<PAGE>
 
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                      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, 1997
                         COMMISSION FILE NUMBER 1-1405
 
                        DELMARVA POWER & LIGHT COMPANY
            (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
 
          DELAWARE & VIRGINIA                        51-0084283
   (STATES OR OTHER JURISDICTIONS OF    (I.R.S. EMPLOYER IDENTIFICATION NO.)
    INCORPORATION OR ORGANIZATION)                       19899
    800 KING STREET, P. O. BOX 231                   (ZIP CODE)
         WILMINGTON, DELAWARE
    (ADDRESS OF PRINCIPAL EXECUTIVE
               OFFICES)
 
       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 302-429-3114
 
                               ----------------
 
          SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
 
        TITLE OF EACH CLASS            NAME OF EACH EXCHANGE ON WHICH REGISTERED
 
 
FIRST MORTGAGE BONDS (SERIES              NEW YORK STOCK EXCHANGE AND
 ISSUED PRIOR TO 1968)                     PHILADELPHIA STOCK EXCHANGE
PREFERRED STOCK, CUMULATIVE, PAR          PHILADELPHIA STOCK EXCHANGE
 VALUE $100.00 (SERIES ISSUED
 PRIOR TO 1978)
 
8.125% CUMULATIVE TRUST PREFERRED         NEW YORK STOCK EXCHANGE
 CAPITAL SECURITIES OF DELMARVA     
 FINANCING I (LIQUIDATION VALUE OF  
 $25.00)                             

 
          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 THE REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION
STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY
AMENDMENT TO THIS FORM 10-K. [X]
 
  THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE
REGISTRANT AS OF MARCH 1, 1998 WAS $0.
 
  AS OF MARCH 1, 1998, THERE WERE ISSUED AND OUTSTANDING 1,000 SHARES OF THE
REGISTRANT'S COMMON STOCK, PAR VALUE $2.25.
 
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<PAGE>
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                                                            PAGE
                                                                            ----
<S>                                                                         <C>
Glossary...................................................................  iii
PART I
Item 1.Business
     The Company...........................................................  I-1
      Overview.............................................................  I-1
      Atlantic Merger......................................................  I-1
      Utility Regulation and Industry Restructuring........................  I-2
      Business Plans.......................................................  I-2
       Conectiv Energy Delivery............................................  I-3
       Conectiv Energy Supply..............................................  I-3
       Conectiv Enterprises................................................  I-3
     Electric Business.....................................................  I-4
      Installed Capacity...................................................  I-4
      Energy Supply Plan...................................................  I-4
      Reserve Margin.......................................................  I-4
      Pennsylvania-New Jersey-Maryland Interconnection Association.........  I-5
      Purchased Power......................................................  I-5
      Demand Side Management Programs......................................  I-5
      Nuclear Power Plants.................................................  I-6
       Peach Bottom Units..................................................  I-6
       Salem Units.........................................................  I-7
      Cost of Output for Load..............................................  I-7
      Fuel Supply for Electric Generation..................................  I-7
       Coal................................................................  I-8
       Oil.................................................................  I-8
       Gas.................................................................  I-8
       Nuclear.............................................................  I-8
      Electric Regulatory Matters..........................................  I-9
       Delaware Depreciation Filing........................................  I-9
       Electric Fuel Adjustment Clauses....................................  I-9
     Gas Business.......................................................... I-10
      Deregulation......................................................... I-10
      Gas Operations....................................................... I-11
      Gas Regulatory Matters............................................... I-11
     Other Regulatory Matters.............................................. I-12
      Special Contract Rate Tariffs........................................ I-12
      Cost Accounting Manual/Code of Conduct............................... I-12
      Virginia Affiliates Act.............................................. I-13
     Nonutility Businesses................................................. I-13
      Conectiv Communications, Inc......................................... I-13
      Conectiv Energy...................................................... I-14
      Conectiv/CNE Energy Services LLC..................................... I-14
      Conectiv Services, Inc............................................... I-14
      Conectiv Solutions LLC............................................... I-15
      Conectiv Thermal Systems, Inc........................................ I-15
      Delmarva Capital Investments, Inc.................................... I-15
      Atlantic Energy Enterprises, Inc..................................... I-15
     Capital Spending and Financing Program................................ I-15
</TABLE>
 
                                       i
<PAGE>
 
<TABLE>
<CAPTION>
                                                                          PAGE
                                                                          ----
<S>                                                                      <C>
    Environmental Matters...............................................   I-16
     Construction Expenditures..........................................   I-16
     Air Quality Regulations............................................   I-16
     Water Quality Regulations..........................................   I-17
     Hazardous Substances...............................................   I-18
     Other Environmental Matters........................................   I-18
    Retail Franchises...................................................   I-18
    Number of Employees.................................................   I-19
    Executive Officers of the Registrant................................   I-19
Item 2.Properties.......................................................   I-20
Item 3.Legal Proceedings................................................   I-21
Item 4.Submission of Matters to a Vote of Security Holders..............   I-22
PART II
Item 5.Market for Registrant's Common Equity and Related Stockholder
 Matters................................................................   II-1
Item 6.Selected Financial Data..........................................   II-2
Item 7.Management's Discussion and Analysis of Financial Condition and
 Results of Operations..................................................   II-3
Item 8.Financial Statements and Supplementary Data......................  II-16
Item 9.Changes in and Disagreements with Accountants on Accounting and
 Financial Disclosure...................................................  II-45
PART III
Item 10.Directors and Executive Officers of the Registrant..............  III-1
Item 11.Executive Compensation..........................................  III-2
Item 12.Security Ownership of Certain Beneficial Owners and Management.. III-12
Item 13.Certain Relationships and Related Transactions.................. III-13
PART IV
Item 14.Exhibits, Financial Statement Schedules, and Reports on Form 8-
 K......................................................................   IV-1
Signatures..............................................................   IV-6
</TABLE>
 
 
                                       ii
<PAGE>
 
                                    GLOSSARY
 
  The following glossary lists the abbreviations used in this report.
 
<TABLE>
<CAPTION>
             TERM                                 DEFINITION
             ----                                 ----------
 <C>                           <S>
 ACE.........................  Atlantic City Electric Company
 ACT.........................  Telecommunications Act of 1996
 AEE.........................  Atlantic Energy Enterprises, Inc.
 AFUDC.......................  Allowance For Funds Used During Construction
 APB.........................  Accounting Principles Board
 APBO........................  Accumulated Postretirement Benefit Obligation
 Atlantic....................  Atlantic Energy, Inc.
 ATS.........................  Atlantic Thermal Systems
 BCF.........................  Billion Cubic Feet
 BPU.........................  Board of Public Utilities
 CAM.........................  Cost Accounting Manual
 CCI.........................  Conectiv Communications, Inc.
 CLEC........................  Competitive Local Exchange Carrier
 Code........................  Code of Conduct
 Company.....................  Delmarva Power & Light Company
 Competition Act.............  Pennsylvania Electricity Generation Consumer
                                Choice and Competition Act
 Conectiv Solutions..........  Conectiv Solutions LLC
 COPCO.......................  Conowingo Power Company
 CSI.........................  Conectiv Services, Inc.
 CT..........................  Combustion Turbine
 CTS.........................  Conectiv Thermal Systems, Inc.
 D&D Fund....................  Decontamination & Decommissioning Fund
                               Delaware Association of Alternative Energy
 DAAEP.......................  Providers Inc.
 DCI.........................  Delmarva Capital Investments, Inc.
 Debentures..................  8.125% Junior Subordinated Debentures
 DOE.........................  United States Department of Energy
 DPSC........................  Delaware Public Service Commission
                               Dividend Reinvestment and Common Share Purchase
 DRIP........................  Plan
 DSM.........................  Demand-Side Management
 Enterprise..................  Public Service Enterprise Group, Inc.
 ERO.........................  Enhanced Retirement Offers
 FASB........................  Financial Accounting Standards Board
 FERC........................  Federal Energy Regulatory Commission
 FGD.........................  Flue Gas Desulfurization
 HVAC........................  Heating, ventilation, and air conditioning
 ILEC........................  Incumbent Local Exchange Carrier
 ISO.........................  Independent System Operator
 ITC.........................  Investment Tax Credits
 kWh.........................  Kilowatt-hour
                               The Private Securities Litigation Reform Act of
 Litigation Reform Act.......  1995
 LLRW........................  Low Level Radioactive Waste
 LTIP........................  Long-Term Incentive Plan
 Mcf.........................  Thousand Cubic Feet
 MD&A........................  Managements Discussion and Analysis of Financial
                                Condition and Results of Operations
 Merger......................  The merger of the Company and Atlantic
 Mortgage....................  Mortgage and Deed of Trust
</TABLE>
 
                                      iii
<PAGE>
 
<TABLE>
<CAPTION>
             TERM                                DEFINITION
             ----                                ----------
 <C>                           <S>
 MPSC........................  Maryland Public Service Commission
 MW..........................  Megawatt
 MWh.........................  Megawatt-hour
 NAAQS.......................  National Ambient Air Quality Standards
 NOTR........................  Northeast Ozone Transport Region
 NOx.........................  Oxides of Nitrogen
 NRC.........................  Nuclear Regulatory Commission
 NWPA........................  Nuclear Waste Policy Act of 1982
 ODEC........................  Old Dominion Electric Cooperative
 Peach Bottom................  Peach Bottom Atomic Power Station
 PECO........................  PECO Energy Company
                               Pennsylvania--New Jersey--Maryland
 PJM Interconnection.........  Interconnection Association
 PPPP........................  Power Plant Performance Program
 PRP.........................  Potentially Responsible Party
 PSE&G.......................  Public Service Electric and Gas Company
 RACT........................  Reasonably Available Control Technology
 RATI........................  Readiness Assessment Team Inspection
 RTP.........................  Real Time Pricing
 Salem.......................  Salem Nuclear Generating Station
 SALP........................  Systematic Assessment of Licensee Performance
 SEC.........................  Securities and Exchange Commission
 SFAS........................  Statement of Financial Accounting Standards
 SO/2/.......................  Sulfur Dioxide
 Star........................  Star Enterprise
 USEPA.......................  United States Environmental Protection Agency
 VRDB........................  Variable Rate Demand Bonds
 VSCC........................  Virginia State Corporation Commission
 Westinghouse................  Westinghouse Electric Corporation
 1935 Act....................  Public Utility Holding Company Act of 1935
</TABLE>
 
 
                                       iv
<PAGE>
 
                                    PART I
 
ITEM 1. BUSINESS
 
THE COMPANY
 
 Overview
 
  Delmarva Power & Light Company (the Company) was incorporated in Delaware in
1909 and in Virginia in 1979. The Company's primary businesses include
producing, purchasing, delivering, and selling electricity; purchasing,
transporting, and selling natural gas; and providing other services which are
primarily energy-related. In 1997, the Company's revenues were earned from the
following sources: 77% from electricity sales and delivery; 14% from the sale
and transportation of natural gas; and 9% from other services.
 
  The Company provides regulated electric service (supply and delivery) to
approximately 448,300 customers located on the Delmarva Peninsula and also
sells electricity off-system in markets which are not subject to price
regulation. The Company's traditional electric service territory on the
Delmarva Peninsula, which includes Delaware, ten primarily Eastern Shore
counties in Maryland, and the Eastern Shore of Virginia, encompasses an area
consisting of about 6,000 square miles with a population of approximately 1.2
million. The Company provides regulated gas service (supply and/or delivery)
to approximately 103,200 customers located in an area consisting of about 275
square miles with a population of approximately 480,000 in northern Delaware,
including the City of Wilmington. The Company also sells gas off-system in
markets which are not subject to price regulation.
 
  In addition to selling competitive electricity and natural gas, the Company
also sells other non-regulated/nonutility products and services which include
the following: local and long-distance telephone service; heating,
ventilation, and air-conditioning (HVAC) products, installation and services;
power plant operating services; and certain other services. For additional
information on nonutility businesses, see "Business Plans" on page I-2 and
"Nonutility Businesses" on page I-13.
 
  For information concerning the Company's business segments, see Note 21 to
the Company's 1997 Consolidated Financial Statements included in Item 8 of
Part II.
 
 Atlantic Merger
 
  On August 12, 1996, the Company announced plans for a merger with Atlantic
Energy, Inc. (Atlantic), an investor-owned holding company located in southern
New Jersey, which owned Atlantic City Electric Company (ACE) and nonutility
subsidiaries. The final required regulatory merger approval was received from
the Securities and Exchange Commission (SEC) on February 27, 1998. On March 1,
1998, a series of merger transactions were consummated. These merger
transactions (the Merger) formed Conectiv, a new holding company, and merged
Atlantic out of existence. As a result of the Merger, Conectiv owns the
Company, the Company's subsidiaries, ACE, and the nonutility subsidiaries
formerly held by Atlantic. ACE serves approximately 481,000 customers in a
2,700 square mile area in southern New Jersey. Atlantic's 1997 operating
revenues and net income were $1,102.4 million and $74.4 million, respectively,
and its total assets were $2,723.9 million as of December 31, 1997.
 
  Conectiv is a registered holding company under the Public Utility Holding
Company Act of 1935, as amended (1935 Act). The 1935 Act imposes certain
restrictions on the operations of registered holding company systems. In
particular, new lines of businesses not otherwise approved under generally
applicable regulations cannot be undertaken without prior approval from the
SEC.
 
  For additional information about the Merger, refer to Management's
Discussion and Analysis of Financial Condition and Results of Operations
(MD&A) in Item 7 of Part II, Note 4 to the Company's 1997 Consolidated
Financial Statements included in Item 8 of Part II, and the registration
statement on Form S-4 dated December 26, 1996.
 
                                      I-1
<PAGE>
 
 Utility Regulation and Industry Restructuring
 
  To date, the Company's regulated electric and gas public utility operations
have provided the predominant share of the Company's net earnings. Delaware,
Maryland, and Virginia regulate the Company's retail electric sales within
areas for which the Company holds retail franchises (see "Retail Franchises"
on page I-18). Delaware also regulates the Company's retail gas sales within
the State. The Federal Energy Regulatory Commission (FERC) regulates the
transmission of electricity, the wholesale sale of electricity, and
interchange and other purchases and sales of electricity involving other
utilities.
 
  Prices charged to electric utility customers have historically been a
"bundled" price which includes the electricity production (supply) cost and
the delivery cost (transmission and distribution). State regulatory
commissions and legislatures throughout the country are considering or have
approved changes to laws and regulations governing the sale and pricing of
electricity. Generally, the supply component of the price charged to a
customer for electricity would be deregulated, and electric suppliers would
compete to supply electricity to customers. Competition is expected to reduce
gross margins earned from the supply of electricity. Customers would continue
to pay the local utility a regulated price for the delivery of the electricity
over the transmission and distribution system.
 
  In Delaware, the Delaware Public Service Commission (DPSC) submitted a
report to the Delaware House of Representatives on January 27, 1998,
recommending that Delaware customers be able to choose their electricity
supplier beginning twelve months after restructuring legislation is enacted.
On March 13, 1998, the DPSC sent draft legislation to the Delaware legislature
which would provide all Delaware electric retail customers the ability to
choose their electric supplier beginning on August 1, 1999. The draft
legislation also includes a provision that would allow the DPSC to delay the
start date of electric retail competition by up to 12 months. In Maryland, the
Maryland Public Service Commission (MPSC) issued an order on December 31,
1997, providing for the phase-in of electric retail competition over a three-
year period beginning July 1, 2000.
 
  In Virginia, the Virginia State Corporation Commission (VSCC) Staff advised
lawmakers that electric competition should be studied and tested over a five-
year period before deciding if retail competition should be implemented. Under
restructuring plans in New Jersey and Pennsylvania, all retail customers in
those states will be able to choose their electric suppliers by July 1, 2000
and January 1, 2001, respectively. See the MD&A in Item 7 of Part II for
additional information about the status of deregulation of the electric
utility industry in Delaware, Maryland, Virginia, New Jersey (which regulates
ACE's retail electric utility business), and Pennsylvania.
 
  The electric resale (wholesale) market is highly competitive due to federal
legislation enacted in 1992 which provided electric resale customers with a
choice of electric suppliers and gave the FERC the authority to order local
utilities to provide transmission service to other resale electricity
suppliers. In 1996, the FERC issued Order No. 888 which required electric
utilities to provide open access to their transmission systems under non-
discriminatory tariffs available to all wholesale sellers and buyers of
electricity. For information on the Company's resale business, refer to the
MD&A in Item 7 of Part II.
 
  For a discussion of deregulation of the Company's gas business, refer to
"Gas Business" on page I-10.
 
 Business Plans
 
  As deregulation of the electric utility industry continues to unfold, the
Company is moving ahead with its plan to become a prominent regional player by
being first into new markets that complement its utility business and by
enhancing its ability to serve additional customers outside of its traditional
borders. The Company is growing its businesses by building long-term customer
relationships, establishing the Conectiv brand name, marketing products and
services that complement the Company's core energy business, and serving more
customers in a larger geographic area. To accomplish these goals, the Company
has increased investments in marketing/branding programs, new businesses, and
infrastructure systems.
 
                                      I-2
<PAGE>
 
  On June 30, 1997, the Company launched a campaign to introduce the new
Conectiv brand and Conectiv's products and services. The campaign explained
that Conectiv is offering energy, telecommunications, heating and cooling, and
related services for homes and businesses. Customer response to the new
Conectiv brand name has been positive, as evidenced by name recognition and
the Company's success in gaining new customers in retail energy pilot
programs. The Company is marketing an array of products and services--energy,
local and long-distance telephone service, HVAC services, and other services--
under the Conectiv name. The Company plans to continue its advertising
campaigns and other support of the Conectiv brand name.
 
  Over the next year or two, the Company's earnings are expected to be
constrained by on-going start-up costs for new businesses, including
telecommunications and HVAC. After this start-up period, these investments are
expected to contribute to long-term consolidated earnings growth exceeding the
utility industry average.
 
  Conectiv's business plans will be carried out by its three business groups;
Conectiv Energy Delivery, Conectiv Energy Supply, and Conectiv Enterprises.
The business groups are aligned with customers' needs, markets, and the future
structure of the utility industry. The business groups are discussed below.
 
 Conectiv Energy Delivery
 
  Conectiv Energy Delivery will deliver electricity and gas to retail and
wholesale customers within its service territory. These delivery services are
structured into various forms of price-regulated offers, some including energy
supply, so that customers may choose the combination that provides the best
value. Customer satisfaction and loyalty is expected to remain high due to the
Company's reliable delivery systems, superior customer service, and
competitive cost and pricing structures.
 
 Conectiv Energy Supply
 
  Conectiv Energy Supply will manage the generating assets, bulk energy
marketing and trading activities, and the transition of those assets and
activities from a regulated to a competitive environment. Its principal
products are electric power and natural gas, supplemented by other fuels and
related energy management services. Its customers are bulk energy users and
retail aggregators in the region stretching from the Delmarva peninsula north
through New England and west to Ohio.
 
 Conectiv Enterprises
 
  Conectiv Enterprises is comprised of the following five start-up businesses:
Conectiv Communications, Inc. (CCI)--provides local and long distance
telephone services; Conectiv Energy--primarily sells energy in competitive
retail markets; Conectiv Services, Inc. (CSI)--provides a full range of HVAC
services; Conectiv Solutions LLC--provides customized solutions to customers'
energy needs; and Conectiv Thermal Systems, Inc. (currently Atlantic Thermal
Systems, Inc.)--provides custom thermal heating and cooling systems. These
businesses provide an opportunity to grow Conectiv's customer base throughout
the Mid-Atlantic region and strengthen its relationship with customers in its
traditional service territory. Conectiv Enterprises expects to incur operating
losses for the first year or two after the Merger due to start-up costs.
 
  For more detailed information about Conectiv Enterprises' businesses and
other nonutility businesses, refer to "Nonutility Businesses" on page I-13.
 
 
                                      I-3
<PAGE>
 
ELECTRIC BUSINESS
 
 Installed Capacity
 
  The megawatts (MW) of net installed summer electric generating capacity
available to the Company to serve its peak load as of December 31, 1997 is
presented below.
 
<TABLE>
<CAPTION>
                                                                           % OF
     INSTALLED SUMMER CAPACITY                                        MW   TOTAL
     -------------------------                                       ----- -----
     <S>                                                             <C>   <C>
     Coal-Fired..................................................... 1,145   34
     Oil-Fired......................................................   599   18
     Combustion Turbines/Combined Cycle.............................   511   15
     Nuclear........................................................   328   10
     Peaking Units..................................................   186    6
     Purchased Capacity.............................................   212    6
     Customer-owned Capacity........................................    57    2
                                                                     -----  ---
       Subtotal..................................................... 3,038   91
     Purchased PJM Interconnection Capacity Credit..................   290    9
                                                                     -----  ---
       Total........................................................ 3,328  100
                                                                     =====  ===
</TABLE>
 
  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
temporarily out of service for inspection, maintenance, repairs, or unforeseen
circumstances. See "Item 2--Properties" on page I-20 for a listing of net
installed generating capacity by station.
 
 Energy Supply Plan
 
  The objective of the Company's energy supply plan is to provide an adequate,
reliable, and competitively priced supply of electricity to customers, in
compliance with environmental laws and regulations. This plan, which is
updated annually, is based on forecasts of customers' demand for electricity
and reserve requirements of the Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM Interconnection). (See page I-5 for
information on the PJM Interconnection.) The plan emphasizes balance and
flexibility, and may be accelerated, slowed, or altered in response to
changing energy demands, fluctuating fuel prices, and emerging technologies.
The current plan closely matches customers' electricity requirements and
relies primarily on short-term power purchases to satisfy incremental needs.
Customer-oriented load management and conservation programs and new or
renovated power plants are also evaluated as incremental energy supply
sources.
 
 Reserve Margin
 
  The Company's peak load in 1997 was 2,852 MW on July 15th, compared to the
Company's previous historical peak demand of 2,602 MW which occurred on August
4, 1995. Because adequate generation was available at the time, these peaks do
not reflect full implementation of the Company's demand-side programs,
including the curtailment of large interruptible customers. The Company's PJM
Interconnection capacity obligation, including a reserve margin, is based on
normal weather conditions and full implementation of its demand-side programs,
which the Company estimates would have resulted in a peak of 2,706 MW in 1997.
Based upon this estimated peak and the Company's installed generating capacity
of 3,162 MW at the time of the peak, the Company's reserve margin would have
been 17%. The Company's reserve obligation varies from year to year, but
typically is around 18%. As discussed under "Purchased Power," the Company
uses short-term capacity-only purchases to satisfy any temporary capacity
deficiencies related to obligations under the PJM Interconnection agreement.
 
 
                                      I-4
<PAGE>
 
 Pennsylvania-New Jersey-Maryland Interconnection Association
 
  As a member of the PJM Interconnection, the Company's generation and
transmission facilities are operated on an integrated basis with other
electricity suppliers in Pennsylvania, New Jersey, Maryland, and the District
of Columbia. This power pool improves the reliability and operating economies
of the systems in the group and provides capital economies by permitting
shared reserve requirements on a group basis. The PJM Interconnection's
installed capacity as of December 31, 1997 was 57,216 MW. The PJM
Interconnection peak demand during 1997 was 49,408 MW on August 15th, which
resulted in a summer reserve margin of 14.8% (based on installed capacity of
56,731 MW on that date).
 
  On November 25, 1997, the FERC approved a restructuring plan for the PJM
Interconnection. The approved restructuring plan recognizes the PJM
Interconnection as an Independent System Operator (ISO) and provides open
access transmission service on a pool-wide basis.
 
  The FERC generally was satisfied that the PJM Interconnection restructuring
proposal met the governing and operational standards concerning formation of
an ISO, which were established by FERC in Order No. 888. The ISO will be
responsible for the system operations and regional transmission planning. In
addition, the FERC also approved operation of the PJM Interconnection's Power
Exchange by the PJM Interconnection.
 
  The FERC Order approved the plan's use of single transmission rates based on
the costs of the transmission system where the point of delivery is located.
There are eight such transmission systems within the PJM Interconnection
system. The FERC Order also approved locational marginal pricing for
transmission congestion costs. The price of transmission constrained
interfaces will be based on price differences on opposite sides of the
constraint.
 
  The PJM Interconnection ISO went into operation as of January 1, 1998.
Changes to the PJM Interconnection Open Access Transmission Tariff become
effective April 1, 1998.
 
 Purchased Power
 
  The Company makes economic short-term electricity purchases from several
sources in an effort to replace higher-cost generation. During 1997, purchases
were made from 46 utilities and power marketers.
 
  Long-term purchased power contracts also provide a portion of the Company's
electric capacity and energy. The Company has a contract to purchase 48 MW of
peaking capacity through May 2018 from the Delaware City Power Plant owned by
Star Enterprise (Star). The capacity obligations of Star and the Company under
the contract were suspended from October 1, 1996 until June 1, 2000. Delmarva
continues to purchase energy under the Star contract. In conjunction with its
acquisition of Conowingo Power Company (COPCO) in 1995, the Company is
purchasing from PECO Energy Company (PECO) 212 MW of base-load capacity and
associated energy, which increases to 279 MW by 2006 when the contract
expires. The Company is currently purchasing 155 MW of capacity under one-year
contracts from various suppliers. In addition, capacity-only purchases with a
term of less than one-year (135 MW as of December 31, 1997) are also made from
time-to-time to meet continuing PJM Interconnection capacity obligations.
 
 Demand Side Management Programs
 
  As of the end of 1997, the Company had enrolled in its demand-side programs
about 103,400 residential customers and about 1,800 commercial and industrial
customers who, in the aggregate, provide the Company with the ability to
reduce its peak by approximately 272 MW. The Company's portfolio of demand-
side management (DSM) programs has been restructured to address concerns about
the cost effectiveness and appropriateness of demand-side management resources
given the availability and cost of supply-side options and the various
uncertainties surrounding restructuring of the electric industry. The DPSC,
the MPSC, and the VSCC have all addressed the Company's concerns by approving
modifications to the Company's existing DSM programs.
 
                                      I-5
<PAGE>
 
 Nuclear Power Plants
 
  The Company's nuclear capacity is provided by Peach Bottom Atomic Power
Station (Peach Bottom) Units 2 and 3 and by Salem Nuclear Generating Station
(Salem) Units 1 and 2. The Company jointly owns these units, as tenants in
common, with PECO, ACE and Public Service Electric and Gas Company (PSE&G).
The Peach Bottom units are operated by PECO and have a combined summer
capacity of 2,186 MW, of which the Company is entitled to 164 MW (7.51%). The
Salem units are operated by PSE&G and have a combined summer capacity of 2,212
MW, of which the Company is entitled to 164 MW (7.41%).
 
  The operation of nuclear generating units is regulated by the Nuclear
Regulatory Commission (NRC). Such regulation requires that all aspects of
plant operation be conducted in accordance with NRC safety and environmental
requirements and that continuous demonstrations be made to the NRC that plant
operations meet applicable requirements. The NRC has the ultimate authority to
determine whether any nuclear generating unit may operate.
 
  For a discussion of the cycle of production, use and disposal of nuclear
fuel, see "Fuel Supply for Electric Generation" on page I-7.
 
  For a discussion of the Company's funding of its share of the estimated
future cost of decommissioning the Peach Bottom and Salem nuclear reactors,
see Note 7 to the Company's 1997 Consolidated Financial Statements included in
Part II, Item 8.
 
  As by-products of their operations, nuclear generating units, including the
Peach Bottom and Salem units, produce low level radioactive waste (LLRW). LLRW
is accumulated at on-site interim storage facilities with five-year storage
capacities and then shipped to a federally licensed disposal facility. Peach
Bottom and Salem are currently shipping LLRW to the disposal site located in
Barnwell, South Carolina.
 
  PECO has informed the Company that Pennsylvania is pursuing development of
its own LLRW disposal site via a volunteer plan option. PSE&G also has
informed the Company that New Jersey has introduced a volunteer siting process
to establish a LLRW disposal facility by the year 2000. To date, no volunteers
have been identified in either state. In New Jersey, the state agency
responsible for the volunteer siting program recommended to the Governor that
this effort be abandoned due to the lack of volunteer sites.
 
 Peach Bottom Units
 
  PECO has informed the Company that on July 17, 1997, the NRC issued its
periodic Systematic Assessment of Licensee Performance (SALP) Report on the
performance of activities at Peach Bottom for the period October 15, 1995 to
June 7, 1997. SALP reports rate licensee performance in four assessment areas:
Operations, Maintenance, Engineering and Plant Support. Ratings range from a
high of "1" to a low of "3". Peach Bottom received a rating of "1" in the
areas of Operations, Maintenance, and Plant Support, and "2" in Engineering.
PECO has informed the Company that the NRC observed excellent performance at
Peach Bottom during the assessment period. The NRC noted that station
management provided excellent oversight and control of engineering activities
throughout the period. The NRC also noted that while overall engineering
performance was good, there were several instances where operating procedures,
surveillances, and tests were not consistent with the design and licensing
bases.
 
  On October 3, 1997, Peach Bottom Station completed an all-time record 206
days of continuous dual unit operation.
 
  The Company was informed by PECO of crack indications that were found in
certain reactor vessel internal piping during the Fall 1997 refueling outage
for Peach Bottom Unit 3. PECO further advised that Unit 3 is being limited to
94% of normal electric output until permanent repairs are made during a March
1998 outage.
 
                                      I-6
<PAGE>
 
 Salem Units
 
  Salem Units 1 and 2 were removed from operation by PSE&G in the second
quarter of 1995 due to operational problems, and maintenance and safety
concerns. After receiving NRC authorization, PSE&G returned Unit 2 to service
on August 30, 1997. Due to degradation of a significant number of tubes in the
Unit 1 steam generators, PSE&G replaced the Unit 1 steam generators. The
Company has been informed by PSE&G that the NRC's Readiness Assessment Team
Inspection (RATI) of Salem Unit No. 1 was completed on February 20, 1998. The
inspection team concluded that Salem Unit 1 was ready to return to operation.
PSE&G expects Unit 1 will return to service in the second quarter of 1998,
subject to final NRC approval.
 
  On June 25, 1997, the NRC met to discuss, and update, its "Watch List"
plants. Salem Units 1 and 2 remained on the Watch List as a Category 2 plant.
A Category 2 plant is identified as having weaknesses that warrant increased
NRC attention until the licensee demonstrates a period of improved
performance.
 
  See Note 18 to the Company's 1997 Consolidated Financial Statements included
in Part II, Item 8, for information concerning (i) the Company's lawsuit
against Westinghouse Electric Corporation, the designer and manufacturer of
the Salem steam generators, (ii) settlement of the Company's lawsuit against
PSE&G with respect to Salem operations, (iii) the ratemaking treatment of the
PSE&G lawsuit settlement proceeds and replacement power costs incurred during
the outage, and (iv) the financial impact of the outages. Also see Item 3,
Legal Proceedings, for additional information concerning settlement of the
Company's lawsuit against PSE&G with respect to Salem operations.
 
  PSE&G has informed the Company that it is implementing the 1994 New Jersey
Pollutant Discharge Elimination System permit issued for Salem which requires,
among other things, water intake screen modifications and wetlands
restoration. In 1999, PSE&G must apply to renew the permit.
 
 Cost of Output for Load
 
  The following table sets forth the Company's annual generation output, fuel
cost per megawatt hour (MWh), and generation mix by unit fuel type for all
Company-owned facilities. Coal is the Company's predominant fuel.
Corresponding values for purchased power and for net interchange (purchases
less sales) as a member of the PJM Interconnection are also listed.
 
<TABLE>
<CAPTION>
   GENERATION                     1997           1996              1995
   ----------                -------------- ----------------  ----------------
                             1,000  $/      1,000   $/        1,000   $/
   UNIT FUEL TYPE             MWH   MWH  %   MWH    MWH   %    MWH    MWH   %
   --------------            ------ --- --- ------  ---  ---  ------  ---  ---
   <S>                       <C>    <C> <C> <C>     <C>  <C>  <C>     <C>  <C>
   Coal-fired...............  4,872  17  35  5,135   17   38   5,086   18   40
   Oil-fired................    950  33   7  1,246   34    9   1,191   28    9
   Nuclear..................  1,458   7  10  1,270    7    9   1,567    8   12
   Natural Gas..............  1,788  27  13  2,656   27   20   2,953   20   23
                             ------ --- --- ------  ---  ---  ------  ---  ---
     Total Company Genera-
      tion..................  9,068  19  65 10,307   20   76  10,797   18   84
<CAPTION>
   PURCHASES/INTERCHANGE
   ---------------------
   <S>                       <C>    <C> <C> <C>     <C>  <C>  <C>     <C>  <C>
   Purchases................  4,756  23  34  5,785   22   42   3,156   21   24
   Net Interchange..........     74 --    1 (2,444) (26) (18) (1,040) (29)  (8)
                             ------ --- --- ------  ---  ---  ------  ---  ---
     Total Output for Load.. 13,898  19 100 13,648   20  100  12,913   18  100
                             ====== === === ======  ===  ===  ======  ===  ===
</TABLE>
 
 Fuel Supply for Electric Generation
 
  The Company's electric generating capacity by fuel type is shown under
"Electric Business--Installed Summer Capacity," on page I-4. To facilitate the
purchase of adequate amounts of fuel at reasonable prices, the
 
                                      I-7
<PAGE>
 
Company contracts with various suppliers of coal, oil, and natural gas on both
a long- and short-term basis. The Company's long-term coal contracts generally
contain provisions for periodic and limited price adjustments, which are based
on current market prices. Oil and natural gas contracts generally are of
shorter term with prices determined by market-based indices.
 
