2000, a hypothetical 10% change in interest rates for short-term and variable rate debt would result in a $0.1 million change in interest costs and earnings before taxes.

Equity Price Risk

As of December 31, 2001, ACE had $3.7 million of investments, including marketable equity securities. As of December 31, 2000, ACE had $112.5 million of investments, primarily nuclear decommissioning trust funds which were transferred to the purchasers of ACE’s interests in nuclear electric generating plants on October 18, 2001. ACE had no equity price risk for changes in the fair value of the nuclear decommissioning trust funds due to periodic adjustment of utility customer rates for such changes. ACE’s equity price risk from a hypothetical 10% change in quoted securities prices was approximately $0.4 million as of December 31, 2001 and 2000.

Commodity Price Risk

As of December 31, 2001 and 2000, ACE had no value at risk with respect to commodity price exposure because ACE did not hold any derivative instruments. See “Basic Generation Service” above for a discussion about how ACE supplies electricity to its customers.

II-14

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 accounting principles generally accepted in the United States of America, 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 auditing standards generally accepted in the United States which include a review of selected internal controls to determine the nature, timing, and extent of audit tests to be applied.

The Audit Committee of Conectiv’s 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 of Directors on recommendation of the Audit Committee.

/s/    JOSEPH M. RIGBY	/s/    JOHN C. VAN RODEN
Joseph M. Rigby	John C. van Roden
President	Chief Financial Officer

February 8, 2002

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REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors

Atlantic City Electric Company

Wilmington, Delaware

In our opinion, the accompanying consolidated financial statements listed in the accompanying index appearing under Item 14(a)(1) on page IV-I present fairly, in all material respects, the financial position of Atlantic City Electric Company and subsidiary companies (“ACE”) as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. 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 ACE’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of the consolidated financial statements in accordance with auditing standards generally accepted in the United States of America 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 our opinion.

/s/    PRICEWATERHOUSECOOPERS LLP

PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 8, 2002

II-16

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	For the Year Ended December 31,
	2001			2000			1999
	(Dollars in Thousands)
Operating Revenues	$	1,041,171		$	960,862		$	1,059,415
Operating Expenses
Electric fuel and purchased energy and capacity		636,552			420,737			480,381
Special charges		—			—			12,301
Operation and maintenance		249,247			243,682			253,970
Depreciation and amortization		84,703			101,527			113,714
Taxes other than income taxes		34,118			35,913			44,288
Deferred electric service costs		(143,190	)		(7,521	)		(17,170	)
		861,430			794,338			887,484
Operating Income		179,741			166,524			171,931
Other Income		11,504			7,808			8,712
Interest Expense
Interest charges		62,166			76,178			60,562
Allowance for borrowed funds used during construction and capitalized interest		(714	)		(645	)		(809	)
		61,452			75,533			59,753
Preferred Dividend Requirements on Preferred Securities of Subsidiary Trusts		7,619			7,619			7,634
Income Before Income Taxes and Extraordinary Item		122,174			91,180			113,256
Income Taxes, Excluding Income Taxes Applicable to Extraordinary Item		46,698			36,746			49,326
Income Before Extraordinary Item		75,476			54,434			63,930
Extraordinary Item (Net of income taxes of $40,474)		—			—			(58,095	)
Net Income		75,476			54,434			5,835
Dividends on Preferred Stock		1,683			2,132			2,132
Earnings Applicable to Common Stock	$	73,793		$	52,302		$	3,703

See accompanying Notes to Consolidated Financial Statements.

II-17

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

	As of December 31,
	2001		2000
	(Dollars in Thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	14,261	$	156,071
Accounts receivable net of allowances of $7,804 and $4,423, respectively		159,679		140,785
Inventories, at average cost
Fuel (coal and oil)		20,331		6,818
Materials and supplies		10,738		6,786
Prepaid income taxes		41,044		—
Other prepayments		1,756		1,738
Deferred income taxes, net		181		15,750
		247,990		327,948
Investments		3,666		112,501
Property, Plant and Equipment
Electric generation		136,152		142,243
Electric transmission and distribution		1,276,896		1,255,184
Other electric facilities		116,215		119,782
Other property, plant, and equipment		5,772		5,772
		1,535,035		1,522,981
Less: Accumulated depreciation		569,495		640,103
Net plant in service		965,540		882,878
Construction work-in-progress		74,780		50,247
Leased nuclear fuel, at amortized cost		—		28,352
		1,040,320		961,477
Deferred Charges and Other Assets
Regulatory assets
Recoverable stranded costs, net		930,036		958,883
Deferred electric service costs		106,259		—
Other non-current regulatory assets		82,944		101,273
Unamortized debt expense		12,966		12,842
Other		8,149		6,458
		1,140,354		1,079,456
Total Assets	$	2,432,330	$	2,481,382

See accompanying Notes to Consolidated Financial Statements.

II-18

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

	As of December 31,
	2001		2000
	(Dollars in Thousands)
CAPITALIZATION AND LIABILITIES
Current Liabilities
Short-term debt	$	44,951	$	—
Long-term debt due within one year		221,450		97,200
Variable rate demand bonds		22,600		22,600
Accounts payable		58,001		50,744
Interest accrued		17,224		18,193
Dividends payable		6,302		17,871
Current capital lease obligation		—		15,480
Deferred energy supply costs		—		34,650
Other		40,461		48,097
		410,989		304,835
Deferred Credits and Other Liabilities
Deferred income taxes, net		470,420		405,385
Deferred investment tax credits		28,482		35,851
Regulatory liability for New Jersey income tax benefit		49,262		49,262
Above-market purchased energy contracts and other electric restructuring liabilities		16,615		16,744
Long-term capital lease obligation		—		12,872
Pension benefit obligation		35,529		26,948
Other postretirement benefit obligation		36,429		37,614
Other		13,311		28,918
		650,048		613,594
Capitalization
Common stock, $3 par value; shares authorized: 25,000,000 ; shares outstanding: 18,320,937		54,963		54,963
Additional paid-in capital		410,194		410,194
Retained earnings		156,152		114,962
Total common stockholder's equity		621,309		580,119
Preferred stock not subject to mandatory redemption		6,231		6,231
Preferred stock subject to mandatory redemption		12,450		23,950
Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely company debentures		95,000		95,000
Long-term debt		636,303		857,653
		1,371,293		1,562,953
Commitments and Contingencies (Note 19)		—		—
Total Capitalization and Liabilities	$	2,432,330	$	2,481,382

See accompanying Notes to Consolidated Financial Statements.

II-19

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2001			2000			1999
	(Dollars in Thousands)
Cash Flows From Operating Activities
Net income	$	75,476		$	54,434		$	5,835
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred recoverable purchased power contract termination payment		—			—			(228,500	)
Extraordinary item net of income taxes		—			—			58,095
Depreciation and amortization		93,987			113,853			126,857
Investment tax credit adjustments, net		(7,369	)		(3,157	)		(2,534	)
Deferred income taxes, net		83,603			23,121			71,897
Deferred electric service and energy supply costs		(143,190	)		(7,521	)		23,844
Net change in:
Accounts receivable		(17,359	)		(7,333	)		(22,644	)
Inventories		(15,645	)		9,110			(7,949	)
Prepaid New Jersey sales and excise taxes		12,772			13,374			22,216
Accounts payable		5,697			(15,008	)		7,921
Taxes accrued		(51,287	)		98,726			(111,399	)
Other current assets and liabilities (1)		3,377			(2,721	)		(3,796	)
Other, net		3,926			5,705			26,828
Net cash provided (used) by operating activities		43,988			282,583			(33,329	)
Cash Flows From Investing Activities
Capital expenditures		(70,023	)		(53,717	)		(48,931	)
Sale of electric generating plants		29,568			—			—
Deposits to nuclear decommissioning trust funds		(825	)		(405	)		(3,213	)
Other, net		(4,117	)		4,196			4,070
Net cash used by investing activities		(45,397	)		(49,926	)		(48,074	)
Cash Flows From Financing Activities
Common dividends paid		(44,172	)		(67,309	)		(59,321	)
Preferred dividends paid		(1,683	)		(2,332	)		(2,821	)
Preferred stock redeemed		(11,500	)		—			—
Long-term debt issued		—			—			228,500
Long-term debt redeemed		(97,200	)		(46,075	)		(48,900	)
Principal portion of capital lease payments		(29,824	)		(12,326	)		(13,143	)
Net change in short-term debt		44,951			(30,000	)		30,000
Other, net		(973	)		—			(223	)
Net cash provided (used) by financing activities		(140,401	)		(158,042	)		134,092
Net change in cash and cash equivalents		(141,810	)		74,615			52,689
Beginning of year cash and cash equivalents		156,071			81,456			28,767
End of year cash and cash equivalents	$	14,261		$	156,071		$	81,456

(1) Other than debt and deferred income taxes classified as current.

See accompanying Notes to Consolidated Financial Statements.

II-20

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDER’S EQUITY

	Total Common Stockholder’s Equity			Common Stock		Additional Paid-in Capital			Retained Earnings
	(Dollars in Thousands)
Balance as of January 1, 1999	$	730,093		$	54,963	$	493,007		$	182,123
Net income		5,835								5,835
Less Cash Dividends:
Preferred stock		(2,132	)							(2,132	)
Common stock		(55,845	)							(55,845	)
Balance as of December 31, 1999		677,951			54,963		493,007			129,981
Net income		54,434								54,434
Less Cash Dividends:
Preferred stock		(2,132	)							(2,132	)
Common stock		(67,309	)							(67,309	)
Contribution to Conectiv of subsidiaries which owned combustion turbine electric generating units (1)		(82,825	)				(82,813	)		(12	)
Balance as of December 31, 2000		580,119			54,963		410,194			114,962
Net income		75,476								75,476
Less Cash Dividends:
Preferred stock		(1,683	)							(1,683	)
Common stock		(32,603	)							(32,603	)
Balance as of December 31, 2001	$	621,309		$	54,963	$	410,194		$	156,152

As of December 31, 2001, ACE had 25 million authorized shares of common stock at $3 par value.

There were 18,320,937 shares outstanding during 1999, 2000 and 2001 which are owned by Conectiv.

(1) See Note 9 to the Consolidated Financial Statements for additional information.

See accompanying Notes to Consolidated Financial Statements.

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ATLANTIC CITY ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.    SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Atlantic City Electric Company (ACE) is a subsidiary of Conectiv, which is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On March 1, 1998, Conectiv was formed (the 1998 Merger) through an exchange of common stock with Atlantic Energy, Inc. and Delmarva Power & Light Company (DPL).

On February 9, 2001, the Boards of Directors of Conectiv and Potomac Electric Power Company (Pepco) approved an Agreement and Plan of Merger (Conectiv/Pepco Merger Agreement) under which Pepco will acquire Conectiv for a combination of cash and stock and Conectiv and Pepco will become wholly-owned subsidiaries of Pepco Holdings, Inc. (the Conectiv/Pepco Merger). The stockholders of Conectiv and Pepco voted in 2001 to approve the Conectiv/Pepco Merger. Management currently expects the Conectiv/Pepco Merger to close in the second quarter of 2002, subject to timely receipt of various statutory and regulatory approvals.

ACE is a public utility which supplies and delivers electricity to its customers under the trade name Conectiv Power Delivery. ACE delivers electricity within its service area to approximately 508,600 customers through its transmission and distribution systems and also supplies electricity (Basic Generation Service) to most of its electricity delivery customers, who have the option of choosing an alternative supplier. ACE’s regulated service area covers about 2,700 square miles within the southern one-third of New Jersey and has a population of approximately 0.9 million.

As discussed in Note 9 to the Consolidated Financial Statements, ACE continued the divestiture of its electric generating plants during 2001. The divestiture began effective July 1, 2000 with ACE’s contribution to Conectiv at net book value of its combustion turbines, which had an electric generating capacity of 502 megawatts (MW). On October 18, 2001, ACE sold its ownership interests in nuclear electric generating plants with 383 MW of capacity. As of December 31, 2001, all of ACE’s remaining electric generating plants, which had a carrying value of $117 million and 739.7 MW of capacity, were subject to an agreement for sale.

Regulation of Utility Operations

Certain aspects of ACE’s electric utility business are subject to regulation by the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC).

ACE’s electric delivery business and Basic Generation Service (BGS) are 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). Prior to the third quarter of 1999, ACE’s electricity generation business was subject to the requirements of SFAS No. 71. As a result of the restructuring of ACE’s electricity generation business in the third quarter of 1999, as discussed in Note 6 to the Consolidated Financial Statements, ACE discontinued applying SFAS No. 71 to its electricity generation business and recorded an extraordinary charge to earnings, as discussed in Note 5 to the Consolidated Financial Statements.

