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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, 1995
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-1405
---------------------
DELMARVA POWER & LIGHT COMPANY
(Exact name of registrant as specified in its charter)
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DELAWARE & VIRGINIA 51-0084283
(States or other jurisdictions (I.R.S. Employer
of incorporation or organization) Identification No.)
800 KING STREET, P. O. BOX 231
WILMINGTON, DELAWARE 19899
(Address of principal executive (Zip Code)
offices)
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Registrant's telephone number, including area code: 302-429-3089
------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ----------------------------------------------- --------------------------------------------------------
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First Mortgage Bonds (Series issued prior to New York Stock Exchange and Philadelphia Stock Exchange
1968)
Preferred Stock, Cumulative, Par Value $100.00 Philadelphia Stock Exchange
(Series issued prior to 1978)
Common Stock, Par Value $2.25 New York Stock Exchange and Philadelphia Stock Exchange
</TABLE>
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 29, 1996 was $1,341,205,862.
As of February 29, 1996, there were issued and outstanding 60,761,765 shares
of the registrant's common stock, Par Value $2.25.
------------------------
DOCUMENTS INCORPORATED BY REFERENCE
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PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
- -------------------- --------------------------------------------------------------------------------------------
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I (Item I -- Segment Portions of the 1995 Annual Report to Stockholders of Delmarva Power & Light Company
Information) and
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 30, 1996, which Definitive Proxy Statement is
expected to be filed with the Securities and Exchange Commission on or about April 25, 1996
IV Portions of the 1995 Annual Report to Stockholders of Delmarva Power & Light Company
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TABLE OF CONTENTS
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PAGE
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PART I
iii
Glossary................................................................................................
Item 1. Business
The Company............................................................................. I-1
Segment Information..................................................................... I-1
Operating Statistics.................................................................... I-1
Strategic Plans for Competition......................................................... I-1
Electric Operations..................................................................... I-3
Installed Capacity................................................................. I-3
Power Pool......................................................................... I-3
Reserve Margin..................................................................... I-4
Energy Supply Plan................................................................. I-4
Power Plants............................................................................ I-5
Nuclear............................................................................ I-5
Peach Bottom Units................................................................. I-6
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
Subsidiaries............................................................................ I-13
Regulatory and Rate Matters............................................................. I-13
Base Rate Proceedings.............................................................. I-13
Fuel Adjustment Clauses............................................................ I-13
Other Regulatory Matters........................................................... I-14
Construction and Financing Program...................................................... I-16
Environmental Matters................................................................... I-17
Construction Expenditures.......................................................... I-17
Clean Air Act...................................................................... I-17
Salem Operating Permit............................................................. I-18
Water Quality Regulations.......................................................... I-18
Hazardous Substances............................................................... I-19
Emerging Environmental Issues...................................................... I-20
Subsidiaries....................................................................... I-20
Retail Franchises....................................................................... I-20
Number of Employees..................................................................... I-21
Executive Officers of the Registrant.................................................... I-21
</TABLE>
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Item 2. Properties..................................................................................... I-23
Item 3. Legal Proceedings.............................................................................. I-24
Item 4. Submission of Matters to a Vote of Security Holders............................................ I-24
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.......................... II-1
Item 6. Selected Financial Data........................................................................ II-1
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i
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PAGE
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....... II-1
Item 8. Financial Statements and Supplementary Data................................................. II-1
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........ II-1
PART III
Item 10. Directors and Executive Officers of the Registrant.......................................... III-1
Item 11. Executive Compensation...................................................................... III-1
Item 12. Security Ownership of Certain Beneficial Owners and Management.............................. III-1
Item 13. Certain Relationships and Related Transactions.............................................. III-1
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............................ IV-1
Signatures.............................................................................................. IV-4
</TABLE>
ii
<PAGE>
GLOSSARY
The following glossary lists the abbreviations used in this report.
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TERM DEFINITION
- ------------------------------------------ ---------------------------------------------------------------------
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AFUDC..................................... Allowance For Funds Used During Construction
BWR....................................... Boiling Water Reactor
Charter................................... Restated Certificate and Articles of Incorporation
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
Delcap.................................... Delmarva Capital Investments, Inc.
DNREC..................................... Delaware Department of Natural Resources and Environmental Control
DOE....................................... United States Department of Energy
DPSC...................................... Delaware Public Service Commission
EDR....................................... Economic Development Rate
EMF....................................... Electric and Magnetic Fields
Energy Act................................ Energy Policy Act of 1992
EPA....................................... United States Environmental Protection Agency
ESA....................................... Expanded Site Assessment
FERC...................................... Federal Energy Regulatory Commission
FGD....................................... Flue Gas Desulfurization
GE........................................ General Electric Company
ISO....................................... Independent System Operator
kV........................................ Kilovolts
kWh....................................... Kilowatt-hour
LLRW...................................... Low Level Radioactive Waste
Mcf....................................... Thousand Cubic Feet
MD&A...................................... Management's Discussion and Analysis of Financial Condition and
Results of Operations
MDE....................................... Maryland Department of the Environment
Mortgage.................................. Mortgage and Deed of Trust
MOU....................................... Memorandum of Understanding
MPSC...................................... Maryland Public Service Commission
MW........................................ Megawatt
MWh....................................... Megawatt-hour
NCR....................................... Negotiated Contract Rate
NJDEPE.................................... New Jersey Department of Environmental Protection and Energy
NOPR...................................... Notice of Proposed Rulemaking
NOTC...................................... Northeast Ozone Transport Commission
NOTR...................................... Northeast Ozone Transport Region
NOx....................................... Oxides of Nitrogen
NPDES..................................... National Pollutant Discharge Elimination System
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.
</TABLE>
iii
<PAGE>
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TERM DEFINITION
- ------------------------------------------ ---------------------------------------------------------------------
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PJM Interconnection....................... Pennsylvania-New Jersey-Maryland Interconnection Association
PPPP...................................... Power Plant Performance Program
PRP....................................... Potentially Responsible Party
PSE&G..................................... Public Service Electric and Gas Company
PURPA..................................... Public Utility Regulatory Policies Act of 1978
PWR....................................... Pressurized Water Nuclear Reactors
RACT...................................... Reasonably Available Control Technology
Salem..................................... Salem Nuclear Generating Station
SALP...................................... Systematic Assessment of Licensee Performance
SEC....................................... Securities and Exchange Commission
SIT....................................... Special Inspection Team
SO2....................................... Sulfur Dioxide
Star...................................... Star Enterprise
VSCC...................................... Virginia State Corporation Commission
Westinghouse.............................. Westinghouse Electric Corporation
</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 June 19, 1995, the Company acquired Conowingo
Power Company (COPCO), the Maryland retail electric subsidiary of PECO Energy
Company (PECO). COPCO was merged into the Company and is now being operated as
the Conowingo District. For a discussion of the Company's purchase of COPCO,
refer to Notes 4 and 12 to the Consolidated Financial Statements of the
Company's 1995 Annual Report to Stockholders filed as Exhibit 13.
The Company is predominantly 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 1.1 million. In 1995, 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 470,000 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, as discussed in the "Strategic Plans For Competition"
section of Management's Discussion and Analysis of Financial Condition and
Results of Operations (MD&A) of the Company's 1995 Annual Report to Stockholders
filed as Exhibit 13. The subsidiaries, also incorporated in Delaware, include
Delmarva Energy Company, Delmarva Industries, Inc., Delmarva Services Company,
and Delmarva Capital Investments, Inc. (Delcap). For a discussion of the
Company's subsidiaries, refer to "Subsidiaries" on page I-13.
SEGMENT INFORMATION
See Note 19 to the Consolidated Financial Statements of the Company's 1995
Annual Report to Stockholders filed as Exhibit 13.
OPERATING STATISTICS
A Schedule of Operating Statistics for the three years ended December 31,
1995, can be found on page IV-3. This schedule provides electric and gas sales
and revenue data.
STRATEGIC PLANS FOR COMPETITION
Competition exists and is expected to increase for certain electric and gas
energy markets historically served exclusively by regulated utilities. In recent
years, changing laws and governmental regulations permitting competition from
other utilities as well as nonregulated energy suppliers have prompted some
customers to use self-generation or alternative sources to meet their electric
and gas needs. The transition from strictly regulated to competitive resale and
retail markets is changing the structure of the utility industry and the way in
which it conducts business. To address the issues of deregulation and increased
competition, the Company also is changing the way that it views and manages its
business.
ELECTRIC RESALE BUSINESS
The Public Utility Regulatory Policies Act of 1978 (PURPA) facilitated the
entry of potential competitors into the electric generation business. Under
PURPA, a utility may be required to purchase the electricity generated by
qualifying facilities at prices reflecting the utility's avoided cost as
determined by utility procedures or state regulatory bodies.
I-1
<PAGE>
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 March 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR) which,
if adopted, would require electric utilities to provide open access to their
transmission systems under non-discriminatory tariffs available to all wholesale
sellers and buyers of electricity. Utilities would be 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. The NOPR 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 the
NOPR, refer to "Power Pool" on page I-3 and "Comparable Use Transmission Tariff"
on page I-15.
For a discussion of the Company's resale business and the impact of
competition on stranded costs, refer to the "Strategic Plans for Competition"
section of the MD&A of the Company's 1995 Annual Report to Stockholders filed as
Exhibit 13.
ELECTRIC RETAIL BUSINESS
Changes affecting competition in retail markets also are occurring. Large
commercial and industrial customers are reducing their energy costs through
self-generation or cogeneration, the use of alternate fuel sources such as
natural gas, and special contracts negotiated on the basis of actual or
potential location or relocation of facilities and operations. While some
states, such as Maryland, have decided that retail wheeling is not in the public
interest at this time (refer to "Maryland Competition and Regulatory Policies
Inquiry" on page I-15), other state governments are considering various forms of
retail wheeling, which would permit other utilities and non-utility generators
to compete to serve retail customers currently served by a particular utility.
In 1995, Delaware enacted legislation that authorizes the Delaware Public
Service Commission (DPSC) to deregulate the utility industry when a competitive
market exists and implement alternatives to traditional rate base, rate of
return regulation (refer to "Delaware Task Force on Regulation" on page I-14).
At the federal level, legislation was recently introduced in the U.S. Senate to
require all states to provide for retail wheeling by the year 2010.
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 1994 was 7.01 cents per kilowatt-hour (kWh)
compared to a regional average of 8.67 cents per kWh. The Company's average
price for industrial customers in 1994 was 4.48 cents per kWh compared to a
regional average of 6.65 cents per kWh. These regional averages are based on
1994 data for 27 utilities within a 300-mile radius of the Company.
The Company believes that the benefits of a competitive market can best be
realized when addressed together by the Company, the Commissions and customers.
In February 1996, the Company presented to the DPSC and the Maryland Public
Service Commission (MPSC) a proposal to enter into a collaborative process to
develop the transition from a regulated to a competitive energy market. For more
information concerning this presentation and the Company's actions and plans to
manage its retail business in a competitive environment, refer to the "Strategic
Plans For Competition" section of the MD&A of the Company's 1995 Annual Report
to Stockholders filed as Exhibit 13.
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.
I-2
<PAGE>
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, to meet this competition
by directly marketing rebundled gas supply principally to the Company's end-use
customers.
In February 1996, the DPSC approved the Company's application to provide
additional local deregulation for end-use customers (refer to "Natural Gas
Restructuring Filing" on page I-15). 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.
ELECTRIC OPERATIONS
INSTALLED CAPACITY
The net installed summer electric generating capacity available to the
Company to serve its peak load as of December 31, 1995, is presented below. The
Company's purchase of 205 megawatts (MW) of capacity from PECO, related to the
COPCO acquisition, was excluded from the Company's installed capacity until
February 1, 1996, as agreed with PECO and in compliance with the accounting
provisions of the Pennsylvania-New Jersey-Maryland Interconnection Association
(PJM Interconnection). For a discussion of the Company's energy supply plan,
refer to "Energy Supply Plan" on page I-4.
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% OF
INSTALLED SUMMER CAPACITY MEGAWATTS TOTAL
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Coal-Fired........................................................................... 1,120 39
Oil-Fired............................................................................ 586 20
Combustion Turbines/Combined Cycle................................................... 511 18
Nuclear.............................................................................. 328 11
Peaking Units........................................................................ 183 6
Purchased Capacity................................................................... 48 2
Customer-owned Capacity.............................................................. 57 2
----- ---
Subtotal........................................................................... 2,833 98
Purchased PJM Interconnection Capacity Credits....................................... 50 2
----- ---
Total.............................................................................. 2,883 100
----- ---
----- ---
</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-23 for a listing of net
installed generating capacity by station.
POWER POOL
As a member of the PJM Interconnection, 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 $12.5 million during 1995.
I-3
<PAGE>
The PJM Interconnection's installed capacity as of December 31, 1995 was
56,098 MW. The PJM Interconnection peak demand during 1995 was 48,524 MW on
August 2nd, which resulted in a summer reserve margin of 15.3% (based on
installed capacity of 55,962 MW on that date). This peak replaces the previous
all-time peak demand of 46,429 MW which was set on July 8, 1993.
In November 1995, seven PJM Interconnection member companies, including the
Company, provided a detailed plan to the FERC to modify or replace the PJM
Interconnection Agreement and other existing transmission agreements among the
current PJM Interconnection members. The detailed plan is intended, among other
things, to provide transmission tariffs which comply with regulations expected
to result from the NOPR on open access transmission issued by FERC in March 1995
(refer to "Electric Resale Business" on page I-1). The sponsoring companies
intend to make a comprehensive filing with FERC by the end of May 1996 with
possible implementation of the basic elements of the restructured PJM
Interconnection pool operations by year-end 1996. The plan includes the
following key elements:
- Pool-wide transmission tariffs providing comparable, open-access service
for all wholesale transactions throughout the PJM Interconnection;
- A regional pool energy market using price-based dispatch that is open to
all available wholesale buyers and sellers of power;
- Establishment of an Independent System Operator (ISO) to provide daily
management and administration of pool operations, the energy market, and
the regional transmission network; and
- Development of an enhanced pool-wide planning function consistent with
Mid-Atlantic Area Coordination principles, criteria and procedures, which
provide for review and evaluation of plans for generation and transmission
facilities and other matters relevant to the reliability of the bulk
electric supply systems in the Mid-Atlantic area.
RESERVE MARGIN
The Company's peak load in 1995 was 2,602 MW on August 4th, which surpassed
the Company's previous peak of 2,551 MW on July 8, 1994. By mutual agreement
with PECO and in compliance with PJM Interconnection accounting provisions, the
1995 peak does not include 172 MW of COPCO load, for which PECO continued to be
responsible until February 1, 1996. Because adequate generation was available,
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 2,364 MW
in 1995. Based upon this estimated peak and the Company's installed generating
capacity of 2,829 MW at the time of the peak, the Company's reserve margin would
have been 19.7%. 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
("demand-side" alternatives) along with long- and short-term power contracts,
and new or renovated power plants ("supply-side" alternatives). 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 the "Energy Supply" section of the MD&A of the Company's 1995 Annual
Report to Stockholders filed as Exhibit 13.
I-4
<PAGE>
As of the end of 1995, the Company had enrolled in its demand-side programs
about 88,600 residential customers and about 1,600 commercial and industrial
customers, who in aggregate provide the Company with the ability to reduce its
peak by approximately 243 MW. On October 3, 1995, the Company filed to close its
existing demand-side programs to new participants in Delaware and Maryland,
while it reexamined the design and efficacy of these programs and considered the
possible implementation of other cost-effective and otherwise appropriate
programs. The Company took this step because analysis indicated that its current
and other potential demand-side programs are not appropriate, cost-effective
resources for meeting the incremental needs of the Company's customers.
As part of the supply-side portion of the energy supply plan, the Company is
purchasing 48 MW of peaking capacity through May 2018 from the Delaware City
Power Plant owned by Star Enterprise (Star). 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 are being considered to meet continuing PJM
Interconnection capacity obligations from 1997 to 2000. 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 peak load and capacity forecast for the
current and next five PJM Interconnection planning periods, beginning annually
on June 1. The Company periodically reviews and updates its forecast to reflect
changes in peak load and capacity estimates.
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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 (%)
- ----------------------------------- ------- ------- ------- --------- ----- --------- -------
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1995............................... 2607 243 2364 48 2781 2829 19.7
1996............................... 2849 243 2606 253 2786 3039 16.6
1997............................... 2877 243 2634 335 2786 3121 18.5
1998............................... 2867 243 2624 310 2786 3096 18.0
1999............................... 2926 243 2683 367 2786 3153 17.5
2000............................... 2985 243 2742 423 2786 3209 17.0
</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 7 to the Consolidated Financial Statements of the Company's 1995
Annual Report to Stockholders filed as Exhibit 13.
I-5
<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, which 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, by a letter dated October 18, 1994, the
NRC approved PECO's request to rerate the authorized maximum reactor-core power
levels of each Peach Bottom unit by 5% to 1,093 MW. The amendment of the Peach
Bottom Unit 2 facility operating license was effective upon the date of the NRC
approval letter and the associated hardware changes were completed during the
Peach Bottom Unit 2 refueling outage in the fall of 1994. The amendment for
Peach Bottom Unit 3 was issued by the NRC on July 18, 1995 and the associated
hardware changes were implemented during the Peach Bottom Unit 3 refueling
outage in the fall of 1995.
On August 2, 1995, the NRC held an enforcement conference regarding three
alleged violations identified by the NRC at Peach Bottom. In a letter dated
August 17, 1995, the NRC stated that the inadequate design control and testing
which led to the degradation of emergency diesel generator capabilities
constituted a Level III violation; however, because PECO identified the issues,
conducted a detailed root-cause evaluation and took appropriate corrective
actions, no civil penalty was proposed.
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. Peach Bottom
Unit 3 was initially examined during its refueling outage in the fall of 1993.
Although crack indications were identified at two locations, PECO presented its
finding to the NRC and provided justification for continued operation of Peach
Bottom Unit 3 for a two-year cycle. Peach Bottom Unit 3 was re-examined during
its last
I-6
<PAGE>
refueling outage in the fall of 1995 and the extent of cracking identified was
determined to be within industry-established guidelines. In a letter to the NRC
dated November 3, 1995, PECO concluded that there is a substantial margin for
each core shroud weld to allow for continued operation of Peach Bottom Unit 3.
Peach Bottom Unit 2 was examined in October 1994 during its last refueling
outage and the inspection revealed a minimal number of flaws. In a letter dated
November 7, 1994, PECO submitted its findings to the NRC and provided
justification for continued operation of Peach Bottom Unit 2. PECO is
participating in a GE BWR Owners Group to develop long-term corrective actions.
SALEM UNITS
Due to operational problems and maintenance concerns, Salem Units 1 and 2
were removed from operation by PSE&G on May 16, 1995 and June 7, 1995,
respectively. PSE&G has informed the Company that since that time, PSE&G has
been engaged in an assessment of each unit to identify and complete the work
necessary to achieve safe, sustained, reliable and economic operation. PSE&G has
stated that it will keep each unit off line until it is satisfied that the unit
is ready to return to service and to operate reliably over the long term and the
NRC has agreed that the unit is sufficiently prepared to restart. On June 9,
1995, the NRC issued a Confirmatory Action Letter documenting these commitments
of PSE&G.
PSE&G has informed the Company that, on December 11, 1995, PSE&G presented
its restart plan for both units to the NRC at a public meeting. On February 13,
1996, the NRC staff issued a letter to PSE&G indicating that it had concluded
that PSE&G's overall restart plan, if implemented effectively, should adequately
address the numerous Salem issues to support a safe plant restart, and
describing further actions the NRC will undertake to confirm that PSE&G's
actions have resulted in the necessary performance improvements to support safe
plant restart.
PSE&G also has stated that, as a part of PSE&G's review, an examination is
being performed on the steam generators, which are large heat exchangers used to
produce steam to drive the turbines. Within the industry, certain pressurized
water nuclear reactors (PWR) other than Salem have experienced cracking in a
sufficient number of the steam generator tubes to require various modifications
to these tubes and replacement of the steam generators in some cases. Until the
current outage, regular periodic inspections of the steam generators for each
Salem unit have resulted in repairs of a small number of tubes well within NRC
limits. As a result of the experience of other utilities with cracking in steam
generator tubes, in April 1995 the NRC issued a generic letter to all utilities
with PWRs to conduct steam generator examinations with more sensitive inspection
devices capable of detecting evidence of degradation. Subsequently, PSE&G
conducted steam generator inspections of the Salem units using the latest
technology available, including a new, more sensitive, eddy current testing
device.
In addition, PSE&G has informed the Company that, with respect to Salem Unit
1, the most recent inspection of the steam generators is not complete, but
partial results from eddy current inspections in February 1996 using this new
technology show indications of degradation in a significant number of tubes. The
inspections are continuing and PSE&G has decided to remove several tubes for
laboratory examination to confirm the results of the inspections. Removal of the
tubes should be completed in March and preliminary results of the state of the
Salem Unit 1 tubes from the subsequent laboratory examinations should be known
in April. However, based on the results of inspections to date, PSE&G has
concluded that the Salem Unit 1 outage, which was expected to be completed in
the second quarter of 1996, will be required to be extended for a substantial
additional period to evaluate the state of the steam generators and to
subsequently determine an appropriate course of action. Degradation of steam
generators in PWRs has become an increasing concern for the nuclear industry.
Nationally and internationally, utilities have undertaken actions to repair or
replace steam generators. In the extreme, degradation of steam generators has
contributed to the retirement of several American nuclear power reactors. After
the Salem Unit 1 tubes are fully examined, PSE&G will be able to evaluate its
course of action in light of NRC and other industry requirements.
I-7
<PAGE>
According to PSE&G, the examination of the Salem Unit 2 steam generators was
completed in January 1996 using the same testing device used in Salem Unit 1.
The results of the Salem Unit 2 inspection are being reviewed again to confirm
their results in light of the experience with Salem Unit 1. Although this review
has not yet been completed, results to date appear to confirm that the condition
of the Salem Unit 2 steam generators is within current repair limits at the
present time. PSE&G also will remove tubes from the Salem Unit 2 steam
generators for laboratory analysis to further confirm the results of this
testing.
Also, PSE&G had planned to return Salem Unit 1 to service in the second
quarter of 1996 and Salem Unit 2 in the third quarter of 1996. As a result of
the extent of the recently discovered degradation in the Salem Unit 1 steam
generators, PSE&G is focusing its efforts on the return of Salem Unit 2 to
service in the third quarter. The conduct of the additional steam generator
inspections and testing on Salem Unit 2 is not expected to adversely affect the
timing of its restart. However, the timing of the restart is subject to
completion of the requirements of the restart plan to the satisfaction of PSE&G
and the NRC as well as to the normal uncertainties associated with such a
substantial review and improvement of the systems of a large nuclear unit, so
that no assurance can be given that the projected return date will be met.
According to PSE&G, on January 3, 1995, the NRC provided PSE&G with its
latest SALP report on Salem for the period between June 20, 1993 and November 5,
1994. Salem received ratings of "3", the lowest acceptable rating, in the
Operations and Maintenance areas, "2" in Engineering, and "1" in Plant Support.
The NRC noted an overall decline in performance and evidenced particular concern
with plant and operator challenges caused by repetitive equipment problems and
personnel errors. The NRC also noted that although PSE&G has initiated several
comprehensive actions within the past year to improve plant performance, and
some recent incremental gains have been made, these efforts have yet to
noticeably change overall performance at Salem.
On March 21, 1995, representatives of the NRC Staff met with the Boards of
Directors of Public Service Enterprise Group, Inc. and PSE&G to reiterate the
previously expressed concerns with regard to Salem's operations. The NRC staff
acknowledged that PSE&G had made efforts to improve Salem's operations,
including making senior management changes, but indicated that demonstrated
sustained results have not yet been achieved.