 Coal
 
  Edge Moor Units 3 and 4, and the Indian River, Keystone and Conemaugh
generating stations are coal-fired. During 1997, 10% of the Company's coal
supply was purchased under short-term contracts (less than three years), 78%
under long-term contracts (up to ten years), and the balance on the spot
market. As of December 31, 1997, a maximum of 74% of the Company's coal
requirements were under supply contracts. The Company does not anticipate any
difficulty in obtaining adequate amounts of coal at reasonable prices.
 
 Oil
 
  Currently, 80% to 100% of the residual oil used in Edge Moor Unit 5 is
supplied under a two-year contract which expires in 1998. Any amount over 80%
of requirements may be purchased in the spot market. Natural gas is utilized
when economically feasible. The residual oil supply contract for the Vienna
Generating Station provides 90% to 100% of that station's requirements under a
two year contract that expires in 1999. Any amount over 90% of requirements
may be purchased in the spot market.
 
 Gas
 
  Natural gas, which is the primary fuel for the three combustion turbines
(CTs) at the Company's Hay Road site and a secondary fuel at Edge Moor Unit 5,
is supplied partly through contracts described under "Gas Operations" on page
I-11. Additional natural gas is purchased on a firm or interruptible basis
from suppliers such as marketers, producers, and utilities. The secondary fuel
for the Hay Road CTs is kerosene, which is purchased on the spot market.
 
 Nuclear
 
  The supply of fuel for nuclear generating units involves the mining and
milling of uranium ore to uranium concentrate, conversion of the uranium
concentrate to uranium hexaflouride gas, enrichment of the uranium
hexaflouride gas, conversion of the enriched gas to fuel pellets, and
fabrication of fuel assemblies. After spent fuel is removed from a nuclear
reactor, it is placed in temporary storage for cooling in a spent fuel pool at
the nuclear station site. The federal government has an obligation for the
transportation and ultimate disposal of the spent fuel, as discussed below.
 
  PSE&G has informed the Company that it has several long-term contracts with
uranium ore operators, converters, enrichers and fabricators to process
uranium ore to uranium concentrate to meet the currently projected
requirements for Salem. The Company has also been advised by PECO that it has
similar contracts to satisfy the fuel requirements of Peach Bottom 2 and 3.
Currently, there is an adequate supply of nuclear fuel for Salem and Peach
Bottom.
 
  In conformity with the Nuclear Waste Policy Act of 1982 (NWPA), PECO and
PSE&G have entered into contracts with the United States Department of Energy
(DOE) on behalf of the joint owners providing that the federal government
shall for a fee take title to, transport, and dispose of spent nuclear fuel
and high level radioactive waste from the Peach Bottom and Salem reactors. In
accordance with the NWPA, the Company pays the DOE one-tenth of one cent per
kWh of nuclear generation (net of station use) for the future cost of spent
nuclear fuel disposal. Under the NWPA, the DOE was to begin accepting spent
fuel for permanent off-site storage no later than January 1998. However, no
such repositories are in service or under construction. The DOE has stated
that it would not be able to open a permanent, high level nuclear waste
storage facility until 2010, at the earliest. On November 14, 1997, the U.S.
Court of Appeals ruled that the plaintiffs in Northern States Power
 
                                      I-8
<PAGE>
 
Co., et al vs. U.S. Department of Energy and the United States of America
"have a clear right to relief, and the Department has a clear duty to act."
The plaintiffs include 42 nuclear utilities and 61 states, state agencies and
municipal governments. The U.S. House of Representatives and the U.S. Senate
passed separate bills in 1997 authorizing construction of a temporary storage
facility which could accept spent nuclear fuel from utilities beginning in
2003. The Company cannot predict when or if the DOE will accept nuclear fuel
as no repository or other storage facility currently exists or is under
construction.
 
  In 1990, the NRC determined that spent nuclear fuel generated in any reactor
can be stored safely and without significant environmental impact in reactor
facility storage pools or in independent spent nuclear fuel storage
installations located at or away from reactor sites for at least 30 years
beyond the licensed life for operation (which may include the term of a
revised or renewed license). PECO has advised the Company that Peach Bottom
has adequate on-site temporary spent fuel storage capability until 2000 for
Peach Bottom Unit 2 and 2001 for Unit 3. PECO has also advised the Company
that it is constructing an on-site dry storage facility which is expected to
be operational in 2000 to provide additional storage capacity. PSE&G also has
advised the Company that, as a result of replacing the existing high density
racks in the spent fuel storage pools of Salem Units 1 and 2 with maximum
density racks, the availability of adequate spent fuel storage capacity is
conservatively estimated through 2012 for Unit 1 and 2016 for Unit 2.
 
  The Energy Policy Act of 1992 provided for creation of a Decontamination &
Decommissioning (D&D) Fund to pay for the future clean-up of DOE gaseous
diffusion enrichment facilities. Domestic utilities and the federal government
are required to make payments to the D&D Fund until 2008 or $2.25 billion,
adjusted annually for inflation, is collected. The liability accrued for the
Company's share of the D&D Fund was $5.9 million as of December 31, 1997. The
Company is recovering this cost through fuel adjustment clause revenues which
are discussed below.
 
 Electric Regulatory Matters
 
  There were no electric or gas base rate increases in 1997. See Note 4 to the
Company's 1997 Consolidated Financial Statements included in Part II, Item 8,
for information concerning expected base rate decreases related to the
Company's Merger with Atlantic.
 
  For information concerning regulatory matters associated with restructuring
of the electric utility industry, refer to the MD&A in Item 7 of Part II.
 
 Delaware Depreciation Filing
 
  On December 15, 1995, the Company filed an electric depreciation study in
Delaware based on 1994 plant balances. The Company requested an increase in
depreciation rates of $868,499 or a 0.18% revenue increase on a Delaware
retail basis. On April 28, 1997, the DPSC approved a settlement, which had a
de minimis effect on depreciation in the aggregate, but shifted $1 million of
Delaware retail electric depreciation expense from transmission and
distribution to production. Comparable treatment was obtained from the MPSC in
1996. A filing was made late in 1997 and is pending before the FERC to obtain
a comparable result for FERC wholesale electric depreciation expense.
 
 Electric Fuel Adjustment Clauses
 
  The Company's electric tariffs generally include fuel adjustment clauses
that permit the collection of the costs of fuel burned in generating stations
and the variable (energy) costs of purchased and net interchange power from
the Company's retail and resale electric customers. Fuel and energy costs are
deferred and charged to operations based on costs billed to customers under
the Company's electric tariffs. For the Delaware, Virginia, and FERC
jurisdictional customers, the clauses are based upon estimated annual fuel
costs. For the Maryland jurisdictional customers, the clause is based on
historical average costs. Supporting data is filed with and audited by the
various commissions and formal hearings are held at periodic intervals as
required by law. Fixed costs
 
                                      I-9
<PAGE>
 
(capacity or demand charges) associated with purchased power transactions
entered into for reliability reasons generally are subject to base rate
recovery. The present status or results of significant fuel rate issues are
discussed below. As of December 31, 1997, the Company had accrued fuel
disallowance reserves that adequately provide for disallowances of fuel costs
and penalties related to the issues discussed below.
 
  Both Delaware and Maryland have programs that assess the overall performance
of the Company's 15 major generating units. Under the DPSC's Power Plant
Performance Program (PPPP), the Company can receive financial rewards or
penalties, which will not exceed an estimated cap of $1.7 million in 1998. The
1996 and 1997 PPPP results are not material to the Company's financial
position or results of operations. If the Company does not meet an overall
system performance standard set by Maryland's Generating Unit Performance
Program, the MPSC can disallow certain fuel costs of units that operated below
their individual performance standards. The Company did not meet the 1996 or
1997 overall system standards due principally to the Salem outage.
 
  In May 1996 and May 1997, the Company filed applications with the VSCC for
revised fuel rates to be effective July 1996 and July 1997, respectively.
Similarly, the Company filed applications with the MPSC in June 1996, May
1997, and November 1997 for revised fuel rates to become effective in August
1996, July 1997, and January 1998. In all five filings, the Company proposed
that 50% of the replacement power costs associated with the Salem outage be
permitted on an interim basis until a full review of the outage occurs at a
future time. For all five filings the Company has received commission
approvals to collect the proposed interim rates. The rates are collected
subject to refund. The November 1997 MPSC filing is still progressing through
the standard Maryland fuel rate hearing process.
 
  In August 1997, the DPSC approved a settlement regarding the ratemaking
treatment of replacement power costs attributable to the Salem outages and $12
million of proceeds received from PSE&G for settlement of the Company's
lawsuit concerning Salem operations. The DPSC settlement provided for recovery
of approximately one-half of the replacement power costs and retention of two-
thirds of the PSE&G settlement payment by the Company's stockholders. The
Company's results of operations and financial position reflect the financial
impact of the Delaware settlement and comparable future settlements
anticipated in the Company's other jurisdictions. Under the terms of the
Delaware settlement, the Company will credit Delaware jurisdictional
customers' fuel rates by approximately $15.6 million. Comparable settlements
in the Company's other jurisdictions would result in an additional credit to
customer fuel rates of approximately $9.6 million. Deferred energy costs on
the Company's balance sheet were reduced by these anticipated credits to
customer fuel rates. In 1998, the Company expects approximately $25,000 per
day (total of all jurisdictions) of additional fuel expense disallowances for
each day Salem Unit 1 remains out of service. The Company currently expects
Salem Unit 1 to return to service in the second quarter of 1998.
 
  As the utility industry is restructured, fuel adjustment clauses are
expected to be eliminated, and any differences between energy costs and
related revenues will impact future earnings. To manage the price risk
associated with its unregulated, off-system energy sales, the Company is
currently engaging in commodity hedging activities, through both physical
transactions and energy derivatives. When energy sales are deregulated in the
Company's service territory, price risk is expected to be managed similarly
for these sales. As discussed, under "Gas Regulatory Matters" the Company has
proposed to the DPSC a gas price hedging/risk management program with respect
to gas supply for regulated customers.
 
GAS BUSINESS
 
 Deregulation
 
  Effective April 1, 1996, natural gas pricing and service options offered to
customers within the Company's service territory were restructured under a
DPSC-approved settlement. The settlement unbundled and separately priced
several services, enabling large and medium volume commercial and industrial
customers to purchase only the services that they need. These customers may
purchase gas from the Company, or directly from other suppliers and make
arrangements for transportation to their facilities. The Company's
transportation customers
 
                                     I-10
<PAGE>
 
pay a fee, which may be either fixed or negotiated, for the use of the
Company's gas transmission and distribution facilities.
 
  The settlement mentioned above also authorized off-system gas sales and
other "nonjurisdictional merchant sales services." Earnings from gas sales
which are off the Delmarva Peninsula and do not use the Company's gas system
assets benefit the Company's stockholders. For other off-system gas sales and
nonjurisdictional merchant sales services, the Company's stockholders retain
20% of the margin (revenues net of fuel costs) earned, and the remaining 80%
reduces fuel rates charged to firm customers.
 
  On July 18, 1997, the Delaware Association of Alternative Energy Providers,
Inc. ("DAAEP") filed a complaint with the DPSC seeking to require the Company
to open the balance of its retail natural gas supply market to competition.
The Company has entered into discussions with the parties to the complaint
case, and anticipates that such discussions may result in a proposal to begin
the availability of gas supplier choice to the Company's residential customers
and the balance of its commercial and industrial customers.
 
 Gas Operations
 
  The Company purchases gas supplies from marketers and producers under spot
market, short-term, and long-term agreements. As shown in the table below, the
Company's maximum 24-hour system capability, including natural gas purchases,
storage deliveries, and the emergency sendout capability of its peak shaving
plant, is 206,960 thousand cubic feet (Mcf).
 
<TABLE>
<CAPTION>
                                                    NUMBER OF EXPIRATION  DAILY
                                                    CONTRACTS   DATES      MCF
                                                    --------- ---------- -------
   <S>                                              <C>       <C>        <C>
   Supply..........................................      3    1998-2001   33,816
   Transportation..................................      4         2004   83,786
   Storage.........................................      4    1998-2004   44,358
   Local Peak Shaving (emergency capability).......                       45,000
                                                                         -------
     Total.........................................                      206,960
                                                                         =======
</TABLE>
 
  The Company experienced an all-time daily peak in combined firm sales and
transportation sendout of 158,810 Mcf on January 17, 1997 during milder
weather than system design weather conditions of 0(degrees) Fahrenheit. The
Company's peak shaving plant liquefies, stores, and re-gasifies natural gas in
order to provide supplemental gas in the event of pipeline supply shortfalls
or system emergencies.
 
  During 1997, the average production cost of all gas sold to on-system
customers was $4.30 per Mcf, compared with $3.59 and $2.95 per Mcf in 1996 and
1995, respectively.
 
 Gas Regulatory Matters
 
  Similar to the Company's Delaware electric fuel adjustment clause, a gas
cost rate clause provides for the billing of gas costs to the Company's
regulated gas customers based on estimated annual gas costs. Gas costs for
regulated, on-system customers are deferred and charged to operations based on
costs billed to customers under the gas cost rate clause.
 
  In accordance with the terms of a settlement agreement with the DPSC, the
Company has proposed a gas price hedging/risk management program with respect
to gas supply for regulated customers. The program would seek to limit
regulated customers exposure to commodity price uncertainty. The Company
expects the DPSC will approve its proposal, or modified version thereof,
during the second quarter of 1998. The Company proposed that any costs or
benefits of the program be included in the gas cost rate clause, resulting in
no effect on the Company's earnings.
 
 
                                     I-11
<PAGE>
 
OTHER REGULATORY MATTERS
 
 Special Contract Rate Tariffs
 
  As previously reported, the Company has the ability to enter into negotiated
contracts with retail electric customers in Maryland, and retail electric and
natural gas customers in Delaware. In addition, in late 1996 and early 1997,
the Company received approval of "Real Time Pricing" (RTP) tariffs in Maryland
and in Delaware, respectively. The Company currently has an approved
experimental RTP tariff in Virginia. Such RTP tariffs provide additional
flexibility in providing pricing and service to certain large customers.
 
 Cost Accounting Manual/Code of Conduct
 
  The Company has cost allocation and direct charging mechanisms in place to
ensure that there is no cross-subsidization of its competitive activities by
regulated utility activities. At the end of February 1997, the Company filed
an application requesting the DPSC to approve a Cost Accounting Manual (CAM),
which describes these accounting procedures. The Company's CAM filing also
included a proposed Code of Conduct (Code) governing the Company's regulated
utility activities and its competitive activities.
 
  In response to Joint Resolutions passed by the General Assembly in mid-1997,
the DPSC issued an order on January 27, 1998 in the CAM and Code proceeding.
The DPSC adopted both the CAM and Code, with certain modifications,
conditioned upon the parties agreeing to auditing procedures and submitting
them to the DPSC by March 16, 1998. The major recommendations of the DPSC were
as follows: no structural or operational separation required; no ban on shared
resources; no ban of, or fees on, employee transfers at this time; no capital
restrictions; no prohibition on use of a common brand name or on disclosures
of affiliation with the utility; and no prohibition on sales leads, joint
offerings and promotions (all of which will be accompanied by proper
disclosures and recordkeeping to monitor compliance with proper disclosures).
No utility customer information may be used for any nonutility purpose by the
Company's competitive businesses or by third parties without the customer's
express written consent. Telephone numbers for regulated and competitive
activities must be separate and, starting July 1, 1998, competitive businesses
cannot include charges in the utility bill unless access is also provided to
third parties. Extensive reporting and compliance procedures were adopted and
additional internal and external auditing will be required. The issuance of
this order also terminates the prior limitation imposed by the General
Assembly on the growth in new employees in the energy services businesses.
 
  In response to a claim brought by the Delaware Alliance for Fair Competition
during the pendency of that proceeding, on November 18, 1997 the DPSC issued
an order finding that the Company was in violation of the Code filed in
February 1997 (the interim Code the Company was operating under until the
proceeding was completed). The DPSC directed the Company to require employees
to notify customers of the existence of third-party competitors regardless of
how the interaction between the customer and employee arose. This meant that
even when in contact with a customer on nonutility business, employees had to
inform customers that other competitors could provide the same service. The
Company filed an appeal and request to stay the order with Kent County
Superior Court on November 25, 1997. The Court denied the motion for a stay on
December 22, 1997. The appeal is proceeding in the normal course. The interim
Code has been superseded by the Code adopted in the DPSC's January 27, 1998
order, and the third-party competitor notification requirement imposed by the
Commission in its November 1997 order has been eliminated. The outcome of the
appeal is not expected to have a material effect on the Company's results of
operations or financial position.
 
  On January 24, 1997, the MPSC instituted an investigation, in the form of a
quasi-legislative proceeding, into "affiliated transactions and affiliated
standards of conduct" for all companies providing gas or electric service in
Maryland, including the Company. On February 23, 1998, the MPSC issued an
order, the implications of which have not yet been fully analyzed. The order
provides for two sets of Code of Conduct provisions applying to Maryland
utilities and their competitive businesses: one applying to energy merchant
activities, and
 
                                     I-12
<PAGE>
 
one applying to all other competitive activities. For affiliated companies
that are not selling electricity or natural gas, the Code provisions adopted
by the MPSC impose few requirements, primarily involving non-discriminatory
and non-preferential provision of utility services to the competitive business
affiliated with the utility and that business's customers. For affiliated
companies that are selling electricity or natural gas on a competitive basis
to customers (i.e., the energy merchant function), the Code adopted by the
MPSC imposes additional requirements, including restricting joint sales calls
to circumstances where the customer has made a request for a joint call;
prohibiting joint promotions unless such promotions are offered to other
competitors on the same terms and conditions; prohibiting the provision of
sales leads from the utility to the merchant affiliate, and prohibiting the
use of utility customer information without the informed written consent of
the customer (although the MPSC order does seem to allow the use of mailing
lists obtained from the utility information database). While the MPSC found
that full structural separation between a utility and its competitive
businesses is not necessary, the order requires separation of the utility's
and its affiliates' operational and managerial employees, and prior MPSC
approval of other types of employees which will provide services to both
utility and competitive businesses. Furthermore, the MPSC order did not
prohibit the use of a common name or logo, but requires a prominent disclaimer
anytime a common name or logo is used, stating that the affiliate and utility
are separate entities.
 
  The full financial implications of this MPSC order are uncertain. However,
some general observations about its potential consequences can be made. The
requirement that separate operational and managerial employees be maintained
could have several impacts, including implications about the way the Company
and the Conectiv system of companies are organized, and the ability of the
Company to capture economies of common management and efficient deployment of
personnel without needlessly duplicating personnel functions to meet a
"separation" requirement. The prohibition on joint promotions may impact the
Company's one-stop-shopping Conectiv brand campaign. Moreover, the Company is
trying to determine the implications of the Order regarding the Conectiv brand
campaign and the use of the Conectiv logo on utility vehicles arising from the
requirement that a disclaimer be prominently displayed any time a common name
or logo are used.
 
  One or more parties to the case may request rehearing or appeal the order
and the ultimate outcome cannot be predicted. The Company has not yet
determined what, if any, such action to take.
 
 Virginia Affiliates Act
 
  In Virginia, certain types of transactions between the Company and its
affiliates may require the prior approval of the VSCC under the Virginia
Affiliates Act. Exemptions from this approval requirement are available
pursuant to a recently-enacted Affiliates Act amendment, but none, to the
Company's knowledge, have yet been granted by the VSCC. The Company has filed
applications with the VSCC under the Affiliates Act for exemption from the
approval requirement, or approval of transactions between the Company and its
affiliates, and, except for applications covering the service company for
Conectiv, post-Merger and certain past transactions, all of these applications
have been approved.
 
NONUTILITY BUSINESSES
 
  The Company's principal current and planned nonutility businesses are
discussed below. These nonutility businesses are conducted through wholly
owned subsidiaries, a joint venture, and operating divisions of the Company.
 
 Conectiv Communications, Inc.
 
  Enactment of the Telecommunications Act of 1996 (the Act) provided an
opportunity for CCI to become a full service telecommunications company,
marketing local and long distance services as well as carrier, network, and
data services. The Act was designed to bring the benefits of competition to
the local telephone market that residential and business customers already
enjoyed for long distance service. In effect, the law is intended to put an
end to the long history of monopoly service in the local telephone market. The
law requires an incumbent local exchange carrier (ILEC), such as Bell
Atlantic, to interconnect its local network with the equipment of a
 
                                     I-13
<PAGE>
 
competitive local exchange carrier (CLEC) such as CCI; provide CLECs access to
any elements of the ILEC network that a CLEC needs to provide service; resell
retail ILEC services to CLECs at a wholesale rate; and permit CLECs to locate
telecommunications equipment on the ILEC's premises.
 
  During 1997, CCI took a variety of steps toward becoming a full-service
telecommunications provider in the region which includes the State of
Delaware, Southeastern Pennsylvania, Southern New Jersey and the Eastern Shore
of Maryland. The Company negotiated an interconnection agreement with Bell
Atlantic and applied for necessary regulatory approvals. To fulfill its
business plan of being a facilities-based telecommunications provider, CCI
began construction of telecommunications facilities to connect the existing
fiber optic network (acquired from Delmarva Power & Light Company) with Bell
Atlantic central offices. To date CCI has built to eight Bell Atlantic central
offices in Delaware, and has physically collocated its own telecommunications
equipment in those Bell Atlantic facilities. On November 17, 1997, CCI began
providing local, regional, and long distance service to business and
residential customers in Delaware and Southeastern Pennsylvania. This service
is provided initially by reselling Bell Atlantic service obtained at a
wholesale discount. These customers will migrate to facilities-based CCI
service as soon as facilities are constructed. Service in Southern New Jersey
and the Eastern Shore of Maryland will commence in 1998.
 
  CCI's strategy of providing facilities-based telecommunications service will
require capital expenditures to further expand CCI's existing fiber optic
network over the next several years. For information concerning the assets
owned by CCI as of December 31, 1997, see Item 2, Properties.
 
  CCI currently operates in a duopoly local service environment with Bell
Atlantic. Competition may increase from other telecommunications companies
seeking to establish a local service presence in the region.
 
  The regulations within each state under which CCI operates requires the
filing of a general tariff detailing the pricing and descriptions of each
service offering. These tariffs are based on a market pricing system rather
than the traditional cost-of-service based regulation model.
Telecommunications tariff filings have been made in and approved by the states
of Delaware and Pennsylvania for the provision of local telephone services.
Tariff filings have also been made with the Federal Communications Commission
for the provision of domestic and international long distance services. These
tariff filings have been approved, authorizing CCI to provide retail local and
long distance phone services. In the first quarter of 1998, the Company will
file tariffs for similar local retail authority in the states of New Jersey
and Maryland. The New Jersey filing is considered an informational filing and
does not require any action prior to offering service in the state.
 
 Conectiv Energy
 
  Conectiv Energy currently sells competitive natural gas, electricity, and
energy related products and services to residential and commercial customers
in the Mid-Atlantic region. (Conectiv Energy was operated as a division of the
Company as of December 31, 1997.) Retail customers' favorable response to the
Conectiv brand has been a key to acquiring new retail customers in competitive
markets. In 1997, Conectiv Energy obtained approximately 7,700 gas customers
and 32,200 electric customers. The costs associated with acquiring new
customers, timing of market entry, gross margins on sales, and regulations
governing the transition to competition are factors critical to this business.
 
 Conectiv/CNE Energy Services, LLC
 
  In September 1997, the Company announced that through its Conectiv Energy
Supply group it formed a joint venture with Connecticut Energy Corporation to
sell natural gas, electricity, fuel oil, and other energy-related products and
services in New York and New England. The new energy marketing and sales
company is operating under the name Conectiv/CNE Energy Services, LLC.
 
 Conectiv Services, Inc.
 
  CSI is a full-service HVAC business operating in the Mid-Atlantic region.
CSI provides commercial customers with mechanical HVAC/piping construction and
installation, design services, sheet metal fabrication,
 
                                     I-14
<PAGE>
 
preventative maintenance and repair services. Residential offerings include
HVAC installation, maintenance, repair and related plumbing services. The
regional HVAC and plumbing industry is highly competitive, fragmented, and
rapidly consolidating. The sales and earnings of HVAC businesses are affected
by weather conditions. CSI originated through acquisitions of established
businesses, and its future growth will be impacted by the availability of
acquisition candidates and any regulatory limits imposed on market access.
 
 Conectiv Solutions LLC
 
  The Company and Atlantic established Conectiv Solutions LLC (Conectiv
Solutions), in order to jointly conduct the business activities described
herein. Conectiv Solutions is building close customer relationships by
understanding individual customers' energy-related needs, and meeting those
needs with customized, turnkey solutions. Conectiv Solutions provides large
commercial and industrial customers, primarily within the Delaware Valley
region, with energy and energy-related products and services. These products
and services are built around occupant comfort, reliability of systems, and
cost containment and reduction. Conectiv Solutions provides energy efficiency
services, power systems consulting, custom on-site energy systems' services
and construction, telecommunication services, and energy procurement. In
addition, Conectiv Solutions offers the HVAC and telecommunications services
provided by CSI and CCI.
 
 Conectiv Thermal Systems, Inc.
 
  Atlantic Thermal Systems (ATS), owned by Atlantic prior to the Merger, will
become Conectiv Thermal Systems, Inc. (CTS) shortly after the Merger. CTS will
provide products and services offered by ATS prior to the Merger, including
heating, cooling and related energy services to large commercial and
industrial customers. In conjunction with these services, ATS develops,
finances, constructs, owns and operates thermal energy production and
distribution plants. Targeted customer groups include gaming/hotel resort
complexes, colleges and universities, health care facilities and industrial
complexes. ATS offers a highly customized service tailored to meet each
customer's specific energy needs. Through ATS' energy outsourcing programs,
customers are able to reduce their capital expenditures on non-strategic
assets, realize energy cost savings, and free themselves from energy matters,
which are incidental to their principal business activities.
 
 Delmarva Capital Investments, Inc.
 
  Delmarva Capital Investments, Inc. (DCI) is primarily involved in power
plant operating services, real estate activities, and leveraged equipment
leases. As part of the Company's intent to divest of non-strategic assets, a
subsidiary of DCI sold its landfill and waste-hauling operations in 1997, as
discussed in Note 5 to the Consolidated Financial Statements included in Item
8 of Part II.
 
 Atlantic Energy Enterprises, Inc.
 
  The nonutility businesses owned before the Merger by Atlantic Energy
Enterprises, Inc. (AEE--previously a nonutility subsidiary of Atlantic) are
now held by Conectiv. These nonutility businesses include cogeneration power
projects, real estate, leveraged leases, investments in energy-related
technology growth companies, telecommunications, and gas marketing.
 
CAPITAL SPENDING AND FINANCING PROGRAM
 
  For financial information concerning the Company'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 10 to 13 to the Company's 1997
Consolidated Financial Statements, included in Item 8 of Part II.
 
  The issuance of First Mortgage Bonds by the Company is limited by a covenant
in its Mortgage and Deed of Trust dated October 1, 1943, as supplemented and
amended (the Mortgage), with The Chase Manhattan Bank, as successor Trustee,
requiring the pro forma ratio of consolidated earnings to interest on First
Mortgage Bonds
 
                                     I-15
<PAGE>
 
for any twelve consecutive months within the fifteen months preceding such
issuance to be not less than 2.00. This ratio for the twelve months ended
December 31, 1997 was 6.02. The issuance of First Mortgage Bonds also is
limited by the Mortgage to 60% of the bondable value of property additions.
 
  Certain provisions in the Company's Restated Certificate and Articles of
Incorporation limit the issuance of preferred stock. The most restrictive of
these provisions requires that the pro forma ratio of consolidated earnings to
fixed charges and preferred stock dividend requirements combined for any
twelve consecutive months within the fifteen months preceding such issuance of
preferred stock be 1.50 or greater. This ratio was 2.03 for the twelve months
ended December 31, 1997.
 
  The Company's ratios of earnings to fixed charges and earnings to fixed
charges and preferred stock dividends under the SEC Methods for 1993-1997 are
shown below.
 
<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                                       ------------------------
                                                       1997 1996 1995 1994 1993
                                                       ---- ---- ---- ---- ----
   <S>                                                 <C>  <C>  <C>  <C>  <C>
   Ratio of Earnings to Fixed Charges (SEC Method).... 2.83 3.33 3.54 3.49 3.47
   Ratio of Earnings to Fixed Charges and Preferred
    Stock Dividends (SEC Method)...................... 2.63 2.83 2.92 2.85 2.88
</TABLE>
 
  Under the SEC Method, earnings, including AFUDC, have been computed by
adding income taxes and fixed charges to net income. Fixed charges include
gross interest expense, the estimated interest component of rentals, and
dividends on preferred securities of a subsidiary trust. For the ratio of
earnings to fixed charges and preferred stock dividends, preferred stock
dividends represent annualized preferred stock dividend requirements
multiplied by the ratio that pre-tax income bears to net income.
 
ENVIRONMENTAL MATTERS
 
  The Company and its subsidiaries are subject to various federal, regional,
state, and local environmental regulations, including air and water quality
control, oil pollution control, solid and hazardous waste disposal, and
limitation on land use. Permits are required for the Company's construction
projects and existing facilities. The Company and its subsidiaries have
incurred, and expect to continue to incur, capital expenditures and operating
costs because of environmental considerations and requirements. The Company
and its subsidiaries are engaged in a continuing program to assure compliance
with the environmental standards adopted by various regulatory authorities.
 
 Construction Expenditures
 
  During the years 1998-2002, construction expenditures for compliance with
environmental regulations, primarily air quality regulations, are estimated at
$116 million for Conectiv, of which $105 million pertains to the Company.
These amounts are included in the estimated capital requirements shown in
"Liquidity and Capital Resources" of the MD&A included in Item 7 of Part II.
 
 Air Quality Regulations
 
  The federal Clean Air Act requires utilities and other industries to
significantly reduce emissions of air pollutants such as sulfur dioxide
(SO/2/) and oxides of nitrogen (NOx). Title IV of the Clean Air Act, the acid
rain provisions, established a two-phase program which mandated reductions of
SO/2/ and NOx emissions from certain utility units by 1995 (Phase I) and
required other utility units to begin reducing SO/2/ and NOx emissions in the
year 2000 (Phase II). Emission reductions at the jointly-owned Conemaugh Power
Plant (a Phase 1 unit), have been achieved through installation and operation
of flue gas desulfurization (FGD) systems and low-NOx burners. The remainder
of the Company's wholly- and jointly-owned fossil-fuel units are expected to
meet phase II emission limits through a combination of fuel switching, and
SO/2/ allowance trading.
 
                                     I-16
<PAGE>
 
  In addition to complying with Title IV, as major sources of NOx emissions,
Company facilities must comply with Title I of the Clean Air Act, the ozone
nonattainment provisions, which require states to promulgate Reasonably
Available Technology (RACT) regulations for existing sources located within
ozone nonattainment areas or within the Northeast Ozone Transport Region
(NOTR). The Company's facilities in Delaware and Maryland are in the NOTR. As
part of the Company's original RACT Proposals submitted to Delaware and
Maryland in 1993 and 1994, low NOx burner technology on four major generating
units have been installed. In December 1996, the Company amended its Delaware
NOx control plans to include installation of low NOx burner technology in 1998
and 1999 on two additional units (Indian River Units 1 and 2) to meet both
Title I and Title IV NOx control requirements. The Company's RACT proposals
have yet to receive final regulatory approval by Delaware and Maryland.
Consequently, costs in addition to those already expended and budgeted, may be
incurred in order to comply with the RACT Regulations.
 
  Additional "post-RACT" NOx emission limitation regulations are being pursued
by states in the NOTR. On February 1, 1998, Delaware promulgated post-RACT NOx
control regulations on certain sources, including the Company's major
generating facilities. Attainment of summer seasonal emission reductions of up
to 65% below 1990 levels is required by May 1999 through reduced emissions
(e.g. through the installation of control technology, operating changes, or
fuel switches) or the procurement of NOx emission allowances. Primarily due to
the short time period in which compliance is required, the Company has
appealed the final Delaware regulations. The Company is preparing a compliance
plan which is expected to include the procurement of NOx allowances and/or
installation of control technology on certain generating units. The Company
has budgeted anticipated capital costs of approximately $14 million for
installing such technology. Maryland has yet to adopt a post-RACT regulation,
but it is anticipated that the imposition of controls on the Company's
Delaware units, and the availability of an allowance trading program, will
provide relief to ensure compliance at the Company's Maryland facilities.
 
