<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, 1996
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: 302-429-3527
----------------
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 PHILADELPHIA
ISSUED PRIOR TO 1968) STOCK EXCHANGE
PREFERRED STOCK, CUMULATIVE, PAR PHILADELPHIA STOCK EXCHANGE
VALUE $100.00 (SERIES ISSUED
PRIOR TO 1978)
COMMON STOCK, PAR VALUE $2.25 NEW YORK STOCK EXCHANGE AND PHILADELPHIA
STOCK EXCHANGE
8.125% CUMULATIVE TRUST PREFERRED NEW YORK STOCK EXCHANGE
CAPITAL SECURITIES OF DELMARVA
POWER 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 FEBRUARY 28, 1997 WAS $1,177,420,300.
AS OF FEBRUARY 28, 1997, THERE WERE ISSUED AND OUTSTANDING 60,947,468 SHARES
OF THE REGISTRANT'S COMMON STOCK, PAR VALUE $2.25.
----------------
DOCUMENTS INCORPORATED BY REFERENCE
<TABLE>
<CAPTION>
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
----------------- ----------------------------------
<C> <S>
I (ITEM 1-SEGMENT PORTIONS OF THE 1996 ANNUAL REPORT TO STOCKHOLDERS OF DELMARVA
INFORMATION) AND POWER & LIGHT COMPANY
II (ITEMS 6, 7 AND
8)
III PORTIONS OF THE DEFINITIVE PROXY STATEMENT FOR THE ANNUAL
MEETING OF STOCKHOLDERS OF DELMARVA POWER & LIGHT COMPANY, TO BE
HELD MAY 29, 1997, WHICH DEFINITIVE PROXY STATEMENT IS EXPECTED
TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OR
ABOUT APRIL 7, 1997
IV PORTIONS OF THE 1996 ANNUAL REPORT TO STOCKHOLDERS OF DELMARVA
POWER & LIGHT COMPANY
</TABLE>
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<PAGE>
TABLE OF CONTENTS
<TABLE>
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PAGE
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<C> <S> <C>
Glossary................................................................. iii
PART I
Item 1. Business
The Company..................................................... I-1
Electric Resale Business........................................ I-2
Electric Retail Business........................................ I-2
Gas Business.................................................... I-3
Nonutility Business............................................. I-3
Segment Information............................................. I-4
Electric Operations............................................. I-4
Installed Capacity.............................................. I-4
Power Pool...................................................... I-4
FERC PJM Interconnection Filing................................. I-5
Reserve Margin.................................................. I-5
Energy Supply Plan.............................................. I-5
Power Plants.................................................... I-6
Nuclear......................................................... I-6
Peach Bottom Units.............................................. I-7
Salem Units..................................................... I-7
Life Extensions................................................. I-9
Purchased Power................................................. I-9
Cost of Output for Load......................................... I-10
Fuel Supply for Electric Generation............................. I-10
Coal............................................................ I-10
Oil............................................................. I-10
Gas............................................................. I-10
Nuclear......................................................... I-11
Gas Operations.................................................. I-12
Regulatory and Rate Matters..................................... I-12
Base Rate Proceedings........................................... I-13
Fuel Adjustment Clauses......................................... I-13
Other Regulatory Matters........................................ I-14
Electric Collaborative Proposal................................. I-14
Delaware Depreciation Filing.................................... I-14
Special Contract Rate Tariffs................................... I-14
Comparable Use Transmission Tariff.............................. I-14
The Company/Atlantic Merger Filings............................. I-15
Natural Gas Restructuring Filing................................ I-15
Additional Regulatory Matters................................... I-15
Capital Spending and Financing Program.......................... I-16
Environmental Matters........................................... I-17
Construction Expenditures....................................... I-18
Clean Air Act................................................... I-18
Salem Operating Permit.......................................... I-18
Water Quality Regulations....................................... I-19
Hazardous Substances............................................ I-19
Subsidiaries.................................................... I-19
</TABLE>
i
<PAGE>
<TABLE>
<CAPTION>
PAGE
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<C> <S> <C>
Retail Franchises............................................ I-19
Forward-Looking Statements................................... I-20
Number of Employees.......................................... I-20
Executive Officers of the Registrant......................... I-21
Item 2. Properties................................................... I-22
Item 3. Legal Proceedings............................................ I-23
Item 4. Submission of Matters to a Vote of Security Holders.......... I-23
PART II
Market for Registrant's Common Equity and Related Stockholder
Item 5. Matters................................................... II-1
Item 6. Selected Financial Data...................................... II-1
Management's Discussion and Analysis of Financial Condition
Item 7. and Results of Operations................................. II-1
Item 8. Financial Statements and Supplementary Data.................. II-1
Changes in and Disagreements with Accountants on Accounting
Item 9. and Financial Disclosure.................................. II-1
PART III
Item 10. Directors and Executive Officers of the Registrant........... III-1
Item 11. Executive Compensation....................................... III-1
Security Ownership of Certain Beneficial Owners and
Item 12. Management................................................ III-1
Item 13. Certain Relationships and Related Transactions............... III-1
PART IV
Exhibits, Financial Statement Schedules, and Reports on Form
Item 14. 8-K....................................................... IV-1
Signatures............................................................. IV-4
</TABLE>
ii
<PAGE>
GLOSSARY
The following glossary lists the abbreviations used in this report.
<TABLE>
<CAPTION>
TERM DEFINITION
---- ----------
<S> <C>
AFUDC................... Allowance For Funds Used During Construction
Atlantic................ Atlantic Energy, Inc.
BWR..................... Boiling Water Reactor
CAM..................... Cost Accounting Manual
Clean Air Act........... Clean Air Act Amendments of 1990
Company................. Delmarva Power & Light Company
COPCO................... Conowingo Power Company
CT...................... Combustion Turbine
D&D Fund................ Decontamination & Decommissioning Fund
DNREC................... Delaware Department of Natural Resources and Environmental Control
DOE..................... United States Department of Energy
DPSC.................... Delaware Public Service Commission
EDR..................... Economic Development Rate
Energy Act.............. Energy Policy Act of 1992
Enterprise.............. Public Service Enterprise Group, Inc.
EPA..................... United States Environmental Protection Agency
FERC.................... Federal Energy Regulatory Commission
FGD..................... Flue Gas Desulfurization
GE...................... General Electric Company
HVAC.................... Heating, ventilation, and air conditioning
kV...................... Kilovolts
kWh..................... Kilowatt-hour
Litigation Reform Act... The Private Securities Litigation Reform Act of 1995
LLRW.................... Low Level Radioactive Waste
Mcf..................... Thousand Cubic Feet
MD&A.................... Managements Discussion and Analysis of Financial Condition
and Results of Operations
Merger.................. The proposed merger of the Company and Atlantic
Merger Agreement........ The Agreement and Plan of Merger, dated as of August 9, 1996,
as amended and restated as of December 26, 1996
Mortgage................ Mortgage and Deed of Trust
MOU..................... Memorandum of Understanding
MPSC.................... Maryland Public Service Commission
MW...................... Megawatt
MWh..................... Megawatt-hour
NCR..................... Negotiated Contract Rate
NJDEP................... New Jersey Department of Environmental Protection
NOTC.................... Northeast Ozone Transport Commission
NOTR.................... Northeast Ozone Transport Region
NOx..................... Oxides of Nitrogen
NRC..................... Nuclear Regulatory Commission
NWPA.................... Nuclear Waste Policy Act of 1982
PADEP................... Pennsylvania Department of Environmental Protection
Peach Bottom............ Peach Bottom Atomic Power Station
PECO.................... PECO Energy Company
Pine Grove.............. Pine Grove Landfill, Inc.
PJM Interconnection..... Pennsylvania-New Jersey-Maryland Interconnection Association
</TABLE>
iii
<PAGE>
<TABLE>
<CAPTION>
TERM DEFINITION
---- ----------
<S> <C>
Plan.................... The Conectiv, Inc. Incentive Compensation Plan
PPPP.................... Power Plant Performance Program
PSE&G................... Public Service Electric and Gas Company
RACT.................... Reasonably Available Control Technology
Salem................... Salem Nuclear Generating Station
SALP.................... Systematic Assessment of Licensee Performance
SEC..................... Securities and Exchange Commission
SO/2/................... Sulfur Dioxide
Star.................... Star Enterprise
Supporting Companies.... Seven of the eight member companies of the PJM Interconnection,
including the Company
VSCC.................... Virginia State Corporation Commission
Watch List.............. Nuclear Regulatory Commission watch list
Westinghouse............ Westinghouse Electric Corporation
1935 Act................ Public Utility Holding Company Act of 1935
</TABLE>
iv
<PAGE>
PART I
ITEM 1. BUSINESS
THE COMPANY
Delmarva Power & Light Company (the Company) was incorporated in Delaware in
1909 and in Virginia in 1979. On August 12, 1996, the Company announced plans
to merge with Atlantic Energy, Inc. (Atlantic), an investor-owned holding
company, located in southern New Jersey, which owns Atlantic City Electric
Company, an electric utility, and nonutility businesses. For a discussion of
the Company's pending merger with Atlantic and the purchase of the Conowingo
Power Company (COPCO) in 1995, refer to Note 4 to the Consolidated Financial
Statements of the Company's 1996 Annual Report to Stockholders filed as
Exhibit 13.
Historically, the Company has been predominantly a public utility that
provides electric and gas service. In 1996, the Company provided electric
service to retail (residential, commercial, and industrial) and wholesale
(resale) customers in Delaware, ten primarily Eastern Shore counties in
Maryland, and the Eastern Shore area of Virginia in an area consisting of
about 6,000 square miles with a population of approximately 1.2 million. The
Company also provided gas service to retail and transportation customers in an
area consisting of about 275 square miles with a population of approximately
475,000 in northern Delaware, including the City of Wilmington. Approximately
90% of the Company's operating revenues were derived from the sale of
electricity in 1996.
In 1996, the Company reorganized into three separate business units; Energy
Supply, Regulated Delivery, and Energy Services. On an integrated basis, the
business units' plans are intended to grow the Company's businesses by
building long-term customer relationships, offering new products and services
that complement the Company's core energy business and are targeted to
individual customer needs, and serving more customers in a larger geographic
area. The business units also reflect the anticipated future structure of the
utility industry. Eventually, all customers are expected to be able to choose
their energy suppliers, while the delivery (transmission and distribution) of
energy is expected to remain as a regulated franchise. For additional
information, see "Electric Retail Business."
Energy Supply produces, buys, and sells energy in a multi-regional
marketplace that is expected to be competitive and have deregulated, market-
based prices. Energy Supply's mission is to provide new and existing customers
with a complete and competitive portfolio of merchant energy products and
services, while maximizing the value of the Company's generating assets.
Regulated Delivery delivers energy over the Company's transmission and
distribution systems at prices which are expected to continue to be regulated
by the public utility commissions. Regulated Delivery's mission is to provide
high-value utility delivery services to customers in the region. By continuing
to maintain a high level of customer satisfaction through high-quality
customer service, Regulated Delivery will help the Company retain existing
customers who may become eligible to choose alternative energy suppliers in
the future.
Energy Services packages and sells energy and related premium products and
services to customers within the competitive regional marketplace. Energy
Services is implementing the Company's strategy of expanding the number of
connections it has with customers through brand recognition and tailored
services that fit together with the Company's core energy business. Energy
Services is starting new businesses which include heating, ventilation, and
air conditioning (HVAC), telecommunications, and other products and services
that complement the Company's core energy business. The Company believes that
new services such as HVAC will help build customer relationships and brand
recognition, leading customers to choose the Company as their energy supplier
when such choice is available.
I-1
<PAGE>
Last year the Company announced plans to merge with Atlantic. The planned
merger will double the Company's size and add about 478,000 customers in
southern New Jersey. The Company also announced a new name for the merged
company, Conectiv. This new name reflects the Company's strategy and gives the
Company a chance to build a strong reputation in areas outside of its existing
service area where people may not recognize the Delmarva Power name.
Electric Resale Business
The Energy Policy Act of 1992 (the Energy Act) enabled the Federal Energy
Regulatory Commission (FERC) to order the provision of transmission service
(wheeling of electricity) for resale electricity producers. The Energy Act
also provided for the creation of a new category of electric power producers
called exempt wholesale generators.
In 1996, the FERC issued Order No. 888 and Order No. 889. FERC Order No. 888
requires electric utilities to provide open access to their transmission
systems under non-discriminatory tariffs available to all wholesale sellers
and buyers of electricity. Utilities are required to offer transmission
services comparable to the services they provide to themselves and to take
transmission services under the same tariffs applied to their transmission
customers. Order No. 888 also provides that stranded costs resulting from
opening retail markets are subject to the jurisdiction of state regulatory
commissions. For a discussion of the Company's actions taken in response to
Order No. 888, refer to "FERC PJM Interconnection Filing" on page I-5 and
"Comparable Use Transmission Tariff" on page I-14.
FERC Order No. 889 is designed to ensure that transmission owners and their
affiliates do not have an unfair competitive advantage in using transmission
to sell power. The rule requires utilities to obtain information about their
transmission system for their own wholesale power transactions, such as
available capacity, in the same way as their competitors do--via an electronic
system (Open Access Same-time Information System ) on the Internet. The rule
also requires utilities to functionally separate their wholesale power
marketing and transmission functions.
For a discussion of the Company's resale business refer to "Electric Resale
Business" in the Management's Discussion and Analysis of Financial Condition
and Results of Operations (MD&A) of the Company's 1996 Annual Report to
Stockholders filed as Exhibit 13.
Electric Retail Business
Competition in the electric retail markets is developing rapidly. Electric
retail wheeling, which results in retail customers purchasing electricity from
the suppliers of their choice at market-based prices, has been introduced in a
number of states and is being considered by many other states. In addition,
federal legislation has been introduced and other bills are being drafted
which could lead to retail wheeling for the entire nation. Current
developments in Pennsylvania and New Jersey, which border on the Company's
service territory, indicate future opportunities for the Company to serve more
electric customers. In Pennsylvania, electric retail wheeling is scheduled to
be phased-in over a three year period beginning in 1999. The New Jersey Board
of Public Utilities has recommended that retail competition be fully phased-in
by April 2001. For information concerning the processes established in the
Company's retail jurisdictions to address changes in the regulation of the
electric utility industry, including the advent of retail wheeling, refer to
"Competition and the Changing Regulatory Environment" in the MD&A of the
Company's 1996 Annual Report to Stockholders filed as Exhibit 13.
The Company is well positioned for competition in the retail markets, partly
due to its relatively low prices within the region. The Company's prices for
large retail customers are among the lowest in the area and are competitive
with alternative sources of energy such as self-generation. The Company's
average price for commercial customers in 1995 was 7.12 cents per kilowatt-
hour (kWh) compared to a regional average of 8.80 cents per kWh. The Company's
average price for industrial customers in 1995 was 4.63 cents per kWh compared
I-2
<PAGE>
to a regional average of 6.67 cents per kWh. These regional averages are based
on 1995 data for 27 utilities within a 300-mile radius of the Company.
Gas Business
Deregulation and restructuring of the production and interstate pipeline
segments of the gas industry began in 1985 with the Wellhead Decontrol Act and
concluded with FERC Order No. 636 in 1993. As a result of FERC's deregulation
of the gas industry, the Company primarily purchases gas directly from
producers and transports the gas through various pipelines.
End-use customers, including the Company's retail gas customers, may also
purchase gas directly from producers and marketers, arrange for their own
transportation on pipelines, and transport gas to their facilities using the
Company's gas transmission and distribution facilities. End-use transportation
customers pay the Company a fee according to retail transportation tariffs.
The Company has entered into a joint marketing program with Columbia Energy
Services Corporation, an affiliate of The Columbia Gas System, Inc., to meet
this competition by directly marketing rebundled gas supply principally to the
Company's end-use customers.
In February 1996, the Delaware Public Service Commission (DPSC) approved the
Company's application to provide additional local deregulation for end-use
customers. Deregulation of the gas industry has allowed the Company to achieve
additional revenues by making off-system sales to end-use customers outside
the traditional service territory.
Finally, the Company is participating as a member of the East Coast Natural
Gas Cooperative with seven other regional distribution companies. These
companies are working jointly to ensure reliability, purchase supplies at the
lowest reasonable cost, provide for joint planning, increase operational
efficiencies, and consider market opportunities.
Nonutility Business
The Company and its wholly owned subsidiaries are engaged in nonutility
businesses. In 1996 and early 1997, a newly established subsidiary of the
Company acquired a number of HVAC service companies located in the Company's
traditional service territory and in Pennsylvania. The Company expects to
expand the services offered by this subsidiary to include plumbing,
electrical, refrigeration, and appliance services. A subsidiary was also
formed in 1996 to conduct telecommunications businesses. The Company currently
provides fiber optic construction and telecommunications engineering services
to customers and plans to provide retail telephone service and carrier service
for long-distance phone companies. The Company's existing fiber optic system
is expected to facilitate entry into the telecommunications business. On
February 18, 1997, the DPSC approved the transfer of the Company's fiber optic
assets to its telecommunications subsidiary.
The Company also has a wholly owned subsidiary engaged in landfill and
waste-hauling operations, the ownership, operation and maintenance of energy-
related projects, real estate sales and development, and investments in
leveraged equipment leases.
The Company also offers services such as utility management, distribution
engineering and construction, substation design, indoor and outdoor lighting
design, installation and maintenance, and other energy related services.
For a further discussion of the Company's nonutility subsidiaries refer to
"Nonutility Subsidiaries" in the MD&A and Note 18 to the Consolidated
Financial Statements of the 1996 Annual Report to Stockholders filed as
Exhibit 13.
I-3
<PAGE>
SEGMENT INFORMATION
See Note 19 to the Consolidated Financial Statements of the Company's 1996
Annual Report to Stockholders filed as Exhibit 13.
ELECTRIC OPERATIONS
Installed Capacity
The net installed summer electric generating capacity available to the
Company to serve its peak load as of December 31, 1996, is presented below.
The Company's purchase of 205 megawatts (MW) of capacity from PECO Energy
Company (PECO), related to the COPCO acquisition, was included in the
Company's installed capacity beginning February 1, 1996. The Company and Star
Enterprise (Star) have negotiated an amendment to a capacity purchase
agreement that has suspended, from October 1, 1996 until June 1, 2000, Star's
obligation to supply the Company with 48 MW of capacity and the Company's
obligation to pay for such capacity. For a discussion of the Company's energy
supply plan, refer to "Energy Supply Plan" on page I-5.
<TABLE>
<CAPTION>
% OF
INSTALLED SUMMER CAPACITY MW TOTAL
------------------------- ----- -----
<S> <C> <C>
Coal-Fired..................................................... 1,120 35
Oil-Fired...................................................... 596 19
Combustion Turbines/Combined Cycle............................. 511 16
Nuclear........................................................ 328 10
Peaking Units.................................................. 183 6
Purchased Capacity............................................. 205 6
Customer-owned Capacity........................................ 57 2
----- ---
Subtotal..................................................... 3,000 94
Purchased PJM Interconnection Capacity Credits................. 185 6
----- ---
Total........................................................ 3,185 100
===== ===
</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-22 for a listing of net
installed generating capacity by station.
Power Pool
As a member of the Pennsylvania-New Jersey-Maryland Interconnection
Association (PJM Inter- connection), the Company's generation and transmission
facilities are operated on an integrated basis with those of seven other
utilities in Pennsylvania, New Jersey, Maryland, and the District of Columbia.
This power pool was formed for the purpose of improving the reliability and
operating economies of the systems in the group and to provide capital
economies by permitting the sharing of reserve requirements on a group basis.
The Company estimates that its fuel savings associated with energy
transactions within the pool amounted to $9.8 million during 1996.
The PJM Interconnection's installed capacity as of December 31, 1996 was
57,308 MW. The PJM Interconnection peak demand during 1996 was 44,302 MW on
August 23rd, which resulted in a summer reserve margin of 28.6% (based on
installed capacity of 56,952 MW on that date).
I-4
<PAGE>
FERC PJM Interconnection Filing
On July 24, 1996, seven of the eight member companies of the PJM
Interconnection, including the Company (Supporting Companies), filed a
restructuring proposal for the PJM Interconnection Pool. In a November 13,
1996, Order the FERC directed the eight PJM Interconnection companies to amend
their proposals. These amendments were to include a pooling agreement that has
open, non-discriminatory membership provisions and the filing of a joint pool-
wide pro forma open access transmission tariff in compliance with FERC Order
No. 888.
On December 31, 1996, all eight PJM Interconnection companies made a Joint
FERC Order No. 888 compliance filing as directed. This filing included, among
other things, a revised Interconnection Agreement for the PJM Interconnection
Pool with open membership provisions and a pool-wide open access transmission
tariff. There were significant differences on certain issues between the seven
Supporting Companies and PECO. The major issues were the appropriate pricing
methodology for transmission congestion and whether the open-access
transmission rate should be developed on a pool-wide postage stamp or zonal
basis. This filing is intended as an interim solution to satisfy the
requirements of FERC Order No. 888. The requested effective date of this
filing is March 1, 1997. Consistent with the FERC's November 13, 1996, Order,
the PJM Interconnection companies and other stakeholders are continuing their
efforts toward a more comprehensive restructuring, including the establishment
of an Independent System Operator. The current goal is to file a full package,
including the pro forma tariff and any other agreements, no later than May 31,
1997.
Reserve Margin
The Company's peak load in 1996 was 2,569 MW on July 9th, compared to the
Company's 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 2,578 MW in 1996.
Based upon this estimated peak and the Company's installed generating capacity
of 3,048 MW at the time, the Company's reserve margin would have been 18.2%.
The Company's reserve obligation varies from year to year, but typically is
around 18%.
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 with a
minimal adverse effect on the environment. This plan, which is updated
annually, is based on forecasts of demand for electricity in the service
territory and reserve requirements of 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 plan considers customer-oriented load management and
conservation programs along with long- and short-term power contracts, and new
or renovated power plants. The plan currently matches customers' energy
requirements and does not require large investments for new resources. For
further discussion of the energy supply plan, refer to "Energy Supply" in the
MD&A of the Company's 1996 Annual Report to Stockholders filed as Exhibit 13.
As of the end of 1996, the Company had enrolled in its load management
programs about 97,900 residential customers and about 1,700 commercial and
industrial customers, who in aggregate provide the Company with the ability to
reduce its peak by approximately 265 MW. The Company filed to close its
existing load management programs to new participants in Delaware and Maryland
on October 3, 1995, and in Virginia on March 12, 1996, because it was
concerned 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 Virginia State Corporation Commission (VSCC) approved on an
interim basis on April 9, 1996, and subsequently on a permanent basis, the
closure of the Company's existing load management programs. The DPSC approved
on August 13, 1996, a stipulation modifying the
I-5
<PAGE>
Company's existing load management programs. The Maryland Public Service
Commission (MPSC) approved, effective December 17, 1996, a stipulation
modifying immediately the Company's existing residential conservation
programs, subject to further changes following a report due not later than
March 31, 1997, addressing technical issues surrounding the Company's demand-
side portfolio in Maryland.
Purchased power contracts provide a portion of the Company's 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. Star's obligation to supply
and the Company's responsibility to pay for that capacity has been suspended
from October 1, 1996 until June 1, 2000, due to the availability of lower cost
alternatives to meeting the Company's energy supply requirements. In
conjunction with its acquisition of COPCO, the Company is purchasing base-load
capacity from PECO that will increase from 205 MW in 1996 to 279 MW when the
contract expires in 2006. In addition, short-term purchases during the period
1997-2001 are being considered to meet continuing PJM Interconnection capacity
obligations. On August 13, 1996, the Company announced that it was soliciting
proposals for short-term capacity and energy, call options on capacity and
energy, capacity only, or load reduction proposals over a three year period
beginning June 1, 1997. The Company is currently reviewing the proposals
received. As further discussed under "Life Extensions" on page I-9, the
Company also has a power plant life-extension program to extend the operating
lives of certain generating units.
The table below summarizes the latest peak load and capacity forecast for
the current and next five PJM Interconnection planning periods, which begin on
June 1 of each year. The Company periodically reviews and updates its forecast
to reflect changes in peak load and capacity estimates.
<TABLE>
<CAPTION>
PEAK LOAD (MW) CAPACITY (MW)
PJM ----------------------- --------------------------
PLANNING GROSS NET TOTAL
YEAR SUMMER TOTAL SUMMER TOTAL OWNED TOTAL RESERVE
BEGINNING COMPANY DEMAND- COMPANY PURCHASED POWER INSTALLED MARGIN
JUNE 1 PEAK SIDE PEAK POWER PLANTS CAPACITY (%)
--------- ------- ------- ------- --------- ------ --------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
1996 2843 265 2578 253 2795 3048 18.2
1997 2906 270 2636 312 2795 3107 17.9
1998 2967 270 2697 387 2795 3182 18.0
1999 2944 270 2674 368 2795 3163 18.3
2000 3007 270 2737 447 2795 3242 18.5
2001 3061 270 2791 503 2795 3298 18.2
</TABLE>
POWER PLANTS
Nuclear
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, Atlantic City Electric Company, 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 Company's funding of its share of the estimated
future cost of decommissioning the Peach Bottom and Salem nuclear reactors,
refer to Note 6 to the Consolidated Financial Statements of the Company's 1996
Annual Report to Stockholders filed as Exhibit 13.
I-6
<PAGE>
As by-products of their operations, nuclear generating units, including the
Peach Bottom and Salem units, produce low level radioactive waste (LLRW). Such
waste includes paper, plastics, protective clothing, water purification
materials and other materials which must be disposed of properly. Prior to
July 1994, PECO and PSE&G disposed of such materials at a federally licensed
permanent disposal facility in Barnwell, South Carolina. At that time, in
accordance with the Low Level Radioactive Waste Policy Act, as amended, the
facility exercised its authority to stop accepting waste from New Jersey and
Pennsylvania, because those states are not members of the regional compact
under which the facility is operated. Peach Bottom and Salem stored the waste
temporarily on-site until the South Carolina site allowed the units to resume
shipments in July 1995. The on-site facilities at PECO and PSE&G have capacity
for at least five years of temporary storage. PECO has informed the Company
that Pennsylvania is pursuing its own LLRW site development via state-selected
candidate sites, along with 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.
Peach Bottom Units
PECO has informed the Company that, on December 5, 1995, the NRC issued its
periodic Systematic Assessment of Licensee Performance (SALP) Report on the
performance of activities at Peach Bottom for the period May 1, 1994 to
October 15, 1995. 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. Station management
oversight, effective use of performance enhancement at all levels of the
organization and other measures in identifying and evaluating issues
contributed to the strong performance. The NRC noted performance improvements
in all assessment areas, particularly in Maintenance and Plant Support.
Although the NRC noted that excellent performance often was displayed in the
Engineering area, errors in modification work, in addition to some other
lapses, indicated inconsistent engineering performance. PECO has informed the
Company that it is taking actions to further improve Peach Bottom performance.
PECO has informed the Company that, in October 1990, General Electric
Company (GE) reported that crack indications were discovered near the seam
welds of the core shroud assembly in a GE Boiling Water Reactor (BWR). As a
result, GE issued a letter requesting that the owners of GE BWR plants take
interim corrective actions, including a review of fabrication records and
visual examinations of accessible areas of the core shroud seam welds.
Inspections performed on Units 2 and 3 during planned refueling outages have
revealed minimal cracking in the seam welds of the cord shroud assemblies,
which PECO concluded and the NRC agreed, was within industry established
guidelines. PECO is participating in a GE BWR Owners Group to develop long-
term corrective actions.
Salem Units
Salem Units 1 and 2 were removed from operation by PSE&G on May 16, 1995 and
June 7, 1995, respectively, due to operational problems and maintenance
concerns. Their return dates are subject to completion of the requirements of
their respective restart plans to the satisfaction of PSE&G and the NRC, which
encompasses a substantial review and improvement of personnel, process, and
equipment issues.
With respect to Unit 1, PSE&G informed the Company in early 1996 that
inspection of the steam generators using a new testing technology indicated
degradation in a significant number of tubes. After evaluating several
options, in May 1996, replacement steam generators from the unfinished
Seabrook Unit 2 nuclear power plant in New Hampshire were purchased from
Northeast Utilities Service Company for installation in Salem Unit 1. The
replacement steam generators arrived on site in October 1996 and are being
installed. PSE&G expects Unit 1 to return to service in the fall of 1997,
after replacement of the unit's steam generators. The Company's share of the
costs to be capitalized for the steam generators, including installation, will
range from approximately $11 million to $13 million.
I-7
<PAGE>
With respect to Unit 2, PSE&G also informed the Company in early 1996 that
inspections of the steam generators using the new testing technology confirmed
that the condition of the generators was within current repair limits. In
January 1997, PSE&G advised the Company that Unit 2 is expected to return to
service in the second quarter of 1997.
As mentioned, restart of both Salem units is subject to NRC approval, which
cannot be assured. On January, 14, 1997, Senator Joseph Biden of Delaware
wrote to the NRC to request that the full Commission vote on the decision to
restart Salem, rather than permit the NRC staff to authorize the restart under
applicable NRC rules. By letter to Senator Biden dated February 20, 1997, the
NRC advised that it would not require a full commission vote on Salem restart.
For additional information concerning Salem, including the financial impact
of the outages on the Company, refer to Note 17, "Salem Outages" to the
Consolidated Financial Statements of the Company's 1996 Annual Report to
Stockholders filed as Exhibit 13.
PSE&G has informed the Company that in August 1996, the NRC conducted an
inspection of the Physical Security Program for Salem and identified six
apparent violations that are being considered for escalated enforcement. These
apparent violations include the failure to: (1) control photo badge key cards;
(2) properly search an individual prior to entrance to the protected area; (3)
notify the nuclear shift supervisor of a potential threat event; (4)
deactivate photo badges for individuals who no longer require site access; (5)
complete training for security supervisors prior to assignment of duties; and
(6) test an intrusion detection system in accordance with procedures. On
September 3, 1996, PSE&G met with the NRC to discuss these issues and provide
specific corrective actions. On November 14, 1996, a predecisional enforcement
conference was held to address these apparent violations. At the conference,
PSE&G presented their corrective actions, including a change in security
management. On December 11, 1996, the NRC issued its written report to PSE&G.
Based on the NRC's review of the inspection findings and information provided
during the enforcement conference, PSE&G was cited for the aforementioned six
violations and penalties totaling $100,000 were imposed. The Company's share
of the penalties is 7.41%. The Company cannot predict what other actions the
NRC may take on this matter.