PSE&G also has informed the Company that an NRC enforcement conference was
held on July 28, 1995, related to certain violations of NRC requirements at
Salem not related to the present outage. The violations included valves that
were incorrectly positioned following a plant modification in May 1993,
non-conservatisms in setpoints for a pressurizer overpressure protection system
and several examples of inadequate root cause determination of events, leading
to insufficient corrective actions. On October 16, 1995, the NRC imposed
cumulative civil penalties related to these violations of $600,000, of which the
Company's share is 7.41%. PSE&G did not contest the penalties.
On October 5, 1995, plant operators at Salem Unit 1 declared an alert
because the overhead annunciator panels located in the control room stopped
functioning. The panels were declared fully operable after testing later that
day, and the alert was terminated. On November 13, 1995, the NRC conducted an
exit meeting to review NRC Special Inspection Team (SIT) findings regarding the
loss of the overhead annunciator panels. The SIT noted two potential violations
and two unresolved items. The items were all associated with Emergency
Preparedness.
PSE&G has informed the Company that PSE&G's own assessments, as well as
those by the NRC and the Institute of Nuclear Power Operations, indicate that
additional efforts are required to further improve operating performance, as
reflected in the restart plans referred to previously. PSE&G has informed the
Company that PSE&G is committed to taking the necessary actions to address
Salem's performance needs. It is anticipated that the NRC will continue to
maintain a close watch on Salem's restart activities and subsequent operational
performance. No assurance can be given as to what, if any, further or additional
actions may be taken or required by the NRC to improve Salem's performance.
I-8
<PAGE>
The Company's operation and maintenance costs and replacement power costs
related to the current outage are discussed in the "Salem Outage" section of the
MD&A and Note 16 to the Consolidated Financial Statements of the Company's 1995
Annual Report to Stockholders filed as Exhibit 13.
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 replacing Salem's steam generators,
alleges violations of federal and New Jersey Racketeer Influenced and Corrupt
Organizations Acts, fraud, negligent misrepresentation and breach of contract.
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 ultimately
will require replacement and these costs should be borne by Westinghouse and not
the customers and shareholders of the Salem co-owners. 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. and PSE&G, the operator of Salem. The lawsuit
alleges that the defendants failed to respond adequately to 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. Further, the defendants failed to take
appropriate corrective action. The suit contends that as a result of these
actions and omissions, the defendants were forced to shut down both Salem units
in 1995. The suit asks for compensatory damages for breach of contract and for
the defendants' "gross negligence, willful, wanton and reckless misconduct and
misfeasance in performance of the Owners' Agreement" and punitive damages, in
amounts to be determined. The Company cannot predict the outcome of this
lawsuit.
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 and 4 have been
completed. Projects identified during the surveys have been completed to date or
will be implemented during scheduled maintenance outages. Edge Moor Unit 5 and
Vienna Unit 8 will undergo surveys beginning in 1996 and 1997, respectively.
Construction expenditures on these projects for the five-year period 1996-2000
are expected to total approximately $31 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 1995, purchases were made from
Allegheny Power System, PECO, and several power marketers. The Company's
estimated fuel savings from these transactions amounted to $3.4 million during
1995.
The Company also purchases 48 MW of long-term capacity from Star Enterprise
and has 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-4.
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>
1995 1994 1993
------------------------------- ------------------------------- -------------------------------
GENERATION 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.............. 5,086 18 40 5,499 18 42 6,028 18 47
Oil-fired............... 1,191 28 9 1,998 27 15 2,343 24 18
Nuclear................. 1,567 8 12 2,052 8 16 1,883 7 14
Natural Gas............. 2,953 20 23 2,033 19 15 1,010 23 8
--------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Company
Generation........... 10,797 18 84 11,582 18 88 11,264 18 87
<CAPTION>
PURCHASES/ INTERCHANGE
- ------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Purchases............... 3,156 21 24 2,873 23 22 3,200 22 25
Net Interchange......... (1,040) (29) (8) (1,328) (32) (10) (1,568) (30) (12)
--------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Output for
Load................. 12,913 18 100 13,127 17 100 12,896 18 100
--------- --------- --------- --------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- --------- --------- --------- ---------
</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-3. 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 1995, 5% 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, 1995, a maximum of 79% 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 75% to 100% of the residual oil used in Edge Moor Unit 5 currently is
being supplied under a two-year contract which expires in 1996. Any amount over
75% of requirements may be purchased in the spot market. The Company expects to
negotiate a new contract in 1996 with similar terms. 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.
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. In
February 1995, two companies that supply uranium concentrates to PECO filed
petitions for bankruptcy under Chapter 11 of the Bankruptcy Code. The two
companies supply approximately half of PECO's 1995 and 1996 requirements for
uranium concentrates. In addition, one of the companies is under contract to
supply approximately 25% of PECO's uranium concentrate requirements for the
period 1997 to 2002. PECO has made alternative arrangements with other suppliers
to satisfy its short-term requirements for uranium concentrates. PECO also is
finalizing arrangements with another supplier to satisfy its longer-term needs.
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 2000 and, thereafter, 60% through 2002. 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) 1998
Salem Unit 1................................................................ 2000 (3) 2004
Salem Unit 2................................................................ 2000 (3) 2005
</TABLE>
- ------------------------
(1) PECO has commitments for 100% of its conversion services for Peach Bottom
through 1997. Approximately 40% of the conversion services requirements are
covered through 2001. PECO does not anticipate any difficulties in obtaining
necessary conversion services for Peach Bottom.
(2) PECO has commitments for enrichment services for Peach Bottom under contract
with the United States Enrichment Corporation. The commitments represent
100% of the enrichment requirements through 1998 and 70% through 1999. 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.
I-11
<PAGE>
In June 1994, a number of utilities and state agencies, including the PUC,
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. The Company cannot predict when the DOE-sponsored
temporary or permanent storage sites will become available.
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 $6.8 million as of December 31, 1995. The Company is recovering this cost
through fuel adjustment clause revenues which are discussed on page I-13.
GAS OPERATIONS
During 1995, the average production cost of all gas sold was $2.95 per
thousand cubic feet (Mcf), compared with $3.06 and $3.22 per Mcf in 1994 and
1993, 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 158,669 Mcf.
<TABLE>
<CAPTION>
NUMBER OF EXPIRATION DAILY
CONTRACTS DATES MCF
--------------- ------------ ---------
<S> <C> <C> <C>
Supply..................................................................... 4 1996-2004 31,442
Transportation............................................................. 3 2004 59,795
Storage.................................................................... 4 1996-2004 42,432
Local Peak Shaving......................................................... -- -- 25,000
---------
Total.................................................................... 158,669
---------
---------
</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
178,669 Mcf. The Company experienced a new all-time peak daily firm sendout of
158,512 Mcf on January 19, 1994, during extreme weather conditions. The maximum
daily firm sendout experienced to date during the 1995/96 winter was 144,125
Mcf.
I-12
<PAGE>
SUBSIDIARIES
Delcap is a wholly-owned subsidiary of the Company that is 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. A Delcap subsidiary operates and maintains Star's
Delaware City Power Plant from which the Company purchases capacity and energy.
As of December 31, 1995, Delcap's stockholder's equity was $36.8 million.
Delmarva Services Company, a wholly-owned subsidiary of the Company, leases
an office building to the Company. As of December 31, 1995, its stockholder's
equity was $6.0 million.
Delmarva Energy Company and Delmarva Industries, Inc. are wholly-owned
subsidiaries of the Company and are partners in joint venture oil and gas
exploration and development programs in New York, Ohio and Pennsylvania. During
1995, Delmarva Energy and Delmarva Industries made dividend payments of $600,000
and $400,000, respectively, to the Company. As of December 31, 1995, their
combined stockholder's equity was $1.1 million.
For a further discussion of the Company's subsidiaries refer to
"Environmental Matters -- Subsidiaries" on page I-20, as well as the "Nonutility
Subsidiaries" section of the MD&A and Notes 1 and 18 to the Consolidated
Financial Statements of the 1995 Annual Report to Stockholders filed as Exhibit
13.
REGULATORY AND RATE MATTERS
The Company is subject to regulation with respect to its retail electric
sales by the DPSC, the MPSC, and the Virginia State Corporation Commission
(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 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, 1995 was as follows: DPSC 64%; MPSC
27%; VSCC 3%; and FERC 6%.
BASE RATE PROCEEDINGS
For information concerning the Company's base rate proceedings, refer to
Note 2 to the Consolidated Financial Statements in the 1995 Annual Report to
Stockholders, which is 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, 1995, the Company had accrued fuel disallowance reserves that
adequately provide for any 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
I-13
<PAGE>
Company can receive financial rewards or penalties, which will not exceed an
estimated cap of $1.6 million in 1996. The 1994 and projected 1995 PPPP results
are not material to the Company's financial position or results of operations.
If the Company does not meet an overall system performance standard set by
Maryland's Generating Unit Performance Program, the MPSC can disallow certain
fuel costs of units that operated below their individual performance standards.
The 1994 results indicated that the overall system performance standard was met.
The 1995 standards are in the process of being set.
In September 1995, the DPSC issued an order concerning the Company's 1995
retail fuel adjustment filing and disallowed approximately $800,000 of net
replacement power costs associated with a Salem Unit 1 outage that occurred from
April 7, 1994 to June 4, 1994. The order excluded the outage in determining
performance under the PPPP.
In December 1995, the DPSC issued an order concerning the Company's 1996
retail fuel adjustment filing and permitted the Company to retain the fuel
adjustments in effect at that time, pending the Company's supplemental filing
sometime in 1996, which is expected to include a request for recovery of
replacement power costs associated with the current Salem outages. For
additional discussion regarding the current Salem outages, refer to "Salem
Units" on page I-7 and the "Salem Outage" section of the MD&A and Note 16 to the
Consolidated Financial Statements of the Company's 1995 Annual Report to
Stockholders filed as Exhibit 13.
In May 1993, the Company's municipal customers filed a complaint with the
FERC, seeking a $5.3 million refund of alleged excessive fuel and replacement
power costs related to coal procurement practices and the operating performance
of certain electric power plants. In September 1995, the FERC dismissed all
issues except for the limited issue of whether the Company should have pursued
legal remedies against PSE&G for the outage that occurred at Salem Unit 2 from
November 9, 1991 to May 10, 1992. In January 1996, the FERC administrative law
judge issued an initial decision dismissing the remaining complaint. The
municipal customers filed an application for rehearing, which was denied by the
FERC on February 28, 1996, and the Docket was terminated. The Municipals have 60
days to file an appeal.
OTHER REGULATORY MATTERS
ELECTRIC COLLABORATIVE PROPOSAL
For a discussion of the electric collaborative proposal presented to the
DPSC and the MPSC, refer to the "Strategic Plans for Competition" section of the
MD&A of the Company's 1995 Annual Report to Stockholders filed as Exhibit 13.
DELAWARE TASK FORCE ON REGULATION
In 1993, the Governor of Delaware convened the Public Utility Regulatory
Task Force, and on June 12, 1995, the Governor signed legislation implementing
the following key recommendations of the task force.
- The DPSC is authorized to (a) deregulate utility businesses when a
competitive market exists and (b) implement alternative forms of
regulation which depart from traditional rate base, rate of return
regulation;
- The DPSC can authorize special rates for economic development purposes,
such as attracting new customers and preventing the loss of existing
customers;
- The process through which the DPSC approves a public utility's proposed
issuances of debt and equity securities has been streamlined;
- The DPSC is authorized to conduct rate proceedings in which the number or
type of issues are limited; and
- The DPSC is encouraged to resolve issues through the use of settlements.
I-14
<PAGE>
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. New and existing
business operations that make a substantial capital investment and/or create new
jobs would be eligible for the EDR, which reflects the guidelines of the
Delaware regulatory reform legislation described previously. These tariffs also
would allow the Company to compete nationally. The proposed 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 Company proposed that the stockholders
and ratepayers share 20% and 80%, respectively, in Delaware and 30% and 70%,
respectively, in Maryland of the value of the EDR discounts. In both states,
stockholders and ratepayers would share equally the amount of the NCR discounts.
Various modifications, dealing primarily with the discount sharing, are being
considered in settlement discussions with parties in Delaware. Maryland's rates
were approved in March 1996.
MARYLAND COMPETITION AND REGULATORY POLICIES INQUIRY
In August 1995, the MPSC determined that retail wheeling is not in the
public interest at this time. The MPSC decided that resale competition in
combination with competitive bidding for new supply-side and demand-side
resources, special contracts, and utility specific performance-based regulation
can achieve most of the benefits expected from retail wheeling without harming
reliability.
COMPARABLE USE TRANSMISSION TARIFF
In November 1994, the Company submitted a comparable use transmission tariff
as part of its filing with the FERC for approval of the purchase of COPCO. The
tariff became effective, subject to refund, in June 1995. On August 28, 1995,
the Company filed a revised tariff to be consistent with the pro forma tariff
described in the FERC NOPR on open access transmission. In light of the
anticipated filing by the PJM Interconnection of a tariff that would lead to
necessary revisions of the Company's proposed revised tariff, the Company,
intervenors, and FERC staff filed a joint motion in January 1996 for suspension
of the procedural schedule in this docket. On February 1, 1996, the FERC
Administrative Law Judge approved the request for suspension. For a further
discussion of the PJM Interconnection filing, refer to "Power Pool" on page I-3.
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 becomes 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. Currently, 100% of these
margins reduce fuel rates for firm customers.
I-15
<PAGE>
CONSTRUCTION AND FINANCING PROGRAM
Utility construction expenditures for the period 1993-1995, excluding $17
million of AFUDC, and estimated utility construction expenditures for the period
1996-2000, excluding $19 million of AFUDC, are shown in the following table:
<TABLE>
<CAPTION>
CALENDAR YEAR
----------------------------------------------------------------------------
1998-
1993 1994 1995 1996 1997 2000
----------- ----------- ----------- ----------- ----------- -----------
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C>
Electric Facilities:
Production....................... $ 69,100 $ 54,300 $ 45,900 $ 38,600 $ 41,000 $ 123,200
Transmission..................... 17,300 26,400 11,300 16,100 29,000 50,300
Distribution..................... 40,300 37,800 38,800 37,200 45,900 141,900
Gas Facilities..................... 17,000 19,400 15,600 19,400 18,600 58,800
General Facilities................. 16,300 16,200 24,000 23,100 25,000 73,800
----------- ----------- ----------- ----------- ----------- -----------
$ 160,000 $ 154,100 $ 135,600 $ 134,400 $ 159,500 $ 448,000
----------- ----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------- -----------
</TABLE>
Capital requirements for the period 1996-1997 are estimated to be $324
million, including $25 million for maturity of First Mortgage Bonds in 1997 and
$294 million for utility construction, excluding AFUDC. The Company anticipates
that $283 million will be generated internally during 1996-1997, net of power
purchase commitments. This represents 87% of estimated capital requirements and
96% of estimated utility construction expenditures. During this period no
long-term external financings are presently planned.
Capital requirements for the period 1998-2000 are estimated to be $549
million, including $448 million for utility construction, excluding AFUDC, and
$65 million for the maturity of long-term debt. The Company anticipates that
during the period 1998-2000 $467 million will be generated internally, which
represents 85% of estimated capital requirements and 104% of estimated utility
construction expenditures. A portion of the balance of the capital requirements
for 1998-2000 is expected to be provided by the sale of long-term debt. The
Company anticipates that it will be able to obtain these amounts in the capital
markets on competitive terms.
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 unsecured debt is limited by certain provisions in the
Company's Restated Certificate and Articles of Incorporation, as amended (the
Charter), to 20% of the Company's total capitalization excluding unsecured debt.
As of December 31, 1995, these provisions would have permitted the Company to
issue approximately $93 million of additional unsecured debt.
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 Chemical Bank (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, 1995
was 6.09. 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 Charter 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 2.27 for the twelve months ended December 31, 1995.
I-16
<PAGE>
The Company's ratios of earnings to fixed charges and earnings to fixed
charges and preferred dividends under the Securities and Exchange Commission
(SEC) Methods for 1991-1995 are shown below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1995 1994 1993 1992 1991
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed Charges (SEC Method)............................. 3.54 3.49 3.47 3.03 2.58
Ratio of Earnings to Fixed Charges (SEC Method), as Adjusted (1)............ -- 3.74 -- 2.78 --
Ratio of Earnings to Fixed Charges and Preferred Dividends (SEC Method)..... 2.92 2.85 2.88 2.51 2.24
Ratio of Earnings to Fixed Charges and Preferred 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 the lawsuit against PECO in connection with the shutdown of Peach
Bottom 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 and the estimated interest component of rentals. For the ratio
of earnings to fixed charges and preferred dividends, preferred dividends
represent annualized preferred dividend requirements multiplied by the ratio
that pre-tax income bears to net income. Net income and income taxes related to
the cumulative effect of a change in accounting for unbilled revenues recorded
in 1991 are excluded from the computation of these ratios.
For further information on the Company's financing activities, refer to
Notes 10 through 12 to the Consolidated Financial Statements and the "Liquidity
and Capital Resources" section of the MD&A of the 1995 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.
CONSTRUCTION EXPENDITURES
Construction expenditures for compliance with environmental regulations,
primarily the Clean Air Act Amendments of 1990 (The Clean Air Act), are
estimated at $53 million (excluding AFUDC) for the years 1996-2000. These
amounts are included in the Company's estimates of utility construction
expenditures under "Construction and Financing Program" on page I-16.
CLEAN AIR ACT
The Clean Air Act requires utilities and other industries to significantly
reduce emissions of air pollutants such as sulfur dioxide (SO2) 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 SO2 and NOx
emissions from certain utility units by 1995 (Phase I) and required other
utility units to begin reducing SO2 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
I-17
<PAGE>
Company's wholly- and jointly-owned fossil fuel fired units are expected to meet
Phase II emission limits through a combination of fuel switching, FGD,
environmental dispatch and SO2 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 decided to comply with the RACT requirements by undertaking certain
operating changes and installing low NOx burner technology. 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.
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 and Energy (NJDEPE). The estimated capital cost of compliance with
the final permit is approximately $100 million, of which the Company's share is
7.41%. A settlement with challenging parties, other than Delaware, precludes
these parties from arguing that modifications to the plant's cooling water
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 NJDEPE advisory committees regarding plant operations.
PSE&G has informed the Company that it is in the process of securing
additional permits required to implement the operating permit. No assurances can
be given as to the receipt of these additional permits, but PSE&G has reported
that it does not foresee any insurmountable obstacles.
WATER QUALITY REGULATIONS
The Delaware Department of Natural Resources and Environmental Control
(DNREC) and the Maryland Department of the Environment (MDE) promulgated major
changes to water quality regulations in 1993 which emphasize increased control
of toxic pollutants and signal a shift away from technology-based standards. In
developing the regulations, one wastewater discharge from the Indian River Power
Plant was included on a Delaware list of suspected toxic pollutant discharges.
In addition, one discharge from the Vienna Power Plant was added to the Maryland
toxic discharge list by the United States Environmental Protection Agency (EPA).
National Pollutant Discharge Elimination System (NPDES) permit modifications for
each plant are expected in 1996. The costs of complying
I-18
<PAGE>
with the final modified Delaware and Maryland regulations and the resultant
NPDES permit modifications are not expected to have a material effect on the
Company's financial position or results of operations.
The 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 $47 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 currently is a potentially responsible party (PRP) at federal
superfund sites in Philadelphia, Pennsylvania (the Metal Bank/Cottman Avenue
site); Elkton, Maryland (Galaxy/Spectron site); and Jamestown, North Carolina
(the Seaboard Chemical site); and is alleged to be a third-party contributor at
two other federal superfund sites (the Bridgeport Rental and Oil Services site
in Logan Township, New Jersey and the Berks Associates site in Douglassville,
Pennsylvania). Because the Company's imputed share of the potential liabilities
at these sites is small, the Company does not expect its share of the
investigation and clean-up costs at these sites, either separately or
cumulatively, to have a material effect on the Company's financial position or
results of operations.
The Company also has two former coal gasification sites in Delaware
(Wilmington and New Castle) and one former coal gasification site in Maryland
(Cambridge), each of which is a state superfund site.
The Company completed an investigation and risk assessment of the Wilmington
Coal Gasification Site in 1987. Based on the results of that study, which was
submitted to DNREC, the Company determined that the site posed a minimal risk to
human health and the environment. At DNREC's request, in 1994, the Company
completed an updated facility evaluation and risk assessment which reaffirmed
the conclusions of the original study and indicated that there may be
contamination at the site. To gain additional information about the site, the
Company, under Delaware's Voluntary Cleanup Program, has agreed to undertake a
remedial investigation/feasibility study on the northern section of the site and
a feasibility study on the southern section. The completion of these studies
will enable the Company to assess the extent of contamination, review
remediation alternatives, and estimate the cost of cleanup or containment.
In 1994, the 3-acre New Castle site was investigated by DNREC as part of an
investigation of a 41-acre marsh. Low levels of contaminants were found
throughout the marsh. These contaminants could have originated from a number of
sources within the marsh area or from surface runoff from adjacent areas. While
DNREC has indicated that additional investigation of this coal gasification site
may be warranted, it has not directed the Company to undertake such an
investigation.
The Cambridge, Maryland coal gasification site was placed on the state
superfund list in 1984. Although the EPA recommended the site for "no further
action" in 1990, the MDE requested and received funding to undertake an expanded
site assessment (ESA) which was conducted in December 1995 and included sampling
of the adjacent creek and adjacent property. The MDE's report of
I-19
<PAGE>
findings is scheduled for completion in October 1996. At MDE's request, the
Company plans to assess site conditions further in 1996. When the MDE report is
available and the Company's investigation is completed, the Company will be able
to estimate clean-up costs, if any.
The Company has accrued a liability of $2 million for clean-up and other
potential costs related to the above 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.
EMERGING ENVIRONMENTAL ISSUES
An environmental issue that could affect the electric utility industry is
that of potential health risks associated with exposure to electric and magnetic
fields (EMF) from electric transmission lines and other facilities. Studies
present conflicting evidence and inconclusive results. Although no direct link
between EMF and human health has been identified, the Company supports further
research. The outcome of future studies may affect the Company's design,
location, and cost of electric power facilities. However, the Company cannot
predict the outcome of this issue.
Another environmental issue with potential impact on the electric utility
industry is the emission of "greenhouse gases" from generating facilities, in
particular the release of carbon dioxide that has been associated with the
potential for global warming. Despite scientific uncertainties and disagreements
regarding the effects of global warming, the Company is exploring cost-effective
ways to reduce emissions of greenhouse gases, while satisfying its customers'
growing demand for energy. Specific actions include supporting scientific
research, continuing the Company's balanced environmental stewardship/energy
resource plans (refer to the "Energy Supply Plan" on page I-4), use of natural
gas, coal ash recycling, and enhanced energy conservation in the Company's
operations. As part of President Clinton's climate challenge action plan
introduced in October 1993, a climate challenge program was developed. Under
this program, the DOE and electric utilities will explore and promote ways in
which electric utilities can voluntarily reduce, limit, avoid or offset
emissions of carbon dioxide and other greenhouse gases. On February 3, 1995, the
Company signed the Climate Challenge Participation Accord with the U.S. DOE.
Should mandatory emissions limitations or a "carbon tax" be imposed, the
Company's operations could be affected. The Company cannot predict the outcome
of this issue.
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 March 1995, one of
the Company's indirect subsidiaries, Pine Grove Landfill, Inc. (Pine Grove),
which owns and operates a solid waste disposal facility in Pennsylvania, entered
into a consent order and agreement with the Pennsylvania Department of
Environmental Protection (PADEP), which addressed alleged past violations of
state solid waste management and air quality regulations due to odors emanating
from its disposal facility. Pursuant to the terms of the consent order and
agreement, Pine Grove paid a $22,000 civil penalty and the costs of certain
environmental services and facility enhancements. 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 the "Strategic Plans for Competition" section of the MD&A of the
Company's 1995 Annual Report to Stockholders filed as Exhibit 13.