ACE recovers through customer rates the costs it incurs in providing BGS, which entails supplying electricity to customers in ACE’s service area who do not choose an alternative supplier. When utility revenues are insufficient to recover current period expenses from customers, the NJBPU may provide for future recovery from customers of such current period expenses. When future recovery is probable for current under-recoveries of utility expenses, 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 the NJBPU.

II-22

Refer to Note 10 for information about regulatory assets and liabilities arising from the financial effects of rate regulation.

Financial Statement Presentation

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.

Adjustments for under-recoveries of costs related to BGS of $7.5 million for 2000 and $17.2 million for 1999 have been reclassified within the Consolidated Statements of Income from electric operating revenues to operating expenses, as a separate line item captioned “Deferred electric service costs.” The accounting policy for BGS is discussed under “Regulation of Utility Operations,” shown above.

Certain other reclassifications of prior period data have been made to conform with the current presentation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions. These assumptions 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

ACE recognizes revenues for the supply and delivery of electricity upon delivery to the customer, including amounts for services rendered, but not yet billed.

Nuclear Fuel

As discussed in Note 9 to the Consolidated Financial Statements, on October 18, 2001, ACE sold its interests in Peach Bottom Atomic Power Station (Peach Bottom), Salem Nuclear Generating Station (Salem), and Hope Creek Nuclear Generating Station (Hope Creek) and the related nuclear fuel to the utilities which operate the plants. Prior to the sale, the ownership interests of ACE in nuclear fuel at the Peach Bottom, Salem and Hope Creek generating stations were financed through contracts accounted for as capital leases. Nuclear fuel costs, including a provision for the future disposal of spent nuclear fuel, were charged to fuel expense on a unit-of-production basis.

Depreciation

The annual provision for depreciation on utility property is computed on the straight-line basis using composite rates by classes of depreciable property. ACE’s overall composite rate of depreciation was 3.5% for 2001, 3.6% for 2000, and 3.7% for 1999. Through the date of the sale of ACE’s interests in nuclear electric generating plants on October 18, 2001, depreciation expense included a provision for ACE’s share of the estimated cost of decommissioning nuclear power plant reactors based on site-specific studies. Accumulated depreciation is charged with the cost of depreciable property retired, including removal costs less salvage and other recoveries.

Interest Expense

The amortization of debt discount, premium, and expense, including deferred debt extinguishment costs, is included in interest expense.

II-23

Income Taxes

The Consolidated Financial Statements include current and deferred income taxes. 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.

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 (deferred recoverable income taxes) and is included on the Consolidated Balance Sheets in “other non-current regulatory assets.”

Deferred income tax expense generally 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.

Cash Equivalents

In the Consolidated Financial Statements, ACE considers all highly liquid investments and debt securities purchased with a maturity of three months or less to be cash equivalents. Investments in Conectiv’s “money pool,” which Conectiv subsidiaries may invest in, or borrow from, are considered cash equivalents.

Utility Plant

Electric generating plants that became impaired as a result of the restructuring of the electric utility industry in 1999 are stated at the estimated fair value of the plants at the time of restructuring, based on amounts included in agreements for the sales of the plants. All other property, plant and equipment is stated at original cost.

Utility plant is generally subject to a first mortgage lien.

Allowance for Funds Used During Construction and Capitalized Interest

Effective in the third quarter of 1999, the cost of financing the construction of electric generation plant is capitalized in accordance with SFAS No. 34, “Capitalization of Interest Cost.”

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 rate of 8.25% for 2001, 2000 and 1999.

Deferred Debt Extinguishment Costs

Debt extinguishment costs for which recovery through regulated utility rates is probable are deferred and subsequently amortized to interest expense during the rate recovery period.

New Accounting Standards

On July 20, 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible

II-24

Assets.” SFAS No. 141 requires that business combinations initiated after June 30, 2001 be accounted for under the purchase method of accounting. SFAS No. 142 became effective January 1, 2002. The adoption of SFAS No. 141 and SFAS No. 142 is not expected to immediately affect ACE’s financial statements.

On August 9, 2001, the FASB issued SFAS No. 143, “Accounting For Asset Retirement Obligations,” which establishes the accounting requirements for asset retirement obligations (ARO) associated with tangible long-lived assets. If a legal obligation for an ARO exists, then SFAS No. 143 requires recognition of a liability, capitalization of the cost associated with the ARO, and allocation of the capitalized cost to expense. The initial measurement of an ARO is based on the fair value of the obligation, which may result in a gain or loss upon the settlement of the ARO. If the requirements of SFAS No. 71 are met, a regulated entity shall also recognize a regulatory asset or liability for timing differences between financial reporting and rate-making in the recognition of the period costs associated with an ARO. SFAS No. 143 will be effective January 1, 2003 for companies with a calendar fiscal year, including ACE. Upon adoption of SFAS No. 143, the difference between the net amount recognized in the balance sheet under SFAS No. 143 and the net amount previously recognized in the balance sheet will be recognized as the cumulative effect of a change in accounting principle. ACE is currently evaluating SFAS No. 143 and cannot predict the impact that this standard may have on its financial position or results of operations; however, any such impact could be material.

On October 3, 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” which requires that one accounting model be used for long-lived assets to be disposed of by sale and broadens discontinued operations to include more disposal transactions. Under SFAS No. 144, operating losses of discontinued operations are recognized in the period in which they occur; future operating losses are not accrued upon discontinuation of the business operation. SFAS No. 144 became effective on January 1, 2002. ACE does not expect the adoption of SFAS No. 144 will materially affect its financial position or results of  operations.

NOTE 2.    SUPPLEMENTAL CASH FLOW INFORMATION

Cash Paid During the Year

	2001		2000			1999
	(Dollars in Thousands)
Interest, net of capitalized amounts	$	59,696	$	73,520		$	51,723
Income taxes, net of refunds	$	21,849	$	(80,677	)	$	90,185

During 2000, ACE received federal and state income tax refunds of $114.2 million and made estimated tax payments of $33.5 million, resulting in $80.7 million of net income taxes received. The income tax refunds received in 2000 were primarily related to the tax benefit associated with ACE’s payment of $228.5 million on December 28, 1999 to terminate ACE’s purchase of electricity under a contract with the Pedricktown Co-generation Limited Partnership (Pedricktown). For additional information concerning the contract termination, see Note 7 to the Consolidated Financial Statements.

Non-cash Investing and Financing Transaction

The 2001 Consolidated Statement of Cash Flows excludes the assumption of former nuclear decommissioning liabilities of ACE by the purchasers of ACE’s ownership interests in nuclear electric generating plants and also excludes the transfer of nuclear decommissioning trust funds to the purchasers. The fair value of the nuclear decommissioning trust funds that were transferred in 2001 was $115.8 million. For additional information about the sale of ACE’s ownership interests in nuclear electric generating plants, see Note 9 to the Consolidated Financial Statements.

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The 2000 Consolidated Statement of Cash Flows excludes the non-cash transaction for ACE’s contribution of combustion turbines to Conectiv. See “Contribution of Combustion Turbines to Conectiv in 2000” in Note 9 to the Consolidated Financial Statements for additional information.

NOTE 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 the taxable income or loss, determined on a separate return basis.

Components of Consolidated Income Tax Expense

		2001			2000			1999
		(Dollars in Thousands)
Operations
Federal:	Current	$	(23,952	)	$	6,930		$	(20,940	)
	Deferred		65,568			22,509			57,713
State:	Current		(5,584	)		9,853			902
	Deferred		18,035			611			14,185
Investment tax credit adjustments(1)			(7,369	)		(3,157	)		(2,534	)
			46,698			36,746			49,326
Extraordinary Item
Federal:	Deferred		—			—			(31,585	)
State:	Deferred		—			—			(8,889	)
			—			—			(40,474	)
Total Income Tax Expense		$	46,698		$	36,746		$	8,852

(1) In 2001, $4.9 million of deferred investment tax credits were reversed and credited to tax expense due to the sale of ACE’s ownership interests in nuclear electric generating plants.

Reconciliation of Effective Income Tax Rate

The amount computed by multiplying “Income before income taxes and extraordinary item” by the federal statutory rate is reconciled below to income tax expense on operations (which excludes amounts applicable to the extraordinary item).

	2001					2000					1999
	Amount			Rate		Amount			Rate		Amount			Rate
	(Dollars in Thousands)
Statutory federal income tax expense	$	42,761		35	%	$	31,913		35	%	$	39,639		35	%
State income taxes, net of federal tax benefit		8,093		6			6,951		8			9,806		9
Plant basis differences		2,000		2			2,172		2			2,275		2
Amortization of investment tax credits		(7,369	)	(6	)		(3,157	)	(3	)		(2,534	)	(2	)
Other, net		1,213		1			(1,133	)	(2	)		140		—
Total income tax expense	$	46,698		38	%	$	36,746		40	%	$	49,326		44	%

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Components of Deferred Income Taxes

Items comprising deferred tax balances as of December 31, 2001 and December 31, 2000 are as follows:

	2001		2000
	(Dollars in Thousands)
Deferred tax liabilities:
Utility plant basis differences	$	340,113	$	308,424
Deferred recoverable income taxes		3,860		4,915
Payment for termination of purchased power contracts with non-utility electric generators		96,840		94,982
Deferred electric service expenses		47,479		—
Other		46,079		42,181
Total deferred tax liabilities		534,371		450,502
Deferred tax assets:
Deferred investment tax credits		9,968		19,324
Other		54,164		41,543
Total deferred tax assets		64,132		60,867
Total deferred taxes, net	$	470,239	$	389,635

NOTE 4.    SPECIAL CHARGES

ACE’s operating results for 1999 include special charges of $12.3 million before taxes ($7.3 million after taxes) for the costs of employee separations, additional costs related to the 1998 Merger, and certain other nonrecurring costs.

NOTE 5.    EXTRAORDINARY ITEM

As discussed in Note 6 to the Consolidated Financial Statements, on July 15, 1999, the NJBPU issued a Summary Order to ACE that, among other things, provided for customer choice of electricity suppliers, rate decreases, and quantification of the recovery through customer rates of the uneconomic portion of assets and long-term contracts that resulted from restructuring (stranded costs). As a result, ACE discontinued applying SFAS No. 71 to its electricity generation business and applied the requirements of SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71” (SFAS No. 101) and Emerging Issues Task Force (EITF) Issue No. 97-4, “Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statements No. 71 and No. 101” (EITF 97-4).

Pursuant to the requirements of SFAS No. 101 and EITF 97-4, ACE recorded extraordinary charges in the third and fourth quarters of 1999 which reduced 1999 earnings by $58.1 million, net of income taxes of $40.5 million. The portion of the extraordinary charge related to impaired assets was determined in accordance with SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets To Be Disposed Of” (SFAS No. 121). The extraordinary charge primarily resulted from impaired electric generating plants and certain other assets, uneconomic energy contracts, and other effects of deregulation requiring loss recognition. The impairment amount for electric generating plants was determined based on expected proceeds under agreements for the sale of the electric generating plants, which are discussed in Note 9 to the Consolidated Financial Statements. The extraordinary charge was decreased by the regulatory asset established for the amount of stranded costs expected to be recovered through regulated electricity delivery rates.

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The details of the 1999 extraordinary charge are shown below.

Items Included in the 1999 Extraordinary Charge	Millions of Dollars
The net book value of the nuclear power plants and certain fossil fuel-fired plants and other electric plant-related assets including inventories, were written-down due to impairment.	$	(662.1	)
Generation-related regulatory assets and certain other utility assets impaired from deregulation were written-off. Also, various liabilities resulting from deregulation were recorded.		(205.7	)
A regulatory asset, recoverable stranded costs, was established for the amount of stranded costs expected to be recovered through regulated electricity delivery rates.		769.2
Total pre-tax extraordinary charge		(98.6	)
Income tax benefit		40.5
Total extraordinary charge, net of income taxes	$	(58.1	)

NOTE 6.    REGULATORY MATTERS

Restructuring

On February 9, 1999, New Jersey enacted the Electric Discount and Energy Competition Act (the New Jersey Act). The New Jersey Act provided for restructuring of the electric utility industry in New Jersey and established that customers of New Jersey electric utilities could choose alternative electricity suppliers beginning August 1, 1999. Restructuring the New Jersey electric utility industry resulted in “stranded costs,” which include the portion of electric generating plants, other assets, and long-term contracts that became uneconomic as a result of the restructuring. Pursuant to the New Jersey Act, on July 15, 1999, the NJBPU issued a Summary Order to ACE concerning stranded costs, unbundled rates, and other matters related to restructuring. In mid-May 2001, the NJBPU issued a Final Decision and Order, which had substantially the same provisions as the Summary Order. The NJBPU determined that ACE will have the opportunity to recover 100% of the net stranded costs related to certain generation units and the stranded costs associated with power purchased from non-utility generators (NUGs), subject to further NJBPU proceedings.