PSE&G has informed the Company that on December 11, 1996, it received a
severity level II violation and an $80,000 civil penalty from the NRC for
apparent violations which occurred in 1993 and early 1994, involving alleged
discrimination against two employees for their engagement in protected
activities in accordance with federal regulations.
On January 29, 1997, the NRC held a meeting and identified plants placed on
the "NRC Watch List" (Watch List), including Salem Units 1 and 2 which were
identified as Category 2 plants. A Category 2 facility is a plant that is
authorized to operate but has had or is having weaknesses that warrant
increased NRC attention. In a letter to PSE&G, dated January 27, 1997, the NRC
stated that the classification of the Salem plants as Category 2 facilities
was being made to recognize that Salem should have been placed on the Watch
List previously and that it would not be removed at this point. The NRC letter
also stated that this classification is not intended to suggest the licensee
actions underway at Salem to achieve needed improvements are incorrectly
targeted and further stated that the NRC is satisfied with the overall
approach and will be monitoring the progress to achieve the planned
improvements.
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. The Salem co-owners contend that the recently
discovered degradation of the steam generators will prevent the steam
generators from operating for a design life of 40 years. The lawsuit asserts
that the Salem steam generators require replacement and these costs should be
I-8
<PAGE>
borne by Westinghouse and not the customers and shareholders of the Salem co-
owners. Westinghouse filed an answer and a $2.5 million counterclaim for
unpaid work on April 30, 1996. The parties are currently engaged in document
production. The Company cannot predict the outcome of this lawsuit.
On March 5, 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. On the same day,
Atlantic filed a complaint in Superior Court of New Jersey against Enterprise
and PSE&G. The lawsuits allege that the defendants failed to heed numerous
citations, warnings, notices of violations and fines by the NRC as well as
repeated warnings from the Institute of Nuclear Power Operations about
performance, safety, and management problems at Salem and to take appropriate
corrective action. The suits contend that as a result of these actions and
omissions, the Salem units were forced to shut down in 1995. The suits ask for
compensatory damages for breach of contract, negligence, and punitive damages,
in amounts to be specified. The Company cannot predict the outcome of its
lawsuit. At present the parties are continuing fact discovery, including
depositions, interrogatories and document production. Discovery of expert
witnesses is expected to occur in March and April 1997. A pre-trial conference
is scheduled for May 20, 1997. In January 1997, Atlantic announced that it
entered into a Stipulation Agreement with PSE&G for the purpose of limiting
Atlantic's exposure to operation and maintenance expenses for Salem to be
incurred during calendar year 1997. In exchange for this Stipulation
Agreement, Atlantic agreed to dismiss its litigation against PSE&G.
See page I-18 for a discussion on the status of the operating permit at
Salem.
Life Extensions
The Company is conducting a life extension program on its older, wholly-
owned generating units to extend the operating life of each unit by a minimum
of 20 years beyond the normal unit 30-year design life. Continued operation of
these units will defer the construction of new capacity and will help to meet
PJM Interconnection generating reserve margin obligations. Surveys of Indian
River Units 1, 2, and 3 and Edge Moor Units 3, 4 and 5 have been completed.
Projects identified during the surveys have been completed to date or will be
implemented during scheduled maintenance outages. Vienna Unit 8 will undergo
surveys beginning in 1999. Construction expenditures on these projects for the
five-year period 1997-2001 are expected to total approximately $19 million,
excluding allowance for funds used during construction (AFUDC).
PURCHASED POWER
The Company makes short-term energy purchases from several sources in an
effort to replace higher-cost generation. During 1996, purchases were made
from approximately 30 utilities and power marketers. The Company's estimated
fuel savings from these transactions amounted to $10.9 million during 1996.
The Company has a contract to purchase 48 MW of long-term capacity from
Star, which has been suspended from October 1, 1996 until June 1, 2000. The
Company has also entered into a power purchase agreement with PECO associated
with the Company's acquisition of COPCO as discussed under "Energy Supply
Plan" on page I-5.
I-9
<PAGE>
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 1996 1995 1994
---------- ---------------- ---------------- ----------------
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.............. 5,135 17 38 5,086 18 40 5,499 18 42
Oil-fired............... 1,246 34 9 1,191 28 9 1,998 27 15
Nuclear................. 1,270 7 9 1,567 8 12 2,052 8 16
Natural Gas............. 2,656 27 20 2,953 20 23 2,033 19 15
------ --- --- ------ --- --- ------ --- ---
Total Company Genera-
tion................. 10,307 20 76 10,797 18 84 11,582 18 88
<CAPTION>
PURCHASES/INTERCHANGE
---------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Purchases............... 5,785 22 42 3,156 21 24 2,873 23 22
Net Interchange......... (2,444) (26) (18) (1,040) (29) ( 8) (1,328) (32) (10)
------ --- --- ------ --- --- ------ --- ---
Total Output for Load. 13,648 20 100 12,913 18 100 13,127 17 100
====== === === ====== === === ====== === ===
</TABLE>
FUEL SUPPLY FOR ELECTRIC GENERATION
The Company's electric generating capacity by fuel type is shown under
"Electric Operations--Installed Capacity," on page I-4. To facilitate the
purchase of adequate amounts of fuel at reasonable prices, the 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 1996, 15% of the Company's coal
supply was purchased under short-term contracts (less than three years), 77%
under long-term contracts (up to ten years), and the balance on the spot
market. As of December 31, 1996, a maximum of 63% 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
From 80% to 100% of the residual oil used in Edge Moor Unit 5 currently is
being 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 fuel supply contract for the Vienna
Generating Station, which expires in 1997, provides from 90% to 100% of that
station's requirements. Any amount over 90% of requirements may be purchased
in the spot market. The Company expects to negotiate a new contract in 1997
with similar terms.
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-12. Additional natural gas is purchased on a firm or interruptible basis
from one of the Company's pipeline suppliers. The secondary fuel for the Hay
Road CTs is kerosene, which is purchased on the spot market.
I-10
<PAGE>
Nuclear
The cycle of production and use of nuclear fuel involves the mining and
milling of uranium ore to uranium concentrate, conversion of the uranium
concentrate to uranium hexaflouride gas, enrichment of that gas, conversion of
the enriched gas to fuel pellets, fabrication of fuel assemblies from the
pellets, and the use of the fuel assemblies in the generating station reactor.
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.
PECO has informed the Company that it has contracts for uranium concentrates
that will satisfy the fuel requirements of Peach Bottom through 2002. PECO
does not anticipate any difficulties in obtaining its requirements for uranium
concentrates. PECO's contracts for uranium concentrates are allocated to Peach
Bottom on an as-needed basis. PSE&G also has informed the Company that it has
contracts for uranium concentrates which will satisfy the fuel requirements of
Salem fully through 2001 and, thereafter, 50% through 2003. PSE&G does not
anticipate any difficulties in obtaining its requirements for uranium
concentrates. The table below summarizes the years through which PECO and
PSE&G have contracted for the other segments of the nuclear fuel supply cycle.
<TABLE>
<CAPTION>
CONVERSION ENRICHMENT FABRICATION
---------- ---------- -----------
<S> <C> <C> <C>
Peach Bottom Unit 2........................ (1) (2) 1999
Peach Bottom Unit 3........................ (1) (2) 2000
Salem Unit 1............................... 2001 (3) 2004
Salem Unit 2............................... 2001 (3) 2005
</TABLE>
- - --------
(1) PECO has commitments for 100% of its conversion services for Peach Bottom
through 2001 and at least 60% of the conversion services requirements are
covered through 2002. PECO does not anticipate any difficulties in
obtaining necessary conversion services for Peach Bottom.
(2) PECO has contractual commitments for enrichment services for Peach Bottom
with the United States Enrichment Corporation. The commitments represent
100% of the enrichment requirements through 2004. PECO does not anticipate
any difficulties in obtaining necessary enrichment services for Peach
Bottom.
(3) 100% coverage through 1998; approximately 50% coverage through 2002; and
approximately 30% coverage through 2004. PSE&G does not anticipate any
difficulties in obtaining necessary enrichment services for Salem.
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 Salem and Peach Bottom reactors. The
Company is collecting one-tenth of one cent per kWh of nuclear generation net
of station use from electric customers through fuel rates to provide for the
future cost of spent nuclear fuel disposal and is paying such amounts to the
DOE. The DOE may revise this charge as necessary to ensure full cost recovery
of nuclear fuel disposal. Under the NWPA, the DOE was to begin accepting spent
fuel for permanent off-site storage no later than 1998. However, the DOE has
stated that it would not be able to open a permanent, high-level nuclear waste
storage facility until 2015, at the earliest.
In June 1994, a number of utilities and state agencies filed a lawsuit
against the DOE seeking a determination of the DOE's legal obligation to
accept fuel by 1998. In April 1995, the DOE published its final interpretation
on the nuclear waste acceptance issues and stated that it had no legal
obligation to begin waste acceptance in 1998, in the absence of an operational
repository or other storage facility. PSE&G has informed the Company that,
along with 24 other utilities and a combination of 48 states, state regulatory
agencies and municipal power agencies, PSE&G has filed a lawsuit in the United
States District Court of Appeals for the District of Columbia Circuit against
the DOE to protect its contractual rights. The Company is not a party to
either of the above lawsuits. In a decision issued July 23, 1996, the Court of
Appeals for the District of Columbia Circuit found that the DOE is obligated
to begin accepting spent nuclear fuel for disposal no later than January 31,
1998. On January 31, 1997, a group of 36 utilities filed a suit in the United
States District Court of
I-11
<PAGE>
Appeals for the District of Columbia Circuit, to force the DOE to take charge
of high-level nuclear wastes from the nation's commercial power plants by the
court-ordered January 1998 deadline. The lawsuit also requests that payments
made to the Nuclear Waste Fund, after February 1, 1998, be placed into an
escrow account instead of providing these funds to the DOE until it fulfills
its obligations. In addition to the utilities' suit, 46 state agencies have
filed a similar combined lawsuit against the DOE. 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 Peach Bottom Unit 3. Options for expansion of
storage capacity beyond the pertinent dates are being investigated by PECO.
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 2008 for Salem Unit 1 and 2012
for Salem Unit 2.
The Energy Act provided for creation of a Decontamination & Decommissioning
(D&D) Fund to pay for the future clean-up of DOE gaseous diffusion enrichment
facilities. Domestic utilities and the federal government are required to make
payments to the D&D Fund until 2008 or $2.25 billion, adjusted annually for
inflation, is collected. The liability for the Company's share of the D&D Fund
was $6.3 million as of December 31, 1996. The Company is recovering this cost
through fuel adjustment clause revenues which are discussed on page I-13.
GAS OPERATIONS
During 1996, the average production cost of all gas sold was $3.59 per
thousand cubic feet (Mcf), compared with $2.95 and $3.06 per Mcf in 1995 and
1994, respectively. Gas capacity requirements are purchased primarily under
contracts with three pipeline suppliers. The Company also purchases gas supply
from marketers and producers, primarily under one- to five-year agreements.
The Company's peak shaving plant for liquefaction, storage, and re-
gasification of natural gas provides supplemental gas.
As shown in the table below, the Company's maximum 24-hour system
capability, including natural gas purchases, storage deliveries, and the
maximum planned sendout of its peak shaving plant, is 186,960 Mcf.
<TABLE>
<CAPTION>
NUMBER OF EXPIRATION DAILY
CONTRACTS DATES MCF
--------- ---------- -------
<S> <C> <C> <C>
Supply.......................................... 2 1996-2004 33,816
Transportation.................................. 4 2004 83,786
Storage......................................... 4 1996-2004 44,358
Local Peak Shaving.............................. -- -- 25,000
-------
Total........................................ 186,960
=======
</TABLE>
The Company's peak shaving plant has an emergency peak shaving capability of
45,000 Mcf per day, which increases the maximum daily sendout capacity to
206,960 Mcf. The Company experienced an all-time peak daily firm sendout of
158,512 Mcf on January 19, 1994, during extreme weather conditions. The
maximum daily sendout experienced to date during the 1996/97 winter was
141,146 Mcf.
REGULATORY AND RATE MATTERS
The Company is subject to regulation with respect to its retail electric
sales by the DPSC, the MPSC, and the VSCC, each of which have broad
jurisdiction over rate matters, accounting, and terms of service. Gas sales
are subject to regulation by the DPSC. In limited respects concerning
properties and operations in New Jersey
I-12
<PAGE>
and Pennsylvania, the Company is subject to regulation by the utility
commissions in those states. The 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. The percentage of combined electric and gas utility operating
revenues regulated by each Commission for the year ended December 31, 1996 was
as follows: DPSC 61.9%; MPSC 28.8%; VSCC 2.8%; and FERC 6.5%.
BASE RATE PROCEEDINGS
There were no electric or gas base rate increases in 1996. On April 18,
1995, the DPSC approved a joint resolution submitted by the Company and two
customer groups for a $4.5 million or 0.9% increase in electric base rates
effective May 1, 1995. The rate increase was designed to recover the costs of
"limited issues," which primarily are costs imposed by government and are
outside the reasonable control of the Company. The joint resolution also
provided for the funding of nuclear decommissioning costs at the current NRC
minimum financial assurance amount. For a further discussion of the Company's
accounting and funding policies for nuclear decommissioning, refer to Note 6
to the Consolidated Financial Statements of the 1996 Annual Report to
Stockholders, filed as Exhibit 13.
FUEL ADJUSTMENT CLAUSES
The Company's 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, and the costs of natural gas
from its gas customers. Fuel costs are deferred and charged to operations on
the basis of fuel costs included in customer billings under the Company's
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 are filed with and audited by the various commissions and
formal hearings are held at periodic intervals as required by law. Fixed costs
(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, 1996, 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 $2.1 million in 1997. The
1995 and 1996 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. In 1996, the Company incurred a
disallowance of $85,000 in Maryland for a 1994 Salem outage. The 1995 results
indicated that the overall system performance standard was met. The Company
did not meet the 1996 standard due principally to the Salem outage.
In May 1996, the Company filed an application with the VSCC for an increased
fuel rate effective July 1996. In June 1996, the Company filed an application
with the MPSC for an increased fuel rate effective August 1996. In both
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 is made at a future time. The VSCC and MPSC approved the
Company's filings, with rates subject to refund.
On December 10, 1996, the DPSC suspended the portion of the interim rates
relating to Salem replacement power costs until the earlier of June 1, 1997 or
the end of the case concerning fuel rates charged to customers. If the
suspended interim rates go into effect prior to the conclusion of the case,
they would go into effect subject to refund pending the final decision by the
DPSC.
I-13
<PAGE>
Electric retail wheeling, which results in retail customers purchasing
electricity from the suppliers of their choice at market-based prices, has
begun in a number of states and is being considered by many other states.
Based on the Company's initiative, a formal process has been established in
Delaware and an informal forum has been established in Maryland through which
the commissions and other interested parties are addressing changes in the
regulation of the electric utility industry. Changes in regulation resulting
from this process could lead to the elimination of the Company's fuel
adjustment clauses in the future. The Company has established an energy supply
risk management oversight committee whose purpose is to monitor and manage the
Company's commodity price and basis price risks.
OTHER REGULATORY MATTERS
Electric Collaborative Proposal
For a discussion of the electric collaborative proposal presented to the
DPSC and the MPSC, refer to "Competition and the Changing Regulatory
Environment" in the MD&A of the Company's 1996 Annual Report to Stockholders
filed as Exhibit 13.
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. The DPSC's filing requests an $18 million decrease in system
electric expense from current rates. The primary difference between the DPSC
and Company's filing is the DPSC's treatment utilized longer life spans for
production plant and did not include the associated future life extension
additions. The Company filed rebuttal testimony on September 27, 1996. A
hearing in this proceeding has been scheduled for April 10, 1997.
Special Contract Rate Tariffs
With respect to its electric business, the Company filed an Economic
Development Rate (EDR) Tariff and a Negotiated Contract Rate (NCR) Tariff with
the DPSC in August 1995, and with the MPSC in November 1995. While slightly
modified from the tariffs originally filed, EDR and NCR tariffs became
effective in Maryland and Delaware on March 7, 1996 and April 17, 1996,
respectively. New and existing business operations that make a substantial
capital investment and/or create new jobs are eligible for the EDR. These
tariffs are allowing the Company to compete nationally. The EDR provides a
discount which is set at a level such that revenues are sufficient to recover
all variable costs and contribute towards fixed costs. The NCR addresses
special business needs and opportunities which cannot otherwise be
accommodated by the Company's standard tariffs or EDR. The amount of the EDR
discounts are shared by stockholders and ratepayers, 20% and 80%,
respectively, in Delaware, and 30% and 70%, respectively in Maryland. In both
states, stockholders and ratepayers share equally the amount of the NCR
discounts.
Comparable Use Transmission Tariff
On July 9, 1996, the Company submitted an open access transmission tariff in
compliance with FERC Order No. 888. This tariff supersedes the comparable use
transmission tariff filed by the Company on August 28, 1995. On December 31,
1996, the eight member companies of the PJM Interconnection made a joint
compliance filing with the FERC under FERC's Order No. 888. This compliance
filing includes a revised Interconnection Agreement for the PJM
Interconnection Pool, with open membership provisions and other revisions, and
a pool-wide open access transmission tariff. On February 28, 1997 the Company
filed a Notice of Cancellation of its open access transmission tariff to
coincide with the effective date of the PJM pool-wide open access transmission
tariff. Service under the PJM pool-wide open access transmission tariff will
commence on April 1, 1997 and will supersede the open access transmission
tariff filed by the Company on July 9, 1996. For a further discussion on the
PJM Interconnection filing refer to "FERC PJM Interconnection Filing" on page
I-5.
I-14
<PAGE>
The Company/Atlantic Merger Filings
On August 12, 1996, the Company announced plans to merge with Atlantic. On
January 30, 1997, the stockholders of each company approved the merger. The
approvals of the Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935, as amended (1935 Act), the NRC under the
Atomic Energy Act of 1954, as amended, the FERC under the Federal Power Act,
as well as the Delaware, Virginia, Maryland, New Jersey and Pennsylvania
utility commissions under applicable state laws and the expiration or
termination of the applicable waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended, are required to consummate
this merger. On November 27, 1996, the Company and Atlantic filed merger-
related applications with the FERC. On February 24, 1997, the Company and
Atlantic filed merger-related applications with the DPSC, the New Jersey Board
of Public Utilities, and on February 25, 1997 with the VSCC.
Upon consummation of the merger, the new holding company, named Conectiv,
must register as a holding company under the 1935 Act. The 1935 Act imposes
restrictions on the operations of registered holding company systems. Among
these are requirements that securities issuances, sales and acquisitions of
utility assets or of securities of utility companies and acquisitions of
interests in any other business be approved by the SEC. The 1935 Act also
limits the ability of registered holding companies to engage in nonutility
ventures and regulates holding company system service companies and the
rendering of services by holding company affiliates to the system's utilities.
The Company recognizes that the divestiture of its existing gas operations and
certain nonutility operations is a possibility under the new registered
holding company structure, however the 1935 Act application will request that
it be allowed to retain its gas utility operations and nonutility operations
or, in the alternative, that the divestiture be deferred. If divestiture is
ultimately required, the SEC historically has allowed companies sufficient
time to accomplish divestiture in a manner that protects stockholder value.
Natural Gas Restructuring Filing
In March 1995, the Company filed an application with the DPSC to restructure
its natural gas pricing and service options. In February 1996, the DPSC
approved an uncontested settlement which became effective on April 1, 1996.
The redesign of gas rates and modification of the gas cost adjustment
mechanism reallocates revenues among firm customer classes in order to reflect
more accurately the cost of serving these customers. The reallocation
increases prices for residential and low volume commercial customers and
decreases prices for most other commercial and industrial customers.
The settlement unbundles and separately prices several services so that
large and medium volume commercial and industrial customers can elect to use
and pay for only the services that they need. The DPSC also approved new
riders and services, including a Flexibly Priced Gas Sales Service, Quasi-Firm
Transportation Service, Peak Management Rider, and a Negotiated Contract Rate.
A one-year notice is required for firm sales customers switching to
transportation or non-firm service.
The settlement authorizes the Company to provide "nonjurisdictional merchant
sales service," including off-system sales, transportation nomination,
scheduling and coordination services, fuel management services, gas supply or
transportation hedging services, and supply imbalance management services. The
settlement also allows the Company's stockholders to retain 20% of the margin
(revenues net of fuel costs) earned from "nonjurisdictional merchant sales
services," non-firm sales and non-firm transportation services. The remaining
80% will reduce fuel rates charged to firm customers. Previously, 100% of
these margins reduced fuel rates for firm customers.
Additional Regulatory Matters
The Company's entry into competitive activities in the jurisdictions in
which it provides utility service has raised questions concerning whether
cross-subsidization is occurring between regulated utility activities and
these competitive activities, and whether the Company has any unfair
competitive advantage due to its involvement in both competitive and regulated
utility activities. The Company has cost allocation and direct charging
I-15
<PAGE>
mechanisms in place to ensure that there is no cross-subsidization of its
competitive activities by regulated utility activities. At the end of
February, 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 includes a proposed Code of Conduct governing the
Company's regulated utility activities and its competitive activities. The
Company believes that the proposed Code of Conduct is a fair and reasonable
approach to addressing concerns regarding any apparent opportunity for unfair
competitive advantage. It is expected that the CAM application will result in
a litigated proceeding which will allow various parties with an interest in
the outcome to express their concerns for the DPSC's consideration. The
Company cannot predict the outcome of this proceeding.
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. At this time, the outcome of this proceeding
and the resulting standards of conduct, if any, cannot be predicted. It is
expected that the Company will participate in this proceeding and will take
the position that the Code of Conduct proposed to the DPSC should be adopted
by the MPSC. The Company expects that the CAM will be filed with the MPSC on
either a formal or informational basis and that the CAM and Code of Conduct
also will be filed with the VSCC on an informational basis.
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
Conectiv Services, Inc., its subsidiary engaging in the heating, ventilation
and air conditioning business and related businesses; transactions between the
Company and Conectiv Communications, Inc., its telecommunications subsidiary;
capital contributions to affiliates regarding a number of competitive
activities; and various other past subsidiary transactions. Only one of these
applications, covering Conectiv Services, Inc., has been acted upon by the
VSCC, which issued an interim order allowing the Company to engage in the
transactions described in the application.
CAPITAL SPENDING AND FINANCING PROGRAM
The Company's estimated capital requirements for the period 1997-2001,
excluding $8.7 million of AFUDC, are shown in the following table:
<TABLE>
<CAPTION>
CALENDAR YEAR (DOLLARS IN THOUSANDS)
--------------------------------------------
1997 1998 1999 2000 2001
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Energy Services:
HVAC.......................... $ 31,474 $ 25,363 $ 28,334 $ 32,302 $ 34,930
Telecommunications............ 34,056 34,573 25,660 14,380 11,789
Other......................... 11,627 818 785 808 716
-------- -------- -------- -------- --------
Total Energy Services.......... 77,157 60,754 54,779 47,490 47,435
Energy Supply.................. 45,781 30,017 47,266 51,498 57,530
Regulated Delivery............. 76,276 99,456 81,714 89,759 70,615
Debt Maturities................ 29,176 35,102 37,471 4,203 5,157
-------- -------- -------- -------- --------
Total Estimated Capital
Requirements................. $228,390 $225,329 $221,230 $192,950 $180,737
======== ======== ======== ======== ========
</TABLE>
The Company's primary capital resources available to fund capital
requirements are internally generated funds and external financings. Although
the Company expects internally generated funds from its regulated utility
business to provide sufficient funds for utility capital requirements,
acquisitions and capital required to fund start-up costs for new businesses
will require external financing in the early part of the five year planning
period.
I-16
<PAGE>
Since the Company's future construction program, internal generation of
funds, and need for outside capital will be affected by such matters as
customer demand, inflation, competition, and rate regulation, future results
may vary from the foregoing estimates. In addition, the ultimate resolution of
the problems at Salem, as discussed in "Salem Units" on page I-7, may increase
future capital requirements.
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 a successor Trustee
requiring the pro forma ratio of consolidated earnings to interest on First
Mortgage Bonds 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, 1996 was 6.16. 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 2.23 for the twelve months
ended December 31, 1996.
The Company's ratios of earnings to fixed charges and earnings to fixed
charges and preferred stock dividends under the SEC Methods for 1992-1996 are
shown below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed Charges (SEC Method)... 3.33 3.54 3.49 3.47 3.03
Ratio of Earnings to Fixed Charges (SEC Method),
as
Adjusted(1)...................................... -- -- 3.74 -- 2.78
Ratio of Earnings to Fixed Charges and Preferred
Stock Dividends (SEC Method)..................... 2.83 2.92 2.85 2.88 2.51
Ratio of Earnings to Fixed Charges and Preferred
Stock Dividends (SEC Method), as Adjusted(1)..... -- -- 3.05 -- 2.30
</TABLE>
- - --------
(1) Adjusted ratios reflect the following pre-tax amounts: for 1994, the
exclusion of an early retirement offer charge of $17.5 million; and for
1992, the exclusion of the gain from the Company's share of a settlement
reached in a lawsuit of $18.5 million.
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.
For further information on the Company's financing activities, refer to
Notes 9 through 12 to the Consolidated Financial Statements and "Liquidity and
Capital Resources" in the MD&A of the 1996 Annual Report to Stockholders filed
as Exhibit 13.
ENVIRONMENTAL MATTERS
The Company is subject to regulation with respect to the environmental
effects of its operations, including air and water quality control, oil
pollution control, solid and hazardous waste disposal, and limitation on land
use by various federal, regional, state, and local authorities. Permits are
required for the Company's construction projects and existing facilities. The
Company has incurred, and expects to continue to incur, capital expenditures
and operating costs because of environmental considerations and requirements.
The Company is engaged in a continuing program to assure compliance with the
environmental standards adopted by various regulatory authorities.
I-17
<PAGE>
Construction Expenditures
Construction expenditures for compliance with environmental regulations,
primarily the Clean Air Act Amendments of 1990 (Clean Air Act), are estimated
at $83 million (excluding AFUDC) for the years 1997-2001. These amounts are
included in the Company's estimates of capital requirements under "Capital
Spending and Financing Program" on page I-16.
Clean Air Act
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, the only units required to comply with Title IV in 1995, have been
achieved through installation and operation of flue gas desulfurization (FGD)
systems. The remainder of the Company's wholly- and jointly-owned fossil fuel
fired units are expected to meet Phase II emission limits through a
combination of fuel switching, and SO/2/ allowance trading.
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 Control 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. The Company has installed low NOx burner technology and will undertake
certain operating changes to comply with the RACT requirement. The Company's
Delaware and Maryland RACT proposals have not received final regulatory
approval. Consequently, costs, in addition to those already budgeted, may be
incurred at these facilities in order to comply with the RACT regulations.
Additional "post-RACT" NOx emission limitations are being discussed by
several entities, including the Northeast Ozone Transport Commission (NOTC).
One such proposal, recognized by a Memorandum of Understanding (MOU) signed by
NOTR member states, would require sources to meet certain emission limitations
or to reduce NOx emissions up to 65% below 1990 levels by 1999. Under the MOU,
states would be required to propose further NOx reductions by 2003, if
necessary. While the special provisions of the MOU have not been adopted by
regulation in Delaware or Maryland, the Company likely will be required to
install post-combustion NOx control equipment on some or all of the Company's
major generating units. At this time, the Company cannot determine the
potential operating impacts and anticipated costs associated with this
particular "post-RACT" initiative.
The United States Environmental Protection Agency (EPA) recently proposed
new ambient air quality standards for ozone and fine-size particulate matter.
The new standards, if adopted in their present form, may require additional
controls on certain power plant sources that are located in areas that are not
attaining standards. At this time the Company cannot predict the potential
future impacts associated with the implementation of any new ozone or
particulate matter standards. In addition, to help attain air quality
standards, the Clean Air Act mandates that the emission of certain air
pollutants by new sources or increased emissions from existing facilities be
offset by reductions in similar emissions from existing sources. Such
requirements may affect the Company's ability to locate, construct, and expand
generating facilities in the future.
Salem Operating Permit
PSE&G has informed the Company that it has settled all challenges raised by
the State of Delaware and other parties to the final five-year operating
permit for the Salem units issued by the New Jersey Department of
Environmental Protection (NJDEP). The estimated capital cost of compliance
with the final permit is approximately $100 million of which the Company's
share is 7.41%. A separate settlement with challenging parties, other than
Delaware, precludes these parties from arguing that modifications to the
plant's cooling water
I-18
<PAGE>
intake system or cooling water system discharge are necessary prior to August
31, 1999. This settlement requires PSE&G to work with the challenging parties
to evaluate intake structure impingement and entrainment technologies, and
authorizes the challenging parties to recommend independent scientists to
participate on NJDEP advisory committees regarding plant operations.
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
discharge systems continue to be in compliance. The studies are expected to
take one to two years. 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 $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.
The Company has accrued a liability of $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.
Subsidiaries
Certain of the Company's subsidiaries are also subject to regulations with
respect to the environmental effects of their operations, including air and
water quality control, solid waste disposal, and limitation on land use by
various federal, regional, state, and local authorities. In February of 1996,
one of the Company's indirect subsidiaries, Pine Grove Landfill, Inc. (Pine
Grove), which owns and operates a solid waste disposal facility in
Pennsylvania, was issued a Notice of Violation by the Pennsylvania Department
of Environmental Protection (PADEP) for a series of odor emissions from the
facility. Pine Grove expects to enter into a consent order and agreement with
PADEP, which will include a $40,000 civil penalty and additional payments of
$48,500 to environmental programs designated by PADEP. Pine Grove's management
believes it has corrected the odor problem at the disposal facility. Pine
Grove's management cannot predict the nature of any actions which PADEP may
take in the event of future odor emissions. PADEP has the authority to impose
fines and/or close, limit expansion, or order changes in the business
practices at the disposal facility. The Company believes that its subsidiaries
are in substantial compliance with all environmental regulations.
RETAIL FRANCHISES
The franchises discussed below could be impacted by legislation mandating
the retail wheeling of electricity. For a further discussion on the
development of competition in retail markets, refer to "Electric Retail
Business" on page I-2 and "Strategic Plans for Competition" in the MD&A of the
Company's 1996 Annual Report to Stockholders filed as Exhibit 13.
The Company holds franchises, which for the most part are perpetual, for the
rendition of 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.