I-20
<PAGE>
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.
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 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.
NUMBER OF EMPLOYEES
The number of full time employees of the Company at December 31, 1995 was
2,527.
A total of 1,457 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, 1996 and June 25, 1997, respectively.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, and positions of all of the executive officers of the
Company as of December 31, 1995 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.
I-21
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
(AS OF DECEMBER 31, 1995)
<TABLE>
<CAPTION>
NAME, AGE AND POSITION BUSINESS EXPERIENCE DURING PAST 5 YEARS
- -------------------------------------------------------- --------------------------------------------------------
<S> <C>
Howard E. Cosgrove, 52.................................. Elected 1992. President and Chief Operating
Chairman of the Board, President, and Officer from 1991 to 1992.
Chief Executive Officer and Director
Joseph W. Ford, 49...................................... Elected 1995. Director, Corporate Re-
Senior Vice President Engineering, Sales & Marketing Worldwide, Digital
Corporation, Boston, Massachusetts, from 1993 to 1994.
Director Business Development United States, Digital
Corporation, Boston, Massachusetts from 1992 to 1993.
Vice President, Sales and Marketing, Asia Region,
Digital Corporation, Hong Kong, from 1991 to 1992.
Barbara S. Graham, 47................................... Elected 1995. Vice President and Chief
Senior Vice President, Treasurer, and Chief Financial Financial Officer from 1992 to 1994. Treasurer from 1987
Officer to 1992.
Ralph E. Klesius, 53.................................... Elected 1992. Vice President, Engineering from
Senior Vice President and Environmental Compliance 1988 to 1992.
Officer
Thomas S. Shaw, 48...................................... Elected 1992. Vice President/President,
Senior Vice President/President, Delmarva Capital Delmarva Capital Investments, Inc. from 1991 to 1992.
Investments, Inc.
Donald E. Cain, 50...................................... Elected 1988.
Vice President, Administration
Paul S. Gerritsen, 50................................... Elected 1993. Vice President and Chief
Vice President Financial Officer from 1987 to 1992.
Wayne A. Lyons, 56...................................... Elected 1990.
Vice President
Frank J. Perry Jr., 52.................................. Elected 1990.
Vice President, Production
Jack Urban, 52.......................................... Elected 1991.
Vice President, Gas Division
James P. Lavin, 48...................................... Elected 1993. Comptroller-Corporate and Chief
Comptroller and Chief Accounting Officer Accounting Officer from 1989 to 1993.
</TABLE>
I-22
<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, 1995.
<TABLE>
<CAPTION>
NET INSTALLED
CAPACITY
STATION LOCATION (KWH)
- ----------------------------------------------- ----------------------------------------------- ----------------
<S> <C> <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................................. 435,000
Vienna....................................... Vienna, MD..................................... 151,000
----------------
586,000
----------------
COMBUSTION TURBINES/COMBINED CYCLE
Hay Road..................................... Wilmington, DE................................. 511,000
----------------
NUCLEAR
Peach Bottom................................. Peach Bottom Twp., PA.......................... 164,000(A)
Salem........................................ Lower Alloways Creek Twp., NJ.................. 164,000(A)
----------------
328,000
----------------
PEAKING UNITS
Christiana................................... Wilmington, DE................................. 45,000
Edge Moor.................................... Wilmington, DE................................. 13,000
Madison Street............................... Wilmington, DE................................. 11,000
West......................................... Marshallton, DE................................ 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
Salem........................................ Lower Alloways Creek Twp., NJ.................. 3,000(A)
Crisfield.................................... Crisfield, MD.................................. 10,000
Bayview...................................... Bayview, VA.................................... 12,000
Keystone..................................... Shelocta, PA................................... 400(A)
Conemaugh.................................... New Florence, PA............................... 400(A)
----------------
182,800
----------------
PURCHASED CAPACITY............................. Delaware City, DE.............................. 48,000
CUSTOMER-OWNED CAPACITY........................ Delaware City, DE.............................. 57,000(B)
----------------
Subtotal.................................................................................... 2,832,800
----------------
PURCHASED PJM INTERCONNECTION CAPACITY CREDITS.................................................. 50,000
----------------
Total....................................................................................... 2,882,800
----------------
----------------
</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-23
<PAGE>
Major transmission and distribution lines owned and in service are as
follows:
<TABLE>
<CAPTION>
VOLTAGE CIRCUIT MILES
- ------------------------------------------------------------ -------------
<S> <C>
Transmission:
500 kilovolts (kV)........................................ 16
230 kV.................................................... 326
138 kV.................................................... 447
69 kV.................................................... 716
Distribution:
34 kV..................................................... 604
25 kV and below........................................... 8,985
</TABLE>
The Company's electric transmission and distribution system includes 1,391
transmission poleline miles of overhead lines, 5 transmission cable miles of
underground cables, 7,123 distribution poleline miles of overhead lines, and
5,268 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................................. 107*
Distribution Mains................................. 1,487
Service Lines...................................... 1,069
</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
As previously reported, in June 1993, the Delaware Coastal Zone Industrial
Control Board adopted regulations (the Regulations) under the Delaware Coastal
Zone Act which would have, among other things, prohibited the Company from
constructing new power-generating facilities or expanding any of its existing
power-generating facilities outside a designated boundary. The Company filed
proceedings in the Delaware Superior Court, and joined with other affected
parties to file a complaint in the Delaware Chancery Court, seeking to have the
Regulations declared null and void. On May 19, 1994, the Chancery Court found
for the Company and the other plaintiffs by declaring the Regulations null and
void on procedural grounds. The proceedings in the Superior Court, which were
suspended pending the outcome in the Chancery Court, are expected to be
dismissed.
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
No matter was submitted during the fourth quarter of the fiscal year covered
by this report to a vote of security holders, through the solicitation of
proxies or otherwise.
I-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 1995 and 1994.
<TABLE>
<CAPTION>
1995 1994
--------------------------------- ---------------------------------
PRICE PRICE
DIVIDEND -------------------- DIVIDEND --------------------
DECLARED HIGH LOW DECLARED HIGH LOW
----------- --------- --------- ----------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
First Quarter............................................ $ .38 1/2 $ 20 $ 17 7/8 $ .38 1/2 $ 23 5/8 $ 20 1/2
Second Quarter........................................... $ .38 1/2 $ 21 1/4 $ 19 1/8 $ .38 1/2 $ 21 $ 16 7/8
Third Quarter............................................ $ .38 1/2 $ 23 $ 19 1/2 $ .38 1/2 $ 20 $ 17 3/4
Fourth Quarter........................................... $ .38 1/2 $ 23 5/8 $ 21 7/8 $ .38 1/2 $ 19 1/4 $ 17 5/8
</TABLE>
The Company had 56,646 registered holders of common stock as of December 31,
1995.
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. For a further discussion of dividends, refer to
the "Dividends" section of the MD&A of the 1995 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 20 of the 1995 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 21 through 28 of the 1995 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 29 through 47 of the 1995 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 25, 1996, 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 25,
1996.
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 25, 1996.
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 1995 Annual Report to Stockholders filed as
Exhibit 13 hereto and incorporated herein by reference.
<TABLE>
<CAPTION>
1995
ANNUAL REPORT
FINANCIAL STATEMENTS (PAGE)
- --------------------------------------------------------------------------------------------------- -------------
<S> <C>
Consolidated Statements of Income for the three years ended December 31, 1995...................... 30
Consolidated Statements of Cash Flows for the three years ended December 31, 1995.................. 31
Consolidated Balance Sheets as of December 31, 1995 and 1994....................................... 32 and 33
Consolidated Statements of Capitalization as of December 31, 1995 and 1994......................... 34
Consolidated Statements of Changes in Common Stockholders' Equity for the three years ended
December 31, 1995................................................................................. 35
Notes to Consolidated Financial Statements......................................................... 36 to 47
</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, 1995 can be found on page IV-3 of this report.
4. Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
- -----------
<C> <S>
2 Stock Purchase Agreement between PECO Energy Company and Delmarva Power & Light Company related to the
acquisition of Conowingo Power Company. (Filed with Form 10-K for the year ended December 31, 1994, File
No. 1-1405.)
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 Copy of the Company's By-Laws as amended September 30, 1993. (Filed with Form 10-K for the year ended
December 31, 1993, File No. 1-1405.)
4-A Copy of the Mortgage and Deed of Trust of Delaware Power & Light Company to the New York Trust Company,
Trustee, (Chemical Bank, successor Trustee) dated as of October 1, 1943 and copies of the First through
Sixty-Eighth Supplemental Indentures thereto. (Filed with Registration Statement No. 33-1763.)
4-B Copy of the Sixty-Ninth Supplemental Indenture. (Filed with Registration Statement No. 33-39756.)
4-C Copies of the Seventieth through Seventy-Fourth Supplemental Indentures. (Filed with Registration
Statement No. 33-24955.)
4-D Copies of the Seventy-Fifth through the Seventy-Seventh Supplemental Indentures. (Filed with
Registration Statement No. 33-39756.)
4-E Copies of the Seventy-Eighth and Seventy-Ninth Supplemental Indentures. (Filed with Registration
Statement No. 33-46892.)
4-F Copy of the Eightieth Supplemental Indenture. (Filed with Registration Statement No. 33-49750.)
</TABLE>
IV-1
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
- -----------
4-G Copy of the Eighty-First Supplemental Indenture. (Filed with Registration Statement No. 33-57652.)
<C> <S>
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.)
10-A Copy of the Management Incentive Compensation Plan amended and restated as of January 1, 1992. (Filed
with Form 10-K for the year ended December 31, 1991, File No. 1-1405.)
10-B Copy of an amendment to the Management Incentive Compensation Plan adopted by the Board of Directors on
January 28, 1993, effective as of January 1, 1993. (Filed with Form 10-K for the year ended December 31,
1992, File No. 1-1405.)
10-C 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-D 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-E Copy of the Long Term Incentive Plan amended and restated as of January 1, 1992. (Filed with Form 10-K
for the year ended December 31, 1991, File No. 1-1405.)
10-F Copy of an amendment to the Long Term Incentive Plan adopted by the Board of Directors on January 28,
1993, effective as of January 1, 1993. (Filed with Form 10-K for the year ended December 31, 1992, File
No. 1-1405.)
10-G 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-H Copy of the current listing of members of management who have signed the severance agreement.
10-I Copy of the Management Life Insurance Plan amended and restated as of January 1, 1992. (Filed with Form
10-K for the year ended December 31, 1991, File No. 1-1405.)
10-J Copy of the Deferred Compensation Plan, effective as of January 1, 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 1995 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):
A Report on Form 8-K dated October 20, 1995, updating matters related to
Salem Units 1 and 2 previously reported, was filed with the Commission.
A Report on Form 8-K dated December 15, 1995, updating matters related to
Salem Units 1 and 2 previously reported, was filed with the Commission.
A Report on Form 8-K dated February 22, 1996, updating matters related to
Salem Units 1 and 2 previously reported, was filed with the Commission.
IV-2
<PAGE>
DELMARVA POWER & LIGHT COMPANY
SCHEDULE OF OPERATING STATISTICS
FOR THE THREE YEARS ENDED DECEMBER 31, 1995
The table below sets forth selected financial and operating statistics for
the electric and gas divisions for the three years ended December 31, 1995.
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
ELECTRIC:
Electricity generated and purchased (MWh):
Generated............................................................ 10,797,547 11,581,929 11,264,540
Purchased............................................................ 3,977,867 3,766,169 3,857,133
Interchange deliveries............................................... (1,862,467) (2,220,898) (2,225,384)
----------- ----------- -----------
Total output for load.............................................. 12,912,947 13,127,200 12,896,289
----------- ----------- -----------
----------- ----------- -----------
Electric sales (MWh):
Residential.......................................................... 3,829,807 3,578,743 3,499,387
Commercial........................................................... 3,744,879 3,461,058 3,336,847
Industrial........................................................... 3,351,834 3,248,131 3,232,233
Resale............................................................... 1,213,459 2,166,154 2,131,920
Other sales (1)...................................................... 170,942 50,996 79,843
----------- ----------- -----------
Total sales........................................................ 12,310,921 12,505,082 12,280,230
Losses and miscellaneous system uses................................... 602,026 622,118 616,059
----------- ----------- -----------
Total disposition of energy.......................................... 12,912,947 13,127,200 12,896,289
----------- ----------- -----------
----------- ----------- -----------
Operating revenue (thousands):
Residential.......................................................... $344,351 $312,224 $305,446
Commercial........................................................... 267,239 242,506 237,785
Industrial........................................................... 155,108 145,594 150,178
Resale............................................................... 58,680 105,350 104,983
Other sales revenues (2)............................................. 14,211 6,816 9,716
Interchange deliveries............................................... 47,271 62,388 61,437
Miscellaneous revenues............................................... 12,802 8,237 6,118
----------- ----------- -----------
Total revenues..................................................... $899,662 $883,115 $875,663
----------- ----------- -----------
----------- ----------- -----------
Number of customers (end of period):
Residential.......................................................... 386,948 347,997 342,710
Commercial........................................................... 48,345 44,060 43,324
Industrial........................................................... 704 699 715
Resale............................................................... 12 12 12
Other................................................................ 641 604 593
----------- ----------- -----------
Total customers.................................................... 436,650 393,372 387,354
----------- ----------- -----------
----------- ----------- -----------
Average annual use per residential customer (kWh) (3).................. 10,365 10,359 10,336
Average annual revenue per residential customer (3).................... $931.95 $903.74 $902.14
Average revenue per kWh (cents):
Residential.......................................................... 9.0 8.7 8.7
Commercial........................................................... 7.1 7.0 7.1
Industrial........................................................... 4.6 4.5 4.7
GAS:
Gas sales (Mcf)........................................................ 18,478 18,087 18,066
Gas transported (Mcf).................................................. 2,893 2,255 1,539
Gas revenue (thousands)................................................ $95,441 $107,906 $94,944
Number of customers (end of period):
Residential.......................................................... 90,890 88,518 86,027
Commercial........................................................... 7,369 6,982 6,751
Industrial........................................................... 146 150 150
Interruptible and other.............................................. 12 12 12
----------- ----------- -----------
Total customers.................................................... 98,417 95,662 92,940
----------- ----------- -----------
----------- ----------- -----------
Residential gas service:
Average annual use per customer (Mcf) (3)............................ 81.75 88.55 86.85
Average annual revenue per customer (3).............................. $525.87 $632.11 $558.59
Average revenue per Mcf.............................................. $6.43 $7.14 $6.43
</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.
<TABLE>
<S> <C> <C>
DELMARVA POWER & LIGHT COMPANY
(REGISTRANT)
Dated: March 26, 1996 By /s/BARBARA S. GRAHAM
-----------------------------------------
(BARBARA S. GRAHAM, SENIOR VICE PRESIDENT,
TREASURER, AND CHIEF FINANCIAL OFFICER)
</TABLE>
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.
<TABLE>
<C> <S> <C>
SIGNATURE TITLE DATE
- ------------------------------------------------------ ------------------------------------- ------------------
/s/ HOWARD E. COSGROVE Chairman of the Board, President,
------------------------------------------- Chief Executive Officer, and March 26, 1996
(HOWARD E. COSGROVE) Director
/s/ BARBARA S. GRAHAM
------------------------------------------- Senior Vice President, Treasurer, and March 26, 1996
(BARBARA S. GRAHAM) Chief Financial Officer
/s/ JAMES P. LAVIN
------------------------------------------- Comptroller and Chief Accounting March 26, 1996
(JAMES P. LAVIN) Officer
/s/ MICHAEL G. ABERCROMBIE
------------------------------------------- Director March 26, 1996
(MICHAEL G. ABERCROMBIE)
/s/ R. FRANKLIN BALOTTI
------------------------------------------- Director March 26, 1996
(R. FRANKLIN BALOTTI)
/s/ ROBERT D. BURRIS
------------------------------------------- Director March 26, 1996
(ROBERT D. BURRIS)
/s/ AUDREY K. DOBERSTEIN
------------------------------------------- Director March 26, 1996
(AUDREY K. DOBERSTEIN)
/s/ M. B. EMERY
------------------------------------------- Director March 26, 1996
(MICHAEL B. EMERY)
/s/ J. H. GILLIAM, JR.
------------------------------------------- Director March 26, 1996
(JAMES H. GILLIAM, JR.)
/s/ SARAH I. GORE
------------------------------------------- Director March 26, 1996
(SARAH I. GORE)
------------------------------------------- Director
(JAMES C. JOHNSON)
/s/ WESTON E. NELLIUS
------------------------------------------- Director March 26, 1996
(WESTON E. NELLIUS)
</TABLE>
IV-4
<PAGE>
DELMARVA POWER & LIGHT COMPANY
1995 ANNUAL REPORT ON FORM 10-K
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ----------- --------------------------------------------------------------------------------------------------------
<S> <C>
10-H Copy of the current listing of members of management who have signed the severance agreement.
10-J Copy of 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 1995 Annual Report to Stockholders which are incorporated by reference in this
Form 10-K.
23 Consent of Independent Accountants.
27 Financial Data Schedule.
</TABLE>
<PAGE>
DELMARVA POWER & LIGHT COMPANY
1995 FORM 10-K
CURRENT LISTING OF SEVERANCE AGREEMENTS
AS OF MARCH 1, 1996
-------------------
<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 W. Land General Manager, Administrative Services 04/19/94
23. James P. Lavin Comptroller/Corporate Accounting 05/22/89
24. Wayne A. Lyons Vice President 02/11/87
25. D. Bruce McClenathan Plant Manager (Delaware City) 02/11/87
26. Dennis R. McDowell Comptroller/Operating Accounting 05/22/89
27. Robert F. Molzahn General Manager, Environmental Affairs 05/22/89
28. James L. Parks Manager, Fuel Supply 05/07/93
29. Frank J. Perry, Jr. Vice President 03/14/90
30. Linda D. Ratchford Manager, Product Development 01/23/96
31. Michael Ratchford General Manager, Communication and Community Relations 09/14/95
32. Philip S. Reese General Manager, Marketing 03/01/95
33. Richard W. Sarau Plant Manager (Hay Road) 03/01/95
34. Mark H. Schneider Manager, Solid Waste Group 05/07/93
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 System Engineering 01/23/96
41. Jack Urban Vice President, Gas Division 01/27/91
42. George G. Vapaa Manager, Corporate Planning 03/25/91
43. Joseph M. Wathen Manager, Pricing 04/08/94
44. N. Guy Winebrenner Manager, Sales 01/23/96
45. James R. Wittine General Manager, System Planning 05/07/93
46. Jeremiah F. Wright, Jr. General Manager, Purchasing 03/14/90
47. D. Wayne Yerkes Vice President, Northern Division 03/14/90
48. John T. Zimmerman Manager, Employee Relations 03/25/91
</TABLE>
<PAGE>
Exhibit 10-J
DELMARVA POWER & LIGHT COMPANY
DEFERRED COMPENSATION PLAN
(Effective January 1, 1996)
<PAGE>
DELMARVA POWER & LIGHT COMPANY
DEFERRED COMPENSATION PLAN
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
-----
<S> <C>
ARTICLE I - PURPOSE . . . . . . . . . . . . . . . . . . . . . . . 1
1.1. Name . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2. Effective Date . . . . . . . . . . . . . . . . . . . . 1
1.3. Employers. . . . . . . . . . . . . . . . . . . . . . . 1
1.4. Purpose. . . . . . . . . . . . . . . . . . . . . . . . 1
ARTICLE II - DEFINITIONS. . . . . . . . . . . . . . . . . . . . . 2
ARTICLE III - PARTICIPATION BY ELIGIBLE EMPLOYEES . . . . . . . . 8
3.1. Participation. . . . . . . . . . . . . . . . . . . . . 8
3.2. Failure to Designate . . . . . . . . . . . . . . . . . 9
3.3. Continuity of Participation. . . . . . . . . . . . . . 9
3.4. Immediate Cash-Out of Ineligible Employee. . . . . . . 9
ARTICLE IV - COMPENSATION DEFERRAL. . . . . . . . . . . . . . . . 10
4.1. Salary, Bonus, and/or Dividend Deferral
Election. . . . . . . . . . . . . . . . . . . . . . . 10
4.2. Deferral of LTIP Shares. . . . . . . . . . . . . . . . 11
4.3. Period for Which Deferral Election is
Effective . . . . . . . . . . . . . . . . . . . . . . 11
ARTICLE V - EMPLOYER MATCHING CREDIT. . . . . . . . . . . . . . . 12
5.1. Employer Matching Credit . . . . . . . . . . . . . . . 12
5.2. Employer Matching Credit for Limited
Participant . . . . . . . . . . . . . . . . . . . . . 13
ARTICLE VI - DISTRIBUTIONS. . . . . . . . . . . . . . . . . . . . 13
6.1. Election of Distribution Date. . . . . . . . . . . . . 13
6.2. Election of Method of Payment. . . . . . . . . . . . . 14
6.3. Unforeseeable Emergency. . . . . . . . . . . . . . . . 15
6.4. Special Election for Early Distribution. . . . . . . . 16
6.5. Distributions on Death . . . . . . . . . . . . . . . . 17
6.6. Acceleration of Payments . . . . . . . . . . . . . . . 18
6.7. Valuation of Distributions . . . . . . . . . . . . . . 18
ARTICLE VII - FORFEITURE FOR CAUSE. . . . . . . . . . . . . . . . 19
7.1. Forfeiture for Cause . . . . . . . . . . . . . . . . . 19
</TABLE>
-i-
<PAGE>
<TABLE>
<CAPTION>
Page
-----
<S> <C>
ARTICLE VIII - ACCOUNTS . . . . . . . . . . . . . . . . . . . . . 20
8.1. Deferred Compensation Account. . . . . . . . . . . . . 20
8.2. Deferred Stock Account . . . . . . . . . . . . . . . . 20
8.3. Employer Matching Account. . . . . . . . . . . . . . . 21
8.4. Crediting of Earnings and Losses, and
Statement of Account. . . . . . . . . . . . . . . . . 22
8.5. Investment to Facilitate Payment of
Benefits. . . . . . . . . . . . . . . . . . . . . . . 23
ARTICLE IX - FUNDING. . . . . . . . . . . . . . . . . . . . . . . 24
9.1. Deferred Compensation Plan Unfunded. . . . . . . . . . 24
ARTICLE X - ADMINISTRATION AND INTERPRETATION . . . . . . . . . . 25
10.1. Administration . . . . . . . . . . . . . . . . . . . . 25
10.2. Interpretation . . . . . . . . . . . . . . . . . . . . 25
10.3. Records and Reports. . . . . . . . . . . . . . . . . . 26
10.4. Payment of Expenses. . . . . . . . . . . . . . . . . . 27
10.5. Indemnification for Liability. . . . . . . . . . . . . 28
10.6. Claims Procedure . . . . . . . . . . . . . . . . . . . 28
10.7. Review Procedure . . . . . . . . . . . . . . . . . . . 29
ARTICLE XI - AMENDMENT AND TERMINATION. . . . . . . . . . . . . . 29
11.1. Amendment and Termination. . . . . . . . . . . . . . . 29
11.2. Deemed Amendment to Matching Formula . . . . . . . . . 31
ARTICLE XII - MISCELLANEOUS PROVISIONS. . . . . . . . . . . . . . 31
12.1. Right of Employers to Take Employment
Actions . . . . . . . . . . . . . . . . . . . . . . . 31
12.2. Alienation or Assignment of Benefits . . . . . . . . . 32
12.3. Right to Withhold. . . . . . . . . . . . . . . . . . . 32
12.4. Construction . . . . . . . . . . . . . . . . . . . . . 32
12.5. Headings . . . . . . . . . . . . . . . . . . . . . . . 33
12.6. Number and Gender. . . . . . . . . . . . . . . . . . . 33
12.7. Change in Control. . . . . . . . . . . . . . . . . . . 33
</TABLE>
-ii-
<PAGE>
DELMARVA POWER & LIGHT COMPANY
DEFERRED COMPENSATION PLAN
(Effective January 1, 1996)
ARTICLE I
PURPOSE
1.1. NAME. The name of this plan is the Delmarva Power & Light
Company Deferred Compensation Plan (hereinafter referred to as the "Deferred
Compensation Plan.")