  In addition to the implementation of RACT and post-RACT controls, additional
summer seasonal NOx controls, commensurate with reductions up to 85% below
baseline years, are presently being considered by the NOTR states and the
United States Environmental Protection Agency (USEPA), for implementation in
the 2003 time frame. As draft regulations have yet to be considered for these
proposals, the Company cannot predict the additional potential operating and
capital cost impacts that may be associated with these initiatives.
 
  On July 16, 1997, the USEPA promulgated final regulations which would amend
the National Ambient Air Quality Standards (NAAQS) for particulate matter and
ozone. The proposal calls for changing the concentration limits, averaging
times, and form of the health-based and welfare-based ozone standards as well
as the establishment of a new fine particulate matter standard (PM/2/./5/-
particulate matter with a mean particle diameter of 2.5 microns). Following a
period of several years to measure and gather air quality monitoring data, the
USEPA may need to reclassify certain air quality control regions. Existing
sources that cause or contribute to nonattainment regions will likely be
subject to additional regulatory requirements, including possible emission
reductions. New sources in nonattainment areas will also be subject to
additional control requirements and will be required to offset their
emissions. Because power plants emit certain air pollutants which could
contribute to the formation of ambient ozone and PM/2/./5/, the Company's
power plants may be required to be retrofitted with additional air pollution
controls in the future. A number of affected parties, including several that
represent the Company's interests, are litigating the standards. It is not
presently possible to predict the potential impacts associated with
implementation of these standards on the Company's facilities.
 
 Water Quality Regulations
 
  The federal Clean Water Act requires that the cooling water intake and
discharge systems at the Edge Moor and Indian River Power Plants minimize
adverse environmental impact. In addition, in 1993, DNREC promulgated
increased restrictions on thermal discharge. Between 1976 and 1979 the Company
submitted to DNREC the results of environmental impact studies which
demonstrated compliance with the Clean Water Act. DNREC is in the process of
requiring the Company to update these studies to determine if the intake and
 
                                     I-17
<PAGE>
 
discharge systems continue to be in compliance. The studies are expected to
take one to two years and begin in spring 1998 and 1999 for the Indian River
and Edgemoor plants, respectively. If it should be determined that the systems
are not in compliance with the Clean Water Act and/or the revised Delaware
thermal limits, construction expenditures to modify the systems could cost up
to approximately $46 million.
 
 Hazardous Substances
 
  The disposal of Company-generated hazardous substances can result in costs
to clean up facilities found to be contaminated due to past disposal
practices. Federal and state statutes authorize governmental agencies to
compel responsible parties to clean up certain abandoned or uncontrolled
hazardous waste sites. The Company's exposure is minimized by adherence to
environmental standards for Company-owned facilities and through a waste
disposal contractor screening and audit process.
 
  As of December 31, 1997, the Company's other accrued liabilities included $2
million for clean-up and other potential costs related to federal and state
superfund sites. The Company does not expect future costs to have a material
effect on the Company's financial position or results of operations.
 
 Other Environmental Matters
 
  Another environmental issue with potential impact on the electric utility
industry is the emission of "greenhouse gases" such as carbon dioxide,
released as a byproduct of the combustion of fossil fuels in the electric
generating process. The release of such substances has been associated with
the potential for global warming. In December 1997, delegates from more 160
countries adopted a treaty that commits industrialized countries to binding
targets for greenhouse gas reductions (Kyoto Protocol). According to the terms
of the Kyoto Protocol, the U.S. would reduce emissions by 7% relative to 1990
levels by the 2008 to 2012 time period. The Kyoto Protocol is only binding on
individual countries after it is ratified by their governments. The Company
cannot predict whether or not the U.S. will ratify the Kyoto Protocol, or if
related regulations affecting the utility industry will be written and
implemented.
 
RETAIL FRANCHISES
 
  The franchises discussed below could be impacted by legislation
restructuring the electric utility industry. For information concerning
restructuring of the electric utility industry see "Utility Regulation and
Industry Restructuring" in Part I and the MD&A in Item 7 of Part II.
 
  The Company holds franchises, which for the most part are perpetual, for
providing retail electric and gas service in certain designated areas and
municipalities in the State of Delaware, pursuant to legislative enactments of
the General Assembly and to consents, orders, and permits from various public
bodies and municipal authorities.
 
  The Company holds franchises, which for the most part are perpetual, for
providing retail electric service in all of its assigned territories in the
State of Maryland, pursuant to Maryland law and appropriate orders of the
MPSC.
 
  The Company holds perpetual franchises for providing retail electric service
in certain designated areas of the Commonwealth of Virginia, pursuant to
appropriate orders of the VSCC under the Virginia Public Utility Facilities
Act. It also has franchises for the rendition of retail electric service
within other municipalities which are not perpetual, but which are expected to
be renewed at their expiration dates.
 
  In Pennsylvania, the Company holds limited certificates of public
convenience from the Pennsylvania Public Utility Commission to own and
exercise rights with respect to its interests in certain electric generating
stations and transmission lines located in the state.
 
                                     I-18
<PAGE>
 
NUMBER OF EMPLOYEES
 
  The number of full time employees of the Company at December 31, 1997 was
3,196.
 
  A total of 1,373 employees are represented by the International Brotherhood
of Electrical Workers Locals 1238 (Northern) and 1307 (Southern) whose
contracts with the Company expire on February 1, 2000 and June 25, 1998,
respectively.
 
EXECUTIVE OFFICERS OF THE REGISTRANT
 
  The names, ages, and positions of all of the executive officers of the
Company as of December 31, 1997, are listed below, along with their business
experiences during the past five years. Officers are elected annually by the
Board of Directors at the meeting of directors immediately following the
Annual Meeting of Stockholders. 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 THE REGISTRANT
                           (AS OF DECEMBER 31, 1997)
 
<TABLE>
<CAPTION>
                                             BUSINESS EXPERIENCE
    NAME, AGE AND POSITION                   DURING PAST 5 YEARS
    ----------------------                   -------------------
<S>                            <C>
Howard E. Cosgrove, 54,        Elected 1992
 Elected 1992.................
 Chairman of the Board,
 President, and Chief
 Executive Officer and
 Director
Barry R. Elson, 56............ Elected 1997. Executive Vice President, Cox
 Executive Vice President      Communications, Inc., Atlanta, Georgia, from
                               1995 to 1996. Senior Vice President, Cox
                               Enterprises/Cox Communications, Inc., Atlanta
                               Georgia, from 1984 to 1995.
Thomas S. Shaw, 50............ Elected 1997. Senior Vice President from 1992 to
 Executive Vice President      1997.
Joseph W. Ford, 52............ Elected 1995. Director Corporate Re-Engineering,
 Senior Vice President         Sales & Marketing Worldwide, Digital
                               Corporation.
                               Boston Massachusetts, from 1993 to 1994.
                               Director Business Development United States,
                               Digital Corporation, Boston, Massachusetts from
                               1992 to 1993.
Barbara S. Graham, 49......... Elected 1996. Senior Vice President, Treasurer
 Senior Vice President and     and Chief Financial Officer from 1994 to 1997.
 Chief Financial Officer       Vice President and Chief Financial Officer from
                               1992 to 1994.
Ralph E. Klesius, 55.......... Elected 1992.
 Senior Vice President
James P. Lavin, 50............ Elected 1993. Comptroller-Corporate and Chief
 Comptroller and Chief         Accounting Officer from 1989 to 1993.
 Accounting Officer
</TABLE>
 
                                     I-19
<PAGE>
 
ITEM 2. PROPERTIES
 
  Substantially all utility plants and properties of the Company are subject
to the lien of the Mortgage under which the Company's First Mortgage Bonds are
issued.
 
  The Company's electric properties are located in Delaware, Maryland,
Virginia, Pennsylvania, and New Jersey. The following table sets forth the net
installed summer electric generating capacity available to the Company to
serve its peak load as of December 31, 1997.
 
<TABLE>
<CAPTION>
                                                                NET INSTALLED
                                                                  CAPACITY
              STATION                       LOCATION             (KILOWATTS)
              -------                       --------            -------------
   <S>                           <C>                            <C>
   COAL-FIRED
     Edge Moor.................. Wilmington, DE................     252,000
     Indian River............... Millsboro, DE.................     767,000
     Conemaugh.................. New Florence, PA..............      63,000(A)
     Keystone................... Shelocta, PA..................      63,000(A)
                                                                  ---------
                                                                  1,145,000
                                                                  ---------
   OIL-FIRED
     Edge Moor.................. Wilmington, DE................     446,000
     Vienna..................... Vienna, MD....................     153,000
                                                                  ---------
                                                                    599,000
                                                                  ---------
   COMBUSTION TURBINES/COMBINED
    CYCLE
     Hay Road................... Wilmington, DE................     511,000
                                                                  ---------
   NUCLEAR
     Peach Bottom............... Peach Bottom Twp., PA.........     164,000(A)
     Salem...................... Lower Alloways Creek Twp., NJ.     164,000(A)
                                                                  ---------
                                                                    328,000
                                                                  ---------
   PEAKING UNITS
     Christiana................. Wilmington, DE................      45,000
     Edge Moor.................. Wilmington, DE................      13,000
     Madison Street............. Wilmington, DE................      11,000
     West....................... Marshallton, DE...............      15,000
     Delaware City.............. Delaware City, DE.............      16,000
     Indian River............... Millsboro, DE.................      17,000
     Vienna..................... Vienna, MD....................      17,000
     Tasley..................... Tasley, VA....................      26,000
     Salem...................... Lower Alloways Creek Twp., NJ.       3,000(A)
     Crisfield.................. Crisfield, MD.................      10,000
     Bayview.................... Bayview, VA...................      12,000
     Keystone................... Shelocta, PA..................         400(A)
     Conemaugh.................. New Florence, PA..............         400(A)
                                                                  ---------
                                                                    185,800
                                                                  ---------
     CUSTOMER-OWNED CAPACITY.... Delaware City, DE.............      57,000(B)
     CAPACITY PURCHASED FROM PECO..............................     212,000
                                                                  ---------
       Subtotal................................................   3,037,800
                                                                  ---------
     PURCHASED PJM INTERCONNECTION CAPACITY CREDITS............     290,000
                                                                  ---------
       Total...................................................   3,327,800
                                                                  =========
</TABLE>
--------
(A) Company portion of jointly-owned plants.
(B) Represents capacity owned by a refinery customer which is available to the
    Company to serve its peak load.
 
 
                                     I-20
<PAGE>
 
  The Company's electric transmission and distribution system includes 1,391
transmission poleline miles of overhead lines, 5 transmission cable miles of
underground cables, 6,931 distribution poleline miles of overhead lines, and
5,540 distribution cable miles of underground cables.
 
  The Company has a liquefied natural gas plant located in Wilmington,
Delaware with a storage capacity of 3.045 million gallons and an emergency
sendout capability of 45,000 Mcf per day.
 
  The Company also owns four natural gas city gate stations at various
locations in its gas service territory. These stations have a total sendout
capacity of 125,000 Mcf per day.
 
  The following table sets forth the Company's gas pipeline miles:
 
<TABLE>
        <S>                                                               <C>
        Transmission Mains...............................................   114*
        Distribution Mains............................................... 1,492
        Service Lines.................................................... 1,104
</TABLE>
            --------
            *  Includes 11 miles of joint-use gas pipeline that is
               used 10% for gas and 90% for electric.
 
  As of December 31, 1997, CCI, the Company's telecommunications subsidiary,
owned the assets listed and described below.
 
<TABLE>
<CAPTION>
        ($ IN MILLIONS)
        <S>                                                               <C>
        Central office equipment......................................... $11.7
        Cable, wiring and conduit........................................  25.0
        Other equipment..................................................   5.8
        Leasehold improvements and other.................................   4.0
                                                                          -----
                                                                          $46.5
                                                                          =====
</TABLE>
 
  "Central office equipment" consists of switching equipment, transmission
equipment and related facilities. "Cable, wiring and conduit" consists
primarily of aerial cable, underground cable, conduit and wiring. "Other
equipment" consists of circuit equipment and radio systems.
 
  The Company owns and occupies office buildings in Wilmington and Christiana,
Delaware and Salisbury, Maryland, and also owns elsewhere in its service area
a number of properties that are used for office, service, and other purposes.
 
ITEM 3. LEGAL PROCEEDINGS
 
  On February 6, 1997, a major customer of the Company filed a lawsuit in the
Delaware Superior Court alleging negligence and breach of contract against the
Company in relation to the electric system outages that occurred on March 28,
1996, and May 14, 1996. The complaint asked for actual damages in excess of
$41 million and for special and punitive damages in unspecified amounts. This
lawsuit was settled before trial. The result of the settlement was not
material to the Company's financial position or results of operations.
 
  See Note 18 to the Company's 1997 Consolidated Financial Statements included
in Part II, Item 8 for information concerning the Company's lawsuit against
Westinghouse Electric Corporation, the designer and manufacturer of the Salem
steam generators.
 
  In March 1996, the Company and PECO filed a complaint in the United States
District Court for the Eastern District of Pennsylvania against Public Service
Enterprise Group, Inc. (Enterprise) and PSE&G seeking damages for breach of
contract and negligence concerning Salem operations. The suit asked for
compensatory damages for breach of contract and negligence and unspecified
punitive damages. On May 12, 1997, it was announced that PSE&G settled the
suit with the Company and PECO. Under the settlement, PSE&G paid the Company
approximately $12 million on December 31, 1997, in settlement of all claims
related to the lawsuit.
 
                                     I-21
<PAGE>
 
  The parties to the settlement also agreed to operating performance standards
through December 31, 2011 for Salem, and similar standards through December
31, 2007 for the Peach Bottom Atomic Power Station operated by PECO. Under
these standards, the Company is entitled to receive payments from the nuclear
plant operator as follows: (a) if the three-year capacity factor determined
annually falls below 40 percent but is equal to or above 20 percent, the
operator will pay the Company $1.5 million for each year that the historical
capacity factor is below 40 percent; and (b) if the historical capacity factor
is below 20 percent, the operator will pay the Company $3.7 to $3.8 million
for each such year. The initial three-year period will begin on the date Unit
1 returns to service, which is expected to be in the second quarter of 1998.
 
  The parties have further agreed to forego litigation in the future, except
for very limited cases in which the operator would be responsible for no more
than $5 million per year.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
  No matter was submitted during the fourth quarter of the fiscal year covered
by this report to a vote of security holders, through the solicitation of
proxies or otherwise.
 
 
                                     I-22
<PAGE>
 
                                    PART II
 
 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 
  The Company's common stock was listed on the New York and Philadelphia Stock
Exchanges and had unlisted trading privileges on the Cincinnati, Midwest, and
Pacific Stock Exchanges and had the following dividends declared and high/low
prices by quarter for the years 1997 and 1996.
 
<TABLE>
<CAPTION>
                                        1997                      1996
                              ------------------------- ------------------------
                                            PRICE                     PRICE
                              DIVIDEND ---------------- DIVIDEND ---------------
                              DECLARED   HIGH     LOW   DECLARED  HIGH     LOW
                              -------- -------- ------- -------- ------- -------
<S>                           <C>      <C>      <C>     <C>      <C>     <C>
First Quarter................ $.38 1/2 $20 3/8  $18 3/8 $.38 1/2 $23 5/8 $21
Second Quarter...............  .38 1/2  19 3/8   16 7/8  .38 1/2  21 1/2  19 1/8
Third Quarter................  .38 1/2  19      17 3/16  .38 1/2  21 1/4  20
Fourth Quarter...............  .38 1/2  23 7/16 18 9/16  .38 1/2  21 1/2  19 1/8
</TABLE>
 
  The Company had 47,187 registered holders of common stock as of December 31,
1997.
 
  For information concerning common dividends, see the MD&A in Item 7 of Part
II.
 
                                      II-1
<PAGE>
 
ITEM. 6 SELECTED FINANCIAL DATA
 
<TABLE>
<CAPTION>
                                           YEAR ENDED DECEMBER 31,
                          ------------------------------------------------------------------------
                             1997            1996           1995           1994            1993
                          -----------     -----------    -----------    -----------     ----------
                               (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                       <C>             <C>            <C>            <C>             <C>
OPERATING RESULTS AND
 DATA
 Operating Revenues (1).. $ 1,423,502     $ 1,175,575    $ 1,055,725    $ 1,033,442     $1,007,851
 Operating Income (1).... $   234,429     $   257,300    $   254,425    $   233,244(2)  $  233,091
 Net Income.............. $   105,709     $   116,187    $   117,488    $   108,310(2)  $  111,076
 Basic and Diluted Earn-
  ings Applicable to Com-
  mon Stock.............. $   101,218     $   107,251    $   107,546    $    98,940(2)  $  101,074
 On System Electric Sales
  (kWh 000) (3)..........  13,231,766      12,925,716     12,310,921     12,505,082     12,280,230
 On System Gas Sold and
  Transported (mcf 000)..      22,855          22,424         21,371         20,342         19,605
COMMON STOCK INFORMATION
 Basic and Diluted Earn-
  ings Per Share of Com-
  mon Stock.............. $      1.66     $      1.77    $      1.79    $      1.67(2)  $     1.76
 Dividends Declared Per
  Share of Common Stock.. $      1.54     $      1.54    $      1.54    $      1.54     $     1.54
 Average Shares Outstand-
  ing (000)..............      61,122          60,698         60,217         59,377         57,557
 Year-End Common Stock
  Price..................         23 1/16         20 3/8         22 3/4         18 9/64        23 5/8
 Book Value Per Common
  Share.................. $     15.59     $     15.41    $     15.20    $     14.85     $    14.66
 Return on Average Common
  Equity.................        10.6%           11.4%          11.7%          11.1%          12.0%
CAPITALIZATION
 Variable Rate Demand
  Bonds (VRDB) (4)....... $    71,500     $    85,000    $    86,500    $    71,500     $   41,500
 Long-Term Debt..........     983,672         904,033        853,904        774,558        736,368
 Company Obligated
  Mandatorily Redeemable
  Preferred Securities of
  Subsidiary Trust
  Holding Solely Company
  Debentures.............      70,000          70,000            --             --             --
 Preferred Stock.........      89,703          89,703        168,085        168,085        168,085
 Common Stockholders' Eq-
  uity...................     954,496         934,913        923,440        884,169        862,195
                          -----------     -----------    -----------    -----------     ----------
 Total Capitalization
  with VRDB.............. $ 2,169,371     $ 2,083,649    $ 2,031,929    $ 1,898,312     $1,808,148
                          ===========     ===========    ===========    ===========     ==========
OTHER INFORMATION
 Total Assets............ $ 3,015,481     $ 2,931,855    $ 2,868,685    $ 2,669,785     $2,592,479
 Long-Term Capital Lease
  Obligation............. $    19,877     $    20,552    $    20,766    $    19,660     $   23,335
 Capital Expenditures.... $   173,008     $   169,012    $   142,833    $   166,938     $  166,222
</TABLE>
--------
(1) Beginning in 1997 operating revenues and operating income include the
    results of non regulated with prior years reclassified for comparative
    purposes.
(2) An early retirement offer decreased earnings net of income taxes and
    earnings per share by $10.7 million and $0.18, respectively.
(3) Excludes interchange deliveries.
(4) Although Variable Rate Demand Bonds are classified as current liabilities,
    the Company intends to use the bonds as a source of long-term financing as
    discussed in Note 13 to the Consolidated Financial Statements.
 
                                     II-2
<PAGE>
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
 
MERGER WITH ATLANTIC
 
  Effective March 1, 1998, Delmarva Power & Light Company (the Company) and
Atlantic Energy, Inc. (Atlantic) consummated merger transactions (the Merger)
which formed a new company named Conectiv and merged Atlantic out of
existence. Additional information about the Merger is included in Note 4 to
the Consolidated Financial Statements and in the registration statement on
Form S-4 dated December 26, 1996.
 
  Prior to the Merger, Atlantic owned Atlantic City Electric Company (ACE), an
electric utility, and subsidiaries engaged in nonutility businesses. As a
result of the Merger, Conectiv owns ACE, nonutility subsidiaries formerly held
by Atlantic, the Company, and the Company's subsidiaries. ACE serves
approximately 481,000 customers in a 2,700 square mile area in southern New
Jersey. Atlantic's 1997 operating revenues and net income were $1,102.4
million and $74.4 million, respectively, and its total assets were $2,723.9
million as of December 31, 1997.
 
  The benefits expected from the Merger include increased scale, cost savings,
competitive prices and services, a more balanced customer base, and increased
financial flexibility. The companies expect cost savings from Merger synergies
of approximately $500 million over 10 years.
 
  Approximately 50% to 75% of estimated cost savings from the Merger with
Atlantic will serve to reduce customers' rates and the balance of the cost
savings realized will benefit Conectiv stockholders. Pursuant to settlement
agreements approving the Merger, the Company will decrease retail customer
non-fuel (base) rates by an aggregate total of $13 million in Delaware,
Maryland, and Virginia. In New Jersey, ACE will share approximately 75% of the
Merger savings with its customers through a $15.75 million electric rate
reduction.
 
  Concurrent with the Merger, the Company and Atlantic plan to achieve
workforce reductions through enhanced retirement offers (ERO) and other
employee separation programs. The cost of the Company's employee separation
programs and other Merger related costs are currently estimated to be $55
million to $60 million before income taxes ($33 million to $36 million after
income taxes).
 
  Each outstanding share of the Company's common stock, par value $2.25 per
share, is being exchanged for one share of Conectiv's common stock, par value
$0.01 per share. Each share of Atlantic's common stock, no par value per
share, is being exchanged for 0.75 of one share of Conectiv's common stock and
0.125 of one share of Conectiv's Class A common stock, par value $0.01 per
share. Class A common stock gives holders of Atlantic common stock a
proportionately greater opportunity to share in the growth prospects of, and a
proportionately greater exposure to the uncertainties associated with the
electric utility business of ACE. Earnings applicable to Class A common stock
will be equal to 30% of the net of (1) earnings attributable to ACE's
regulated electric utility business, as the business existed on August 9,
1996, less (2) $40 million per year. Earnings applicable to Conectiv common
stock will be the consolidated earnings of Conectiv less earnings applicable
to Class A common stock.
 
EARNINGS RESULTS SUMMARY
 
  The Company's earnings per share for 1997 were $1.66 compared to $1.77 for
1996. Earnings from the Company's traditional, regulated utility operations
were relatively flat, and the $0.11 per share earnings decrease was primarily
attributed to expenses of non-regulated activities, as discussed below. For
the utility business, the positive effects of higher net electric revenues and
lower outage expenses for the Salem nuclear generating units were offset by
anticipated higher capital costs. Net electric revenues grew despite milder
weather due to customer growth and a strong economy.
 
  The earnings decrease from non-regulated activities resulted from planned
cost increases associated with investments in new businesses, branding, and
other expenditures which are positioning the Company to compete in deregulated
energy markets. Part of the Company's strategy for competition (in deregulated
markets) involves
 
                                     II-3
<PAGE>
 
the divestiture of non-strategic assets. A $0.22 per share gain from the
Company's sale of Pine Grove, Inc., which owned a landfill and related waste-
hauling company, mitigated the earnings decrease. This sale freed up capital
invested in a non-strategic asset and enabled the Company to absorb additional
investments to grow new businesses.
 
  Earnings per share for 1996 were $1.77, a $0.02 decrease from 1995.
Excluding the adverse impact of the Salem outages, earnings rose $0.08 per
share in 1996, primarily due to additional revenues from customer growth,
partly offset by higher depreciation and other expenses, including marketing
expenses for new value-added (energy-related) services.
 
DIVIDENDS
 
  On December 11, 1997, the Board of Directors declared a dividend on common
stock of $0.38 1/2 per share for the fourth quarter or $1.54 on an annualized
basis. The Company's growth strategy will require increased reinvestment of
earnings into new businesses. The business growth from these investments and
the payment of dividends on common stock are expected to maximize stockholder
value on a long-term basis. Following the Merger, dividends on Conectiv common
stock are expected to be paid at the rate of $1.54 per year, subject to
periodic evaluation of Conectiv's results of operations, financial condition,
capital requirements and other relevant considerations. Dividends on Class A
common stock are expected to be paid at the rate of $3.20 per share for three
years following the Merger subject to periodic evaluation of Conectiv's
results of operations, financial condition, capital requirements and other
relevant considerations. After the three-year period, dividends on Class A
common stock are expected to be equal to approximately 90% of earnings
available for Class A common stock. However, if dividends on Class A common
stock exceed earnings available for Class A common stock during the three year
period, that may influence the Board's determination of the amount of Class A
common stock dividends to be paid after the three-year period.
 
ELECTRIC UTILITY INDUSTRY RESTRUCTURING
 
  Prices charged to electric utility customers have historically been a
"bundled" price which includes the electricity production (supply) cost and
the delivery cost (transmission and distribution). State regulatory
commissions and legislatures throughout the country are considering or have
approved changes to laws and regulations governing the sale and pricing of
electricity. Generally, the supply component of the price charged to a
customer for electricity would be deregulated, and electric suppliers would
compete to supply electricity to customers. Competition is expected to reduce
gross margins earned from the supply of electricity. Customers would continue
to pay the local utility a regulated price for the delivery of the electricity
over the transmission and distribution system. Discussed below are proposals
concerning deregulation of the electric utility industry in Delaware,
Maryland, and Virginia (which have jurisdiction over the Company's retail
electric utility business), New Jersey (which regulates ACE's retail electric
utility business), and Pennsylvania.
 
DELAWARE
 
  In response to a request from the Delaware House of Representatives, on
January 27, 1998, the Delaware Public Service Commission (DPSC) submitted its
report on electric utility industry restructuring to the Delaware General
Assembly. The report included the following recommendations:
 
  .  All customers in Delaware would be able to choose their electricity
     supplier beginning twelve months after the restructuring legislation is
     signed into law.
 
  .  The incumbent utility would serve as the default electricity supplier
     during a DPSC-determined transition period. During this period, the
     retail generation rates for default customers would be market-based, but
     would continue to be regulated.
 
  .  Each utility would have an opportunity to recover all DPSC-approved non-
     mitigated stranded costs (or costs which would not be recovered under
     competitive pricing). Stranded cost recovery would occur through a
     separate, non-bypassable charge, which would be applied to all
     transmission and distribution
 
                                     II-4
<PAGE>
 
     customers. A "true-up" process would be established to adjust for
     fluctuations in stranded cost recovery due to sales volumes.
 
  .  Utilities would file their estimates of potential, non-mitigated
     stranded costs with the DPSC approximately three months after the
     restructuring was enacted. The estimates would be reviewed in a
     proceeding before the DPSC to determine the level of stranded cost
     recovery.
 
  .  A legal divestiture of generation assets would not be required; however,
     the generation business would have to be functionally separated from the
     remaining regulated utility business.
 
  .  The distribution and transmission services provided to retail customers
     by utilities, as well as some customer service functions, would continue
     to be regulated by the DPSC. Distribution services would continue to be
     priced based on cost-of-service. The DPSC also recommends that it
     oversee pricing of retail transmission services for some period;
     however, the Federal Regulatory Energy Commission (FERC) has indicated
     that it has jurisdiction over pricing of such transmission services.
 
  .  The DPSC recognized that alternative plans should be considered without
     necessitating changes to the restructuring legislation. Accordingly, the
     DPSC recommended that it be authorized to consider such alternatives and
     implement them, if they achieve the same customer choice goals and are
     in the public interest.
 
  On March 13, 1998, the DPSC sent draft legislation to the Delaware
legislature which would provide all Delaware electric retail customers the
ability to choose their electric supplier beginning on August 1, 1999. The
draft legislation also includes a provision that would allow the DPSC to delay
the start date of electric retail competition by up to 12 months.
Restructuring legislation may be considered by the Delaware legislature during
this session, which ends on June 30, 1998.
 
MARYLAND
 
  On December 3, 1997, the Maryland Public Service Commission (MPSC) issued an
order concluding that retail electric competition is in the public interest
and should be phased-in over a three-year period, one-third of the customers
per year, beginning April 1, 1999. The order established a schedule for filing
of additional information, roundtables, and proceedings. Enabling legislation
and resolution of complex issues such as stranded costs and utility taxation
will be necessary for implementation of retail electric competition in
Maryland.
 
  On December 31, 1997, the MPSC ordered a delay in the start of the three-
year phase in period from April 1, 1999 to July 1, 2000 and also suspended all
mandated filing dates. The MPSC subsequently adopted a revised schedule for
this proceeding. The Company and other Maryland utilities supported the
adoption of this schedule.
 
  Certain key provisions of the MPSC's order are as follows:
 
  .  A price cap would be in effect during the three-year phase-in period.
 
  .  Utilities would be given the opportunity to recover their verifiable and
     prudently incurred stranded costs subject to full mitigation.
     Securitization of stranded costs would be permitted. Utilities are to
     file with the MPSC their estimates of stranded costs and proposed
     recovery mechanisms.
 
  .  Cost-of-service regulation of electric generation would be discontinued
     at the end of the three-year period, while distribution service would
     remain subject to cost-of-service regulation.
 
  .  The local utility will supply customers who do not select alternate
     suppliers during the three-year period.
 
  .  Reciprocity from out-of-state suppliers will not be required.
 
  Restructuring legislation is being considered by the Maryland legislature.
 
 
                                     II-5
<PAGE>
 
VIRGINIA
 
  On November 7, 1997, the Virginia State Corporation Commission (VSCC) Staff
report recommended that electric competition should be studied and tested over
a five-year period before determining if retail competition should be
implemented.
 
  Restructuring legislation is being considered by the Virginia legislature.
 
NEW JERSEY
 
  In New Jersey, the Board of Public Utilities (BPU) has recommended that
retail choice begin with 10% of customers on October 1, 1998 and be available
to 100% of the customers by July 1, 2000. New Jersey electric utilities, as
directed by the BPU, have filed complete restructuring plans, stranded cost
estimates and unbundled rates. Proceedings are currently underway to address
restructuring issues.
 
PENNSYLVANIA
 
  In December 1996, the Pennsylvania legislature enacted the Pennsylvania
Electricity Generation Customer Choice and Competition Act (Competition Act)
which provides for the restructuring of the electric industry in Pennsylvania,
including retail competition beginning in 1999. The Competition Act requires
that all customers be allowed to choose their suppliers by January 1, 2001. In
accordance with the Competition Act, pilot programs, open to 5% of each
customer class, began on November 1, 1997. The Company is currently selling
electricity under the Conectiv Energy brand name in the pilot programs and has
acquired approximately 32,200 new customers. The Company plans to continue to
evaluate market opportunities in Pennsylvania.
 
  In December 1997, the Pennsylvania Public Utility Commission approved a
restructuring plan for PECO Energy Company (PECO) under which two-thirds of
PECO's customers can choose their energy supplier on January 2, 1999, and the
remaining PECO customers can choose as of January 1, 2000. Starting in 1999,
PECO's residential customers who purchase electricity from another supplier
will receive a credit of 5.2 cents per kilowatt hour. This credit will allow
electricity suppliers, such as the Company, a better opportunity than under
previous terms to earn a profit from electricity sales to PECO's existing
customers.
 
STRANDED COSTS
 
  The transition to a competitive market could result in "stranded costs" for
a utility. Stranded costs are generally costs which may not be recoverable in
a competitive market due to market-based pricing or customers choosing
different energy suppliers. Potential stranded costs could include (i) above-
market costs associated with generation facilities or long-term power purchase
agreements and (ii) regulatory assets (see Note 9 to the Consolidated
Financial Statements) if cost recovery does not continue under a transition
plan.
 
  Authoritative accounting guidance issued in 1997 prescribes that a utility
should cease to apply Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation," for any
separable portion of the business, such as the electricity production (supply)
portion of its business, no later than the date that a specific deregulation
plan is finalized. Stranded costs and regulatory assets attributed to
electricity supply would continue to be recognized to the extent that a
transition plan provides for their recovery through cash flows from the
regulated transmission and distribution business.
 
  As previously discussed, proposals concerning deregulation of the electric
utility industry are being considered in Delaware, Maryland, and Virginia, but
no deregulation plan has yet been finalized. Due to the uncertainty
surrounding the outcome of the restructuring plans, the Company cannot
currently predict if or when it would cease applying SFAS No. 71. To the
extent stranded cost recovery is not provided for, the Company would be
required to write down asset values, and such write-downs could be material.
 
 
                                     II-6
<PAGE>
 
BUSINESS PLANS
 
  As deregulation of the electric utility industry continues to unfold, the
Company is moving ahead with its plan to become a prominent regional player by
being first into new markets that complement its utility business and by
enhancing its ability to serve additional customers outside of its traditional
borders. The Company is growing its businesses by building long-term customer
relationships, establishing the Conectiv brand name, marketing products and
services that complement the Company's core energy business, and serving more
customers in a larger geographic area. To accomplish these goals, the Company
has increased investments in marketing/branding programs, new businesses, and
infrastructure systems.
 