Rate Decreases

The NJBPU directed ACE to implement a 5% aggregate rate reduction effective August 1, 1999 and an additional 2% rate reduction by January 1, 2001. By August 1, 2002, rates must be reduced by 10% from the rates that were in effect as of April 30, 1997. The initial 5% rate reduction effective August 1, 1999 reduced annual revenues by approximately $50 million. The additional 2%, or $20 million, rate reduction required by January 1, 2001 was implemented through two separate 1%, or $10 million, rate reductions effective January 1, 2000 and 2001, respectively. The final rate reduction, which is required by August 1, 2002, is expected to reduce revenues by an additional $30 million, which would result in a cumulative rate reduction of $100 million since August 1, 1999.

Securitization

Under the New Jersey Act, up to 100% of recovery-eligible stranded costs related to electric generating plants and the costs to effect buyouts or buydowns of NUG contracts may be recovered through customer rates. Also, the New Jersey Act permits securitization of stranded costs through the issuance of transition bonds in the amount approved by the NJBPU. More specifically, the New Jersey Act provides for securitization of: (a) up to 75% of recovery-eligible stranded costs related to electric generating plants, over a period not to exceed 15 years, and (b) 100% of the costs to effect NUG contract buyouts or buydowns, over a period not to exceed the remaining term of the restructured contracts. The principal of and interest on transition bonds is to be collected from customers through a transition bond charge over the securitization term. Also, customer rates are to include a

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separate market transition charge for recovery of the income tax expense associated with the revenues from transition bond charges. The ability to issue transition bonds depends on approval of the NJBPU and conditions in the relevant capital markets at the times of the offerings.

On June 25, 2001, ACE filed a petition with the NJBPU, seeking the authority to: (i) issue through a special purpose entity up to $2 billion in transition bonds in one or more series; (ii) collect from ACE’s customers a non-bypassable, per kilowatt-hour (kWh) delivered, transition bond charge (TBC) sufficient to fund principal and interest payments on the bonds and related expenses and fees; (iii) collect from ACE’s customers a separate non-bypassable, per kWh delivered, charge for recovery of the income tax expense associated with the revenues from the TBC; and (iv) sell “bondable transition property,” which is the irrevocable right to collect TBC, to a special purpose financing entity.

The transition bonds are expected to be issued after the NJBPU issues a bondable stranded costs rate order (Financing Order) establishing “bondable transition property,” as provided for in the New Jersey Act. To facilitate the issuance of transition bonds, ACE formed Atlantic City Electric Transition Funding LLC (ACE Transition Funding) during 2001. Assuming that the NJBPU issues a Financing Order containing terms and conditions satisfactory to ACE, subsequent to issuance of such order, ACE Transition Funding is expected to issue transition bonds and use the proceeds to purchase the bondable transition property from ACE. When issued, the transition bonds of ACE Transition Funding will be included in ACE’s Consolidated Balance Sheet. The New Jersey Act requires utilities, including ACE, to use the proceeds from the sale of bondable transition property to redeem debt or equity or both, restructure NUG purchased power contracts, or otherwise reduce costs in order to decrease regulated electricity rates.

On September 17, 2001, the NJBPU issued a Decision and Order concerning the stranded costs associated with ACE’s former ownership interests in nuclear electric generating plants. The NJBPU determined the amount of such stranded costs eligible for recovery by ACE to be approximately $298 million, after income taxes, (or $504 million before income taxes) as of December 31, 1999, subject to further adjustments. The NJBPU also found that ACE shall have the opportunity to recover the eligible stranded costs through its market transition charge, in a time frame and manner to be determined by the NJBPU.

See Note 7 to the Consolidated Financial Statements concerning the eligibility for securitization of a $228.5 million payment made by ACE to terminate a NUG purchased power contract. Management anticipates that transition bonds will ultimately be used to finance the stranded costs associated with the buyout or buydown of ACE’s NUG contracts.

On February 20, 2002, the NJBPU issued a Decision and Order approving the sale of ACE’s fossil fuel-fired electric generating plants and determined the amount eligible for recovery by ACE of stranded costs associated with such plants to be approximately $101 million, after income taxes, (or $171 million before income taxes) as of December 31, 1999, subject to further adjustment. See Note 9 to the Consolidated Financial Statements for additional information.

Basic Generation Service

Through July 31, 2002, ACE is obligated to provide Basic Generation Service (BGS); this service entails supplying electricity to customers in ACE’s service area who do not choose an alternative supplier. The Final Decision and Order provides for the recovery through customer rates of the costs incurred by ACE in providing BGS, including an allowed return on certain electric generating plants, the above-market portion of the cost of power purchased from NUGs, and the above-market portion of costs associated with generating power for BGS customers. In recognition of this cost-based, rate-recovery mechanism, when the costs incurred by ACE in providing BGS exceed the revenues from billings to ACE’s customers for BGS, the under-recovered costs are deferred as a regulatory asset. ACE deferred costs related to providing BGS in the amounts of $143.2 million for 2001, $7.5 million for 2000 and $17.2 million for 1999. Pursuant to the terms of the 1999 restructuring of ACE’s

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electric generation business, during 1999-2001, the under-recovered costs were first applied to a deferred energy cost liability which was eliminated and then a regulatory asset was established ($106.3 million as of December 31, 2001). After the initial four-year transition period ends July 31, 2003, customer rates are to be adjusted to recover the under-recovered cost balance over a reasonable period of time to be determined by the NJBPU. ACE’s recovery of the deferred costs is subject to review by the NJBPU.

On June 29, 2001, New Jersey electric utilities, including ACE, filed a proposal with the NJBPU to use an auction process to procure electricity supply for BGS customers. ACE and the other New Jersey electric utilities proposed that the BGS supply period for which the auction be conducted be the final year of the transition period (August 1, 2002-July 31, 2003) provided for in the New Jersey Act. Under this supply arrangement, ACE, as agent for its BGS customers, will pay for electricity from the suppliers selected by the auction process and the costs associated with this supply will be subject to the regulated cost-based, rate-recovery mechanism for BGS. ACE will continue to collect BGS revenues and will continue to provide all customer-related services. On February 15, 2002, the NJBPU approved the results of the auction that was held from February 4, to February 13, 2002. As result of the auction, four suppliers will provide electricity for 1,900 MW, or about 80% of ACE’s load, at a price of 5.12 cents per kWh beginning on August 1, 2002. The remaining 20% of ACE’s load will continue to be supplied with power purchased under ACE’s existing purchased power contracts with NUGs. If there is a default by a supplier determined by the auction process, then the defaulted load will be offered to other winning bidders of the auction process, or if that is not possible, then ACE would purchase the electricity supply from the PJM Interconnection L.L.C.

NOTE 7.    TERMINATION OF PURCHASED POWER CONTRACT

On November 10, 1999, the NJBPU issued a Decision and Order approving termination of a contract under which ACE had purchased energy and capacity from Pedricktown, a NUG partnership which was owned 50% by other Conectiv subsidiaries prior to June 29, 2001. The NJBPU decided that ACE is entitled to recover from customers the contract termination payment of $228.5 million, transaction costs, and interim financing costs. The NJBPU also found that the contract termination payment and related transaction costs are eligible for long-term financing through the issuance of transition bonds. On December 28, 1999, ACE paid $228.5 million to terminate the contract. The contract termination payment and related costs are included in “Recoverable Stranded Costs” on the Consolidated Balance Sheets. Effective January 1, 2000, ACE’s customer rates were reduced by about 1% (approximately $10 million of revenues on an annualized basis) as a result of the net savings from the contract termination.

NOTE 8.    JOINTLY-OWNED PLANT

ACE’s Consolidated Balance Sheets include its proportionate share of assets and liabilities related to jointly owned plant. ACE has ownership interests in electric generating plants, transmission facilities, and other facilities in which various parties have ownership interests. ACE’s proportionate shares of operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in ACE’s Consolidated Statements of Income. ACE is responsible for providing its share of financing for the jointly owned facilities.

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Information with respect to ACE’s share of jointly owned plant as of December 31, 2001 is shown below. As discussed in Note 9 to the Consolidated Financial Statements, the jointly-owned coal-fired Keystone and Conemaugh plants were under agreement for sale as of December 31, 2001.

	Ownership Share	Megawatt Capability Owned	Plant in Service		Accumulated Depreciation		Construction Work in Progress
			(Dollars in Thousands)
Keystone*	2.47%	42	$	13,758	$	4,694	$	1,661
Conemaugh*	3.83%	65		34,777		10,993		1,938
Transmission Facilities	Various	—		24,881		11,802		—
Other Facilities	Various	—		1,113		217		—
Total		107	$	74,529	$	27,706	$	3,599

* Coal-fired electric generating plant.

NOTE 9.    DIVESTITURE OF ELECTRIC GENERATING PLANTS

ACE continued the divestiture of its electric generating plants during 2001. The divestiture began effective July 1, 2000 with ACE’s contribution to Conectiv at net book value of its combustion turbines (502 MW). On October 18, 2001, ACE sold its ownership interests in nuclear electric generating plants (383 MW). As of December 31, 2001, all of ACE’s remaining electric generating plants, which had a carrying value of $117 million and 739.7 MW of capacity, were subject to an agreement for sale.

After the sales of ACE’s electric generating plants are completed, the principal remaining business of ACE will be the transmission and distribution of electricity. ACE will purchase power to supply electricity to customers who do not choose alternative electricity suppliers. ACE’s exit from the electricity production business is expected to cause a decrease in ACE’s earnings capacity.

Sales of Electric Generating Plants Completed in 2001

On October 18, 2001, ACE sold for $29.6 million its 7.51% (164 MW) interest in Peach Bottom Atomic Power Station (Peach Bottom), 7.41% interest (167 MW) in Salem Nuclear Generating Station (Salem) and 5.0% interest (52 MW) in Hope Creek Nuclear Generating Station (Hope Creek) and the related nuclear fuel to the utilities which operate the plants. ACE’s trust funds and obligation for decommissioning the plants were transferred to the purchasers in conjunction with the sale. The net assets sold had a carrying value of $27.3 million, which reflects a write-down in 1999 related to discontinuing SFAS No. 71. ACE used $20.5 million of the proceeds to repay the lease obligations related to the nuclear fuel. There was a $2.4 million pre-tax gain on the sale, which did not affect earnings due to the terms of the 1999 restructuring of the electricity generation business of ACE; instead, the pre-tax gain on the sale decreased the balance of deferred recoverable stranded costs.

Contribution of Combustion Turbines to Conectiv in 2000

Effective July 1, 2000, ACE contributed at book value its combustion turbines (502 megawatts of capacity) and related transmission equipment, inventories, and liabilities to a wholly-owned subsidiary (Conectiv Atlantic Generation, LLC, or CAG). ACE then contributed CAG to Conectiv in conjunction with the formation of an energy-holding company by Conectiv, which is engaged in non-regulated electricity production and sales, and energy trading and marketing. The primary effects on ACE’s balance sheet of the contribution to Conectiv were as follows: (a) property, plant and equipment decreased $86 million (primarily electric generating plants); (b) fuel and other inventories decreased $6 million; (c) deferred income taxes and investment tax credits decreased $9 million; and (d) the additional paid-in capital portion of common stockholder’s equity decreased $83 million.

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Electric Generating Plants Subject to Agreements for Sale as of December 31, 2001

As of December 31, 2001, ACE’s fossil fuel-fired electric generating plants (Deepwater Station, Conemaugh and Keystone Stations and B.L. England Station) were under agreements for sale to NRG Energy, Inc. (NRG) for approximately $178 million (before certain adjustments and expenses). The plants to be sold have electric generating capacity of 739.7 MW, and as of December 31, 2001, the carrying value of the plants was approximately $117 million. Due to the terms of ACE’s electric utility restructuring in 1999 and expected sales proceeds, (i) the loss expected to be realized on the sale of the Deepwater Station was included in the extraordinary charge to earnings in 1999, (ii) the loss expected to be realized on the sale of the B.L. England Station is included in recoverable stranded costs, and (iii) any net gain that may be realized on the sale of ACE’s interests in Conemaugh and Keystone Stations is expected to reduce the amount of stranded costs to be recovered from ACE’s utility customers.