I-19
<PAGE>
The Company holds franchises, which for the most part are perpetual, for the
rendition of 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 the rendition of 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.
FORWARD-LOOKING STATEMENTS
The Private Securities Litigation Reform Act of 1995 (Litigation Reform Act)
provides a new "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; 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.
NUMBER OF EMPLOYEES
The number of full time employees of the Company at December 31, 1996 was
2,963.
A total of 1,415 employees are represented by the International Brotherhood
of Electrical Workers Locals 1238 (Northern) and 1307 (Southern) whose
contracts with the Company expire on December 15, 1997 and June 25, 1997,
respectively.
I-20
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, and positions of all of the executive officers of the
Company as of January 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 JANUARY 31, 1997)
<TABLE>
<CAPTION>
BUSINESS EXPERIENCE
NAME, AGE AND POSITION DURING PAST 5 YEARS
---------------------- -------------------
<S> <C>
Howard E. Cosgrove, 53........ Elected 1992.
Chairman of the Board,
President, and Chief
Executive Officer and
Director
Joseph W. Ford, 51............ 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, 48......... 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, 54.......... Elected 1992.
Senior Vice President
Thomas S. Shaw, 49............ Elected 1992.
Senior Vice President
James P. Lavin, 49............ Elected 1993. Comptroller--Corporate and Chief
Comptroller and Chief Accounting Officer from 1989 to 1993.
Accounting Officer
</TABLE>
I-21
<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, 1996.
<TABLE>
<CAPTION>
NET INSTALLED
CAPACITY
STATION LOCATION (KWH)
------- -------- -------------
<C> <S> <C>
COAL-FIRED
Edge Moor......................... Wilmington, DE.......... 251,000
Indian River...................... Millsboro, DE........... 743,000
Conemaugh......................... New Florence, PA........ 63,000(A)
Keystone.......................... Shelocta, PA............ 63,000(A)
---------
1,120,000
---------
OIL-FIRED
Edge Moor......................... Wilmington, DE.......... 445,000
Vienna............................ Vienna, MD.............. 151,000
---------
596,000
---------
COMBUSTION TURBINES/COMBINED CYCLE
Hay Road.......................... Wilmington, DE.......... 511,000
---------
NUCLEAR
Peach Bottom...................... Peach Bottom Twp., PA... 164,000(A)
Lower Alloways Creek
Salem............................. 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......... 14,000
Delaware City..................... Delaware City, DE....... 14,000
Indian River...................... Millsboro, DE........... 17,000
Vienna............................ Vienna, MD.............. 17,000
Tasley............................ Tasley, VA.............. 26,000
Lower Alloways Creek
Salem............................. 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)
---------
182,800
---------
CUSTOMER-OWNED CAPACITY.............. Delaware City, DE....... 57,000(B)
CAPACITY PURCHASED FROM PECO.................................... 205,000
---------
Subtotal..................................................... 2,999,800
---------
PURCHASED PJM INTERCONNECTION CAPACITY CREDITS.................. 185,000
---------
Total........................................................ 3,184,800
=========
</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-22
<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, 6,927 distribution poleline miles of overhead lines, and
5,416 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 a maximum
planned daily sendout capacity of 25,000 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............................................... 111*
Distribution Mains............................................... 1,539
Service Lines.................................................... 1,091
</TABLE>
--------
* Includes 11 miles of joint-use gas pipeline that is
used 10% for gas and 90% for electric.
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, E. I. du Pont de Nemours and 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 asks for actual damages in excess of
$41 million and for special and punitive damages in unspecified amounts. The
Company believes that its insurance will cover any amounts awarded in this
lawsuit in excess of $1 million for each outage. There is $2 million included
in the Company's current liabilities as of December 31, 1996, for claims
related to the outages. The Company cannot predict the outcome of this
lawsuit.
For a discussion of the Company's lawsuit against Westinghouse, refer to
"Salem Units" on page I-7.
For a discussion of the Company's lawsuit against Public Service Enterprise
Group, Inc. and PSE&G, refer to "Salem Units" on page I-7.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On January 30, 1997, at a Special Meeting of the stockholders of the
Company, the holders of the Company's Common Stock voted to approve the
Agreement and Plan of Merger, dated as of August 9, 1996, as amended and
restated as of December 26, 1996, (Merger Agreement) by and among the Company,
Atlantic, Conectiv, Inc. and DS Sub, Inc. The Merger Agreement covers the
proposed merger of the Company and Atlantic (Merger), which originally was
announced on August 12, 1996.
For the Merger Agreement to be approved, the holders of more than two-thirds
of the outstanding shares of Common Stock entitled to vote were required to
vote for approval of the Merger Agreement. Out of 60,754,568 shares of Common
Stock issued and outstanding and entitled to vote, 51,621,009 shares (84.97%)
were represented in person or by proxy at the Special Meeting. 49,681,023
shares (81.77%) of the Common Stock voted for, 1,399,950 shares (2.30%) of the
Common Stock voted against, and 540,036 (.89%) shares of the Common Stock
abstained from voting on the approval of the Merger Agreement.
I-23
<PAGE>
The holders of the Common Stock also approved the Conectiv, Inc. Incentive
Compensation Plan (Plan), which will become effective if and when the Merger
is consummated. The Plan is for the purpose of rewarding those officers, key
employees, consultants and advisors of Conectiv (the new holding company
following the Merger) and its subsidiaries, who are responsible for Conectiv's
and its subsidiaries continued growth, development and financial success. The
affirmative vote of the holders of a majority of the Common Stock present in
person or by proxy and entitled to vote was required for approval of the Plan.
Out of 60,754,568 shares of Common Stock issued and outstanding and entitled
to vote, 51,621,009 shares (84.97%) of the Common Stock were present in person
or by proxy at the Special Meeting. 44,584,519 shares (86.37%) of the Common
Stock present in person or by proxy voted for, 4,850,150 shares (9.40%) of the
Common Stock present in person or by proxy voted against, and 2,186,019 shares
(4.23%) of the Common Stock present in person or by proxy abstained from
voting on the approval of the Plan.
I-24
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed on the New York and Philadelphia Stock
Exchanges and has unlisted trading privileges on the Cincinnati, Midwest, and
Pacific Stock Exchanges and had the following dividends declared and high/low
prices by quarter for the years 1996 and 1995.
<TABLE>
<CAPTION>
1996 1995
------------------------ ------------------------
PRICE PRICE
DIVIDEND --------------- DIVIDEND ---------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ------- ------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
First Quarter................. $.38 1/2 $23 5/8 $21 $.38 1/2 $20 $17 7/8
Second Quarter................ .38 1/2 21 1/2 19 1/8 .38 1/2 21 1/4 19 1/8
Third Quarter................. .38 1/2 21 1/4 20 .38 1/2 23 19 1/2
Fourth Quarter................ .38 1/2 21 1/2 19 3/4 .38 1/2 23 5/8 21 7/8
</TABLE>
The Company had 52,644 registered holders of common stock as of December 31,
1996.
While the Board of Directors intends to continue the practice of paying
dividends quarterly, amounts and dates of such dividends as may be declared
will necessarily be dependent upon the Company's future earnings, financial
requirements, and other factors. On August 12, 1996, the Company announced
plans to merge with Atlantic. The Merger Agreement restricts the Company's
common stock dividend through the Merger's effective date to an amount which
cannot exceed $1.54 per share. The Merger is part of the Company's growth
strategy, which 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 shareholder value on a
long-term basis. For a further discussion of dividends, refer to "Dividends"
in the MD&A of the 1996 Annual Report to Stockholders filed herein as Exhibit
13, which portion of such Annual Report is hereby incorporated by reference
herein.
ITEM 6. SELECTED FINANCIAL DATA
This information is contained on page 22 of the 1996 Annual Report to
Stockholders filed herein as Exhibit 13, which portion of such Annual Report
is hereby incorporated by reference herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
This information is contained on pages 23 through 32 of the 1996 Annual
Report to Stockholders filed herein as Exhibit 13, which portion of such
Annual Report is hereby incorporated by reference herein.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements, notes 1 through 20 to consolidated
financial statements, and related report thereon of Coopers & Lybrand L.L.P.,
independent accountants, appear on pages 33 through 54 of the 1996 Annual
Report to Stockholders filed herein as Exhibit 13, which portion of such
Annual Report is hereby incorporated by reference herein.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
II-1
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
"Proposal No. 1--Election of Directors" is incorporated by reference herein
from the Definitive Proxy Statement which is expected to be filed on or about
April 7, 1997, and information about the executive officers of the registrant
is included under Item 1.
ITEM 11. EXECUTIVE COMPENSATION
"Executive Compensation" is incorporated by reference herein from the
Definitive Proxy Statement which is expected to be filed on or about April 7,
1997.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
"Proposal No. 1--Election of Directors" is incorporated by reference herein
from the Definitive Proxy Statement which is expected to be filed on or about
April 7, 1997.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
III-1
<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 the Company's 1996 Annual Report to Stockholders filed as Exhibit 13
hereto and incorporated herein by reference.
<TABLE>
<CAPTION>
1996
ANNUAL REPORT
FINANCIAL STATEMENTS (PAGE)
-------------------- -------------
<S> <C>
Consolidated Statements of Income for the three years ended
December 31, 1996............................................ 34
Consolidated Statements of Cash Flows for the three years
ended December 31, 1996...................................... 35
Consolidated Balance Sheets as of December 31, 1996 and 1995.. 36 and 37
Consolidated Statements of Changes in Common Stockholders' Eq-
uity for the three years ended December 31, 1996............. 38
Notes to Consolidated Financial Statements.................... 39 to 54
</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, 1996 can be found on page IV-3 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 Copy of the Company's By-Laws as amended November 21, 1996.
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.)
</TABLE>
IV-1
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
-------
<C> <S>
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.
10-B Copy of the Supplemental Executive Retirement Plan, revised as of
October 29, 1991. (Filed with Form 10-K for the year ended December
31, 1992, File No. 1-1405.)
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.
10-E Copies of amendments to the Long Term Incentive Plan, effective
January 1, 1997, and January 30, 1997.
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.
10-H Copy of the Management Life Insurance Plan amended and restated as of
January 1, 1992.
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.
12-A Computation of ratio of earnings to fixed charges.
12-B Computation of ratio of earnings to fixed charges and preferred
dividends.
13 Certain portions of the 1996 Annual Report to Stockholders which are
incorporated by reference in this Form 10-K.
23 Consent of Independent Accountants.
27 Financial Data Schedule.
</TABLE>
(b) Reports on Form 8-K (filed during the reporting period): None
IV-2
<PAGE>
DELMARVA POWER & LIGHT COMPANY
SCHEDULE OF OPERATING STATISTICS
FOR THE THREE YEARS ENDED DECEMBER 31, 1996
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, 1996.
<TABLE>
<CAPTION>
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
ELECTRIC:
Electricity generated and purchased
(MWh):
Generated.............................. 10,307,299 10,797,547 11,581,929
Purchased.............................. 6,195,720 3,977,867 3,766,169
Interchange deliveries................. (2,855,109) (1,862,467) (2,220,898)
----------- ----------- -----------
Total output for load................. 13,647,910 12,912,947 13,127,200
=========== =========== ===========
Electric sales (MWh):
Residential............................ 4,262,710 3,829,807 3,578,743
Commercial............................. 4,018,120 3,744,879 3,461,058
Industrial............................. 3,331,175 3,351,834 3,248,131
Resale................................. 1,333,268 1,213,459 2,166,154
Other sales(1)......................... (19,557) 170,942 50,996
----------- ----------- -----------
Total sales........................... 12,925,716 12,310,921 12,505,082
Losses and miscellaneous system uses... 722,194 602,026 622,118
----------- ----------- -----------
Total disposition of energy............ 13,647,910 12,912,947 13,127,200
=========== =========== ===========
Operating revenue (thousands):
Residential............................ $ 378,520 $ 344,351 $ 312,224
Commercial............................. 286,438 267,239 242,506
Industrial............................. 156,329 155,108 145,594
Resale................................. 65,989 58,680 105,350
Other sales revenues(2)................ 2,503 14,211 6,816
Interchange deliveries................. 75,301 47,271 62,388
Miscellaneous revenues................. 15,597 12,802 8,237
----------- ----------- -----------
Total revenues........................ $ 980,677 $ 899,662 $ 883,115
=========== =========== ===========
Number of customers (end of period):
Residential............................ 391,611 386,948 347,997
Commercial............................. 49,165 48,345 44,060
Industrial............................. 683 704 699
Resale................................. 12 12 12
Other.................................. 645 641 604
----------- ----------- -----------
Total customers....................... 442,116 436,650 393,372
=========== =========== ===========
Average annual use per residential cus-
tomer (kWh)(3)........................ 10,948 10,365 10,359
Average annual revenue per residential
customer(3)........................... $ 972.12 $ 931.95 $ 903.74
Average revenue per kWh (cents):
Residential............................ 8.9 9.0 8.7
Commercial............................. 7.1 7.1 7.0
Industrial............................. 4.7 4.6 4.5
GAS:
Gas sales (Mcf)........................ 18,659 18,478 18,087
Gas transported (Mcf).................. 5,498 2,893 2,255
Gas revenue (thousands)................ $ 114,284 $ 95,441 $ 107,906
Number of customers (end of period):
Residential............................ 93,149 90,890 88,518
Commercial............................. 7,615 7,369 6,982
Industrial............................. 139 146 150
Interruptible and other................ 1 12 12
----------- ----------- -----------
Total customers....................... 100,904 98,417 95,662
=========== =========== ===========
Residential gas service:
Average annual use per customer
(Mcf)(3).............................. 94.56 81.75 88.55
Average annual revenue per customer(3). $ 652.95 $ 525.87 $ 632.11
Average revenue per Mcf................ $ 6.91 $ 6.43 $ 7.14
</TABLE>
- - --------
(1) Includes unbilled sales.
(2) Includes unbilled revenues.
(3) Based on average number of customers during period.
IV-3
<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.
Delmarva Power & Light Company
(Registrant)
Dated: March 26, 1997
By /s/ Barbara S. Graham
----------------------------------
(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 AND ON THE DATE INDICATED.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Howard E. Cosgrove Chairman of the Board, March 26, 1997
- - ------------------------------------- President, Chief
(Howard E. Cosgrove) Executive Officer,
and Director
/s/ Barbara S. Graham Senior Vice President March 26, 1997
- - ------------------------------------- and Chief Financial
(Barbara S. Graham) Officer
/s/ James P. Lavin Comptroller and Chief March 26, 1997
- - ------------------------------------- Accounting Officer
(James P. Lavin)
/s/ Michael G. Abercrombie Director March 26, 1997
- - -------------------------------------
(Michael G. Abercrombie)
/s/ R. Franklin Balotti Director March 26, 1997
- - -------------------------------------
(R. Franklin Balotti)
/s/ Robert D. Burris Director March 26, 1997
- - -------------------------------------
(Robert D. Burris)
/s/ Audrey K. Doberstein Director March 26, 1997
- - -------------------------------------
(Audrey K. Doberstein)
/s/ Michael B. Emery Director March 26, 1997
- - -------------------------------------
(Michael B. Emery)
/s/ James H. Gilliam, Jr. Director March 26, 1997
- - -------------------------------------
(James H. Gilliam, Jr.)
/s/ Sarah I. Gore Director March 26, 1997
- - -------------------------------------
(Sarah I. Gore)
/s/ James C. Johnson Director March 26, 1997
- - -------------------------------------
(James C. Johnson)
/s/ Weston E. Nellius Director March 26, 1997
- - -------------------------------------
(Weston E. Nellius)
IV-4
<PAGE>
DELMARVA POWER & LIGHT COMPANY
1996 ANNUAL REPORT ON FORM 10-K
EXHIBIT INDEX
Exhibit
Number Description
- - ------ -----------
3-F Copy of the Amendment to the Company's By-Laws.
10-A Copy of the Management Incentive Compensation Plan.
10-D Copy of the Long Term Incentive Plan.
10-E Copy of the Amendment to the Long Term Incentive Plan.
10-G Copy of the current listing of members of management who have
signed the severance agreement.
10-H Copy of the Management Life Insurance Plan.
10-J Copy of the Amendment to the Deferred Compensation Plan.
12-A Computation of ratio of earnings to fixed charges.
12-B Computation of ratio of earnings to fixed charges
and preferred dividends.
13 Certain portions of the 1996 Annual Report to
Stockholders which are incorporated by reference in
this Form 10-K.
23 Consent of Independent Accountants.
27 Financial Data Schedule.
<PAGE>
DELMARVA POWER & LIGHT COMPANY
BY-LAWS
ARTICLE I
Offices
Section 1. The principal office of the Company in the State of Delaware
shall be at 800 King Street in the City of Wilmington and County of New Castle.
The Company may also have offices at such other places as the Board of Directors
may from time to time determine.
ARTICLE II
Meetings of Stockholders
Section 1. The Annual Meeting of the stockholders of the Company shall be
held for the purpose of electing directors and for the transaction of only such
business as is properly brought before the meeting in accordance with the By-
Laws. The Annual Meeting shall take place at such time and location as
determined by resolution of the Board of Directors on the last Thursday of May
in each year, unless such day is a legal holiday, in which case it shall be held
on the first day thereafter which is not a legal holiday, and on any subsequent
day or days to which such meeting may be adjourned. In case the Annual Meeting
of Stockholders should not be held on the day fixed therefor, or should be
finally adjourned without completing the election of directors, such election
may be held subsequently at a special stockholders' meeting, called as
hereinafter provided. The time and place for said annual meeting shall be set at
least sixty (60) days prior to the date of each annual meeting. A notice of the
time and place shall be given to each stockholder entitled to vote at least
twenty (20) days before the date of the meeting, in person or by letter mailed
to his last known post office address.
To be properly brought before the Annual Meeting, business must be either (a)
specified in the notice of meeting (or any supplement thereto) given by or at
the direction of the Board, or (b) otherwise properly brought before the meeting
by or at the direction of the Board, or (c) otherwise properly brought before
the meeting by a stockholder. In addition to any other applicable requirements,
for business to be properly brought before an annual meeting by a stockholder,
the stockholder must have given timely notice thereof in writing to the
Secretary of the Company. To be timely, a stockholder's notice must be delivered
to or mailed and received at the principal executive offices of the Company, not
less than fifty (50) days nor more than seventy-five (75) days prior to the
meeting; provided, however, that in the event that less than sixty-five (65)
days' notice or prior public disclosure of the date of the meeting is given or
made to stockholders, notice by the stockholder to be timely must be so received
not later than the close of business on the fifteenth (15th) day following the
day on which such notice of the date of the Annual Meeting was mailed or such
public disclosure was made, whichever first occurs. A stockholder's notice to
the secretary shall set forth as to each matter the stockholder proposes to
bring before the Annual Meeting (i) a brief description of the business desired
to be brought before the Annual Meeting and the reasons for conducting such
business at the Annual Meeting, (ii) the name and record address of the
stockholder proposing such
<PAGE>
business, (iii) the class and number of shares of the Company which are
beneficially owned by the stockholder, and (iv) any material interest of the
stockholder in such business.
No business shall be conducted at the Annual Meeting except in accordance
with the procedures set forth in this Article II, provided, however, that
nothing in this Article II shall be deemed to preclude discussion by any
stockholder of any business properly brought before the annual meeting.
The Chairman/Chairwoman of an annual meeting shall, if the facts warrant,
determine and declare to the meeting that business was not properly brought
before the meeting in accordance with the foregoing procedures, and if he/she
should so determine, he/she shall so declare to the meeting and any such
business not properly brought before the meeting shall not be transacted.
Section 2. The directors shall be divided into three classes, designated
Class I, Class II, and Class III. Each Class shall consist, as nearly as may be
possible, of one-third of the total number of Directors constituting the entire
Board of Directors. At each Annual Meeting of stockholders, successors to the
class of directors whose term expires at the Annual Meeting shall be elected for
a three-year term. If the number of directors is changed, any increase or
decrease shall be apportioned among the classes so as to maintain the number of
directors in each class as nearly as possible, but in no case will a decrease in
the number of directors shorten the term of any incumbent director. A director
shall hold office until the Annual Meeting for the year in which his or her term
expires and until his or her successor shall be elected and shall qualify,
subject, however, to prior death, resignation, retirement, disqualification or
removal from office.
Only persons who are nominated in accordance with the following procedures
shall be eligible for election as directors. Nominations of persons for election
to the Board of Directors of the Company may be made at a meeting of
stockholders by the Board of Directors, at the direction of the Board by any
nominating committee or person appointed by the Board, or by any stockholder of
the Company entitled to vote for the election of Directors at the meeting who
complies with the notice procedures set forth in this Section 2. Such
nominations, other than those made by or at the direction of the Board, shall be
made pursuant to timely notice in writing to the Secretary of the Company. To be
timely, a stockholder's notice shall be delivered to or mailed and received at
the principal executive offices of the Company not less than fifty (50) days nor
more than ninety (90) days prior to the meeting; provided, however, that in the
event that less than sixty-five (65) days' notice or prior public disclosure of
the date of the meeting is given or made to stockholders, notice by the
stockholder to be timely must be so received not later than the close of
business on the fifteenth (15th) day following the day on which such notice of
the date of the meeting was mailed or such public disclosure was made, whichever
first occurs. Such stockholder's notice to the Secretary shall set forth (a) as
to each person whom the stockholder proposes to nominate for election or re-
election as a director, (i) the name, age, business address and residence
address of the person, (ii) the principal occupation or employment of the
person, (iii) the class and number of shares of capital stock of the Company
which are beneficially owned by the person and (iv) any other information
relating to the person that is required to be disclosed in solicitations for
proxies for election of directors pursuant to Rule 14A under the Securities
Exchange Act of 1934, as amended; and (b) as to the stockholder giving the
notice (i) the name and
<PAGE>
record address of such stockholder and (ii) the class and number of shares of
capital stock of the Company which are beneficially owned by such stockholder.
The Company may require any proposed nominee to furnish such other information
as may reasonably be required by the Company to determine the eligibility of
such proposed nominee to serve as a director of the Company. No person shall be
eligible for election as a director of the Company unless nominated in
accordance with the procedures set forth herein.
The Chairman/Chairwoman of the meeting shall, if the facts warrant,
determine and declare to the meeting that a nomination was not made in
accordance with the foregoing procedure and if he/she should so determine,
he/she shall so declare to the meeting and the defective nomination shall be
disregarded.
Section 3. At each Annual Meeting of the stockholders of the Company,
independent public accountants shall be appointed by vote of the holders of
shares of the Common Stock, to audit the accounts and records of the Company and
its subsidiaries and to report on the financial statements for the current
fiscal year.
Section 4. At least ten (10) days before every election a complete list of
stockholders entitled to vote, arranged in alphabetical order, shall be prepared
and shall be open at the place where said election is to be held and at the
Company's principal place of business for said ten (10) days to the inspection
of any stockholder, and shall be produced and kept at the time and place of
election during the whole time thereof and subject to the inspection of any
stockholder who may be present.
Section 5. Except as otherwise required by law, a representation of at
least a majority of the outstanding capital stock of the Company issued and
entitled to vote shall constitute a quorum requisite for the transaction of
business at all meetings of the stockholders; less than such quorum, however,
shall have power to adjourn any meeting from time to time without notice.
Section 6. Each stockholder of record having the right to vote at meetings
shall be entitled to one vote for each share of stock standing in his name upon
the books of the Company, to be voted by the stockholder in person, or by duly
authorized proxy or attorney. The record date for determining stockholders
entitled to vote shall be fixed under the provisions of Section 3 of Article XVI
hereof, provided that if the transfer books are not closed and no record date is
fixed, the date on which the notice of the meeting is given, as provided for in
Section 9 of this Article II, shall be the record date for determining
stockholders entitled to vote. No authority as proxy or attorney shall be valid
unless executed in writing and dated not more than eleven (11) months prior to
the meeting at which it is to be used, except as otherwise provided by law.
Section 7. All questions shall be decided by vote of a majority of the
stock present or represented and entitled to vote, unless otherwise especially
provided by law.
Section 8. Special meetings of the stockholders may be held outside the
State of Delaware and may be called by the Chairman/Chairwoman, the President,
or the Board of Directors.
Section 9. In addition to any notice which may be required by law, notice
of the Annual Meeting for the election of directors and of all special meetings
of the stockholders shall be given by delivering or sending by mail written or
printed notice thereof, stating the object of such meeting, to each stockholder
appearing as such on the books of the Company and entitled to vote at such
meeting, and in case of mailing, at the address given
<PAGE>
on such books, at least ten (10) days prior to an annual meeting or a special
meeting; but meetings may be held without notice if all stockholders are present
in person or represented by proxy or if notice is waived, whether before or
after the time stated therein, by those not present in person or represented by
proxy. Except as required by statute, no notice need be given of any adjourned
meeting of stockholders.
Section 10. At each meeting of the stockholders the polls shall be opened
and closed and the proxies and ballots shall be received and taken in charge of
and all questions touching on the qualifications of voters and the validity of
proxies and the acceptance and rejection of votes shall be decided by two (2)
Inspectors of Election. The Inspectors of Election shall also, if so directed by
the presiding officer of the meeting, decide and report upon the presence of a
quorum. Such Inspectors of Election shall be appointed by the Board of Directors
before or at the meeting, and if no such appointment shall have been made, then
by the presiding officer of the meeting. If for any reason any of the Inspectors
of Election previously appointed shall fail to attend or refuse or be unable to
serve, Inspectors of Election in place of any so failing to attend or refusing
or unable to serve shall be appointed either by the Board of Directors or by the
presiding officer of the meeting. No Inspector of Election shall enter on the
duties of his office or appointment until he takes and subscribes an oath or
affirmation before some person qualified by law to administer oaths that he will
faithfully, honestly, and impartially perform his duties as an Inspector of
Election to the best of this skill and ability.
Section 11. Article 14.1 of the Virginia Stock Corporation Act does not
apply to acquisitions of shares of stock of the Company.
ARTICLE III
Directors and Officers
Section 1. The business and affairs of the Company shall be managed under
the direction of a Board of Directors consisting of not less than three (3) nor
more than fifteen (15) directors, the exact number of directors to be determined
from time to time by resolution adopted by the affirmative vote of a majority of
the directors then in office or two-thirds of the shares, represented by proxy
or in person, entitled to vote and a meeting at which a quorum is present.
Section 2. Any director of the Company may resign at any time by giving
written notice to the President or the Secretary of the Company. Such
resignation shall take effect at the time specified therein; and, unless
otherwise specified therein, the acceptance of such resignation shall not be
necessary to make it effective.
Section 3. The officers shall be a Chairman/Chairwoman of the Board, a
President, one or more Vice Presidents, a Secretary and one or more Assistant
Secretaries, a Treasurer and one or more Assistant Treasurers, one or more
Comptrollers and one or more Assistant Comptrollers, and such other officers as
the Board of Directors may from time to time deem necessary. One person may hold
more than one office, except that the same person shall not be President and a
Vice President, or President and Secretary, or President and Treasurer.
<PAGE>
ARTICLE IV
Powers and Duties of Directors
Section 1. The Board of Directors shall choose the Chairman/Chairwoman of
the Board and the President from among their number. Vacancies in the Board,
except those caused by an increase in the number of directors authorized by more
than two (2), may be filled by a majority of the then members of the Board of
Directors, though less than a quorum.
Section 2. The Board of Directors shall elect the Vice Presidents, a
Secretary, a Treasurer, one or more Comptrollers, one or more Assistant
Secretaries, one or more Assistant Treasurers, and one or more Assistant
Comptrollers and shall have the power to constitute and appoint such other
officers as may be found necessary and the interests of the Company may require
and to fix, or delegate the power to fix, the compensation and define the duties
of all such officers.
Section 3. All the officers of the Company shall be subject to the orders
of the Board and may be removed by the Board at discretion.
Section 4. The Board of Directors may appoint from among its members an
Executive Committee by vote of a majority of the number of the directors fixed
by these By-Laws. A majority of the Committee shall be necessary to constitute a
quorum for the transaction of business. Regular meetings of the Committee may be
held on such days, and at such time as may be determined by a majority vote of
its members. Additional meetings shall be held as the Chairman/Chairwoman of the
Committee, or any two (2) members thereof shall from time to time call. Except
as otherwise provided by law, the Committee shall have power to consider and
decide upon all questions concerning the management and the affairs of the
Company, including all proposed liabilities, expenditures and contracts,
together with such other business as may be submitted to it from time to time by
the officers of the Company between meetings of the Board of Directors, and such
business shall be finally disposed of by the Committee; provided, however, that
the Committee shall preserve minutes of its meetings, which shall be submitted
to the Board of Directors at its regular meetings; and provided that the
Committee shall have no power or authority to amend the Certificate of
Incorporation or By-Laws, to adopt an agreement of merger, exchange or
consolidation, to sell, lease, pledge or exchange all or substantially all of
the Company's assets, to adopt or revoke a plan of dissolution, or, unless the
Board expressly so provides by resolutions, to declare a dividend or issue
stock.
ARTICLE V
Meetings of Directors
Section 1. The Board of Directors shall at the next regular meeting
following the Annual Meeting of the stockholders, or at a special meeting called
for that purpose, elect and appoint officers to serve for the ensuing year, and
may transact such other business as may properly come before the meeting.
Section 2. All other regular meetings of the Board of Directors shall be
held at such time and place as shall be from time to time determined by
resolution of the Board of Directors. Notice shall not be required of any
regular meeting of the Board of Directors.
<PAGE>
Section 3. Special meetings of the Board of Directors may be held at any
place upon the call of the Chairman/Chairwoman of the Board or the President.
The Secretary shall also call such meetings on written request of two (2)
directors.
Section 4. Any meeting of the Board of Directors may be held outside of the
State of Delaware.
Section 5. A written or printed notice of all special meetings of the Board
of Directors, delivered personally or mailed or telegraphed on or before the
second day preceding the date of meeting, addressed to a director at his/her
usual place of residence or such other place as he/she may designate, shall be
sufficient notice of such meetings. No notice shall be required to any director
who shall be personally present at any meeting or who shall waive notice,
whether before or after the time stated therein. A meeting may be held at any
time when all of the Directors are present.
Section 6. A quorum of the Board competent to transact business shall
consist of the smallest number of directors necessary to constitute a majority
of the full Board. Less than a quorum may adjourn from time to time without
notice.
Section 7. All questions shall be decided by vote of a majority of the
Directors present, unless otherwise specifically provided by law or by these By-
Laws. The yeas and nays on any question shall be taken and recorded on the
minutes at the request of any Director.