  On June 30, 1997, the Company launched a campaign to introduce the new
Conectiv brand and Conectiv's products and services. The campaign explained
that Conectiv is offering energy, telecommunications, heating and cooling, and
related services for homes and businesses. Customer response to the new
Conectiv brand name has been positive, as evidenced by name recognition and
the Company's success in gaining new customers in retail energy pilot
programs. The Company is marketing an array of products and services--energy,
local and long-distance telephone service, heating, ventilation, and cooling
(HVAC) services, and other services--under the Conectiv name. The Company
plans to continue its advertising campaigns and other support of the Conectiv
brand name.
 
  Over the next year or two, the Company's earnings are expected to be
constrained by on-going start-up costs for new businesses, including
telecommunications and HVAC. After this start-up period, these investments are
expected to contribute to long-term consolidated earnings growth which exceeds
the utility industry average.
 
  Conectiv's business plans will be carried out by its three business groups:
Conectiv Energy Delivery; Conectiv Energy Supply; and Conectiv Enterprises.
The business groups are aligned with customers' needs, markets, and the future
structure of the utility industry. The business groups are discussed below.
For financial information concerning the Company's business segments and the
expected impact of SFAS No. 131, "Disclosure About Segments of an Enterprise
and Related Information", see Note 21 to the Consolidated Financial
Statements.
 
CONECTIV ENERGY DELIVERY
 
  Conectiv Energy Delivery will deliver electricity and gas to retail and
wholesale customers within its service territory. These delivery services are
structured into various forms of price-regulated offers, some including energy
supply, so that customers may choose the combination that provides the best
value. Customer satisfaction and loyalty is expected to remain high due to the
Company's reliable delivery systems, superior customer service, and
competitive cost and pricing structures.
 
CONECTIV ENERGY SUPPLY
 
  Conectiv Energy Supply will manage the generating assets, bulk energy
marketing and trading activities, and the transition of those assets and
activities from a regulated to a competitive environment. Its principal
products are electric power and natural gas, supplemented by other fuels and
related energy management services. Its customers are bulk energy users and
retail aggregators in the region stretching from the Delmarva peninsula north
through New England and west to Ohio.
 
CONECTIV ENTERPRISES
 
  Conectiv Enterprises is comprised of the following five start-up businesses:
Conectiv Communications, Inc. (CCI)--provides local and long distance
telephone services; Conectiv Energy--primarily sells energy in competitive
retail markets; Conectiv Services, Inc. (CSI)--provides a full range of HVAC
services; Conectiv Solutions LLC--provides customized solutions to customers'
energy needs, and Conectiv Thermal Systems, Inc. (currently Atlantic Thermal
Systems, Inc.)--provides custom thermal heating and cooling systems. These
businesses provide an opportunity to grow Conectiv's customer base throughout
the Mid-Atlantic region and
 
                                     II-7
<PAGE>
 
strengthen its relationship with customers in its traditional service
territory. Conectiv Enterprises expects to incur operating losses for the
first year or two after the Merger due to start-up costs.
 
 Conectiv Communications, Inc.
 
  CCI is a full range facilities based telecommunications company initially
operating in the region that includes Delaware, Southeastern Pennsylvania,
Southern New Jersey, and Eastern Maryland. CCI's product and service offerings
include all local and long distance services as well as carrier, network, and
data services. CCI is marketing its products and services to business,
residential, and carrier customers. CCI will focus on providing a facilities-
based solution to its customers, and will also resell Bell Atlantic service.
This strategy requires capital expenditures for further expansion of CCI's
existing fiber optic network over the next several years. CCI currently
operates in a duopoly local service environment with Bell Atlantic.
Competition may increase from other telecommunications companies seeking to
establish a local service presence in the region.
 
 Conectiv Energy
 
  Conectiv Energy currently sells competitive natural gas, electricity, and
energy related products and services to residential and commercial customers
in the Mid-Atlantic region. Retail customers' favorable response to the
Conectiv brand has been a key to acquiring new retail customers in competitive
markets. In 1997, Conectiv Energy obtained approximately 7,700 gas customers
and 32,200 electric customers. The costs associated with acquiring new
customers, timing of market entry, gross margins on sales, and regulations
governing the transition to competition are factors critical to this business.
 
 Conectiv Services, Inc.
 
  CSI is a full-service HVAC business operating in the Mid-Atlantic region.
CSI provides commercial customers with mechanical HVAC/piping construction and
installation, design services, sheet metal fabrication, preventative
maintenance and repair services. Residential offerings include HVAC
installation, maintenance, repair and related plumbing services. The regional
HVAC and plumbing industry is highly competitive, fragmented, and rapidly
consolidating. The sales and earnings of HVAC businesses are affected by
weather conditions. CSI originated through acquisitions of established
businesses, and its future growth will be impacted by the availability of
acquisition candidates and any regulatory limits imposed on market access.
 
 Conectiv Solutions LLC
 
  Conectiv Solutions LLC (Conectiv Solutions) is building close customer
relationships by understanding individual customers' energy-related needs, and
meeting those needs with customized, turnkey solutions. Conectiv Solutions
provides large commercial and industrial customers, primarily within the
Delaware Valley region, with energy and energy-related products and services.
These products and services are built around occupant comfort, reliability of
systems, and cost containment and reduction. Conectiv Solutions provides
energy efficiency services, power systems consulting, custom on-site energy
systems' services and construction, telecommunication services, and energy
procurement. In addition, Conectiv Solutions offers the HVAC and
telecommunications services provided by CSI and CCI.
 
 Conectiv Thermal Systems, Inc.
 
  Atlantic Thermal Systems, Inc. (ATS), owned by Atlantic prior to the Merger,
will become Conectiv Thermal Systems, Inc. (CTS) shortly after the Merger. CTS
will provide products and services offered by ATS prior to the Merger,
including heating, cooling and related energy services to large commercial and
industrial customers. In conjunction with these services, ATS develops,
finances, constructs, owns and operates thermal energy production and
distribution plants. Targeted customer groups include gaming/hotel resort
complexes, colleges and universities, health care facilities and industrial
complexes. ATS offers a highly customized service
 
                                     II-8
<PAGE>
 
tailored to meet each customer's specific energy needs. Through ATS' energy
outsourcing programs, customers are able to reduce their capital expenditures
on non-strategic assets, realize energy cost savings, and free themselves from
energy matters, which are incidental to their principal business activities.
 
PRICE REGULATION OF ENERGY REVENUES
 
  Through 1997, customer rates for non-fuel costs represented a "bundled"
price, including production costs and delivery costs, and have been set in
past base rate proceedings before utility regulatory commissions. Changes in
non-fuel (or base rate) revenues due to volume, or rate changes, generally
affect the earnings of the Company.
 
  Energy costs, including fuel and purchased energy, are currently billed to
customers located within the Company's service territory under regulated fuel
adjustment clause rates. These rates are adjusted periodically for cost
changes and are subject to review by utility regulatory commissions. "Fuel
revenues", or energy costs billed to customers, do not generally affect net
income, because the amount of under- or over-recovered fuel costs is generally
deferred until it is subsequently recovered from or returned to utility
customers.
 
  As the utility industry is restructured, fuel adjustment clauses are
expected to be eliminated, and any differences between energy costs and
related revenues will impact future earnings. The Company is currently
managing the price risk associated with its unregulated, off-system energy
sales through commodity hedging activities as discussed in Note 6 to the
Consolidated Financial Statements. When energy sales are deregulated in the
Company's service territory, price risk is expected to be managed similarly
for these sales.
 
  Electric revenues also include interchange delivery revenues, which result
primarily from the sale of electricity to other electricity suppliers in the
Pennsylvania-New Jersey-Maryland (PJM) Interconnection, which is an electric
power pool. Interchange delivery revenues are currently reflected in the
calculation of rates charged to customers under fuel adjustment clauses and,
thus, do not affect net income. The future deregulation of the generation
function will cause the margins from interchange delivery revenues to impact
earnings.
 
  Merchant revenues result from off-system energy sales in competitive markets
outside the Company's traditional service territory. These sales are not
subject to price regulation and include retail competition pilot programs and
bulk commodity sales.
 
ELECTRIC REVENUES AND SALES
 
  The Company's sources of electric revenues as a percentage of total electric
revenues are shown below.
 
<TABLE>
<CAPTION>
                                                               1997  1996  1995
                                                               ----  ----  ----
   <S>                                                         <C>   <C>   <C>
   Retail revenues............................................ 81.0% 85.7% 88.3%
   Resale revenues............................................  6.3%  6.7%  6.5%
   Interchange delivery revenues..............................  3.3%  7.6%  5.2%
   Merchant revenues..........................................  9.4%  --    --
</TABLE>
 
  Electric retail revenues provide the highest gross margin (revenues less
fuel and purchased energy costs) of the revenue categories shown above and are
currently subject to price regulation. The electric resale and electric
merchant businesses' gross margins, as a percent of revenue, are lower due to
product differences, greater volume per customer, and competitive/unregulated
pricing. However, the Company's new electric merchant business contributed an
incremental amount of gross margin in 1997, which enhanced the Company's
overall profitability.
 
  In 1997, the percentage of electric retail revenues contributed by the
various retail customer classes were as follows: residential--42.6%;
commercial--33.9%; industrial--19.6%; and other--3.9%.
 
 
                                     II-9
<PAGE>
 
  Details of the changes in the various components of electric revenues are
shown below.
 
COMPARATIVE INCREASE (DECREASE) FROM PRIOR YEAR IN ELECTRIC REVENUES
 
<TABLE>
<CAPTION>
                                                           1997         1996
                                                        -----------  ----------
                                                        (DOLLARS IN MILLIONS)
   <S>                                                  <C>          <C>
   Retail and Resale Revenues
     Non-fuel (Base Rate) Revenues..................... $       8.9  $     27.2
     Fuel Revenues.....................................        32.7        26.8
   Interchange Delivery Revenues.......................       (38.8)       28.0
   Merchant Revenues...................................       102.4         --
                                                        -----------  ----------
                                                        $     105.2  $     82.0
                                                        ===========  ==========
</TABLE>
 
  For 1997 compared to 1996, electric non-fuel revenues increased $8.9 million
mainly due to a 2.6% increase in total retail kilowatt-hour (kWh) sales. The
sales increase was due to a 1.4% increase in the number of regulated retail
customers and favorable economic conditions, partly offset by milder weather's
unfavorable effect on sales. For 1996 compared to 1995, electric non-fuel
revenues increased $27.2 million due to a 4.5% increase in total retail kWh
sales which was attributed primarily to a full year of Conowingo District
sales in 1996 versus a half year in 1995. As discussed in Note 4 to the
Consolidated Financial Statements, the Company acquired Conowingo Power
Company (COPCO) in June 1995.
 
  In 1997 and 1996, electric fuel revenues increased $32.7 million and $26.8
million, respectively, due to higher average fuel rates and increased kWh
sales.
 
  In 1997, more output was sold off-system through the Company's merchant
program (discussed below), reducing kWh deliveries to and revenues from the
PJM Interconnection. In 1996, interchange delivery revenues increased $28.0
million principally due to increased energy purchases which enabled the
Company to sell more of its higher-cost peaking unit output to utilities in
the PJM Interconnection.
 
  Electric merchant revenues, which are not subject to price regulation,
increased $102.4 million due to the start-up of the Company's new merchant
group which sells power in competitive markets outside the Company's
traditional service territory.
 
ELECTRIC RESALE BUSINESS
 
  With electric resale customers free to choose their electric supplier, the
electric resale business continues to be highly competitive. If a supplier
other than the local utility is selected, then the local utility receives a
fee for delivering the electricity to the resale customer. The status of the
Company's contract with its largest electric resale customer, Old Dominion
Electric Cooperative (ODEC), is discussed below. Other electric resale
customers of the Company have electricity supply contracts with the Company
which expire in 2001 to 2004.
 
  Under notice provisions in its electricity supply contract, ODEC informed
the Company in August 1996 that it will reduce its load of approximately 200
megawatts (MW) by 60 MW on September 1, 1998, and will further reduce its load
to zero on September 1, 2001. The Company and ODEC have signed a new contract
under which the Company will supply part of the 60 MW. Due to lower pricing
and capacity supplied under this new contract beginning September 1, 1998,
annualized earnings per share will decrease by $0.04 to $0.05 based on
historical common shares outstanding, which equates to about $0.03 based on
pro forma Conectiv common shares outstanding. If ODEC further reduces its load
to zero on September 1, 2001, then annualized earnings per share would
decrease by an additional $0.04 to $0.05 based on historical common shares
outstanding, or about $0.03 to $0.04 based on pro forma Conectiv common shares
outstanding. These projected earnings decreases are net of the expected
savings from avoided capacity costs, which are expected to rise in price
substantially during 1998-2000.
 
                                     II-10
<PAGE>
 
GAS REVENUES, SALES AND TRANSPORTATION
 
  The Company earns gas revenues from gas sales on-system and off-system
(merchant sales) and from the transportation of gas for customers.
Transportation customers may purchase gas from the Company or other suppliers.
 
  Details of the changes in the various components of gas revenues are shown
below.
 
COMPARATIVE INCREASE (DECREASE) FROM PRIOR YEAR IN GAS REVENUES
 
<TABLE>
<CAPTION>
                                                            1997        1996
                                                         ----------  ----------
                                                         (DOLLARS IN MILLIONS)
   <S>                                                   <C>         <C>
   Non-fuel (Base Rate) Revenues........................ $     (1.2) $      3.7
   Fuel Revenues........................................        8.8        10.5
   Merchant Revenues....................................       82.2         4.6
                                                         ----------  ----------
                                                         $     89.8  $     18.8
                                                         ==========  ==========
</TABLE>
 
  The total number of on-system gas customers served by the Company increased
by 2.3% in 1997 and 2.5% in 1996.
 
  Gas non-fuel revenues decreased $1.2 million in 1997 principally due to a
9.8% decline in residential gas sales from milder winter weather, partly
offset by sales to new customers. In 1996, gas non-fuel revenues increased
$3.7 million mainly due to customer growth and a colder heating season.
 
  Gas fuel revenues increased $8.8 million in 1997 primarily due to higher
fuel rates. In 1996, gas fuel revenues increased $10.5 million due to a prior
year refund of over-recovered fuel costs, higher sales, and higher average
rates.
 
  The Company launched its gas merchant business in 1996 and ramped-up
operations in 1997. Gas merchant revenues increased $82.2 million in 1997
primarily due to higher off-system gas sales. Similar to electric merchant
revenues, the margin provided by gas merchant revenues in excess of related
purchased gas costs is relatively small due to the competitive nature of bulk
commodity sales.
 
OTHER SERVICES REVENUES
 
  Other service revenues were comprised of the following:
 
<TABLE>
<CAPTION>
                                                           1997    1996   1995
                                                          ------- --------------
                                                          (DOLLARS IN MILLIONS)
   <S>                                                    <C>     <C>    <C>
   HVAC.................................................. $  62.8 $  7.1 $  --
   Operation of power plants (1).........................    23.5   21.5   26.6
   Landfill and waste hauling............................    12.7   14.1   13.5
   Other (2).............................................    28.3   31.7   15.3
                                                          ------- ------ ------
     Total............................................... $ 127.3 $ 74.4 $ 55.4
                                                          ======= ====== ======
</TABLE>
--------
  (1) Primarily the Company's operation of the Delaware City power plant
      which supplies power to Star Enterprises' oil refinery.
  (2) Other includes real estate activities, value-added (energy-related)
      services, leveraged leasing, telecommunications and other
      miscellaneous services.
 
  HVAC revenues increased $55.7 million and $7.1 million in 1997 and 1996,
respectively, due to acquisitions by CSI of companies which provide HVAC and
plumbing services. (For information concerning CSI, see "Business Plans.")
Revenues classified above as "Landfill and waste hauling" were earned by Pine
 
                                     II-11
<PAGE>
 
Grove, Inc. which was sold in the fourth quarter of 1997, as discussed in Note
5, to the Consolidated Financial Statements. In 1996, "Other" revenues
increased $16.4 million due to increased revenues from real estate activities
and value-added (energy-related) services.
 
ELECTRIC FUEL AND PURCHASED ENERGY EXPENSES
 
  In 1997, electric fuel and purchased energy expenses increased $89.2 million
compared to 1996 primarily due to greater volumes of energy sold and lower
amounts of energy expenses deferred under fuel adjustment clauses.
 
  In 1996, electric fuel and purchased energy expenses increased $59.6 million
mainly due to higher kWh sales and interchange deliveries, and higher fuel and
purchased energy prices. Lower energy expense recognition due to higher
amounts deferred under fuel adjustment clauses mitigated the increase.
 
  For information concerning the Salem outage's impact on electric fuel and
purchased energy expenses, see Note 18 to the Consolidated Financial
Statements.
 
  The kWh output required to serve load within the Company's service territory
is substantially equivalent to total output less interchange deliveries and
off-system sales. In 1997, the Company's output for load within its service
territory was provided by 35% coal generation, 35% net purchased power, 20%
oil and gas generation, and 10% nuclear generation.
 
GAS PURCHASED
 
  In 1997, gas purchased increased $91.8 million due primarily to larger
volumes of gas purchased for resale off-system. In 1996, gas purchased
increased $12.6 million principally due to higher prices for purchased gas and
less purchased gas costs deferred under the fuel adjustment clause.
 
OTHER SERVICES' COST OF SALES
 
  Other services' cost of sales increased to $85.2 million in 1997 from $55.3
million in 1996 due to acquisitions of HVAC service companies, partly offset
by decreased volume in real estate activities and landfill/ waste hauling
operations. In 1996, other services' cost of sales increased by $16.3 million
primarily due to acquisitions of HVAC service companies and higher volume of
real estate activities and value-added (energy-related) services.
 
OPERATION AND MAINTENANCE EXPENSES
 
  Operation and maintenance expenses increased to $331.8 million in 1997 from
$277.9 million in 1996. The $53.9 million increase was mainly due to the
start-up of the HVAC, telecommunications, retail energy, and merchant
businesses, and costs associated with establishing the Conectiv brand name and
gaining new customers. Lower pension cost and Salem outage expenses partly
reduced the total increase in operation and maintenance expenses.
 
  In 1996, operation and maintenance expenses increased $12.5 million
primarily due to marketing expenses for value-added (energy-related) services,
increased costs associated with the Salem outages, and a full year's operation
of the Conowingo District.
 
YEAR 2000
 
  A Conectiv project team has been formed to address the issue of computer
programs not properly recognizing the Year 2000. The project team is
identifying, analyzing, correcting and reporting on all systems, equipment,
and processes suspected of putting Conectiv's businesses or customers at risk.
The Year 2000 project team has developed a detailed plan to address the
problem. The project team's goal is to resolve Year 2000
 
                                     II-12
<PAGE>
 
related problems associated with all core systems by the close of 1998. The
recent implementation of a new management information system has resolved a
substantial portion of the "Year 2000" problem. The Company has also contacted
major vendors to review remediation of their Year 2000 issues. The Company
believes it will successfully resolve its Year 2000 issues in a timely manner
and does not expect related costs to be material to the Company's results of
operations or financial position.
 
DEPRECIATION EXPENSE
 
  Depreciation expense increased $7.8 million in 1997 due to completion of on-
going construction projects and installation of new systems. Depreciation
expense increased $9.2 million in 1996 due to the completion of on-going
construction projects and the acquisition of COPCO in mid-1995.
 
OTHER INCOME
 
  In 1997, other income increased to $28.2 million from $7.6 million in 1996
primarily due to a $22.9 million pre-tax gain on the sale of the Pine Grove
landfill and waste-hauling operations. On an after-tax basis, the gain was
$13.7 million or $0.22 per common share.
 
FINANCING COSTS
 
  Financing costs reflected in the consolidated income statement include
interest charges, allowance for funds used during construction (AFUDC),
dividends on preferred securities of a subsidiary trust, and dividends on
preferred stock. In 1997, financing costs increased $9.9 million primarily due
to higher interest charges from the issuance of $124.2 million of Medium-Term
Notes in February 1997 and $42.0 million of Medium-Term Notes in the fourth
quarter of 1997, partly offset by savings from the refinancing of $78.4
million of preferred stock in the fourth quarter of 1996. In 1996, financing
costs increased $3.2 million primarily due to debt issued in mid-1995 to
finance the acquisition of COPCO.
 
LIQUIDITY AND CAPITAL RESOURCES
 
  The Company's primary capital resources are internally generated funds (net
cash provided by operating activities less common and preferred dividends) and
external financings. These resources provide capital for utility construction
expenditures, expansion of new business lines and other capital requirements,
such as repayment of maturing debt and capital lease obligations. Utility
construction expenditures are the Company's largest on-going capital
requirement and are affected by many factors including growth in demand for
electricity. In the foreseeable future, the Company expects that incremental
demand for electricity will be supplied with purchased power. This
expectation, and the Company's strategy to grow new businesses, has shifted a
larger proportion of the Company's capital resources into new businesses.
 
  Capital expenditures increased $4.0 million in 1997 and $26.2 million in
1996. The 1997 increase was principally due to $35 million of capital
expenditures to expand CCI's fiber optic network, partially offset by a $30
million decrease in utility construction expenditures, including deferred
Merger-related costs. In 1996, capital expenditures increased $26.2 million
primarily due to higher utility construction.
 
  The Company's cash expenditures for business acquisitions of $17.6 million
and $4.9 million in 1997 and 1996, respectively, were due to CSI's acquisition
of HVAC and related businesses. In 1995, the Company acquired COPCO for $157.0
million, net of cash acquired, with $125.8 million of long-term debt and the
balance with short-term debt.
 
  Operating activities provided net cash inflows of $221.3 million in 1997,
$222.7 million in 1996, and $239.4 million in 1995. In 1997, increased cash
flows from higher regulated fuel revenues, net of amounts paid for fuel and
purchased energy, were offset by planned cost increases associated with
investments in new businesses. In 1996, net cash flow from operating
activities decreased $16.7 million due to lower electric fuel revenues, net of
amounts paid for electric fuel and purchased energy.
 
                                     II-13
<PAGE>
 
  After deducting common and preferred dividend payments of $98.0 million in
1997, $102.4 million in 1996, and $102.0 million in 1995, internally generated
funds were $123.2 million in 1997, $120.3 million in 1996, and $137.4 million
in 1995. Internally generated funds provided 110%, 79%, and 101% of the cash
required for utility construction in 1997, 1996, and 1995, respectively.
 
  "Sales of nonutility assets" under cash flows from investing activities
includes $33.4 million of pre-tax proceeds from the 1997 sale of Pine Grove
Inc.'s landfill and waste-hauling operations. The principal effects of the
sale on the consolidated balance sheet were a $23.7 million decrease in
nonutility property and an $11.7 million decrease in variable rate demand
bonds.
 
  Long-term financings during 1995-1997, net of long-term refinancings and
redemptions, raised $292.8 million of net capital. Sources of cash from long-
term financings, net of refinancings and redemptions, included the following:
$28.9 million of common stock; $260.6 million of long-term debt; $11.7 million
of variable rate demand bonds; and $70.0 million of Company obligated
mandatorily redeemable preferred securities issued by the Company's subsidiary
trust (as discussed below). Preferred stock outstanding was reduced by $78.4
million during this period.
 
  Depending on its financing needs, the Company periodically raises cash by
issuing common stock through its Dividend Reinvestment and Common Share
Purchase Plan (DRIP). Alternatively, the Company at times provides DRIP shares
to investing stockholders by purchasing its common shares in the open market.
 
  In February 1997, the Company issued $124.2 million of unsecured Medium-Term
Notes with maturities of 10 to 30 years and interest rates of 7.06% to 7.72%.
The proceeds were used to repay short-term debt. On the consolidated balance
sheet as of December 31, 1996, $77.0 million of short-term debt was
reclassified to long-term debt to recognize the amount of short-term debt
refinanced with the Medium-Term Notes.
 
  In September 1997, $25.0 million of 6 3/8% First Mortgage Bonds were
redeemed at maturity. In June 1998, $25 million of 5.69%, Medium-Term Notes
are scheduled to mature.
 
  In the fourth quarter of 1997, the Company repaid short-term debt with
proceeds from the issuance of $42 million of unsecured Medium-Term Notes with
maturities of 5 to 9 years and interest rates of 6.6% to 6.8%.
 
  In January 1998, the Company issued $33.0 million of 6.81% Medium-Term
Notes, which mature in 20 years, and used $25.4 million of the proceeds to
repay short-term debt. In recognition of this refinancing, $25.4 million of
short-term debt was reclassified to long-term debt on the consolidated balance
sheet as of December 31, 1997.
 
  In October 1996, a subsidiary trust of the Company issued $70 million of
8.125% Company obligated mandatorily redeemable preferred securities and
loaned the proceeds to the Company. On a consolidated basis, this financing
vehicle results in a tax benefit which is equivalent to the tax effect of a
deduction for distributions on the preferred securities. The proceeds from the
issuance of the preferred securities and additional short-term debt were used
to retire $78.4 million of the Company's preferred stock, which had an average
dividend rate of 6.9%. On an after-tax basis, the refinancing lowers financing
costs by approximately $1.5 million annually.
 
  The Company's capital structure as of December 31, 1997 and 1996, expressed
as a percentage of total capitalization, is shown below.
 
<TABLE>
<CAPTION>
                                                                     1997  1996
                                                                     ----  ----
   <S>                                                               <C>   <C>
     Long-term debt and variable rate demand bonds.................. 48.7% 47.5%
     Mandatorily redeemable preferred securities....................  3.2%  3.3%
     Preferred stock................................................  4.1%  4.3%
     Common stockholders' equity.................................... 44.0% 44.9%
</TABLE>
 
                                     II-14
<PAGE>
 
  Presented below are Conectiv's estimated capital requirements, including
anticipated expenditures for business acquisitions.
 
<TABLE>
<CAPTION>
                                              1998   1999   2000   2001   2002
                                             ------ ------ ------ ------ ------
                                                   (DOLLARS IN MILLIONS)
<S>                                          <C>    <C>    <C>    <C>    <C>
Conectiv Enterprises
  Conectiv Communications, Inc.............. $ 32.8 $ 34.2 $ 38.6 $ 36.6 $ 25.1
  Conectiv Energy...........................    0.9    0.5    0.1    0.2    --
  Conectiv Services, Inc....................   31.5   27.7    2.9    1.2    1.2
  Conectiv Solutions........................    7.3   40.2   28.3   31.7   36.0
  Conectiv Thermal Systems..................   25.3    --    16.5   12.3    --
                                             ------ ------ ------ ------ ------
                                               97.8  102.6   86.4   82.0   62.3
Conectiv Energy Delivery....................  131.1  142.2  148.0  136.3  134.6
Conectiv Energy Supply......................   54.0   82.7   59.3   96.1   61.7
                                             ------ ------ ------ ------ ------
  Subtotal..................................  282.9  327.5  293.7  314.4  258.6
Debt Maturities and Other...................  111.5   69.9   56.2   62.6  118.2
                                             ------ ------ ------ ------ ------
  Consolidated Conectiv..................... $394.4 $397.4 $349.9 $377.0 $376.8
                                             ====== ====== ====== ====== ======
</TABLE>
 
  Over the five-year forecast period, Conectiv's capital requirements,
exclusive of maturing debt, are expected to be funded by internally generated
funds. External financing, during the five-year period, is anticipated only
for the refunding of maturing debt.
 
NONUTILITY SUBSIDIARIES
 
  For summarized financial information on the Company's nonutility
subsidiaries, please refer to Note 20 to the Consolidated Financial
Statements.
 
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 "will," "anticipate,"
"estimate," "expect," "objective," and similar expressions are intended to
identify forward-looking statements. In addition to any assumptions and other
factors referred to specifically in connection with such forward-looking
statements, factors that could cause actual results to differ materially from
those contemplated in any forward-looking statements include, among others,
the following: deregulation and the unbundling of energy supplies and
services; an increasingly competitive energy marketplace; sales retention and
growth; federal and state regulatory actions; future litigation results; costs
of construction; operating restrictions; increased costs and construction
delays attributable to environmental regulations; nuclear decommissioning and
the availability of reprocessing and storage facilities for spent nuclear
fuel; and credit market concerns. The Company undertakes no obligation to
publicly update or revise any forward-looking statements, whether as a result
of new information, future events or otherwise. The foregoing review of
factors pursuant to the Litigation Reform Act should not be construed as
exhaustive or as any admission regarding the adequacy of disclosures made by
the Company prior to the effective date of the Litigation Reform Act.
 
 
                                     II-15
<PAGE>
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
REPORT OF MANAGEMENT
 
  Management is responsible for the information and representations contained
in the Company's financial statements. Our financial statements have been
prepared in conformity with generally accepted accounting principles, based
upon currently available facts and circumstances and management's best
estimates and judgments of the expected effects of events and transactions.
 
  Delmarva Power & Light Company maintains a system of internal controls
designed to provide reasonable, but not absolute, assurance of the reliability
of the financial records and the protection of assets. The internal control
system is supported by written administrative policies, a program of internal
audits, and procedures to assure the selection and training of qualified
personnel.
 
  Coopers & Lybrand L.L.P., independent accountants, are engaged to audit the
financial statements and express their opinion thereon. Their audits are
conducted in accordance with generally accepted auditing standards which
include a review of selected internal controls to determine the nature,
timing, and extent of audit tests to be applied.
 
  The Audit Committee of the Board of Directors, composed of outside directors
only, meets with management, internal auditors, and independent accountants to
review accounting, auditing, and financial reporting matters. The independent
accountants are appointed by the Board on recommendation of the Audit
Committee, subject to stockholder approval.
 
/s/ Howard E. Cosgrove                    /s/ Barbara S. Graham
-------------------------------------     -------------------------------------
Howard E. Cosgrove                        Barbara S. Graham
Chairman of the Board, President          Senior Vice President
and Chief Executive Officer               and Chief Financial Officer
 
March 1, 1998
 
                                     II-16
<PAGE>
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Board of Directors and Stockholders
 Delmarva Power & Light Company
 Wilmington, Delaware
 
  We have audited the accompanying consolidated balance sheets of Delmarva
Power & Light Company and Subsidiary Companies as of December 31, 1997 and
1996, and the related consolidated statements of income, changes in common
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 1997. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
 
  We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
 
  In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Delmarva
Power & Light Company and Subsidiary Companies as of December 31, 1997 and
1996, and the consolidated results of their operations and their cash flows
for each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
 
/s/ Coopers & Lybrand L.L.P.
-------------------------------------
Coopers & Lybrand L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 6, 1998, except as
to the information presented
in Note 4 under Merger with
Atlantic Energy, Inc., for
which the effective date of the
merger is March 1, 1998
 
 
                                     II-17
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
                       CONSOLIDATED STATEMENTS OF INCOME
 
<TABLE>
<CAPTION>
                                                 YEAR ENDED DECEMBER 31,
                                             ----------------------------------
                                                1997        1996        1995
                                             ----------  ----------  ----------
                                                  (DOLLARS IN THOUSANDS)
<S>                                          <C>         <C>         <C>
OPERATING REVENUES
  Electric.................................  $1,092,144  $  986,921  $  904,904
  Gas......................................     204,057     114,284      95,441
  Other services...........................     127,301      74,370      55,380
                                             ----------  ----------  ----------
                                              1,423,502   1,175,575   1,055,725
                                             ----------  ----------  ----------
OPERATING EXPENSES
  Electric fuel and purchased power........     416,640     327,464     267,885
  Gas purchased............................     153,027      61,208      48,615
  Other services' cost of sales............      85,192      55,276      38,970
  Purchased electric capacity..............      28,470      32,126      29,116
  Operation and maintenance................     331,770     277,893     265,400
  Depreciation.............................     136,340     128,571     119,393
  Taxes other than income taxes............      37,634      35,737      31,921
                                             ----------  ----------  ----------
                                              1,189,073     918,275     801,300
                                             ----------  ----------  ----------
OPERATING INCOME...........................     234,429     257,300     254,425
                                             ----------  ----------  ----------
OTHER INCOME
  Allowance for equity funds used during
   construction............................       1,337       1,338         708
  Other income.............................      28,187       7,595       4,716
                                             ----------  ----------  ----------
                                                 29,524       8,933       5,424
                                             ----------  ----------  ----------
INTEREST EXPENSE
  Interest charges.........................      83,398      74,242      69,191
  Allowance for borrowed funds used during
   construction and capitalized interest...      (2,996)     (3,926)     (2,370)
                                             ----------  ----------  ----------
                                                 80,402      70,316      66,821
                                             ----------  ----------  ----------
DIVIDENDS ON PREFERRED SECURITIES OF A SUB-
 SIDIARY TRUST.............................       5,687       1,390         --
                                             ----------  ----------  ----------
INCOME BEFORE INCOME TAXES.................     177,864     194,527     193,028
INCOME TAXES...............................      72,155      78,340      75,540
                                             ----------  ----------  ----------
NET INCOME.................................     105,709     116,187     117,488
DIVIDENDS ON PREFERRED STOCK...............       4,491       8,936       9,942
                                             ----------  ----------  ----------
EARNINGS APPLICABLE TO COMMON STOCK........  $  101,218  $  107,251  $  107,546
                                             ==========  ==========  ==========
COMMON STOCK
  Average Shares of Common Stock Outstand-
   ing (000)...............................      61,122      60,698      60,217
  Basic and Diluted Earnings Per Average
   Share of Common Stock...................  $     1.66  $     1.77  $     1.79
  Dividends Declared Per Share of Common
   Stock...................................  $     1.54  $     1.54  $     1.54
</TABLE>
 
          See accompanying Notes to Consolidated Financial Statements.
 