On February 20, 2002, the NJBPU issued a Decision and Order approving the sale of ACE’s fossil fuel-fired electric generating plants and determined the amount eligible for recovery by ACE of stranded costs associated with such plants to be approximately $101 million, after income taxes, (or $171 million before income taxes) as of December 31, 1999, subject to further adjustment. The agreements between ACE and NRG for the sale of the fossil fuel-fired electric generating plants remain in effect, but, after February 28, 2002, are subject to termination by either party, by giving notice. Neither party has terminated the agreements. The appeal period for the Decision and Order that was issued by the NJBPU to approve the plant sales expires in early-April 2002. ACE cannot predict whether or not any or all of the plants will be sold, but ACE is endeavoring to close the sales on mutually-acceptable terms and timetable.

Wholesale Transaction Confirmation Letter Agreements

On October 3, 2000, ACE entered into Wholesale Transaction Confirmation letter agreements (Letter Agreements). The Letter Agreements provided for the sale of the electricity output and capacity associated with the former ownership interests of ACE in Peach Bottom, Salem, and Hope Creek. Under the Letter Agreements, the operators of the nuclear plants purchased the electricity output and capacity from ACE during the period from October 7, 2000 through October 18, 2001 (the date ACE sold its interests in the plants). In exchange for the electricity output and capacity purchased from a given plant, the plant operators reimbursed ACE for the nuclear fuel burned and paid ACE’s share of operation and maintenance costs, inventories, and capital expenditures.

NOTE 10.    REGULATORY ASSETS AND LIABILITIES

The electric delivery and BGS businesses of ACE are subject to the requirements of SFAS No. 71. ACE recovers through customer rates the costs it incurs in providing BGS, which entails supplying electricity to customers in ACE’s service area who do not choose an alternative supplier. When utility revenues are insufficient to recover current period expenses from customers, the NJBPU may provide for future recovery from customers of such current period expenses. When future recovery is probable for current under-recoveries of utility expenses, 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 the NJBPU.

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The table below displays the regulatory assets and liabilities as of December 31, 2001 and 2000.

	December 31, 2001		December 31, 2000
	(Millions of Dollars)
Regulatory Assets
Deferred Charges and Other Assets
Recoverable stranded costs	$	930.0	$	958.9
Deferred electric service costs		106.3		—
Other non-current regulatory assets
Deferred recoverable income taxes		11.0		14.0
Deferred debt extinguishment costs		11.4		12.4
Unrecovered New Jersey state excise taxes		—		10.4
Deferred other postretirement benefit costs		27.5		30.0
Unrecovered purchased power costs		12.5		14.5
Deferred NUG buyout costs		8.7		4.1
Deferred costs for nuclear decommissioning/decontamination		—		5.1
Asbestos removal costs		7.7		8.0
Other		4.2		2.8
		83.0		101.3
Total regulatory assets	$	1,119.3	$	1,060.2
Regulatory Liabilities
Deferred energy supply costs	$	—	$	34.7
Regulatory liability for New Jersey income tax benefit		49.3		49.3
Total regulatory liabilities	$	49.3	$	84.0

Recoverable Stranded Costs:    The pre-tax balances of $930.0 million as of December 31, 2001 and $958.9 million as of December 31, 2000 arose from the $228.5 million NUG contract termination payment in December 1999, as discussed in Note 7 to the Consolidated Financial Statements, and discontinuing the application of SFAS No. 71 to the electricity generation business in third quarter of 1999, as discussed in Notes 1, 5, and 6 to the Consolidated Financial Statements. The regulatory asset, “Recoverable stranded costs,” was established in the third quarter of 1999 to recognize amounts to be collected from regulated delivery customers for stranded costs that resulted from deregulation of the electricity generation business. As discussed in Note 9 to the Consolidated Financial Statements, any gain realized on the sale of the fossil fuel-fired electric generating plants of ACE that are subject to agreements for sale is expected to reduce the amount of recoverable stranded costs.

Deferred Electric Service Costs:    See “Basic Generation Service” in Note 6 the Consolidated Financial Statements.

Deferred Recoverable Income Taxes:    Represents the portion of deferred income tax liabilities applicable to ACE’s utility operations that has not been reflected in current customer rates for which future recovery is probable. As temporary differences between the financial statement and tax bases of assets reverse, deferred recoverable income taxes are amortized.

Deferred Debt Extinguishment Costs:     Debt extinguishment costs for which recovery through regulated utility rates is probable are deferred and subsequently amortized to interest expense during the rate recovery period.

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Unrecovered New Jersey State Excise Taxes:    Represented additional amounts paid by ACE as a result of prior legislative changes in the computation of New Jersey state excise taxes.

Deferred Other Postretirement Benefit Costs:    Represents the non-cash portion of other postretirement benefit costs deferred by ACE during 1993 through 1997. This cost is being recovered over a 15-year period which began on January 1, 1998.

Unrecovered Purchased Power Costs:    Includes costs incurred by ACE for renegotiation of a long-term capacity and energy contract. These costs are included in current customer rates with the balance scheduled for full recovery over the next 6 years.

Deferred NUG Buyout Costs:    Includes certain NUG buyout costs and a NUG restructuring payment which are probable of recovery from customers based on the terms of the 1999 restructuring of ACE’s electric generation business.

Deferred Costs for Nuclear Decommissioning/Decontamination:    Prior to the sale of ACE’s interests in nuclear electric generating plants, this regulatory asset represented amounts recoverable from ACE’s customers for amounts that ACE had owed to the U.S. government pursuant to the Energy Policy Act of 1992; this obligation was assumed by the purchasers of ACE’s interests in nuclear electric generating plants.

Asbestos Removal Costs:    Represents costs incurred by ACE to remove asbestos insulation from a wholly-owned electric generating station. These costs are included in current customer rates with the balance scheduled for full recovery over the next 28 years.

Deferred Energy Supply Costs:    At the time of ACE’s electric utility restructuring in the third quarter of 1999, ACE had a regulatory liability because energy supply costs had been over-recovered from customers, under an energy adjustment clause. In accordance with terms of the restructuring, as ACE under-recovered costs related to providing BGS, the under-recovery was first applied to the deferred energy cost supply liability, which was eliminated, and then the regulatory asset, “deferred electric service costs” was established.

Regulatory Liability for New Jersey Income Tax Benefit:    In 1999, a deferred tax asset arising from the write down of ACE’s electric generating plants was established. The deferred tax asset represents the future tax benefit expected to be realized when the higher tax basis of the generating plants is deducted for New Jersey state income tax purposes. To recognize that this tax benefit probably will be given to ACE’s regulated electricity delivery customers through lower electric rates, ACE established a regulatory liability.

NOTE 11.    COMMON STOCKHOLDER’S EQUITY

Conectiv owns all 18,320,937 outstanding shares of ACE’s common stock ($3 per share par value).

For information concerning changes in ACE’s common stockholder’s equity, see the Statement of Changes in Common Stockholder’s Equity.

ACE’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.

As a subsidiary of a registered holding company under PUHCA, ACE can pay dividends only to the extent of its retained earnings unless SEC approval is obtained.

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NOTE 12.    PREFERRED STOCK

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 Not Subject to Mandatory Redemption

Series	2001			2000			Current Redemption Price
	Shares	(000)		Shares	(000)
4%, $100 par value	24,268	$	2,427	24,268	$	2,427	$	105.50
4.1%, $100 par value	20,504		2,051	20,504		2,051		101.00
4.35%, $100 par value	3,102		310	3,102		310		101.00
4.35%, $100 par value	1,680		168	1,680		168		101.00
4.75%, $100 par value	8,631		863	8,631		863		101.00
5%, $100 par value	4,120		412	4,120		412		100.00
Total	62,305	$	6,231	62,305	$	6,231

Preferred Stock Subject to Mandatory Redemption

As of December 31, 2001, ACE had 124,500 shares outstanding of $7.80 annual dividend rate preferred stock, $100 per share stated value, or $12.45 million. As of December 31, 2000, ACE had 239,500 shares outstanding of $7.80 annual dividend rate preferred stock, $100 per share stated value, or $23.95 million.

On May 1, 2001 ACE redeemed 115,000 shares of its $7.80 annual dividend rate preferred stock at the $100 per share stated value or $11.5 million in total. Effective May 1, 2001, 115,000 shares of the $7.80 annual dividend rate preferred stock became subject to mandatory redemption annually.

NOTE 13. COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY COMPANY DEBENTURES

Issuer	Series	Securities Outstanding		Amount
		2001	2000	2001		2000
				(Dollars in Thousands)
Atlantic Capital I *	$25 per share, 8.25%	2,800,000	2,800,000	$	70,000	$	70,000
Atlantic Capital II *	$25 per share, 7.375%	1,000,000	1,000,000		25,000		25,000
				$	95,000	$	95,000

* Per share value is stated liquidation value.

The outstanding preferred securities issued by ACE’s wholly owned financing subsidiary trusts, Atlantic Capital I and Atlantic Capital II, are shown in the above table. The financing subsidiary trusts have common and preferred trust securities outstanding and hold Junior Subordinated Debentures (the Debentures) of ACE. ACE owns all of the common securities of the trusts, which constitute approximately 3% of the liquidation amount of all of the trust securities issued by the trusts. The trusts use interest payments received on the Debentures, which are the trusts’ only assets, to make cash distributions on the trust securities. The obligations of ACE pursuant to the Debentures and guarantees of distributions with respect to the trusts’ securities, to the extent the trusts have funds available therefor, constitute full and unconditional guarantees of the obligations of the trusts under the trust securities the trusts have issued.

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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 held by Atlantic Capital I mature in 2026 and the Debentures held by Atlantic Capital II mature in 2028. The 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.

NOTE 14.    DEBT

Maturities of long-term debt during the next five years are as follows: 2002—$221.5 million; 2003—$70.1 million; 2004—$67.1 million; 2005—$40.1 million; and, 2006—$66.8 million.

As of December 30, 2001, ACE had $45.0 million of 2.5% short-term debt outstanding, which was entirely commercial paper.

On May 15, 2001 and August 1, 2001, ACE redeemed at maturity $10 million of 7.0%, Medium Term Notes and $30 million of 6.81% Medium Term Notes, respectively.

ACE borrowed $228.5 million through a bank term loan on December 28, 1999 to finance a cash payment for termination of a NUG purchased power contract with Pedricktown, as discussed in Note 7 to the Consolidated Financial Statements. On December 20, 2001, ACE repaid $57.125 million of the term loan balance; the remaining $171.375 million balance is due December 20, 2002.

ACE’s term loan contains financial and other covenants which, if not met, could result in the acceleration of repayment obligations under the agreement or restrict ACE’s ability to borrow under this agreement. The term loan requires a ratio of total indebtedness to total capitalization of 65% or less. As of December 31, 2001, the ratio was 56%, computed in accordance with the terms of the agreement. The term loan also contains a number of events of default that could be triggered by the acceleration of indebtedness under certain other borrowing arrangements, bankruptcy actions or judgments or decrees against ACE, as well as by a change of control of ACE, such as the Conectiv/Pepco Merger. ACE plans to request a waiver of its term loan change of control provisions so the term loan will continue after the Conectiv/Pepco Merger. ACE plans to repay this debt with proceeds from the expected issuance of transition bonds, which are discussed in Note 6 to the Consolidated Financial Statements.

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. ACE’s mortgage requires that electric generating plants sold (as discussed in Note 9 to the Consolidated Financial Statements) be released from the lien. Assets may be released with a combination of cash, bondable property additions, and credits representing previously issued and retired First Mortgage Bonds. Pursuant to these terms, ACE’s interests in nuclear electric generating plants that were sold on October 18, 2001 were released from the lien. ACE expects to have sufficient credits from retired First Mortgage Bonds to release its fossil fuel-fired plants that are expected to be sold during 2002, as discussed in Note 9 to the Consolidated Financial Statements.

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Long-term debt outstanding as of December 31, 2001 and 2000 is presented below.