ARTICLE VI
Chairman/Chairwoman of the Board
Section 1. The Chairman/Chairwoman of the Board shall, when present,
preside at all meetings of the Directors and of the stockholders. He/She shall
also generally have the power and perform the duties which by law and general
usage appertain to the office. He/She shall be the chief executive officer of
the Company and have charge of its business and affairs when so designated by
resolution of the Board of Directors.
ARTICLE VII
President
Section 1. The President shall be the chief operating officer of the
Company and shall direct the ordinary business operations of the Company. He/She
shall also be the chief executive officer of the Company and have charge of its
business and affairs unless the Board of Directors has by resolution designated
the Chairman/Chairwoman of the Board to be chief executive officer. He/She
shall, when present, in the absence of the Chairman/ Chairwoman of the Board,
preside at all meetings of the Directors and of the stockholders. He/She shall
affix the corporate seal of the Company to instruments required by law, these
By-Laws, or by resolution of the Board of Directors to have the seal affixed by
the President. He/She shall sign certificates of stock and obligations, and
shall execute contracts and other instruments in behalf of the corporation
except as otherwise provided for by the Board of Directors. The President shall
also generally have the powers and perform the duties which by law and general
usage appertain to the office. He/She shall employ, or delegate the power to
employ, such agents, managers and employees as may be
<PAGE>
necessary and the interest of the Company may require and shall fix, or delegate
the power to fix, the compensation and define, or delegate the power to define,
the duties of all such agents, managers and employees.
ARTICLE VIII
Vice President
Section 1. A Vice President shall in the absence or disability or at the
request of the President, perform the duties of the President, and perform such
other duties as shall, from time to time, be imposed upon him/her by the Board.
The performance of any such duty by a Vice President shall be conclusive
evidence of his/her right to act.
ARTICLE IX
Secretary
Section 1. The Secretary shall keep, in proper books provided for that
purpose, a record of all meetings and proceedings of the Board of Directors, and
also the minutes of the stockholders' meetings. He/She shall record all votes of
the corporation. He/She shall carefully preserve and keep in his custody in the
office of the Company all letters, contracts, leases, assignments, deeds and
other instruments in writing and documents not properly belonging to the office
of the Treasurer; shall attend to such correspondence of the Company as the
Board of Directors shall direct, and shall perform such other duties as he/she
may be charged with by the Board of Directors or by law or as by general usage
appertain to his/her office.
ARTICLE X
Assistant Secretaries
Section 1. An Assistant Secretary shall, in the absence or disability or at
the request of the Secretary, perform the duties of the Secretary, and perform
such other duties as shall, from time to time, be imposed upon him/her by the
Board. The performance of any such duty by an Assistant Secretary shall be
conclusive evidence of his/her right to act.
ARTICLE XI
Treasurer
Section 1. The Treasurer shall have charge of all receipts and
disbursements of the Company, and shall be the custodian of the Company's funds.
He/She shall have full authority to receive and give receipts for all money due
and payable to the Company from any source whatever, and to endorse checks,
drafts and warrants in its name and on its behalf, and to give full discharge
for the same. He/She shall sign all certificates of stock, checks, notes and
drafts, except as otherwise provided for by the Board of Directors. He/She shall
also affix the seal of the Company to all certificates of stock and other
instruments of writing required or directed by law, these By-Laws, or by
resolution of the Board of Directors to have the seal affixed by him/her. He/She
shall also perform such other duties as he/she may be charged with by the Board
or Directors or by law or as by general usage appertain to his/her office.
<PAGE>
Section 2. The Treasurer shall execute, if required by the Board, a bond in
the penalty fixed by the Board, with such surety as the Board may approve,
conditioned for the delivery to the President, or according to the order of the
Board, in case of his/her (Treasurer's) decease, resignation or discharge, of
all moneys, bonds, evidences of debt, vouchers, accounts, books, writings, and
papers belonging to the Company, received by him/her or in his/her possession,
charge or custody, and for the faithful performance of all duties of his/her
office.
ARTICLE XII
Assistant Treasurer
Section 1. An Assistant Treasurer shall, in the absence or disability or at
the request of the Treasurer, perform the duties of the Treasurer and perform
such other duties as shall, from time to time, be imposed upon him/her by the
Board. The performance of any such duty shall be conclusive evidence of his/her
right to act. He/She shall execute, if required by the Board, a bond in the same
manner as the Treasurer, as provided in Section 2, Article XI, of these By-Laws.
ARTICLE XIII
Comptroller
Section 1. The Comptroller shall be the chief accounting officer of the
Company. He/She shall cause to be kept full and accurate books and accounts of
all assets, liabilities and transactions of the Company. He/She shall develop
and establish systems and procedures to maintain internal controls, to report on
operations, and to provide financial statements. The Comptroller shall also
perform such other duties as he/she may be charged with by the Board of
Directors or by law or as by general usage appertain to his/her office.
ARTICLE XIV
Assistant Comptroller
Section 1. An Assistant Comptroller shall, in the absence or disability or
at the request of the Comptroller, perform the duties of the Comptroller and
perform such other duties as shall from time to time be imposed upon him/her by
the Board. The performance of any such duty shall be conclusive evidence of
his/her right to act.
ARTICLE XV
Corporate Seal
Section 1. The Company shall have a corporate seal, which shall be circular
in form, with the name of the Company on the circumference, and "Delaware" in
the center.
ARTICLE XVI
Certificates of Stock and Transfer Thereof
Section 1. Each stockholder of the Company shall be entitled to receive a
certificate of the number of shares standing to his, her or their credit on the
books of the Company, which certificate shall be signed by the President or a
Vice President or other officer designated by the Board of Directors,
countersigned by the Treasurer or an
<PAGE>
Assistant Treasurer and sealed with the common seal of the Company. The
signature, countersignature and seal, or any of them, required by this Section,
may be executed in facsimile, engraved or printed, if the certificate of stock
is countersigned by a transfer agent or registered by a registrar appointed by
the Board of Directors which shall not be the Company or an employee of the
Company. In case any such officer, who has signed or countersigned or whose
facsimile signature or countersignature has been placed upon such certificate,
shall have ceased to be such before such certificate is issued, it may be issued
by the Company with the same effect as if such officer had not ceased to be such
at the date of its issue. Said certificates shall be in such form as the Board
of Directors shall from time to time prescribe.
Section 2. The shares may be transferred on the books of the Company, by
the holder thereof in person or by duly authorized attorney, upon surrender of
the certificates properly endorsed.
Section 3. The Board of Directors shall have power to close the stock
transfer books of the Company for a period not exceeding sixty (60) days
preceding the date of any meeting of the stockholders or the date for payment of
any dividend or the date for the allotment of rights or the date when any change
or conversion or exchange of capital stock shall go into effect, or for a period
of not exceeding sixty (60) days in connection with obtaining the consent of
stockholders for any purpose; provided, however, that in lieu of closing the
stock transfer books as aforesaid, the Board of Directors may fix in advance a
date not exceeding sixty (60) days preceding the date of any meeting of
stockholders or the date for the payment of any dividend or the date for the
allotment of rights or the date when any change or conversion or exchange of
capital stock shall go into effect, or a date in connection with obtaining such
consent as a record date for the determination of the stockholders entitled to
notice of, and to vote at any such meeting and any adjournment thereof, or
entitled to receive payment of any such dividend, or to any such allotment of
rights, or to exercise the rights in respect of any such change, conversion or
exchange of capital stock, or to give such consent, and in such case only such
stockholders as shall be stockholders of record on the date so fixed shall be
entitled to such notice of, and to vote at, such meeting and any adjournment
thereof, or to receive payment of such dividend, or to receive such allotment of
rights, or to exercise such rights, or to give such consent, as the case may be,
notwithstanding any transfer of any stock on the books of the Company after any
such record date fixed as aforesaid.
Section 4. Where a certificate for capital stock of the Company has been
lost or destroyed, the proper officers of the Company may execute and issue a
new certificate therefor upon satisfactory proof of such loss or destruction and
upon giving of a bond, with or without surety, to protect the Company from any
liability or expense which it may incur by reason of the original certificate
remaining outstanding.
ARTICLE XVII
Indemnification and Advancement of Expenses
Section 1. With respect to any person made or threatened to be made a party
to any threatened, pending, or completed action, suit, or proceeding, whether
civil, criminal, administrative, or investigative (hereinafter and, whether
threatened, pending or completed, a "proceeding"), by reason of the fact that
such person is or was a director or
<PAGE>
officer of the Company, including service by such person at the request of the
Company as a director or officer of another corporation, partnership, joint
venture, trust, or other enterprise, the Company shall pay the expenses
(including attorneys' fees) incurred by such person in defending any such
proceeding in advance of its final disposition (hereinafter an "advancement of
expenses"); provided, however, that the payment of expenses (including
attorneys' fees) incurred by such person in advance of the final disposition of
such proceeding shall be made only upon receipt of (1) a written statement by
such person of his or her good faith belief that he or she has met the standards
of conduct that entitles him or her to indemnity and (2) an undertaking
(hereinafter an "undertaking") by such person to repay all amounts advanced if
it shall ultimately be determined by final judicial decision from which there is
no further right to appeal (hereinafter "final adjudication") that such person
is not entitled to be indemnified for such expenses under this Article XVII or
otherwise; and further provided that a determination is made that the facts then
known to those persons making the determination to advance expenses would not
preclude indemnification; and further provided that with respect to a proceeding
initiated against the Company by a director or officer of the Company (including
a director or officer of the Company serving at the request of the Company as a
director or officer of another corporation, partnership, joint venture, trust,
or other enterprise), such director or officer shall be entitled under this
Section to the payment of expenses (including attorneys' fees) incurred by such
person in defending any counterclaim, cross-claim, affirmative defense, or like
claim of the Company in connection with such proceeding in advance of the final
disposition of such proceeding only if such proceeding was authorized by the
Board of Directors of the Company.
Section 2. With respect to any person made or threatened to be made a party
to any proceeding by reason of the fact that such person is or was a director or
officer of the Company, including service by such person at the request of the
Company as a director or officer of another corporation, partnership, joint
venture, trust, or other enterprise, the right to indemnification and the
advancement of expenses conferred by the Company's Restated Certificate and
Articles of Incorporation and the right to the advancement of expenses conferred
by Section 1 of this Article XVII shall be contract rights. If a claim with
respect to such rights is not paid in full by the Company within sixty (60) days
after a written demand has been received by the Company, except in the case of a
claim for an advancement of expenses, in which case the applicable period shall
be twenty (20) days, the person seeking to enforce a right to indemnification or
an advancement of expenses hereunder may at any time thereafter bring suit
against the Company to recover the unpaid amount of the claim. If successful in
whole or in part in any such suit, or in a suit brought by the Company to
recover an advancement of expenses pursuant to the terms of an undertaking, the
person seeking to enforce a right to indemnification or an advancement of
expenses hereunder or the person from whom the Company seeks to recover an
advancement of expenses shall also be entitled to be paid the expenses
(including attorneys' fees) of prosecuting or defending such suit. In any suit
brought by a person seeking to enforce a right to indemnification hereunder (but
not in a suit brought by a person seeking to enforce a right to an advancement
of expenses hereunder) it shall be a defense that the person seeking to enforce
a right to indemnification has not met any applicable standard for
indemnification under applicable law. In any suit brought by the
<PAGE>
Company to recover an advancement of expenses pursuant to the terms of an
undertaking, the Company shall be entitled to recover such expenses upon a final
adjudication that the person from whom the Company seeks to recover an
advancement of expenses has not met any applicable standard for indemnification
under applicable law. With respect to any suit brought by a person seeking to
enforce a right to indemnification hereunder (including any suit seeking to
enforce a right to the advancement of expenses hereunder) or any suit brought by
the Company to recover an advancement of expenses pursuant to the terms of an
undertaking, neither the failure of the Company (including its directors,
independent legal counsel, or its stockholders) to have made a determination
prior to commencement of such suit that indemnification of such person is proper
in the circumstances because such person has met the applicable standards of
conduct under applicable law, nor an actual determination by the Company
(including its directors, met such independent legal counsel, or its
stockholders) that such person has not met applicable standards of conduct,
shall create a presumption that such person has not met the applicable standards
of conduct or, in a case brought by such person seeking to enforce a right to
indemnification, be a defense to such suit. In any suit brought by a person
seeking to enforce a right to indemnification or to an advancement of expenses
hereunder, or by the Company to recover an advancement of expenses pursuant to
the terms of an undertaking, the burden of proving that the person seeking to
enforce a right to indemnification or to an advancement of expenses or the
person from whom the Company seeks to recover an advancement of expenses is not
entitled to be indemnified, or to such an advancement of expenses, under this
Article XVII or otherwise shall be on the Company.
ARTICLE XVIII
Fiscal Year
Section 1. The fiscal year of this Company shall be the calendar year.
ARTICLE XIX
Amendments
Section 1. These By-Laws may be altered, added to or repealed at any annual
or special meeting of the stockholders or at any regular or special meeting of
the Board of Directors.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C>
Objectives of the Plan 1
I. Summary of the Plan 2
II. Eligibility 4
III. Establishment of Annual Unadjusted 5
Incentive Opportunity
IV. Operation of the Plan 5
V. Distribution of Awards 11
VI. Effective Date of the Plan 12
VII. Effect on Other Benefits 12
VIII. Company Successors 13
IX. Modifications to the Plan 13
X. Termination of the Plan 13
</TABLE>
<PAGE>
OBJECTIVES OF THE PLAN
. Improve financial and operational performance of the Company by focusing
executive attention on the earnings performance of the Company and the cost
of its product relative to other utilities.
. Stimulate individual performance.
. Provide compensation levels that allow the Company to attract, retain, and
motivate highly competent executives.
. Build teamwork by focusing on common corporate goals.
<PAGE>
I. SUMMARY OF THE PLAN
DEFINITIONS
-----------
Basic Incentive Opportunity is the unadjusted incentive award projected
---------------------------
for, and communicated to, each individual at the beginning of each
Performance Year. It is adjusted to reflect actual corporate and individual
performance results.
EPS/Rates Multiplier is used to adjust the Basic Incentive Opportunity to
--------------------
reflect corporate performance as measured by earnings per share (EPS) and
net change in rates over a three-year period. The maximum EPS/Rates
Multiplier is 1.50. The Base EPS/Rates Multiplier is 1.00.
Incentive Award is the actual amount of award of cash made to a
---------------
participant for any Performance Year. It is calculated by multiplying the
Individual Percentage Award by the participant's midpoint or salary, as
appropriate.
Incentive Structure is the table in Section IV that sets forth the minimum
-------------------
and maximum percentages for both the EPS/Rates Opportunity and the
Individual Evaluation Opportunity.
Individual Evaluation Opportunity is the range of percentage awards
---------------------------------
available to participants based on their individual performance and
leadership in the Performance Year. The range of Individual Evaluation
Opportunity is set forth in the Incentive Structure.
Percentage Award is multiplied by the participant's midpoint or salary, as
----------------
appropriate, to determine the individual Incentive Award. It is determined
by adding the EPS/Rates component to the Individual Evaluation component.
<PAGE>
Performance Year is the Calendar Year for which EPS, rates and individual
----------------
performance are evaluated and awards are made. The Compensation Committee
establishes the Basic Incentive Opportunity at the beginning of the
Performance Year and awards, if any, are made after the close of the
Performance Year based on activity in that year.
Plan Description
----------------
This Plan links individual compensation with Delmarva's success in meeting
certain financial goals on an annual basis. Awards under this Plan are
based on a combination of individual performance and the company's overall
performance on goals relating to earnings per share (EPS) and electric rate
levels.
Two key "triggers" activate awards under this Plan: actual EPS must be
greater than or equal to 95% of Delmarva's annual EPS goal AND at least
half of the Corporate Performance Incentive Plan (CPIP) goals must be met.
If BOTH of these triggers are met, awards may be made. If actual EPS is
less than 95% of the annual goal OR if half or more of the CPIP goals are
not met, no awards will be made. At the beginning of each Performance Year,
the Compensation Committee of the Board of Directors will establish a Basic
Incentive Opportunity for each Plan participant. This amount will be
expressed in dollars and calculated using the Incentive Structure and the
participant's midpoint or actual salary for that year.
After the close of that year, if both triggers are met, the Basic Incentive
Opportunity will be adjusted to determine individual Incentive Awards.
Adjustments will be based on the following factors:
<PAGE>
CORPORATE PERFORMANCE
. EPS Performance -- Actual EPS compared to the Company's annual EPS goal.
---------------
. Rates Performance -- The relative change in Delmarva's average electric
-----------------
rates/kwh compared to a peer group of investor-owned utilities, averaged
over a three-year period.
INDIVIDUAL PERFORMANCE
. Individual Performance - Individual contribution and leadership with
----------------------
particular focus on achieving department goals may increase the amount of a
participant's Incentive Award according to the Individual Evaluation
Opportunity in the Incentive Structure.
The adjustments calculated according to these factors will be combined to
determine the Percentage Award to be applied to each participant's midpoint or
salary, as appropriate, to determine the participant's actual Incentive Award.
All Incentive Awards are subject to approval by the Compensation Committee of
the Board of Directors and are payable in cash.
II. ELIGIBILITY
Employees in jobs core graded 18 or above are eligible for participation in
the Incentive Plan, including employees in the entry grade 17 to a job core
graded 18.
<PAGE>
III. ESTABLISHMENT OF ANNUAL UNADJUSTED INCENTIVE OPPORTUNITY
At the beginning of each Performance Year, the Compensation Committee of
the Board of Directors will establish the annual unadjusted incentive
opportunity, known as the Basic Incentive Opportunity, for each Plan
participant. This amount will be expressed in dollars and calculated using
the Incentive Structure and the participant's midpoint or actual salary for
that year. This is the amount of Incentive Award available to the
participant if the EPS and Rates triggers are both met, but no adjustments
are made for EPS, rates, or individual performance.
IV. OPERATION OF THE PLAN
Incentive Awards will be made under the Plan only if both of the following
two conditions or "triggers" are met for the Performance Year:
. Actual EPS must be greater than or equal to 95% of Delmarva's annual EPS
goal and
. At least half of the CPIP goals must be met.
If both of these conditions are met, this Plan will operate and awards will be
made as follows:
A. Incentive Structure
-------------------
The incentive opportunity for each participant is expressed as a percentage
of the midpoint of the participant's salary grade for graded jobs and as a
percentage of the participant's salary for ungraded jobs. The midpoint and
salaries used in determining awards are those for the Performance Year,
i.e., the year for which EPS, rates and individual performance are
evaluated for purposes of this Plan.
<PAGE>
The Basic Incentive Opportunity may be adjusted by three components for
each participant:
. EPS Adjustment
. Rates Adjustment
. Individual Evaluation Adjustment
As shown in the following table, the combined EPS/Rates Opportunity
component increases as a percentage of the Incentive Opportunity from grade
18 through grade 23 to reflect the relatively larger impact of increasing
job responsibility on earnings and rate performance. Conversely, the
Individual Evaluation Opportunity component represents the highest
percentage of the incentive opportunity at grade 18 and declines as a
percentage through grade 23. The relationship between the EPS/Rates
Opportunity and the Individual Evaluation Opportunity for senior management
will be established by the Compensation Committee in advance of each
Performance Year.
<TABLE>
<CAPTION>
Percentage of Maximum Incentive Opportunity
-------------------------------------------------------
Individual Evaluation
EPS/Rates Opportunity Opportunity
- - ----------------------------------------------------------------------------
Sr. Management Set annually by Set annually by
Compensation Committee Compensation Committee
- - ----------------------------------------------------------------------------
<S> <C> <C>
SGL 23 70% 30%
- - ----------------------------------------------------------------------------
SGL 22 60% 40%
- - ----------------------------------------------------------------------------
SGL 21 50% 50%
- - ----------------------------------------------------------------------------
SGL 20 40% 60%
- - ----------------------------------------------------------------------------
SGL 19 27% 73%
- - ----------------------------------------------------------------------------
SGL 18 14% 86%
- - ----------------------------------------------------------------------------
</TABLE>
<PAGE>
The Incentive Structure is set forth in the following table which shows the
minimum and maximum percentage for the EPS/Rates Opportunity and Individual
Evaluation Opportunity for each grade level. The Compensation Committee will
establish these percentages annually for senior management.
INCENTIVE STRUCTURE
<TABLE>
<CAPTION>
- - -----------------------------------------------------------------------------------------------------------------------------------
Individual Evaluation
Tiers EPS/Rates Opportunity Opportunity Range of Opportunity**
- - -----------------------------------------------------------------------------------------------------------------------------------
Unadjusted Adjusted* Minimum Maximum Minimum Maximum
- - -----------------------------------------------------------------------------------------------------------------------------------
Senior
Management Set annually by Compensation Committee
- - -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
SGL 23 12% 18% 0% 8% 12% 26%
- - -----------------------------------------------------------------------------------------------------------------------------------
SGL 22 10% 15% 0% 10% 10% 25%
- - -----------------------------------------------------------------------------------------------------------------------------------
SGL 21 8% 12% 0% 12% 8% 24%
- - -----------------------------------------------------------------------------------------------------------------------------------
SGL 20 6% 9% 0% 14% 6% 23%
- - -----------------------------------------------------------------------------------------------------------------------------------
SGL 19 4% 6% 0% 16% 4% 22%
- - -----------------------------------------------------------------------------------------------------------------------------------
SGL 18 2% 3% 0% 18% 2% 21%
- - -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* Maximum EPS/Rates Multiplier = 1.50; "Adjusted" is 1.50 times
"Unadjusted".
** Assuming EPS and Rates triggers are met.
The Base EPS/Rates Multiplier is 1.00 and may be adjusted as described
in paragraphs B and C. The maximum EPS/Rates Multiplier is 1.50.
B. Earnings Per Share Adjustment
-----------------------------
For each 1% positive deviation of actual EPS from the EPS goal of 100%, the
EPS/Rates Multiplier (1.00) will be increased by 5%. For each 1% negative
deviation of actual EPS from EPS goal of 100%, the EPS/Rates Multiplier
(1.00) will be decreased by 20%.
C. Electric Rates Adjustment
-------------------------
<PAGE>
The EPS/Rates Multiplier will further be adjusted, upward or downward,
based upon the relative change in Delmarva's average rates/kwh as compared
to a survey group of other investor-owned utilities used by the Company for
a broad range of financial and operating comparisons.
A positive adjustment will be made when the three-year average rate of
change in Delmarva's price per kwh increases less or decreases more than
the three-year average rate of change for the survey companies. For each
1% positive deviation in Delmarva's electric rate trend compared to the
survey companies, the EPS/Rates Multiplier will be adjusted upward by 5%.
A negative adjustment will be made when the three-year average rate of
change in Delmarva's price per kwh increases more or decreases less than
the three-year average rate of change for the survey companies. For each
1% negative deviation in Delmarva's electric rate trend, the EPS/Rates
Multiplier will be adjusted downward by 2%. The following example
illustrates the Rates adjustment:
<TABLE>
<CAPTION>
================================================================
c/kwh Annual c/kwh Annual Change
Year Survey Change % DP&L %
- - ----------------------------------------------------------------
<S> <C> <C> <C> <C>
1 7.1 6.7
- - ----------------------------------------------------------------
2 7.6 7.0 6.9 3.0
- - ----------------------------------------------------------------
3 7.5 -1.3 7.0 1.4
- - ----------------------------------------------------------------
4 7.5 0.0 6.5 -7.1
- - ----------------------------------------------------------------
Net Change: up 5.7% down - 2.7%
================================================================
</TABLE>
Three-Year Average Change in c/kwh:
. Survey: 5.7% divided by 3 years = 1.9%
<PAGE>
. Delmarva: -2.7% divided by 3 years = -.9%
1.9% Survey
-(.9%) Delmarva
-----
2.8%
x 5.0%
----
14.0%
Under this example, the EPS/Rates Multiplier would be adjusted to 1.14 for
Year 4 to reflect Delmarva's success in managing its rates relative to
those of the survey companies.
D. Combined EPS and Rates Adjustments
----------------------------------
The EPS and Rates adjustments determined under paragraphs B and C are
combined to determine the EPS/Rates Multiplier. This is then multiplied by
the Basic Incentive Opportunity for each tier in the Incentive Opportunity
Structure to determine the EPS/Rates component of the Percentage Awards.
The maximum combined EPS/Rates Multiplier is 1.50. This means that the
maximum adjusted EPS/Rates Opportunity is 150% of the Basic Incentive
Opportunity.
E. Individual Evaluation Adjustment
--------------------------------
1. Eligibility
-----------
Participants will have a January 1 merit review date and must be
evaluated as at least "meeting expectations" under the Performance
Management System to qualify for an award. Each participant's Basic
Incentive Opportunity may be increased based on the evaluation of
individual and departmental performance in the Performance Year, with
a particular emphasis on achievement of goals. The individual
performance adjustment cannot exceed the maximum Individual Evaluation
Opportunity set forth in the Incentive Opportunity Structure for the
participant's grade.
<PAGE>
2. Performance Indicators
----------------------
The individual performance evaluation will focus on departmental
performance including, but not limited to, the following performance
indicators as appropriate:
a. Safety
b. Cost
c. PSP - Team Effectiveness
d. Customers
e. Manpower
f. Planning
g. Departmental Goals
3. Application of the Evaluation Adjustment
----------------------------------------
Individual performance must be evaluated by each participant's
immediate supervisor and reviewed by senior management before any
evaluation adjustment can be made. The evaluation adjustment for the
Chairman of the Board and Chief Executive Officer will be determined
by the Compensation Committee of the Board of Directors. Any
adjustment for senior management members will be determined by the
Chairman of the Board and Chief Executive Officer. All awards under
this Plan are subject to approval by the Compensation Committee of the
Board of Directors. An Evaluation adjustments will reflect the overall
assessment of each participant's total contribution using the
following performance standards: (1) quality; (2) quantity; (3) cost;
(4) time; and (5) manners of performance.
F. Total EPS/Rates and Evaluation Adjustment
-----------------------------------------
<PAGE>
The EPS/Rates Adjustment determined under paragraphs B and C will be
added to the Individual Evaluation Adjustment determined under
paragraph E to make the annual Percentage Award, which is then
multiplied by grade midpoint or salary, whichever is appropriate, to
determine the actual Incentive Award for each participant.
V. VESTING AND DISTRIBUTION OF AWARDS
A. Form of Distribution
--------------------
Incentive Awards will be paid in an annual lump sum in cash after the
closing of the Performance Year.
B. Retirement, Death or Disability, or Termination
-----------------------------------------------
Upon retirement, death or disability, or upon termination of
employment for any reason, all Incentive Awards earned but not
distributed shall be payable immediately to the employee or his/her
designated beneficiary. This payment will be made in one lump sum as
soon as possible.
C. Vesting of Incentive Awards
---------------------------
Subject to all other provisions of this Plan, Incentive Awards vest
on the last calendar day of the Performance Year, and employees must
be employed as of that date, except that in the event of retirement,
death or disability, vesting occurs on the employee's last day of
employment prior to such event.
D. Administration of Distribution to New Eligibles During a Plan Year
------------------------------------------------------------------
Any employee promoted or hired into a job in core grade 18 or above
during the first six months of a Performance Year will be eligible for
pro rata participation in this Plan for that year. Employees promoted
or hired into
<PAGE>
a job in core grade 18 or above during the last six months of a
Performance Year will become eligible for Plan participation as of
January 1 of the following year.
VI. EFFECTIVE DATE OF THE PLAN
The Incentive Plan was effective on January 1, 1982 with the first awards
distributed the first quarter of 1983 for the 1982 Performance Year.
VII. EFFECT ON OTHER BENEFITS
The benefits awarded under this Plan, with the exception of partial year
awards for the year of retirement, will accrue towards total wages in the
calculation of retirement benefits. However, no other wage-sensitive
benefit will be affected by any income generated by the Incentive Plan.
Only the participant's base salary will be used in the calculation of all
other benefits.
VIII. COMPANY SUCCESSORS
In the event the Company becomes a party to a merger, consolidation, sale
of substantially all of its assets or any other corporate reorganization
in which the Company will not be the surviving corporation or in which the
holders of Company stock will receive securities of another corporation,
the Company, prior to such merger, consolidation, sale of assets or
reorganization, shall make payment of all Incentive Awards earned but not
distributed. In the event that a change in ownership of the Company
through the purchase by an individual or group of individuals acting in
concert of at least 25% of the voting securities of the Company takes
place, all Incentive Awards earned but not distributed will be immediately
paid.
IX. MODIFICATIONS TO THE PLAN
<PAGE>
The operation of this Plan may be modified by the Compensation Committee
of the Board of Directors to accommodate extraordinary or extenuating
circumstances.
X. TERMINATION OF THE PLAN
The Plan may be terminated by the Company without notice or cause at any
time. The existence of the Plan does not constitute or evidence a
guarantee of current or future awards nor does it represent an employment
or any other kind of contract between the Company and any employee.
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
Page
<S> <C> <C>
Objectives of the Plan 1
I. Plan Components 2
II. Common Stock Options Program 2
III. Dividend Rights Program 3
IV. Performance-Based Restricted Stock Program 4
V. Specific Guidelines 7
VI. Eligibility 8
VII. Issuance 8
VIII. Company Successors 9
</TABLE>
2
<PAGE>
OBJECTIVES OF THE PLAN
. Improve financial and operational performance of the Company by focusing
executive attention on the long run total return to stockholders, including
competitive growth in market price and dividend yield.
. Align executive interest with stockholder interest in a balanced fashion
with predominant focus on long-term stock price appreciation and a strong
secondary focus on dividend security and growth and executive stock
ownership.
. Stimulate individual performance within the context of a team effort.
. Provide compensation levels that allow the Company to attract, retain, and
motivate highly competent executives.
1
<PAGE>
I. PLAN COMPONENTS
The Compensation Committee of the Board of Directors has the authority to
designate appropriate programs to carry out the objectives of the Long-Term
Incentive Plan. The Committee has broad authority to choose any
combination of stock options, stock appreciation rights, restricted stock,
performance units, performance shares, or other long-term programs to meet
these objectives.
Effective January 1, 1993, for the 1993 Plan Year and for awards and grants
made under the Long-Term Incentive Plan (the "Plan") thereafter, the
Compensation Committee has determined that given current tax laws and other
economic considerations, the Performance-Based Restricted Common Stock
Grants program is the appropriate program to be authorized under the Plan.