                                     II-18
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
                          CONSOLIDATED BALANCE SHEETS
 
<TABLE>
<CAPTION>
                                                          AS OF DECEMBER 31,
                                                        -----------------------
                                                           1997        1996
                                                        ----------- -----------
                                                        (DOLLARS IN THOUSANDS)
<S>                                                     <C>         <C>
ASSETS
CURRENT ASSETS
  Cash and cash equivalents............................ $    35,339 $    36,533
  Accounts receivable..................................     197,561     142,431
  Inventories, at average cost
    Fuel (coal, oil and gas)...........................      37,425      36,584
    Materials and supplies.............................      40,518      41,292
  Prepayments..........................................      11,255      20,233
  Deferred energy costs................................      18,017      31,127
  Deferred income taxes, net...........................         776         --
                                                        ----------- -----------
                                                            340,891     308,200
                                                        ----------- -----------
INVESTMENTS
  Investment in leveraged leases.......................      46,375      46,961
  Funds held by trustee................................      48,086      38,923
  Other investments....................................       9,500       4,155
                                                        ----------- -----------
                                                            103,961      90,039
                                                        ----------- -----------
PROPERTY, PLANT AND EQUIPMENT
  Electric utility plant...............................   3,010,060   2,961,940
  Gas utility plant....................................     241,580     229,362
  Common utility plant.................................     154,791     136,897
                                                        ----------- -----------
                                                          3,406,431   3,328,199
  Less: Accumulated depreciation.......................   1,373,676   1,296,513
                                                        ----------- -----------
  Net utility plant in service.........................   2,032,755   2,031,686
  Utility construction work-in-progress................      93,017     118,208
  Leased nuclear fuel, at amortized cost...............      31,031      31,513
  Nonutility property, net.............................      74,811      55,408
  Goodwill, net........................................      92,602      83,505
                                                        ----------- -----------
                                                          2,324,216   2,320,320
                                                        ----------- -----------
DEFERRED CHARGES AND OTHER ASSETS
  Prepaid employee benefits costs......................      58,111      35,146
  Unamortized debt expense.............................      12,911      13,858
  Deferred debt refinancing costs......................      18,760      21,366
  Deferred recoverable income taxes....................      88,683      90,263
  Other................................................      67,948      52,663
                                                        ----------- -----------
                                                            246,413     213,296
                                                        ----------- -----------
TOTAL ASSETS........................................... $ 3,015,481 $ 2,931,855
                                                        =========== ===========
</TABLE>
 
          See accompanying Notes to Consolidated Financial Statements.
 
                                     II-19
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
                          CONSOLIDATED BALANCE SHEETS
 
<TABLE>
<CAPTION>
                                                        AS OF DECEMBER 31,
                                                      ------------------------
                                                         1997         1996
                                                      -----------  -----------
                                                      (DOLLARS IN THOUSANDS)
<S>                                                   <C>          <C>
CAPITALIZATION AND LIABILITIES
CURRENT LIABILITIES
  Short-term debt.................................... $    23,254  $    74,355
  Long-term debt due within one year.................      33,318       27,676
  Variable rate demand bonds.........................      71,500       85,000
  Accounts payable...................................     103,607       81,628
  Taxes accrued......................................      10,723          --
  Interest accrued...................................      19,902       16,193
  Dividends payable..................................      23,775       23,265
  Current capital lease obligation...................      12,516       12,598
  Deferred income taxes, net.........................         --         7,276
  Other..............................................      35,819       31,489
                                                      -----------  -----------
                                                          334,414      359,480
                                                      -----------  -----------
DEFERRED CREDITS AND OTHER LIABILITIES
  Deferred income taxes, net.........................     492,792      479,151
  Deferred investment tax credits....................      39,942       42,501
  Long-term capital lease obligation.................      19,877       20,552
  Other..............................................      30,585       31,522
                                                      -----------  -----------
                                                          583,196      573,726
                                                      -----------  -----------
CAPITALIZATION
  Common stock, $2.25 par value; 90,000,000 shares
   authorized; shares outstanding: 1997--61,210,262,
   1996--60,682,719..................................     139,116      136,765
  Additional paid-in capital.........................     526,812      508,300
  Retained earnings..................................     300,757      293,604
                                                      -----------  -----------
                                                          966,685      938,669
  Treasury shares, at cost:
    1997--619,237 shares, 1996--101,831 shares.......     (11,687)      (2,138)
  Unearned compensation..............................        (502)      (1,618)
                                                      -----------  -----------
  Total common stockholders' equity..................     954,496      934,913
  Cumulative preferred stock.........................      89,703       89,703
  Company obligated mandatorily redeemable preferred
   securities of subsidiary trust holding solely Com-
   pany debentures...................................      70,000       70,000
  Long-term debt.....................................     983,672      904,033
                                                      -----------  -----------
                                                        2,097,871    1,998,649
                                                      -----------  -----------
  Commitments and Contingencies (Notes 15 and 19)....
                                                      -----------  -----------
TOTAL CAPITALIZATION AND LIABILITIES................. $ 3,015,481  $ 2,931,855
                                                      ===========  ===========
</TABLE>
 
          See accompanying Notes to Consolidated Financial Statements.
 
                                     II-20
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                   YEAR ENDED DECEMBER 31,
                                                -------------------------------
                                                  1997       1996       1995
                                                ---------  ---------  ---------
                                                   (DOLLARS IN THOUSANDS)
<S>                                             <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES
 Net income...................................  $ 105,709  $ 116,187  $ 117,488
 Adjustments to reconcile net income to net
  cash provided by operating activities
 Depreciation and amortization................    142,734    134,109    127,268
 Allowance for equity funds used during con-
  struction...................................     (1,337)    (1,338)      (708)
 Investment tax credit adjustments, net.......     (2,560)    (2,560)    (2,516)
 Deferred income taxes, net...................      7,169     33,218     15,992
 Net change in:
  Accounts receivable.........................    (53,911)    (5,030)   (14,022)
  Inventories.................................      4,763     (4,489)    18,590
  Accounts payable............................     16,394     18,418      3,269
  Other current assets & liabilities(1).......     43,450    (48,383)   (14,349)
 Gains on sales of nonutility assets..........    (22,896)      (380)    (3,420)
 Other, net...................................    (18,250)   (17,100)    (8,164)
                                                ---------  ---------  ---------
Net cash provided by operating activities.....    221,265    222,652    239,428
                                                ---------  ---------  ---------
CASH FLOWS FROM INVESTING ACTIVITIES
 Acquisition of businesses, net of cash ac-
  quired......................................    (17,594)    (4,884)  (157,014)
 Capital expenditures.........................   (173,008)  (169,012)  (142,833)
 Change in working capital for construction...         55     (4,880)     1,102
 Sales of nonutility assets...................     34,880        793      4,970
 Decrease in bond proceeds held in trust
  funds.......................................      2,002      7,163      2,658
 Deposits to nuclear decommissioning trust
  funds.......................................     (4,240)    (4,238)    (3,612)
 Other, net...................................      1,132      1,195       (351)
                                                ---------  ---------  ---------
Net cash used by investing activities.........   (156,773)  (173,863)  (295,080)
                                                ---------  ---------  ---------
CASH FLOWS FROM FINANCING ACTIVITIES
 Dividends: Common............................    (93,811)   (93,290)   (92,221)
 Preferred....................................     (4,233)    (9,102)    (9,813)
 Issuances: Long-term debt(2).................    166,200        --     125,800
 Variable rate demand bonds...................        --         --      15,000
 Common stock.................................     17,807        486     24,693
 Preferred securities(3)......................        --      70,000        --
 Redemptions:Long-term debt(2)................    (28,540)    (1,504)    (1,388)
 Variable rate demand bonds...................     (1,800)    (1,500)       --
 Common stock.................................     (7,323)    (5,466)    (1,253)
 Preferred stock..............................        --     (78,383)       --
 Principal portion of capital lease payments..     (6,813)    (5,538)    (7,875)
 Net change in term loan(4)...................        --         --     (45,000)
 Net change in short-term debt................   (102,671)    86,498     53,154
 Cost of issuances and refinancings...........     (4,502)    (3,408)    (1,523)
                                                ---------  ---------  ---------
Net cash used by financing activities.........    (65,686)   (41,207)    59,574
                                                ---------  ---------  ---------
Net change in cash and cash equivalents.......     (1,194)     7,582      3,922
Beginning of year cash and cash equivalents...     36,533     28,951     25,029
                                                ---------  ---------  ---------
End of year cash and cash equivalents.........  $  35,339  $  36,533  $  28,951
                                                =========  =========  =========
</TABLE>
--------
(1)  Other than debt and deferred income taxes classified as current.
(2)  Excluding net change in term loan.
(3)  Company obligated mandatorily redeemable preferred securities of
     subsidiary trust holding solely Company debentures.
(4)  As of December 31, 1994, the Company had a $45.0 million term loan which
     was classified as long-term debt.
 
          See accompanying Notes to Consolidated Financial Statements.
 
                                     II-21
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
       CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDERS' EQUITY
 
<TABLE>
<CAPTION>
                            COMMON              ADDITIONAL                     UNEARNED
                            SHARES       PAR     PAID-IN   RETAINED  TREASURY  COMPEN-
                          OUTSTANDING  VALUE(1)  CAPITAL   EARNINGS   STOCK     SATION    TOTAL
                          -----------  -------- ---------- --------  --------  --------  --------
                                                (DOLLARS IN THOUSANDS)
<S>                       <C>          <C>      <C>        <C>       <C>       <C>       <C>
BALANCE AS OF JANUARY 1,
 1995...................  59,542,006   $133,970  $484,377  $267,002  $    --   $(1,180)  $884,169
Net income..............                                    117,488                       117,488
Cash dividends declared
 Common stock ($1.54 per
  share)................                                    (92,686)                      (92,686)
 Preferred stock........                                     (9,942)                       (9,942)
Issuance of common stock
 DRIP(2)................   1,210,048      2,723    21,806                                  24,529
 Stock options..........       3,900          9        63                                      72
 Other issuance.........       4,731         11        82                                      93
Reacquired common
 shares.................     (63,370)                                  (1,253)      19     (1,234)
LTTP(3).................      62,050                                    1,223   (1,223)       --
Amortization of unearned
 compensation...........                                                           951        951
                          ----------   --------  --------  --------  --------  -------   --------
BALANCE AS OF DECEMBER
 31, 1995...............  60,759,365    136,713   506,328   281,862       (30)  (1,433)   923,440
Net income..............                                    116,187                       116,187
Cash dividends declared
 Common stock ($1.54 per
  share)................                                    (93,294)                      (93,294)
 Preferred stock........                                     (8,936)                       (8,936)
Issuance of common stock
 Business acquisitions..     212,350                                    4,396               4,396
 DRIP(2)................      21,465         47       388                                     435
 Stock options..........       2,400          5        45                                      50
 Expenses...............                              (72)                                    (72)
Reacquired common stock.    (312,861)                 532              (6,504)     363     (5,609)
Amortization of unearned
 compensation...........                              687                         (548)       139
Refinancing of preferred
 stock..................                              392    (2,215)                       (1,823)
                          ----------   --------  --------  --------  --------  -------   --------
BALANCE AS OF DECEMBER
 31, 1996...............  60,682,719    136,765   508,300   293,604    (2,138)  (1,618)   934,913
Net income..............                                    105,709                       105,709
Cash dividends declared
 Common stock ($1.54 per
  share)................                                    (94,065)                      (94,065)
 Preferred stock........                                     (4,491)                       (4,491)
Issuance of common stock
 DRIP(2)................     965,655      2,173    15,485                                  17,658
 LTIP(3)................      71,103        160     1,200                       (1,360)       --
 Stock options..........       5,450         12        88                                     100
 Other issuance.........       2,741          6        47                                      53
Reacquired common stock.    (517,406)                 230              (9,549)   2,162     (7,157)
Amortization of unearned
 compensation...........                            1,462                          314      1,776
                          ----------   --------  --------  --------  --------  -------   --------
BALANCE AS OF DECEMBER
 31, 1997...............  61,210,262   $139,116  $526,812  $300,757  $(11,687) $  (502)  $954,496
                          ==========   ========  ========  ========  ========  =======   ========
</TABLE>
--------
(1)  The Company's common stock has a par value of $2.25 per share and
     90,000,000 shares are authorized.
(2)  Dividend Reinvestment and Common Share Purchase Plan (DRIP)--As of
     December 31, 1997, 3,742,677 shares remained available under the Company's
     registration statement filed with the Securities and Exchange Commission
     for issuance of shares through the DRIP.
(3)  Shares of restricted common stock granted under the Company's Long-Term
     Incentive Plan.
 
          See accompanying Notes to Consolidated Financial Statements.
 
                                     II-22
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1. SIGNIFICANT ACCOUNTING POLICIES
 
NATURE OF BUSINESS
 
  As discussed in Note 4 to the Consolidated Financial Statements, effective
March 1, 1998, Delmarva Power & Light Company (the Company) and Atlantic
Energy, Inc. (Atlantic) consummated a series of merger transactions (the
Merger) which formed a new company named Conectiv, and merged Atlantic out of
existence.
 
  In 1997, the Company's revenues were earned from the following sources: 77%
from the sale and delivery of electricity, 14% from the sale and
transportation of gas, and 9% from other services.
 
  The Company provides regulated electric service (supply and delivery) to
approximately 448,300 customers located on the Delmarva Peninsula and also
sells electricity off-system in markets which are not subject to price
regulation. The Company's traditional electric service territory on the
Delmarva Peninsula, which includes Delaware, ten primarily Eastern Shore
counties in Maryland, and the Eastern Shore of Virginia, encompasses an area
consisting of about 6,000 square miles with a population of approximately 1.2
million.
 
  The Company provides regulated gas service (supply and/or transportation) to
approximately 103,200 customers located in an area consisting of about 275
square miles with a population of approximately 480,000 in northern Delaware,
including the City of Wilmington. The Company also sells gas off-system in
markets which are not subject to price regulation.
 
  "Other services," which are not subject to utility regulation, are sold by
the Company and its wholly owned subsidiaries. As of December 31, 1997, other
services' business activities were conducted primarily by three subsidiaries:
Conectiv Services, Inc., which provides heating, ventilation, and air-
conditioning (HVAC) sales, installation and services; Conectiv Communications,
Inc., which provides local and long-distance phone service; and Delmarva
Capital Investments, Inc., which is involved in power plant operating
services, real estate activities, and leveraged equipment leases. Delmarva
Capital Investments, Inc. sold its landfill and waste-hauling operations in
1997 as discussed in Note 5 to the Consolidated Financial Statements.
 
REGULATION OF UTILITY OPERATIONS
 
  The Company is subject to regulation with respect to its retail utility
sales by the Delaware and Maryland Public Service Commissions (DPSC and MPSC,
respectively) and the Virginia State Corporation Commission (VSCC), which have
powers over rate matters, accounting, and terms of service. Gas sales are
subject to regulation by the DPSC. The Federal Energy Regulatory Commission
(FERC) exercises jurisdiction with respect to the Company's accounting systems
and policies, the transmission of electricity, the wholesale sale of
electricity, and interchange and other purchases and sales of electricity
involving other utilities. The FERC also regulates the price and other terms
of transportation of natural gas purchased by the Company. Excluding off-
system sales not subject to price regulation, the percentage of electric and
gas utility operating revenues regulated by each Commission for the year ended
December 31, 1997, was as follows: DPSC, 64.0%; MPSC, 27.0%; VSCC, 2.7%; and
FERC, 6.3%.
 
  Refer to Note 9 to the Consolidated Financial Statements for a discussion of
regulatory assets arising from the financial effects of rate regulation.
 
CONSOLIDATION POLICY
 
  The consolidated financial statements include the accounts of the Company's
wholly owned subsidiaries. All significant intercompany accounts and
transactions are eliminated in consolidation. Certain reclassifications, not
affecting net income, have been made to conform amounts previously reported to
the current presentation.
 
                                     II-23
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
Primarily, the operating results of nonutility subsidiaries were reclassified
from "Other income" into other classifications within the income statement.
 
USE OF ESTIMATES
 
  The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make certain estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
 
UTILITY REVENUES
 
  At the end of each month, there is an amount of electric and gas service
rendered from the last meter reading to the month-end which has not yet been
billed to customers. The non-fuel (base rate) revenues associated with such
unbilled services are accrued by the Company.
 
  When interim rates are placed in effect subject to refund, the Company
recognizes revenues based on expected final rates.
 
FUEL EXPENSE
 
  Fuel costs charged to the Company's results of operations generally are
adjusted to match fuel costs included in customer billings (fuel revenues).
The difference between fuel revenues and actual fuel costs incurred is
reported on the Consolidated Balance Sheets as "Deferred energy costs." The
deferred balance is subsequently recovered from or returned to utility
customers.
 
  The Company's share of nuclear fuel at the Peach Bottom Atomic Power Station
(Peach Bottom) and the Salem Nuclear Generating Station (Salem) is financed
through a contract which is accounted for as a capital lease. Nuclear fuel
costs, including a provision for the future disposal of spent nuclear fuel,
are charged to fuel expense on a unit-of-production basis.
 
FINANCIAL INSTRUMENTS
 
  The Company's Energy Supply business group (currently known as Conectiv
Energy Supply) uses futures, options and swap agreements to hedge firm
commitments or anticipated transactions of commodities associated with the
energy sector (natural gas and electricity). In order to qualify for hedge
accounting a derivative, at its inception and on an ongoing basis, must be
expected to substantially offset adverse price movements in the firm
commitment or anticipated transaction that it is hedging. Gains and losses
related to qualifying hedges are deferred and are recognized in income when
the underlying transaction occurs. If subsequent to being hedged, underlying
transactions are no longer likely to occur or the hedge is no longer
effective, the related derivatives gains or losses are recognized currently in
income. Gains and losses on derivatives that do not qualify as hedges are
recognized currently in revenues. Premiums paid for options are included as
current assets in the consolidated balance sheet until they are exercised or
expire. Margin requirements for futures contracts are also recorded as current
assets. Unrealized gains and losses on all futures contracts are deferred on
the consolidated balance sheet as either current assets or deferred credits.
The cash flows from derivatives are included in the cash flows from operations
section of the cash flow statement.
 
DEPRECIATION EXPENSE
 
  The annual provision for depreciation on utility property is computed on the
straight-line basis using composite rates by classes of depreciable property.
The relationship of the annual provision for depreciation for
 
                                     II-24
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
financial accounting purposes to average depreciable property was 3.7% for
1997 and 3.6% for 1996 and 1995. Depreciation expense includes a provision for
the Company's share of the estimated cost of decommissioning nuclear power
plant reactors based on amounts billed to customers for such costs. Refer to
Note 7 to the Consolidated Financial Statements for additional information on
nuclear decommissioning.
 
INCOME TAXES
 
  Refer to Note 3, for the Company's accounting policy on income taxes and
investment tax credits.
 
DEBT REFINANCING COSTS
 
  Costs of refinancing debt are deferred and amortized over the period during
which the refinancing costs are recovered in utility rates.
 
INTEREST EXPENSE
 
  The amortization of debt discount, premium, and expense, including
refinancing expenses, is included in interest expense.
 
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
 
  Allowance for Funds Used During Construction (AFUDC) is included in the cost
of utility plant and represents the cost of borrowed and equity funds used to
finance construction of new utility facilities. In the Consolidated Statements
of Income, the borrowed funds component of AFUDC is reported as a reduction of
interest expense and the equity funds component of AFUDC is reported as other
income. AFUDC was capitalized on utility plant construction at the rates of
7.5% in 1997, 6.7% in 1996, and 7.1% in 1995.
 
STOCK-BASED EMPLOYEE COMPENSATION
 
  Refer to Note 10 to the Consolidated Financial Statements for the Company's
accounting policy on stock-based employee compensation.
 
GOODWILL
 
  The Company amortizes goodwill arising from business acquisitions over the
shorter of the estimated useful life or 40 years.
 
LEVERAGED LEASES
 
  As of December 31, 1997, the Company's portfolio of leveraged leases, held
by a nonutility subsidiary, consisted of five aircraft leased to three
separate airlines. The Company's investment in leveraged leases includes the
aggregate of rentals receivable (net of principal and interest on nonrecourse
indebtedness) and estimated residual values of the leased equipment less
unearned and deferred income (including investment tax credits). Unearned and
deferred income is recognized at a level rate of return during the periods in
which the net investment is positive.
 
FUNDS HELD BY TRUSTEE
 
  Funds held by trustee are stated at fair market value and generally include
deposits in the Company's external nuclear decommissioning trusts and
unexpended, restricted, tax-exempt bond proceeds.
 
                                     II-25
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
EARNINGS PER SHARE
 
  Earnings per share has been computed in accordance with Statement of
Financial Accounting Standards (SFAS) No. 128, "Earnings Per Share." Under
SFAS No. 128, basic earnings per share is computed based on earnings
applicable to common stock (net income less preferred dividends) divided by
the weighted average number of common shares outstanding for the period.
Diluted earnings per share is computed based on earnings applicable to common
stock divided by the weighted average number of shares of common stock
outstanding during the period after giving effect to securities considered to
be dilutive common stock equivalents. The effect of dilutive common stock
equivalents was not significant, consequently for 1997, 1996, and 1995, the
Company's basic and diluted earnings per share were the same amounts.
 
CASH EQUIVALENTS
 
  In the consolidated financial statements, the Company considers highly
liquid marketable securities and debt instruments purchased with a maturity of
three months or less to be cash equivalents.
 
2. SUPPLEMENTAL CASH FLOW INFORMATION
 
CASH PAID DURING THE YEAR
 
<TABLE>
<CAPTION>
                                                         1997    1996    1995
                                                        ------- ------- -------
                                                        (DOLLARS IN THOUSANDS)
   <S>                                                  <C>     <C>     <C>
   Interest, net of capitalized amount................. $73,211 $67,596 $62,660
   Income taxes, net of refunds........................ $53,550 $56,582 $66,764
</TABLE>
 
3. INCOME TAXES
 
  The Company files a consolidated federal income tax return which includes
its wholly owned subsidiaries. Income taxes are allocated to the Company's
subsidiaries based upon the taxable income or loss of each subsidiary.
 
  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 the Company's deferred tax liability applicable to
utility operations that has not been reflected in current customer rates
represents income taxes recoverable through future rates and is reflected on
the Consolidated Balance Sheets as "Deferred recoverable income taxes."
Deferred recoverable income taxes were $88.7 million and $90.3 million as of
December 31, 1997 and 1996, respectively.
 
  Deferred income tax expense represents the net change during the reporting
period in the net deferred tax liability and deferred recoverable income
taxes.
 
  Investment tax credits (ITC) from regulated operations are being amortized
over the useful lives of the related utility plant. ITC associated with
leveraged leases are being amortized over the lives of the related leases
during the periods in which the net investment is positive.
 
 
                                     II-26
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
COMPONENTS OF CONSOLIDATED INCOME TAX EXPENSE
 
<TABLE>
<CAPTION>
                                                       1997     1996     1995
                                                      -------  -------  -------
                                                      (DOLLARS IN THOUSANDS)
   <S>                                                <C>      <C>      <C>
   Federal:
     Current......................................... $58,737  $40,953  $51,780
     Deferred........................................   6,589   26,131   12,766
   State:
     Current.........................................   8,810    6,729   10,284
     Deferred........................................     579    7,087    3,226
   Investment tax credit adjustments, net............  (2,560)  (2,560)  (2,516)
                                                      -------  -------  -------
                                                      $72,155  $78,340  $75,540
                                                      =======  =======  =======
</TABLE>
 
RECONCILIATION OF EFFECTIVE INCOME TAX RATE
 
  The amount computed by multiplying income before tax by the federal statutory
rate is reconciled below to the total income tax expense.
 
<TABLE>
<CAPTION>
                                            1997          1996          1995
                                        ------------  ------------  -------------
                                        AMOUNT  RATE  AMOUNT  RATE  AMOUNT   RATE
                                        ------- ----  ------- ----  -------  ----
                                                (DOLLARS IN THOUSANDS)
   <S>                                  <C>     <C>   <C>     <C>   <C>      <C>
   Statutory federal income tax ex-
    pense.............................. $62,252  35%  $68,084  35%  $67,560   35%
   Increase (decrease) due to State
    income taxes, net of federal tax
    benefit............................   6,102   4     8,980   5     8,792    5
   Other, net..........................   3,801   2     1,276 --       (812)  (1)
                                        ------- ---   ------- ---   -------  ---
     Total income tax expense.......... $72,155  41%  $78,340  40%  $75,540   39%
                                        ======= ===   ======= ===   =======  ===
</TABLE>
 
COMPONENTS OF DEFERRED INCOME TAXES
 
  The tax effect of temporary differences that give rise to the Company's net
deferred tax liability are shown below.
 
<TABLE>
<CAPTION>
                                                          AS OF DECEMBER 31,
                                                        -----------------------
                                                           1997        1996
                                                        ----------- -----------
                                                        (DOLLARS IN THOUSANDS)
   <S>                                                  <C>         <C>
   Deferred Tax Liabilities
     Utility plant basis differences
       Accelerated depreciation........................ $   300,558 $   275,230
       Other...........................................     109,303     111,891
     Leveraged leases..................................      38,288      41,604
     Deferred recoverable income taxes.................      41,061      42,556
     Deferred energy costs.............................       7,054      13,240
     Other.............................................      81,482      75,332
                                                        ----------- -----------
     Total deferred tax liabilities....................     577,746     559,853
   Deferred Tax Assets
     Deferred ITC......................................      14,815      15,902
     Other.............................................      70,915      57,524
                                                        ----------- -----------
     Total deferred tax assets.........................      85,730      73,426
                                                        ----------- -----------
   Total deferred taxes, net........................... $   492,016 $   486,427
                                                        =========== ===========
</TABLE>
 
  Valuation allowances for deferred tax assets were not material as of December
31, 1997 and 1996.
 
 
                                     II-27
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
4. MERGERS AND ACQUISITIONS
 
MERGER WITH ATLANTIC ENERGY, INC.
 
  On August 12, 1996, the Company announced plans to merge with Atlantic
Energy, Inc. (Atlantic). On March 1, 1998, the two companies consummated
merger transactions (the Merger) which formed a new company named Conectiv,
and merged Atlantic out of existence. Prior to the Merger, Atlantic owned
Atlantic City Electric Company (ACE), an electric utility, and subsidiaries
engaged in nonutility businesses. ACE serves approximately 481,000 customers
in a 2,700 square mile area in southern New Jersey. For financial information
about Atlantic and ACE, see the tables presented at the end of this note.
 
  Under the Merger approval settlement agreements with the DPSC, MPSC, and
VSCC, the Company will reduce retail base rates in order to share with utility
customers a portion (ranging from approximately 50% to 60%) of the net cost
savings expected to result from the Merger. The annualized amounts of the
retail base rate decreases are as follows:
 
<TABLE>
<CAPTION>
                                               ANNUALIZED BASE
   JURISDICTION                                 RATE DECREASE     EFFECTIVE DATE
   ------------                               ------------------  --------------
   <S>                                        <C>                 <C>
   Delaware retail electric.................. $7.5 million (1.5%) March 1, 1998
   Delaware retail electric.................. $0.6 million (0.1%) March 1, 1999
   Delaware retail electric.................. $0.4 million (0.1%) March 1, 2000
   Delaware gas.............................. $0.5 million (0.5%) March 1, 1999
   Maryland retail electric.................. $3.5 million (1.3%) March 1, 1998
   Virginia retail electric.................. $0.5 million (1.5%) March 1, 1998
</TABLE>
 
  Under the Merger order of the Board of Public Utilities (BPU) in New Jersey,
ACE will share approximately 75% of the estimated Merger savings with its
customers through a $15.75 million (on an annualized basis) electric rate
reduction.
 
  On June 26, 1997, the Company and Atlantic announced that enhanced
retirement offers (ERO) and other employee separation programs were expected
to be utilized to achieve workforce reductions concurrent with the Merger of
the two companies. As of December 31, 1997, the ERO and other employee
separation programs were contingent on consummation of the Merger. Employee
separation costs and other Merger costs related to Delmarva will be expensed
and are estimated to be approximately $55 million to $60 million before taxes
($33 million to $36 million after taxes).
 
  Conectiv, a corporation formed to accomplish the Merger, holds the common
stock of the Company and ACE and is a registered holding company under the
Public Utility Holding Company Act of 1935. Each outstanding share of the
Company's common stock, par value $2.25 per share, is being exchanged for one
share of Conectiv's common stock, par value $0.01 per share. Each share of
Atlantic's common stock, no par value per share, is being exchanged for 0.75
of one share of Conectiv's common stock and 0.125 of one share of Conectiv's
Class A common stock, par value $0.01 per share. Class A common stock gives
holders of Atlantic common stock a proportionately greater opportunity to
share in the growth prospects of, and a proportionately greater exposure to
the uncertainties associated with the electric utility business of ACE.
Earnings applicable to Class A common stock will be equal to 30% of the net of
(1) earnings attributable to ACE's regulated electric utility business, as the
business existed on August 9, 1996, less (2) $40 million per year. Earnings
applicable to Conectiv common stock will be the consolidated earnings of
Conectiv less earnings applicable to Class A common stock.
 
  The Merger is being accounted for under the purchase method of accounting,
with the Company as the acquirer. The total consideration to be paid to
Atlantic's common stockholders, measured by the average daily
 
                                     II-28
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
closing market price of Atlantic's common stock for the three trading days
immediately preceding and the three trading days immediately following the
public announcement of the Merger, is $921.0 million. The consideration paid
plus estimated acquisition costs and liabilities assumed in connection with
the Merger are expected to exceed the net book value of Atlantic's net assets
by approximately $200.5 million, which will be recorded as goodwill. The
actual amount of goodwill recorded will be based on Atlantic's net assets as
of the Merger date and, accordingly, will vary from the preceding estimate
which is based on Atlantic's net assets as of December 31, 1997. The goodwill
will be amortized over 40 years.
 
  Pro forma unaudited financial information for Conectiv on a consolidated
basis, giving effect to the Merger as if it had occurred on January 1, 1997,
and actual reported financial information for Atlantic and ACE is presented
below. The pro forma information excludes expected one-time charges related to
the Merger such as the ERO and other employee separation costs. The pro forma
information is not necessarily indicative of the results that would have
occurred in 1997, or that will occur in the future.
 
SUMMARIZED INCOME STATEMENT INFORMATION (UNAUDITED)
 
<TABLE>
<CAPTION>
                                                YEAR ENDED DECEMBER 31, 1997
                                              --------------------------------
                                              PRO FORMA
                                               CONECTIV   ATLANTIC     ACE
                                              ---------- ---------- ----------
                                                (DOLLARS IN THOUSANDS EXCEPT
                                                     PER SHARE AMOUNTS)
<S>                                           <C>        <C>        <C>
Operating Revenues........................... $2,525,862 $1,102,360 $1,084,890
Net Income................................... $  185,923 $   74,405 $   85,747
Earnings Applicable to Common Stock:
  Common stock............................... $  170,005 $   74,405 $   80,926
  Class A common stock(1).................... $   15,918
Average common shares outstanding (000)
  Common stock...............................    100,500     52,281
  Class A common stock.......................      6,563
Basic and Diluted Earnings per average share
 outstanding of:
  Common stock............................... $     1.69 $     1.42
  Class A common stock....................... $     2.43
</TABLE>
--------
(1) The calculation of pro forma 1997 earnings applicable to Class A common
stock is shown below.
 