Type of Debt	Maturity Date	December 31,
		2001			2000
		(Dollars in Thousands)
Secured debt
Medium Term Notes Series C (6.86%)	2001	$	—		$	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			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			65,000
6-3/8% Pollution Control Series	2006		2,125			2,200
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
6-5/8% First Mortgage Bonds	2013		68,600			68,600
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	2021		38,865			38,865
7% First Mortgage Bonds	2023		62,500			62,500
5.60% Pollution Control Series A	2025		4,000			4,000
7% First Mortgage Bonds	2028		75,000			75,000
6.15% Pollution Control Series A	2029		23,150			23,150
7.20% Pollution Control Series A	2029		25,000			25,000
7% Pollution Control Series B	2029		6,500			6,500
			623,740			663,815
Unsecured debt
6.46% Medium Term Notes Series A	2002		20,000			20,000
6.63% Medium Term Notes Series A	2003		30,000			30,000
7.52% Medium Term Notes Series A	2007		5,000			5,000
7.50% Medium Term Notes Series A	2007		10,000			10,000
			65,000			65,000
Term Loan
7.32% Term Loan	2001		—			57,125
2.95% Term Loan	2002		171,375			171,375
Unamortized Premium and Discount, Net			(2,362	)		(2,462	)
Current Maturities of Long-Term Debt			(221,450	)		(97,200	)
Total Long Term Debt			636,303			857,653
Variable Rate Demand Bonds, Pollution Control Series A*	2014		18,200			18,200
Variable Rate Demand Bonds, Pollution Control Series B*	2017		4,400			4,400
Total Long Term Debt and Variable Rate Demand Bonds		$	658,903		$	880,253

* 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 2.4% for 2001 and 3.9% for 2000.

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NOTE 15.    FAIR VALUE OF FINANCIAL INSTRUMENTS

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.

	2001				2000
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(Dollars in Thousands)
Investments	$	3,666	$	3,666	$	112,501	$	112,501
Long Term Debt		636,303		642,304		857,653		850,753
Preferred Stock Subject to Mandatory Redemption		12,450		12,948		23,950		24,369
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Company Debentures		95,000		95,840		95,000		92,914

NOTE 16.    LONG-TERM PURCHASED POWER CONTRACTS

As of December 31, 2001, ACE’s commitments under long-term purchased power contracts provided ACE 1,800 MW of capacity and varying amounts of firm electricity per hour during each month of a given year. Commitments for purchased capacity under contracts existing as of December 31, 2001 will decrease by approximately 1,300 MW in 2002, primarily due to the anticipated replacement of the capacity supplied by these contracts with the capacity and energy to be provided by the BGS suppliers that were selected by the auction process discussed in Note 6 to the Consolidated Financial Statements. Based on existing contracts as of December 31, 2001, the commitments of ACE during the next five years for capacity and energy under long-term purchased power contracts are estimated to be as follows: $297 million in 2002, $214 million in 2003; $206 million in 2004; $234 million in 2005; and $231 million in 2006. As of December 31, 2001, provisions of certain contracts under which ACE procures electricity for BGS would require ACE to provide cash collateral of $42.1 million, if ACE’s credit ratings were downgraded below investment grade. The cash collateral required in the event of a credit rating downgrade fluctuates based on energy market conditions.

NOTE 17.    LEASES

Nuclear Fuel

As discussed in Note 9 to the Consolidated Financial Statements, ACE sold its ownership interests in nuclear electric generating plants and the related nuclear fuel on October 18, 2001. Prior to the sale, ACE leased its share of nuclear fuel at the nuclear electric generating plants. The obligation of ACE under the contracts was repaid upon the sale of the interest in the nuclear electric generating plants on October 18, 2001 with proceeds from the sale.

Leased nuclear fuel costs included in operating expenses were $10.4 million for 2001, $14.2 million for 2000 and $14.8 million for 1999.

Lease Commitments

ACE also leases other types of property and equipment for use in its operations. Amounts charged to operating expenses for these leases were $8.2 million in 2001, $10.1 million in 2000, and $7.6 million in 1999. Future minimum rental payments for all non-cancelable lease agreements are less than $10 million per year for each of the next five years.

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NOTE 18.    PENSION AND OTHER POSTRETIREMENT BENEFITS

The employees of ACE and other Conectiv subsidiaries are provided pension benefits and other postretirement benefits under Conectiv benefit plans. The amounts shown below are for the benefit plans of Conectiv and include amounts for all covered employees of the Conectiv subsidiaries which elect to participate in the benefit plans.

Assumptions

	2001	2000	1999
Discount rates used to determine projected benefit obligation as of December 31	7.25%	7.50%	7.75%
Expected long-term rates of return on assets	9.50%	9.50%	9.00%
Rates of increase in compensation levels	4.50%	4.50%	4.50%
Health-care cost trend rate on covered charges	10.00%	8.00%	6.50%

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 2007. Increasing the health-care cost trend rates of future years by one percentage point would increase the accumulated postretirement benefit obligation by $10.3 million and would increase annual aggregate service and interest costs by $0.8 million. Decreasing the health-care cost trend rates of future years by one percentage point would decrease the accumulated postretirement benefit obligation by $10.3 million and would decrease annual aggregate service and interest costs by $0.9 million.

The following schedules reconcile the beginning and ending balances of the pension and other postretirement benefit obligations and related plan assets for Conectiv. Other postretirement benefits include medical benefits for retirees and their spouses and retiree life insurance.

Change in Conectiv’s Benefit Obligation

	Pension Benefits						Other Postretirement Benefits
	2001			2000			2001			2000
	(Dollars in Thousands)
Benefit obligation at beginning of year	$	694,621		$	673,095		$	201,493		$	194,031
Service cost		20,338			18,388			4,381			3,908
Interest cost		53,154			51,856			17,121			14,513
Plan participants’ contributions		—			—			543			511
Plan amendments		3,775			4,359			—			—
Actuarial loss		38,102			12,689			57,346			5,500
Benefits paid		(55,023	)		(66,438	)		(17,047	)		(16,970	)
Other		—			672			—			—
Benefit obligation at end of year	$	754,967		$	694,621		$	263,837		$	201,493

Change in Conectiv’s Plan Assets

	Pension Benefits						Other Postretirement Benefits
	2001			2000			2001			2000
	(Dollars in Thousands)
Fair value of assets at beginning of year	$	948,043		$	1,017,844		$	119,724		$	120,072
Actual return on plan assets		(31,628	)		(3,363	)		(2,356	)		166
Employer contributions		—			—			16,196			15,945
Plan participants’ contributions		—			—			543			511
Benefits paid		(55,023	)		(66,438	)		(17,047	)		(16,970	)
Fair value of assets at end of year	$	861,392		$	948,043		$	117,060		$	119,724

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Reconciliation of Funded Status of Conectiv’s Plans

	Pension Benefits						Other Postretirement Benefits
	2001			2000			2001			2000
	(Dollars in Thousands)
Funded status at end of year	$	106,425		$	253,422		$	(146,777	)	$	(81,769	)
Unrecognized net actuarial (gain) loss		(24,781	)		(181,008	)		22,438			(46,246	)
Unrecognized prior service cost		17,727			7,794			99			149
Unrecognized net transition (asset) obligation		(7,480	)		(10,245	)		34,404			37,531
Net amount recognized at end of year	$	91,891		$	69,963		$	(89,836	)	$	(90,335	)
Portion applicable to ACE	$	(35,529	)	$	(26,948	)	$	(36,429	)	$	(37,614	)

Based on fair values as of December 31, 2001, the pension plan assets were comprised of publicly traded equity securities ($559.9 million or 65%) and fixed income obligations ($301.5 million or 35%). Based on fair values as of December 31, 2001, the other postretirement benefit plan assets included equity securities ($77.7 million or 66%) and fixed income obligations ($39.4 million or 34%).

Components of Conectiv’s Net Periodic Benefit Cost

	Pension Benefits									Other Postretirement Benefits
	2001			2000			1999			2001			2000			1999
	(Dollars in Thousands)
Service cost	$	20,338		$	18,388		$	20,288		$	4,381		$	3,908		$	5,282
Interest cost		53,154			51,856			51,442			17,121			14,513			13,839
Expected return on assets		(88,346	)		(90,037	)		(83,999	)		(8,981	)		(8,645	)		(6,769	)
Amortization of:
Transition obligation (asset)		(2,764	)		(2,764	)		(2,764	)		3,128			3,128			3,128
Prior service cost		1,189			694			406			49			49			49
Actuarial (gain)		(5,499	)		(13,767	)		(4,248	)		—			(3,060	)		(1,059	)
Total net periodic benefit cost	$	(21,928	)	$	(35,630	)	$	(18,875	)	$	15,698		$	9,893		$	14,470
Portion of net periodic benefit cost applicable to ACE	$	8,580		$	6,154		$	9,546		$	6,641		$	4,607		$	8,856
ACE portion of net periodic benefit cost included in results of operations	$	8,580		$	6,154		$	9,546		$	6,641		$	4,607		$	8,856

Conectiv also maintains 401(k) savings plans for covered employees. Conectiv contributes Conectiv common stock to the plan, at varying levels up to $0.50 of common stock for each dollar of up to 6% of pay contributed by the employee. The amount expensed for ACE’s share of the 401(k) savings plan was $1.0 million in 2001, $1.0 million in 2000, and $1.6 million in 1999.

NOTE 19.    COMMITMENTS AND CONTINGENCIES

Commitments

ACE’s capital expenditures for 2002 are estimated to be approximately $84 million.

See Note 16 to the Consolidated Financial Statements for commitments related to long-term purchased power contracts and Note 17 to the Consolidated Financial Statements for commitments related to leases.

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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 (NJDEP). ACE is also a defendant in an action to recover costs at a federal superfund site in Gloucester County, New Jersey. ACE’s liability for clean-up costs is affected by the activities of these governmental agencies and private land-owners, the nature of past disposal practices, the activities of others (including whether they are able to contribute to clean-up costs), and the scientific and other complexities involved in resolving clean-up related issues (including whether ACE or a corporate predecessor is responsible for conditions on a particular parcel). There is $3.2 million included in ACE’s current liabilities as of December 31, 2001 ($1.0 million as of December 31, 2000) 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.

On July 11, 2001, the NJDEP denied ACE’s request to renew a permit variance, effective through July 30, 2001, that authorized Unit 1 at the B.L. England station to burn coal containing greater than 1% sulfur. ACE has appealed the denial. The NJDEP has issued a stay of the denial to authorize ACE to operate Unit 1 with the current fuel until June 30, 2002 and an addendum to the permit/certificate to operate authorizing a trial burn of coal with a sulfur content less than 2.6%. Management is not able to predict the outcome of ACE’s appeal.

Other

On October 24, 2000, the City of Vineland, New Jersey, filed an action in a New Jersey Superior Court to acquire ACE electric distribution facilities located within the City limits by eminent domain. The carrying value of the electric distribution facilities was approximately $9.1 million, as of December 31, 2001. The City’s Superior Court action has been dismissed, based on the failure to hold a referendum, and the City has appealed this decision. On November 6, 2001, the City held a referendum and City residents voted to approve the City’s proposal to acquire ACE electric distribution facilities located within the City limits. On March 8, 2002, ACE and the City announced that they had reached a tentative agreement which provides for ACE to receive $23.9 million for the electric distribution facilities located within the City limits. After a transition period of 18 to 24 months primarily to reconfigure facilities, the transaction would close and the City would provide electric service to the City’s residents previously served by ACE.

On November 26, 2001, the FERC published a notice establishing a generic refund effective date of January 26, 2002 relative to collections by all utilities pursuant to their market-based rates (MBR). ACE cannot determine with certainty whether the intent of FERC is to make all MBR collections subject to refund as of January 26, 2002. There has been no allegation that ACE has misused its MBR authority, and any possible refund liability would not affect 2001 revenues.

NOTE 20.    BUSINESS SEGMENTS

Conectiv’s organizational structure and management reporting information is aligned with Conectiv’s business segments, irrespective of the subsidiary, or subsidiaries, through which a business is conducted. Businesses are managed based on lines of business, not 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. However, ACE’s principal business is expected to be the transmission and distribution of electricity upon completion of the divestiture of the electric generating plants of ACE (as discussed in Note 9 to the Consolidated Financial Statements).

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NOTE 21.    QUARTERLY FINANCIAL INFORMATION (unaudited)

The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations, differences between summer and winter rates, and the scheduled downtime and maintenance of electric generating units.