No amendment to the Plan shall be deemed to affect any award already
granted under the Plan for prior Plan Years.
II. COMMON STOCK OPTIONS PROGRAMS
This Program consists of Non-Qualified Stock Options encompassing the
following characteristics:
. Granted at fair market value on date of grant.
. Gain is solely a function of stock price increases above the initial
grant price.
. After a one-year holding period, 100% of the options are vested.
. Options are exercisable over a 10-year term or age 70, whichever is
earlier.
2
<PAGE>
. At termination other than through retirement, death or disability,
options that have been held less than one year are forfeited; options
that have been held for more than one year are "exercisable" but may
be exercised only for a period of three months from termination.
. Stock for stock swaps are permitted.
. For 1992, options to purchase shares of the Company's Common Stock
were granted at a level to produce 20% of the targeted competitive
gain. Effective January 1, 1993, no new options will be granted under
the Plan.
. Employees who retire within the calendar year when an option might be
granted may have their options prorated based on remaining active
employment, except as the Compensation Committee may otherwise decide.
III. DIVIDEND RIGHTS PROGRAM
The Dividend Rights Program consists of a Dividend Rights Account for each
participant encompassing the following characteristics:
. Dividends accrue to rights in an assigned account,
. Fixed date for payout is five years after date of grant.
. For 1992, Dividend Rights were granted at a level to produce 40% of
the targeted competitive gain. Effective January 1, 1993, no new
grants of Dividend Rights will be made under the Plan.
. Dividend Rights accounts do not accrue interest.
. Account balance is forfeited if participant's employment terminates
other than through retirement, death or disability before the date of
payout unless waived by the Compensation Committee. Payout is made at
time of retirement, death or disability.
3
<PAGE>
. Dividend Rights account balances payable prior to 1997 will be paid in
cash. Effective January 1, 1992, for the 1992 Plan Year and for
Dividend Rights granted thereafter (which Dividend Rights are payable
beginning in 1997), Dividend Rights account balances will be paid as
described herein. Subject to adjustment for fractional shares of
Common Stock, 75% of each Dividend Rights account balance due will be
paid to the participant in cash. 25% of cash Dividend Rights account
balance due will be paid to the participant in shares of the Company's
Common Stock, using, at the Company's option, either newly-issued or
open-market shares (or a combination thereof). The market value of
such shares of Common Stock will be determined at the close of trading
on the New York Stock Exchange on the first business day in February
following the date on which the Dividend Rights account balance
becomes payable. If the portion of a Dividend Rights account balance
to be paid in shares of the Company's Common Stock includes fractional
shares, the value of such fractional shares will be paid as part of
the cash payment made to the participant.
IV. PERFORMANCE-BASED RESTRICTED STOCK PROGRAM
The Performance-Based Restricted Stock Program will consist of conditional
grants, subject to forfeiture, of performance-based restricted shares of
the Company's Common Stock, using openmarket shares, encompassing the
following characteristics:
. Vesting of final awards of performance-based restricted common stock
shall occur, if at all, at the end of a four-year restriction period.
. The participant's ability to transfer or otherwise alienate or assign
performance-based restricted shares of the Company's Common Stock
4
<PAGE>
conditionally granted to him or her (as well as the ability to
transfer the right to vote or direct the voting of those shares and
receive dividend-related compensation) is restricted for a period of
four years.
. The number of shares conditionally granted to a participant are
subject to forfeiture or increase, depending on how the total return
for Delmarva shareholders compares to a peer group of electric
utilities at the end of the four-year restriction period, as follows:
<TABLE>
<CAPTION>
====================================================
Delmarva's Total
Shareholder Return Percent of Conditional
Percentile Grant Earned
(4-year cumulative)* (no interpolation)
----------------------------------------------------
<S> <C>
90% to 100% 150%
----------------------------------------------------
75% to 89.9% 130%
----------------------------------------------------
60% to 74.9% 115%
----------------------------------------------------
50% to 59.9% 100%
----------------------------------------------------
40% to 49.9% 50%
----------------------------------------------------
35% to 39.9% 25%
----------------------------------------------------
less than 35% 0%
====================================================
</TABLE>
*This column represents Delmarva's actual percentile ranking based on
the peer group comparison at the end of the four-year restriction
period. There is no interpolation between steps.
. The participant receives compensation measured by dividends and may
vote or direct the voting of performance-based restricted shares of
Common Stock during the four-year restriction period. No portion of
such compensation paid to the participant during the restriction
period will be forfeited if the performance criterion is not met. No
additional dividends will be paid, however, to the participant for
prior periods if shares of Common Stock actually earned by and vested
in the participant at the end of the four-year
5
<PAGE>
restriction period exceed the number of performance-based restricted
shares initially granted to the participant.
. For 1992, awards of performance-based restricted shares of Common
Stock were granted at a level to produce 40% of the potential gain.
Effective January 1, 1993, awards of performance-based restricted
shares of Common Stock are granted at a level to produce 100% of the
targeted competitive gain.
. Conditional grants of performance-based restricted shares of Common
Stock are forfeited in the event of termination, other than for
reasons of retirement, death, or disability, unless the forfeiture is
waived by the Compensation Committee.
. Restrictions on shares of Common Stock conditionally granted to
participants who then become retired or disabled will lapse at the end
of the four-year restriction period. The participant's shares will be
subject to forfeiture or increase at that time, on a pro rata basis,
depending on the total return for Delmarva's shareholders over the
four-year restriction period.
. In the event of a participant's death (including his or her death
while retired or disabled), restrictions on his or her performance-
based restricted shares of Common Stock will lapse, on a pro rata
basis, immediately, without regard to whether the performance
criterion is met at the end of the four-year restriction period.
. For purposes of this program, "pro rata" means the difference between
the time a grant is made and the date of retirement, disability, or
death as that period relates to the four-year restriction period.
6
<PAGE>
V. SPECIFIC GUIDELINES
Regardless of programs selected by the Compensation Committee, the
following guidelines apply.
The overall potential gains from the Plan are intended to be sufficient,
when combined with other forms of compensation, to attract and retain
highly competent executives and to motivate high levels of performance from
individuals with the knowledge, skills and abilities to build long-run
total return for shareholders, consistent with the Company's customer
objectives for reliable energy supply at competitive prices. The Company
will analyze surveys of long-term incentive plans to determine recommended
target and grant levels. Annually, the Compensation Committee will approve
target and grant levels designed to accomplish this objective.
The Compensation Committee will exercise its discretion to increase or
decrease general grant levels depending upon its evaluation of management
performance and its desire to provide additional individual incentive for
future performance.
However, it is assumed that in order to receive any grant, the eligible
executive must be performing at a competent level. Recommended adjustments
for the Chairman and Chief Executive Officer will be made by the Chairman
of the Compensation Committee.
VI. ELIGIBILITY
7
<PAGE>
Employees in jobs core graded at salary grade level 19 and above are
eligible for participation in the Long-Term Incentive Plan including
employees in the entry grade 18 to a job core graded 19.
VII. ISSUANCE
Grants under the Long-Term Incentive Plan will be considered on a yearly
basis subject to recommendation of senior management and approval of the
Compensation Committee of the Board of Directors. At its discretion, the
Compensation Committee may discontinue issuance of grants as it deems
appropriate and may alter the Plan pursuant to authority granted by the
stockholders.
Upon recommendation by senior management, the Compensation Committee may
also award grants for newly promoted or hired employees at any time.
Appropriate grant instruments will be issued to participants for their
review and execution.
VIII. COMPANY SUCCESSORS
In the event the Company becomes a party to a merger, consolidation, sale
of substantially all of its assets, or any other corporate reorganization
in which the Company will not be the surviving corporation or in which the
holders of Company stock will receive securities of another corporation,
the Company, prior to such merger, consolidation, sale of assets or
reorganization, shall make payment of all dividends in the Dividend Rights
Accounts or at the participants' option the ongoing obligation to make such
payments shall be assumed by the surviving corporation. In
8
<PAGE>
the event that the change in ownership of the Company through the purchase
by an individual or group of individuals acting in concert of at least 25%
of the voting securities of the Company takes place, all dividends in the
Dividend Rights Account will be immediately paid or, at the employees
option, the ongoing obligation to make such payments will continue.
All rights with respect to options granted and vested will likewise remain
exercisable for their ten-year lives in the event of reorganizations or
changes in ownership as outlined in this Section.
Likewise, in the event of reorganizations or changes in ownership as
outlined in this Section, all restrictions on performance-based restricted
shares of Common Stock will lapse immediately, without regard to
performance criterion then or at the end of any four-year Performance
Period, and shares of Common Stock free of any restrictive legend shall be
issued to the participant or his legal representative.
9
<PAGE>
LONG TERM INCENTIVE PLAN
AMENDMENTS TO PAYOUT SCHEDULE AND METHODOLOGY FOR
CALCULATING TOTAL SHAREHOLDER RETURN AND
TO CLARIFY RELATIONSHIP TO STOCKHOLDER PLAN
Management recommends the following changes in the Long Term Incentive Plan
effective January 1, 1997:
1. Changes to Payout Schedule. To provide for payout opportunities that
--------------------------
more closely match actual performance, to require higher performance to support
final payout at grant level and to offset industry experience that high Total
Shareholder Return performance at the end of a cycle generally results from poor
performance at the beginning of the cycle, three changes in the current Payout
Schedule are recommended: a) the "step-rate" payout table currently in the plan
be replaced with a "continuous" payout curve as shown on the attached, b) Total
Shareholder Return performance to achieve payout at 100% of grant level be
increased from 50th to 55th percentile of the peer group, c) the initial
threshold has been raised from 35th to 40th percentile, and d) performance to
achieve payout at 150% of grant level be decreased from 90th to 85th percentile
of the peer group.
2. Change in Treatment of Dividends for Total Shareholder Return
-------------------------------------------------------------
Calculation. To reflect delivery of shareholder value through the Company's
- - -----------
relatively high dividend payout ratio over the full term of the four-year
performance cycle, calculation of Total Shareholder Return at the end of each
cycle be done as if dividends paid during the cycle were reinvested.
3. Resolving Conflicts between Operational Plan and Stockholder-Approved
---------------------------------------------------------------------
Plan. A paragraph be added which specifies that the Plan, as it is in effect at
- - ----
any time, is the operational document under the omnibus Delmarva Power & Light
Company Long-Term Incentive Plan attached as Exhibit A to the Company's 1996
Proxy Statement and approved by the stockholders at the 1996 Annual Meeting; and
that if there any conflicts in the terms of the operational document and the
omnibus Plan approved by the stockholders, the Operational Plan will govern.
Suggested Resolutions:
- - ---------------------
RESOLVED, That the LTIP document be amended by deleting the chart (and
text below the chart) in Section IV, third item and substituting in its
place the attached Payout Schedule and text;
FURTHER RESOLVED, That the calculation of Total Shareholder Return for
the 1997 and any future cycles be done as if dividends paid during the
cycle were reinvested;
<PAGE>
FURTHER RESOLVED, That the LTIP document be amended by adding a new Section
IX as follows:
IX. OPERATIONAL DOCUMENT
This Long-Term Incentive Plan is effective as of the effective
date set forth on the cover page hereof, until further amended by
the Board of Directors or the Compensation Committee. This Long-
Term Incentive Plan is the operational document setting forth the
specific plan design determined by the Compensation Committee,
under the Delmarva Power & Light Company Long-Term Incentive Plan
attached as Exhibit A to the Company's Proxy Statement dated
April 26, 1996, and approved by the stockholders at the Annual
Meeting held on May 30, 1996 (the "Omnibus Plan"). In the event
of any conflict between the terms of this operational document
and the Omnibus Plan, this operational document shall govern and
any such term shall operate as an amendment to the Omnibus Plan
made by the Compensation Committee pursuant to authority granted
to it under Section 19 of the Omnibus Plan, and/or an
interpretation of the Omnibus Plan made by the Compensation
Committee pursuant to authority granted to it under Section 3 of
the Omnibus Plan.
Attachment: new Payout Schedule
<PAGE>
LONG TERM INCENTIVE PLAN
(ATTACHED PAGE - SECTION IV, THIRD ITEM)
A graph titled "Payout Chart" is displayed here on the attachment to the
Amendment to the Long Term Incentive Plan. The y-axis shows the percentage of
shares earned, beginning at zero, increasing by increments of 20%, and ending at
160%. The x-axis shows the percentile ranking of the Company compared to its
peers, beginning at zero, and ending at 100. The graphed data are as follows:
<TABLE>
<CAPTION>
Percentile Ranking Among Peers % Shares Earned
------------------------------ ---------------
<S> <C>
85% or more 150%
55% 100%
40% 25%
Less than 40% 0%
</TABLE>
<TABLE>
<CAPTION>
Delmarva's Total Shareholder Percent of conditional Grant
Return Percentile Earned
(4-Year cumulative)* (With interpolation between steps)
- - --------------------------------------------------------------------
<S> <C>
85% or more 150%
- - --------------------------------------------------------------------
55% 100%
- - --------------------------------------------------------------------
40% 25%
- - --------------------------------------------------------------------
Less than 40% 0%
- - --------------------------------------------------------------------
</TABLE>
* This column represents Delmarva's actual percentile ranking based on the peer
group comparison at the end of the four-year restriction period. Interpolation
is performed between steps with the exception of a percentile less than 40% for
which none of the grant is earned.
<PAGE>
PROPOSED RESOLUTIONS OF THE
DELMARVA POWER & LIGHT COMPANY
COMPENSATION COMMITTEE OF THE
BOARD OF DIRECTORS
January 30, 1997
1997 LONG-TERM INCENTIVE PLAN GRANTS
Management recommends that the 1997 grants of Performance-Based Restricted
Stock contain a special condition which prevents the shares from vesting upon
the consummation of the proposed merger with Atlantic Energy, Inc. These
special conditions will operate as a one-time amendment to the Long-Term
Incentive Plan specifically for these awards and are intended to provide an
incentive to Company management in the transition period before the merger, and
after the merger during the period that Conectiv is beginning its operations.
Suggested Resolution:
- - --------------------
RESOLVED, That the awards of Performance-Based Restricted Stock
granted to participants under the Company's Long-Term Incentive Plan (the
"Plan") as set forth in the charts attached hereto (the "1997 Awards") be,
and they hereby are, granted subject to the following condition (which is
intended as an amendment to Section VIII--"Company Successors" of the
operational Long-Term Incentive for the purposes of only the 1997 Awards):
The consummation of the proposed merger and related transactions between
the Company and Atlantic Energy, Inc. (the "Merger") shall not constitute a
merger, consolidation, sale of assets or reorganization under Section VIII
of the Plan which causes the restrictions to lapse on such shares as
contemplated in Section VIII of the Plan. Instead, after the Merger is
consummated (the "Closing"), the 1997 Awards either (a) will continue to be
held in the Plan (but in the form of Conectiv's Common Stock rather than
the Company's Common Stock) until the performance period for the 1997
Awards expires and the 1997 Awards vest or are forfeited in part or in
whole, in which case, the Plan will continue in effect until the
performance period for the 1997 Awards has expired, or (b) Conectiv will
honor the outstanding 1997 Awards and the terms and conditions of the 1997
Awards otherwise will remain the same, in which case, the Plan will be
terminated by the Company as soon as practicable after the Closing; and, in
each case, if the performance cycle with respect to the 1997 Awards extends
beyond the effective date of the Closing, the performance criteria will be
modified to take into consideration the performance of Conectiv for the
period after the Closing, as well as the performance of the Company prior
to the Closing.
<PAGE>
DELMARVA POWER & LIGHT COMPANY
1996 FORM 10-K
CURRENT LISTING OF SEVERANCE AGREEMENTS
AS OF MARCH 1, 1997
-------------------
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------------------------
DATE OF
NAME CURRENT TITLE AGREEMENT
- - --------------------------------------------------------------------------------------------------------------
<S> <C> <C>
1. Arturo F. Agra General Manager, Product Management & Development 03/01/95
2. Heinz J. Beck Manager, Transmission & Distribution 05/07/93
3. W. Douglas Boyce Vice President, Central Division 05/07/93
4. Roberta S. Brown General Manager, Operations 01/23/96
5. Donald E. Cain Vice President 05/22/89
6. Raymond V. Civatte General Manager, Information Systems 01/23/96
7. Peter F. Clark Counsel, Assistant General 05/11/89
8. Donald P. Connelly Secretary, Corporate 02/11/87
9. Howard E. Cosgrove Chairman, President & Chief Executive Officer 05/07/93
10. Moira K. Donoghue Manager, Compensation, Benefits & Organizational Development 11/04/94
11. David G. Dougher Manager, Reports and Compliance 09/14/95
12. Joseph W. Ford Senior Vice President 09/14/95
13. Carmine F. Gargiulo Manager, Systems Development 02/11/87
14. Charles R. Gates Plant Manager (Indian River) 02/11/87
15. Paul S. Gerritsen Vice President 05/07/93
16. Barbara S. Graham Sr. Vice President, Treasurer & Chief Financial Officer 03/01/95
17. R. Erik Hansen General Manager, Regulatory Practice 05/07/93
18. Michael J. Harrison Manager, Delmarva Operating Services 03/01/95
19. Hudson P. Hoen, III Vice President, Southern Division 04/09/94
20. Albert F. Kirby General Manager, Mechanical Engineering & Standards 03/04/90
21. Ralph E. Klesius Sr. Vice President 05/07/93
22. John V. Kutys Plant Manager, Edgemoor 08/07/96
23. John W. Land General Manager, Administrative Services 04/19/94
24. James P. Lavin Comptroller/Corporate Accounting 05/22/89
25. Wayne A. Lyons Vice President 02/11/87
26. D. Bruce McClenathan Plant Manager (Delaware City) 02/11/87
27. Dennis R. McDowell Comptroller/Operating Accounting 05/22/89
28. Robert F. Molzahn General Manager, Environmental Affairs 05/22/89
29. James L. Parks Manager, Fuel Supply 05/07/93
30. Frank J. Perry, Jr. Vice President 03/14/90
31. Linda D. Ratchford Manager, Product Development 01/23/96
32. Michael Ratchford General Manager, Communication and Community Relations 09/14/95
33. Philip S. Reese General Manager, Marketing 03/01/95
34. Richard W. Sarau Plant Manager (Hay Road) 03/01/95
35. Thomas S. Shaw Sr. Vice President/President, DCI 05/07/93
36. James R. Silvius Manager, Electrical Engineering 05/11/89
37. William H. Spence Manager, Gas Operations & Planning 05/07/93
38. Richard J. Squadron Manager/General Manager, CFO - DCI 04/12/94
39. Dale G. Stoodley Vice President & General Counsel 04/18/89
40. Duane C. Taylor Vice President, Electric 01/23/96
41. Jack Urban Vice President, Gas Division 01/27/91
42. George G. Vapaa Manager, Corporate Planning 03/25/91
43. David M. Velazquez Manager, Strategic Planning 03/01/97
44. Joseph M. Wathen Manager, Pricing 04/08/94
45. N. Guy Winebrenner Manager, Sales 01/23/96
46. James R. Wittine General Manager, System Planning 05/07/93
47. Jeremiah F. Wright, Jr. General Manager, Purchasing 03/14/90
48. D. Wayne Yerkes Vice President, Northern Division 03/14/90
49. John T. Zimmerman Manager, Employee Relations 03/25/91
- - --------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C> <C>
I. Plan Benefits 1
II. Eligibility and Enrollment 1
III. Cost of the Plan 2
IV. Options at Retirement 2
V. Cost Recovery by Delmarva 2
VI. Change in Coverage 3
VII. Insurability 3
VIII. Termination 3
IX. Statement 3
X. Disability 4
XI. Change in Ownership 4
</TABLE>
<PAGE>
I. PLAN BENEFITS
Delmarva Power & Light Company, hereinafter referred to as Delmarva,
provides all eligible executives an amount of life insurance equal to a
minimum of three times their annual salary. This coverage may be provided
in two alternative programs. The first option is coverage under the
Employee Group Life Insurance Plan, capped at $202,500 of coverage. The
second option includes $50,000 of coverage under the Group Life Insurance
Plan, and the balance under this Management Life Insurance Plan, hereafter
referred to as the Plan. The Plan coverage will be issued under individual
policies by the New England Mutual Life Insurance Company. Servicing
representative of the Plan is Rockwell Associates of Wilmington, Delaware.
II. ELIGIBILITY AND ENROLLMENT
Employees in jobs core graded 19 and above are eligible for participation
in this Plan, including employees in the entry grade 18 to a job core
graded 19. Eligible employees may elect to continue their coverage under
the Group Life Insurance Plan unchanged or may elect to participate under
this Plan. If the employee elects this Plan, the employee will be enrolled
immediately and coverage in the Plan will be effective the first day of the
first full month following enrollment. At this time the employee will
become a participant of the Plan and group life insurance coverage will be
reduced to $50,000. The participant will then complete an application
provided by the Compensation & Benefits Department at Delmarva, which will
then be submitted to New England Life. All other necessary forms will be
completed and signed at this time. The participant will personally own the
management life insurance
<PAGE>
policy, but will collaterally assign it to Delmarva for cost recovery
purposes. As a participant's salary increases, additional insurance may be
purchased according to the benefit schedule. The same application procedure
will apply.
As a participant nears retirement, an increase in benefits may adversely
affect cash values already in force. As a result, the participant has the
right to review and reject the additional coverage.
III. COST OF THE PLAN
The cost of the Plan is paid for by Delmarva and the employee. Each
participant will pay the preferred term rate per $1,000 of life insurance
----
coverage. The balance of the premium will be paid by Delmarva.
IV. OPTIONS AT RETIREMENT
At retirement each participant will have the option of electing a
combination of (1) a reduced paid-up policy (minimum $20,000 coverage) with
an annual cash dividend, (2) a lump sum of cash, or (3) maintaining a life
insurance policy at coverage greater than the paid-up value by assuming the
premium payments.
V. COST RECOVERY BY DELMARVA
Should the employee die before retirement, Delmarva's cost is recovered
through the death benefit generated by the Plan, which will always be
sufficient to recover total premiums paid by Delmarva and provide the
benefits illustrated to the participant in the benefit schedule.
<PAGE>
At the participant's retirement, Delmarva will recover its cost (total
premiums paid) out of policy cash values and the balance will be used to
support those options listed under Section IV entitled, "Options at
Retirement."
VI. CHANGE IN COVERAGE
Participants whose salaries increase are eligible to apply for a new
policy to reach the benefit amount as shown on the attached schedule.
Procedures for additional benefits are the same as the original enrollment
procedures. Any such increase will be effective January 1 of each year. If
a participant moves into a job core graded below 19, regardless of salary
amount, the participant is not eligible for the Plan.
VII. INSURABILITY
Delmarva's executive physical is used for medical evidence of insurability
-- smokers will be considered a "standard" medical risk. Additional
evidence of insurability may be required.
VIII. TERMINATION
Other than death, disability, or retirement, the participant forfeits all
benefits of the Plan.
IX. STATEMENT
An Annual Statement will be provided to each participant showing total
life insurance benefits under the Plan.
<PAGE>
X. DISABILITY
In the event a participant becomes disabled, the group life insurance
benefit is reduced according to its schedule, and the existing amount of
insurance under the Management Life Insurance Plan remains in effect until
normal retirement age is reached.
XI. CHANGE IN OWNERSHIP OR ORGANIZATION
In the event that Delmarva becomes a party to a merger, consolidation, sale
of substantially all of its assets, or other corporate reorganization in
which the Company will not be a surviving corporation, or in which the
holders of the stock will receive securities of another corporation (in any
such case, the "New Company"), then the New Company shall assume the rights
and obligations of the Company under this Plan and further will immediately
prepay all premiums to any life insurance contract in force, the proceeds
of which are intended to fund the annuity obligations under this Plan.
<PAGE>
PLAN DESCRIPTION
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C> <C>
Plan Description
Management Life Insurance Benefits 1
Management Life Insurance Plan 3
-- When Coverage Becomes Effective 3
-- How the Plan Is Funded 3
-- Changes in the Amount of Your Coverage 4
-- If You Become Disabled 4
-- At Retirement 4
-- If You Leave Delmarva 5
-- An Example 5
-- Definitions 8
</TABLE>
<PAGE>
MANAGEMENT LIFE INSURANCE BENEFITS
______________________________________________________________________________
As part of its overall compensation and benefits package, Delmarva Power & Light
Company offers all employees a life insurance benefit of approximately three
times annual salary. Employees in jobs core graded 19 and above (including
entry grade 18 to a job core graded 19) may elect to participate in the
management life insurance program. The following chart shows coverage amounts
by salary range.
<TABLE>
<CAPTION>
SALARY LIFE INSURANCE AMOUNT
- - --------------------------------------------
<S> <C>
$50,000 - $64,999 $ 150,000
65,000 - 79,999 200,000
80,000 - 99,999 250,000
100,000 - 124,999 325,000
125,000 - 149,999 400,000
150,000 - 199,000 550,000
200,000 - 249,000 700,000
250,000 - 349,000 1,000,000
- - --------------------------------------------
350,000 - + 1,250,000
- - --------------------------------------------
</TABLE>
If you are eligible, you may choose coverage through:
. the Group Life Insurance Plan, up to a maximum term benefit of $202,500, or
. a combination of term coverage through the group plan and permanent,
individual coverage through the Management Life Insurance Plan.
<PAGE>
Term coverage provides a death benefit to your beneficiary if you die while you
are employed by Delmarva and covered by the Plan. If you choose the term
coverage, Delmarva will pay the premium. However, you will be required to pay
imputed income tax on amounts of coverage over $50,000.
Unlike term coverage, the Management Life Insurance Plan has a cash value at
retirement, which means the Plan may be used as a long-term savings vehicle as
well as a death benefit. If you choose the combination term and permanent
coverage, Delmarva will pay the full cost of the $50,000 term coverage and you
and Delmarva will share the cost of amounts over $50,000 under the Management
Life Insurance Plan.
The remainder of this summary describes your benefits under the Management Life
Insurance Plan (also referred to as "the Plan"). You'll find more about your
term life insurance coverage in the Survivor Benefits Section in your Employee
Handbook.
<PAGE>
MANAGEMENT LIFE INSURANCE BENEFITS
______________________________________________________________________________
WHEN COVERAGE BECOMES EFFECTIVE
Coverage under the Management Life Insurance Plan is underwritten by New England
Mutual Life Insurance Company. You may enroll in the Plan and designate a
beneficiary as soon as you become eligible. As mentioned earlier, you become
eligible when you are in a job core graded 19 (or entry grade 18 to a core
graded 19 job). Your coverage will become effective on the first day of the
month after you enroll, provided New England Mutual approves your application.
Approval will be subject to evidence of insurability based on your executive
physical and certain other tests that may be required. This process takes
several months. Your Group Life Insurance continues in effect, without change,
during the application period.
HOW THE PLAN IS FUNDED
You and Delmarva share the cost of coverage under the Management Life Insurance
Plan. Because the Plan has a cash value, the total premium is significantly
higher than that of term coverage. Delmarva pays most of this cost. Your cost
is less than what the premium would be if the coverage were term, rather than
permanent, coverage.
<PAGE>
Although you actually own the policy, you assign part of the policy to Delmarva.
This ensures that, in the event of your death before retirement, Delmarva will
recover its cost to provide the coverage through the cash value portion of the
Plan. Your beneficiary will receive the death benefit, which is the amount
shown in the chart on page 1.
CHANGES IN THE AMOUNT OF YOUR COVERAGE
As your salary increases, you'll have the option of increasing life insurance
benefits as well (based on the available coverage amounts outlined on page 1).
The application procedure for additional amounts is the same process that is
required for the initial enrollment. Increases will become effective on January
1 of each year, based on your salary on that date.
IF YOU BECOME DISABLED
In case of disability, the portion of your coverage that is provided under the
group life insurance plan will be reduced according to that plan's schedule.
The existing amount of coverage under the Management Life Insurance Plan will
remain in effect until you reach normal retirement age (age 65). You will
continue to pay your share of the premium until age 65.
<PAGE>
AT RETIREMENT
When you retire, Delmarva will recover its cost for the Plan. With the
remaining cash value, you'll have the following three options which you may
choose in the combination that best suits your individual situation:
. a reduced, paid-up policy with a death benefit of at least $20,000 and an
annual cash dividend,
. a lump sum of cash, or
. to continue a policy that exceeds the paid-up value. In this case, you will
assume full premium payments.
IF YOU LEAVE DELMARVA
If your employment terminates for any reason other than retirement, disability
or death, you will forfeit all benefits under the Management Life Insurance
Plan.
<PAGE>
AN EXAMPLE
The following example shows how the Management Life Insurance Plan works. The
example assumes that premium payments will be required for 10 years. After 10
years, dividends will cover the premiums necessary to maintain the policy. It
is important to note that while dividends typically cover the cost after 10
years, dividends cannot be guaranteed.
<TABLE>
<CAPTION>
Assumptions:
- - -----------
<S> <C>
Age when policy begins: 45
*Salary $ 100,000
*Life Insurance Amount $ 325,000
Annual Premium: $10,021.90
</TABLE>
* For purposes of this example, these amounts are constant. Increased
amounts of coverage would result in increased premiums.
<PAGE>
<TABLE>
<CAPTION>
MANAGEMENT LIFE INSURANCE PLAN FUNDING
PREMIUM PAYMENTS
------------------------------
YEAR EMPLOYEE DELMARVA
- - ----------------------------------------------------------
<S> <C> <C>
1 $ 269.75 $ 9,752.15
- - ----------------------------------------------------------
2 $ 286.00 $ 9,735.90
- - ----------------------------------------------------------
3 $ 308.75 $ 9,713.15
- - ----------------------------------------------------------
4 $ 328.25 $ 9,693.65
- - ----------------------------------------------------------
5 $ 351.00 $ 9,670.90
- - ----------------------------------------------------------
6 $ 367.25 $ 9,654.65
- - ----------------------------------------------------------
7 $ 383.50 $ 9,638.40
- - ----------------------------------------------------------
8 $ 403.00 $ 9,618.90
- - ----------------------------------------------------------
9 $ 422.50 $ 9,599.40
- - ----------------------------------------------------------
10 $ 445.25 $ 9,576.65
- - ----------------------------------------------------------
Total $3,565.25 $96,653.75
- - ----------------------------------------------------------
</TABLE>
In this example, the employee will have paid $3,565.25 over a ten year period
and no additional payments will be required. However, he or she will pay
imputed income tax on the premium amount that is covered by dividends.