<TABLE>
<CAPTION>
                                                         (DOLLARS IN THOUSANDS)
   <S>                                                   <C>
   ACE earnings applicable to common stock..............        $ 80,926
   Add: Termination of employee benefit plans due to
    Merger..............................................          15,600
   Less: Net earnings of nonutility activities specifi-
    cally excluded......................................          (3,466)
   Less: Fixed amount of $40 million per year...........         (40,000)
                                                                --------
   Subtotal.............................................          53,060
   Percentage applicable to Class A common stock........              30%
                                                                --------
   Earnings applicable to Class A common stock..........        $ 15,918
                                                                ========
</TABLE>
 
 
                                     II-29
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
SUMMARIZED BALANCE SHEET INFORMATION (UNAUDITED)
 
<TABLE>
<CAPTION>
                                                    AS OF DECEMBER 31, 1997
                                                --------------------------------
                                                PRO FORMA
                                                 CONECTIV   ATLANTIC     ACE
                                                ---------- ---------- ----------
                                                  (DOLLARS IN THOUSANDS EXCEPT
                                                       PER SHARE AMOUNTS)
   <S>                                          <C>        <C>        <C>
   Current assets.............................. $  599,747 $  268,022 $  239,751
   Noncurrent assets...........................  5,329,687  2,455,862  2,197,004
                                                ---------- ---------- ----------
   Total assets................................ $5,929,434 $2,723,884 $2,436,755
                                                ========== ========== ==========
   Current liabilities......................... $  774,458 $  342,526 $  181,880
   Noncurrent liabilities......................  3,033,099  1,472,325  1,347,892
   Preferred stock and securities..............    283,653    123,950    123,950
   Common shareholders' equity.................  1,838,224    785,083    783,033
                                                ---------- ---------- ----------
   Total capitalization and liabilities........ $5,929,434 $2,723,884 $2,436,755
                                                ========== ========== ==========
</TABLE>
 
ACQUISITION OF CONOWINGO POWER COMPANY
 
  On June 19, 1995, the Company acquired Conowingo Power Company (COPCO), the
Maryland retail electric subsidiary of PECO Energy Company (PECO), for $158.2
million ($157.0 million net of cash acquired). The Company financed the
acquisition with $125.8 million of long-term debt and the balance with short-
term debt. COPCO was merged into the Company and is operated as the Conowingo
District. Approximately 37,500 electric retail customers were added to the
Company's customer base. The acquisition was accounted for as a purchase and,
accordingly, the operating results of the Conowingo District since June 19,
1995 are included in the Consolidated Statements of Income. The purchase price
included $76 million of goodwill which is being amortized on a straight-line
basis over 40 years.
 
  Assuming that the COPCO acquisition had occurred at the beginning of 1995,
the Company's pro forma operating results for 1995 would not have been
materially different from the operating results reported.
 
ACQUISITION OF OTHER SERVICE COMPANIES
 
  The Company's expenditures for HVAC and other service companies acquired in
1997 and 1996 were $17.6 million and $9.3 million (including non-cash
consideration), respectively.
 
5. SALE OF PINE GROVE LANDFILL AND WASTE HAULING COMPANIES
 
  In the fourth quarter 1997, a subsidiary of the Company sold the Pine Grove
Landfill and its related waste-hauling company. The subsidiaries which were
sold had a net book value of approximately $11.3 million and reported revenues
in 1997 of approximately $12.7 million. Pre-tax proceeds received from the
sale were $34.2 million ($33.4 million net of cash sold), resulting in a pre-
tax gain of $22.9 million ($13.7 million after income taxes) or $0.22 per
common share.
 
6. COMMODITY HEDGING ACTIVITIES
 
  The Company's Energy Supply business group (currently known as Conectiv
Energy Supply) engages in commodity hedging activities to minimize the risk of
market fluctuations associated with the purchase and sale of energy
commodities (natural gas and electricity). Some hedging activities are
conducted using energy derivatives. Most of the Company's hedging activity is
conducted by backing physical transactions with offsetting physical positions.
Currently, commodity hedging activities using derivatives are only conducted
in
 
                                     II-30
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
conjunction with transactions that are not subject to price regulation. The
hedging objectives include the assurance of stable and known minimum cash
flows and the fixing of favorable prices and margins when they become
available. Under internal guidelines, risk exposure is mitigated to acceptable
risk tolerance levels.
 
  Energy Supply utilizes futures, options and swap agreements to manage risk.
Futures help manage commodity price risk by fixing purchase or sales prices.
Options provide a floor or ceiling on future purchases or sales prices while
allowing the Company to benefit from favorable price movements. Swaps are
structured to provide the same risk protection as futures and options. Basis
swaps are used to manage risk by fixing the basis differential that exists
between a delivery location index and the commodity futures price.
 
  At December 31, 1997, there were 220 open futures contracts and 30 open
options contracts to purchase natural gas, representing a notional quantity of
2.5 billion cubic feet (Bcf) through October of 1999, at an average price of
$2.35 per thousand cubic feet (Mcf), and 60 open options contracts, to sell
natural gas, representing a notional quantity of 0.6 Bcf through July of 1998
at an average price of $2.38 per Mcf. At December 31, 1997, there was 1 swap
contract to sell electricity, representing a notional quantity of 68,000
megawatt-hours (MWh), through August of 1998 at an average price of $31.91 per
MWh. These open contracts were entered into to hedge the gas and electric
marketing activities of the Energy Supply business group through October 1999.
A total of $0.3 million of unrealized losses were deferred on the consolidated
balance sheet as of December 31, 1997.
 
  The Company is exposed to credit losses in the event of nonperformance by
counterparties to its various hedging contracts. Management has evaluated and
implemented policies and procedures to monitor such risk and believes that the
overall business risk is minimized as a result.
 
7. NUCLEAR DECOMMISSIONING
 
  The Company records a liability for its share of the estimated cost of
decommissioning the Peach Bottom and Salem nuclear reactors over the remaining
lives of the plants based on amounts collected in rates charged to electric
customers. For utility rate-setting purposes, the Company estimates its share
of future nuclear decommissioning costs based on Nuclear Regulatory Commission
(NRC) regulations concerning the minimum financial assurance amount for
nuclear decommissioning. The Company is presently recovering, through electric
rates in the Delaware and Virginia jurisdictions, nuclear decommissioning
costs based on the current NRC minimum financial assurance amount of
approximately $130 million. In the Maryland and FERC jurisdictions, the
Company is presently recovering nuclear decommissioning costs based on the
1990 NRC minimum financial assurance amount of approximately $50 million.
 
  The Company's accrued nuclear decommissioning liability, which is reflected
in the accumulated reserve for depreciation, was $48.8 million as of December
31, 1997. The provision reflected in depreciation expense for nuclear
decommissioning was $4.2 million in 1997, $4.2 million in 1996, and $3.6
million in 1995. External trust funds established by the Company for the
purpose of funding nuclear decommissioning costs had an aggregate book balance
of $46.5 as of December 31, 1997. Earnings on the trust funds are recorded as
an increase to the accrued nuclear decommissioning liability, which, in
effect, reduces the expense recorded for nuclear decommissioning.
 
  The ultimate cost of nuclear decommissioning for the Peach Bottom and Salem
reactors may exceed the NRC minimum financial assurance amount, which is
updated annually under a NRC prescribed formula.
 
  The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry,
including the Company, regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating stations in the
financial statements of electric utilities. In February 1996, the Financial
Accounting Standards Board (FASB) issued the Exposure Draft,
 
                                     II-31
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
"Accounting for Certain Liabilities Related to Closure or Removal of Long-
Lived Assets," which proposed changes in the accounting for closure and
removal costs of long-lived assets, including the recognition, measurement,
and classification of decommissioning costs for nuclear generating stations.
If the proposed changes were adopted: (1) annual provisions for
decommissioning would increase, (2) the estimated cost for decommissioning
would be recorded as a liability rather than as accumulated depreciation, and
(3) trust fund income from the external decommissioning trusts would be
reported as investment income rather than as a reduction of decommissioning
expense. The FASB is uncertain when it will issue a final Statement or a
revised Exposure Draft.
 
8. JOINTLY OWNED PLANT
 
  The Company's Consolidated Balance Sheets include its proportionate share of
assets and liabilities related to jointly owned plant. The Company's share of
operating and maintenance expenses of the jointly owned plant is included in
the corresponding expenses in the Consolidated Statements of Income. The
Company is responsible for providing its share of financing for the jointly
owned facilities. Information with respect to the Company's share of jointly
owned plant as of December 31, 1997 was as follows:
 
<TABLE>
<CAPTION>
                                     MEGAWATT                        CONSTRUCTION
                          OWNERSHIP CAPABILITY PLANT IN ACCUMULATED    WORK IN
                            SHARE     OWNED    SERVICE  DEPRECIATION   PROGRESS
                          --------- ---------- -------- ------------ ------------
                                          (DOLLARS IN THOUSANDS)
<S>                       <C>       <C>        <C>      <C>          <C>
Nuclear
  Peach Bottom..........      7.51%   164 MW   $133,598   $ 83,708     $11,487
  Salem.................      7.41%   164 MW    237,597    105,367      10,558
Coal-Fired
  Keystone..............      3.70%    63 MW     20,582      8,924         112
  Conemaugh.............      3.72%    63 MW     33,295     11,009         176
Transmission Facilities.   Various                4,567      2,306         --
Other Facilities........   Various                1,791        233       2,534
                                               --------   --------     -------
Total...................                       $431,430   $211,547     $24,867
                                               ========   ========     =======
</TABLE>
 
9. REGULATORY ASSETS
 
  In conformity with generally accepted accounting principles, the Company's
accounting policies reflect the financial effects of rate regulation and
decisions issued by regulatory commissions having jurisdiction over the
Company's utility business. In accordance with the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation," the Company
defers expense recognition of certain costs and records an asset, a result of
the effects of rate regulation. Except for deferred energy costs, which are
classified as a current asset, these "regulatory assets" are included on the
Company's Consolidated Balance Sheets under "Deferred Charges and Other
Assets." As of December 31, 1997, the Company had $156.5 million of regulatory
assets, which included the following: deferred energy costs--$18.0 million;
deferred debt refinancing costs--$18.8 million; deferred recoverable income
taxes--$88.7 million (refer to Note 3, to the Consolidated Financial
Statements); deferred recoverable plant costs--$7.8 million; deferred costs
for decontamination and decommissioning of United States Department of Energy
gaseous diffusion enrichment facilities--$6.3 million; deferred demand-side
management costs--$6.2 million; and other regulatory assets--$10.7 million.
The costs of these assets are either being recovered or are probable of being
recovered through customer rates. Generally, the costs of these assets are
recognized in operating expenses over the period the cost is recovered from
customers.
 
  Prices charged to electric utility customers have historically been a
"bundled" price which includes the electricity production (supply) cost and
the delivery cost (transmission and distribution). Various state regulatory
 
                                     II-32
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
commissions and legislatures, as well as federal legislators, are considering
or have approved changes to laws and regulations governing the pricing of
electricity. These changes would generally deregulate the supply component of
the price charged to a customer for electricity. Under existing plans, the
transmission and distribution of electricity would continue to be regulated.
Authoritative accounting guidance issued in 1997 prescribes that a utility
should cease to apply SFAS No. 71 for any separable portion of the business,
such as the electricity supply portion of the business no later than the date
that a specific deregulation plan is finalized. Stranded costs and regulatory
assets attributed to electricity supply would continue to be recognized to the
extent that a transition plan provides for their recovery through cash flows
from the regulated transmission and distribution business.
 
  Proposals concerning deregulation of the electric utility industry are being
considered in Delaware, Maryland, and Virginia (the states which have
jurisdiction over the Company's retail electric utility business), but no
deregulation plan has yet been finalized. Thus, at this time, the Company
cannot predict if or when it would cease applying SFAS No. 71, and the related
financial impacts of discontinuing SFAS No. 71.
 
10. COMMON STOCK
 
  For information concerning issuances and redemptions of common stock during
1995-1997, please refer to the Consolidated Statements of Changes in Common
Stockholders' Equity.
 
  Through the effective date of the Company's Merger with Atlantic (March 1,
1998), the Company's Long-Term Incentive Plan (LTIP) provided long-term
incentives to key employees through contingent awards of performance-based
restricted stock. The restricted stock is earned over a four-year period to
the extent that performance targets are satisfied. Restrictions on shares
contingently granted in 1994-1996 will lapse upon the earlier of March 1, 1998
or the end of the four-year vesting period. Restrictions on shares
contingently granted in 1997 do not lapse on March 1, 1998. During 1997, 1996,
and 1995, the number of restricted shares contingently granted and their fair
values as of grant date was as follows: 1997--110,670 shares, $19 1/8 per
share fair value; 1996--48,750 shares, $22 3/4 per share fair value; 1995--
62,050 shares, $18 9/64 per share fair value.
 
  Changes in stock options granted under the LTIP are summarized below.
 
<TABLE>
<CAPTION>
                                  1997                    1996                    1995
                         ----------------------- ----------------------- -----------------------
                          NUMBER     WEIGHTED     NUMBER     WEIGHTED     NUMBER     WEIGHTED
                         OF SHARES AVERAGE PRICE OF SHARES AVERAGE PRICE OF SHARES AVERAGE PRICE
                         --------- ------------- --------- ------------- --------- -------------
<S>                      <C>       <C>           <C>       <C>           <C>       <C>
Beginning-of-year bal-
 ance...................  43,950      $20.19      46,350      $20.16      53,050      $20.03
Options exercised.......   5,450      $17.61       2,400      $19.69       3,900      $17.85
Options forfeited.......     --          --          --          --        2,800      $20.98
End-of-year balance.....  38,500      $20.55      43,950      $20.19      46,350      $20.16
Exercisable.............  38,500      $20.55      43,950      $20.19      46,350      $20.16
                          ------      ------      ------      ------      ------      ------
</TABLE>
 
  For options outstanding as of December 31, 1997, the range of exercise
prices was $17.50 to $21.25 and the weighted average remaining contractual
life was 2.8 years.
 
  The Company recognizes compensation costs for its stock-based employee
compensation plans based on the accounting prescribed by Accounting Principles
Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Stock-
based employee compensation costs charged to expense were $2.2 million in
1997, $0.3 million in 1996, and $1.3 million in 1995. Pro forma net income,
based on the application of SFAS No. 123, "Accounting for Stock-Based
Compensation," would have changed by $0.5 million or less in 1997, 1996, and
1995, and earnings per share would have changed by less than $0.01 per share
in each year.
 
                                     II-33
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
11. COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
    SUBSIDIARY TRUST HOLDING SOLELY COMPANY DEBENTURES
 
  A wholly owned subsidiary trust (Delmarva Power Financing I) was established
in 1996 as a financing subsidiary of the Company for the purposes of issuing
common and preferred trust securities and holding 8.125% Junior Subordinated
Debentures (the Debentures). The Debentures held by the trust are its only
assets. The trust uses interest payments received on the Debentures it holds
to make cash distributions on the trust securities.
 
  The combination of the obligations of the Company pursuant to the
Debentures, agreements to pay the expenses of the trust and the Company's
guarantee of distributions with respect to trust securities, to the extent the
trust has funds available therefor, constitute a full and unconditional
guarantee by the Company of the obligations of the trust under the trust
securities the trust has issued. The Company is the owner of all of the common
securities of the trust, which constitute approximately 3% of the liquidation
amount of all of the trust securities issued by the trust.
 
  In October 1996, the trust issued $70 million in aggregate liquidation
amount of 8.125% Cumulative Trust Preferred Capital Securities (representing
2,800,000 preferred securities at $25 per security). At the same time,
$72,165,000 in aggregate principal amount of 8.125% Junior Subordinated
Debentures, Series I, due 2036 were issued to the trust. For consolidated
financial reporting purposes, the Debentures are eliminated in consolidation
against the trust's investment in the Debentures. The preferred trust
securities are subject to mandatory redemption upon payment of the Debentures
at maturity or upon redemption. The Debentures are subject to redemption, in
whole or in part at the option of the Company, at 100% of their principal
amount plus accrued interest, after an initial period during which they may
not be redeemed and at any time upon the occurrence of certain events.
 
  In October 1996, the Company used part of the proceeds received from the
trust to purchase and retire $32,087,500 of its $25 par value, 7.75% series
preferred stock, and $31,295,200 of various series of its $100 par value
preferred stock which had an average dividend rate of 5.68%. In December 1996,
the Company used the balance of the proceeds and cash from short-term debt to
fund the redemption of its entire 7.52% preferred stock series which had a
total par value of $15,000,000.
 
 
                                     II-34
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
12. CUMULATIVE PREFERRED STOCK
 
  The Company has $1, $25, and $100 par value per share preferred stock for
which 10,000,000; 3,000,000; and 1,800,000 shares are authorized,
respectively. No shares of the $1 par value per share preferred stock are
outstanding. Shares outstanding for each series of the $25 and $100 par value
per share preferred stock are listed below. Redemptions of preferred stock in
1996 are discussed in Note 11 to the Consolidated Financial Statements.
 
<TABLE>
<CAPTION>
                                               SHARES              AMOUNT
                                             OUTSTANDING   (DOLLARS IN THOUSANDS)
                                           --------------- -----------------------
                              CURRENT
                            REDEMPTION
        SERIES                 PRICE        1997    1996      1997        1996
        ------            ---------------  ------- ------- ----------- -----------
<S>                       <C>              <C>     <C>     <C>         <C>
$25 per share par value
 7 3/4%.................               (1) 316,500 316,500 $     7,913 $     7,913
$100 per share par value
  3.70%-5%..............  $103.00-$105.00  181,698 181,698      18,170      18,170
  6 3/4%................               (2)  35,000  35,000       3,500       3,500
  Adjustable rate(3)....  $           100  151,200 151,200      15,120      15,120
  Auction rate(4).......  $           100  450,000 450,000      45,000      45,000
                          ---------------  ------- ------- ----------- -----------
                                                           $    89,703 $    89,703
                          ===============  ======= ======= =========== ===========
</TABLE>
--------
(1)  Redeemable beginning September 30, 2002, at $25 per share.
(2)  Redeemable beginning November 1, 2003, at $100 per share.
(3)  Average rates were 5.5% during 1997 and 1996.
(4)  Average rates were 4.1% during 1997 and 1996.
 
13. DEBT
 
  Substantially all utility plant of the Company is subject to the lien of the
Mortgage and Deed of Trust collateralizing the Company's First Mortgage Bonds.
 
  As of December 31, 1997, the Company had $200 million of bank lines of
credit available for borrowing except for amounts supporting outstanding
short-term debt. Two separate revolving credit facilities aggregating to $500
million have been arranged for Conectiv effective on March 1, 1998. The
Conectiv credit facilities are comprised of a $300 million credit facility
which expires five years after becoming effective and a $200 million credit
facility which expires one year after becoming effective. The Conectiv
revolving credit facilities will replace the Company's and Atlantic's credit
lines and certain other short-term credit facilities which existed as of
December 31, 1997.
 
  The weighted average interest rates on short-term debt outstanding as of
December 31, 1997 and 1996 were 6.6% and 5.6%, respectively.
 
  Maturities of long-term debt and sinking fund requirements during the next
five years are as follows: 1998--$33.3 million; 1999--$35.7 million; 2000--
$2.7 million; 2001--$3.6 million; 2002--$49.2 million.
 
  In February 1997, the Company issued $124.2 million of unsecured Medium-Term
Notes with maturities of 10 to 30 years and interest rates of 7.06% to 7.72%.
The proceeds were used to refinance short-term debt. On the consolidated
balance sheet as of December 31, 1996, $77.0 million of short-term debt was
reclassified to long-term debt in order to recognize the amount of short-term
debt which had been refinanced with Medium-Term Notes.
 
                                     II-35
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  In September 1997, the Company redeemed $25 million of 6 3/8% First Mortgage
Bonds at maturity through the issuance of short-term debt.
 
  In October 1997, the Company initiated a public offering of up to $75
million of unsecured Medium-Term Notes. Through December 31, 1997, the Company
had issued $42 million of unsecured Medium-Term Notes with maturities of 5 to
9 years and interest rates of 6.6% to 6.8%. The proceeds were used to
refinance short-term debt.
 
  In January 1998, the Company issued $33.0 million of 6.81% unsecured Medium-
Term Notes which mature in 20 years. The Company used $25.4 million of the
proceeds to refinance short-term debt. In recognition of this refinancing
$25.4 million of short-term debt has been reclassified to long-term debt on
the consolidated balance sheet as of December 31, 1997.
 
 
                                     II-36
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
LONG-TERM DEBT OUTSTANDING AS OF DECEMBER 31, 1997 AND 1996 IS PRESENTED
BELOW:
 
<TABLE>
<CAPTION>
                              INTEREST RATES    DUE          1997       1996
                              -------------- ---------    ----------  --------
                                         (DOLLARS IN THOUSANDS)
<S>                           <C>            <C>          <C>         <C>
First Mortgage Bonds                 6 3/8%       1997    $      --   $ 25,000
                                      6.95%       2002        30,000    30,000
                                      6.40%       2003        90,000    90,000
                                7.30%-8.15%  2014-2015        81,000    81,000
                                5.90%-8.50%  2018-2022       208,200   208,200
                                      7.71%       2025       100,000   100,000
                                      6.05%       2032        15,000    15,000
Amortizing First Mortgage
 Bonds                                6.95%  1998-2008        25,103    25,800
                                                          ----------  --------
 Total First Mortgage Bonds                                  549,303   575,000
Other Bonds                     7.15%-7.50%  2011-2017        54,500    54,500
Pollution Control Notes:
 Series 1973                          5.75%       1998         6,000     6,125
 Series 1976                   7.125%-7.25%  1998-2006         2,900     3,000
Medium-Term Notes:                    5.69%       1998        25,000    25,000
                                      7.50%       1999        30,000    30,000
                                6.59%-9.29%       2002        16,000     4,000
                                      8.30%       2004        35,000    35,000
                                      6.84%       2005        10,000       --
                                      6.75%       2006        20,000       --
                               7.06%-8.125%       2007        91,500    81,000
                                7.54%-7.62%       2017        40,700    10,000
                                      6.81%       2018        25,430       --
                                7.61%-9.95%  2019-2021        73,000    67,000
                                      7.72%       2027        30,000    30,000
Other Obligations:              6.00%-9.50%  1998-2002           232     1,502
                                      8.00%       1999(1)      3,660     3,970
                                      9.65%       2002(2)      5,354     6,184
Unamortized premium and dis-
 count, net                                                   (1,589)     (572)
Current maturities of long-
 term debt                                                   (33,318)  (27,676)
                                                          ----------  --------
Total long-term debt                                         983,672   904,033
Variable Rate Demand Bonds
 (3)                                                          71,500    85,000
                                                          ----------  --------
Total long-term debt and
 Variable Rate Demand Bonds                               $1,055,172  $989,033
                                                          ==========  ========
</TABLE>
--------
(1) Repaid through monthly payments of principal and interest using a 15-year
    principal amortization, with the unpaid balance due in September 1999.
(2) Repaid through monthly payments of principal and interest over 15 years
    ending November 2002.
(3) The Company's debt obligations included Variable Rate Demand Bonds (VRDB)
    in the amounts of $71.5 million as of December 31, 1997 and $85.0 million
    as of December 31, 1996. The VRDB are classified as current liabilities
    because the VRDB are due on demand by the bondholder. However, bonds
    submitted to the Company for purchase are remarketed by a remarketing
    agent on a best efforts basis. The Company expects that bonds submitted
    for purchase will continue to be remarketed successfully due to the
    Company's credit worthiness and the bonds' interest rates being set at
    market. The Company also may utilize one of the fixed rate/fixed term
    conversion options of the bonds. Thus, the Company considers the VRDB to
    be a source of long-term financing. The $71.5 million balance of VRDB
    outstanding as of December 31, 1997, matures in 2017 ($26 million), 2028
    ($15.5 million), and 2029 ($30 million). Average annual interest rates on
    the VRDB were 3.8% in 1997 and 3.6% in 1996.
 
                                     II-37
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
 
  The year-end fair values of certain financial instruments are listed below.
The fair values were based on quoted market prices of the Company's securities
or securities with similar characteristics.
 
<TABLE>
<CAPTION>
                                                  1997               1996
                                           ------------------- -----------------
                                           CARRYING    FAIR    CARRYING   FAIR
                                            AMOUNT    VALUE     AMOUNT   VALUE
                                           -------- ---------- -------- --------
                                                  (DOLLARS IN THOUSANDS)
<S>                                        <C>      <C>        <C>      <C>
Funds held by trustee....................  $ 48,086 $   48,086 $ 38,923 $ 38,923
Company Obligated Mandatorily Redeemable
 Preferred Securities of Subsidiary Trust
 Holding Solely Company Debentures.......  $ 70,000 $   72,464 $ 70,000 $ 71,064
Long-Term Debt...........................  $983,672 $1,053,810 $904,033 $944,670
</TABLE>
 
15. COMMITMENTS
 
  The Company's expected capital and acquisition expenditures are estimated to
be approximately $187 million in 1998.
 
  The Company has a 26-year agreement with Star Enterprise effective through
May 2018, to purchase 48 MW of capacity supplied by the Delaware City Power
Plant. By mutual agreement, the capacity portion of the contract has been
suspended from October 1, 1996 until June 1, 2000. In conjunction with the
COPCO acquisition, the Company agreed to purchase capacity and energy from
PECO effective June 19, 1995, through May 31, 2006. The base amount of the
capacity purchase, which is subject to certain possible adjustments, started
at 205 MW, is currently 212 MW, and increases annually to 279 MW in 2006. The
Company also has a contract with Electric Clearinghouse to purchase 100 MW of
energy from January 1, 1998 to December 31, 2005. Under the terms of these
agreements, the Company's expected commitments for capacity and energy charges
are as follows: 1998--$79.5 million; 1999--$87.4 million; 2000--$95.7 million;
2001--$99.2 million; 2002--$103.1 million; after 2002--$410.3 million; total--
$875.2 million.
 
  The Company's share of nuclear fuel at Peach Bottom and Salem is financed
through a nuclear fuel energy contract, which is accounted for as a capital
lease. Payments under the contract are based on the quantity of nuclear fuel
burned by the plants. The Company's obligation under the contract is generally
the net book value of the nuclear fuel financed, which was $31.0 million as of
December 31, 1997.
 
  The Company leases an 11.9% interest in the Merrill Creek Reservoir. The
lease is considered an operating lease and payments over the remaining lease
term, which ends in 2032, are $150.5 million in aggregate. The Company also
has long-term leases for certain other facilities and equipment. Minimum
commitments as of December 31, 1997 under the Merrill Creek Reservoir lease
and all other noncancelable lease agreements (excluding payments under the
nuclear fuel energy contract which cannot be reasonably estimated) are as
follows: 1998--$6.7 million; 1999--$6.6 million; 2000--$5.4 million; 2001--
$5.3 million; 2002--$4.6 million; after 2002--$133.9 million; total--$162.5
million. Approximately 93% of the minimum lease commitments shown above are
payments due under the Merrill Creek Reservoir lease.
 
                                     II-38
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
RENTALS CHARGED TO OPERATING EXPENSES
 
  The following amounts were charged to operating expenses for rental payments
under both capital and operating leases.
 
<TABLE>
<CAPTION>
                                                         1997    1996    1995
                                                        ------- ------- -------
                                                        (DOLLARS IN THOUSANDS)
<S>                                                     <C>     <C>     <C>
Interest on capital leases............................. $ 1,548 $ 1,628 $ 1,773
Amortization of capital leases.........................   6,499   5,653   8,044
Operating leases.......................................  11,590  13,795  13,619
                                                        ------- ------- -------
                                                        $19,637 $21,076 $23,436
                                                        ======= ======= =======
</TABLE>
 
16. PENSION PLAN
 
  The Company currently has a defined benefit pension plan covering all
regular employees. The benefits are based on years of service and the
employee's compensation. The Company's funding policy is to contribute each
year the net periodic pension cost for that year; however, contributions have
not been necessary during 1995-1997 due to the pension expense credit and the
plans' funding status.
 
  Based on fair values as of December 31, 1997, pension plan assets were
comprised of the following: publicly traded equity securities ($466.5 million
or 60%), U.S. government obligations ($121.5 million or 16%), and primarily
investment grade corporate and other fixed income obligations ($183.3 million
or 24%).
 
  The following schedules show the funded status of the plan, the components
of pension cost, and assumptions.
 
RECONCILIATION OF FUNDED STATUS OF THE PLAN
 
<TABLE>
<CAPTION>
                                                        AS OF DECEMBER 31,
                                                      ------------------------
                                                         1997         1996
                                                      -----------  -----------
                                                      (DOLLARS IN THOUSANDS)
<S>                                                   <C>          <C>
Accumulated benefit obligation
  Vested............................................. $   365,698  $   330,639
  Nonvested..........................................      36,015       24,869
                                                      -----------  -----------
                                                          401,713      355,508
Effect of estimated future compensation increases....     113,877       95,132
                                                      -----------  -----------
Projected benefit obligation.........................     515,590      450,640
Plan assets at fair value............................     771,257      676,189
                                                      -----------  -----------
Excess of plan assets over projected benefit obliga-
 tion................................................     255,667      225,549
Unrecognized prior service cost......................      26,945       28,980
Unrecognized net gain................................    (205,732)    (196,496)
Unrecognized net transition asset....................     (23,199)     (26,513)
                                                      -----------  -----------
Prepaid pension cost................................. $    53,681  $    31,520
                                                      ===========  ===========
</TABLE>
 
                                     II-39
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
COMPONENTS OF NET PENSION COST
 
<TABLE>
<CAPTION>
                                                  1997       1996       1995
                                                ---------  ---------  ---------
                                                   (DOLLARS IN THOUSANDS)
<S>                                             <C>        <C>        <C>
Service cost-benefits earned during period....  $  12,779  $  13,172  $   9,719
Interest cost on projected benefit obligation.     34,173     32,531     30,654
Actual return on plan assets..................   (115,982)   (82,488)  (135,850)
Net amortization and deferral.................     46,869     22,164     83,981
                                                ---------  ---------  ---------
Net pension cost..............................  $ (22,161) $ (14,621) $ (11,496)
                                                =========  =========  =========
 
ASSUMPTIONS
 
<CAPTION>
                                                  1997       1996       1995
                                                ---------  ---------  ---------
<S>                                             <C>        <C>        <C>
Discount rates used to determine projected
 benefit obligation as of December 31.........    7.00%      7.50%      7.00%
Rates of increase in compensation levels......    5.00%      5.00%      5.00%
Expected long-term rates of return on assets..    9.00%      9.00%      8.75%
</TABLE>
 
  The Company maintains a 401(k) savings plan for its employees. The plan
provides for employee contributions up to 15% of pay and for $0.50 in matching
contributions by the Company for each dollar contributed up to 5% of employee
pay. The Company's matching contributions charged to expense were $3.0 million
in 1997, $2.4 million in 1996, and $2.3 million in 1995.
 
17. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
 
  The Company provides health-care and life insurance benefits to its retired
employees and substantially all of the Company's employees may become eligible
for these benefits upon retirement. The Company's policy is to fund its
obligation to the extent that costs are reflected in customer rates, including
amounts which are capitalized. Based on fair values as of December 31, 1997,
the plan's assets consisted of $35.7 million (73%) of equity securities,
including mutual funds and directly owned publicly traded securities, and
$12.9 million (27%) of intermediate term investment grade bond mutual funds.
 
  The following schedules show the funded status of the plan, the components
of the cost of postretirement benefits other than pensions, and assumptions.
 
RECONCILIATION OF FUNDED STATUS OF THE PLAN
 
<TABLE>
<CAPTION>
                                                   AS OF DECEMBER 31,
                                                   --------------------
                                                     1997       1996
                                                   ---------  ---------
                                                   (DOLLARS IN THOUSANDS)
<S>                                                <C>        <C>       
Accumulated postretirement benefit obligation
 (APBO)
  Active employees fully eligible for benefits.... $   6,361  $   4,568
  Other active employees..........................    26,365     23,900
  Current retirees................................    47,774     45,373
                                                   ---------  ---------
                                                      80,500     73,841
Plan assets at fair value.........................    48,591     36,075
                                                   ---------  ---------
APBO in excess of plan assets.....................   (31,909)   (37,766)
Unrecognized prior service cost...................       317        370
Unrecognized net gain.............................   (18,238)   (16,855)
Unrecognized transition obligation................    54,259     57,876
                                                   ---------  ---------
Prepaid postretirement benefit cost............... $   4,429  $   3,625
                                                   =========  =========
</TABLE>
 
                                     II-40
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
ANNUAL COST OF POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
 
<TABLE>
<CAPTION>
                                                      1997     1996      1995
                                                     -------  -------  --------
                                                      (DOLLARS IN THOUSANDS)
<S>                                                  <C>      <C>      <C>
Service cost-benefits earned during period.........  $ 2,393  $ 2,512  $  2,152
Interest cost on projected benefit obligation......    5,547    5,213     6,601
Actual return on plan assets.......................   (9,108)  (4,241)   (1,008)
Amortization of the unrecognized transition obliga-
 tion..............................................    3,617    3,617     3,617
Other, net.........................................    5,869    2,072       149
                                                     -------  -------  --------
Net postretirement benefit cost....................  $ 8,318  $ 9,173  $ 11,511
                                                     =======  =======  ========
 
ASSUMPTIONS
 
<CAPTION>
                                                      1997     1996      1995
                                                     -------  -------  --------
<S>                                                  <C>      <C>      <C>
Discount rates used to determine APBO as of Decem-
 ber 31............................................   7.00%    7.50%    7.00%
Rates of increase in compensation levels...........   5.00%    5.00%    5.00%
Expected long-term rates of return on assets.......   9.00%    9.00%    8.75%
Health-care cost trend rate........................   7.50%    8.00%    10.50%
</TABLE>
 
  The health-care cost trend rate, or the expected rate of increase in health-
care costs, is assumed to decrease to 7.0% in 1998 and gradually decrease to
5.4% by 2002. Increasing the health-care cost trend rates of future years by
one percentage point would increase the accumulated postretirement benefit
obligation by $5.1 million and would increase annual aggregate service and
interest costs by $0.5 million.
 