	2001
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(Dollars in Thousands)
Operating Revenues	$	225,771	$	247,323	$	337,827	$	230,250	$	1,041,171
Operating Income		32,402		54,208		62,299		30,832		179,741
Net Income		9,276		23,353		27,707		15,140		75,476
Earnings Applicable to Common Stock		8,743		22,820		27,399		14,831		73,793

	2000
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(Dollars in Thousands)
Operating Revenues	$	215,151	$	221,366	$	287,092	$	237,253	$	960,862
Operating Income		22,680		36,411		66,123		41,310		166,524
Net Income		1,573		14,113		28,155		10,593		54,434
Earnings Applicable to Common Stock		1,040		13,581		27,621		10,060		52,302

As discussed in Note 1 to the Consolidated Financial Statements, under-recoveries of costs related to BGS have been reclassified within the Consolidated Statements of Income from electric operating revenues to operating expenses, as a separate line item captioned “Deferred electric service costs.” A reconciliation of quarterly revenues previously reported to restated quarterly revenues is shown below.

	2001
	First Quarter			Second Quarter			Third Quarter
	(Dollars in Thousands)
Operating revenues as reported in 2001 quarterly reports on Form 10-Q	$	230,538		$	300,877		$	404,876
Adjustment for deferred electric service costs		(4,767	)		(53,554	)		(67,049	)
Restated operating revenues	$	225,771		$	247,323		$	337,827

	2000
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter			Total
	(Dollars in Thousands)
Operating revenues as reported in 2000 quarterly reports on Form 10-Q and the 2000 Form 10-K	$	208,886	$	236,249		$	282,966	$	240,282		$	968,383
Adjustment for deferred electric service costs		6,265		(14,883	)		4,126		(3,029	)		(7,521	)
Restated operating revenues	$	215,151	$	221,366		$	287,092	$	237,253		$	960,862

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

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PART III

ITEM 10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors	Business Experience during Past 5 Years
As of December 31, 2001
Howard E. Cosgrove, 58 Chairmanof the Board	Elected 1998 as Chairman of the Board and Chief Executive Officer of Conectiv and Chairman of the Board of ACE. Chairman, President and Chief Executive Officer of Delmarva Power & Light Company since 1992. Director of the Federal Reserve Board. Chairman of the Board of Trustees of the University of Delaware.
Thomas S. Shaw, 54 Director	Elected 2000 as President and Chief Operating Officer of Conectiv. Elected 1998 as Executive Vice President of Conectiv. Elected 1992 as Senior Vice President of Delmarva Power & Light Company.
John C. van Roden, 52 Director	Elected 2000 as Senior Vice President and Chief Financial Officer of Conectiv and Chief Financial Officer of ACE. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv. Principal, Cook and Belier, Inc. in 1998. Senior Vice President/Chief Financial Officer and Vice President/Treasurer, Lukens, Inc. from 1987 to 1998.
Barbara S. Graham, 53 Director	Elected 1999 as Senior Vice President of Conectiv. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv. Elected 1994 as Senior Vice President, Treasurer and Chief Financial Officer of Delmarva Power & Light Company.

Executives

Information about ACE’s executive officers is included under Item 1.

ITEM 11.     EXECUTIVE COMPENSATION

The following table shows information regarding the compensation earned during the past year by the ACE President and by ACE’s other four most highly compensated executive officers for the fiscal year ending December 31, 2001.

Table 1—SUMMARY COMPENSATION TABLE

	Year (1)						Long Term Compensation				All Other Compensation (6)
		Annual Compensation					Awards			Payouts
Name and Principal Position		Salary (2)		Variable Compensation (Bonus) (3)		Other Annual Compensation	Restricted Stock Awards (4)		Securities Underlying Options	LTIP Payouts (5)
J. M. Rigby, President	2001 2000	$ $	239,600 182,800	$ $	428,567 70,240	0 0	$ $	21,950 12,500	32,000 28,500	—     —	$ $	22,285 4,884
J. C. van Roden, Senior Vice President	2001 2000	$ $	294,700 275,000	$ $	90,535 85,400	0 0	$ $	106,725 90,625	39,300 34,700	—   —	$ $	23,569 8,406
J. C. Weller, Vice President	2001 2000	$ $	171,500 158,794	$ $	33,501 34,500	0 0	$ $	43,125 41,000	13,100 11,100	—   —	$ $	3,923 4,429
J. M. Castaldi, Vice President	2001 2000	$ $	130,900 126,000	$ $	30,192 28,880	0 0	$ $	9,025 0	7,500 6,800	—   —	$ $	3,856 4,580
J. M. Wathen, Director	2001 2000	$ $	125,300 120,000	$ $	17,180 16,800	0 0	$ $	21,000 20,571	7,200 6,500	—   —	$ $	3,874 4,362

III-1

1. This group of executive officers was appointed as of June 2000 and, therefore, only compensation for years 2000 and 2001 is listed.

2. In 2001 and 2000, Mr. Castaldi was paid an additional $3,528 and $6,057, respectively, for unused vacation.

3. The target award is 40% of annualized salary for Mr. Rigby, 45% for Mr. Van Roden, 30% for Mr. Weller, 20% for Mr. Castaldi and 20% for Mr. Wathen. For 2000, the dollar value of the bonus reported above has been reduced by the portion of the bonus deferred, as follows: J. M Rigby ($87,800 bonus with $17,560 purchasing Restricted Stock Units (“RSU’s”)); J. C. van Roden ($170,800 bonus with $85,400 purchasing RSU’s); J. C. Weller ($69,000 bonus with $34,500 purchasing RSU’s); J. M. Castaldi ($36,100 bonus with $7,220 purchasing RSU’s); and J. M. Wathen ($33,600 bonus with $16,800 purchasing RSU’s). For 2001, the dollar value of the bonus reported above has been reduced by the portion of the bonus deferred, as follows: J. M Rigby ($157,133 bonus with $78,567 purchasing RSU’s); J. C. van Roden ($181,071 bonus with $90,536 purchasing RSU’s); J. C. Weller ($67,001 bonus with $33,501 purchasing RSU’s); J. M. Castaldi ($37,740 bonus with $7,548 purchasing RSU’s); and J. M Wathen ($34,360 bonus with $17,180 purchasing RSU’s). In addition, in 2001, Mr. Rigby received a $350,000 retention bonus related to the Conectiv/Pepco Merger.

4. A mandatory 20% of the bonus (reported in this Table as “Variable Compensation”) and any additional portion of the bonus that an executive elects to defer (up to an additional 30%) is deferred for at least three years under the Management Stock Purchase Program (“MSPP”) and used to purchase RSU’s at a 20% discount. The dollar value of RSU’s deferred under MSPP in 2001 (inclusive of the discounted portion), based on the fair market value at the award date, was J. M. Rigby ($21,950 of which $4,390 is the discount); J. C. van Roden ($106,750 of which $21,350 is the discount); J. C. Weller ($43,125 of which $8,625 is the discount); J. M. Castaldi ($9,025 of which $1,805 is the discount); and J. M. Wathen ($21,000 of which $4,200 is the discount). At the end of 2001, the number and value of the aggregate restricted stock holdings (including RSU’s, Performance Accelerated Restricted Stock (“PARS”) and special grants) valued at $24.49, the closing stock price on December 31, 2001, for the individuals identified in the Summary Compensation Table was as follows: for Mr. Rigby, 9,007 restricted stock holdings valued at $220,581; for Mr. Van Roden, 20,539 restricted stock holdings valued at $498,592; for Mr. Weller, 8,935 restricted stock holdings valued at $218,818; for Mr. Castaldi 2,269 restricted stock holdings valued at $55,568; and for Mr. Wathen 4,797 restricted stock holdings valued at $117,479.

5. As of December 31, 2001, Mr. Rigby held 7,600 shares of restricted stock (with grants of 1,600 for 2000 and 3,800 for 2001); Mr. Van Roden held 12,300 shares of restricted stock (with grants of 4,700 for 2000 and 4,600 for 2001); Mr. Weller held 5,500 shares of restricted stock (with grants of 1,500 for 2000 and 1,500 for 2001); Mr. Castaldi held 1,900 shares of restricted stock (with grants of 1,000 for 2000 and 900 for 2001); and Mr. Wathen held 3,100 shares of restricted stock (with grants of 900 for 2000 and 800 for 2001). No new grants of Dividend Equivalent Units (“DEU’s”) were made to executives in 2001. For the year 2000, Mr. Rigby received DEU grants of 5,750; Mr. Van Roden received DEU grants of 17,350; Mr. Weller received DEU grants of 5,550; Mr. Castaldi received DEU grants of 3,400; and Mr Wathen received DEU grants of 3,250. All DEU’s granted in years prior to 2001 lapsed following the dividend declared in the fourth quarter of 2000, which was payable in January of 2001. Dividends paid on DEU’s for 2000 were as follows: Mr. Rigby, $9,075, $5,280 of which was deferred into the Conectiv Deferred Compensation Plan; Mr. Van Roden, $20,251, all of which was deferred into the Conectiv Deferred Compensation Plan; Mr. Weller, $9,691; Mr. Castaldi $2,244, and Mr. Wathen, $5,665, $3,520 of which was deferred into the Conectiv Deferred Compensation Plan. Dividends on shares of restricted stock and DEU’s are accrued at the same rate as that paid to all holders of common stock. Holders of restricted stock are entitled to receive dividends as, if and when declared.

6. The amount of All Other Compensation for each of the named executive officers for fiscal year 2001 include the following: Mr. Rigby, $4,500 in Conectiv matching contributions to Conectiv’s Savings and Investment Plan, $2,700 in Conectiv matching contributions to Conectiv’s Deferred Compensation Plan, $257 in term life insurance premiums paid by Conectiv and $14,828 in financial planning services and related taxes; for Mr. van Roden, $5,100 in Conectiv matching contributions to Conectiv’s Savings and Investment Plan, $2,250 in Conectiv matching contributions to the Conectiv Deferred Compensation Plan, $1,039 in term life in - -

III-2

surance premiums paid by Conectiv, and $15,180 in financial planning services and related taxes; for Mr. Weller, $3,218 in Conectiv matching contributions to Conectiv’s Savings and Investment Plan, and $705 in term life insurance premiums paid by Conectiv; for Mr. Castaldi, $3,175 in Conectiv matching contributions to Conectiv’s Savings and Investment Plan, and $681 in term life insurance premiums paid by Conectiv; and for Mr. Wathen, $3,526 in Conectiv matching contributions to Conectiv’s Savings and Investment Plan and $348 in term life insurance premiums paid by Conectiv.

Table 2—Option Grants in Last Fiscal Year (1)

Name	Number of Securities Underlying Options Granted(#)		% of Total Options Granted to Employees in Fiscal Year		Exercise Price ($/Sh)		Expiration Date	Grant Date Present Value (3)
J.M. Rigby	32,000	(2)	5	%	$	19.53125	1/2/11	$	109,664
J.C.van Roden	39,300	(2)	6	%	$	19.53125	1/2/11	$	134,681
J.C. Weller	13,100	(2)	2	%	$	19.53125	1/2/11	$	44,894
J.M. Castaldi	7,500	(2)	1	%	$	19.53125	1/2/11	$	25,703
J.M. Wathen	7,200	(2)	1	%	$	19.53125	1/2/11	$	25,703

1. Currently, Conectiv does not grant stock appreciation rights.

2. Denotes Nonqualified Stock Options. One-half of such Options vest and are exercisable at the end of the second year from date of grant. Second one-half vest and are exercisable at end of the third year from the date of grant.

3. Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise price of $19.53125, equal to the Fair Market Value as of date of grant (b) an option term of ten years (c) risk-free rate of return of 5.00% (d) volatility of 20.00% and (e) dividend yield of 4.75%.

Table 3—Aggregated Option Exercises in Last Fiscal Year

and FY-End Option Values

Name	Shares Acquired On Exercise	Value Realized ($) (1)	Number of Securities Underlying Unexercised Options at FY-End (2) Exercisable/Unexercisable	Value of Unexercised in- the-Money Options at FY-End (1) Exercisable/Unexercisable
J. M. Rigby	0	0	9,000/63,500	$	10,598/385,334
J. C. van Roden	0	0	10,000/234,000	$	2,400/508,363
J. C. Weller	0	0	17,700/35,200	$	11,870/153,795
J. M. Castaldi	0	0	0/14,300	$	0/91,098
J. M. Wathen	0	0	6,000/15,700	$	7,065/87,712

1. The closing price for Conectiv’s common stock as reported by the New York Stock Exchange on December 31, 2001 was $24.49. Any value in the options is based on the difference between the exercise price of the options and the value at the time of the exercise (e.g., $24.49 as of the close of business on December 31, 2001), which difference is multiplied by the number of options exercised.

2. All of the unexercisable options listed on Table 3 are in the money except for Mr. Weller’s, of which 27,700 out of 35,200 unexercisable options are in the money. Unless vesting is accelerated under the terms of Conectiv’s Long-Term Incentiv Plan (“LTIP”), 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).