If the employee dies before retirement, Delmarva will recover its cost of
$96,653.75 and the employee's beneficiary will receive a benefit of $325,000.
As an example, at normal retirement, this employee may choose:
-- a lump sum cash payment of $135,283,
-- a paid-up policy with a death benefit of $273,024,
-- to pay premiums for a policy that offers a higher level of coverage
than the paid-up policy.
The above amount would be reduced if the employee were to take early retirement.
<PAGE>
DEFINITIONS
______________________________________________________________________________
Term Coverage Coverage in effect only while employee works
for Delmarva and is covered under Group Life
Insurance Plan.
Permanent Coverage Death benefit payable to beneficiary if
employee dies while covered under Management
Life Insurance Plan. Employee may surrender
policy for cash at retirement.
Cash Value Amount payable in exchange for policy;
increases over lifetime of policy. Delmarva
recovers its cost for coverage from cash
value. At retirement, employee may elect
cash value, less Delmarva's cost, in lieu of
life insurance coverage.
Paid-up Policy Permanent policy that has been paid in full
and no additional premium is required.
Dividends are paid in cash rather than used
to pay premiums.
<PAGE>
MANAGEMENT LIFE INSURANCE PLAN
AT-A-GLANCE
<PAGE>
MANAGEMENT LIFE INSURANCE PLAN AT-A-GLANCE
______________________________________________________________________________
Eligibility Jobs core graded 19 and above, including entry
grade 18. Participation is at election of
employee
Cost Shared by Delmarva and employee
Coverage Amount Approximately three times salary
Type of Coverage $50,000 term; remainder permanent
Death Benefit Payable to beneficiary
Cash Value Sufficient to recover Delmarva's cost; available
at retirement in lieu of policy
Options at Retirement Combination of:
. Reduced, paid-up policy
. Lump sum payment
. Policy that exceeds paid-up value
In Event of Disability Reduction in term benefit; continuation of
permanent coverage
Upon Termination Coverage ceases, cash value forfeited
Permanent Coverage Provided by New England Mutual Life Insurance
Company
<PAGE>
WRITTEN CONSENT OF
PLAN ADMINISTRATOR OF DEFERRED COMPENSATION PLAN
Whereas, at its meeting held on December 12, 1996, the Board of Directors
(the "Board") authorized the Vice President of Administration (the
"Administrator") to make any amendments to the Deferred Compensation Plan (the
"Plan") necessary to (1) remove the 10% limitation for contributions of Base
Salary and allow executive participants in "ungraded" positions to defer as much
as 100% of Base Salary as they would elect and (2) permit the Directors of the
Company to defer under the Plan their Directors' compensation, with both of such
changes to be effective December 12, 1996;
NOW, THEREFORE BE IT
RESOLVED, That the Delmarva Power & Light Company Deferred Compensation
Plan (the "Plan") be, and it hereby is, amended, effective December 12, 1996, by
adding the following to the end of Section 2.7:
For purposes of participation by members of the Board of Directors,
"Compensation" shall mean each Director's compensation paid by the Company
(whether in the form of cash or Company common stock) for serving as a
member of the Board of Directors of Delmarva Power & Light Company.
FURTHER RESOLVED, That the Plan be, and it hereby is, amended, effective
December 12, 1996, by deleting Section 2.9 and replacing it with new Section 2.9
as follows:
2.9. "Deferred Compensation Account" shall mean the bookkeeping
-----------------------------
account established by the Administrator for each Participant to which the
Participant's base salary, MICP bonus and Director's compensation deferred
pursuant to Section 4.1 (and income thereon) is credited and from which
distributions to the Participant or to his or her Beneficiary are made. A
Participant shall at all times be fully vested in the balance of his
Deferred Compensation Account.
FURTHER RESOLVED, That the Plan be, and it hereby is, amended, effective
December 12, 1996, by deleting Section 2.12 and replacing it with a new Section
2.12 as follows:
2.12. "Eligible Employee" shall mean an individual employed by the
-----------------
Employer who is a member of a select group of management and/or highly
compensated employees, and as determined by the Committee to be eligible to
participate hereunder pursuant to Article III. "Eligible Employee" shall
also mean each member of the Board of Directors of Delmarva Power & Light
Company.
<PAGE>
FURTHER RESOLVED, That the Plan be, and it hereby is, amended, effective
December 12, 1996, by deleting Section 2.15 and replacing it with a new Section
2.15 as follows:
2.15. "Investment Alternatives" shall mean the investment options
-----------------------
made available to employees under the Savings Plan, which shall be used as
measuring standards for credits to a Participant's Deferred Compensation
Account. In the case of the Participant's Employer Matching Account and
Deferred Stock Account and in the case of a Director's Deferred
Compensation Account credited with Compensation in the form of Company
common stock, the only Investment Alternative shall be Delmarva common
stock as traded on the open market.
FURTHER RESOLVED, That the Plan be, and it hereby is, amended, effective
December 12, 1996, by deleting Section 4.1 and substituting a new Section 4.1 as
follows:
4.1. Salary, Bonus, Dividend, and/or Director's Compensation Deferral
----------------------------------------------------------------
Election. No later than the "Deferral Deadline" as shown in Table 4.1,
--------
each Eligible Employee designated as eligible to participate for purposes
of this Article IV may irrevocably elect, by completing and executing an
Application for Participation and filing it with the Administrator, to
defer any portion of his base salary to be paid in the future, MICP bonus
to be paid in the future, Director's compensation to be paid in the future,
or cash awarded to him on account of dividends that may subsequently be
paid on restricted shares of common stock held under the LTIP for
contingent grant to the Participant or on shares of common stock deferred
under the Participant's Deferred Stock Account.
TABLE 4.1
---------
<TABLE>
<CAPTION>
Type of Deferral Deferral Deadline
- - ---------------------------------------------------------------------------------
<S> <C>
Base Salary Last day before the pay period for which the
deferral is to be effective.
- - ---------------------------------------------------------------------------------
MICP Bonus Award September 30 of the performance year for which
the award is earned.
- - ---------------------------------------------------------------------------------
Dividends Last day before the dividend declaration date
for dividends as to which the deferral is to be
effective.
- - ---------------------------------------------------------------------------------
Director's Compensation Meeting Fees - Last day before calendar quarter
------------
in which Board and Committee meetings are held.
Annual Retainer - May 31 prior to fiscal year
---------------
beginning June 1.
- - ---------------------------------------------------------------------------------
</TABLE>
FURTHER RESOLVED, That the Plan be, and it hereby is, amended, effective
December 12, 1996, by deleting Section 4.3 and substituting a new Section 4.3 as
follows:
4.3. Period for Which Deferral is Effective.
--------------------------------------
<PAGE>
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------
Type of Deferral Applicable Period and Conditions
- - ---------------------------------------------------------------------------------
<S> <C>
Base Salary Continues until amended or terminated.
- - ---------------------------------------------------------------------------------
MICP Bonus Award New election required for each Plan Year.
- - ---------------------------------------------------------------------------------
Dividend Deferral Continues until amended or terminated. Limited
to one election per 12 month period.
- - ---------------------------------------------------------------------------------
LTIP Shares New election required for each performance cycle.
- - ---------------------------------------------------------------------------------
Director's Compensation Continues until amended or terminated.
- - ---------------------------------------------------------------------------------
</TABLE>
FURTHER RESOLVED, That the Plan be, and it hereby is, amended, effective
December 12, 1996, by deleting the last paragraph of Section 6.2 and replacing
it with a new last paragraph under Section 6.2 as follows:
Distribution of a Participant's Company Matching Account and the
portion of a Director's Deferred Compensation Account credited with Company
common stock shall be paid in the form of cash, notwithstanding the fact
that such accounts are denominated in the form of shares of Delmarva stock.
Distribution of a participant's Deferred Stock Account shall be in the form
of Delmarva shares, which may be purchased by Delmarva or transferred from
any grantor trust or other treasury stock account maintained by Delmarva,
except to the extent such shares must be converted to cash to satisfy
applicable withholding requirements.
IN WITNESS WHEREOF, the undersigned Administrator has set his hand as
of the date indicated.
/s/ D. E. Cain January 17, 1997
-------------------------------------------
D.E. Cain Date
<PAGE>
Exhibit 12-A
Delmarva Power & Light Company
Ratio of Earnings to Fixed Charges
----------------------------------
(Dollars in Thousands)
----------------------
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Net income $116,187 $117,488 $108,310 $111,076 $ 98,526
-------- -------- -------- -------- --------
Income taxes 78,340 75,540 67,613 67,102 54,834
-------- -------- -------- -------- --------
Fixed charges:
Interest on long-term debt
including amortization of
discount, premium and
expense 69,329 65,572 61,128 62,651 66,976
Other interest 12,516 10,353 9,336 9,245 8,449
Preferred dividend require-
ments of a subsidiary
trust 1,390 - - - -
-------- -------- -------- -------- --------
Total fixed charges 83,235 75,925 70,464 71,896 75,425
-------- -------- -------- -------- --------
Nonutility capitalized interest (311) (304) (256) (246) (231)
-------- -------- -------- -------- --------
Earnings before income taxes
and fixed charges $277,451 $268,649 $246,131 $249,828 $228,554
======== ======== ======== ======== ========
Ratio of earnings to fixed charges 3.33 3.54 3.49 3.47 3.03
</TABLE>
For purposes of computing the ratio, earnings are net income plus income taxes
and fixed charges, less nonutility capitalized interest. Fixed charges consist
of interest on long- and short-term debt, amortization of debt discount,
premium, and expense, plus the interest factor associated with the Company's
major leases, and one-third of the remaining annual rentals.
<PAGE>
Exhibit 12-B
Delmarva Power & Light Company
Ratio of Earnings to Fixed Charges and Preferred Dividends
----------------------------------------------------------
(Dollars in Thousands)
----------------------
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Net income $116,187 $117,488 $108,310 $111,076 $ 98,526
-------- -------- -------- -------- --------
Income taxes 78,340 75,540 67,613 67,102 54,834
-------- -------- -------- -------- --------
Fixed charges:
Interest on long-term debt
including amortization of
discount, premium and
expense 69,329 65,572 61,128 62,651 66,976
Other interest 12,516 10,353 9,336 9,245 8,449
Preferred dividend require-
ments of a subsidiary
trust 1,390 - - - -
-------- -------- -------- -------- --------
Total fixed charges 83,235 75,925 70,464 71,896 75,425
-------- -------- -------- -------- --------
Nonutility capitalized interest (311) (304) (256) (246) (231)
-------- -------- -------- -------- --------
Earnings before income taxes
and fixed charges $277,451 $268,649 $246,131 $249,828 $228,554
======== ======== ======== ======== ========
Fixed charges $ 83,235 $ 75,925 $ 70,464 $ 71,896 $ 75,425
Preferred dividend requirements 14,961 16,185 15,948 14,803 15,785
-------- -------- -------- -------- --------
$ 98,196 $ 92,110 $ 86,412 $ 86,699 $ 91,210
======== ======== ======== ======== ========
Ratio of earnings to fixed charges
and preferred dividends 2.83 2.92 2.85 2.88 2.51
</TABLE>
For purposes of computing the ratio, earnings are net income plus income taxes
and fixed charges, less nonutility capitalized interest. Fixed charges consist
of interest on long- and short-term debt, amortization of debt discount,
premium, and expense, dividends on preferred securities of a subsidiary trust,
plus the interest factor associated with the Company's major leases, and one-
third of the remaining annual rentals. Preferred dividend requirements represent
annualized preferred dividend requirements multiplied by the ratio that pre-tax
income bears to net income.
<PAGE>
EXHIBIT 13
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31,
(Dollars in Thousands, Except Per Share Amounts) 1996 1995 1994 1993 1992
- - ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
OPERATING RESULTS AND DATA
Operating Revenues $ 1,094,961 $ 995,103 $ 991,021 $ 970,607 $ 864,044
Operating Income $ 179,380 $ 178,406 $ 163,156(1) $ 164,139 $ 143,711(2)
Net Income $ 116,187 $ 117,488 $ 108,310(1) $ 111,076 $ 98,526(2)
Earnings Applicable to Common Stock $ 107,251 $ 107,546 $ 98,940(1) $ 101,074 $ 90,177(2)
Electric Sales (kWh 000)(3) 12,925,716 12,310,921 12,505,082 12,280,230 11,520,811
Gas Sold and Transported (mcf 000) 24,157 21,371 20,342 19,605 20,168
COMMON STOCK INFORMATION
Earnings Per Share of Common Stock $ 1.77 $ 1.79 $ 1.67(1) $ 1.76 $ 1.69(2)
Dividends Declared Per Share of
Common Stock $ 1.54 $ 1.54 $ 1.54 $ 1.54 $ 1.54
Average Shares Outstanding (000) 60,698 60,217 59,377 57,557 53,456
Year-End Common Stock Price $ 20 3/8 $ 22 3/4 $ 18 9/64 $ 23 5/8 $ 23 1/4
Book Value Per Common Share $ 15.41 $ 15.20 $ 14.85 $ 14.66 $ 13.77
Return on Average Common Equity 11.4% 11.7% 11.1% 12.0% 12.2%
CAPITALIZATION
Variable Rate Demand Bonds (VRDB)(4) $ 85,000 $ 86,500 $ 71,500 $ 41,500 $ 41,500
Long-Term Debt 904,033 853,904 774,558 736,368 787,387
Company Obligated Mandatorily Redeemable
Preferred Securities of Subsidiary Trust
Holding Solely Company Debentures 70,000 -- -- -- --
Preferred Stock 89,703 168,085 168,085 168,085 176,365
Common Stockholders' Equity 934,913 923,440 884,169 862,195 745,789
---------- ---------- ---------- ---------- ----------
Total Capitalization with VRDB $2,083,649 $2,031,929 $1,898,312 $1,808,148 $1,751,041
========== ========== ========== ========== ==========
OTHER INFORMATION
Total Assets $ 2,979,153 $ 2,866,685 $ 2,669,785 $ 2,592,479 $ 2,374,793
Long-Term Capital Lease Obligation $ 20,552 $ 20,768 $ 19,660 $ 23,335 $ 26,081
Construction Expenditures(5) $ 151,728 $ 135,614 $ 154,119 $ 159,991 $ 207,439
Internally Generated Funds (IGF)(6) $ 120,260 $ 137,394 $ 123,948 $ 108,693 $ 130,275
IGF as a Percent of Construction Expenditures 79% 101% 80% 68% 63%
</TABLE>
(1) An early retirement offer decreased net income and earnings per share by
$10.7 million and $0.18, respectively.
(2) The settlement of a lawsuit increased net income and earnings per share by
$11.4 million and $0.21, 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 12, "Debt," to the Consolidated Financial Statements.
(5) Excludes Allowance for Funds Used During Construction.
(6) Net cash provided by operating activities less common and preferred
dividends.
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EARNINGS SUMMARY
Earnings per share for 1996 were $1.77, a $0.02 decrease from 1995. In 1996 and
1995, the outages of the two units at the Salem Nuclear Generating Station
(Salem), which began in May and June 1995, caused increases in operation and
maintenance expenses and fuel-related costs, including replacement power. The
Salem outages decreased earnings per share by approximately $0.19 in 1996 and
$.09 in 1995. See "Salem Outages" for additional information. Excluding 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. The Company held operation and maintenance expenses within
$1.3 million (0.6%) of 1995 expenses after excluding the effects of the Salem
outages and the Company's acquisition of the Conowingo Power Company (COPCO) in
June 1995, as discussed in Note 4, "Mergers and Acquisitions," to the
Consolidated Financial Statements. The Conowingo District's operating results
continued in 1996 to have a minimal impact on earnings, as expected. Earnings
from nonutility businesses were relatively flat as higher earnings from
operations of nonutility subsidiaries were offset by start-up costs of new,
nonutility businesses incurred by the parent company.
Earnings per share for 1995 were $1.79, a $0.12 increase from 1994. Excluding an
$0.18 per share charge in 1994 for an early retirement offer (ERO), earnings per
share decreased $0.06 in 1995 due to a $0.09 decrease attributed to utility
operations, partly offset by a $0.03 increase for nonutility subsidiaries. The
$0.09 per share decrease for utility operations resulted from additional costs
expensed for the Salem outages. Excluding the Salem outages and the 1994 charge
for the ERO, earnings per share from utility operations in 1995 were unchanged
from 1994, reflecting the Company's success in offsetting lower wholesale
(resale) revenues with a combination of cost reductions, retail sales growth,
and modest price increases.
DIVIDENDS
On December 12, 1996, the Board of Directors declared a common stock dividend of
$0.38 1/2 per share for the fourth quarter or $1.54 on an annualized basis. As
discussed under "Strategic Plans For Competition," on August 9, 1996, the
Company announced plans to merge with Atlantic Energy, Inc. (Atlantic). The
merger agreement restricts the Company's common stock dividend through the
merger's effective date to an amount which cannot exceed $1.54 per share. The
merger is part of the Company's growth strategy, which 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.
SALEM OUTAGES
The Company owns 7.41% of Salem, which consists of two pressurized water nuclear
reactors and is operated by Public Service Electric & Gas Company (PSE&G). Salem
Units 1 and 2 were removed from operation by PSE&G in May and June 1995,
respectively, due to operational problems and maintenance concerns. Due to
degradation of a significant number of tubes in the Unit 1 steam generators,
PSE&G is replacing the Unit 1 steam generators and expects Unit 1 to return to
service in the fall of 1997. The Company's share of the costs to be capitalized
for the steam generators, including installation, will range from approximately
$11 million to $13 million. PSE&G has advised the Company that Unit 2 is
expected to return to service in the second quarter of 1997. The units' return
dates are subject to completion of the requirements of their respective restart
plans to the satisfaction of PSE&G and the Nuclear Regulatory Commission (NRC),
which encompasses a substantial review and improvement of personnel, process,
and equipment issues.
In 1996 and 1995, the Company incurred higher than expected operation and
maintenance costs at Salem of approximately $9 million and $5 million,
respectively, which were expensed as incurred.
The Company incurs replacement power costs while the units are out of service of
approximately $750,000 per month, per unit. Such amounts vary based on the cost
and availability of other Company-owned generation and the cost of purchased
energy. Replacement power costs typically are not incurred for routine refueling
and maintenance outages, and the recovery of replacement power costs is subject
to approval by the regulatory commissions having jurisdiction over the Company.
From the inception of the Salem unit outages through December 31, 1996,
approximately one-half of
<PAGE>
estimated replacement power costs of $20.4 million has been expensed ($6.1
million expensed in 1996 and $4.1 million expensed in 1995) and the remaining
$10.2 million has been deferred on the Company's Consolidated Balance Sheet in
expectation of future recovery. The unavailability of the Salem units also
resulted in a $4 million charge to 1996 fuel expense for capacity deficiency
charges owed to the Pennsylvania-New Jersey-Maryland Interconnection Association
(PJM Interconnection).
The actual costs ultimately incurred by the Company may differ from the
foregoing estimates, since the periods projected by PSE&G during which the Salem
units will be out of service, the extent of the maintenance that will be
required, and the costs of replacement power and the extent of its recovery may
be different from those set forth above.
The Company began recovering one-half of the replacement power costs associated
with the Salem outages on an interim basis, subject to refund, from retail
electric customers in Virginia and Maryland in July and August 1996,
respectively. The Company expects the Virginia State Corporation Commission
(VSCC) and Maryland Public Service Commission (MPSC) to conduct full reviews of
the outages before making final determinations concerning replacement power cost
recovery.
On December 10, 1996, the Delaware Public Service Commission (DPSC) suspended
the portion of interim rates related to the Salem replacement power costs until
the earlier of June 1, 1997, or the end of the case concerning fuel rates
charged to customers. If the suspended interim rates go into effect prior to the
conclusion of the case, they would go into effect subject to refund pending the
final decision by the DPSC.
Since the 1995 shutdown of the units, the Company's objective has been to reduce
the negative financial impact on its stockholders and customers. As discussed in
Note 17 to the Consolidated Financial Statements, "Contingencies," the legal
actions initiated in the first quarter of 1996 by the Company against PSE&G and
Westinghouse Electric Corporation, which manufactured the steam generators
originally installed at Salem, are still pending.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
As a result of federal legislation, electric resale customers can choose their
electric suppliers, resulting in a highly-competitive electric resale market.
Many states are considering, and a number of states have introduced, electric
retail wheeling, which results in retail customers purchasing electricity from
the suppliers of their choice at market-based prices. In addition, federal
legislation has been introduced and other bills are being drafted which could
lead to retail wheeling for the entire nation on varying dates. As subsequently
discussed under "Business Units," although prices charged to customers for the
production (or supply) of electricity may become deregulated, the transmission
and distribution (or delivery) of electricity is expected to remain subject to
regulation.
The transition to a competitive market could result in "stranded costs" for a
utility. Stranded costs generally are considered to be costs which may not be
recoverable in a competitive market due to market-based pricing or customers
choosing different energy suppliers. The states in which retail wheeling is
planned have allowed, or are considering allowing, utilities to recover some or
all of their stranded costs. Potential stranded costs could include (i) above-
market costs associated with generation facilities or long-term power purchase
agreements and (ii) regulatory assets, which are deferred expenses expected to
be recovered from customers in the future. Changes in the regulatory environment
potentially could require the Company to write down asset values, and such
write-downs could be material. However, given the uncertainty with respect to
the timing of regulatory changes, the resulting deregulated market prices for
capacity and energy, and the extent to which the Company's regulatory
commissions will allow for recovery of any previously incurred costs, it is not
possible to predict the level of unrecovered stranded costs, if any, which would
result. Potential write-offs of stranded costs or reductions in profit margins
due to competition would reduce the Company's common equity and could result in
lower credit ratings and higher financing costs. To the extent that additional
equity capital is required, issuance of common stock may be necessary and
earnings per share would decrease.
<PAGE>
Based on the Company's initiative, a formal process has been established in
Delaware and an informal forum has been established in Maryland through which
the commissions and other interested parties are addressing changes in the
regulation of the electric utility industry. During 1996, Delaware and Maryland
forum meetings addressed issues such as retail wheeling, stranded costs,
environmental matters, social programs, rate redesign, and alternative forms of
regulation.
In October 1996, the MPSC issued an order instituting a proceeding to continue
its review of regulatory and competitive issues affecting the electric industry
in Maryland. In consultation with Maryland's electric utilities and other
stakeholders, the MPSC staff has been directed to evaluate regulatory and
competitive issues facing the electric utility industry, including electric
retail competition, developments in federal and state regulation, and the
interests of Maryland's customers and utilities. The MPSC instructed its staff
to submit their recommendations by May 31, 1997.
In December 1996, the forum participants issued to the DPSC and MPSC reports
which discussed the issues and the positions of stakeholders, but did not reach
any conclusions. While there was consensus on some issues, such as the need for
unbundled costs and tariffs, there were many issues where consensus was not
reached, such as the need for and benefits of retail wheeling, recovery of
stranded costs, environmental and social program issues, franchise and property
rights, rate design, and performance-based ratemaking.
The issues mentioned above continue to be discussed by the Company, the DPSC
Staff, and other interested parties. The Company expects to develop formal
proposals on deregulation which are expected to be filed in mid-1997 with the
DPSC. In Maryland, the participants decided in January 1997 to suspend the
collaborative process until the MPSC Staff files its report.
In response to a directive from the VSCC, the VSCC Staff issued in July 1996 a
report on restructuring the electric industry, which included, among other
recommendations, a recommendation for a "go slow" approach to restructuring. In
November 1996, the VSCC issued an order indicating that more evaluation is
necessary to determine what, if any, restructuring may best serve the public
interest in Virginia. The VSCC established a new docket and directed its Staff
to monitor and file separate studies in 1997 regarding the development of a
competitive wholesale market in Virginia, service quality standards, and the
results of retail wheeling experiments in other states. Also, several utilities,
excluding the Company, were directed to file unbundled cost studies and tariffs.
STRATEGIC PLANS FOR COMPETITION
The Company intends to grow its businesses by building long-term customer
relationships, offering new products and services that complement the Company's
core energy business and are targeted to individual customer needs, and serving
more customers in a larger geographical area. The Company plans to develop new
distribution channels throughout the region for its products and services. To
retain existing customers and attract new customers, the Company plans to
differentiate itself from its competitors by providing exceptional service,
maintaining quality and competitive prices, and expanding connections with
customers through new services. The Company believes that its growth strategy
will maximize long-term stockholder value. In the short term, implementation of
this strategy may result in moderate downward pressure on earnings due to costs
for the start-up of new businesses, building a regional distribution platform,
expanding the Company's marketing and sales organization, and upgrading
information technology systems.
The Company plans to sell energy and related premium products and services to
existing customers and to new customers who may be outside the Company's current
service territory. Current developments in the adjoining states of Pennsylvania
and New Jersey indicate future opportunities for the Company to serve more
electric customers. In Pennsylvania, electric retail wheeling is scheduled to be
phased-in over a three year period beginning in 1999. The New Jersey Board of
Public Utilities has recommended that retail electric competition be fully
phased-in by April 2001.
<PAGE>
BUSINESS UNITS
In 1996, the Company reorganized into three separate business units (Energy
Supply, Regulated Delivery, and Energy Services) which strengthen the Company's
ability to meet customers' needs and also reflect the anticipated future
structure of the utility industry. Although the products and services of each
business unit are different and each business unit has a separate strategy, the
business units' plans complement and support each other.
Energy Supply produces, buys, and sells energy in a multi-regional marketplace
that is expected eventually to be competitive and have deregulated, market-based
prices. Energy Supply's mission is to provide new and existing customers with a
complete and competitive portfolio of merchant energy products and services,
while maximizing the value of the Company's generation assets.
Regulated Delivery delivers energy over the Company's transmission and
distribution systems at prices which are expected to continue to be regulated by
the public utility commissions. Regulated Delivery's mission is to provide high-
value utility delivery services to customers in the region. By continuing to
maintain a high level of customer satisfaction through high-quality customer
service, Regulated Delivery will help the Company retain existing customers who
may become eligible to choose alternative energy suppliers in the future.
Energy Services packages and sells energy and related premium products and
services to customers within the competitive regional marketplace. Energy
Services is starting new businesses which include heating, ventilation, and air
conditioning (HVAC) services, telecommunications, and other products and
services which complement the Company's core energy business. In
telecommunications, Energy Services provides fiber optic construction and
engineering services to customers and plans to provide retail telephone services
and carrier service for long-distance phone companies.
PENDING MERGER WITH ATLANTIC
On August 9, 1996, the Company announced plans to merge with Atlantic, an
investor-owned holding company, which owns Atlantic City Electric Company, an
electric utility, and nonutility businesses. Atlantic is located in southern New
Jersey. Atlantic's 1996 operating revenues and net income were $980.3 million
and $58.8 million, respectively, and its total assets were $2,670.8 million as
of December 31, 1996. The merger is expected to facilitate success in the
competitive marketplace and is part of the Company's integrated strategy to
build a regional delivery platform over which a portfolio of products and
services can be distributed. Other anticipated benefits of the merger include
increased scale, cost savings, competitive prices and services, a more balanced
customer base, and increased financial flexibility. On January 30, 1997, the
stockholders of the Company and Atlantic approved the merger. Various federal
and state regulatory approvals are also required for the merger to become
effective. The regulatory approval process is expected to be completed during
late 1997 to early 1998. Refer to Note 4, "Mergers and Acquisitions," to the
Consolidated Financial Statements for additional information on the merger.
ELECTRIC RESALE BUSINESS
The Company's total electric resale revenues as a percent of total billed
electric sales revenues were 7.4% in 1996, 7.0% in 1995, and 13.0% in 1994.
Resale non-fuel revenues decreased $24.2 million in 1995, primarily because Old
Dominion Electric Cooperative (ODEC), the Company's largest resale customer,
began purchasing about one-half of its capacity and energy requirements from
other suppliers. The reduction in 1995 resale non-fuel revenues was offset
through cost reductions, retail sales growth, and modest price increases.
<PAGE>
The Company has substantially reduced the financial risk related to its resale
business. In 1994 and 1995, the Company entered into long-term contracts with
all of its municipal customers. In addition, the Company negotiated extended
notice provisions on the remaining portion of ODEC's capacity and energy
requirements served by the Company. The notice provisions require ODEC to
provide the Company with two years' notice for up to a 30% load reduction and
five years' notice for load reductions greater than 30%.
The Company currently provides approximately 200 megawatts (MW) of load to ODEC,
which represented 3.8% of the Company's 1996 total billed electric sales
revenues, including about $24 million of non-fuel (base rate) revenues. On
August 16, 1996, ODEC notified the Company that it will reduce its load by 60 MW
effective September 1, 1998, and will further reduce its load to zero effective
September 1, 2001.
ODEC had issued a request for proposals in March 1996 to replace eventually
ODEC's capacity and energy agreements with its current suppliers. On July 1,
1996, the Company submitted its proposal to ODEC to continue to serve all of the
load currently supplied by the Company. ODEC expects to select a supplier by
March 1997 for the 60 MW it will cease purchasing under its existing contract
with the Company, effective September 1, 1998.
If ODEC selects a new electric supplier for some or all of the load currently
supplied by the Company, the decrease in non-fuel revenues would be offset
partially by avoided purchased capacity costs. Also, the Company would continue
to receive transmission wheeling revenues from ODEC. The Company estimates that
earnings per share would decrease by $0.06 to $0.08, on an annualized basis,
after September 1, 1998 if ODEC reduces its load by 60 MW. Earnings per share
would decrease by an additional $0.10 to $0.12, on an annualized basis, after
September 1, 2001, if ODEC further reduces its load to zero. Any such earnings
decrease would be mitigated by natural load growth in the Company's service
territory and by any of ODEC's load that the Company may obtain through the
bidding process.
COMPONENTS OF UTILITY REVENUES
Fuel and energy costs billed to customers (fuel revenues) generally are based on
rates in effect in fuel adjustment clauses which are adjusted periodically to
reflect cost changes and are subject to regulatory approval. Rates for non-fuel
costs billed to customers are dependent on rates determined in base rate
proceedings before regulatory commissions. Changes in non-fuel (base rate)
revenues can affect directly the earnings of the Company. Fuel revenues, or fuel
costs billed to customers, generally do not affect net income since the expense
recognized as fuel costs is adjusted to match the fuel revenues. The amount of
under- or over-recovered fuel costs generally is deferred until it is
subsequently recovered from or returned to utility customers.