1.2. EFFECTIVE DATE. The effective date of this Deferred
Compensation Plan is January 1, 1996.
1.3. EMPLOYERS. Delmarva Power & Light Company ("Delmarva") and
each subsidiary or affiliate of Delmarva that employs one or more Eligible
Employees who have become Participants in accordance with Article III, shall
each be an "Employer" under this Deferred Compensation Plan.
1.4. PURPOSE. This Deferred Compensation Plan is established
effective January 1, 1996 by Delmarva for the purposes of providing
supplemental retirement and deferred compensation benefits for a select group
of management and/or highly compensated employees of the Employer.
This Deferred Compensation Plan (i) provides a means whereby
Participants may defer a portion or all of their compensation in the form of
salary and/or bonus they would otherwise receive for services performed for
the Employer, (ii) provides participants in the Delmarva Power & Light
Company Long-Term Incentive Plan (the "LTIP") with the ability to defer
receipt of a portion or all of the performance-based restricted
<PAGE>
shares of Delmarva's common stock awarded under the LTIP, (iii) provides
participants in the Delmarva Power & Light Company Savings and Thrift Plan
(the "Savings Plan") with the ability to defer compensation that would be
deferred and eligible for matching contributions under the Savings Plan but
for the applications of Sections 401(a)(17), 401(m), 402(g) and/or 415 of the
Internal Revenue Code of 1986, as amended (the "Code"), and provides such
Savings Plan participants with a matching contribution similar to that which
would be made under the Savings Plan but for the application of certain
restrictions contained in the Code.
ARTICLE II
DEFINITIONS
Whenever the following initially capitalized words and phrases are
used in this Deferred Compensation Plan, they shall have the meanings
specified below unless the context clearly indicates to the contrary:
2.1. "ADMINISTRATOR" shall mean the Vice President of
Administration of Delmarva (or any successor to such position), or his
delegate.
2.2. "APPLICATION FOR PARTICIPATION" shall mean a document (or
documents) as made available from time to time by the Administrator, whereby
an Eligible Employee enrolls as a
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Participant and elects to defer Compensation pursuant to Article IV of this
Deferred Compensation Plan.
2.3. "BENEFICIARY" shall mean such person or legal entity as may
be designated by a Participant under Section 6.5 to receive benefits
hereunder after such Participant's death.
2.4. "BOARD" shall mean the Board of Directors of Delmarva, as
constituted from time to time.
2.5. "CHANGE IN CONTROL" shall be deemed to have occurred upon the
earliest to occur of the following:
(a) any Person is or becomes the beneficial owner, directly
or indirectly, of securities of an Employer (not including in the securities
beneficially owned by such Person any securities acquired directly from the
Employer or its subsidiaries) representing 25% or more of either the
then-outstanding shares of common stock of the Employer or the combined
voting power of the Employer's then-outstanding securities; or
(b) the following individuals cease for any reason to
constitute a majority of the number of directors then serving: individuals
who, on the effective date of this Plan, constitute the Board and any new
director (other than a director whose initial assumption of office is in
connection with an actual or threatened election contest, including but not
limited to a consent solicitation, relating to the election of directors of
the Employer) whose appointment or election by the Board or
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nomination for election by the Employer's stockholders was approved by a vote
of at least two-thirds (2/3) of the directors then still in office who either
were directors on the effective date of this Plan or whose appointment,
election or nomination for election was previously so approved; or
(c) there is consummated a merger or consolidation of the
Employer with any other corporation other than (i) a merger or consolidation
which would result in the voting securities of the Employer outstanding
immediately prior to such merger or consolidation continuing to represent
(either by remaining outstanding or by being converted into voting securities
of the surviving entity or any parent thereof) at least 75% of the combined
voting power of the voting securities of the Employer or such surviving
entity or any parent thereof outstanding immediately after such merger or
consolidation, or (ii) a merger or consolidation effected to implement a
recapitalization of the Employer (or similar transaction) in which no Person
is or becomes the beneficial owner, directly or indirectly, of securities of
the Employer (not including in the securities beneficially owned by such
Person any securities acquired directly from the Employer or its
subsidiaries) representing 25% or more of either the then-outstanding shares
of common stock of the Employer or the combined voting power of the
Employer's then-outstanding securities; or
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(d) the stockholders of the Employer approve a plan of
complete liquidation or dissolution of the Employer or there is consummated
an agreement for the sale or disposition by the Employer of all or
substantially all of the Employer's assets to an entity, at least 75% of the
combined voting power of the voting securities of which are owned by Persons
in substantially the same proportions as their ownership of the Employer
immediately prior to such sale.
(e) For purposes of this Section, the term "beneficial owner"
or "beneficial ownership" shall have the same meaning as under Rule 13d-3
under the Exchange Act, and the term "Person" shall have the meaning given in
Section 3(a)(9) of the Exchange Act, as modified and used in Sections 13(d)
and 14(d) thereof, except that such term shall not include (i) Delmarva or
any of its subsidiaries, (ii) a trustee or other fiduciary holding securities
under an employee benefit plan of Delmarva or any of its subsidiaries, (iii)
an underwriter temporarily holding securities pursuant to an offering of such
securities, or (iv) a corporation owned directly or indirectly by the
stockholders of the Employer in substantially the same proportions as their
ownership of stock of the Employer.
2.6. "COMMITTEE" shall mean the Compensation Committee of the
Board.
2.7. "COMPENSATION" shall mean the base salary of a Participant
for a Plan Year (before any reduction to such salary
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is effected in accordance with the Application for Participation, or in
accordance with any salary reduction agreement effected under the terms of
Sections 125 or 401(k) of the Code); plus the amount of bonus, if any, earned
by a Participant during the Plan Year under the Delmarva Power & Light
Company Management Incentive Compensation Plan (the "MICP"). To the extent a
Participant elects to defer cash awarded to him on account of dividends 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, such cash dividend equivalents also
shall be considered Compensation subject to deferral under this Plan.
2.8. "DEFERRED COMPENSATION" shall mean that portion of the
Participant's Compensation which the Participant elects to defer pursuant to
Section 4.1 of this Deferred Compensation Plan in accordance with an
Application for Participation.
2.9. "DEFERRED COMPENSATION ACCOUNT" shall mean the bookkeeping
account established by the Administrator for each Participant to which the
Participant's base salary and MCIP bonus 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 debited. A Participant shall at
all times be fully vested in the balance of his Deferred Compensation Account.
2.10. "DEFERRED STOCK" shall mean shares of stock conditionally
granted to a Participant under LTIP, which shares
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may vest no earlier than the last day of the calendar year after a Plan Year
in which the Participant elects to defer receipt of such shares pursuant to
Section 4.2, plus cash dividend equivalents described in Section 2.8 and
credited to a Participant's Deferred Stock Account pursuant to Section 8.2.
2.11. "DEFERRED STOCK ACCOUNT" shall mean the bookkeeping account
established by the Administrator for each Participant to which the
Participant's Deferred Stock is credited and from which distributions of
Deferred Stock to the Participant or to his or her Beneficiary are debited.
A Participant shall at all times be fully vested in the balance of his
Deferred Stock Account, except to the extent LTIP shares have not yet vested
under the terms of LTIP.
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.
2.13. "EMPLOYER MATCHING ACCOUNT" shall mean the bookkeeping
account established by the Administrator for a Participant to which the
Participant's Employer Matching Credit (and income thereon) is credited and
from which distributions to the Participant or his or her Beneficiary are
debited. A Participant shall be fully vested in the balance of his Employer
Matching Account, except as provided in Section 7.1.
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2.14. "EMPLOYER MATCHING CREDIT" shall mean an amount credited (if
any) to the Participant's Employer Matching Account pursuant to Section 5.1
of this Deferred Compensation Plan.
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, the only Investment Alternative shall be Delmarva
common stock as traded on the open market.
2.16. "PARTICIPANT" shall mean an Eligible Employee designated as
a Participant by the Committee and who has amounts standing to his credit
under a Deferred Compensation Account, a Deferred Stock Account, or a
Employer Matching Account. The Committee may designate an Eligible Employee
as a Participant for purposes of part, but not all, of the Deferred
Compensation Plan.
2.17. "PLAN YEAR" shall mean the calendar year.
ARTICLE III
PARTICIPATION BY ELIGIBLE EMPLOYEES
3.1. PARTICIPATION. Participation in this Deferred Compensation
Plan is limited to Eligible Employees. An Eligible Employee shall
participate in the Deferred Compensation Plan as determined by the Committee
in its sole discretion; provided,
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however, that for purposes of employees who first become Eligible Employees
during a Plan Year, such Eligible Employees shall participate in the Plan as
determined by the Administrator in his sole discretion.
3.2. FAILURE TO DESIGNATE. In the event that the Committee fails
to designate the group of Eligible Employees who shall be eligible to
participate for any year, each Eligible Employee who was designated in the
prior year shall be deemed to have been designated for the next succeeding
Plan Year, provided that any such employee shall participate for purposes of
the next succeeding Plan Year only if he or she is actively employed by an
Employer on the first day of such succeeding Plan Year and provided he or she
is an Eligible Employee for such year; and provided further that such
participation shall be limited, if at all, as set forth in Section 2.12.
3.3. CONTINUITY OF PARTICIPATION. A Participant who separates
from service with all of the Employers will cease active participation
hereunder. However, the separation from service of an Eligible Employee with
one Employer will not interrupt the continuity of his or her active
participation if, concurrently with or immediately after such separation, he
or she is employed by one or more of the other Employers.
3.4. IMMEDIATE CASH-OUT OF INELIGIBLE EMPLOYEE. This Deferred
Compensation Plan is intended to be an unfunded "top-hat" plan, maintained
primarily for the purpose of providing
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deferred compensation for a select group of management or highly compensated
employees. Accordingly, if the Committee determines that any Participant
does not qualify as a member of the select group, one hundred percent (100%)
of such Participant's Deferred Compensation Account and/or Employer Matching
Account shall be paid to the Participant immediately, the vested portion of
such Participant's Deferred Stock Account shall be paid to the Participant
immediately, and the unvested portion shall be returned to the LTIP.
ARTICLE IV
COMPENSATION DEFERRAL
4.1. SALARY, BONUS, AND/OR DIVIDEND 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, 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.
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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.
- ---------------------------------------------------------------------
</TABLE>
In the case of deferral of base salary, a Participant may not defer base
salary in excess of 10% of base pay reduced by the limit in effect under Code
Section 402(g) for the Plan Year.
4.2. DEFERRAL OF LTIP SHARES. At any time prior to the last year
of the performance cycle by which performance under LTIP is measured, a
Participant can elect to defer the receipt of shares which otherwise would be
delivered to the Participant after such last year, based upon performance
during the performance cycle applicable to such shares.
4.3. PERIOD FOR WHICH DEFERRAL ELECTION IS EFFECTIVE.
<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
- ---------------------------------------------------------------------
</TABLE>
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ARTICLE V
EMPLOYER MATCHING CREDITS
5.1. EMPLOYER MATCHING CREDIT. The amount of the Employer
Matching Credit credited to the Employer Matching Account of each Eligible
Employee designated as eligible to participate in this Section 5.1 shall be
equal to the "Company-Matching Contributions" which would have been made to
the Participant's "Thrift Fund Account" under the Savings Plan but for
certain statutory limitations. Generally, the Employer Matching Credit shall
be equal to the "matching percentage" (50%, as of the effective date of this
Plan) set forth in the Savings Plan, multiplied by the first 5% of the
Participant's base salary in excess of the Code Section 401(a)(17) limit that
is deferred under Section 4.1. In the event the dollar amount of the
"Company-Matching Contributions" under the Savings Plan for the Plan Year was
limited due to the application of the provisions of Section 401(m) of the
Code, or the percentage of the Participant's base salary that could be
deferred under the Savings Plan was limited to an amount less than 5% because
of other Code limitations, an additional Employer Matching Credit shall be
contributed under this Plan equal to the amount of "Company-Matching
Contributions" that would have been made to the Savings Plan but for such
limitations, but only if and to the extent the Participant has deferred
additional amounts of base salary to this Plan at least equal to the amount
that would have been required to have been
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deferred under the Savings Plan in order to support such additional
"Company-Matching Contributions" in the absence of such limitations.
5.2. EMPLOYER MATCHING CREDIT FOR LIMITED PARTICIPANT. For any
Participant whose right to receive "Company-Matching Contributions" under the
Savings Plan is limited by a specific Savings Plan provision to $10 or less
(without regard to the amount of salary deferrals elected by such
Participant), the Employer Matching Credit shall be equal to the matching
percentage described in Section 5.1, multiplied by the first 5% of the
Participant's base salary that is deferred under Section 4.1.
ARTICLE VI
DISTRIBUTIONS
6.1. ELECTION OF DISTRIBUTION DATE. At the time a Participant
makes an election to defer Compensation under Article IV, such Participant
shall also specify in writing on the Application for Participation the date
on which payment of the Deferred Compensation Account, the Deferred Stock
Account, and the Employer Matching Account attributable to that Application
for Participation shall be made or commence. Such date shall be any of the
following:
(a) a specified date not less than two years from the end of
the Plan Year of the deferral; or
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(b) a date occurring within a specific number of calendar
days (not less than 15) after a specified event occurs (which event is not
reasonably expected to occur within the two years following the Plan Year of
the deferral); such as, the date the Participant terminates employment with
the Employer, or the date Delmarva's common stock price reaches a specified
level (which must be at least 10% above the stock price as of the date of
deferral).
Except as set forth hereinafter, the above distribution date, once
elected by the Participant, shall be irrevocable.
6.2. ELECTION OF METHOD OF PAYMENT. At the time a Participant
makes an election to defer Compensation under Section 4.1, such Participant
may also specify in writing on the Application for Participation the method
by which payment of the Deferred Compensation Account and the Employer
Matching Account attributable to that Application for Participation shall be
made. Such election must specify a payment method if the distribution date is
determined by an event as described in Section 6.1(b). If a payment method is
not specified in the election, or if a payment method is specified but a
Participant wishes to change the payment method, a change of election or new
election may be effective only if submitted to the Administrator no later
than the last day of the calendar year that ends at least one year before the
distribution date, and subject to approval by the Committee.
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<PAGE>
A payment method shall be in the form of a lump sum payment, in
annual installments, or in any other method approved by the Committee. In
the absence of a valid election, distribution of accounts shall be in the
form of annual installments over a 10-year period. Except as set forth
herein, the form of payment, once elected by the Participant, shall be
irrevocable.
Distribution of a Participant's Company Matching Account shall be
paid in 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.
6.3. UNFORESEEABLE EMERGENCY. The Committee shall have the
authority to determine, in its sole discretion, that payments should be made
in any manner the Committee deems appropriate, in whole or in part, on any
other date or dates in order to alleviate a financial hardship of a
Participant or a Beneficiary. "Financial hardship" shall mean a severe
financial hardship resulting from a sudden and unexpected illness or
accident of the Participant or Beneficiary, or of a dependent (as defined in
Section 152(a) of the Code) of the Participant or
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<PAGE>
Beneficiary, loss of the Participant's or Beneficiary's property due to
casualty, or other similar extraordinary and unforeseeable circumstances
arising as a result of events beyond the control of the Participant or
Beneficiary. The circumstances that will constitute an unforeseeable
emergency will depend on the facts of each case, but, in any case, payment
may not be made to the extent that such hardship is or may be relieved (i)
through reimbursement or compensation by insurance or otherwise, (ii) by
liquidation of the Participant's or Beneficiary's assets, to the extent such
liquidation would not itself cause severe financial hardship, and (iii) by
cessation of deferrals under the Deferred Compensation Plan. Any financial
hardship distribution approved by the Committee shall be limited to the
amount necessary to meet the emergency (including taxes that are expected to
be imposed on the distribution), and shall be made solely from the Deferred
Compensation Account and/or the vested portion of the Deferred Stock Account.
6.4. SPECIAL ELECTION FOR EARLY DISTRIBUTION. A Participant may
apply to the Administrator for early distribution of all or any part of his
Deferred Compensation Account and/or the vested portion of his Deferred Stock
Account. Such early distribution shall be made in a single lump sum and (for
the Deferred Stock Account) in shares of Delmarva stock, provided that 10% of
the amount withdrawn in such early distribution shall be forfeited prior to
payment of the remainder to the
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Participant. A Participant may not elect an early distribution hereunder if
he has received an early distribution or hardship distribution within the
previous twelve months. In the event a Participant's early distribution
election is submitted within 60 days after a Change in Control or an
elimination of Investment Alternatives that the Committee determines is a
substantial detriment to Participants, the early distribution election may
include amounts credited to the Employer Matching Account, and the forfeiture
penalty shall be reduced to 5%.
6.5. DISTRIBUTIONS ON DEATH. In the event of a Participant's
death before his or her Deferred Compensation Account, Deferred Stock
Account, and/or Employer Matching Account has been fully distributed,
distribution(s) shall be made to the Beneficiary selected by the Participant,
in a single lump sum and (for the Deferred Stock Account) in shares of
Delmarva stock, within 60 days after the Administrator receives notice of the
date of death (or, if later, after the proper Beneficiary has been
identified). A Participant may from time to time change his or her
designated Beneficiary without the consent of such Beneficiary by filing a
new designation in writing with the Administrator. If no Beneficiary
designation is in effect at the time of the Participant's death, or if the
designated Beneficiary is missing or has predeceased the Participant, payment
shall be made to the Participant's surviving spouse, or if none, to his
surviving children per stirpes, or, if none, to his estate.
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<PAGE>
6.6. ACCELERATION OF PAYMENTS. Notwithstanding any other
provision of this Deferred Compensation Plan to the contrary, the Committee,
in its sole discretion, is empowered to accelerate the payment of a
Participant's Deferred Compensation Account, Deferred Stock Account, and/or
Employer Matching Account, before or after any termination of employment,
including conversion to a smaller number of installment payments or to a
single lump sum payment, for any reason the Committee may determine to be
appropriate without premium or penalty. None of the Employers, the Committee
nor the Board shall have any obligation to make any such acceleration for any
reason whatsoever.
6.7. VALUATION OF DISTRIBUTIONS. All account distributions under
this Deferred Compensation Plan shall be (a) based upon the value of the
Participant's Deferred Compensation Account as of the Investment Alternative
valuation date immediately preceding the date of the distribution; or (b)
paid in the form of Delmarva stock or, where otherwise permitted under the
Plan, such stock may be converted to cash at the fair market price of such
stock as of the immediately preceding trading day. It is understood that
administrative requirements may lead to a delay between such valuation date
or trading day and the date of distribution, not to exceed five business days.
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ARTICLE VII
FORFEITURE FOR CAUSE
7.1. FORFEITURE FOR CAUSE. If any Participant entitled to a
Employer Matching Credit under this Deferred Compensation Plan is discharged
for cause, or enters into competition with an Employer, or interferes with
the relations between an Employer and any customer, or engages in any
activity that would result in material damage to an Employer as determined in
the sole discretion of the Committee, the rights of such Participant to a
Employer Matching Credit under this Deferred Compensation Plan, including the
rights of a Beneficiary to such benefits, will be forfeited, unless the
Committee determines that such activity is not detrimental to the best
interests of the Employer. However, if the individual ceases such activity
and notifies the Committee of this cessation, then the Participant's right to
receive such benefits, and any right of a Beneficiary to such benefits, may
be restored if the Committee in its sole discretion determines that the prior
activity has not caused serious injury to the Employer and that the
restoration of the benefits would be in the best interest of the Employer.
All determinations by the Committee with respect to forfeiture or restoration
of such benefits shall be final and conclusive.
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<PAGE>
ARTICLE VIII
ACCOUNTS
8.1. DEFERRED COMPENSATION ACCOUNT. The Administrator shall
establish and maintain, or cause to be established and maintained, a separate
Deferred Compensation Account for each Participant hereunder who executes an
election pursuant to Section 4.1. Each such Participant's Compensation
deferred pursuant to an Application for Participation under Section 4.1 shall
be separately accounted for and credited, for bookkeeping purposes only, to
his or her Deferred Compensation Account. A Participant's Deferred
Compensation Account shall be solely for the purposes of measuring certain
amounts to be paid under the Deferred Compensation Plan, and Delmarva shall
not be required to fund or secure the Account in any way, Delmarva's
obligation to Participants hereunder being purely contractual.
8.2. DEFERRED STOCK ACCOUNT. The Administrator shall establish
and maintain, or cause to be established and maintained, a separate Deferred
Stock Account for each Participant hereunder who executes an election
pursuant to Section 4.2 or who elects to defer dividend equivalents under
Section 4.1. Each such Participant's LTIP shares deferred pursuant to an
Application for Participation under Section 4.2 shall be separately accounted
for and credited, for bookkeeping purposes only, to his or her Deferred Stock
Account. A Participant's Deferred Stock Account shall be solely for the
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purposes of measuring certain amounts to be paid under the Deferred
Compensation Plan, and Delmarva shall not be required to fund or secure the
Account in any way, Delmarva's obligation to Participants hereunder being
purely contractual. The Deferred Stock Account shall be credited with shares
conditionally granted to the Participant at the beginning of each LTIP cycle
(or as of the effective date of the election under Section 4.2, if later), to
the extent receipt of such shares has been deferred pursuant to an election
under Section 4.2. At the conclusion of the LTIP cycle, the Deferred Stock
Account related to such cycle shall be increased by any additional deferred
shares credited to the Participant under LTIP as a result of performance
above LTIP goals, or decreased by any deferred shares forfeited by the
Participant under LTIP as a result of performance below LTIP goals. The
Deferred Stock Account shall also be credited with the number of shares of
stock that could be purchased, as of the dividend payment date, by the amount
of any dividend equivalents deferred pursuant to Section 4.1.
8.3. EMPLOYER MATCHING ACCOUNT. The Administrator shall establish
and maintain, or cause to be established and maintained, a separate Employer
Matching Account for each Participant hereunder. Each such Participant's
Employer Matching Credit earned pursuant to an Application for Participation
shall be separately accounted for and credited, for bookkeeping purposes
only, to his or her Employer Matching Account. A
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Participant's Employer Matching Account shall be solely for the purposes of
measuring certain amounts to be paid under the Deferred Compensation Plan,
and Delmarva shall not be required to fund or secure the Account in any way,
Delmarva's obligation to Participants hereunder being purely contractual.
8.4. CREDITING OF EARNINGS AND LOSSES, AND STATEMENT OF ACCOUNT.
At such times, with such frequency, and in such percentages as the
Administrator shall determine, each Participant may elect the Investment
Alternatives in which his Deferred Compensation Account may be deemed
invested (subject to the approval of the Committee). The Participant's
Employer Matching Account and Deferred Stock Account shall be deemed invested
solely in Delmarva common stock, shall be denominated in numbers of shares,
and shall be valued at any time as the shares of stock credited to such
Account multiplied by the then-current market value of Delmarva common stock.
Amounts credited to the Deferred Compensation Account will be increased by
earnings (or decreased by losses) equal to the earnings or losses that would
be realized by such Account if it had been invested in the Investment
Alternatives specified by the Participant. As soon as practicable after the
end of each Plan Year (and at such additional times as the Administrator may
determine), the Administrator shall furnish each Participant with a statement
of the balance credited to the Participant's Deferred Compensation
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Account, Deferred Stock Account, and/or Employer Matching Account, as the
case may be.