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Table 4—Long-Term Incentive Plans – Awards in Last Fiscal Year (1)

Name	Number of Restricted Shares (#)	Performance Period Until Maturation Or Payout(1)
J. M. Rigby	3,800 shares	1/2/08
J. C. van Roden	4,600 shares	1/2/08
J. C. Weller	1,500 shares	1/2/08
J. M. Castaldi	900 shares	1/2/08
J. M. Wathen	800 shares	1/2/08

1. Awards of PARS were made to all 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 January 2, 2004) upon achievement of favorable stock price performance goals. In the absence of such favorable performance or accelerated vesting under the terms of Conectiv’s LTIP, restrictions lapse after 7 years (i.e., January 2, 2008), provided that at least a defined level of average, total return to stockholders is achieved. As of December 31, 2001, Mr. Rigby’s 3,800 PARS were valued at $93,062, Mr.van Roden’s 4,600 PARS were valued at $112,654, Mr. Weller’s 1,500 PARS were valued at $36,735, Mr. Castaldi’s 900 PARS were valued at $22,041, and Mr Wathen’s 800 PARS were valued at $19,592. These values are based on the December 31, 2001 closing stock price of $24.49.

PENSION PLAN

The Conectiv Retirement Plan includes the Cash Balance Pension Plan and certain “grandfathering” 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. Annually, 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 pay, overtime and bonuses, depending on the participant’s age at the end of the plan year, as follows:

Age at end of Plan Year	% of Pay
Under 30	5
30 to 34	6
35 to 39	7
40 to 44	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 Retirement Plan and Atlantic Retirement Plan are fully protected as of December 31, 1998, and were converted to an equivalent cash amount and included in each participant’s initial cash balance account. When a participant terminates employment, the amount credited to his or her account is converted into an annuity or paid in a lump sum.

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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 federal tax laws and regulations.

Estimated Retirement Benefits Payable to Named Executives Officers

The following table shows the estimated retirement benefits, including supplemental retirement benefits under the plans applicable to the named executives, that would be payable if he or she were to retire at normal retirement age (65), 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. Rigby—43, Mr. van Roden—16, Mr. Weller—21, Mr. Castaldi—42, and Mr. Wathen—27.

Name	Year of 65th Birthday	Lump Sum Value
J. M. Rigby	2021	$	2,152,000	(1)
J. C. van Roden	2014	$	1,056,000	(1)
J. C. Weller	2014	$	530,000	(1)
J. M. Castaldi	2012	$	1,206,000	(1)
J. M. Wathen	2020	$	733,000	(1)

(1) Amounts include (i) interest credits for cash balances projected to be 5.32% per annum on annual salary credits and prior service balances, if any, and (ii) accrued benefits as of December 31, 2001, 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 pay or total pay.

Under the Conectiv Retirement Plan’s grandfathering provisions, employees who participated in the Delmarva or Atlantic Retirement Plans and who met certain age and service requirements as of January 1, 1999, will have retirement benefits for all years of service up to the earlier of December 31, 2008, or retirement calculated according to their original benefit formula. This benefit will be compared to the cash balance account and the employee will receive, whichever is greater. For years after December 31, 2008, all participants’ benefits will be calculated under the cash balance plan. Current actuarial estimates and assumptions indicate that all five of the above executives will receive retirement benefits based on the Cash Balance Pension Plan.

Change in Control Severance Agreements and

Other Provisions Relating to Possible Change in Control

For the executive officers of ACE, Conectiv has entered into change in control severance agreements with Messrs. Rigby and van Roden. The agreements are intended to encourage the continued dedication of Conectiv’s senior management team. The agreements provide potential benefits for these executives upon actual or constructive termination of employment (other than for cause) following a change in control of Conectiv, as defined in the agreements. Each affected executive would receive a severance payment equal to three times base salary and bonus, medical, dental, vision, group life and disability benefits for three years after termination of employment, and a cash payment equal to the actuarial equivalent of accrued 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, 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 Personnel and Compensation Committee. For the Deferred Compensation Plan, this Committee

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may decide to distribute all deferrals in cash immediately or continue the deferral elections of participants, in which case Conectiv will fully fund a “springing rabbi trust” to satisfy the obligations. An independent institutional trustee will maintain any 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-6

PART IV

ITEM 14.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8–K

(a)  Documents 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 Accountant, PricewaterhouseCoopers LLP	II-16
Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999	II-17
Consolidated Balance Sheets as of December 31, 2001 and 2000	II-18, 19
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999	II-20
Consolidated Statements of Changes in Common Stockholder’s Equity for the years ended December 31, 2001, 2000, and 1999	II-21
Notes to Consolidated Financial Statements	II-22

2.  Financial Statement Schedules

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2001, 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, 2001, 2000, 1999

(Dollars in thousands)

			Additions
	Balance at beginning of period		Charged to cost and expenses		Charged to other accounts	Deductions			Balance at end of period
2001
Allowance for doubtful accounts	$	4,423	$	11,330	—	$	7,949	(a)	$	7,804
2000
Allowance for doubtful accounts		3,500		4,248	—		3,325	(a)		4,423
1999
Allowance for doubtful accounts		3,500		5,590	—		5,590	(a)		3,500

(a) Accounts receivable written-off.

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3.  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	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 with 1998 Form 10-K, file no. 1-3559)
3-B	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 with 1998 Form 10-K, file no. 1-3559)
3-C	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 with 1998 Form 10-K, file no. 1-3559)
3-D	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. 2-66280—Exhibit 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)(1)
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)
4-D	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))
4-E	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))
4-F	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))
4-G	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 with 1998 Form 10-K, file no. 1-3559)

IV-2

Exhibit Number
4-H	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 with 1998 Form 10-K, file no. 1-3559)
4-I	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 with 1998 Form 10-K, file no. 1-3559)
10-A	Termination Agreement dated August 14, 1997 between Atlantic Energy, Inc. and Michael J. Chesser. (Filed with 1997 Form 10-K, file No. 1-3559)
10-B	Purchase And Sale Agreement By And Between Atlantic City Electric Company and NRG Energy Inc. (wholly owned electric generating plants) (filed with ACE’s 2000 Annual Report on Form 10-K, as Exhibit 10-B).
10-C	Purchase And Sale Agreement By And Between Atlantic City Electric Company and NRG Energy Inc. (jointly owned electric generating plants) (filed with ACE’s 2000 Annual Report on Form 10-K, as Exhibit 10-C).
10-D	Second Amendment to the Purchase and Sale Agreement by and between Atlantic City Electric Company and NRG Energy, Inc., dated as of October 31, 2001 (wholly owned electric generating plants) (Filed with ACE’s report on Form 10-Q for the quarterly period ended September 30, 2001, as Exhibit 10-B)
10-E	Second Amendment to the Purchase and Sale Agreement by and between Atlantic City Electric Company and NRG Energy, Inc., dated as of October 31, 2001 (jointly owned electric generating plants) (Filed with ACE’s report on Form 10-Q for the quarterly period ended September 30, 2001, as Exhibit 10-C)
12-A	Ratio of earnings to fixed charges, filed herewith
12-B	Ratio of earnings to fixed charges and preferred dividends, filed herewith
99	Pro Forma Financial Statements—Generation Asset Sale , filed herewith

(b)  Reports on Form 8-K

The following Reports on Form 8-K were filed in the fourth quarter of 2001:

On October 22, 2001, ACE filed a Current Report on Form 8-K dated October 18, 2001, reporting on Item 5, Other Events, and Item 7, Financial Statements, Pro Forma Financial Statements, and Exhibits.

IV-3

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 27, 2002.

AT LANTIC CITY ELECTRIC COMPANY

(Re gistrant)

By	/s/    JOHN C. VAN RODEN
	(John C. van Roden, 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 27, 2002.

Signature	Title
/S/    HOWARD E. COSGROVE (Howard E. Cosgrove)	Chairman of the Board
/S/    JOSEPH M. RIGBY (Joseph M. Rigby)	President
/S/    JOHN C. VAN RODEN (John C. van Roden)	Director and Chief Financial Officer
/S/    JAMES P. LAVIN (James P. Lavin)	Controller and Chief Accounting Officer
/S/    THOMAS S. SHAW (Thomas S. Shaw)	Director
/S/    BARBARA S. GRAHAM (Barbara S. Graham)	Director

IV-4

EXHIBIT INDEX

Exhibit No.	Description
12-A	Ratio of Earnings to Fixed Charges
12-B	Ratio of Earnings to Fixed Charges and Preferred Dividends
99	Pro Forma Financial Statements—Generation Asset Sale

EX-12.A

Exhibit 12-A

Atlantic City Electric Company

Ratio of Earnings to Fixed Charges

(Dollars in Thousands)

	Year Ended December 31,
	2001		2000		1999		1998		1997
Income before extraordinary item	$	75,476	$	54,434	$	63,930	$	30,276	$	85,747
Income taxes		46,698		36,746		49,326		18,178		50,442
Fixed charges:
Interest on long-term debt including amortization of discount, premium and expense		62,166		76,178		60,562		63,940		64,501
Other interest		3,314		4,518		3,837		3,435		3,574
Preferred dividend requirements of subsidiary trusts		7,619		7,619		7,634		6,052		5,775
Total fixed charges		73,099		88,315		72,033		73,427		73,850
Earnings before extraordinary item, income taxes and fixed charges	$	195,273	$	179,495	$	185,289	$	121,881	$	210,039
Ratio of earnings to fixed charges		2.67		2.03		2.57		1.66		2.84

For purposes of computing the ratio, earnings are income before extraordinary item plus income taxes and fixed charges. Fixed charges consist of interest on long- and short-term debt, amortization of debt discount, premium, and expense, dividends on preferred securities of subsidiary trusts, and the estimated interest component of rentals.

EX-12.B

Exhibit 12-B

Atlantic City Electric Company

Ratio of Earnings to Fixed Charges and Preferred Dividends

(Dollars in Thousands)

	Year Ended December 31,
	2001		2000		1999		1998		1997
Income before extraordinary item	$	75,476	$	54,434	$	63,930	$	30,276	$	85,747
Income taxes		46,698		36,746		49,326		18,178		50,442
Fixed charges:
Interest on long-term debt including amortization of discount, premium and expense		62,166		76,178		60,562		63,940		64,501
Other interest		3,314		4,518		3,837		3,435		3,574
Preferred dividend requirements of subsidiary trusts		7,619		7,619		7,634		6,052		5,775
Total fixed charges		73,099		88,315		72,033		73,427		73,850
Earnings before extraordinary item, income taxes and fixed charges	$	195,273	$	179,495	$	185,289	$	121,881	$	210,039
Fixed charges	$	73,099	$	88,315	$	72,033	$	73,427	$	73,850
Preferred dividend requirements		2,724		3,571		3,777		5,289		7,506
	$	75,823	$	91,886	$	75,810	$	78,716	$	81,356
Ratio of earnings to fixed charges and preferred dividends		2.58		1.95		2.44		1.55		2.58

For purposes of computing the ratio, earnings are income before extraordinary item plus income taxes and fixed charges. Fixed charges consist of interest on long- and short-term debt, amortization of debt discount, premium, and expense, dividends on preferred securities of subsidiary trusts, and the estimated interest component of rentals. Preferred dividend requirements represent annualized preferred dividend requirements multiplied by the ratio that pre-tax income bears to income.

EX-99

EXHIBIT 99

ATLANTIC CITY ELECTRIC COMPANY

PRO FORMA FINANCIAL STATEMENTS—GENERATION ASSET SALE

General

In 1999, the electric utility business of Atlantic City Electric Company (ACE) was restructured pursuant to legislation enacted in New Jersey and a Summary Order issued by the New Jersey Board of Public Utilities (NJBPU). The restructuring of ACE’s electric utility business is discussed in ACE’s 2001 Annual Report on Form 10-K in Notes 1, 5, 6, 7 and 10 to the Consolidated Financial Statements, included in Item 8 of Part II.

Electric Generating Plants Sold During 2001

On October 18, 2001, ACE sold for $29.6 million its 7.51% (164 MW) interest in Peach Bottom Atomic Power Station (Peach Bottom), 7.41% interest (167 MW) in Salem Nuclear Generating Station (Salem) and 5.0% interest (52 MW) in Hope Creek Nuclear Generating Station (Hope Creek) and the related nuclear fuel to the utilities that operate the plants. ACE’s trust funds and obligation for decommissioning the plants were transferred to the purchasers in conjunction with the sale. The net assets sold had a carrying value of $27.3 million, which reflects a write-down in 1999 related to discontinuing Statement of Financial Accounting Standards No. 71, “Accounting For the Effects of Certain Types of Regulation” (SFAS No. 71). ACE used $20.5 million of the proceeds to repay the lease obligations related to the nuclear fuel. There was a $2.4 million pre-tax gain on the sale, which did not affect earnings due to the terms of the 1999 restructuring of the electricity generation business of ACE; instead, the pre-tax gain on the sale decreased the balance of deferred recoverable stranded costs.