Electric revenues also include interchange delivery revenues, which result
primarily from the sale of electric power to utilities in the PJM
Interconnection. The PJM Interconnection is an electric power pool comprised of
eight utilities in the region, including the Company. The power pool provides
both capital and operating economies to member utilities. Interchange delivery
revenues are reflected in the calculation of rates charged to customers under
fuel adjustment clauses. Due to this ratemaking treatment, interchange delivery
revenues generally do not affect net income.
ELECTRIC REVENUES AND SALES
In 1996, the percentage of total billed electric sales revenues contributed by
the various customer classes were as follows: residential - 42.3%; commercial -
32.0%; industrial - 17.5%; resale - 7.4%; and other - 0.8%.
<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>
(Dollars in Millions) 1996 1995
- - ---------------------------------------------------------------------------------------------
<S> <C> <C>
Non-fuel (Base Rate) Revenues
Retail Sales Volume $21.6 $ 54.9
Resale Sales Volume -- (24.2)
Increased Rates 1.8 3.3
Fuel Revenues 26.8 (6.9)
Interchange Delivery Revenues 28.0 (15.1)
Other Operating Revenues 2.8 4.5
----- ------
Total $81.0 $ 16.5
===== ======
</TABLE>
For 1996 compared to 1995, Non-fuel Revenues increased $21.6 million from
"Retail Sales Volume" due to a 4.5% increase in total retail kilowatt-hour (kWh)
sales, which reflects Conowingo District sales for all of 1996, versus about
one-half of 1995, and other sales growth. Excluding the Conowingo District,
retail sales increased 0.7% mainly due to 1.3% growth in the number of retail
customers, partly offset by lower sales to industrial customers.
For 1995 compared to 1994, Non-fuel Revenues increased $54.9 million from
"Retail Sales Volume" due to a 7.3% increase in total kWh sales, which resulted
primarily from Conowingo District sales beginning June 19, 1995. Excluding the
Conowingo District, retail sales increased 2.9% mainly due to a 1.4% increase in
the number of retail customers and 4.5% commercial sales growth.
Changes in Non-fuel Revenues from "Resale Sales Volume" were insignificant for
1996 compared to 1995. Non-fuel resale revenues decreased $24.2 million in 1995
because ODEC changed electric suppliers on January 1, 1995 for one-half of its
electricity requirements.
The increases in Non-fuel Revenues from "Increased Rates" of $1.8 million in
1996 and $3.3 million in 1995 resulted from an increase in Delaware retail
electric rates that became effective May 1, 1995. The rate increase was designed
to recover the costs of "limited issues," which primarily were costs imposed by
government.
In 1996, Fuel Revenues increased $26.8 million due to increased kWh sales and
higher average fuel rates. In 1995, Fuel Revenues decreased $6.9 million mainly
due to lower kWh sales to resale customers.
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. In
1995, Interchange Delivery Revenues decreased $15.1 million mainly due to lower
sales and billing rates to the PJM Interconnection.
GAS REVENUES, SALES AND TRANSPORTATION
The Company earns gas revenues from the sale and transportation of gas for
customers. Transportation customers may purchase gas from the Company or other
suppliers. The total number of gas customers served by the Company increased by
2.5% in 1996 and 2.9% in 1995.
In 1996, total gas revenues increased $18.8 million due to a $5.5 million
increase in non-fuel revenues and a $13.3 million increase in fuel revenues.
Non-fuel revenues increased $5.5 million mainly due to customer growth and a
colder heating season which resulted in a 4.9% increase in total gas sold and
transported on the Company's system. Including off-system sales which began in
1996, total gas sold and transported increased 13.0%. Fuel revenues increased
$13.3 million due to a prior year $6.8 million refund of over-recovered fuel
costs, higher sales, and higher average rates.
<PAGE>
In 1995, total gas revenues decreased $12.5 million from 1994 because of a $16.5
million decrease in fuel revenues, partly offset by a $4.0 million increase in
non-fuel revenues. The $4.0 million increase in non-fuel revenues was due to
$2.7 million of additional revenue from a base rate increase which became
effective November 1, 1994, and a $1.3 million increase in sales volume. Fuel
revenues decreased $16.5 million in 1995 due to lower average fuel rates charged
to customers and a $6.8 million refund in 1995 of over-recovered fuel costs.
ELECTRIC FUEL AND PURCHASED ENERGY EXPENSES
In 1996, electric fuel and purchased energy expenses increased $59.6 million
compared to 1995. The increase was due to a $32.2 million increase for higher
kWh output; a $21.4 million increase, net of amounts deferred pursuant to fuel
adjustment clauses, due to higher oil, gas, and purchased energy prices; and a
$6.0 million increase in replacement power and PJM capacity charges expensed due
to the Salem outages.
In 1995, electric fuel and purchased energy expenses decreased $14.7 million
from 1994 primarily due to lower kWh output and lower purchased energy prices,
which were partly offset by $4.1 million of replacement power costs expensed due
to the Salem outages.
The kWh output required to serve load within the Company's service territory is
substantially equivalent to total output less interchange deliveries. In 1996,
the Company's output for load within its service territory was provided by 37.6%
coal generation, 28.6% oil and gas generation, 24.5% net purchased power, and
9.3% nuclear generation.
GAS PURCHASED
Gas purchased increased $12.6 million in 1996 compared to 1995, due primarily to
higher average prices paid for gas and a prior year $6.8 million customer refund
of over-recovered fuel costs. The $6.8 million customer refund reduced 1995 gas
purchased expense because fuel expense is adjusted to match fuel revenues as
explained under "Components of Utility Revenues."
For 1995 compared to 1994, gas purchased decreased $15.2 million primarily due
to the $6.8 million customer refund in 1995 and due to variances in fuel costs
deferred and subsequently amortized under the Company's fuel adjustment clause.
PURCHASED ELECTRIC CAPACITY
Purchased electric capacity increased from $3.4 million in 1994 to $29.1 million
in 1995 due to an interim purchased power contract with PECO, effective from
June 19, 1995 to February 1, 1996, that was associated with the Company's
purchase of COPCO. Pursuant to agreements made in conjunction with the COPCO
purchase, in February 1996, a long-term contract with lower-priced capacity
replaced the interim contract. In 1996, purchased electric capacity increased
$3.0 million since electric capacity associated with COPCO was purchased during
the entire year. The increase was mitigated substantially by lower-priced
capacity purchased under the long-term contract.
OPERATION, MAINTENANCE, AND DEPRECIATION EXPENSES
In 1996, operation and maintenance expenses increased $7.3 million due to a $3.7
million increase associated with the Salem outages, a $2.3 million increase from
a full year's operation of the Conowingo District, and $1.3 million of
miscellaneous increases.
In 1995, operation and maintenance expenses decreased $17.8 million in
comparison to 1994, principally due to the $17.5 million expense recorded in
1994 for the ERO. Higher than expected costs of approximately $5 million due to
Salem's operational problems were largely offset by lower payroll costs
attributed to reduced staff levels.
Depreciation expense increased in 1996 and 1995 due to completion of on-going
utility construction projects and the addition of the Conowingo District in June
1995.
<PAGE>
UTILITY FINANCING COSTS
For information concerning the 1996 issuance of $70 million of mandatorily
redeemable preferred securities by the Company's subsidiary trust and related
redemptions of preferred stock, see "Liquidity and Capital Resources" and Note
10 to the Consolidated Financial Statements, "Company Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trust Holding Solely Company
Debentures."
Interest expense increased $3.6 million in 1996 and $6.3 million in 1995,
primarily due to debt issued in 1995 to finance the acquisition of COPCO.
Allowance for equity and borrowed funds used during construction (AFUDC)
increased $2.2 million in 1996, primarily due to higher average construction
work-in-progress balances, including the cost of software to support the
reporting of financial results by business units beginning in 1997. AFUDC
decreased $2.4 million in 1995, mainly due to a lower AFUDC rate.
Due to common equity financing, the average number of shares of common stock
increased in 1996 and 1995, which lowered earnings per share by $0.01 and $0.03,
respectively.
ENERGY SUPPLY
The Company's energy supply plan reflects its strategy to provide an adequate,
reliable supply of electricity to customers and keep prices competitive, while
minimizing adverse impacts on the environment. The Company's plan, which is
updated annually, is based on forecasts of demand for electricity in the service
territory and reserve requirements of the PJM Interconnection. The Company's
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 plan combines customer-oriented load management and
strategic conservation programs with short-term power purchases, long-term power
contracts, and renovated power plants.
The Company's current plan would enable the Company to meet customers' energy
requirements without making large investments for new resources. The Company
must balance the potential risks of providing too much or insufficient capacity.
The main risks of excess capacity are that the Company's prices may become
uncompetitive or that regulators may not allow the associated costs to be
recovered through customer rates. The principal risks of inadequate capacity are
unreliable service or the payment of capacity deficiency charges to the PJM
Interconnection. The PJM Interconnection requires the Company to plan for and to
provide an adequate capacity level.
During the past three years, the Company's plan has reduced customers' demand
for electricity by an additional 39 MW, and has provided 205 MW of capacity from
a long-term purchased power contract with PECO Energy Company, which began in
1996. Under an amendment to a long-term purchased power contract, the Company's
purchase of 48 MW of peaking capacity from Star Enterprise has been suspended
from October 1, 1996 until June 1, 2000, due to the availability of lower cost
power.
Beginning in 1997 and continuing through 2001, the Company expects it may
purchase up to 200 MW of power under short-term agreements in addition to the
currently existing long-term purchases mentioned above. The Company plans to
keep peak load reductions achieved through customer-oriented load management
programs at existing levels.
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 into 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,
compliance with environmental regulations, and the periodic need for upgrading
or replacing information systems.
<PAGE>
Operating activities provided net cash inflows of $222.7 million in 1996, $239.4
million in 1995, and $224.6 million in 1994. The $16.7 million decrease in 1996
net cash flow from operating activities reflects electric fuel revenues which
were less than electric fuel and energy costs. See "Salem Outages" for a
discussion of the Company's recent electric fuel rate changes and filings.
After deducting common and preferred dividend payments of $102.4 million in
1996, $102.0 million in 1995, and $100.6 million in 1994, internally generated
funds were $120.3 million in 1996, $137.4 million in 1995, and $124.0 million in
1994. Internally generated funds provided 79%, 101%, and 80% of the cash
required for utility construction in 1996, 1995, and 1994, respectively.
Utility construction expenditures, excluding AFUDC, were $151.7 million in 1996,
$135.6 million in 1995, and $154.1 million in 1994. Construction expenditures in
1996, 1995, and 1994 included $4.4 million, $16.4 million, and $20.7 million,
respectively, for projects attributed to environmental compliance. In 1995, the
Company acquired COPCO for $158.2 million ($157.0 million net of cash acquired)
with $125.8 million of long-term debt and the balance with short-term debt.
The amount of cash used to purchase or construct nonutility assets was $15.0
million in 1996, $3.6 million in 1995, and $11.0 million in 1994. Nonutility
assets purchased or constructed during 1994-1996 included construction
expenditures at the Pine Grove Landfill during all three years, assets related
to the start-up of new businesses including HVAC services in 1996, and purchase
of an office building in 1994.
Long-term financings during 1994-1996, net of long-term refinancings and
redemptions, raised $159.2 million of capital. Sources of cash, net of
refinancings and redemptions, included the following: $32.6 million of common
stock; $91.5 million of long-term debt; $43.5 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.
In 1994 and 1995, cash was raised from common stock primarily through the
Dividend Reinvestment and Common Share Purchase Plan (DRIP). Depending on the
financing needs of the Company, shares issued through the DRIP may be either
newly issued shares or shares purchased in the open market. In 1996, shares for
the DRIP were purchased in the open market until December 31 when the Company
began raising cash again by issuing new common shares.
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 $63.4
million of the Company's preferred stock, which had an average dividend rate of
6.73%, and the Company's $15.0 million, 7.52% series preferred stock in October
and December 1996, respectively. On an after-tax basis, the refinancing will
save approximately $1.5 million annually.
From February 4, 1997 to February 7, 1997, the Company issued $77.0 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 borrowings which
were outstanding as of December 31, 1996. In recognition of this refinancing,
$77.0 million of short-term debt has been reclassified to long-term debt on the
consolidated balance sheet as of December 31, 1996.
<PAGE>
Long-term debt due within one year increased from $1.5 million as of December
31, 1995 to $27.7 million as of December 31, 1996 primarily due to the scheduled
maturity of the Company's 6 3/8% Series First Mortgage Bond on September 1,
1997.
The Company's capital structure as of December 31, 1996 and 1995, expressed as a
percentage of total capitalization, is shown below.
<TABLE>
<CAPTION>
1996 1995
---- ----
<S> <C> <C>
Long-term debt and variable rate demand bonds 47.5% 46.3%
Mandatorily redeemable preferred securities 3.3% --
Preferred stock 4.3% 8.3%
Common stockholders' equity 44.9% 45.4%
</TABLE>
Capital requirements for the period 1997-1998 are estimated to be $453 million,
including $230 million for utility construction (excluding AFUDC), $64 million
for payment of long-term debt maturities, and $159 million of other requirements
primarily for investments in new business lines.
The Company anticipates that $282 million will be generated internally during
1997-1998, net of power purchase commitments. This represents 62% of estimated
capital requirements and 123% of estimated utility construction expenditures for
1997-1998. During 1997-1998, long-term external financings are presently
estimated at $216 million, including $160 million of long-term debt and $56
million of common stock.
NONUTILITY SUBSIDIARIES
Information on the Company's nonutility subsidiaries, in addition to the
following discussion, can be found in Notes 1, "Significant Accounting
Policies," and 18, "Nonutility Subsidiaries," to the Consolidated Financial
Statements.
Earnings per share resulting from nonutility subsidiaries were $0.10 in 1996,
$0.07 in 1995, and $0.04 in 1994. Start-up costs for new nonutility businesses
incurred in 1996 by the parent company (reflected in "Other income, net of
income taxes") offset the $0.03 increase in 1996 earnings per share of
nonutility subsidiaries. During 1996, 1995, and 1994, nonutility earnings were
generated primarily from the recovery of previously written-off joint venture
assets, the operation of power plants for other parties, gains from the sale of
real estate, and leveraged lease operations.
Earnings per share contributed by nonutility subsidiaries increased in 1996
primarily due to higher recoveries of previously written-off joint venture
assets. Partial year 1996 operating results for the Company's new HVAC and
telecommunication business lines had a minimal effect on earnings.
Nonutility subsidiary earnings in 1994 were reduced by a write-down of oil and
gas wells.
The subsidiaries' solid waste businesses, including the Pine Grove Landfill,
contributed earnings in 1994, but incurred an operating loss in 1995 and 1996. A
permit for expansion of the Pine Grove Landfill is currently pending before the
Pennsylvania Department of Environmental Protection (PADEP). In August 1996, the
Governor of Pennsylvania issued an executive order suspending consideration of
landfill expansion applications until new regulations were written. The Company
is revising its landfill expansion permit application to comply with the new
PADEP guidelines issued in January 1997. The Company will comply with all new
regulations and expects to receive permit approval to avoid any interruption in
landfill services.
<PAGE>
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.
Howard E. Cosgrove Barbara S. Graham
Chairman of the Board, President Senior Vice President
and Chief Executive Officer and Chief Financial Officer
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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.
Coopers & Lybrand L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 7, 1997
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
(Dollars in Thousands) 1996 1995 1994
- - -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Electric $ 980,677 $ 899,662 $ 883,115
Gas 114,284 95,441 107,906
----------- ----------- -----------
1,094,961 995,103 991,021
----------- ----------- -----------
OPERATING EXPENSES
Electric fuel and purchased energy 327,464 267,885 282,570
Gas purchased 61,208 48,615 63,814
Purchased electric capacity 32,126 29,116 3,370
Operation and maintenance 253,367 246,049 263,837
Depreciation 123,174 113,022 109,523
Taxes other than income taxes 42,386 38,449 38,585
Income taxes 75,856 73,561 66,166
----------- ----------- -----------
915,581 816,697 827,865
----------- ----------- -----------
OPERATING INCOME 179,380 178,406 163,156
----------- ----------- -----------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains 65,390 52,042 43,142
Expenses including interest and income taxes (59,192) (47,896) (40,790)
----------- ----------- -----------
Net earnings of nonutility subsidiaries 6,198 4,146 2,352
Allowance for equity funds used during
construction 1,338 708 3,389
Other income, net of income taxes (928) 557 (285)
----------- ----------- -----------
6,608 5,411 5,456
----------- ----------- -----------
INCOME BEFORE UTILITY INTEREST CHARGES
AND DIVIDENDS ON PREFERRED SECURITIES 185,988 183,817 168,612
----------- ----------- -----------
UTILITY INTEREST CHARGES
Interest expense 72,026 68,395 62,076
Allowance for borrowed funds used during
construction (3,615) (2,066) (1,774)
----------- ----------- -----------
68,411 66,329 60,302
----------- ----------- -----------
DIVIDENDS ON PREFERRED SECURITIES OF A
SUBSIDIARY TRUST 1,390 -- --
----------- ----------- -----------
EARNINGS
Net income 116,187 117,488 108,310
Dividends on preferred stock 8,936 9,942 9,370
----------- ----------- -----------
Earnings applicable to common stock $ 107,251 $ 107,546 $ 98,940
=========== =========== ===========
COMMON STOCK
Average shares of common stock outstanding (000) 60,698 60,217 59,377
Earnings per average share of common stock $1.77 $1.79 $1.67
Dividends declared per share of common stock $1.54 $1.54 $1.54
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
(Dollars in Thousands) 1996 1995 1994
- - ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 116,187 $ 117,488 $ 108,310
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and amortization 128,712 120,897 120,803
Deferred income taxes, net 33,218 15,992 4,829
Provision for early retirement offer -- -- 17,500
Net change in:
Accounts receivable (5,030) (14,022) 7,980
Inventories (4,489) 18,590 (21,409)
Accounts payable 18,418 3,269 5,811
Other current assets & liabilities(1) (48,383) (14,349) (10,668)
Other, net (15,981) (8,437) (8,569)
--------- --------- ---------
Net cash provided by operating activities 222,652 239,428 224,587
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures, excluding AFUDC (151,728) (135,614) (154,119)
Allowance for borrowed funds used during construction (3,615) (2,066) (1,774)
Change in working capital for construction (4,880) 1,102 (439)
Acquisition of COPCO, net of cash acquired -- (157,014) --
Sales of nonutility assets 693 4,970 4,596
Nonutility assets purchased or constructed (15,036) (3,645) (11,045)
Net (increase)/decrease in bond proceeds held in trust funds 7,163 2,658 (11,816)
Deposits to nuclear decommissioning trust funds (4,238) (3,612) (2,438)
Other, net (2,222) (1,859) (744)
--------- --------- ---------
Net cash used by investing activities (173,863) (295,080) (177,779)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends: Common (93,290) (92,221) (91,175)
Preferred (9,102) (9,813) (9,464)
Issuances: Long-term debt(2) -- 125,800 4,640
Variable rate demand bonds -- 15,000 30,000
Common stock 486 24,693 14,974
Preferred securities(3) 70,000 -- --
Redemptions: Long-term debt(2) (1,504) (1,388) (26,096)
Variable rate demand bonds (1,500) -- --
Common stock (5,466) (1,253) (794)
Preferred stock (78,383) -- --
Principal portion of capital lease payments (5,538) (7,875) (11,280)
Net change in term loan(4) -- (45,000) 35,000
Net change in short-term debt 86,498 53,154 10,000
Cost of issuances and refinancings (3,408) (1,523) (601)
--------- --------- ---------
Net cash provided/(used) by financing activities (41,207) 59,574 (44,796)
--------- --------- ---------
Net change in cash and cash equivalents 7,582 3,922 2,012
Beginning of year cash and cash equivalents 28,951 25,029 23,017
--------- --------- ---------
End of year cash and cash equivalents $ 36,533 $ 28,951 $ 25,029
========= ========= =========
</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.
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
As of December 31,
(Dollars in Thousands) 1996 1995
- - -----------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
UTILITY PLANT--AT ORIGINAL COST
Electric $3,037,830 $2,942,969
Gas 229,362 208,245
Common 136,897 130,949
---------- ----------
3,404,089 3,282,163
Less: Accumulated depreciation 1,292,325 1,189,269
---------- ----------
Net utility plant in service 2,111,764 2,092,894
Construction work-in-progress 118,208 105,588
Leased nuclear fuel, at amortized cost 31,513 31,661
---------- ----------
2,261,485 2,230,143
---------- ----------
OTHER PROPERTY AND INVESTMENTS
Nonutility property, net 63,023 50,011
Investment in leveraged leases 46,961 48,367
Funds held by trustee 34,735 36,275
Other investments 4,155 4,770
---------- ----------
148,874 139,423
---------- ----------
CURRENT ASSETS
Cash and cash equivalents 36,533 28,951
Accounts receivable 142,431 131,236
Inventories, at average cost
Fuel (coal, oil, and gas) 36,584 30,076
Materials and supplies 41,292 36,823
Prepayments 20,233 12,969
Deferred energy costs 31,127 --
Deferred income taxes, net -- 5,400
---------- ----------
308,200 245,455
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS
Prepaid employee benefit costs 35,146 16,899
Unamortized debt expense 13,858 12,256
Deferred debt refinancing costs 21,366 23,972
Deferred recoverable income taxes 137,561 151,250
Other 52,663 47,287
---------- ----------
260,594 251,664
---------- ----------
Total $2,979,153 $2,866,685
========== ==========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
As of December 31,
(Dollars in Thousands) 1996 1995
- - ------------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $2.25 par value; 90,000,000 shares authorized;
shares outstanding: 1996--60,682,719, 1995--60,759,365 $ 136,765 $ 136,713
Additional paid-in capital 508,300 506,328
Retained earnings 293,604 281,862
---------- ----------
938,669 924,903
Treasury shares, at cost:
1996--101,831 shares, 1995-1,320 shares (2,138) (30)
Unearned compensation (1,618) (1,433)
---------- ----------
Total common stockholders' equity 934,913 923,440
Cumulative preferred stock 89,703 168,085
Company obligated mandatorily redeemable
preferred securities of subsidiary trust holding
solely Company debentures 70,000 --
Long-term debt 904,033 853,904
---------- ----------
1,998,649 1,945,429
---------- ----------
CURRENT LIABILITIES
Short-term debt 74,355 63,154
Long-term debt due within one year 27,676 1,485
Variable rate demand bonds 85,000 86,500
Accounts payable 81,628 64,056
Interest accrued 16,193 16,355
Dividends declared 23,265 23,426
Current capital lease obligation 12,598 12,604
Deferred income taxes, net 7,276 --
Other 31,489 36,773
---------- ----------
359,480 304,353
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes, net 526,449 519,597
Deferred investment tax credits 42,501 45,061
Long-term capital lease obligation 20,552 20,768
Other 31,522 31,477
---------- ----------
621,024 616,903
---------- ----------
Commitments and Contingencies (Notes 14 and 17) -- --
Total $2,979,153 $2,866,685
========== ==========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
<PAGE>
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Common Additional Unearned
Shares Par Paid-in Retained Treasury Compen-
(Dollars in Thousands) Outstanding Value (1) Capital Earnings Stock sation Total
- - --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance as of January 1, 1994 58,829,283 $132,366 $470,997 $259,507 $ -- $ (675) $862,195
Net income 108,310 108,310
Cash dividends declared
Common stock ($1.54 per share) (91,436) (91,436)
Preferred stock (9,370) (9,370)
Issuance of common stock
DRIP(2) 703,726 1,584 13,199 14,783
Other issuance 8,997 20 171 191
Reacquired common stock (36,840) (794) (794)
Common shares granted(3) 36,840 794 (794) --
Amortization of unearned compensation 289 289
Other 10 (9) 1
---------- -------- -------- -------- ------- ------- --------
Balance as of December 31, 1994 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 stock (63,370) (1,253) 19 (1,234)
Common shares granted(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
========== ======== ======== ======== ======= ======= ========
</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, 1996, 4,979,971 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.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
The Company is predominately a public utility that provides electric and gas
service. The Company provides electric service to retail (residential,
commercial, and industrial) and wholesale (resale) customers in Delaware, ten
primarily Eastern Shore counties in Maryland, and the Eastern Shore area of
Virginia in an area consisting of about 6,000 square miles with a population of
approximately 1.2 million. In 1996, 90% of the Company's operating revenues were
derived from the sale of electricity. The Company provides gas service to retail
and transportation customers in an area consisting of about 275 square miles
with a population of approximately 475,000 in northern Delaware, including the
City of Wilmington.
In addition, the Company and its wholly owned subsidiaries are engaged in
nonutility activities. The Company is developing and marketing energy-related
products and services primarily targeted to customers in retail markets. The
Company's primary nonutility activities are heating, ventilation, and air-
conditioning (HVAC) services; telecommunication services; landfill and
wastehauling operations; operation and maintenance of energy-related projects;
real estate sales and developments; and leveraged equipment leases.
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. The percentage of
electric and gas utility operating revenues regulated by each Commission for the
year ended December 31, 1996, was as follows: DPSC, 61.9%; MPSC, 28.8%; VSCC,
2.8%; and FERC, 6.5%.
Refer to Note 8, "Regulatory Assets," to the Consolidated Financial Statements
for a discussion of regulatory assets arising from the financial effects of rate
regulation.
Reporting of Subsidiaries
The consolidated financial statements include the accounts of the Company's
wholly owned subsidiaries. All significant intercompany accounts and
transactions are eliminated in consolidation. The results of operations of the
Company's nonutility subsidiaries are reported in the Consolidated Statements of
Income as "Other Income." Refer to Note 18, "Nonutility Subsidiaries," to the
Consolidated Financial Statements for financial information about the Company's
nonutility subsidiaries.
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.
<PAGE>
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.
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 financial
accounting purposes to average depreciable property was 3.6% for 1996, 1995 and
1994. 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 6, "Nuclear Decommissioning,"
to the Consolidated Financial Statements for additional information on nuclear
decommissioning.
Income Taxes
Refer to Note 3, "Income Taxes," 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 under "Utility
Interest Charges" 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 6.7% in 1996, 7.1% in 1995, and 9.3%
in 1994.
Stock-based Employee Compensation
Refer to Note 9, "Common Stock," for the Company's accounting policy on stock-
based employee compensation.
Capitalized Software Costs
The Company capitalizes software projects which exceed $1 million. Capitalized
software costs net of accumulated depreciation were $31.6 million as of December
31, 1996 and $8.2 million as of December 31, 1995. Capitalized software costs
are amortized over periods of 5 to 10 years.
Leveraged Leases
As of December 31, 1996, the Company's portfolio of leveraged leases, held by a
nonutility subsidiary, consists of five aircraft which are 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.
<PAGE>
Funds Held By Trustee
Funds held by trustee generally include deposits in the Company's external
nuclear decommissioning trusts and unexpended, restricted, tax-exempt bond
proceeds. Earnings on such trust funds are also reflected in the balance.
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
<TABLE>
<CAPTION>
CASH PAID DURING THE YEAR
(Dollars in Thousands) 1996 1995 1994
- - -------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest, net of capitalized amount $67,596 $62,660 $57,837
Income taxes, net of refunds $56,582 $66,764 $67,922
</TABLE>
3. INCOME TAXES
The Company and its wholly owned subsidiaries file a consolidated federal income
tax return. Income taxes are allocated to the Company's utility business and
subsidiaries based upon their respective taxable incomes, tax credits, and
effects of the alternative minimum tax, if any.
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 $137.6 million and $151.3 million as of December 31, 1996 and 1995,
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.
<TABLE>
<CAPTION>
COMPONENTS OF CONSOLIDATED INCOME TAX EXPENSE
(Dollars in Thousands) 1996 1995 1994
- - --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operation
Federal: Current $32,937 $46,517 $50,276
Deferred 31,670 16,452 5,592
State: Current 6,536 9,851 11,268
Deferred 7,273 3,257 928
Investment tax credit adjustments, net (2,560) (2,516) (1,898)
------- ------- -------
Total Operation 75,856 73,561 66,166
------- ------- -------
Other income
Federal: Current 8,016 5,263 2,789
Deferred (5,539) (3,686) (2,008)
State: Current 193 433 349
Deferred (186) (31) 317
------- ------- -------
Total Other Income 2,484 1,979 1,447
------- ------- -------
Total income tax expense $78,340 $75,540 $67,613
======= ======= =======
</TABLE>
<PAGE>
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>
1996 1995 1994
(Dollars in Thousands) Amount Rate Amount Rate Amount Rate
- - --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Statutory federal income
tax expense $68,084 35% $67,560 35% $ 61,574 35%
Increase (decrease) due to
State income taxes, net of
federal tax benefit 8,980 5 8,792 5 8,361 4
Other, net 1,276 -- (812) (1) (2,322) (1)
------- -- ------- -- -------- --
Total income tax expense $78,340 40% $75,540 39% $ 67,613 38%
======= == ======= == ======== ==
</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,
(Dollars in Thousands) 1996 1995
- - ---------------------------------------------------------------------------------------------
<S> <C> <C>
Deferred Tax Liabilities
Utility plant basis differences
Accelerated depreciation $310,343 $307,346
Other 107,186 99,941
Leveraged leases 41,604 44,662
Deferred recoverable income taxes 58,747 64,376
Deferred energy costs 13,240 --
Other 75,005 54,507
-------- --------
Total deferred tax liabilities 606,125 570,832
-------- --------
Deferred Tax Assets
Deferred ITC 14,876 15,719
Other 57,524 40,916
-------- --------
Total deferred tax assets 72,400 56,635
-------- --------
Total deferred taxes, net $533,725 $514,197
======== ========
</TABLE>
Valuation allowances for deferred tax assets were not material as of December
31, 1996 and 1995.
4. MERGERS AND ACQUISITIONS
Pending Merger with Atlantic Energy, Inc.
On August 9, 1996, the Company and Atlantic Energy, Inc. (Atlantic) announced
plans for a business combination of the Company and Atlantic in a merger of
equals. Conectiv, Inc., a Delaware corporation, was newly formed to accomplish
the merger and its outstanding capital stock is owned 50% by the Company and 50%
by Atlantic. After the merger, Conectiv, Inc. will become the parent company of
the Company and its direct and indirect subsidiaries and of the direct and
indirect subsidiaries of Atlantic. Conectiv, Inc., whose name will be changed to
Conectiv at the time of the merger, will be a holding company registered under
the Public Utility Holding Company Act of 1935, as amended.