8.5. INVESTMENT TO FACILITATE PAYMENT OF BENEFITS. Although the
Employers are not obligated to invest in any specific asset or fund, or
purchase any insurance contract in order to provide the means for the payment
of any liabilities under this Deferred Compensation Plan, an Employer may
elect to do so. In the event an Employer elects to invest in any specific
asset or fund, the Committee may, but is not required to, honor the
investment request of the Participant described in Section 8.4, with respect
to any investment to facilitate payment.
In the event an Employer elects to purchase an insurance contract
or contracts on the life of a Participant as a means for the payment of any
liabilities under this Deferred Compensation Plan, the Participant shall
cooperate in the securing of such insurance contract or contracts by
furnishing all information and taking all actions as the Employer and the
insurance carrier may require, including without limitation providing the
results and reports of previous Employer and insurance carrier physical
examinations and taking such additional physical examinations as may be
requested. The Employer shall be the sole owner of any such insurance
contract or contracts or fund or asset, with all incidents of ownership
therein, including without limitation the right to cash and loan values,
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dividends, death benefits and the right to terminate any such contract or
contracts or to dispose of any such fund or asset.
The Participant shall have no interest whatsoever in any contract
or contracts or fund or asset and shall exercise none of the incidents of
ownership thereof.
ARTICLE IX
FUNDING
9.1. DEFERRED COMPENSATION PLAN UNFUNDED. This Deferred
Compensation Plan shall be unfunded and no trust shall be created by the
Deferred Compensation Plan. The crediting to each Participant's Deferred
Compensation Account, Deferred Stock Account, and/or Employer Matching
Account, as the case may be, shall be made through bookkeeping entries. No
actual funds shall be set aside; provided, however, that nothing herein shall
prevent the Employers from establishing one or more grantor trusts from which
benefits due under this Deferred Compensation Plan may be paid in certain
instances. All distributions shall be paid by the Employer from its general
assets and a Participant (or his or her Beneficiary) shall have the rights of
a general, unsecured creditor against the Employer for any distributions due
hereunder. The Deferred Compensation Plan constitutes a mere promise by the
Employer to make benefit payments in the future.
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ARTICLE X
ADMINISTRATION AND INTERPRETATION
10.1. ADMINISTRATION. Except where certain duties are delegated
to the Administrator, the Committee shall be in charge of the operation and
administration of this Deferred Compensation Plan. The Committee has, to the
extent appropriate and in addition to the powers described elsewhere in this
Deferred Compensation Plan, full discretionary authority to construe and
interpret the terms and provisions of the Deferred Compensation Plan; to
adopt, alter and repeal administrative rules, guidelines and practices
governing the Deferred Compensation Plan; to perform all acts, including the
delegation of its administrative responsibilities to advisors or other
persons who may or may not be employees of the Employers; and to rely upon
the information or opinions of legal counsel or experts selected to render
advice with respect to the Deferred Compensation Plan, as it shall deem
advisable, with respect to the administration of the Deferred Compensation
Plan.
10.2. INTERPRETATION. The Committee may take any action, correct
any defect, supply any omission or reconcile any inconsistency in the
Deferred Compensation Plan, or in any election hereunder, in the manner and
to the extent it shall deem necessary to carry the Deferred Compensation Plan
into effect or to carry out the Committee's purposes in adopting the Plan.
Any decision, interpretation or other action made or taken in good
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<PAGE>
faith by or at the direction of the Employers, the Board, the board of
directors of any Employer, the Committee, or the Administrator arising out of
or in connection with the Deferred Compensation Plan, shall be within the
absolute discretion of all and each of them, as the case may be, and shall be
final, binding and conclusive on the Employers, and all employees,
Participants and Beneficiaries and their respective heirs, executors,
administrators, successors and assigns. The Committee's determinations
hereunder need not be uniform, and may be made selectively among Eligible
Employees, whether or not they are similarly situated. Any actions to be
taken by the Committee will require the consent of a majority of the
Committee members. If a member of the Committee is a Participant in this
Deferred Compensation Plan, such member may not decide or determine any
matter or question concerning his or her benefits under this Deferred
Compensation Plan that such member would not have the right to decide or
determine if he or she were not a member.
10.3. RECORDS AND REPORTS. The Administrator shall keep a record
of proceedings and actions and shall maintain or cause to be maintained all
such books of account, records, and other data as shall be necessary for the
proper administration of the Deferred Compensation Plan. Such records shall
contain all relevant data pertaining to individual Participants and their
rights under the Deferred Compensation Plan. The Administrator shall have
the duty to carry into effect all rights or benefits
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<PAGE>
provided hereunder to the extent assets of the Employers are properly
available therefor.
10.4. PAYMENT OF EXPENSES. The Employers, in such proportions as
the Committee determines, shall bear all expenses incurred by them and by the
Committee in administering this Deferred Compensation Plan. If a claim or
dispute arises concerning the rights of a Participant or Beneficiary to
amounts deferred under this Deferred Compensation Plan (including interest or
earnings thereon), regardless of the party by whom such claim or dispute is
initiated, the Employers shall (in such proportions as between the Employers
as the Committee determines), and upon presentation of appropriate vouchers,
pay all legal expenses, including reasonable attorneys' fees, court costs,
and ordinary and necessary out-of-pocket costs of attorneys, billed to and
payable by the Participant or by anyone claiming under or through the
Participant (such person being hereinafter referred to as the "Participant's
Claimant"), in connection with the bringing, prosecuting, defending,
litigating, negotiating, or settling of such claim or dispute; provided, that:
(a) The Participant or the Participant's Claimant shall repay to
the Employers any such expenses theretofore paid or advanced by the Employers
if and to the extent that the party disputing the Participant's rights
obtains a judgment in its favor from a court of competent jurisdiction from
which no appeal
-27-
<PAGE>
may be taken, whether because the time to do so has expired or otherwise, and
it is determined by the court that such expenses were not incurred by the
Participant or the Participant's Claimant while acting in good faith;
provided further, that
(b) In the case of any claim or dispute initiated by a Participant
or the Participant's Claimant, such claim shall be made, or notice of such
dispute given, with specific reference to the provisions of this Deferred
Compensation Plan, to the Committee within one year (two years, in the event
of a Change in Control) after the occurrence of the event giving rise to such
claim or dispute.
10.5. INDEMNIFICATION FOR LIABILITY. The Employers shall
indemnify the Administrator, the members of the Committee, and the employees
of any Employer to whom the Administrator delegates duties under the Deferred
Compensation Plan, against any and all claims, losses, damages, expenses and
liabilities arising from their responsibilities in connection with the
Deferred Compensation Plan, unless the same is determined to be due to gross
negligence or willful misconduct.
10.6. CLAIMS PROCEDURE. If a claim for benefits or for
participation under this Deferred Compensation Plan is denied in whole or in
part, an employee will receive written notification. The notification will
include specific reasons for the denial, specific reference to pertinent
provisions of this Deferred Compensation Plan, a description of any additional
-28-
<PAGE>
material or information necessary to process the claim and why such material
or information is necessary, and an explanation of the claims review
procedure. If the Committee fails to respond within 90 days, the claim is
treated as denied.
10.7. REVIEW PROCEDURE. Within 60 days after the claim is denied
or, if the claim is deemed denied, within 150 days after the claim is filed,
an employee (or his duly authorized representative) may file a written
request with the Committee for a review of his denied claim. The employee
may review pertinent documents that were used in processing his claim, submit
pertinent documents, and address issues and comments in writing to the
Committee. The Committee will notify the employee of its final decision in
writing. In its response, the Committee will explain the reason for the
decision, with specific references to pertinent Deferred Compensation Plan
provisions on which the decision was based. If the Committee fails to
respond to the request for review within 60 days, the review is treated as
denied.
ARTICLE XI
AMENDMENT AND TERMINATION
11.1. AMENDMENT AND TERMINATION. The Board shall have the right,
at any time, to amend or terminate the Deferred Compensation Plan in whole or
in part provided that such amendment or termination shall not adversely
affect the right of
-29-
<PAGE>
any Participant or Beneficiary to a payment under the Deferred Compensation
Plan on the basis of Deferred Compensation allocated to the Participant's
Deferred Compensation Account or Deferred Stock Account or on the basis of a
Employer Matching Credit credited to the Employer Matching Account prior to
such amendment or termination. Delmarva reserves the right, in its sole
discretion, to discontinue deferrals under, or completely terminate, the
Deferred Compensation Plan at any time. If the Deferred Compensation Plan is
discontinued with respect to future deferrals, Participants' Deferred
Compensation Account, Deferred Stock Account and Employer Matching Account
balances shall be distributed on the distribution dates elected in accordance
with Sections 6.1 and 6.2, unless the Committee designates that distributions
shall be made on an earlier date or dates. If the Committee designates such
earlier date or dates, each Participant shall receive (or commence receiving)
distribution of his entire Deferred Compensation Account, Deferred Stock
Account and Employer Matching Account balances on such date or dates, as
specified by the Committee. If the Deferred Compensation Plan is completely
terminated, each Participant shall receive distribution of his entire
Deferred Compensation Account, Deferred Stock Account and Employer Matching
Account balance in one lump sum payment as of the date of the Deferred
Compensation Plan termination designated by the Board.
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<PAGE>
11.2. DEEMED AMENDMENT TO MATCHING FORMULA. In the event the
matching contribution formula under the Savings Plan is modified to increase
or reduce the matching percentage or the percentage of base salary that is
matched, the formulae in Section 5.1 and Section 5.2 shall be deemed to be
modified to equal such matching percentage or percentage of base salary that
is matched, unless otherwise specified in the Board vote amending the Savings
Plan.
ARTICLE XII
MISCELLANEOUS PROVISIONS
12.1. RIGHT OF EMPLOYERS TO TAKE EMPLOYMENT ACTIONS. The adoption
and maintenance of this Deferred Compensation Plan shall not be deemed to
constitute a contract between an Employer and any employee, or to be a
consideration for, or an inducement or condition of, the employment of any
person. Nothing herein contained, or any action taken hereunder, shall be
deemed to give any employee the right to be retained in the employ of an
Employer or to interfere with the right of an Employer to discharge any
employee at any time or to change any employee's compensation or benefits,
nor shall it be deemed to give to an Employer the right to require the
employee to remain in its employ, nor shall it interfere with the employee's
right to terminate his or her employment at any time. Nothing in this Plan
shall prevent an Employer from amending, modifying, or
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<PAGE>
terminating any other benefit plan, including the Savings Plan, the MICP or
the LTIP.
12.2. ALIENATION OR ASSIGNMENT OF BENEFITS. A Participant's
rights and interest under the Deferred Compensation Plan shall not be
assigned or transferred except as otherwise provided herein, and the
Participant's rights to benefit payments under the Deferred Compensation Plan
shall not be subject to alienation, pledge or garnishment by or on behalf of
creditors (including heirs, beneficiaries, or dependents) of the Participant
or of a Beneficiary, except for a qualified domestic relations order as
defined in Section 514(b)(7) of the Employee Retirement Income Security Act
of 1974, as amended.
12.3. RIGHT TO WITHHOLD. To the extent required by law in effect
at the time a distribution is made from the Deferred Compensation Plan, the
Employer or its agents shall have the right to withhold or deduct from any
distributions or payments any taxes required to be withheld by federal, state
or local governments.
12.4. CONSTRUCTION. All legal questions pertaining to the
Deferred Compensation Plan shall be determined in accordance with the laws of
the State of Delaware (without regard to otherwise-applicable conflict of law
principles), to the extent such laws are not superseded by the Employee
Retirement Income Security Act of 1974, as amended, or any other federal law.
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<PAGE>
12.5. HEADINGS. The headings of the Articles and Sections of this
Deferred Compensation Plan are for reference only. In the event of a
conflict between a heading and the contents of an Article or Section, the
contents of the Article or Section shall control.
12.6. NUMBER AND GENDER. Whenever any words used herein are in
the singular form, they shall be construed as though they were also used in
the plural form in all cases where they would so apply, and references to the
male gender shall be construed as applicable to the female gender where
applicable, and vice versa.
12.7. CHANGE IN CONTROL. At the Committee's discretion, after
consultation with all affected Participants, in the event of a Change in
Control and a termination of employment for any reason, each affected
Participant's Deferred Compensation Account, Deferred Stock Account, and
Employer Matching Account shall either be distributed immediately to the
Participant in one lump sum payment, or paid in accordance with the
distribution options selected by the Participant, as determined by the
Committee and made applicable to all affected Participants. In the event
distribution continues to be deferred under the terms of the Plan, the
affected Employer shall be required to contribute cash or equivalent assets
to a grantor trust (maintained by an institutional trustee independent of the
Employer) within 60 days after such Change in Control, in an amount not less
than the
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<PAGE>
then-current value of all Participant Accounts related to such Employer.
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<PAGE>
EXHIBIT 12-A
DELMARVA POWER & LIGHT COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
-------- -------- -------- ------- -------
<S> <C> <C> <C> <C> <C>
Net income (1) $117,488 $108,310 $111,076 $98,526 $80,506
-------- -------- -------- ------- -------
Income taxes (1) 75,540 67,613 67,102 54,834 43,249
-------- -------- -------- ------- -------
Fixed charges:
Interest on long-term debt
including amortization of
discount, premium and
expense 65,572 61,128 62,651 66,976 68,133
Other interest 10,353 9,336 9,245 8,449 10,192
-------- -------- -------- ------- -------
Total fixed charges 75,925 70,464 71,896 75,425 78,325
-------- -------- -------- ------- -------
Nonutility capitalized interest (304) (256) (246) (231) (143)
-------- -------- -------- ------- -------
Earnings before income taxes
and fixed charges $268,649 $246,131 $249,828 $228,554 $201,937
======== ======== ======== ======== ========
Ratio of earnings to fixed charges 3.54 3.49 3.47 3.03 2.58
</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.
(1) Net income and income taxes related to the cumulative effect of a change
in accounting for unbilled revenues recorded in 1991 are excluded from the
computation of this ratio.
<PAGE>
EXHIBIT 12-B
DELMARVA POWER & LIGHT COMPANY
RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDENDS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Net income (1) $117,488 $108,310 $111,076 $98,526 $80,506
-------- -------- -------- -------- --------
Income taxes (1) 75,540 67,613 67,102 54,834 43,249
-------- -------- -------- -------- --------
Fixed charges:
Interest on long-term debt
including amortization of
discount, premium and
expense 65,572 61,128 62,651 66,976 68,133
Other interest 10,353 9,336 9,245 8,449 10,192
-------- -------- -------- -------- --------
Total fixed charges 75,925 70,464 71,896 75,425 78,325
-------- -------- -------- -------- --------
Nonutility capitalized interest (304) (256) (246) (231) (143)
-------- -------- -------- -------- --------
Earnings before income taxes
and fixed charges $268,649 $246,131 $249,828 $228,554 $201,937
======== ======== ======== ======== ========
Fixed charges $75,925 $70,464 $71,896 $75,425 $78,325
Preferred dividend requirements 16,185 15,948 14,803 15,785 11,672
-------- -------- -------- -------- --------
$92,110 $86,412 $86,699 $91,210 $89,997
======== ======== ======== ======== ========
Ratio of earnings to fixed charges
and preferred dividends 2.92 2.85 2.88 2.51 2.24
</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.
Preferred dividend requirements represent annualized preferred dividend
requirements multiplied by the ratio that pre-tax income bears to net income.
(1) Net income and income taxes related to the cumulative effect of a change
in accounting for unbilled revenues recorded in 1991 are excluded from the
computation of this ratio.
<PAGE>
SELECTED FINANCIAL DATA
(Dollars in Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993 1992 1991
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
OPERATING RESULTS AND DATA
Operating Revenues $995,103 $991,021 $970,607 $864,044 $855,821
Operating Income $178,406 $163,156(1) $164,139 $143,711(2) $136,410
Income Before Cumulative Effect of a
Change in Accounting Principle $117,488 $108,310(1) $111,076 $98,526(2) $80,506
Cumulative Effect of a Change in
Accounting for Unbilled Revenues -- -- -- -- $12,730
Net Income $117,488 $108,310(1) $111,076 $98,526(2) $93,236
Earnings Applicable to Common Stock $107,546 $98,940(1) $101,074 $90,177(2) $85,259
Electric Sales (kWh 000)(3) 12,310,921 12,505,082 12,280,230 11,520,811 11,460,280
Gas Sold and Transported (mcf 000) 21,371 20,342 19,605 20,168 18,184
COMMON STOCK INFORMATION
Earnings Per Share of Common Stock
Before Cumulative Effect of a
Change in Accounting Principle $1.79 $1.67(1) $1.76 $1.69(2) $1.44
Cumulative Effect of a Change in
Accounting for Unbilled Revenues -- -- -- -- $0.25
Total Earnings Per Share $1.79 $1.67(1) $1.76 $1.69(2) $1.69
Dividends Declared Per Share of
Common Stock $1.54 $1.54 $1.54 $1.54 $1.54
Average Shares Outstanding (000) 60,217 59,377 57,557 53,456 50,581
Year-End Common Stock Price $22 3/4 $18 9/64 $23 5/8 $23 1/4 $21 1/4
Book Value Per Common Share $15.20 $14.85 $14.66 $13.77 $13.42
Return on Average Common Equity 11.7% 11.1% 12.0% 12.2% 12.4%
CAPITALIZATION
Variable Rate Demand Bonds (VRDB)(4) $86,500 $71,500 $41,500 $41,500 $41,500
Long-Term Debt 853,904 774,558 736,368 787,387 770,146
Preferred Stock 168,085 168,085 168,085 176,365 136,365
Common Stockholders' Equity 923,440 884,169 862,195 745,789 706,583
----------------------------------------------------------------------
Total Capitalization with VRDB $2,031,929 $1,898,312 $1,808,148 $1,751,041 $1,654,594
----------------------------------------------------------------------
----------------------------------------------------------------------
OTHER INFORMATION
Total Assets $2,866,685 $2,669,785 $2,592,479 $2,374,793 $2,263,718
Long-Term Capital Lease Obligation $20,768 $19,660 $23,335 $26,081 $29,337
Construction Expenditures (5) $135,614 $154,119 $159,991 $207,439 $181,820
Internally Generated Funds (IGF)(6) $137,394 $123,948 $108,693 $130,275 $96,081
IGF as a Percent of Construction Expenditures 101% 80% 68% 63% 53%
</TABLE>
(1) An early retirement offer decreased earnings net of income taxes and
earnings per share by $10.7 million and $0.18, respectively.
(2) The settlement of a lawsuit with PECO Energy Company increased earnings net
of income taxes 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 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.
Delmarva Power & Light Company
20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
EARNINGS SUMMARY
The earnings per average share of common stock attributed to the core utility
business and nonutility subsidiaries are shown below.
<TABLE>
<CAPTION>
1995 1994 1993
-----------------------------------
<S> <C> <C> <C>
Core Utility
Operations $1.72 $1.81 $1.73
Early Retirement Offer -- (0.18) --
-----------------------------------
1.72 1.63 1.73
Nonutility Subsidiaries 0.07 0.04 0.03
-----------------------------------
Total $1.79 $1.67 $1.76
-----------------------------------
-----------------------------------
</TABLE>
Earnings per share from core utility operations decreased by $0.09 in 1995
compared to 1994 due to a portion of estimated additional costs that were
expensed for the Salem Nuclear Generating Station (Salem) arising from
operational problems, including the current outage, which is discussed further
under "Salem Outage." Excluding the portion of estimated additional costs that
were expensed for Salem, earnings per share from core utility operations in 1995
were unchanged from 1994, reflecting the Company's success in offsetting
decreased wholesale (resale) revenues with a combination of cost reduction
efforts, retail sales growth, and modest price increases pursuant to the
Company's "Three-Legged Stool" strategy, which is discussed further under
"Strategic Plans for Competition--Resale Business." Operating results from the
new Conowingo District, which began in June 1995 as a result of the Company's
acquisition of Conowingo Power Company (COPCO), had a minimal impact on
earnings, as expected. Refer to Note 4 to the Consolidated Financial Statements
for information concerning the Company's acquisition of COPCO.
Earnings per share from core utility operations increased by $0.08 in 1994
compared to 1993 primarily due to additional electric base revenues from rate
increases and additional electric sales. The earnings growth from additional
electric base revenues was partially offset by higher depreciation expense and
the dilutive effect of additional common shares outstanding.
Core utility earnings were reduced in 1994 by $10.7 million after taxes, or
$0.18 per share, to reflect a voluntary early retirement offer (ERO), which
resulted in a work force reduction of 10.5% or 296 people. Refer to Note 5 to
the Consolidated Financial Statements for additional information concerning the
ERO.
DIVIDENDS
On December 20, 1995, the Board of Directors declared a common stock dividend of
$0.38 1/2 per share for the fourth quarter. As the utility industry moves from a
regulated to a competitive environment, the Company believes it can best provide
shareholder value through maintaining the current dividend level and providing
annual earnings growth. Over time, this strategy is expected to reduce the
Company's dividend payout ratio and allow the Company to invest in opportunities
that are anticipated to have a sustainable positive impact on earnings growth.
Delmarva Power & Light Company
21
<PAGE>
SALEM OUTAGE
The Company owns 7.41% of Salem, which consists of two pressurized water nuclear
reactors (PWR) and is operated by Public Service Electric & Gas Company (PSE&G).
As of December 31, 1995, the Company's net investment in plant in-service for
Salem was approximately $57 million for Unit 1 and $60 million for Unit 2. Each
unit represents approximately 2% of the Company's total assets and approximately
3% of the Company's installed electric generating capacity.
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. The units will remain shut down until PSE&G makes the equipment and
management changes necessary to operate the units reliably over the long term.
The restart of the units is subject to Nuclear Regulatory Commission (NRC)
authorization. In December 1995, PSE&G completed a workscope assessment of both
units and estimated that Unit 1 would return to service in the second quarter of
1996 and Unit 2 in the third quarter of 1996.
On February 21, 1996, PSE&G informed the Company that partial results from
recent inspections of Unit 1 using a new testing technology revealed indications
of degradation in a significant number of steam generator tubes. PSE&G is
continuing its inspections and also will conduct further laboratory analysis of
the tubes with results expected in April 1996. Based on the results of
inspections to date, PSE&G has concluded that the Unit 1 outage will be extended
for an indefinite period to evaluate the state of the steam generators and to
subsequently determine an appropriate course of action. Degradation of steam
generators in PWRs has become of increasing concern for the nuclear industry.
Nationally and internationally, utilities have undertaken actions to repair or
replace steam generators. In the extreme, degradation of steam generators has
contributed to the retirement of several American nuclear power reactors.
PSE&G also has informed the Company that recent steam generator inspections of
Unit 2 using the new testing technology have revealed that the condition of the
Unit 2 steam generators is within current repair limits at the present time.
However, to confirm the Unit 2 test results, PSE&G also will conduct laboratory
analysis of the tubes for Unit 2. As a result of the delay in the restart of
Unit 1, PSE&G is focusing its efforts on the return of Unit 2 to service in the
third quarter of 1996, as scheduled. However, the Company cannot predict when
the NRC will approve the restart of the unit or when the restart actually will
occur.
In 1995, the Company incurred higher than expected operation and maintenance
costs at Salem of approximately $5 million, which reflect the operational
problems at the plant. These costs were expensed as incurred. Also,
outage-related replacement power costs were estimated to be approximately $8
million. One-half of the estimated replacement power costs was expensed and
the other one-half was deferred on the Company's Consolidated Balance Sheet
in expectation of future recovery. Based on PSE&G's current estimates, the
Company estimates that its share of additional costs related to the outage in
1996 will consist of operation and maintenance costs ranging from $4 million
to $7 million, which will be expensed as incurred, and replacement power
costs while the units are out of service of approximately $750,000 per month,
per unit. In total, the Company estimates that its share of outage-related
costs in 1996 will range from $17 million to $22 million. However, these 1996
estimates could change as a result of PSE&G's analysis of the degradation of
the steam generator tubes. Beyond 1996, the Company cannot predict the amount
of outage-related costs it could incur. During 1996, the Company plans to
file a proposal with the Delaware Public Service Commission (DPSC), the
Company's primary rate jurisdiction, for recovery of replacement power costs.