Agreements for Sale of Electric Generating Plants

As discussed in Note 9 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv’s 2001 Annual Report on Form 10-K, as of December 31, 2001, ACE’s fossil fuel-fired electric generating plants (Deepwater Station, Conemaugh and Keystone Stations and B.L. England Station) were under agreements for sale to NRG for approximately $178 million (before adjustments for inventories, expenses, and other items). The plants to be sold have electric generating capacity of 739.7 MW, and as of December 31, 2001, the carrying value of the plants was approximately $117 million. Due to the terms of ACE’s electric utility restructuring in 1999 and expected sales proceeds, (i) the loss expected to be realized on the sale of the Deepwater Station was included in the extraordinary charge to earnings in 1999, (ii) the loss expected to be realized on the sale of the B.L. England Station is included in recoverable stranded costs, and (iii) any net gain that may be realized on the sale of ACE’s interests in Conemaugh and Keystone Stations is expected to reduce the amount of stranded costs to be recovered from ACE’s utility customers.

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Description of Pro Forma Financial Information

The following consolidated financial statements for ACE are filed with this Exhibit:

• Unaudited Pro Forma Consolidated Balance Sheet at December 31, 2001, and

• Unaudited Pro Forma 2001 Consolidated Statement of Income.

The following major assumptions were made in preparing these pro forma financial statements:

• For purposes of the Pro Forma Consolidated Balance Sheet, (i) ACE’s fossil fuel-fired electric generating plants that are subject to the agreements for sale, as discussed in Note 9 to the Consolidated Financial Statements included in Item 8 of Part II of ACE’s 2001 Annual Report on Form 10-K, were assumed to be sold as of December 31, 2001, and (ii) the proceeds from the sale of ACE’s fossil fuel-fired electric generating plants were assumed to be used to repay short-term and long-term debt, after considering expected debt retirement costs and tax payments on the gain on the sale of the electric generating plants.

• For purposes of the Pro Forma 2001 Consolidated Statement of Income, the following sale and expected sale were assumed to have occurred on January 1, 2001: (i) the sale of ACE’s ownership interests in nuclear electric generating plants (383 MW) on October 18, 2001, and (ii) the expected sale of ACE’s fossil fuel-fired electric generating plants (739.7 MW), which were under agreements for sale as of December 31, 2001. As a result, expenses related to the electric generating plants that were assumed to be sold were eliminated for the period of operations during 2001.

• To replace the kilowatt-hours produced by the electric generating plants that were assumed to be sold, replacement energy and capacity were assumed to be purchased from the PJM Interconnection, L.L.C. (PJM). The energy costs were based on an hourly PJM Locational Marginal Price (LMP) and the capacity costs were based on average PJM capacity rates.

• Under its rates for electricity supplied to utility customers, ACE was assumed to be permitted to earn a return on the stranded costs resulting from the power plant sales and to no longer earn a return on the power plants sold.

• Revenues which resulted from the Wholesale Transaction Confirmation Letter Agreements during 2001, as discussed in Note 9 to the Consolidated Financial Statements included in Item 8 of Part II of ACE’s 2001 Annual Report on Form 10-K, were assumed not to have been earned due to the assumption that the nuclear power plants were sold on January 1, 2001.

• The net pro forma gain from the sale of ACE’s fossil fuel-fired electric generating plants was primarily recorded as a reduction to recoverable stranded costs. A gain on the Deepwater electric generating plant (primarily due to depreciation subsequent to the 1999 write-down associated with discontinuing the application of SFAS No. 71 to ACE’s electric generation business) and the recognition of unamortized deferred investment tax credits were credited to retained earnings.

• An effective tax rate of 40% was utilized to calculate the income tax effects of adjustments to the Pro Forma 2001 Consolidated Statement of Income.

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These Pro Forma Consolidated Financial Statements have been prepared for comparative purposes only and do not purport to be indicative of operations or financial condition which would have actually resulted if the sale of generation assets or other related transactions occurred on the dates of the period presented, or which may result in the future. Further, these Pro Forma Consolidated Financial Statements have been prepared using information available at the date of this filing. As a result, certain amounts indicated herein are preliminary in nature and, therefore, will be subject to adjustment in the future.

Description of Pro Forma Adjustments

The Unaudited Pro Forma Consolidated Statement of Income and Balance Sheet filed with this Exhibit reflect the following adjustments:

Adjustments to the Consolidated Statement of Income

1. A net decrease in “Operating revenues” due to (i) no revenues from the operations of the deregulated Deepwater electric generating plant, and (ii) no revenues earned under the “Wholesale Transaction Confirmation Letter Agreements” from ACE’s interests in the nuclear electric generating plants.

2. An increase in “Electric fuel and purchased energy and capacity” primarily because the cost increase from ACE purchasing all energy and capacity requirements to meet its retail load exceeded the cost decrease from no longer purchasing fuel for the electric generating units.

3. Decreases in other operating expenses as a result of the assumed sales of certain electric generating plants as of January 1, 2001.

4. A decrease in the amount of “Deferred electric service costs” associated with ACE’s Basic Generation Service because (i) for ratemaking purposes, the total return earned on the stranded costs of ACE is less than the total return earned on the generation rate base of ACE’s divested plants, and (ii) there is a net reduction in the operating expenses associated with supplying ACE’s load, which results in a related reduction in the operating expenses deferred. For additional information, see “Basic Generation Service” in Note 6 to the Consolidated Financial Statements included in Item 8 of Part II of Conectiv’s 2001 Annual Report on Form 10-K.

5. A decrease in “Interest charges” as a result of retirement of debt due to the sale of certain electric generating plants.

6. A decrease in income taxes due to the decrease in income before income taxes.

Adjustments to the Consolidated Balance Sheet

1. A net increase to “Cash and cash equivalents” primarily as a result of net proceeds received from the sale of certain electric generating plants, less cash used for the retirement of short-term and long-term debt.

2. Net decreases in “Fuel” and “Materials and supplies” inventories, “Investments,” “Property, plant and equipment,” “Other” within “Deferred Charges and Other Assets,” and “Prepaid income taxes” as a result of the sale of certain electric generating plants.

3. A decrease in “Recoverable stranded costs, net” due to an expected net gain on ACE’s interests in Conemaugh and Keystone Stations, which, along with ACE’s B.L. England Station and ACE’s former interests in nuclear electric generating plants, are subject to stranded cost recovery.

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4. Decreases to “Short-term debt” and “Long-term debt” because the proceeds from the sale of ACE’s fossil fuel-fired electric generating plants were assumed to be used to repay short-term and long-term debt, after considering expected debt retirement costs and tax payments on the gain on the sale of the electric generating plants.

5. Changes to “Deferred income taxes, net,” “Deferred investment tax credits,” and “Other” within “Deferred Credits and Other Liabilities” as a result of the sale of certain electric generating plants.

6. A gain on the Deepwater electric generating plant, primarily due to depreciation subsequent to the 1999 write-down associated with discontinuing the application of SFAS No. 71 to ACE’s electric generation business, and the recognition of unamortized deferred investment tax credits was credited to retained earnings.

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ATLANTIC CITY ELECTRIC COMPANY

UNAUDITED CONSOLIDATED PRO FORMA STATEMENTS OF INCOME

YEAR ENDED DECEMBER 31, 2001

	Reported			Adjustments			Pro Forma
	(Dollars in Thousands)
OPERATING REVENUES	$	1,041,171		$	(53,308	)(1)	$	987,863
OPERATING EXPENSES
Electric fuel and purchased energy and capacity		636,552			42,143	(2)		678,695
Operation and maintenance		249,247			(84,012	)(3)		165,235
Depreciation and amortization		84,703			(30,821	)(3)		53,882
Taxes other than income taxes		34,118			(1,180	)(3)		32,938
Deferred electric service costs		(143,190	)		45,271	(4)		(97,919	)
		861,430			(28,599	)		832,831
OPERATING INCOME		179,741			(24,709	)		155,032
OTHER INCOME		11,504			—			11,504
INTEREST EXPENSE
Interest charges		62,166			(9,417	)(5)		52,749
Allowance for borrowed funds used during construction and capitalized interest		(714	)		—			(714	)
		61,452			(9,417	)		52,035
PREFERRED DIVIDEND REQUIREMENTS ON PREFERRED SECURITIES OF SUBSIDIARY TRUSTS		7,619			—			7,619
INCOME BEFORE INCOME TAXES		122,174			(15,292	)		106,882
INCOME TAXES		46,698			(6,117	)(6)		40,581
NET INCOME		75,476			(9,175	)		66,301
DIVIDENDS ON PREFERRED STOCK		1,683			—			1,683
EARNINGS APPLICABLE TO COMMON STOCK	$	73,793		$	(9,175	)	$	64,618

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ATLANTIC CITY ELECTRIC COMPANY

UNAUDITED CONSOLIDATED PRO FORMA BALANCE SHEETS

As of December 31, 2001

	Reported		Adjustments			Pro Forma
	(Dollars in Thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	14,261	$	20,328	(1)	$	34,589
Accounts receivable net of allowances of $7,804		159,679					159,679
Inventories, at average cost
Fuel (coal and oil)		20,331		(20,331	)(2)		—
Materials and supplies		10,738		(1,839	)(2)		8,899
Prepaid income taxes		41,044		(20,328	)(2)		20,716
Other prepayments		1,756					1,756
Deferred income taxes, net		181					181
		247,990		(22,170	)		225,820
Investments		3,666		(3,590	)(2)		76
Property, Plant and Equipment
Electric generation		136,152		(136,152	)(2)		—
Electric transmission and distribution		1,276,896		(1,007	)(2)		1,275,889
Other electric facilities		116,215					116,215
Other property, plant, and equipment		5,772					5,772
		1,535,035		(137,159	)		1,397,876
Less: Accumulated depreciation		569,495		(19,879	)(2)		549,616
Net plant in service		965,540		(117,280	)		848,260
Construction work-in-progress		74,780					74,780
Leased nuclear fuel, at amortized cost		—					—
		1,040,320		(117,280	)		923,040
Deferred Charges and Other Assets
Regulatory assets
Recoverable stranded costs, net		930,036		(27,971	)(3)		902,065
Deferred electric service costs		106,259					106,259
Other non-current regulatory assets		82,944					82,944
Unamortized debt expense		12,966					12,966
Other		8,149		1,104	(2)		9,253
		1,140,354		(26,867	)		1,113,487
Total Assets	$	2,432,330	$	(169,907	)	$	2,262,423

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31, 2001

	Reported		Adjustments			Pro Forma
	(Dollars in Thousands)
CAPITALIZATION AND LIABILITIES
Current Liabilities
Short-term debt	$	44,951	$	(44,951	)(4)	$	—
Long-term debt due within one year		221,450		(120,001	)(4)		101,449
Variable rate demand bonds		22,600					22,600
Accounts payable		58,001					58,001
Interest accrued		17,224					17,224
Dividends payable		6,302					6,302
Other		40,461					40,461
		410,989		(164,952	)		246,037
Deferred Credits and Other Liabilities
Deferred income taxes, net		470,420		(718	)(5)		469,702
Deferred investment tax credits		28,482		(7,114	)(5)		21,368
Regulatory liability for New Jersey income tax benefit		49,262					49,262
Above-market purchased energy contracts and							—
other electric restructuring liabilities		16,615					16,615
Pension benefit obligation		35,529					35,529
Other postretirement benefit obligation		36,429					36,429
Other		13,311		(4,648	)(5)		8,663
		650,048		(12,480	)		637,568
Capitalization
Common stock, $3 par value; shares authorized: 25,000,000 ; shares outstanding: 18,320,937		54,963					54,963
Additional paid-in capital		410,194					410,194
Retained earnings		156,152		7,525	(6)		163,677
Total common stockholder’s equity		621,309		7,525			628,834
Preferred stock not subject to mandatory redemption		6,231					6,231
Preferred stock subject to mandatory redemption		12,450					12,450
Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely company debentures		95,000					95,000
Long-term debt		636,303					636,303
		1,371,293		7,525			1,378,818
Total Capitalization and Liabilities	$	2,432,330	$	(169,907	)	$	2,262,423

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