18. SALEM NUCLEAR GENERATING STATION
 
  The Company owns 7.41% of the Salem Nuclear Generating Station (Salem),
which consists of two pressurized water nuclear reactors operated by Public
Service Electric & Gas Company (PSE&G). Salem Units 1 and 2 were removed from
operation by PSE&G in the second quarter of 1995 due to operational problems,
and maintenance and safety concerns. After receiving NRC authorization, PSE&G
returned Unit 2 to service on August 30, 1997. Due to degradation of a
significant number of tubes in the Unit 1 steam generators, PSE&G replaced the
Unit 1 steam generators. The Company has been informed by PSE&G that the NRC's
Readiness Assessment Team has concluded that Unit 1 is ready to return to
operation. PSE&G expects Unit 1 will return to service in the second quarter
of 1998, subject to final NRC approval.
 
  In May 1997, the Company settled its lawsuit against PSE&G concerning Salem
operations. Under the settlement's primary provision, PSE&G paid the Company
$12 million in settlement of all claims related to the lawsuit. In August
1997, the DPSC approved a settlement regarding the ratemaking treatment of the
PSE&G settlement payment and the replacement power costs attributable to the
Salem outages. The DPSC settlement provided for recovery of approximately one-
half of the replacement power costs from electric customers and retention of
two-thirds of the PSE&G settlement payment by the Company's stockholders.
Based on expected similar ratemaking treatment in other regulatory
jurisdictions and the terms of these settlements, the Company charged $3.1
million, net of the stockholder portion of the PSE&G settlement payment, to
fuel expenses in 1997. In 1996 and 1995, approximately $10.1 million and $4.1
million, respectively, were charged to fuel expenses for replacement power
costs and capacity deficiency charges owed to the Pennsylvania-New Jersey-
Maryland (PJM) Interconnection. (Utilities which are parties to the PJM
Interconnection agreement are required to pay capacity deficiency charges if
capacity levels are lower than the level committed to by the PJM utility.) The
aforementioned fuel-related expenses decreased earnings for 1997, 1996, and
1995 because these amounts were not expected to be recovered through
customers' fuel rates. The Company also estimates that operation and
maintenance costs were higher than normal by $4 million, $9 million, and $5
million in 1997, 1996, and 1995, respectively, because of the Salem outages.
 
                                     II-41
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  As previously reported, on February 27, 1996, the co-owners of Salem,
including the Company, filed a complaint in the United States District Court
for New Jersey against Westinghouse Electric Corporation (Westinghouse), the
designer and manufacturer of the Salem steam generators. The complaint, which
seeks to recover from Westinghouse the costs associated with and resulting
from the cracks discovered in Salem's steam generators and with replacing such
steam generators, alleges violations of federal and New Jersey Racketeer
Influenced and Corrupt Organizations Acts, fraud, negligent misrepresentation
and breach of contract. The estimated replacement cost of such generators is
between $150 million and $170 million. On October 1, 1997, Westinghouse filed
a motion for summary judgment. The parties argued the summary judgment motion
and a decision on the motion is expected after March 1, 1998. No trial date
has been set. The Company cannot predict the outcome of this lawsuit.
 
19. CONTINGENCIES
 
ENVIRONMENTAL MATTERS
 
  The Company 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. The disposal of Company-generated
hazardous substances can result in costs to clean up facilities found to be
contaminated due to past disposal practices. Federal and state statutes
authorize governmental agencies to compel responsible parties to clean up
certain abandoned or uncontrolled hazardous waste sites. The Company is
currently a potentially responsible party (PRP) at three federal superfund
sites and is alleged to be a third-party contributor at three other federal
superfund sites. The Company also has two former coal gasification sites in
Delaware and one former coal gasification site in Maryland, each of which is a
state superfund site. The Company's current liabilities included $2 million as
of December 31, 1997 and 1996, respectively, for clean-up and other potential
costs related to the federal and state superfund sites. The Company does not
expect such future costs to have a material effect on the Company's financial
position or results of operations.
 
NUCLEAR INSURANCE
 
  In the event of an incident at any commercial nuclear power plant in the
United States, the Company could be assessed for a portion of any third-party
claims associated with the incident. Under the provisions of the Price
Anderson Act, if third-party claims relating to such an incident exceed $200
million (the amount of primary insurance), the Company could be assessed up to
$23.7 million for such third-party claims. In addition, Congress could impose
a revenue-raising measure on the nuclear industry to pay such claims.
 
  The co-owners of Peach Bottom and Salem maintain property insurance coverage
in the aggregate amount of $2.8 billion for each unit for loss or damage to
the units, including coverage for decontamination expense and premature
decommissioning. The Company is self-insured, to the extent of its ownership
interest, for its share of property losses in excess of insurance coverages.
Under the terms of the various insurance agreements, the Company could be
assessed up to $3.2 million in any policy year for losses incurred at nuclear
plants insured by the insurance companies.
 
  The Company is a member of an industry mutual insurance company, which
provides replacement power cost coverage in the event of a major accidental
outage at a nuclear power plant. The premium for this coverage is subject to
retrospective assessment for adverse loss experience. The Company's present
maximum share of any assessment is $1.3 million per year.
 
 
                                     II-42
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
20. NONUTILITY SUBSIDIARIES
 
  The following presents summarized financial information about the Company's
nonutility wholly owned subsidiaries. Common general and administrative costs
are allocated to the Company's nonutility subsidiaries on the basis of cost
causative factors. The Company's management believes the cost allocations are
reasonable.
 
  Excluding non-regulated energy sales conducted by operating divisions of the
Company, as of December 31, 1997, the following three subsidiaries conducted
substantially all of the Company's nonutility business: Conectiv Services,
Inc., which provides HVAC sales, installation and services; Conectiv
Communications, Inc., which provides local and long-distance phone service;
and Delmarva Capital Investments, Inc. (DCI), which is involved in power plant
operating services, real estate activities, and leveraged equipment leases.
Delmarva Capital Investments, Inc. sold its landfill and waste-hauling
operations in 1997 as discussed in Note 5 to the Consolidated Financial
Statements.
 
<TABLE>
<CAPTION>
                                          1997           AS OF DECEMBER 31, 1997
                                 ----------------------- ------------------------
                                 OPERATING      NET        TOTAL    STOCKHOLDERS
                                 REVENUES  INCOME/(LOSS)  ASSETS       EQUITY
                                 --------- ------------- ------------------------
                                              (DOLLARS IN THOUSANDS)
<S>                              <C>       <C>           <C>       <C>
Conectiv Services, Inc. .......   $62,755     $(6,330)   $    53,208 $    41,529
Conectiv Communications, Inc. .   $ 1,670     $(5,671)   $    46,486 $    37,843
Delmarva Capital Investments,
 Inc. .........................   $49,557     $21,481    $    76,469 $    14,501
</TABLE>
 
  DCI's net income was $6.3 million in 1996 and $4.1 million in 1995. DCI's
total assets were $101.1 million and $117.1 million at December 31, 1996 and
1995, respectively. Conectiv Services, Inc. and Conectiv Communications, Inc.
started operations in late 1996.
 
21. SEGMENT INFORMATION
 
  In 1997, the FASB issued SFAS No. 131, "Disclosure About Segments of an
Enterprise and Related Information." SFAS No. 131 will supersede SFAS No. 14,
"Financial Reporting for Segments of a Business Enterprise," and become
effective for the Company's annual financial statements in 1998. Under SFAS
No. 131, operating segments will be based on the manner in which management
operates the business. The Company expects that its operating segments will be
Conectiv Energy Delivery, Conectiv Energy Supply, and Conectiv Enterprises, as
described in Management's Discussion and Analysis of Financial Condition and
Results of Operations. In brief, the businesses of these operating segments
are as follows: Conectiv Energy Supply--produces and purchases energy, and
sells bulk energy in competitive markets; Conectiv Energy Delivery--delivers
energy to customers at regulated prices over transmission and distribution
systems; Conectiv Enterprises--sells retail energy, HVAC services, local and
long distance telephone service, and other services in competitive markets.
 
  The operating segments presented below are based on the criteria of SFAS No.
14. For a description of the Electric, Gas, and Other Services' businesses,
refer to Note 1 to the Consolidated Financial Statements. Under SFAS No. 131,
the energy and delivery businesses embedded within both the Electric and Gas
businesses will be unbundled and reported under Conectiv Energy Supply and
Conectiv Energy Delivery, respectively. Unregulated retail electric and gas
sales will be reported within Conectiv Enterprises. The businesses in Other
Services will primarily be included in Conectiv Enterprises.
 
                                     II-43
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
<TABLE>
<CAPTION>
                                                 1997        1996       1995
                                              ----------  ---------- ----------
                                                   (DOLLARS IN THOUSANDS)
<S>                                           <C>         <C>        <C>
OPERATING REVENUES
 Electric--service territory................. $  953,356  $  911,620 $  857,633
 Electric--interchange deliveries............     36,430      75,301     47,271
 Electric--off-system merchant...............    102,358         --         --
                                              ----------  ---------- ----------
 Total electric..............................  1,092,144     986,921    904,904
                                              ----------  ---------- ----------
 Gas--service territory......................    117,190     109,658     95,441
 Gas--off-system merchant....................     86,867       4,626        --
                                              ----------  ---------- ----------
 Total gas...................................    204,057     114,284     95,441
                                              ----------  ---------- ----------
 Other services..............................    127,301      74,370     55,380
                                              ----------  ---------- ----------
  Total...................................... $1,423,502  $1,175,575 $1,055,725
                                              ----------  ---------- ----------
OPERATING INCOME
 Electric.................................... $  223,164  $  231,144 $  233,430
 Gas.........................................     20,801      24,092     18,537
 Other services..............................     (9,536)      2,064      2,458
                                              ----------  ---------- ----------
  Total...................................... $  234,429  $  257,300 $  254,425
                                              ----------  ---------- ----------
DEPRECIATION EXPENSE
 Electric.................................... $  119,877  $  115,448 $  105,780
 Gas.........................................      8,795       7,726      7,242
 Other services..............................      7,668       5,397      6,371
                                              ----------  ---------- ----------
  Total...................................... $  136,340  $  128,571 $  119,393
                                              ----------  ---------- ----------
CAPITAL EXPENDITURES
 Electric.................................... $  113,922  $  137,886 $  120,535
 Gas.........................................     15,310      20,874     17,145
 Other services..............................     43,776      10,252      5,153
                                              ----------  ---------- ----------
  Total...................................... $  173,008  $  169,012 $  142,833
                                              ----------  ---------- ----------
IDENTIFIABLE ASSETS, NET
 Electric.................................... $2,537,796  $2,490,212 $2,493,797
 Gas.........................................    250,596     217,586    189,339
 Other Services..............................    161,432     135,482    119,098
 Unallocated.................................     65,657      88,575     64,451
                                              ----------  ---------- ----------
  Total...................................... $3,015,481  $2,931,855 $2,866,685
                                              ----------  ---------- ----------
</TABLE>
 
 
                                     II-44
<PAGE>
 
                        DELMARVA POWER & LIGHT COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
22. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
 
  The quarterly data presented below reflect all adjustments necessary in the
opinion of the Company for a fair presentation of the interim results.
Quarterly data normally vary seasonally because of temperature variations,
differences between summer and winter rates, the timing of rate orders, and
the scheduled downtime and maintenance of electric generating units.
 
  As discussed in Note 5 to the Consolidated Financial Statements, in the
fourth quarter of 1997, net income was increased by $13.7 million ($0.22 per
average common share) due to the sale of the Pine Grove Landfill and its
related waste-hauling company.
 
<TABLE>
<CAPTION>
                                                                                  EARNINGS
                                                        APPLICABLE    AVERAGE       PER
 UARTERQ                  OPERATING  OPERATING   NET    TO COMMON      SHARES     AVERAGE
 ENDED                     REVENUE    INCOME    INCOME    STOCK     OUTSTANDING    SHARE
-------                   ---------- --------- -------- ---------- -------------- --------
                                   (DOLLARS IN THOUSANDS)          (IN THOUSANDS)
 <S>                      <C>        <C>       <C>      <C>        <C>            <C>
 1997
 March 31................ $  346,079 $ 63,150  $ 25,793  $ 24,578      60,856      $0.40
 June 30.................    310,968   51,376    17,997    16,913      61,177       0.28
 September 30............    400,502   85,509    39,411    38,319      61,247       0.63
 December 31.............    365,953   34,394    22,508    21,408      61,207       0.35
                          ---------- --------  --------  --------      ------      -----
                          $1,423,502 $234,429  $105,709  $101,218      61,122      $1.66
                          ========== ========  ========  ========      ======      =====
 1996
 March 31................ $  308,619 $ 75,620  $ 35,143  $ 32,703      60,759      $0.54
 June 30.................    267,783   52,316    22,325    19,902      60,703       0.33
 September 30............    308,340   77,536    37,035    34,605      60,667       0.57
 December 31.............    290,833   51,828    21,684    20,041      60,665       0.33
                          ---------- --------  --------  --------      ------      -----
                          $1,175,575 $257,300  $116,187  $107,251      60,698      $1.77
                          ========== ========  ========  ========      ======      =====
</TABLE>
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
 
  None.
 
                                     II-45
<PAGE>
 
                                   PART III
 
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
 
DIRECTORS
 
  The following were the Directors of the Company on February 28, 1998, prior
to consummation of the Merger:
 
CLASS I DIRECTORS WITH TERMS EXPIRING IN 2000--
 
  R. FRANKLIN BALOTTI, age 55. Director since 1995. Member of the law firm of
Richards Layton & Finger, Wilmington, Delaware. Mr. Balotti is a past
President of the Delaware Bar Association and serves as a member of the Board
of Overseers of Widener University School of Law.
 
  MICHAEL B. EMERY, age 59. Director since 1994. Retired, Former Senior Vice
President of E.I. duPont deNemours & Company (a diversified chemical, energy,
and specialty products company), Wilmington, Delaware. Mr. Emery serves as
Chairperson of the Development Council of Delaware Technical and Community
College.
 
  SARAH I. GORE, age 62. Director since 1990. Human Resources Associate, W. L.
Gore & Associates, Inc. (a high technology manufacturing company), Newark,
Delaware. Member of the Delaware Advisory Board of CoreStates Bank,
Wilmington, Delaware. Mrs. Gore and her family created the I Have a Dream
Foundation of Delaware for which she serves as a director.
 
CLASS II DIRECTORS WITH TERMS EXPIRING IN 1998--
 
  HOWARD E. COSGROVE, age 54. Director since 1986. Chairman, President and
Chief Executive Officer of the Company. Mr. Cosgrove also is a director of the
Federal Reserve Bank of Philadelphia and is a Trustee of The University of
Delaware.
 
  AUDREY K. DOBERSTEIN, age 65. Director since 1992. President of Wilmington
College, New Castle, Delaware. Director of Mellon Bank Delaware (N.A.),
Wilmington, Delaware. Dr. Doberstein also serves as a member of the Board of
Directors of Blue Cross/Blue Shield of Delaware.
 
  JAMES C. JOHNSON, age 62. Director since 1992. Retired, Former President and
Chief Executive Officer of Loyola Federal Savings Bank, Baltimore, Maryland.
Mr. Johnson is a member of the Board of Directors of the Chesapeake Bay Trust.
 
  WESTON E. NELLIUS, age 61. Director since 1995. President, Nellius
Management Associates, Inc. (an information technology, financial, management
and government relations consulting firm), Dover, Delaware. Director of
Nations Bank of Delaware (N.A.), Dover, Delaware. Mr. Nellius also serves as a
member of the Board of Directors of The Delaware Family Foundation and the
Board of the Delaware Region of the National Conference of Christians and
Jews.
 
CLASS III DIRECTORS WITH TERMS EXPIRING IN 1999--
 
  MICHAEL G. ABERCROMBIE, age 58. Director since 1993. President of Cato, Inc.
(a petroleum distributorship), Salisbury, Maryland. Mr. Abercrombie is a past
President of The Community Foundation of the Eastern Shore and is a past
Chairman of the Greater Salisbury Committee.
 
  ROBERT D. BURRIS, age 53. Director since 1993. President of Burris Foods,
Inc. (a refrigerated food distribution company), Milford, Delaware. Mr. Burris
also is a director of the Federal Reserve Bank of Philadelphia and is a member
of the Board of BayHealth, Inc.
 
 
                                     III-1
<PAGE>
 
EXECUTIVES
 
  Information about the executive officers of the registrant is included under
Item 1.
 
ITEM 11. EXECUTIVE COMPENSATION
 
  The summary compensation table below (along with important explanatory notes
on the next page) provides information about salary and other compensation.
Following the summary compensation table are tables about long-term incentive
plan awards and pension benefits, a performance graph that compares the
Company's common stockholder return to both the S&P 500 Index and the Dow
Jones Electric Utilities Index, and a report by the Compensation Committee
about executive compensation.
 
                          SUMMARY COMPENSATION TABLE
 
<TABLE>
<CAPTION>
                                                                              LONG TERM COMPENSATION
                                                                           -----------------------------                 
                                                   ANNUAL COMPENSATION            AWARDS         PAYOUTS
                                               --------------------------- --------------------- -------
                                                                   OTHER                                   ALL
                                                                   ANNUAL  RESTRICTED SECURITIES          OTHER
                                                                   COMP-     STOCK    UNDERLYING  LTIP    COMP-
                                                                  ENSATION  AWARD(S)   OPTIONS   PAYOUTS ENSATION
      NAME AND PRINCIPAL POSITION         YEAR SALARY($) BONUS($)    $        $(1)       (#)       ($)    ($)(2)
      ---------------------------         ---- --------- -------- -------- ---------- ---------- ------- --------
<S>             <C>                       <C>  <C>       <C>      <C>      <C>        <C>        <C>     <C>      
H. E. Cosgrove  Chairman of the Board,    1997  400,000        0      0         0          0         0    18,981
                President and Chief       1996  400,000        0      0         0          0         0    18,115
                Executive Officer         1995  345,000   73,500      0         0          0         0    19,498
T. S. Shaw      Executive Vice President  1997  219,249   27,100      0         0          0         0     6,563
                                          1996  180,000   52,300      0         0          0         0     6,333
                                          1995  165,000   34,400      0         0          0         0     8,179
B. S. Graham    Senior Vice President and 1997  184,000   27,100      0         0          0         0     3,390
                Chief Financial Officer   1996  180,000   92,300      0         0          0         0     5,529
                                          1995  165,000   33,500      0         0          0         0     6,793
J. W. Ford (3)  Senior Vice President     1997  184,000   23,400      0         0          0         0     3,960
                                          1996  180,000   32,300      0         0          0         0     3,767
                                          1995  125,461   32,500      0         0          0         0       145
R. E. Klesius   Senior Vice President     1997  168,000   24,700      0         0          0         0     4,792
                                          1996  165,000   24,600      0         0          0         0     5,994
                                          1995  157,000   31,100      0         0          0         0     7,978
</TABLE>
--------
# Number of units $--Dollar amounts
(1) Dividends on shares of performance-based restricted stock are accrued at
    the same rate as that paid to all holders of Common Stock. Restricted
    stock awards are reported in the Long-Term Incentive Plan Table on page
    III-4. As of December 31, 1997: Mr. Cosgrove held 62,750 shares of
    restricted stock with a value of $1,275,606.25 (6,070, 11,570, 9,590, and
    35,520 shares with a grant-date market price of $22.00, $19.50, $22.875,
    and $19.625 per share respectively); Mr. Shaw held 14,810 shares of
    restricted stock with a value of $301,878.75 (1,350, 2,870, 2,580, and
    8,010 shares with a grant-date market price of $22.00, $19.50, $22.875,
    and $19.625 per share respectively); Mrs. Graham held 14,530 shares of
    restricted stock with a value of $295,718.75 (1,070, 2,870, 2,580, and
    8,010 with a grant-date market price of $22.00, $19.50, $22.875, and
    $19.625 respectively); Mr. Ford held 13,460 shares of restricted stock
    with a value of $272,178.75 (2,870, 2,580 and 8,010 shares with a grant-
    date market price of $19.50, $22.785, and $19.625 per share respectively);
    and Mr. Klesius held 14,070 shares of restricted stock with a value of
    $287,356.25 (1,350, 2,870, 2,580, and 7,270 shares with a grant-date
    market price of $22.00, $19.50, $22.875, and $19.625 per share
    respectively). During 1997, all the shares granted in 1993 were forfeited
    because the Company's Total Stockholder Return was 65th out of 87
    companies in its Peer Group over the four-year performance period.
(2) The amounts of All Other Compensation for each of the named executive
    officers for fiscal year 1997 include the following: for Mr. Cosgrove,
    $2,083 in Company matching contributions to the Company's Savings & Thrift
    Plan, and $16,688 in Company matching contributions under the Company's
    Deferred Compensation Plan Thrift Fund; for Mr. Shaw, $2,458 in Company
    matching contributions to the Company's Savings & Thrift Plan, and $3,895
    in Company matching contributions under the Company's Deferred
    Compensation Plan Thrift Fund; for Mrs. Graham, $2,483 in Company matching
    contributions to the Company's Savings & Thrift Plan, and $697 in Company
    matching contributions under the Company's Deferred Compensation Plan
    Thrift Fund; for Mr. Ford, $3,750 in Company matching contributions to the
    Company's Savings & Thrift Plan; and for Mr. Klesius, $2,444 in Company
    matching contributions to the Company's Savings & Thrift Plan, and $2,138
    in Company matching contributions under the Company's Deferred
    Compensation Plan Thrift Fund. In addition, the amounts of All Other
    Compensation for each of the five named executive officers includes $210
    in term life insurance premiums paid by the Company on such officer's
    behalf (which insurance is provided on an equal basis to all employees of
    the Company).
(3) Mr. Ford joined the Company on March 13, 1995.
 
                                     III-2
<PAGE>
 
OPTION EXERCISES DURING 1997 AND YEAR-END OPTION VALUES
 
  The following table provides information related to options held by the
named executive officers at fiscal year-end 1997. The Board of Directors, at
its January 1993 meeting, approved an amendment to the Company's Long-Term
Incentive Plan eliminating awards of Common Stock options and dividend rights
effective fiscal year 1993. The Company does not grant stock appreciation
rights.
 
   AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION VALUES
 
<TABLE>
<CAPTION>
                                                      NUMBER OF
                                                     SECURITIES     VALUE OF
                                                     UNDERLYING   UNEXERCISED
                                                     UNEXERCISED  IN-THE-MONEY
                                                     OPTIONS AT    OPTIONS AT
                                                      FY-END(#)    FY-END($)
                     SHARES ACQUIRED      VALUE      ----------- --------------
NAME                 ON EXERCISE (#) REALIZED ($)(*) EXERCISABLE EXERCISABLE(*)
----                 --------------- --------------- ----------- --------------
<S>                  <C>             <C>             <C>         <C>
H. E. Cosgrove......       --              --          14,400       $30,525
T. S. Shaw..........       --              --             --            --
B. S. Graham........       --              --             --            --
J. W. Ford..........       --              --             --            --
R. E. Klesius.......       --              --           4,400         8,950
</TABLE>
--------
(*) The closing price for the Company's Common Stock as reported by the New
    York Stock Exchange on December 31, 1997, was $23.0625. The value is
    calculated on the basis of the difference between the exercise price of
    the options and $23.0625, which difference is multiplied by the number of
    options. For Mr. Cosgrove, 8,500 of the exercisable options have an
    exercise price of $21.25, and 5,900 have an exercise price of $20.50. For
    Mr. Klesius, 3,100 of the exercisable options have an exercise price of
    $21.25, and 1,300 have an exercise price of $20.50. The options all are
    exercisable currently. No options were exercised in 1997 by the named
    executive officers.
 
 
                                     III-3
<PAGE>
 
PERFORMANCE-BASED RESTRICTED STOCK GRANTS CHART
 
  The following table shows the number of shares of performance-based
restricted stock that were granted to the named executive officers as part of
the Company's Long-Term Incentive Plan in 1997. It also shows the number of
shares of Common Stock that would be awarded if the threshold, target or
maximum performance is achieved at the end of the four-year performance
period.
 
             LONG-TERM INCENTIVE PLANS AWARDS IN LAST FISCAL YEAR
 
<TABLE>
<CAPTION>
                                                                   ESTIMATED FUTURE
                                                               PAYOUTS UNDER NON-STOCK
                            NUMBER OF                             PRICE-BASED PLANS
                         SHARES, UNITS OR    PERFORMANCE OR    ------------------------
                           OTHER RIGHTS    OTHER PERIOD UNTIL  THRESHOLD TARGET MAXIMUM
    NAME                      (#)(*)      MATURATION OR PAYOUT    (#)     (#)     (#)
    ----                 ---------------- -------------------- --------- ------ -------
<S>                      <C>              <C>                  <C>       <C>    <C>
H. E. Cosgrove..........      35,520             4 yrs.          8,880   35,520 53,280
T. S. Shaw..............       8,010             4 yrs.          2,003    8,010 12,015
B. S. Graham............       8,010             4 yrs.          2,003    8,010 12,015
J. W. Ford..............       8,010             4 yrs.          2,003    8,010 12,015
R. E. Klesius...........       7,270             4 yrs.          1,818    7,270 10,905
</TABLE>
--------
(*) Shares of performance-based restricted stock were granted as a part of the
    Company's Long-Term Incentive Plan. Actual awards are made after the end
    of a four-year performance cycle and are based on a comparison of the
    combination of the Company's performance prior to the Merger, and
    Conectiv's performance after the Merger, as measured by Total Stockholder
    Return (stock appreciation and dividends paid), to the Peer Group. The
    target number of shares (100% of the shares originally granted) will be
    awarded if the Total Stockholder Return (four year cumulative as compared
    to the Peer Group) is in the 55th percentile (up to 149.9% to be awarded
    for Total Stockholder Return up to the 84.9th percentile). The threshold
    number of shares (25% of the shares originally granted) will be awarded if
    the Total Stockholder Return (four year cumulative as compared to the Peer
    Group) is in the 40th percentile (up to 99.9% to be awarded for Total
    Stockholder Return up to the 54.9th percentile). The maximum number of
    shares (150% of the shares originally granted) will be awarded if the
    Total Stockholder Return (four year cumulative as compared to the Peer
    Group) is in the 85th percentile or greater. The actual percentage of the
    originally granted shares to be awarded will be determined by
    interpolation of a straight line within the percentile ranges.
 
 
                                     III-4
<PAGE>
 
RETIREMENT PLAN
 
                              PENSION PLAN TABLE
 
                         ANNUAL RETIREMENT BENEFITS TO
                       PERSONS IN SPECIFIED REMUNERATION
                     AND YEARS OF SERVICE CLASSIFICATIONS
 
<TABLE>
<CAPTION>
 AVERAGE ANNUAL
EARNINGS FOR THE 5
CONSECUTIVE YEARS                 CREDITED YEARS OF SERVICE
 OF EARNINGS THAT        ----------------------------------------------------
   RESULT IN THE           15       20          25          30          35
 HIGHEST AVERAGE         YRS.(1)   YRS.        YRS.        YRS.        YRS.
------------------       ------- --------    --------    --------    --------
<S>                      <C>     <C>         <C>         <C>         <C>
 $125,000............... $21,735 $ 38,132    $ 47,665    $ 57,198    $ 66,732
  200,000(2)............  35,415   62,132      77,665      93,198     108,732
  300,000(2)............  53,655   94,132     117,665     141,198(3)  164,732(3)
  400,000(2)............  71,895  126,132(3)  157,665(3)  189,198(3)  220,732(3)
  500,000(2)............  90,135  158,132(3)  197,665(3)  237,198(3)  276,732(3)
</TABLE>
--------
(1) Represents reduced early retirement benefit payable at age 55.
(2) Effective January 1, 1998, annual compensation recognized in computing
    Average Annual Earnings under the Retirement Plan may not exceed $160,000
    as limited by Section 401(a)(17) of the Internal Revenue Code of 1986, as
    amended (the "Internal Revenue Code"). With the exception of this
    limitation, and the exclusion of compensation paid under the Company's
    Long-Term Incentive Plan and Company contributions under the Savings &
    Thrift Plan and Supplemental Executive Retirement Plan ("SERP"), Average
    Annual Earnings include substantially all cash compensation shown in the
    Summary Compensation Table on page III-2. Compensation in excess of the
    limitation of Section 401(a)(17) is recognized in computing the benefit
    payable under the SERP.
(3) For 1998, the limit on annual benefits payable under qualified, defined
    benefit plans is $130,000. The amount in excess of $130,000 in the above
    table would be payable under the Company's SERP.
 
  The Company has a trusteed, noncontributory Retirement Plan covering all
regular employees. Directors who are not employees of the Company do not
participate in the Plan. Subject to the maximum limitation on benefits imposed
by Section 415(b) of the Internal Revenue Code, the Retirement Plan provides
management employees, including all officers, a retirement income equal to
years of service times the sum of (1) plus (2) where (1) is 1.30% of the
Average Annual Earnings (for the five consecutive years of earnings that
result in the highest annual average) up to the Average Social Security
Earnings Base ($31,128 in 1998), and where (2) is 1.60% of such Average Annual
Earnings above the Average Social Security Earnings Base. Effective January 1,
1996, a second formula was added (i.e., 1.50% of Average Annual Earnings times
years of service). Management employees will receive a pension computed under
this second formula if it results in a greater pension amount. Normal
retirement is age 65; however, employees may retire as early as age 55 with an
actuarial reduction in benefits and also at age 60 without such reduction,
provided they have completed the requisite number of years of service with the
Company. Aside from the integration feature of the above-described benefit
formula, retirement benefits are not subject to any reduction for Social
Security benefits or other offset amounts.
 
  Annual benefits payable upon retirement will be in the form of a joint and
50% survivor annuity for married individuals and a straight life annuity for
single individuals. Both the straight life and joint and survivor forms are
paid to management employees in specified remuneration and years of service
classifications, as illustrated in the Pension Plan Table.
 
  Mr. Cosgrove, Mrs. Graham, and Messrs. Shaw, Ford and Klesius have,
respectively, 31, 14, 26, 3 and 32 credited years of service under the
Company's Retirement Plan.
 
                                     III-5
<PAGE>
 
  In the event of a change in control of the Company, as defined in the
Retirement Plan, the Plan's surplus assets are to be allocated to the extent
available to (1) satisfy all Plan liabilities, (2) fund certain post-
retirement medical benefits and death benefits and (3) subject to certain
limitations, increase the benefits payable to employees who were active
participants on the date of such change in control by crediting each such
participant with an additional five years of deemed credited service and five
years of deemed salary increases at 5% per year. If the Plan is terminated or
merged or benefits are reduced within five years of such change in control,
any remaining surplus assets would be allocated to the extent available to (1)
provide a 2% cost of living increase for retirees for each year of retirement
and (2) subject to certain limitations, increase the benefits payable to
employees who were active participants on the date of such termination, merger
or benefit curtailment by crediting each such participant with additional
years of deemed credited service for the ten-year period following such change
in control together with salary increases at 5% per year for such period. The
Retirement Plan requires that the obligations described above that are assumed
following such a change in control must be funded by the purchase of a
guaranteed annuity contract.
 
DIRECTORS' COMPENSATION
 
  Directors who are not officers of the Company receive an annual retainer of
$12,000, plus $700 for each Board meeting attended and $600 for each Committee
of the Board meeting attended. Chairpersons of the Audit, Compensation, and
Nuclear Oversight Committees receive an additional annual retainer of $1,000.
There have been no changes in the amounts of Directors' compensation since May
1, 1992. Beginning on June 1, 1997, the $12,000 annual retainer paid to each
Director and the $1,000 annual retainer paid to Chairpersons of the Committees
previously mentioned were paid in Common Stock of the Company.
 
SEVERANCE AGREEMENTS AND OTHER PROVISIONS RELATING TO POSSIBLE CHANGE OF
CONTROL
 
  The Company has entered into severance agreements with each of the five
named executive officers. The severance agreements are intended to encourage
the continued dedication of members of the Company's management. These
agreements provide potential benefits for such persons upon actual or
constructive termination of employment (other than for cause) following a
change of control of the Company, as defined in such agreements. Each affected
employee would receive a severance payment equal to 2.99 times base salary (as
defined in Section 280G of the Internal Revenue Code), and entitlement to
Company-paid life, disability, medical and dental benefits for 24 months
following termination, as well as an amount in cash equal to the actuarial
equivalent value of accrued retirement pension credits equal to 24 months
following termination; provided, however, that if any payments under such
agreements would not be deductible by the Company as a result of Section 280G
of the Internal Revenue Code, the amounts payable under such agreements will
be reduced until the entire payment is deductible. The Merger comes within the
definition of "change of control" under the severance agreements. Mr. Ford has
terminated employment in connection with the Merger, and has received the
severance payment and will receive the other benefits under the severance
agreement. Although Mr. Klesius will remain with Conectiv for a transition
period, he also has terminated employment in connection with the Merger, and
will receive both the severance payment and the other benefits under the
severance agreement.
 