Since the periods during which these 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 currently anticipated,
the actual costs to be incurred by the Company may vary from the foregoing
estimates.
STRATEGIC PLANS FOR COMPETITION
The electric resale segment of the utility industry has become highly
competitive as a result of federal legislation. Resale customers now can choose
their electric supplier. Competition in the retail markets also is being
discussed at both the Federal and State levels. As the retail segment of the
industry transitions to a more competitive market, the Company is making changes
in the way it manages its business.
Resale Business
The Company's total electric resale revenues as a percent of total billed
electric sales revenues decreased from 13% in 1994 to 7% in 1995, primarily due
to Old Dominion Electric Cooperative's (ODEC) purchase of about one-half of its
capacity and energy requirements from other suppliers beginning January 1, 1995.
The resulting decrease in resale non-fuel revenues in 1995 of $24.2 million was
offset through the Company's "Three-Legged Stool" strategy, which involved a
combination of cost reduction efforts, retail sales growth, and modest price
increases.
The Company has reduced substantially the financial risk related to its resale
business. In 1994 and 1995, the Company successfully bid against other suppliers
and retained all of its municipal customers under long-term contracts. In
addition, the Company negotiated extended notice provisions on the remaining
portion of ODEC's capacity and energy requirements served by the Company. These
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%. ODEC has indicated that it may issue a request for proposals in early
1996 for the remaining portion of its capacity and energy requirements currently
served by the Company. To the extent there is any further reduction in load, the
notice provisions provide the Company with the ability to manage the financial
impact.
Delmarva Power & Light Company
22
<PAGE>
(A graph titled "Reduced Resale Financial Risk" is displayed on page 23 of the
1995 Annual Report to Stockholders. A description of this graph is included in
the Appendix to Management's Discussion and Analysis of Financial Condition and
Results of Operations.)
Retail Business
Retail customers also are expected to be able to choose their energy suppliers
in the future. The Company is well positioned for competition, due to its
relatively low prices within the region, and is taking steps to manage its
separate businesses in a competitive market, as discussed below.
During 1995, the Company introduced various new products and services and
extended its markets into the region. Through an expanded marketing team, the
Company is offering consulting, design, construction, and operating and
maintenance services to commercial, industrial, and resale customers; developing
and marketing residential products and services; and exploring the use of its
energy delivery infrastructure to provide services to the telecommunications
industry. In addition, the Company is working closely with neighboring
communities, governments, and businesses to attract new customers and new jobs
to the Company's service territory.
During 1996, the Company will reorganize into three separate business units--
energy supply, regulated delivery, and energy services--to better focus on the
evolving energy markets. The Company also is investing in information technology
systems that will provide immediate access to the information needed to manage
the business units in a competitive environment.
In February 1996, the Company presented to the DPSC and the Maryland Public
Service Commission a proposal to enter into a collaborative process to develop
the transition from a regulated to a competitive energy market. The Company
believes that the benefits of a competitive market can best be realized when
addressed together by the Company, the Commissions, and customers. The Company
also believes that this process should develop solutions for the following key
issues: retail wheeling, stranded investment, the unbundling of electric price
elements, and performance-based pricing mechanisms. The first goal will be to
seek agreement on the objectives and principles for the transition to a market
that allows choices for all customers. Afterwards, specific details and filings
with the Commissions will be addressed.
Impact of Competition on Stranded Costs
As the electric utility industry transitions from a regulated to a competitive
environment, utilities may not be able to recover certain costs, resulting in
these costs being "stranded." Stranded costs could result from the shift from
current cost-of-service based pricing to market-based pricing and from customers
changing energy suppliers. Potential stranded costs include above-market costs
associated with generation facilities; long-term purchased power contracts; and
regulatory assets, which are expenses that have been deferred pending recovery
from customers pursuant to Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation." If changes
in the regulatory environment ultimately require a recognition of any stranded
costs, the Company could be required to write down asset values, and such write-
downs could be material. However, since the time frame of further deregulation,
the market conditions relative to capacity and energy demand and prices at the
time of deregulation, and the extent to which regulatory commissions allow
recovery of stranded costs are not known at this time, the Company cannot
predict the level of stranded costs it could incur. Based on recent independent
studies, the Company has less exposure to stranded costs than many other
utilities in the industry.
Refer to "Impact of New Accounting Standards" for discussion of a related topic
and Note 8 to the Consolidated Financial Statements for additional information
on regulatory assets.
(A graph titled "Electric Price Comparison" is displayed on page 23 of the 1995
Annual Report to Stockholders. A description of this graph is included in the
Appendix to Management's Discussion and Analysis of Financial Condition and
Results of Operations.)
Delmarva Power & Light Company
23
<PAGE>
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 Pennsylvania-New
Jersey-Maryland Interconnection Association (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 1995, the percentages of total billed sales revenues contributed by the
various customer classes were as follows: residential--41.4%;
commercial--32.1%; industrial--18.6%; resale--7.0%; and other--0.9%.
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) 1995 1994
--------------------
<S> <C> <C>
Non-fuel (Base Rate) Revenues
Retail Sales Volume $54.9 $4.1
Resale Sales Volume (24.2) (0.2)
Increased Rates 3.3 15.9
Fuel Revenues (6.9) (15.4)
Interchange Delivery Revenues (15.1) 1.0
Other Operating Revenues 4.5 2.1
--------------------
Total $16.5 $7.5
--------------------
--------------------
</TABLE>
For 1995 compared to 1994, Non-fuel Revenues increased $54.9 million from Retail
Sales Volume due to a 7.3% increase in total retail kilowatt-hour (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
higher commercial sales resulting from a strong economy in the Company's service
territory, a 1.4% increase in the number of retail customers, and the favorable
impact of hotter summer weather. Excluding the Conowingo District, billed sales
to residential and commercial customers increased by 1.1% and 4.5%,
respectively; industrial sales were flat.
For 1994 compared to 1993, Non-fuel Revenues increased $4.1 million from Retail
Sales Volume due to a 1.9% increase in total retail sales, which resulted
primarily from a 1.6% increase in the total number of retail customers, an
improving economy in the Company's service territory, and colder winter weather,
offset in part by cooler summer weather. Billed sales to residential and
commercial customers increased by 2.3% and 3.7%, respectively; industrial sales
were flat.
Non-fuel Revenues decreased $24.2 million in 1995 from Resale Sales Volume due
to a 44.0% decrease in resale sales, mainly due to ODEC's purchase of about one-
half of its capacity and energy requirements from other suppliers beginning
January 1, 1995. Changes in resale sales have less of an impact on non-fuel
revenues than changes in retail sales, since average resale non-fuel rates are
significantly lower than average retail non-fuel rates.
The increases in Non-fuel Revenues from Increased Rates resulted from increases
in electric customer base rates which became effective during 1993 and 1995.
Refer to Note 2 to the Consolidated Financial Statements for information
concerning these rate increases.
In 1995, Fuel Revenues decreased $6.9 million mainly due to lower total sales.
In 1994, Fuel Revenues decreased $15.4 million due to lower rates charged to
customers under the fuel adjustment clauses, partially offset by higher total
sales.
In 1995, Interchange Delivery Revenues decreased $15.1 million, mainly due to
lower sales and billing rates to the PJM Interconnection.
Delmarva Power & Light Company
24
<PAGE>
GAS REVENUES, SALES, AND TRANSPORTATION
The Company earns gas revenues from the sale of gas to customers and also from
transporting gas through the Company's system for some customers who purchase
gas directly from other suppliers.
In 1995, total gas revenues decreased $12.5 million from 1994 because of a $4.0
million increase in non-fuel revenues and a $16.5 million decrease in fuel
revenues. The increase in non-fuel revenues was due to $2.7 million of
additional revenue from a base rate increase that became effective November 1,
1994, and a $1.3 million increase in sales volume. Total volumes of gas sold and
transported in 1995 increased 5.1% due to a 1.9% increase in firm gas sales,
resulting primarily from a 2.9% increase in the number of customers, and a 17.2%
increase in non-firm sales and gas transported. Gas 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.
In 1994, total gas revenues increased $13.0 million from 1993 due to a $3.0
million increase in non-fuel revenues and a $10.0 million increase in fuel
revenues. The increase in non-fuel revenues was due to $0.6 million of
additional revenue from a November 1, 1994 base rate increase and a $2.4 million
increase in sales volume. Total volumes of gas sold and transported in 1994
increased 3.8% due to a 2.9% increase in the number of customers and colder
winter weather during the first quarter. Gas fuel revenues increased $10.0
million in 1994 due to higher average fuel rates and higher sales.
ELECTRIC FUEL AND PURCHASED POWER EXPENSES
In 1995, electric fuel and purchased power expenses decreased $14.7 million from
1994 primarily due to lower kWh output and lower purchased power prices. The
$14.7 million decrease is net of $4.1 million of expense, which represents one-
half of the total Salem outage-related replacement power costs that were
estimated for 1995.
In 1994, electric fuel and purchased power expenses decreased $15.7 million from
1993 primarily due to variances in fuel costs deferred and subsequently
amortized under the Company's fuel adjustment clauses.
The kWh output required to serve load within the Company's service territory
is substantially equivalent to total output less interchange deliveries. In
1995, the Company's output for load within its service territory was provided
by 39.4% coal generation, 32.1% oil and gas generation, 16.4% net purchased
power, and 12.1% nuclear generation.
GAS PURCHASED
For 1995, compared to 1994, the cost of gas purchased decreased $15.2 million,
primarily due to a $6.8 million refund in 1995 of over-recovered fuel costs and
variances in fuel costs deferred and subsequently amortized under the Company's
fuel adjustment clause. The refund of over-recovered fuel costs reduced the
amount of expense recorded for gas purchased because fuel expense is adjusted to
match fuel revenues as explained under "Components of Utility Revenues."
For 1994, compared to 1993, the cost of gas purchased increased $10.2 million,
primarily due to variances in fuel costs deferred and subsequently amortized
under the Company's fuel adjustment clause.
Delmarva Power & Light Company
25
<PAGE>
OPERATION, MAINTENANCE, DEPRECIATION, AND INCOME TAX EXPENSES
Operation and maintenance expenses increased in 1995 by $8.0 million compared to
1994. The most significant factor contributing to the increase was $29.5 million
of costs related to the Conowingo District, including $26.1 million for capacity
purchase charges under the Company's contracts to purchase the Conowingo
District's electric power requirements from PECO Energy Company (PECO). Also
contributing to the increase in expense were higher than expected costs at Salem
of approximately $5 million, which reflect the operational problems at the
plant, including the current outage. Largely offsetting these increases were a
$17.5 million ERO expense recorded in 1994, salary and wage savings in 1995 from
reduced staff levels, and lower storm damage costs.
Operation and maintenance expenses increased in 1994 by $19.2 million
compared to 1993 due mainly to the following factors: the $17.5 million ERO
expense, a $3.5 million increase in winter storm damage costs, a $3.5 million
increase in the cost for postretirement benefits other than pensions (OPEB),
and a $7.8 million reduction in pension expense, of which $4.5 million was
due to a lower assumed rate of salary increase. The Company's OPEB costs were
deferred during part of 1993 due to probable rate recovery. In 1994, the
deferral for the Delaware jurisdiction (electric and gas) was expensed in
accordance with a settlement agreement, approved October 18, 1994, concerning
the Company's gas base rate case.
Depreciation expense increased in 1995, primarily due to the addition of the
Conowingo District. In 1994, depreciation expense increased mainly due to
additions to the electric system, including Hay Road Unit 4 in mid-1993.
Inflation affects the Company through increased operating expenses and higher
replacement costs for utility plant assets. Although timely rate increases can
lessen the effects of inflation, due to competition and the changing nature of
the utility industry, the Company does not plan to file for an increase in base
rates in the near term. The Company plans to use its existing cost control
programs and sales initiatives as its primary means to mitigate the effects of
inflation.
Income tax expense on operations increased $7.4 million in 1995 in comparison to
1994 and decreased $2.0 million in 1994 in comparison to 1993, mainly due to a
corresponding increase and decrease in pre-tax income.
UTILITY FINANCING COSTS
Interest expense increased $6.3 million in 1995 in comparison to 1994, primarily
due to the issuance of debt to acquire COPCO. Also contributing to the increase
were higher average short-term debt balances and rates. Interest expense
decreased $2.0 million in 1994, mainly due to the redemption on June 1, 1993, of
$50 million of 10% First Mortgage Bonds with proceeds from a public offering of
common stock.
Allowance for equity and borrowed funds used during construction (AFUDC)
decreased $2.4 million in 1995, mainly due to a lower AFUDC rate. The decrease
in AFUDC of $3.6 million in 1994 was primarily due to lower average construction
balances.
Due to common equity financing, the average number of shares of common stock
outstanding increased in 1995 and 1994. The additional shares outstanding
decreased earnings per share by $0.03 in 1995 and $0.05 in 1994.
ENERGY SUPPLY
The Company's energy supply plan reflects its strategy to provide an adequate,
reliable supply of electricity to customers, while minimizing adverse impacts on
the environment and keeping prices competitive. 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 strategic
conservation programs ("demand-side" alternatives), with short-term power
purchases, long-term power contracts, and new or renovated power plants
("supply-side" alternatives).
The plan currently matches customers' energy requirements and does not require
large investments for new resources. The Company must balance the risks of
providing too much or too little capacity. The main risks of too much capacity
are that the Company's prices may become uncompetitive and that regulators may
not allow the associated costs to be recovered through customer rates. The
principal risks of inadequate capacity are unreliable service and 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 47 megawatts (MW), provided 205 MW of capacity
from a long-term power contract with PECO beginning in 1996, and provided 175 MW
of capacity from a new power plant, Hay Road Unit 4. Looking forward through
2000, the Company's plan includes the following provisions:
(1) "Demand-side" -- No additional peak load reduction through customer-
oriented load management and strategic conservation programs. The Company filed
to close its existing demand-side programs to new participants in Delaware and
Maryland on October 3, 1995, because these programs are not considered the most
appropriate and cost effective resources for meeting future demand requirements.
(2) "Supply-side" -- Starting in 1997 and continuing through 2000, up to 125 MW
of short-term power purchases, in addition to the long-term power contract
discussed above.
Delmarva Power & Light Company
26
<PAGE>
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 plant
construction expenditures 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 need for improvement and replacement of
existing facilities.
Operating activities provided cash inflows of $239.4 million in 1995, $224.6
million in 1994, and $206.7 million in 1993. After deducting common and
preferred dividend payments of $102.0 million in 1995, $100.6 million in 1994,
and $98.0 million in 1993, internally generated funds were $137.4 million in
1995, $124.0 million in 1994, $108.7 million in 1993. Internally generated funds
provided 101%, 80%, and 68% of the cash required for utility construction in
1995, 1994, and 1993, respectively.
Utility construction expenditures were $135.6 million in 1995, $154.1 million in
1994, and $160.0 million in 1993. Construction expenditures in 1995, 1994, and
1993 included $16.4 million, $20.7 million, and $9.2 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. During 1993-1995, investments by the Company's nonutility
subsidiaries were primarily construction expenditures at a landfill business as
well as the purchase of a $5.7 million office building in 1994. In 1995 and
1994, the subsidiaries raised $3.7 million and $4.6 million, respectively,
through the sale of real estate. In 1993, the subsidiaries sold interests in
leveraged leases, which resulted in a $21.5 million cash inflow.
Capital raised externally during 1993-1995, net of $303.3 million of redemptions
and refinancings, consisted of $146.3 million of common stock, $67.0 million of
long-term debt, and $45.0 million of variable rate demand bonds. Preferred stock
outstanding decreased $8.3 million. After considering $15.2 million of costs
associated with issuing and refinancing debt and equity securities during 1993-
1995, the net amount of capital raised from external financings during this
period was $234.8 million.
Issuances of common stock during 1993-1995 included a public offering in 1993 of
3,300,000 shares for $77.1 million. The Company's 1993 financing requirements
associated with utility plant were principally satisfied by issuing common stock
in order to strengthen the Company's capital structure. Additional common stock
was issued during 1993-1995, 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. During 1993-1995, shares issued through the
DRIP were newly issued shares, except during the last seven months of 1994 when
the shares were purchased in the open market. Effective January 1, 1996, shares
issued through the DRIP are being purchased in the open market. Book value per
share of common stock increased to $15.20 as of December 31, 1995, from $14.85
as of December 31, 1994.
In addition to the Company's issuance in 1995 of $125.8 million of long-term
debt to acquire COPCO, one of the Company's non-utility subsidiaries issued
$15.0 million of variable rate demand bonds to finance the past and future
expansion of its landfill business. During the year, the Company's term loan
balance of $45.0 million was repaid using cash from operations. No other
significant debt redemption occurred in 1995.
(A graph titled "Internally Generated Funds & Construction Expenditures" is
displayed on page 27 of the 1995 Annual Report to Stockholders. A description of
this graph is included in the Appendix to Management's Discussion and Analysis
of Financial Condition and Results of Operations.)
Delmarva Power & Light Company
27
<PAGE>
The Company's capital structure as of December 31, 1995 and 1994, expressed as a
percentage of total capitalization, is shown below.
<TABLE>
<CAPTION>
1995 1994
--------------------
<S> <C> <C>
Long-term debt and variable
rate demand bonds 46.3% 44.6%
Preferred stock 8.3% 8.8%
Common stockholders' equity 45.4% 46.6%
</TABLE>
Capital requirements for the period 1996-1997 are estimated to be $324 million,
including $25 million for maturity of First Mortgage Bonds in 1997 and $294
million for utility construction expenditures, excluding AFUDC. The estimate of
1996-1997 utility construction expenditures includes $11 million related to
environmental compliance plans, including provision of the Clean Air Act
Amendments of 1990. During 1998-2000, an additional $42 million of construction
expenditures (excluding AFUDC) related to compliance with environmental
regulations are planned.
The Company anticipates that $283 million will be generated internally during
1996-1997, net of power purchase commitments. This represents 87% of estimated
capital requirements and 96% of estimated utility construction expenditures for
1996-1997. During this period, no long-term external financings are presently
planned.
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.
NONUTILITY SUBSIDIARIES
Information on the Company's nonutility subsidiaries, in addition to the
following discussion, can be found in Notes 1 and 18 to the Consolidated
Financial Statements.
Earnings per share of nonutility subsidiaries were $0.07 in 1995 in comparison
to $0.04 in 1994. The $0.03 increase in earnings was primarily due to higher
recoveries of previously written-off joint venture assets, the receipt of an
additional payment related to a prior year sale of a leveraged lease interest,
and a 1994 adjustment to reduce the realizable value of oil and gas wells. The
increase in 1995 earnings was partially offset by lower earnings from solid
waste group operations. Both 1995 and 1994 included gains from the sale of real
estate.
Earnings per share of nonutility subsidiaries were $0.04 in 1994 in comparison
to $0.03 in 1993. The $0.01 increase in earnings was mainly attributed to gains
on the sale of real estate, improved operating results of the solid waste group,
and higher earnings from various other nonutility business activities. These
earnings increases were largely offset by a 1994 adjustment to the realizable
value of oil and gas wells and by 1993 after-tax gains on sales of leveraged
leases.
IMPACT OF NEW ACCOUNTING STANDARDS
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of," which requires the Company to review long-lived
assets and certain identifiable intangibles held and used by the Company for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. If an asset is considered
impaired, then its value would be written down with a corresponding charge to
earnings. SFAS No. 121 also requires rate-regulated companies to write off
regulatory assets against earnings whenever those assets no longer meet the
criteria for recognition of a regulatory asset as defined by SFAS No. 71. The
new standard is effective in 1996. Based on current circumstances, the Company
does not expect the adoption of SFAS No. 121 to have a material effect upon the
Company's financial condition or results of operations. However, the effects of
the electric utility industry's transition to a competitive environment could
result in the future write-down of asset values as discussed under "Strategic
Plans for Competition--Impact of Competition on Stranded Costs."
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which encourages, but does not require, entities to recognize
compensation costs for stock-based employee compensation plans using a fair
value based method of accounting rather than the intrinsic value based method of
accounting currently prescribed by Accounting Principles Board (APB) Opinion No.
25, "Accounting for Stock Issued to Employees." Entities electing to continue
using the accounting prescribed by APB Opinion No. 25 are required to disclose
pro forma net income and earnings per share as if the fair value based method of
accounting under SFAS No. 123 had been applied. The new standard is effective in
1996. The Company does not expect to adopt the accounting provisions of SFAS No.
123 for income statement recognition purposes.
Delmarva Power & Light Company
28
<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
Chairman of the Board, President,
and Chief Executive Officer
Barbara S. Graham
Senior Vice President, Treasurer,
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 and statements of
capitalization of Delmarva Power & Light Company and Subsidiary Companies as of
December 31, 1995 and 1994, 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, 1995. 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, 1995 and 1994, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995, in conformity with generally
accepted accounting principles.
Coopers & Lybrand L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 2, 1996, except as to the information presented under the caption Salem
Outage in Note 16, for which the date is February 26, 1996
Delmarva Power & Light Company
29
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
(Dollars in Thousands) Year Ended December 31,
1995 1994 1993
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Electric $899,662 $883,115 $875,663
Gas 95,441 107,906 94,944
--------------------------------------
995,103 991,021 970,607
--------------------------------------
OPERATING EXPENSES
Electric fuel and purchased power 267,885 282,570 298,307
Gas purchased 48,615 63,814 53,631
Operation and maintenance 275,165 267,207 248,052
Depreciation 113,022 109,523 100,929
Taxes other than income taxes 38,449 38,585 37,419
Income taxes 73,561 66,166 68,130
--------------------------------------
816,697 827,865 806,468
--------------------------------------
OPERATING INCOME 178,406 163,156 164,139
--------------------------------------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains 52,042 43,142 37,636
Expenses including interest and income taxes (47,896) (40,790) (35,828)
--------------------------------------
Net earnings of nonutility subsidiaries 4,146 2,352 1,808
Allowance for equity funds used during construction 708 3,389 5,309
Other income, net of income taxes 557 (285) 511
--------------------------------------
5,411 5,456 7,628
--------------------------------------
INCOME BEFORE UTILITY INTEREST CHARGES 183,817 168,612 171,767
--------------------------------------
UTILITY INTEREST CHARGES
Interest expense 68,395 62,076 64,095
Allowance for borrowed funds used during construction (2,066) (1,774) (3,404)
--------------------------------------
66,329 60,302 60,691
--------------------------------------
EARNINGS
Net income 117,488 108,310 111,076
Dividends on preferred stock 9,942 9,370 10,002
--------------------------------------
Earnings applicable to common stock $107,546 $ 98,940 $101,074
--------------------------------------
--------------------------------------
COMMON STOCK
Average shares of common stock outstanding (000) 60,217 59,377 57,557
Earnings per average share of common stock $1.79 $1.67 $1.76
Dividends declared per share of common stock $1.54 $1.54 $1.54
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
Delmarva Power & Light Company
30
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
(Dollars in Thousands) Year Ended December 31,
1995 1994 1993
- ------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
<S> <C> <C> <C>
Net income $117,488 $108,310 $111,076
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and amortization 120,897 120,803 112,926
Allowance for equity funds used during construction (708) (3,389) (5,309)
Investment tax credit adjustments, net (2,516) (1,898) (2,515)
Deferred income taxes, net 15,992 4,829 (1,171)
Provision for early retirement offer -- 17,500 --
Net change in:
Accounts receivable (14,022) 7,980 (15,851)
Inventories 18,590 (21,409) 5,314
Accounts payable 3,269 5,811 (3,749)
Other current assets & liabilities(1) (14,349) (10,668) 11,441
Other, net (5,213) (3,282) (5,438)
---------------------------------------------------
Net cash provided by operating activities 239,428 224,587 206,724
---------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures, excluding AFUDC (135,614) (154,119) (159,991)
Allowance for borrowed funds used during construction (2,066) (1,774) (3,404)
Change in working capital for construction 1,102 (439) 3,123
Acquisition of COPCO, net of cash acquired (157,014) -- --
Cash flows from leveraged leases
Sales of interests in leveraged leases 1,314 -- 21,542
Other 1,685 1,592 1,511
Proceeds from sales of subsidiary property 3,656 4,596 --
Investment in subsidiary projects and operations (3,645) (11,045) (2,827)
Net (increase)/decrease in bond proceeds held in trust funds 2,658 (11,816) 1,152
Deposits to nuclear decommissioning trust funds (3,612) (2,438) (2,657)
Other, net (3,544) (2,336) (389)
---------------------------------------------------
Net cash used by investing activities (295,080) (177,779) (141,940)
---------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends: Common (92,221) (91,175) (87,989)
Preferred (9,813) (9,464) (10,042)
Issuances: Long-term debt(2) 125,800 4,640 148,200
Variable rate demand bonds 15,000 30,000 15,500
Common stock 24,693 14,974 109,463
Preferred stock -- -- 20,000
Redemptions: Long-term debt(2) (1,388) (26,096) (184,206)
Variable rate demand bonds -- -- (15,500)
Common stock (1,253) (794) (748)
Preferred stock -- -- (28,280)
Principal portion of capital lease payments (7,875) (11,280) (9,956)
Net change in term loan (45,000) 35,000 10,000
Net change in short-term debt 53,154 10,000 (17,000)
Cost of issuances and refinancings (1,523) (601) (13,097)
---------------------------------------------------
Net cash provided/(used) by financing activities 59,574 (44,796) (63,655)
---------------------------------------------------
Net change in cash and cash equivalents 3,922 2,012 1,129
Beginning of year cash and cash equivalents 25,029 23,017 21,888
---------------------------------------------------
End of year cash and cash equivalents $28,951 $25,029 $23,017
---------------------------------------------------
---------------------------------------------------
</TABLE>
(1) Other than debt and deferred income taxes classified as current.