Atlantic is a public utility holding company with three wholly owned
subsidiaries, Atlantic City Electric Company (ACE), Atlantic Energy Enterprises,
Inc., and Atlantic Energy International, Inc. ACE, which is Atlantic's regulated
utility subsidiary, is primarily engaged in the generation, transmission,
distribution, and sale of electric energy to about 478,000 customers in an area
consisting of 2,700 square miles in southern New Jersey. Atlantic's 1996
operating revenues and net income were $980.3 million and $58.8 million,
respectively, and its total assets were $2,670.8 million as of December 31,
1996.
<PAGE>
On January 30, 1997 the merger was approved by the stockholders of the Company
and Atlantic. The merger is expected to close shortly after all remaining
conditions to the consummation of the merger, including obtaining applicable
regulatory approvals, are met or waived. The regulatory approval process is
expected to be completed in late 1997 or early 1998.
As a result of the merger, each outstanding share of the Company's common stock,
par value $2.25 per share, will be 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, will be 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. The preferred stock of the Company will remain outstanding and
unchanged. The purchase method of accounting will be used to account for the
merger.
The total consideration to be paid to Atlantic's common stockholders, measured
by the average daily closing market price of Atlantic's common stock for the ten
trading days following the public announcement of the merger, is $948.6 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 $204.5 million, which will be recorded as
goodwill. The goodwill will be amortized over 40 years.
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 now being 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 are included in the Consolidated Statements of
Income starting June 19, 1995. 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 and
1994, the Company's pro forma operating results for these years would not have
been materially different from the operating results reported.
5. EARLY RETIREMENT OFFER
In the third quarter of 1994, the Company completed a voluntary early retirement
offer (ERO) for all management and union employees at least 55 years old with at
least 10 years of continuous service by December 31, 1994. The ERO was accepted
by 10.5% of the Company's workforce (296 people), which represented an 82%
participation rate among eligible employees. In accordance with Statement of
Financial Accounting Standards (SFAS) No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," the Company expensed $17.5 million of costs associated
with the ERO ($10.7 million after taxes or $0.18 per share).
6. 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 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 $42.9 million as of December 31,
1996. The provision reflected in depreciation expense for nuclear
decommissioning was $4.2 million in 1996, $3.6 million in 1995, and $2.4 million
in 1994. External trust funds established by the Company for the purpose of
funding nuclear decommissioning costs had an aggregate book balance of $31.1
million (fair value of $35.3 million) as of December 31, 1996. 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.
<PAGE>
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, "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets," which proposes
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 are 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 to
decommissioning expense.
7. 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, 1996 was as follows:
<TABLE>
<CAPTION>
Megawatt Construction
Ownership Capability Plant in Accumulated Work in
(Dollars in Thousands) Share Owned Service Depreciation Progress
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Nuclear
Peach Bottom 7.51% 164 MW $130,196 $ 76,251 $12,426
Salem 7.41% 164 MW 216,788 102,568 24,548
Coal-Fired
Keystone 3.70% 63 MW 19,943 8,236 307
Conemaugh 3.72% 63 MW 33,274 9,821 342
Transmission Facilities Various 4,564 2,205 --
Other Facilities Various 1,746 179 1,633
-------- -------- -------
Total $406,511 $199,260 $39,256
======== ======== =======
</TABLE>
8. 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 is 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, 1996, the Company had $219.7 million of regulatory assets, which
included the following: Deferred Energy Costs--$31.1 million; Deferred debt
refinancing costs--$21.4 million; Deferred recoverable income taxes--$137.6
million (refer to Note 3, "Income Taxes," to the Consolidated Financial
Statements); Deferred recoverable plant costs--$7.9 million; Deferred costs for
decontamination and decommissioning of United States Department of Energy
gaseous diffusion enrichment facilities--$6.8 million; Deferred demand-side
management costs--$6.1 million; and other regulatory assets--$8.8 million. The
costs of these assets either are 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.
<PAGE>
9. COMMON STOCK
Refer to the Consolidated Statements of Changes in Common Stockholders' Equity
for information concerning issuances and redemptions of common stock during
1994-1996.
The merger agreement with Atlantic (discussed in Note 4, "Mergers and
Acquisitions") contains a restriction on the payment of dividends on common
stock. Under the merger agreement, the Company's annual per share common stock
dividend cannot exceed $1.54 through the effective date of the merger.
The Company's Long Term Incentive Plan (LTIP) provides long-term incentives to
key employees through awards of stock-based compensation. Up to 1,500,000 shares
of common stock may be issued under the LTIP during the ten-year period from May
31, 1996 through May 30, 2006. Currently, awards granted under the LTIP consist
entirely of shares of performance-based restricted stock which are contingently
granted and 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 the effective date of the pending merger with
Atlantic or the end of the four year vesting period. Restrictions will not lapse
due to consummation of the merger on shares contingently granted in 1997 through
the effective date of the pending merger with Atlantic. During 1996, 1995, and
1994, the number of restricted shares contingently granted and their fair value
as of grant date was as follows: 1996--48,750 shares, $22 3/4 per share fair
value; 1995--62,050 shares, $18 9/64 per share fair value; 1994--36,840 shares,
$23 5/8 per share fair value. Formerly, the LTIP also provided for stock options
and dividend rights; some of the stock options are still outstanding. Changes in
stock options are summarized below.
<TABLE>
<CAPTION>
1996 1995 1994
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
balance 46,350 $20.16 53,050 $20.03 53,050 $20.03
Options exercised 2,400 $19.69 3,900 $17.85 --- ---
Options forfeited ---- ---- 2,800 $20.98 --- ---
End-of-year balance 43,950 $20.19 46,350 $20.16 53,050 $20.03
Exercisable 43,950 $20.19 46,350 $20.16 53,050 $20.03
</TABLE>
For options outstanding as of December 31, 1996, the range of exercise prices
was $17 1/2 to $21 1/4 and the weighted average remaining contractual life was
3.5 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 $0.3 million in 1996,
$1.3 million in 1995, and $0.6 million in 1994. Pro forma net income and
earnings per share for 1996, 1995, and 1994, based on application of SFAS No.
123, "Accounting for Stock-Based Compensation" are not materially different from
net income and earnings per share as reported.
10. 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 will use 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
<PAGE>
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 from the trust to
purchase and retire $63,382,700 (par value) of its preferred stock as follows:
$1,013,400 of the 3.70% series ($100 par value); $2,012,600 of the 4% series
($100 par value); $2,459,600 of the 4.2% series ($100 par value); $2,154,000 of
the 4.28% series ($100 par value); $3,042,900 of the 4.56% series ($100 par
value); $3,147,700 of the 5% series ($100 par value); $16,500,000 of the 6.75%
series ($100 par value); $32,087,500 of the 7.75% series ($25 par value), and
$965,000 of the Adjustable Rate series ($100 par value). 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.
11. 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 10 to the Consolidated Financial Statements, "Company Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trust Holding Solely Company
Debentures."
<TABLE>
<CAPTION>
Current Shares Amount
Redemption Outstanding (Dollars in Thousands)
Series Price 1996 1995 1996 1995
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$25 per share par value
7 3/4% (1) 316,500 1,600,000 $ 7,913 $40,000
$100 per share par value
3.70%-5% $103.00-$105.00 181,698 320,000 18,170 32,000
6 3/4% (2) 35,000 200,000 3,500 20,000
7.52% -- -- 150,000 -- 15,000
Adjustable rate(3) $100 151,200 160,850 15,120 16,085
Auction rate(4) $100 450,000 450,000 45,000 45,000
------- --------
$89,703 $168,085
======= ========
</TABLE>
(1) Redeemable beginning September 30, 2002, at $25 per share.
(2) Redeemable beginning November 1, 2003, at $100 per share.
(3) Average rates during 1996 and 1995 were 5.5% and 5.6%, respectively.
(4) Average rates during 1996 and 1995 were 4.1% and 4.5%, respectively.
<PAGE>
12. 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, 1996, the Company had $150 million of unused bank lines of
credit. The Company generally is required to pay annual commitment fees of 0.10%
for its credit lines. The lines of credit are reviewed periodically by the
Company, at which time they may be renewed or cancelled. The weighted average
interest rates on short-term debt outstanding as of December 31, 1996 and 1995
were 5.6% and 5.3%, respectively.
Maturities of long-term debt and sinking fund requirements during the next five
years are as follows: 1997--$29.4 million; 1998--$35.1 million; 1999--$37.5
million; 2000--$4.2 million; 2001--$5.2 million.
From February 4, 1997 to February 7, 1997, the Company issued $77.0 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 borrowings which
were outstanding as of December 31, 1996. In recognition of this refinancing,
$77.0 million of short-term debt has been reclassified to long-term debt on the
consolidated balance sheet as of December 31, 1996. Long-term debt outstanding
as of December 31, 1996 and 1995 is presented below:
<TABLE>
<CAPTION>
(Dollars in Thousands) Interest Rates Due 1996 1995
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First Mortgage Bonds: 6 3/8% 1997 $ 25,000 $ 25,000
6.40%-6.95% 2002-2003 120,000 120,000
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% 1997-2008 25,800 25,800
-------- --------
Total First Mortgage Bonds 575,000 575,000
Other Bonds 7.15%-7.50% 2011-2017 54,500 54,500
Pollution Control Notes:
Series 1973 5 3/4% 1997-1998 6,125 6,250
Series 1976 7 1/8%-7 1/4% 1997-2006 3,000 3,100
Medium Term Notes: 5.69% 1998 25,000 25,000
7 1/2% 1999 30,000 30,000
8.30%-9.29% 2002-2004 39,000 39,000
7.06%-8 1/8% 2007 81,000 50,000
7.55%-7.62% 2017 10,000 --
7.61%-9.95% 2020-2021 67,000 61,000
7.72% 2027 30,000 --
Other Obligations: 8.09% 1997-2002 1,502 940
8.00% 1999(1) 3,970 4,279
9.65% 2002(2) 6,184 6,938
Unamortized premium and discount, net (572) (618)
Current maturities of long-term debt (27,676) (1,485)
-------- --------
Total long-term debt 904,033 853,904
Variable Rate Demand Bonds(3) 85,000 86,500
-------- --------
Total long-term debt
and Variable Rate Demand Bonds $989,033 $940,404
======== ========
</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 $85.0 million as of December 31, 1996 and $86.5 million
as of December 31, 1995. The VRDB are classified as current liabilities
because the VRDB are due on demand by the bondholder. However, bonds
submitted to Delmarva for purchase are remarketed by a remarketing agent on
a best efforts basis. Delmarva expects that bonds submitted for purchase
will continue to be remarketed successfully due to Delmarva'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 $85.0 million balance of VRDB outstanding as of December 31,
1996, matures in 2017 ($26 million), 2019 ($13.5 million), 2028 ($15.5
million), and 2029 ($30 million). Average annual interest rates on the VRDB
were 3.6% in 1996 and 4.0% in 1995.
<PAGE>
13. 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>
1996 1995
Carrying Fair Carrying Fair
(Dollars in Thousands) Amount Value Amount Value
- - ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Funds held by trustee $ 34,735 $ 38,908 $ 36,275 $ 37,060
Company Obligated Mandatorily
Redeemable Preferred Securities
of Subsidiary Trust Holding
Solely Company Debentures $ 70,000 $ 71,064 -- --
Long-Term Debt $904,033 $944,670 $853,904 $936,480
</TABLE>
14. COMMITMENTS
The Company currently estimates its commitments for construction of utility
plant, excluding AFUDC, and purchases under fuel supply contracts, excluding
nuclear fuel, to be approximately $183 million in 1997 and $198 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, starts at 205
megawatts (MW) and increases annually to 279 MW in 2006. Under the terms of the
agreements with Star Enterprise and PECO, the Company's expected commitments for
capacity and energy charges are as follows: 1997--$57.7 million; 1998--$61.1
million; 1999--$68.6 million; 2000--$76.3 million; 2001--$79.4 million; after
2001--$431.5 million; total--$774.6 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 $31.5 million as of
December 31, 1996.
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 $154.3 million in aggregate. The Company also has long-
term leases for certain other facilities and equipment. Minimum commitments as
of December 31, 1996 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: 1997--$6.5
million; 1998--$6.4 million; 1999--$6.2 million; 2000--$5.0 million; 2001--$4.9
million; after 2001--$137.0 million; total--$166.0 million. Approximately 93% of
the minimum lease commitments shown above are payments due under the Merrill
Creek Reservoir lease.
Rentals Charged To Operating Expenses
The following amounts were charged to operating expenses for rental payments
under both capital and operating leases.
<TABLE>
<CAPTION>
(Dollars in Thousands) 1996 1995 1994
- - ----------------------------------------------------------------
<S> <C> <C> <C>
Interest on capital leases $ 1,628 $ 1,773 $ 1,560
Amortization of capital leases 5,653 8,044 11,456
Operating leases 13,795 13,619 14,552
------- ------- -------
$21,076 $23,436 $27,568
======= ======= =======
</TABLE>
<PAGE>
15. PENSION PLAN
The Company 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, the contribution for any year will not be less than
the minimum required contribution nor greater than the maximum tax deductible
contribution.
Based on fair values as of December 31, 1996, pension plan assets were comprised
of the following: publicly traded equity securities ($472.5 million or 70%),
U.S. government obligations ($101.2 million or 15%), and primarily investment
grade corporate and other fixed income obligations ($102.5 million or 15%).
The following schedules show the funded status of the plan, the components of
pension cost, and assumptions.
<TABLE>
<CAPTION>
Reconciliation of Funded Status of the Plan As of December 31,
(Dollars in Thousands) 1996 1995
- - -----------------------------------------------------------------------------------
<S> <C> <C>
Accumulated benefit obligation
Vested $ 330,639 $ 338,485
Nonvested 24,869 26,024
--------- ---------
355,508 364,509
Effect of estimated future compensation increases 95,132 109,706
--------- ---------
Projected benefit obligation 450,640 474,215
Plan assets at fair value 676,189 616,600
--------- ---------
Excess of plan assets over projected benefit obligation 225,549 142,385
Unrecognized prior service cost 28,980 29,191
Unrecognized net gain (196,496) (124,850)
Unrecognized net transition asset (26,513) (29,827)
--------- ---------
Prepaid pension cost $ 31,520 $ 16,899
========= =========
</TABLE>
<TABLE>
<CAPTION>
Components of Net Pension Cost
(Dollars in Thousands) 1996 1995 1994
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost--benefits earned during period $ 13,172 $ 9,719 $ 10,939
Interest cost on projected benefit obligation 32,531 30,654 26,574
Actual return on plan assets (82,488) (135,850) 3,349
Net amortization and deferral 22,164 83,981 (52,601)
--------- --------- ---------
Net pension cost $ (14,621) $ (11,496) $ (11,739)
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
Assumptions 1996 1995 1994
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rates used to determine projected
benefit obligation as of December 31 7.50% 7.00% 8.25%
Rates of increase in compensation levels 5.00% 5.00% 5.50%
Expected long-term rates of return on assets 9.00% 8.75% 8.25%
</TABLE>
The net pension cost excludes the expense recorded in 1994 under SFAS No. 88 for
the Company's ERO. Prepaid pension cost as of December 31, 1994, was reduced by
the ERO. Refer to Note 5, "Early Retirement Offer," to the Consolidated
Financial Statements for additional information on the ERO.
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 $2.4 million
in 1996, and $2.3 million in 1995 and 1994.
<PAGE>
16. 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, 1996, the
plan's assets consisted of $24.3 million (67%) of equity securities, including
mutual funds and directly owned publicly traded securities, and $11.8 million
(33%) 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,
(Dollars in Thousands) 1996 1995
- - ----------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation (APBO)
Active employees fully eligible for benefits $ 4,568 $ 6,019
Other active employees 23,900 23,990
Current retirees 45,373 63,629
-------- --------
73,841 93,638
Plan assets at fair value 36,075 24,900
-------- --------
APBO in excess of plan assets (37,766) (68,738)
Unrecognized prior service cost 370 423
Unrecognized net (gain)/loss (16,855) 5,212
Unrecognized transition obligation 57,876 61,493
-------- --------
Prepaid/(accrued) postretirement benefit cost $ 3,625 ($ 1,610)
======== ========
</TABLE>
Annual Cost of Postretirement Benefits Other than Pensions
<TABLE>
<CAPTION>
(Dollars in Thousands) 1996 1995 1994
- - ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost--benefits earned during period $ 2,512 $ 2,152 $ 2,127
Interest cost on projected benefit obligation 5,213 6,601 5,520
Actual return on plan assets (4,241) (1,008) 100
Amortization of the unrecognized transition obligation 3,617 3,617 3,617
Other, net 2,072 149 (481)
-------- -------- --------
Net postretirement benefit cost $ 9,173 $ 11,511 $ 10,883
======== ======== ========
</TABLE>
Assumptions
<TABLE>
<CAPTION>
1996 1995 1994
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rates used to determine APBO as of December 31 7.50% 7.00% 8.25%
Rates of increase in compensation levels 5.00% 5.00% 5.50%
Expected long-term rates of return on assets 9.00% 8.75% 8.25%
Health-care cost trend rate 8.00% 10.50% 11.00%
</TABLE>
The health-care cost trend rate, or the expected rate of increase in health-care
costs, is assumed to decrease to 7.5% in 1997 and gradually decrease to 5.0% by
2002. Increasing the health-care cost trend rates of future years by one
percentage point would increase the accumulated postretirement benefit
obligation by $4.2 million and would increase annual aggregate service and
interest costs by $0.4 million.
17. CONTINGENCIES
Salem Outages
The Company owns 7.41% of Salem Nuclear Generating Station (Salem), which
consists of two pressurized water nuclear reactors and is operated by Public
Service Electric & Gas Company (PSE&G). As of December 31, 1996, the Company's
net investment in plant in service for Salem was approximately $56 million for
Unit 1 and $60 million for Unit 2, including common plant allocated between the
two units. Each unit represents approximately 2% of the Company's total assets
and approximately 2.6% of the Company's installed electric generating capacity.
<PAGE>
Salem Units 1 and 2 were removed from operation by PSE&G on May 16, 1995, and
June 7, 1995, respectively, due to operational problems and maintenance and
safety concerns. Their return dates are subject to completion of the
requirements of their respective restart plans to the satisfaction of PSE&G and
the NRC, which encompasses a substantial review and improvement of personnel,
process, and equipment issues.
With respect to Unit 1, PSE&G informed the Company in early 1996 that
inspections of the steam generators using a new testing technology indicated
degradation in a significant number of tubes. After evaluating several options,
in May 1996, replacement steam generators from the unfinished Seabrook Unit 2
nuclear power plant in New Hampshire were purchased from Northeast Utilities
Service Company for installation in Salem Unit 1. The replacement steam
generators arrived on site in October 1996. PSE&G expects Unit 1 to return to
service in the fall of 1997, after replacement of the unit's steam generators.
The Company's share of the costs to be capitalized for the steam generators,
including installation, will range from approximately $11 million to $13
million.
With respect to Unit 2, PSE&G also informed the Company in early 1996, that
inspections of the steam generators using the new testing technology confirmed
that the condition of the generators was within current repair limits. In
January 1997, PSE&G advised the Company that Unit 2 is expected to return to
service in the second quarter of 1997.
In 1996 and 1995, the Company incurred higher than expected operation and
maintenance costs at Salem of approximately $9 million and $5 million,
respectively, which were expensed as incurred.
The Company incurs replacement power costs while the units are out of service of
approximately $750,000 per month, per unit. Such amounts vary based on the cost
and availability of other Company-owned generation and the cost of purchased
energy. Replacement power costs typically are not incurred for routine refueling
and maintenance outages, and the recovery of replacement power costs is subject
to approval by the regulatory commissions having jurisdiction over the Company.
From the inception of the Salem unit outages through December 31, 1996,
approximately one-half of the estimated replacement power costs of $20.4 million
has been expensed ($6.1 million in 1996 and $4.1 million in 1995) and the
remaining $10.2 million has been deferred on the Company's Consolidated Balance
Sheet in expectation of future recovery. The unavailability of the Salem units
also resulted in a $4 million charge to 1996 fuel expense for capacity
deficiency charges owed to the PJM Interconnection.
The actual costs ultimately incurred by the Company may differ from the
foregoing estimates, since the periods projected by PSE&G during which the Salem
units will be out of service, the extent of the maintenance that will be
required, and the costs of replacement power and the extent of its recovery may
be different from those set forth above.
The Company began recovering one-half of the replacement power costs associated
with the Salem outages on an interim basis, subject to refund, from retail
customers in Virginia and Maryland in July and August 1996, respectively. The
Company expects the VSCC and MPSC to conduct full reviews of the outages before
making final determinations concerning replacement power cost recovery.
On December 10, 1996, the DPSC suspended the portion of interim rates related to
the Salem replacement power costs until the earlier of June 1, 1997, or the end
of the case concerning fuel rates charged to customers. If the suspended interim
rates go into effect prior to the conclusion of the case, they would go into
effect subject to refund pending the final decision by the DPSC.
Notwithstanding current discussions with regulators concerning deregulation of
the electric generation portion of the utility business, the Company believes it
is reasonable to assume that rates will be set at levels that will recover the
current and anticipated costs, including the costs needed to return the Salem
units to operating status, of the Company's investment in the Salem plant, and
such rates can be charged to and collected from customers.
On February 27, 1996, the co-owners of Salem, including the Company, filed a
complaint in the United States District Court for the District of New Jersey
against Westinghouse Electric Corporation (Westinghouse), the designer and
manufacturer of the Salem steam generators. The complaint 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. The
estimated replacement cost of such generators is between $150 million and $170
million. The Company cannot predict the outcome of this lawsuit.
<PAGE>
On March 5, 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. The lawsuit alleges that the
defendants failed to heed numerous citations, warnings, notices of violations,
and fines by the NRC as well as repeated warnings from the Institute of Nuclear
Power Operations about performance, safety, and management problems at Salem and
to take appropriate corrective action. The suit contends that as a result of
these actions and omissions, the Salem units were forced to shut down in 1995.
The suit asks for compensatory damages for breach of contract, negligence, and
punitive damages, in amounts to be specified. The Company cannot predict the
outcome of this lawsuit.
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 Company has incurred, and expects to continue to
incur, capital expenditures and operating costs because of environmental
considerations and requirements. 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 is currently participating with the States of Delaware and
Maryland in evaluating the coal gasification sites to assess the extent of
contamination and risk to the environment. The Company has accrued a liability
of $2 million 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 $3.7 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.
Other
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 electric system outages that occurred on March 28, 1996,
and May 14, 1996. The complaint asks for actual damages in excess of $41 million
and for special and punitive damages in unspecified amounts. The Company
believes that its insurance will cover any amounts awarded in this lawsuit in
excess of $1 million for each outage. There is $2 million included in the
Company's current liabilities as of December 31, 1996 for claims related to the
outages. The Company cannot predict the outcome of this lawsuit.
<PAGE>
18. NONUTILITY SUBSIDIARIES
The following presents condensed financial information of 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.
CONDENSED SUBSIDIARY STATEMENTS OF INCOME
<TABLE>
<CAPTION>
(Dollars in Thousands) 1996 1995 1994
- - -------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues and Gains
Landfill and waste hauling $ 14,144 $ 13,505 $14,186
Operating services 21,457 26,564 22,468
Real estate 13,079 5,820 4,450
HVAC services 7,000 -- --
Recoveries of written-off
joint venture assets 6,911 2,812 572
Other revenue 2,799 3,341 1,466
-------- -------- -------
65,390 52,042 43,142
-------- -------- -------
Costs and Expenses
Operating expenses 54,798 45,594 38,499
Interest expense, net 1,000 492 370
Income tax expense 3,394 1,810 1,921
-------- -------- -------
59,192 47,896 40,790
-------- -------- -------
Net income $ 6,198 $ 4,146 $ 2,352
======== ======== =======
</TABLE>
CONDENSED SUBSIDIARY BALANCE SHEETS
<TABLE>
<CAPTION>
(Dollars in Thousands) As of December 31,
Assets 1996 1995
- - ------------------------------------------------------------
<S> <C> <C>
Current assets
Cash and cash equivalents $ 17,315 $ 19,483
Other 16,806 6,633
-------- --------
34,121 26,116
-------- --------
Noncurrent assets
Investment in
Leveraged leases 46,961 48,367
Other 4,550 9,925
Landfill & waste hauling
property, plant & equipment 24,389 24,177
Other 18,505 9,778
-------- --------
94,405 92,247
-------- --------
Total $128,526 $118,363
======== ========
<CAPTION>
Liabilities and As of December 31,
Stockholder's Equity 1996 1995
- - ------------------------------------------------------------
<S> <C> <C>
Current liabilities
Debt due within one year $ 4,524 $ 506
Variable rate demand bonds 13,500 15,000
Other 13,548 7,801
-------- --------
31,572 23,307
-------- --------
Noncurrent liabilities
Long-term debt 4,548 4,713
Deferred income taxes 44,974 50,064
Other 3,344 2,389
-------- --------
52,866 57,166
-------- --------
Stockholder's Equity 44,088 37,890
-------- --------
Total $128,526 $118,363
======== ========
</TABLE>
<PAGE>
Pine Grove Landfill, Inc.
One of the Company's indirect subsidiaries, Pine Grove Landfill, Inc. ("Pine
Grove"), which owns and operates a solid waste disposal facility in
Pennsylvania, currently has pending before the Pennsylvania Department of
Environmental Protection (PADEP) an application for expansion of the facility.
In August 1996, the Governor of Pennsylvania issued an executive order
suspending consideration of landfill expansion applications until new
regulations were written. The Company is revising its landfill expansion permit
application to comply with the new PADEP guidelines issued in January 1997. The
Company will comply with all new regulations and expects to receive permit
approval to avoid any interruption in landfill services.
<PAGE>
19. SEGMENT INFORMATION
Segment information with respect to electric and gas operations was as follows:
<TABLE>
<CAPTION>
(Dollars in Thousands) 1996 1995 1994
- - --------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Electric $ 980,677 $ 899,662 $ 883,115
Gas 114,284 95,441 107,906
---------- ---------- ----------
Total $1,094,961 $ 995,103 $ 991,021
---------- ---------- ----------
OPERATING INCOME
Electric $ 164,300 $ 165,914 $ 153,409
Gas 15,080 12,492 9,747
---------- ---------- ----------
Total $ 179,380 $ 178,406 $ 163,156
---------- ---------- ----------
DEPRECIATION EXPENSE
Electric $ 115,448 $ 105,780 $ 102,746
Gas 7,726 7,242 6,777
---------- ---------- ----------
Total $ 123,174 $ 113,022 $ 109,523
---------- ---------- ----------
CONSTRUCTION EXPENDITURES
Electric $ 131,122 $ 118,655 $ 133,884
Gas 20,606 16,959 20,235
---------- ---------- ----------
Total $ 151,728 $ 135,614 $ 154,119
---------- ---------- ----------
IDENTIFIABLE ASSETS, NET
Electric $2,536,287 $2,493,797 $2,314,448
Gas 218,809 189,339 188,813
Assets not allocated 224,057 183,549 166,524
---------- ---------- ----------
Total $2,979,153 $2,866,685 $2,669,785
========== ========== ==========
</TABLE>
20. 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.
<TABLE>
<CAPTION>
Earnings Earnings
Applicable Average per
Quarter 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>
1996
March 31 $ 292,630 $ 50,560 $ 35,143 $ 32,703 60,759 $0.54
June 30 250,593 38,523 22,325 19,902 60,703 0.33
September 30 291,356 54,263 37,035 34,605 60,667 0.57
December 31 260,382 36,034 21,684 20,041 60,665 0.33
---------- -------- -------- -------- ------ -----
$1,094,961 $179,380 $116,187 $107,251 60,698 $1.77
========== ======== ======== ======== ====== =====
1995
March 31 $ 257,600 $ 48,252 $ 35,408 $ 32,889 59,738 $0.55
June 30 213,228 34,178 19,444 16,962 60,109 0.28
September 30 283,065 60,960 42,714 40,238 60,372 0.67
December 31 241,210 35,016 19,922 17,457 60,651 0.29
---------- -------- -------- -------- ------ -----
$ 995,103 $178,406 $117,488 $107,546 60,217 $1.79
========== ======== ======== ======== ====== =====
</TABLE>
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the Registration Statements
of Delmarva Power & Light Company on Form S-3 (File Nos. 33-63582 and 333-00505)
and on Form S-8 (File Nos. 33-33810 and 333-20715) of our report dated February
7, 1997 on our audits of the consolidated financial statements of Delmarva Power
& Light Company and subsidiary companies as of December 31, 1996 and 1995 and
for each of the three years in the period ended December 31, 1996, which report
is included in this Annual Report on Form 10-K.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
March 24, 1997
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AND STATEMENT OF INCOME FROM THE COMPANY'S 1996
ANNUAL REPORT TO STOCKHOLDERS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,111,764
<OTHER-PROPERTY-AND-INVEST> 148,874
<TOTAL-CURRENT-ASSETS> 308,200
<TOTAL-DEFERRED-CHARGES> 260,594
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,979,153
<COMMON> 136,765
<CAPITAL-SURPLUS-PAID-IN> 508,300
<RETAINED-EARNINGS> 293,604
<TOTAL-COMMON-STOCKHOLDERS-EQ> 934,913
70,000
89,703
<LONG-TERM-DEBT-NET> 904,033
<SHORT-TERM-NOTES> 74,355
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 27,676
0
<CAPITAL-LEASE-OBLIGATIONS> 20,552
<LEASES-CURRENT> 12,598
<OTHER-ITEMS-CAPITAL-AND-LIAB> 845,323
<TOT-CAPITALIZATION-AND-LIAB> 2,979,153
<GROSS-OPERATING-REVENUE> 1,094,961
<INCOME-TAX-EXPENSE> 75,856
<OTHER-OPERATING-EXPENSES> 839,725
<TOTAL-OPERATING-EXPENSES> 915,581
<OPERATING-INCOME-LOSS> 179,380
<OTHER-INCOME-NET> 6,608
<INCOME-BEFORE-INTEREST-EXPEN> 185,988
<TOTAL-INTEREST-EXPENSE> 69,801
<NET-INCOME> 116,187
8,936
<EARNINGS-AVAILABLE-FOR-COMM> 107,251
<COMMON-STOCK-DIVIDENDS> 93,294
<TOTAL-INTEREST-ON-BONDS> 66,042
<CASH-FLOW-OPERATIONS> 222,652
<EPS-PRIMARY> 1.77
<EPS-DILUTED> 1.77
</TABLE>