  The Company has the following additional benefit plans containing "change in
control" provisions. These plans, for which the five named executive officers
are eligible, were established by the Board of Directors. In the event of a
change in control: The SERP provides for the Company to satisfy the
liabilities accrued under the SERP through the purchase of fully-paid annuity
or life insurance contracts; the Company's Management Incentive Compensation
Plan provides that, at the option of the participant, the Company will pay all
Incentive Awards earned but not distributed; the Company's Management Life
Insurance Plan provides for the Company to prepay all premiums to any life
insurance policy under this Insurance Plan; and the Company's Long-Term
Incentive Plan provides that all restrictions on shares of performance-based
restricted stock will lapse immediately, without regard to performance
criterion, and shares will be issued to all participants, and all dividends in
each Dividend Rights Account will be paid or, at the employee's option, the
ongoing obligation to make such payments will continue. Mr. Ford has
terminated employment in connection with the Merger, and has received the
severance payment. He also will receive the other benefits under his severance
agreement and the
 
                                     III-6
<PAGE>
 
benefit plans described above. Although Mr. Klesius will remain with Conectiv
for a transition period, he also has terminated employment in connection with
the Merger, and will receive the severance payment, the other benefits under
his severance agreement and the benefit plans mentioned above.
 
BOARD COMPENSATION COMMITTEE REPORT
 
                        DELMARVA POWER & LIGHT COMPANY
                      BOARD COMPENSATION COMMITTEE REPORT
 
PRINCIPLES OF EXECUTIVE COMPENSATION PROGRAM
 
OVERALL OBJECTIVES
 
  This will be the last Board Compensation Committee Report for the Company.
Effective March 1, 1998, a series of merger transactions were consummated,
involving the Company and Atlantic Energy, Inc. (the "Merger"). A new holding
company, named Conectiv, was formed as a result of the Merger, and the shares
of the Company's Common Stock were exchanged for shares of Conectiv common
stock. The next Compensation Committee Report will be contained in the 1999
proxy statement for Conectiv.
 
  The Company's executive compensation program was designed to motivate its
senior executives to achieve the Company's goals of providing the Company's
stockholders with a competitive return on their investment and its customers
with high quality service at a competitive price.
 
Toward that end, the Company's program was designed to provide total
compensation that emphasizes long-term performance which increases stockholder
value and reflects market conditions for executive talent. This program has
included the following elements:
 
  .Long-term incentive compensation based on long-term performance which
  increases stockholder value;
 
  .Annual incentive compensation that varies based on corporate and
  individual performance; and
 
  .Base salary levels related to position and individual performance.
 
  In its role as administrator of the executive compensation program, the
Compensation Committee has placed particular emphasis on long-term
compensation as a critical element of total compensation. The Compensation
Committee's objective has always been to provide incentives which have a
direct link to increased stockholder value.
 
TOTAL COMPENSATION
 
  Total compensation (base salary, annual incentive, and long-term incentive)
opportunities were developed for Company executives utilizing the Edison
Electric Institute ("EEI") Executive Compensation Survey Report and other
general competitive industry surveys, as well as counsel with the Company's
outside consulting firm, Towers Perrin. In general, the total compensation
structure for executives was targeted to the median of a blend of utility and
general competitive industry peers contained in the EEI Executive Compensation
Survey Report (the "Peer Group")/1/ and other general competitive industry
surveys with individual reward levels varying based on contribution and
performance. The targets for each component of the executive compensation
program have been reviewed on an annual basis to ensure alignment with the
Company's compensation philosophy and to ensure a proper balance between
short- and long-term objectives. Annual base salary increases reflect the
individual's performance and contribution over several years in addition to
the results for a single year. Year-to-year changes in annual incentive awards
have varied with the performance results of the individual as well as
--------
/1/ The compensation Peer Group includes some, but not all, of the same
    companies as the published industry index in the Comparison of Five Year
    Cumulative Total Return graph included in this Proxy Statement.
 
                                     III-7
<PAGE>
 
the Company. The Company's base salary level for the five named executive
officers as a group was below the median of the salary levels defined by the
Peer Group.
 
  The Company has examined the IRS regulation pertaining to the $1,000,000
compensation deductibility cap for each of the five named executive officers
and has determined that the regulation is not applicable to the Company, since
the total compensation for any one individual is significantly below the cap.
 
ANNUAL INCENTIVE COMPENSATION
 
  The Company's Management Incentive Compensation Plan was designed to
motivate participants to accomplish stretch financial and individual goals.
The corporate financial goals relate to both customer and stockholder
measurements. Two criteria must be met before there were any awards under this
plan: (1) at least half of specified corporate goals must have been met; and
(2) actual earnings per share ("EPS") for the year must have met or exceeded
95% of the Company's EPS goal.
 
  The awards, upon satisfaction of these criteria, contained two components:
corporate performance and individual performance. For the senior executives,
award targets for both performance components were set annually by the
Compensation Committee and have varied among individuals. Approximately 75% of
the maximum incentive opportunity for the Company's senior executives,
including those named in the compensation tables in this Proxy Statement,
arose out of corporate performance, which was measured by (1) the Company's
EPS as compared with the Company's EPS goal, and (2) the Company's net change
in electric rates per kilowatt hour as compared against the net change in the
electric rates of the average of a regional survey/2/ over a three-year
period. Generally, the payout in connection with corporate performance was
determined in the following manner. The base multiplier of 1.00 was adjusted
at year-end based upon corporate performance. This adjustment could not exceed
150% and was based upon the EPS and Rates performance at the corporate level.
EPS Adjustment: If actual EPS was higher than the goal, the multiplier was
increased by 5% for each 1% above the goal. If actual EPS was lower than the
goal, the multiplier was decreased by 20% for each 1% below the goal. Rates
Adjustment: If the Company's rates decreased more, or increased less, than the
regional survey average, the multiplier was increased by 5% for each 1%
positive deviation. If the Company's rates increased more, or decreased less,
than the regional survey average, the decrease was 2% for each 1% negative
deviation.
 
  The remaining approximately 25% of the maximum incentive opportunity for
senior executives arose out of individual performance, with a particular focus
on achievement of individual goals, as evaluated at each year-end merit
review.
 
LONG-TERM INCENTIVE COMPENSATION
 
  The Company's Long-Term Incentive Plan has reinforced the importance of
providing investors with a competitive return on their investment. Awards
granted under this Plan in 1997 consisted entirely of shares of performance-
based restricted stock. Participants in the Plan were granted shares of the
Company's stock, subject to forfeiture if performance criteria are not met
over a four-year performance period. After the end of the four-year
performance cycle, a combination of the Company's performance prior to the
Merger, and Conectiv's performance after the Merger, as measured by Total
Stockholder Return (stock appreciation and dividends paid), will be compared
to the Peer Group to determine the number of shares of unrestricted Conectiv
common stock to be paid out to participants. Upon consummation of the Merger,
the restricted Common Stock of the Company held in the Long-Term Incentive
Plan were converted to shares of Conectiv common stock, as required by the
merger agreement. For grants made under the Plan in prior years, for which the
performance cycle had not yet run (1995 and 1996 grants), 100% of the shares
originally granted were awarded as unrestricted shares of Company Common Stock
upon consummation of the Merger, pursuant to the "change in control
provisions"
--------
/2/ The regional survey includes some, but not all, of the same companies as
    the Peer Group and the published industry index in the Comparison of Five
    Year Cumulative Total Return graph included in this Proxy Statement.
 
                                     III-8
<PAGE>
 
contained in the Plan. The grants made in 1993 and 1994 did not meet the
performance criteria and were forfeited.
 
  For the 1997 grants, the following amounts of shares of Conectiv common
stock will be awarded at the end of the four-year performance cycle if the
combination of the Total Stockholder Return for the Company prior to the
Merger, and Conectiv after the Merger, over the four-year cycle as compared to
the Peer Group falls in the following percentile ranges: no award for Total
Stockholder Return less than the 40th percentile; 25%--99.9% of the shares
originally granted for Total Stockholder Return in the 40th percentile to the
54.9th percentile; 100%--149.9% of the shares originally granted for Total
Stockholder Return in the 55th percentile to the 84.9th percentile; and 150%
of the shares originally granted for Total Stockholder Return in the 85th
percentile or greater. The actual percentage of the originally granted shares
to be awarded will be determined by interpolation of a straight line within
the percentile ranges.
 
SUMMARY OF ACTIONS TAKEN BY THE COMPENSATION COMMITTEE
 
  The Compensation Committee of the Company, which has consisted entirely of
outside directors, has reviewed and approved each of the transactions with the
Company's officers under the Company's executive compensation plans, and has
assessed the effectiveness of the program as a whole. This included activities
such as reviewing the design of the Company's various incentive plans and
assessing the reasonableness of the overall executive compensation program.
 
  In addition, the Committee has administered key aspects of the Company's
salary program and incentive plans, such as approving the annual salary
increase budget, setting the targets used in the annual incentive plan,
approving the size of the annual incentive pool and approving the grants under
the annual and long-term incentive plans. With respect to the annual incentive
pool, individual awards were not limited by the size of the total pool, but
were limited to maximum amounts annually determined by the Compensation
Committee. For 1997 performance, within the senior executive group, these
maximum amounts have varied among individuals.
 
  Finally, the Committee has implemented the Company's executive compensation
program, which includes the Chief Executive Officer and the Company's four
other most highly-compensated executives--i.e., the five "named executive
officers."
 
  Significant actions by the Committee for fiscal year 1997 included setting
salaries and reviewing criteria for and approving the grants of annual
incentive awards and long-term incentive opportunities. For 1997, total
compensation opportunities for the named executive officers were consistent
with the compensation levels in the evolving utility and general industry
markets for executive talent. The Committee believes these compensation levels
to be appropriate, since having the ability to attract and retain high-quality
executives from both within and outside the utility industry is increasingly
important in an environment where competition is increasing and predicted to
become more intense. In 1997, the Compensation Committee made its senior
management team's compensation opportunities more sensitive to the long-term
performance of the Company (and Conectiv, after the Merger) and increased
value to the Company's and Conectiv's stockholders. The Committee's purpose in
doing so was to keep management interests in line with the long-term
stockholder interests. Accordingly, more of the total compensation of the
Company's management team was granted in the form of incentive awards tied to
long-term corporate performance. The targets to achieve those incentives were
also set at higher levels than in the past./3/ Thus, the potential for reward
at the end of the four-year performance cycle is greater, but higher levels of
performance, measured based on the Company's performance prior to the Merger,
and Conectiv's performance
--------
/3/ The only exception is that the target for the maximum level was decreased
    from 90% to 85%. The 90% target had proven unrealistic based on an
    evaluation of the companies that have achieved this level of performance.
    Most of these companies have had an extraordinary event over the
    performance cycle which enabled them to reach the maximum target level.
    The 85% level still represents a significant challenge but has the
    potential to be achieved, while ensuring that management's interests
    continue to be aligned with stockholders.
 
                                     III-9
<PAGE>
 
thereafter, will be required to achieve that potential. Consistent with the
intention to tie more compensation opportunity to long-term corporate
performance, the base salaries for the senior management team were increased
slightly, with lower annual incentive awards than in the past.
 
CHIEF EXECUTIVE OFFICER COMPENSATION
 
SALARY ACTION
 
  Chief Executive Officer, Howard E. Cosgrove's salary remained the same as in
1996, at $400,000. This salary placed Mr. Cosgrove at approximately 97% of the
median for Chief Executive Officers in comparably-sized utilities.
 
  Consistent with the Compensation Committee's goal to tie more of its
executives' total compensation opportunity to corporate performance, the
Compensation Committee decided to freeze Mr. Cosgrove's base salary for the
1997 fiscal year and not to grant any annual incentive award. This decision
was not intended as a negative reflection on Mr. Cosgrove's performance. On
the contrary, the Committee commends Mr. Cosgrove's leadership and supports
the direction the Company is taking in this increasingly competitive and
uncertain environment. As an expression of confidence in Mr. Cosgrove's
ability to drive the Company's, and now Conectiv's, success in the long term,
increases in Mr. Cosgrove's total compensation will be earned in long-term
incentives which are tied to the Company's and Conectiv's long-term
performance.
 
ANNUAL INCENTIVE AWARD
 
  In lieu of an annual incentive award, a greater long-term incentive
opportunity was granted to Mr. Cosgrove in 1997 than otherwise would have been
granted, to allow Mr. Cosgrove to share in corporate success if stockholder
value is increased through better long-term corporate performance.
 
LONG-TERM INCENTIVE PLAN
 
  Long-term incentive grants represent an increasingly important component of
the compensation opportunity for the Chief Executive Officer. Consistent with
the Company's Long-Term Incentive Plan, the Committee determined the 1997
grants of performance-based restricted stock (reflected in the compensation
tables contained in this Proxy Statement) made to Mr. Cosgrove. The initial
award of performance-based restricted stock is targeted at providing total
compensation, including a long-term opportunity, consistent with similar
awards made to other executives from the Peer Group. The number of shares
actually earned, if any, will be awarded in the year 2001 based on a
comparison of the combination of the Company's performance prior to the
Merger, and Conectiv's performance thereafter, as measured by Total
Stockholder Return compared to the Peer Group over the four-year period 1997-
2000, as discussed under "Long-Term Incentive Compensation" on page III-8. As
discussed above, Mr. Cosgrove's 1997 base salary was not increased and he
received no annual incentive award; instead, all of Mr. Cosgrove's opportunity
to increase his total compensation in 1997 was in the form of long-term
incentives tied to corporate performance over the four-year period.
 
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
 
  The Compensation Committee is comprised solely of non-officer directors.
There are no Compensation Committee interlocks.
 
COMPENSATION COMMITTEE
 
S. I. Gore, Chairperson
M. B. Emery
J. C. Johnson
 
                                    III-10
<PAGE>
 

 
                  COMPARISON OF FIVE YEAR TOTAL RETURN*
          AMONG DELMARVA POWER & LIGHT COMPANY, THE S&P INDEX
               AND THE DOW JONES ELECTRIC UTILITIES INDEX
            [graph appears here--plot points are listed below]
                                       Dow Jones
                                    Electric Utility
      Year            Company            Index           S&P 500
      ----            -------       ----------------     -------
      1992              100              100               100
      1993              108              112               110
      1994               90               98               112
      1995              122              129               153
      1996              117              130               189
      1997              144              165               252
* $100 invested on 12/31/92 in stock or index including reinvestment of
  dividends. Fiscal year ending December 31.
 
                                     III-11
<PAGE>
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
  Security Ownership of Directors and Executive Officers as of December 31,
1997:
 
<TABLE>
<CAPTION>
                                                                  SHARES OF
                                                              COMMON STOCK(1)(2)
                                                              ------------------
<S>                                                           <C>
DIRECTORS
Class I Directors with Terms Expiring in 2000--
  R. Franklin Balotti........................................        1,894
  Michael B. Emery...........................................        1,728
  Sarah I. Gore..............................................        1,753
Class II Directors with Terms Expiring in 1998--
  Howard E. Cosgrove.........................................       79,703(3)(4)
  Audrey K. Doberstein.......................................        1,728
  James C. Johnson...........................................        1,809
  Weston E. Nellius..........................................        1,228
Class III Directors with Terms Expiring in 1999--
  Michael G. Abercrombie.....................................        1,789(5)
  Robert D. Burris...........................................        1,195
OTHER EXECUTIVE OFFICERS
  Barbara S. Graham..........................................       18,493(3)
  Thomas S. Shaw.............................................       21,293(3)
  Joseph W. Ford.............................................       13,863(3)
  Ralph E. Klesius...........................................       22,329(3)(4)
</TABLE>
 
  As of December 31, 1997, all current executive officers and directors as a
group (14 persons) owned beneficially 168,805 shares of Common Stock,
representing 0.27% of the shares of Common Stock outstanding.
 
    (1) Each of the individuals listed beneficially owned less than 1% of the
  Company's outstanding common stock.
 
    (2) Includes shares owned beneficially by Mr. Cosgrove and Other
  Executive Officers of the Company pursuant to the Company's Savings &
  Thrift Plan, Payroll-Based Employee Stock Ownership Plan, and Deferred
  Compensation Plan Thrift Fund.
 
    (3) Includes 62,750, 14,530, 14,810, 13,460, and 14,070 shares, of
  performance-based restricted stock for Mr. Cosgrove, Mrs. Graham, and
  Messrs. Shaw, Ford and Klesius respectively, which were granted as a part
  of the Company's Long-Term Incentive Plan. The number of shares actually
  earned will depend on the Company's performance, as measured by Total
  Stockholder Return (stock appreciation and dividends paid), relative to the
  Peer Group at the end of a four-year period.
 
    (4) Does not include 14,400 and 4,400 shares of Common Stock which
  Messrs. Cosgrove and Klesius respectively, are deemed to have beneficial
  ownership. These shares may be acquired upon the exercise of stock options
  granted under the Company's Long-Term Incentive Plan.
 
    (5) Does not include 300 shares of Common Stock owned by Mr.
  Abercrombie's wife, beneficial ownership of which he disclaims.
 
                                    III-12
<PAGE>
 
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
 
  The following table provides information with respect to the only person who
is known to Delmarva Power & Light Company to be the beneficial owner of more
than 5% of the outstanding shares of Common Stock of the Company.
 
<TABLE>
<CAPTION>
             NAME                                          SHARES
        AND ADDRESS OF                                  BENEFICIALLY PERCENT OF
       BENEFICIAL OWNER                                   OWNED(1)     CLASS
       ----------------                                 ------------ ----------
   <S>                                                  <C>          <C>
   Franklin Resources, Inc.............................  5,801,750      9.5%
   777 Mariners Island Boulevard
   P.O. Box 7777
   San Mateo, California 94403
</TABLE>
--------
(1) The share ownership shown above is based on Amendment No. 5 to a Form 13G,
    dated January 16, 1998 filed with the Securities and Exchange Commission.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
  None.
 
 
                                    III-13
<PAGE>
 
                                    PART IV
 
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
 
  (a) The following documents are filed as part of this report:
 
    1. Financial Statements--The following financial statements are contained
  in Item 8 of Part II.
 
<TABLE>
<CAPTION>
                                                                        PAGE NO.
                                                                        --------
   <S>                                                                  <C>
   Report of Independent Accountants..................................   II-17
   Consolidated Statements of Income for the three years ended Decem-
    ber 31, 1997......................................................   II-18
   Consolidated Balance Sheets as of December 31, 1997 and 1996.......   II-19
   Consolidated Statements of Cash Flows for the three years ended De-
    cember 31, 1997...................................................   II-21
   Consolidated Statements of Changes in Common Stockholders' Equity
    for the three years ended December 31, 1997.......................   II-22
   Notes to Consolidated Financial Statements.........................   II-23
</TABLE>
 
    2. Financial Statement Schedules--No financial statement schedules have
  been filed since the required information is not present in amounts
  sufficient to require submission of the schedule or because the information
  required is included in the respective financial statements or the notes
  thereto.
 
    3. Schedule of Operating Statistics for the three years ended December
  31, 1997 can be found on page IV-4 of this report.
 
    4. Exhibits
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBER
 -------
 <C>     <S>
   2     Amended and Restated Agreement and Plan of Merger, dated as of
         December 26, 1996, between the Company, Atlantic Energy, Inc.,
         Conectiv, Inc. and DS Sub, Inc. (Filed with Registration Statement No.
         333-18843.)
   3-A   Copy of the Restated Certificate and Articles of Incorporation
         effective as of April 12, 1990. (Filed with Registration Statement No.
         33-50453.)
   3-B   Copy of the Company's Certificate of Designation and Articles of
         Amendment establishing the 7 3/4% Preferred Stock--$25 Par. (Filed
         with Registration Statement No. 33-50453.)
   3-C   Copy of the Company's Certificate of Designation and Articles of
         Amendment establishing the 6 3/4% Preferred Stock. (Filed with
         Registration Statement No. 33-53855.)
   3-D   A copy of the Company's Certificate of Amendment of Restated
         Certificate and Articles of Incorporation, filed with the Delaware
         Secretary of State, effective as of June 7, 1996. (Filed with
         Registration No. 333-07281.)
   3-E   A copy of the Company's Articles of Amendment of Restated Certificate
         and Articles of Incorporation, filed with the Virginia State
         Corporation Commission, effective as of June 7, 1996. (Filed with
         Registration No. 333-07281.)
   3-F   A copy of the Company's Certificate and Articles of Amendment of
         Restated Certificate and Articles of Incorporation, filed with the
         Delaware Secretary of State, effective as of March 2, 1998 (filed with
         the Company's Current Report on Form 8-K dated March 4, 1998; File No.
         1-1405).
   3-G   A copy of the Company's Articles of Amendment of Restated Certificate
         and Articles of Incorporation, filed with the Virginia State
         Corporation Commission, effective as of March 2, 1998 (filed with the
         Company's Current Report on Form 8-K dated March 4, 1998; File No. 1-
         1405).
   3-H   Certificate of Merger of DS Sub, Inc., a Delaware Corporation with and
         into the Company, filed with the Delaware Secretary of State,
         effective as of March 1, 1998 (filed with the Company's Current Report
         on Form 8-K dated March 4, 1998; File No. 1-1405).
</TABLE>
 
                                     IV-1
<PAGE>
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBER
 -------
 <C>     <S>
  3-I    Certificate of Merger of DS Sub, Inc., a Delaware Corporation with and
         into the Company, filed with the Virginia State Corporation
         Commission, effective as of March 1, 1998 (filed with the Company's
         Current Report on Form 8-K dated March 4, 1998; File No. 1-1405).
  3-J    Copy of the Company's By-Laws as amended March 2, 1998 ( filed with
         the Company's Current Report on Form 8-K dated March 4, 1998; File No.
         1-1405).
  4-A    Copy of the Mortgage and Deed of Trust of Delaware Power & Light
         Company to the New York Trust Company, Trustee, (the Chase Manhattan
         Bank, successor Trustee) dated as of October 1, 1943 and copies of the
         First through Sixty-Eighth Supplemental Indentures thereto. (Filed
         with Registration Statement No.33-1763.)
  4-B    Copy of the Sixty-Ninth Supplemental Indenture. (Filed with
         Registration Statement No. 33-39756.)
  4-C    Copies of the Seventieth through Seventy-Fourth Supplemental
         Indentures. (Filed with Registration Statement No. 33-24955.)
  4-D    Copies of the Seventy-Fifth through the Seventy-Seventh Supplemental
         Indentures. (Filed with Registration Statement No. 33-39756.)
  4-E    Copies of the Seventy-Eighth and Seventy-Ninth Supplemental
         Indentures. (Filed with Registration Statement No. 33-46892.)
  4-F    Copy of the Eightieth Supplemental Indenture. (Filed with Registration
         Statement No. 33-49750.)
  4-G    Copy of the Eighty-First Supplemental Indenture. (Filed with
         Registration Statement No. 33-57652.)
  4-H    Copy of the Eighty-Second Supplemental Indenture. (Filed with
         Registration Statement No. 33-63582.)
  4-I    Copy of the Eighty-Third Supplemental Indenture. (Filed with
         Registration Statement No. 33-50453.)
  4-J    Copies of the Eighty-Fourth through Eighty-Eighth Supplemental
         Indentures. (Filed with Registration Statement No. 33-53855.)
  4-K    Copies of the Eighty-Ninth and Ninetieth Supplemental Indentures.
         (Filed with Registration Statement No. 333-00505.)
  4-L    A copy of the Indenture between the Company and The Chase Manhattan
         Bank (ultimate successor to Manufacturers Hanover Trust Company), as
         Trustee, dated as of November 1, 1988. (Filed with Registration
         Statement No. 33-46892.)
  4-M    A copy of the Indenture (for Unsecured Subordinated Debt Securities
         relating to Trust Securities) between the Company and Wilmington Trust
         Company, as Trustee, dated as of October 1, 1996. (Filed with
         Registration Statement No. 333-20715.)
  4-N    A copy of the Officer's Certificate dated October 3, 1996,
         establishing the 8.125% Junior Subordinated Debentures, Series I, Due
         2036. (Filed with Registration Statement No. 333-20715.)
  4-O    A copy of the Guarantee Agreement between the Company, as Guarantor,
         and Wilmington Trust Company, as Trustee, dated as of October 1, 1996.
         (Filed with Registration Statement No. 333-20715.)
  4-P    A copy of the Amended and Restated Trust Agreement between the
         Company, as Depositor, and Wilmington Trust Company, Barbara S.
         Graham, Edric R. Mason and Donald P. Connelly, as Trustees, dated as
         of October 1, 1996. (Filed with Registration Statement No. 333-20715.)
  4-Q    A copy of the Agreement as to Expenses and Liabilities dated as of
         October 1, 1996, between the Company and Delmarva Power Financing I.
         (Filed with Registration Statement No. 333-20715.)
  10-A   Copy of the Management Incentive Compensation Plan amended and
         restated as of January 1, 1996. (Filed with Form 10-K for the year
         ended December 31, 1996, File No. 1-1405.)
  10-B   Copy of the Supplemental Executive Retirement Plan, revised as of
         October 29, 1991.
</TABLE>
 
                                      IV-2
<PAGE>
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBER
 -------
 <C>     <S>
  10-C   Copies of amendments to the Supplemental Executive Retirement Plan,
         effective June 15, 1994, and November 1, 1994. (Filed with Form 10-K
         for the year ended December 31, 1994, File No. 1-1405.)
  10-D   Copy of the Long Term Incentive Plan amended and restated as of
         January 1, 1996. (Filed with Form 10-K for the year ended December 31,
         1996, File No. 1-1405.)
  10-E   Copies of amendments to the Long Term Incentive Plan, effective
         January 1, 1997, and January 30, 1997. (Filed with Form 10-K for the
         year ended December 31, 1996, File No. 1-1405.)
  10-F   Copy of the severance agreement with members of management. (Filed
         with Form 10-K for the year ended December 31, 1994, File No. 1-1405.)
  10-G   Copy of the current listing of members of management who have signed
         the severance agreement. (Filed with Form 10-K for the year ended
         December 31, 1996, File No. 1-1405.)
  10-H   Copy of the Management Life Insurance Plan amended and restated as of
         January 1, 1992. (Filed with Form 10-K for the year ended December 31,
         1996, File No. 1-1405.)
  10-I   Copy of the Deferred Compensation Plan, effective as of January 1,
         1996. (Filed with the Form 10-K for the year ended December 31, 1995,
         File No. 1-1405.)
  10-J   Copy of amendment to the Deferred Compensation Plan, effective
         December 12, 1996. (Filed with Form 10-K for the year ended December
         31, 1996, File No. 1-1405.)
  12-A   Computation of ratio of earnings to fixed charges.
  12-B   Computation of ratio of earnings to fixed charges and preferred
         dividends.
  23     Consent of Independent Accountants.
  27     Financial Data Schedule.
</TABLE>
 
(b) Reports on Form 8-K:
 
  On October 27, 1997, the Company filed a Form 8-K which reported an agreement
for the sale of a landfill and waste-hauling company owned by a subsidiary of
the Company.
 
                                      IV-3
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
                        SCHEDULE OF OPERATING STATISTICS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1997
 
  The table below sets forth selected financial and operating statistics for
the Company's electric and gas businesses for the three years ended December
31, 1997.
 
<TABLE>
<CAPTION>
                                               1997         1996        1995
                                            -----------  ----------  ----------
<S>                                         <C>          <C>         <C>
ELECTRIC:
 Electricity generated and purchased
  (MWh):
 Generated................................    9,067,236  10,307,299  10,797,547
 Purchased................................    5,908,796   6,195,720   3,977,867
 Interchange deliveries...................   (1,078,471) (2,855,109) (1,862,467)
                                            -----------  ----------  ----------
  Total system output for load............   13,897,561  13,647,910  12,912,947
  Nonregulated purchases..................    4,201,619         --          --
                                            -----------  ----------  ----------
 Total output.............................   18,099,180  13,647,910  12,912,947
                                            ===========  ==========  ==========
 Electric sales (MWh):
 Residential..............................    4,097,773   4,262,710   3,829,807
 Commercial...............................    4,091,636   4,018,120   3,744,879
 Industrial...............................    3,598,006   3,331,175   3,351,834
 Resale...................................    1,335,226   1,333,268   1,213,459
 Other sales (1)..........................      109,124     (19,557)    170,942
                                            -----------  ----------  ----------
  Total service territory sales...........   13,231,765  12,925,716  12,310,921
 Merchant sales (2).......................    4,201,619         --          --
                                            -----------  ----------  ----------
  Total sales excluding interchange.......   17,433,384  12,925,716  12,310,921
 Losses and miscellaneous system uses.....      665,796     722,194     602,026
                                            -----------  ----------  ----------
 Total disposition of energy..............   18,099,180  13,647,910  12,912,947
                                            ===========  ==========  ==========
 Operating revenue (thousands):
 Residential..............................  $   377,528  $  378,520  $  344,351
 Commercial...............................      299,649     286,438     267,239
 Industrial...............................      173,413     156,329     155,108
 Resale...................................       68,315      65,989      58,680
 Miscellaneous revenues (3)...............       34,451      24,344      32,255
                                            -----------  ----------  ----------
  Total service territory.................      953,356     911,620     857,633
 Interchange deliveries...................       36,430      75,301      47,271
 Merchant sales (2).......................      102,358         --          --
                                            -----------  ----------  ----------
  Total revenues..........................  $ 1,092,144  $  986,921  $  904,904
                                            ===========  ==========  ==========
 Number of customers (end of period):
 Residential..............................      396,798     391,611     386,948
 Commercial...............................       50,216      49,165      48,345
 Industrial...............................          672         683         704
 Resale...................................           12          12          12
 Other....................................          624         645         641
                                            -----------  ----------  ----------
  Total customers (4) ....................      448,322     442,116     436,650
                                            ===========  ==========  ==========
</TABLE>
 
                                                  (Table continued on next page)
 
 
                                      IV-4
<PAGE>
 
                         DELMARVA POWER & LIGHT COMPANY
 
                 SCHEDULE OF OPERATING STATISTICS--(CONTINUED)
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1997
 
<TABLE>
<CAPTION>
                                                      1997      1996      1995
                                                    --------- --------- --------
<S>                                                 <C>       <C>       <C>
GAS:
 Gas Sales and Gas Transported (Mcf):
 Residential......................................      7,844     8,692    7,328
 Commercial.......................................      5,313     5,724    4,809
 Industrial.......................................      2,772     2,696    3,935
 Interruptible, transportation and other..........      6,926     5,312    5,299
                                                    --------- --------- --------
  Total service territory.........................     22,855    22,424   21,371
 Merchant sales...................................     27,216     1,733      --
                                                    --------- --------- --------
  Total...........................................     50,071    24,157   21,371
                                                    ========= ========= ========
 Operating revenue (thousands):
 Residential......................................  $  63,937 $  60,017 $ 47,135
 Commercial.......................................     34,895    32,191   24,458
 Industrial.......................................     12,582    12,349   14,588
 Interruptible, transportation and other..........      5,776     5,085    9,260
                                                    --------- --------- --------
  Total service territory.........................    117,190   109,642   95,441
 Merchant revenues................................     86,867     4,642      --
                                                    --------- --------- --------
  Total...........................................  $ 204,057 $ 114,284 $ 95,441
                                                    ========= ========= ========
 Number of customers (end of period):
 Residential......................................     95,295    93,149   90,890
 Commercial.......................................      7,793     7,615    7,369
 Industrial.......................................        128       139      146
 Interruptible and other..........................        --          1       12
                                                    --------- --------- --------
  Total customers (4) ............................    103,216   100,904   98,417
                                                    ========= ========= ========
</TABLE>
--------
(1) Includes unbilled sales.
(2) Offsystem, competitive sales and other services.
(3) Includes unbilled revenues and other miscellaneous revenues.
(4) Service territory only.
 
                                      IV-5
<PAGE>
 
                                  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,
1998.
 
                                              Delmarva Power & Light Company
                                                       (Registrant)
 
                                                   /s/ Barbara S. Graham
                                          By __________________________________
                                              (Barbara S. Graham, Senior Vice
                                               President and Chief Financial
                                                         Officer)
 
  PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES, ON MARCH 27, 1998.
 
              SIGNATURE                        TITLE
 
       /s/ Howard E. Cosgrove          Chairman of the Board,
 .....................................   Chief Executive
        (Howard E. Cosgrove)            Officer and Director
 
        /s/ Barbara S. Graham          Senior Vice President,
 .....................................   Chief Financial
         (Barbara S. Graham)            Officer and Director
 
         /s/ James P. Lavin            Controller and Chief
 .....................................   Accounting Officer
          (James P. Lavin)
 
   /s/  Meredith I. Harlacher, Jr.     Director
 .....................................
    (Meredith I. Harlacher, Jr.)
 
         /s/  Thomas S. Shaw           Director
 .....................................
          (Thomas S. Shaw)
 
         /s/  Barry R. Elson           Director
 .....................................
          (Barry R. Elson)
 
      /s/ Audrey K. Doberstein         Director
 .....................................
       (Audrey K. Doberstein)
 
       /s/  Jerrold L. Jacobs          Director
 .....................................
         (Jerrold L. Jacobs)
 
                                     IV-6