(2) Excluding net change in term loan.
See accompanying Notes to Consolidated Financial Statements.
Delmarva Power & Light Company
31
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
(Dollars in Thousands) As of December 31,
1995 1994
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
<S> <C> <C>
UTILITY PLANT--AT ORIGINAL COST
Electric $2,942,969 $2,676,871
Gas 208,245 196,188
Common 130,949 120,933
---------------------------------------------------
3,282,163 2,993,992
Less: Accumulated depreciation 1,189,269 1,062,565
---------------------------------------------------
Net utility plant in service 2,092,894 1,931,427
Construction work-in-progress 105,588 85,220
Leased nuclear fuel, at amortized cost 31,661 30,349
---------------------------------------------------
2,230,143 2,046,996
---------------------------------------------------
INVESTMENTS AND NONUTILITY PROPERTY
Investment in leveraged leases 48,367 49,595
Funds held by trustee 36,275 32,824
Other investments and nonutility property, net 54,781 57,289
---------------------------------------------------
139,423 139,708
---------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 28,951 25,029
Accounts receivable
Customers 116,606 93,739
Other 14,630 15,144
Inventories, at average cost
Fuel (coal, oil, and gas) 30,076 48,262
Materials and supplies 36,823 37,055
Prepayments 12,969 9,014
Deferred income taxes, net 5,400 9,276
---------------------------------------------------
245,455 237,519
---------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS
Prepaid pension cost 16,899 5,905
Unamortized debt expense 12,256 11,387
Deferred debt refinancing costs 23,972 26,530
Deferred recoverable income taxes 151,250 149,206
Other 47,287 52,534
---------------------------------------------------
251,664 245,562
---------------------------------------------------
Total $2,866,685 $2,669,785
---------------------------------------------------
---------------------------------------------------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
Delmarva Power & Light Company
32
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
(Dollars in Thousands) As of December 31,
1995 1994
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (SEE STATEMENTS OF CAPITALIZATION)
Common stock, $2.25 par value; 90,000,000 shares authorized;
shares outstanding: 1995--60,759,365, 1994--59,542,006 $136,713 $133,970
Additional paid-in capital 506,298 484,377
Retained earnings 281,862 267,002
Unearned compensation (1,433) (1,180)
---------------------------------------------------
Total common stockholders' equity 923,440 884,169
Preferred stock 168,085 168,085
Long-term debt 853,904 774,558
---------------------------------------------------
1,945,429 1,826,812
---------------------------------------------------
CURRENT LIABILITIES
Short-term debt 63,154 10,000
Long-term debt due within one year 1,485 1,399
Variable rate demand bonds 86,500 71,500
Accounts payable 64,056 59,596
Taxes accrued 4,802 7,264
Interest accrued 16,355 15,459
Dividends declared 23,426 22,831
Current capital lease obligation 12,604 12,571
Deferred energy costs 222 12,241
Other 33,595 27,538
---------------------------------------------------
306,199 240,399
---------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes, net 519,597 505,435
Deferred investment tax credits 45,061 47,577
Long-term capital lease obligation 20,768 19,660
Other 29,631 29,902
---------------------------------------------------
615,057 602,574
---------------------------------------------------
Commitments and Contingencies (Notes 13 and 16) -- --
Total $2,866,685 $2,669,785
---------------------------------------------------
---------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
</TABLE>
Delmarva Power & Light Company
33
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
(Dollars in Thousands) As of December 31,
1995 1994
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
COMMON STOCKHOLDERS' EQUITY
Total common stockholders' equity (1) $923,440 $884,169
-----------------------------------------
CUMULATIVE PREFERRED STOCK
Par value $1 per share, 10,000,000 shares authorized, none outstanding -- --
Par value $25 per share, 3,000,000 shares authorized,
7 3/4% Series, 1,600,000 shares issued (2) 40,000 40,000
Par value $100 per share, 1,800,000 shares authorized:
</TABLE>
<TABLE>
<CAPTION>
Current call
Series Shares outstanding price per share
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C>
3.70%-5% 320,000 $103.00-$105.00 32,000 32,000
6 3/4% 200,000 (3) 20,000 20,000
7.52% 150,000 $103.50 15,000 15,000
Adjustable--5.56%, 5.54% (4) 160,850 $103.00 (5) 16,085 16,085
Auction rate--4.54%, 3.32% (4) 450,000 $100.00 45,000 45,000
-----------------------------------------
168,085 168,085
-----------------------------------------
</TABLE>
<TABLE>
<CAPTION>
LONG-TERM DEBT
First Mortgage Bonds:
Maturity Interest Rates
- -----------------------------------------------
<S> <C> <C> <C>
1997 6 3/8% 25,000 25,000
2002-2003 6.40%-6.95% 120,000 120,000
2014-2015 7.30%-8.15% 81,000 81,000
2018-2022 5.90%-8.50% 208,200 208,200
2025 7.71% 100,000 --
2032 6.05% 15,000 15,000
-----------------------------------------
549,200 449,200
</TABLE>
<TABLE>
<S> <C> <C>
Amortizing First Mortgage Bonds, due 1997-2008, 6.95% 25,800 --
Other Bonds, due 2011-2017, 7.15%-7.50% 54,500 54,500
Pollution Control Notes:
Series 1973, due 1996-1998, 5 3/4% 6,250 6,375
Series 1976, due 1996-2006, 7 1/8%-7 1/4% 3,100 3,200
Medium Term Notes, due 1998, 5.69% 25,000 25,000
Medium Term Notes, due 1999, 7 1/2% 30,000 30,000
Medium Term Notes, due 2002-2004, 8.30%-9.29% 39,000 39,000
Medium Term Notes, due 2007, 8 1/8% 50,000 50,000
Medium Term Notes, due 2020-2021, 8.96%-9.95% 61,000 61,000
Mortgage Notes, 9.65% (6) 6,938 7,606
Mortgage Note, 8% (7) 4,279 4,588
Term Loan (8) -- 45,000
Other Obligations, due 1996-2000, 9.63% 940 1,126
Unamortized premium and discount, net (618) (638)
Current maturities of long-term debt (1,485) (1,399)
-----------------------------------------
Total long-term debt 853,904 774,558
-----------------------------------------
Total capitalization 1,945,429 1,826,812
-----------------------------------------
Variable Rate Demand Bonds (9) 86,500 71,500
-----------------------------------------
Total capitalization with Variable Rate Demand Bonds $2,031,929 $1,898,312
-----------------------------------------
-----------------------------------------
</TABLE>
(1) Refer to Consolidated Statements of Changes in Common Stockholders' Equity
for additional information.
(2) Redeemable beginning September 30, 2002, at $25 per share.
(3) Redeemable beginning November 1, 2003, at $100 per share.
(4) Average rates during 1995 and 1994, respectively.
(5) Call price changes to $100 per share for redemptions on or after July 1,
1996.
(6) Repaid through monthly payments of principal and interest over 15 years
ending November 2002.
(7) Repaid through monthly payments of principal and interest using a 15-year
principal amortization, with the unpaid balance due in September 1999.
(8) Refer to Note 12 to the Consolidated Financial Statements for additional
information.
(9) Classified under current liabilities as discussed in Note 12 to the
Consolidated Financial Statements.
See accompanying Notes to Consolidated Financial Statements.
Delmarva Power & Light Company
34
<PAGE>
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
(Dollars in Thousands)
Common Additional Unearned
Shares Par Paid-in Retained Treasury Compen-
Outstanding Value (1) Capital Earnings Stock (2) sation Total
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE AS OF JANUARY 1, 1993 54,143,853 $121,824 $374,976 $249,176 -- $(187) $745,789
Net income 111,076 111,076
Cash dividends declared
Common stock ($1.54) (89,792) (89,792)
Preferred stock (10,002) (10,002)
Issuance of common stock
Public offering 3,300,000 7,425 69,713 77,138
DRIP (3) 1,246,380 2,804 26,519 29,323
Stock options 139,050 313 2,689 3,002
Expenses (2,627) (2,627)
Reacquired shares (31,490) $(748) (748)
Shares granted (4) 31,490 748 (748) --
Amortization of unearned compensation 260 260
Refinancing of preferred stock (273) (951) (1,224)
--------------------------------------------------------------------------------
BALANCE AS OF DECEMBER 31, 1993 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) (91,436) (91,436)
Preferred stock (9,370) (9,370)
Issuance of common stock
DRIP (3) 703,726 1,584 13,199 14,783
Other Issuance 8,997 20 171 191
Reacquired shares (36,840) (794) (794)
Shares granted (4) 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) (92,686) (92,686)
Preferred stock (9,942) (9,942)
Issuance of common stock
DRIP (3) 1,210,048 2,723 21,806 24,529
Stock options 3,900 9 63 72
Other issuance 4,731 11 82 93
Reacquired shares (63,370) (1,253) 19 (1,234)
Shares granted (4) 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
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
</TABLE>
(1) The Company's common stock has a par value of $2.25 per share and
90,000,000 shares are authorized.
(2) Treasury Stock, which is recorded at cost, is included in Additional Paid-
in Capital on the Consolidated Balance Sheet.
(3) Dividend Reinvestment and Common Share Purchase Plan (DRIP)--As of December
31, 1995, 149,648 shares remained on the registration for issuance through
the DRIP. On January 29, 1996, the Company filed with the Securities and
Exchange Commission to register an additional 6,000,000 shares for issuance
through the DRIP.
(4) Shares of restricted common stock granted under the Company's Long Term
Incentive Plan.
See accompanying Notes to Consolidated Financial Statements.
Delmarva Power & Light Company
35
<PAGE>
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 1.1 million. In 1995, 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 470,000 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
subsidiaries' nonutility activities include landfill and wastehauling
operations, the operation and maintenance of energy-related projects, real
estate sales and development, and investments in 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, 1995, was as follows: DPSC, 64%; MPSC, 27%; VSCC, 3%;
and FERC, 6%.
Refer to Note 8 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 and
its wholly-owned subsidiaries--Delmarva Capital Investments, Inc.; Delmarva
Energy Company; Delmarva Industries, Inc.; and Delmarva Services Company. 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 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.
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 1995 and 1994,
and 3.7% for 1993. Depreciation expense includes a provision for the Company's
share of the estimated cost of decommissioning nuclear power plant reactors
based on amounts billed to customers for such costs. Refer to Note 7 to the
Consolidated Financial Statements for additional information on nuclear
decommissioning.
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 7.1% in 1995, 9.3% in 1994, and 9.6%
in 1993.
Delmarva Power & Light Company
36
<PAGE>
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.
Leveraged Leases
As of December 31, 1995, 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.
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.
2. BASE RATE MATTERS
Electric and gas base rate increases which became effective in 1993, 1994, and
1995 are summarized in the following table.
<TABLE>
<CAPTION>
Return On
Annualized Base Effective Common Equity
Jurisdiction Revenue Increase Date Allowed
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Retail Electric
Delaware (1) $ 4.5 million or 0.9% 05/01/95 11.5%
Delaware (2) $ 24.9 million or 5.8% 06/01/93 11.5%
Maryland (3) $ 7.8 million or 4.3% 04/01/93 --
Virginia $ 1.3 million or 5.4% 10/05/93 11.05%
Resale (FERC)(4) $ 1.5 million or 1.5% 06/03/93 --
Gas (5) $ 3.1 million or 3.1% 11/01/94 11.5%
</TABLE>
(1) Net of reduced fuel rates, customer rates decreased 1.45%.
(2) Net of fuel savings from Hay Road Unit 4, customer rates increased 3.7%.
(3) Although a return on equity was not specified, the Company believes that
the implied return on equity approaches 12%. Net of fuel savings from Hay
Road Unit 4, customer rates increased 2.3%.
(4) The settlement agreement did not specify a return on equity.
(5) Net of reduced fuel rates, customer rates decreased 1.75%.
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 following:
- - A rate moratorium whereby the Company will not increase its electric base
rates before January 1, 1997. However, the Company is permitted to file for
a redesign of electric base rates that would not result in a change in
total electric base revenues.
- - A provision whereby the Company would be required to submit a proposal
supporting current rate levels if its return on common equity exceeds its
currently approved rate of 11.5%. A return on common equity test will be
performed quarterly beginning with the twelve-month period ended December
31, 1995, and continuing through the twelve-month period ended December 31,
1996.
- - Funding of nuclear decommissioning costs at the current Nuclear Regulatory
Commission (NRC) minimum financial assurance amount. See Note 7 to the
Consolidated Financial Statements for a further discussion of the Company's
accounting and funding policies for nuclear decommissioning.
In 1994, the Company also had filed an application with the MPSC for a $3.9
million "limited issues" increase in electric base rates. In April 1995, the
MPSC denied the Company's application to increase rates because it was unable to
determine the reasonableness of the Company's current base rates due to the
"limited issues" format of the case.
The electric base rate increases that became effective in 1993 were designed to
recover higher costs associated with completion of Hay Road Unit 4, costs for
postretirement benefits other than pensions, and other items, including general
inflation.
The gas base rate increase effective in 1994 was designed to recover higher
operating costs and plant investment levels than were reflected in the previous
rates.
Delmarva Power & Light Company
37
<PAGE>
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 $151.3 million and $149.2 million as of December 31, 1995 and 1994,
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) 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operation
Federal: Current $46,517 $50,276 $50,264
Deferred 16,452 5,592 7,710
State: Current 9,851 11,268 10,839
Deferred 3,257 928 1,832
Investment tax credit adjustments, net (2,516) (1,898) (2,515)
-----------------------------------------------------------------------
Total Operation 73,561 66,166 68,130
-----------------------------------------------------------------------
Other income
Federal: Current 5,263 2,789 9,398
Deferred (3,686) (2,008) (9,398)
State: Current 433 349 287
Deferred (31) 317 (1,315)
-----------------------------------------------------------------------
Total Other Income 1,979 1,447 (1,028)
-----------------------------------------------------------------------
Total income tax expense $75,540 $67,613 $67,102
-----------------------------------------------------------------------
-----------------------------------------------------------------------
</TABLE>
Reconciliation of Effective Income Tax Rate
The amount computed by multiplying income before tax by the federal statutory
rate is reconciled below to the total income tax expense.
<TABLE>
<CAPTION>
1995 1994 1993
(Dollars in Thousands) Amount Rate Amount Rate Amount Rate
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Statutory federal income
tax expense $67,560 35% $61,574 35% $62,362 35%
Increase (decrease) due to
State income taxes, net of
federal tax benefit 8,792 5 8,361 4 7,567 4
Other, net (812) (1) (2,322) (1) (2,827) (1)
------------------------------------------------------------------------------------
Total income tax expense $75,540 39% $67,613 38% $67,102 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) 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Deferred Tax Liabilities
Utility plant basis differences
Accelerated depreciation $307,346 $296,651
Other 99,941 98,437
Leveraged leases 44,662 47,080
Deferred recoverable income taxes 64,376 64,130
Other 54,507 44,418
--------------------------------------
Total deferred tax liabilities 570,832 550,716
--------------------------------------
Deferred Tax Assets
Deferred ITC 15,719 17,763
Other 40,916 36,794
--------------------------------------
Total deferred tax assets 56,635 54,557
--------------------------------------
Total deferred taxes, net $514,197 $496,159
--------------------------------------
--------------------------------------
</TABLE>
Valuation allowances for deferred tax assets were not material as of December
31, 1995 and 1994.
Delmarva Power & Light Company
38
<PAGE>
4. PURCHASE 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). As disclosed in Note 12 to the
Consolidated Financial Statements, the Company financed the acquisition with
$125.8 million of long-term debt and the balance with short-term debt. The
acquisition resulted in approximately 37,500 new electric retail customers,
which represents 9% of the Company's current customer base.
The acquisition has been accounted for as a purchase. Immediately after the
acquisition, COPCO was merged into the Company and is now being operated as the
Conowingo District. Operating results of the Conowingo District have been
included in the Consolidated Statements of Income since June 19, 1995. Pro forma
results of the Company, assuming the acquisition had taken place at the
beginning of each period presented, would not be materially different from the
results reported.
Under FERC accounting requirements, the COPCO assets have been recorded at their
net book value, reflecting electric plant of $107.8 million and related
accumulated depreciation of $31.7 million and other net assets and liabilities
of $7.9 million. The difference between the amount paid to PECO plus acquisition
costs and the net book value of the COPCO assets, or $75.8 million, has been
recorded as goodwill and is included in electric utility plant. The MPSC has
approved recovery of this goodwill using a sinking fund method through Maryland
retail rates in two components. Approximately $50 million of the goodwill will
be recovered as an acquisition adjustment with a carrying charge over 20 years
beginning at the time of the Company's next Maryland base rate case. The
remaining $26 million will be recovered with a carrying charge over
approximately 10 years via a pre-approved surcharge to the Company's existing
Maryland retail rates. This surcharge was placed in effect for Conowingo
District customers on February 1, 1996. For financial statement purposes, the
goodwill is being amortized on a straight-line basis over 40 years beginning
July 1995.
In conjunction with the acquisition, the Company signed a contract with PECO to
purchase electric capacity and energy from the PECO system beginning February 1,
1996, and ending May 31, 2006. The base amount of the capacity purchase, which
is subject to certain possible adjustments, will start at 205 megawatts (MW) and
will increase annually to 279 MW in 2006. Under another contract, the Company
agreed to purchase the Conowingo District's interim electric power requirements
from PECO from the acquisition date until February 1, 1996.
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. 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, 1995 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 $129,028 $69,134 $9,595
Salem 7.41% 164 MW 210,458 93,728 10,103
Coal-Fired
Keystone 3.70% 63 MW 19,244 7,506 339
Conemaugh 3.72% 63 MW 32,406 8,543 520
Transmission Facilities Various 4,564 2,103 --
Other Facilities Various 1,721 128 797
------------------------------------------
Total $397,421 $181,142 $21,354
------------------------------------------
------------------------------------------
</TABLE>
Delmarva Power & Light Company
39
<PAGE>
7. NUCLEAR DECOMMISSIONING
The Company records a liability for its share of the estimated cost of
decommissioning the Peach Bottom and Salem nuclear reactors over the remaining
lives of the plants based on amounts collected in rates charged to electric
customers. For utility rate-setting purposes, the Company estimates its share of
future nuclear decommissioning costs based on 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 $122 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 $37.2 million as of December 31,
1995. The provision reflected in depreciation expense for nuclear
decommissioning was $3.6 million in 1995, $2.4 million in 1994, and $2.3 million
in 1993. External trust funds established by the Company for the purpose of
funding nuclear decommissioning costs had an aggregate balance of $25.5 million
as of December 31, 1995. Earnings on the trust funds are recorded as an increase
to the accrued nuclear decommissioning liability, which, in effect, reduces the
expense recorded for nuclear decommissioning.
The ultimate cost of nuclear decommissioning for the Peach Bottom and Salem
reactors may exceed the NRC minimum financial assurance amount, which is updated
annually under a NRC prescribed formula.
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. These "regulatory assets" are included on the
Company's Consolidated Balance Sheets under "Deferred Charges and Other Assets."
As of December 31, 1995, the Company had $207.0 million of regulatory assets,
which included the following: Deferred debt refinancing costs--$24.0 million;
Deferred recoverable income taxes--$151.3 million (refer to Note 3 to the
Consolidated Financial Statements); Deferred recoverable plant costs--$9.8
million; Deferred costs for decontamination and decommissioning of United States
Department of Energy gaseous diffusion enrichment facilities--$7.2 million;
Deferred demand-side management costs--$5.4 million; and other regulatory assets
- --$9.3 million. The costs of these assets are either being recovered or are
probable of being recovered through customer rates. Generally, the costs of
these assets are recognized in operating expenses over the period the cost is
recovered from customers.
In March 1995, the FASB issued SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which requires
the Company to review long-lived assets and certain identifiable intangibles
held and used by the Company for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. If an asset is considered impaired, then its value would be written
down with a corresponding charge to earnings. SFAS No. 121 also requires rate-
regulated companies to write off regulatory assets against earnings whenever
those assets no longer meet the criteria for recognition of a regulatory asset
as defined by SFAS No. 71. The new standard is effective in 1996. Based on
current circumstances, the Company does not expect the adoption of SFAS No. 121
to have a material effect upon the Company's financial condition or results of
operations.
9. INVESTMENTS
As of December 31, 1995, the Company had $39.6 million of investments in
securities which were included in the following balance sheet classifications:
Funds held by trustee--$36.3 million; Other investments and nonutility property,
net--$1.6 million; Cash and cash equivalents--$1.7 million. These securities,
based on the Company's intent and criteria established by SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities," are
categorized as available-for-sale securities. The fair value of such securities
was not materially different from book value as of December 31, 1995. Gains and
losses from the sale of investment securities were not material to the Company's
operating results in 1995, 1994, and 1993. As of December 31, 1995, the
Company's investments in debt securities, other than those considered to be cash
equivalents, had the following maturities: $2.4 million due in 1996; $9.3
million due in 1997-2000; and $8.7 million due in 2001-2005.
Delmarva Power & Light Company
40
<PAGE>
10. COMMON STOCK
Refer to the Consolidated Statements of Changes in Common Stockholders' Equity
for information concerning issuances and redemptions of common stock during
1993-1995.
The Company's Restated Certificate and Articles of Incorporation and the
Mortgage and Deed of Trust collateralizing the Company's outstanding First
Mortgage Bonds contain restrictions on the payment of dividends on common stock.
Such restrictions would become applicable if the Company's capital and retained
earnings fall below certain specific levels or if preferred dividends are in
arrears. Under the most restrictive of these provisions, as of December 31,
1995, approximately $246.2 million was available for payment of common
dividends.
Prior to January 1, 1993, the Company had a nonqualified stock option plan for
certain employees. Options were priced at the actual market value on the grant
date. Effective January 1, 1993, the Company's Board of Directors declared that
no new stock options will be granted and that the performance-based restricted
stock program will be the program in effect under the Long Term Incentive Plan.
Changes in stock options are summarized below.
<TABLE>
<CAPTION>
1995 1994 1993
Number Option Number Option Number Option
of Shares Price of Shares Price of Shares Price
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Beginning-of-year
balance 53,050 $17 1/2-$21 1/4 53,050 $17 1/2-$21 1/4 192,100 $17 1/2-$21 1/4
Options exercised 3,900 $17 1/2-$18 1/8 -- -- 139,050 $17 1/2-$21 1/4
Options forfeited 2,800 $20 1/2-$21 1/4 -- -- -- --
End-of-year balance 46,350 $17 1/2-$21 1/4 53,050 $17 1/2-$21 1/4 53,050 $17 1/2-$21 1/4
Exercisable 46,350 $17 1/2-$21 1/4 53,050 $17 1/2-$21 1/4 53,050 $17 1/2-$21 1/4
</TABLE>
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which encourages, but does not require, entities to recognize
compensation costs for stock-based employee compensation plans using a fair
value based method of accounting rather than the intrinsic value based method of
accounting currently prescribed by Accounting Principles Board (APB) Opinion No.
25, "Accounting for Stock Issued to Employees." Entities electing to continue
using the accounting prescribed by APB Opinion No. 25 are required to disclose
pro forma net income and earnings per share as if the fair value based method of
accounting under SFAS No. 123 had been applied. The new standard is effective in
1996. The Company does not expect to adopt the accounting provisions of SFAS No.
123 for income statement recognition purposes.
11. PREFERRED STOCK
On November 4, 1993, the Company issued 200,000 shares of 6 3/4%, cumulative
preferred stock, $100 per share par value, for $20 million. On December 1, 1993,
the Company used the proceeds and cash on-hand to redeem $18.28 million of its
7.88% series and $10.0 million of its 7.84% series preferred stock.
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.
On June 19, 1995, the Company issued the following debt to finance the $158.2
million acquisition of COPCO: $100 million of First Mortgage Bonds, Series I,
7.71% Bonds Due June 1, 2025; $25.8 million of First Mortgage Bonds, Series I,
6.95% Amortizing Bonds Due June 1, 2008, with principal repayable in annual
installments beginning June 1, 1997; and the balance with short-term debt.
On August 30, 1995, the Schuylkill County Industrial Development Authority,
Commonwealth of Pennsylvania, issued on behalf of a nonutility subsidiary of the
Company, $15 million of Variable Rate Demand Revenue Bonds due on demand or at
maturity on October 1, 2019. Proceeds from the bonds are being used to finance
the past and future expansion of a landfill which is owned and operated by the
subsidiary.
The Company's debt obligations included Variable Rate Demand Bonds (VRDB) in the
amounts of $86.5 million as of December 31, 1995, and $71.5 million as of
December 31, 1994. Although VRDB are classified as current liabilities because
VRDB are due on demand by the bondholder, such bonds are immediately remarketed
because the interest rate is set at market. The Company may also 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 $86.5 million
balance of VRDB outstanding as of December 31, 1995, matures in 2017 ($26
million), 2019 ($15 million), 2028 ($15.5 million), and 2029 ($30 million).
Average annual interest rates on the VRDB were 4.0% in 1995.
Delmarva Power & Light Company
41
<PAGE>
As of December 31, 1995, the Company had $150 million of bank lines of credit,
including $130 million of such credit lines under which the Company may convert
short-term borrowings to a term loan with a maturity date of 12 to 24 months
following the date of the requested conversion. As of December 31, 1994, the
Company had reclassified $45 million of short-term debt as long-term debt ("Term
Loan") in recognition of the expected refinancing on a long-term basis and long-
term financing capability provided by the credit lines. During 1995, this short-
term debt was repaid resulting in no term loan balance as of December 31, 1995.
The Company generally is required to pay commitment fees for its credit lines.
The lines of credit are periodically reviewed by the Company, at which time they
may be renewed or canceled.
Maturities of long-term debt and sinking fund requirements during the next five
years are as follows: 1996--$3.2 million; 1997--$29.0 million; 1998--$35.0
million; 1999--$37.4 million; 2000--$4.2 million.
As of December 31, 1995, the fair market value of the Company's long-term debt
was $936.5 million in comparison to the book value of $853.9 million. As of
December 31, 1994, the fair market value of the Company's long-term debt was
$752.5 million in comparison to the book value of $774.6 million. The fair
market value of the Company's long-term debt was based on quoted market prices
of the Company's securities or securities with similar characteristics.
13. COMMITMENTS
The Company currently estimates its expenditures for construction of utility
plant, excluding AFUDC, and commitments for purchases under fuel supply
contracts, excluding nuclear fuel, to be approximately $223 million in 1996 and
$236 million in 1997.
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.
As discussed in Note 4 to the Consolidated Financial Statements, the Company
also has agreements to purchase capacity and energy from PECO effective June 19,
1995, through May 31, 2006. Under the terms of these agreements, the Company's
expected commitments for capacity and energy charges are as follows: 1996--$57.6
million; 1997--$58.6 million; 1998--$63.6 million; 1999--$70.9 million; 2000--
$77.3 million; after 2000--$505.5 million; total--$833.5 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 generally is
the net book value of the nuclear fuel financed, which was $31.7 million as of
December 31, 1995.
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 $158.1 million in aggregate. The Company also has long-
term leases for certain other facilities and equipment. Minimum commitments as
of December 31, 1995, 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: 1996--$6.1
million; 1997--$6.1 million; 1998--$6.1 million; 1999--$6.0 million; 2000--$4.1
million, after 2000--$140.9 million; total--$169.3 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) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest on capital leases $1,773 $1,560 $1,296
Amortization of capital leases 8,044 11,456 10,243
Operating leases 13,619 14,552 15,176
-----------------------------------------
$23,436 $27,568 $26,715
-----------------------------------------
-----------------------------------------
</TABLE>
Delmarva Power & Light Company
42
<PAGE>
14. 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. Pension plan assets consist primarily of equity securities, fixed
income securities, and cash equivalents.
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) 1995 1994
- ------------------------------------------------------------------------------------------------------
<S> <C> <C>
Accumulated benefit obligation
Vested $338,485 $265,597
Nonvested 26,024 19,311
-------------------------------------------
364,509 284,908
Effect of estimated future compensation increases 109,706 67,947
-------------------------------------------
Projected benefit obligation 474,215 352,855
Plan assets at fair value 616,600 502,588
-------------------------------------------
Excess of plan assets over projected benefit obligation 142,385 149,733
Unrecognized prior service cost 29,191 19,155
Unrecognized net gain (124,850) (129,842)
Unrecognized net transition asset (29,827) (33,141)
-------------------------------------------
Prepaid pension cost $ 16,899 $ 5,905
-------------------------------------------
-------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Components of Net Pension Cost Year ended December 31,
(Dollars in Thousands) 1995 1994 1993
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost--benefits earned during period $ 9,719 $ 10,939 $13,152
Interest cost on projected benefit obligation 30,654 26,574 26,411
Actual return on plan assets (135,850) 3,349 (58,247)
Net amortization and deferral 83,981 (52,601) 14,748
-------------------------------------------
Net pension cost $(11,496) $(11,739) $(3,936)
-------------------------------------------
-------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Assumptions 1995 1994 1993
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rates used to determine projected
benefit obligation as of December 31 7.00% 8.25% 7.25%
Rates of increase in compensation levels 5.00% 5.50% 6.50%
Expected long-term rates of return on assets 9.00% 8.25% 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 to the Consolidated Financial Statements for additional
information on the ERO.
The net 1994 pension cost reflects a decrease of $4.5 million attributed to a
reduction in the assumed rate of increase in compensation levels from 6.5% to
5.5%, effective January 1, 1994. Also, the discount rate was increased from
7.25% to 8.25%, effective October 1, 1994.
Delmarva Power & Light Company
43
<PAGE>
15. 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. Plan assets held in external trust funds consist
primarily of investments in domestic equity securities and fixed income
securities.
The following schedules show the funded status of the plan, the components of
the cost of postretirement benefits other than pensions, and assumptions.
<TABLE>
<CAPTION>
Reconciliation of Funded Status of the Plan As of December 31,
(Dollars in thousands) 1995 1994
- ------------------------------------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation (APBO)
Active employees fully eligible for benefits $6,019 $9,319
Other active employees 23,990 12,638
Current retirees 63,629 58,445
-------------------------------------------
93,638 80,402
Plan assets at fair value 24,900 15,140
-------------------------------------------
APBO in excess of plan assets 68,738 65,262
Unrecognized prior service cost (423) --
Unrecognized net loss (5,212) (256)
Unrecognized transition obligation (61,493) (65,110)
-------------------------------------------
Accrued/(prepaid) postretirement benefit cost $1,610 $(104)
-------------------------------------------
-------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Annual Cost of Postretirement Benefits Other Than Pensions Year ended December 31,
(Dollars in thousands) 1995 1994 1993
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost--benefits earned during period $2,152 $2,127 $2,206
Interest cost on projected benefit obligation 6,601 5,520 5,613
Actual return on plan assets (1,008) 100 --
Amortization of the unrecognized transition obligation 3,617 3,617 3,617
Other, net 149 (481) --
-------------------------------------------
Net postretirement benefit cost $11,511 $10,883 $11,436
-------------------------------------------
-------------------------------------------
<CAPTION>
Assumptions 1995 1994 1993
- ------------------------------------------------------------------------------------------------------
Discount rates used to determine APBO as of December 31 7.00% 8.25% 7.25%
Rates of increase in compensation levels 5.00% 5.50% 6.50%
Expected long-term rates of return on assets 9.00% 8.25% 8.25%
Health-care cost trend rate 10.50% 11.00% 12.00%
</TABLE>
The health-care cost trend rate, or the expected rate of increase in health-care
costs, is assumed to decrease to 10.0% in 1996 and gradually decrease to 5.5% by
2005. Increasing the health-care cost trend rates of future years by one
percentage point would increase the accumulated postretirement benefit
obligation by $4.4 million and would increase annual aggregate service and
interest costs by $0.3 million.
16. CONTINGENCIES
Salem Outage
The Company owns 7.41% of Salem, which consists of two pressurized water nuclear
reactors (PWR) and is operated by Public Service Electric & Gas Company (PSE&G).
As of December 31, 1995, the Company's net investment in plant in-service for
Salem was approximately $57 million for Unit 1 and $60 million for Unit 2. Each
unit represents approximately 2% of the Company's total assets and approximately
3% of the Company's installed electric generating capacity.
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. The units will remain shut down until PSE&G makes the equipment and
management changes necessary to operate the units reliably over the long term.
The restart of the units is subject to NRC authorization. In December 1995,
PSE&G completed a workscope assessment of both units and estimated that Unit 1
would return to service in the second quarter of 1996 and Unit 2 in the third
quarter of 1996.
On February 21, 1996, PSE&G informed the Company that partial results from
recent inspections of Unit 1 using a new testing technology revealed indications
of degradation in a sig-
Delmarva Power & Light Company
44
<PAGE>
nificant number of steam generator tubes. PSE&G is continuing its inspections
and also will conduct further laboratory analysis of the tubes with results
expected in April 1996. Based on the results of inspections to date, PSE&G has
concluded that the Unit 1 outage will be extended for an indefinite period to
evaluate the state of the steam generators and to subsequently determine an
appropriate course of action. Degradation of steam generators in PWRs has become
of increasing concern for the nuclear industry. Nationally and internationally,
utilities have undertaken actions to repair or replace steam generators. In the
extreme, degradation of steam generators has contributed to the retirement of
several American nuclear power reactors.
PSE&G also has informed the Company that recent steam generator inspections of
Unit 2 using the new testing technology have revealed that the condition of the
Unit 2 steam generators is within current repair limits at the present time.
However, to confirm the Unit 2 test results, PSE&G also will conduct laboratory
analysis of the tubes for Unit 2. As a result of the delay in the restart of
Unit 1, PSE&G is focusing its efforts on the return of Unit 2 to service in the
third quarter of 1996, as scheduled. However, the Company cannot predict when
the NRC will approve the restart of the unit or when the restart actually will
occur.
In 1995, the Company incurred higher than expected operation and maintenance
costs at Salem of approximately $5 million, which reflect the operational
problems at the plant. These costs were expensed as incurred. Also, outage-
related replacement power costs were estimated to be approximately $8 million.
One-half of the estimated replacement power costs was expensed and the other
one-half was deferred on the Company's Consolidated Balance Sheet in expectation
of future recovery. Based on PSE&G's current estimates, the Company estimates
that its share of additional costs related to the outage in 1996 will consist of
operation and maintenance costs ranging from $4 million to $7 million, which
will be expensed as incurred, and replacement power costs while the units are
out of service of approximately $750,000 per month, per unit. In total, the
Company estimates that its share of outage-related costs in 1996 will range from
$17 million to $22 million. However, these 1996 estimates could change as a
result of PSE&G's analysis of the degradation of the steam generator tubes.
Beyond 1996, the Company cannot predict the amount of outage-related costs it
could incur. During 1996, the Company plans to file a proposal with the DPSC,
the Company's primary rate jurisdiction, for recovery of replacement power
costs.
Since the periods during which these 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 currently anticipated,
the actual costs to be incurred by the Company may vary from the foregoing
estimates.
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 two 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 $5.4 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 $1.4 million per year.
Other
The Company is involved in certain legal and administrative proceedings before
various courts and governmental agencies concerning rates, fuel contracts, tax
filings, and other matters. The Company expects that the ultimate disposition of
these proceedings will not have a material effect on the Company's financial
position or results of operations.
Delmarva Power & Light Company
45
<PAGE>
17. SUPPLEMENTAL CASH FLOW INFORMATION
<TABLE>
<CAPTION>
Cash Paid during the Year for Year Ended December 31,
(Dollars In Thousands) 1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest, net of capitalized amount $62,660 $57,837 $58,154
Income taxes, net of refunds $66,764 $67,922 $72,384
</TABLE>
18. NONUTILITY SUBSIDIARIES
The following presents condensed financial information of the Company's
nonregulated wholly-owned subsidiaries: Delmarva Capital Investments, Inc.;
Delmarva Energy Company; and Delmarva Industries, Inc. A subsidiary that leases
real estate to the Company's utility business, Delmarva Services Company, is
excluded from these statements since its income is derived from intercompany
transactions which are eliminated in consolidation.
<TABLE>
<CAPTION>
Condensed Subsidiary Statements of Income
(Dollars In Thousands)
1995 1994 1993
- --------------------------------------------------------------------------------
Revenues and Gains
<S> <C> <C> <C>
Landfill and waste hauling $13,505 $14,186 $11,745
Operating services 26,564 22,468 22,118
Real estate 5,820 4,450 1,677
Leveraged leases 1,772 272 835
Other revenue 4,381 1,766 1,261
----------------------------------------
52,042 43,142 37,636
----------------------------------------
Costs and Expenses
Operating expenses 45,594 38,499 36,424
Interest expense, net 492 370 --
Income tax expense (benefit) 1,810 1,921 (596)
----------------------------------------
47,896 40,790 35,828
----------------------------------------
Net income $ 4,146 $ 2,352 $ 1,808
----------------------------------------
----------------------------------------
Earnings per share of common stock
attributed to subsidiaries $0.07 $0.04 $0.03
</TABLE>
<TABLE>
<CAPTION>
Condensed Subsidiary Balance Sheets
(Dollars In Thousands)
As of December 31,
Assets 1995 1994
- ---------------------------------------------------------
<S> <C> <C>
Current assets
Cash and cash equivalents $ 19,483 $ 8,631
Other 6,633 5,702
-------------------------
26,116 14,333
-------------------------
Noncurrent assets
Investment in
Leveraged leases 48,367 49,595
Other 9,925 4,354
Landfill & waste hauling
property, plant & equipment 24,177 25,424
Other 9,778 9,558
-------------------------
92,247 88,931
-------------------------
Total $118,363 $103,264
-------------------------
-------------------------
Liabilities and As of December 31,
Stockholder's Equity 1995 1994
- ---------------------------------------------------------
<S> <C> <C>
Current liabilities
Debt due within one year $ 506 $ 489
Variable rate demand bonds 15,000 --
Other 7,801 6,873
-------------------------
23,307 7,362
-------------------------
Noncurrent liabilities
Long-term debt 4,713 5,225
Deferred income taxes 50,064 53,592
Other 2,389 2,342
--------------------------
57,166 61,159
-------------------------
Stockholder's Equity 37,890 34,743
-------------------------
Total $118,363 $103,264
-------------------------
-------------------------
</TABLE>
Delmarva Power & Light Company
46
<PAGE>
19. SEGMENT INFORMATION
Segment information with respect to electric and gas operations was as follows:
<TABLE>
<CAPTION>
(Dollars In Thousands) 1995 1994 1993
- --------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric Operations
Operating revenues $899,662 $883,115 $875,663
Operating income 165,914 153,409 154,412
Depreciation 105,780 102,746 94,549
Construction expenditures 118,655 133,884 142,238
Gas Operations
Operating revenues 95,441 107,906 94,944
Operating income 12,492 9,747 9,727
Depreciation 7,242 6,777 6,380
Construction expenditures 16,959 20,235 17,753
Identifiable Assets, Net
Electric 2,493,797 2,314,448 2,267,050
Gas 189,339 188,813 160,618
Assets not allocated 183,549 166,524 164,811
</TABLE>
20. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments, consisting of normal
recurring accruals and unusual items as noted below, 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>
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
-------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------
<CAPTION>
1994
March 31 $292,394 $53,770 $39,641 $37,377 59,022 $0.63
June 30 218,465 33,994 20,776 18,453 59,402 0.31
September 30 260,601 42,921 29,366 27,008 59,542 0.46
December 31 219,561 32,471 18,527 16,102 59,542 0.27
-------------------------------------------------------------------------------------
$991,021 $163,156 $108,310 $98,940 59,377 $1.67
-------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------
</TABLE>
In the third quarter of 1994, the Company expensed the costs associated with the
ERO (Note 5 to the Consolidated Financial Statements), which decreased net
income by $10.7 million ($0.18 per share).
In the fourth quarter of 1994, the Company reduced the rate of salary increase
assumed for computation of pension cost, effective January 1, 1994, which
increased net income by $2.1 million ($0.03 per share).
Delmarva Power & Light Company
47
<PAGE>
DELMARVA POWER & LIGHT COMPANY
1995 ANNUAL REPORT TO STOCKHOLDERS
APPENDIX TO MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
DESCRIPTIONS OF GRAPHS
"REDUCED RESALE FINANCIAL RISK"
On page 23 of the 1995 Annual Report to Stockholders, a pie chart titled
"Reduced Resale Financial Risk" is displayed. The pie chart is comprised of the
Company's 1995 billed electric sales revenues by customer class (residential,
commercial, industrial, resale, and other) with the resale slice "exploded" out.
The following caption is under the chart: "The Company has substantially reduced
the financial risk of its resale business by signing long-term contracts and
extended notice provisions with all of its resale customers." The pie chart is
comprised of the following slices:
<TABLE>
<S> <C>
Residential 41%
Commercial 32%
Industrial 19%
Resale 7%
Other 1%
----
Total 100%
----
----
</TABLE>
"ELECTRIC PRICE COMPARISON"
On page 23 of the 1995 Annual Report to Stockholders, a bar graph titled
"Electric Price Comparison" is displayed. The graph compares the Company's
electric prices to the average prices for 27 regional utilities. The price
comparisons are based on 1994 average electric prices per kilowatt-hour sold and
are made for the residential, commercial, and industrial classes. The following
caption is next to the chart: "The Company's prices for electricity are below
the regional average. A balanced and flexible energy supply plan helped the
Company gain this advantage."
For each customer class, two side-by-side vertical, rectangular bars are
displayed. The bar on the left represents the Company's price and the bar on
the right represents the regional average price. The y-axis is scaled in cents,
beginning at zero, increasing by increments of two cents, and ending at twelve
cents. The prices graphed are as follows:
<TABLE>
<CAPTION>
1994 CENTS/kWh Sold
---------------------------
Regional
Delmarva Average
---------------------------
<S> <C> <C>
Residential 8.74 10.29
Commercial 7.01 8.67
Industrial 4.48 6.65
</TABLE>
-1-
<PAGE>
"INTERNALLY GENERATED FUNDS & CONSTRUCTION EXPENDITURES"
On page 27 of the 1995 Annual Report to Stockholders, a bar graph titled
"Internally Generated Funds & Construction Expenditures" is displayed. The
y-axis is scaled in millions of dollars, beginning at zero, increasing by
increments of $50 million, and ending at $162.5 million. The x-axis consists of
the years 1993, 1994, 1995, 1996 (forecast), and 1997 (forecast). For each
year, two side-by-side vertical, rectangular bars are displayed. The bar on the
left is internally generated funds and the bar on the right is construction
expenditures. The following caption is next to the chart: "The percentage of
construction expenditures funded internally is expected to remain high through
1997." The graphed data are as follows:
<TABLE>
<CAPTION>
$ Millions
-------------------------------------------------
1993 1994 1995 1996* 1997*
-------------------------------------------------
<S> <C> <C> <C> <C> <C>
Internally generated funds 109 124 137 141 142
Construction expenditures 160 154 136 134 160
* forecast
</TABLE>
-2-
<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. 33-39756,
33-63582, 33-53855 and 333-00505) and on Form S-8 (File No. 33-33810) of our
report dated February 2, 1996, except as to the information presented under
the caption Salem Outage in Note 16, for which the date is February 26, 1996,
on our audits of the consolidated financial statements of Delmarva Power &
Light Company and its subsidiary companies as of December 31, 1995 and 1994
and for each of the three years in the period ended December 31, 1995, which
report is incorporated by reference in this Annual Report on Form 10-K.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
March 26, 1996
<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 1995
ANNUAL REPORT TO STOCKHOLDERS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,092,894
<OTHER-PROPERTY-AND-INVEST> 139,423
<TOTAL-CURRENT-ASSETS> 245,455
<TOTAL-DEFERRED-CHARGES> 251,644
<OTHER-ASSETS> 137,249
<TOTAL-ASSETS> 2,866,685
<COMMON> 136,713
<CAPITAL-SURPLUS-PAID-IN> 504,865
<RETAINED-EARNINGS> 281,862
<TOTAL-COMMON-STOCKHOLDERS-EQ> 923,440
0
168,085
<LONG-TERM-DEBT-NET> 853,904
<SHORT-TERM-NOTES> 63,154
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1,485
0
<CAPITAL-LEASE-OBLIGATIONS> 20,768
<LEASES-CURRENT> 12,604
<OTHER-ITEMS-CAPITAL-AND-LIAB> 823,245
<TOT-CAPITALIZATION-AND-LIAB> 2,866,685
<GROSS-OPERATING-REVENUE> 995,103
<INCOME-TAX-EXPENSE> 73,561
<OTHER-OPERATING-EXPENSES> 743,136
<TOTAL-OPERATING-EXPENSES> 816,697
<OPERATING-INCOME-LOSS> 178,406
<OTHER-INCOME-NET> 5,411
<INCOME-BEFORE-INTEREST-EXPEN> 183,817
<TOTAL-INTEREST-EXPENSE> 66,329
<NET-INCOME> 117,488
9,942
<EARNINGS-AVAILABLE-FOR-COMM> 107,546
<COMMON-STOCK-DIVIDENDS> 92,686
<TOTAL-INTEREST-ON-BONDS> 61,511
<CASH-FLOW-OPERATIONS> 239,428
<EPS-PRIMARY> 1.79
<EPS-DILUTED> 1.79
</TABLE>
