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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1993
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)
DELAWARE & VIRGINIA 51-0084283
(STATES OR OTHER JURISDICTIONS OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION) 19899
800 KING STREET, P. O. BOX 231 (ZIP CODE)
WILMINGTON, DELAWARE
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 302-429-3011
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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FIRST MORTGAGE BONDS (SERIES ISSUED NEW YORK STOCK EXCHANGE AND
PRIOR TO 1968) PHILADELPHIA STOCK EXCHANGE.
PREFERRED STOCK, CUMULATIVE, PAR VALUE PHILADELPHIA STOCK EXCHANGE
$100.00 (SERIES ISSUED PRIOR TO 1978)
NEW YORK STOCK EXCHANGE AND
COMMON STOCK, PAR VALUE $2.25 PHILADELPHIA STOCK EXCHANGE.
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
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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
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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 JANUARY 31, 1994 WAS $1,311,729,482.
AS OF JANUARY 31, 1994, THERE WERE ISSUED AND OUTSTANDING 59,082,904 SHARES
OF THE REGISTRANT'S COMMON STOCK, PAR VALUE $2.25.
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DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
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I (ITEM 1-SEGMENT PORTIONS OF THE 1993 ANNUAL REPORT TO STOCKHOLDERS OF
INFORMATION) AND DELMARVA POWER & LIGHT COMPANY.
II (ITEMS 6, 7 AND 8)
III PORTIONS OF THE DEFINITIVE PROXY STATEMENT FOR THE ANNUAL
MEETING OF STOCKHOLDERS OF DELMARVA POWER & LIGHT
COMPANY, TO BE HELD MAY 26, 1994, WHICH DEFINITIVE PROXY
STATEMENT IS EXPECTED TO BE FILED WITH THE SECURITIES AND
EXCHANGE COMMISSION ON OR ABOUT APRIL 21, 1994.
IV PORTIONS OF THE 1993 ANNUAL REPORT TO STOCKHOLDERS OF
DELMARVA POWER & LIGHT COMPANY
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TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business:
The Company.................................................. I-1
Segment Information.......................................... I-1
Competition.................................................. I-1
Electric Business.......................................... I-1
Gas Business............................................... I-3
Electric Operations.......................................... I-3
Installed Capacity......................................... I-3
Power Pool................................................. I-4
Reserve Margin............................................. I-4
Challenge 2000 Plan........................................ I-4
Power Plants................................................. I-6
Nuclear.................................................... I-6
Peach Bottom Units......................................... I-6
Salem Units................................................ I-7
Hay Road................................................... I-7
Life Extensions and Repowerings............................ I-7
Purchased Power.............................................. I-7
Cost of Output for Load...................................... I-8
Fuel Supply for Electric Generation.......................... I-8
Coal....................................................... I-8
Oil........................................................ I-8
Gas........................................................ I-8
Nuclear.................................................... I-9
Gas Operations............................................... I-10
Non-Regulated Utility Business (Steam Utility)............... I-10
Subsidiaries................................................. I-11
Regulatory and Rate Matters.................................. I-11
Base Rate Proceedings...................................... I-11
Fuel Adjustment Clauses.................................... I-13
Other Regulatory Matters................................... I-15
Construction and Financing Program........................... I-15
Environmental Matters........................................ I-17
Construction Expenditures.................................. I-17
Clean Air Act.............................................. I-17
Salem Nuclear Generating Station........................... 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-20
Executive Officers of the Registrant......................... I-21
Item 2. Properties....................................................... I-22
Item 3. Legal Proceedings................................................ I-23
Item 4. Submission of Matters to a Vote of Security Holders.............. I-24
i
TABLE OF CONTENTS
PAGE
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PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters.................................................... II-1
Item 6. Selected Financial Data....................................... II-1
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
Report of Independent Accountants...................................... II-2
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-15
ii
PART I
ITEM 1. BUSINESS
THE COMPANY
Delmarva Power & Light Company (the Company) was incorporated in Delaware in
1909 and in Virginia in 1979. The Company's wholly-owned subsidiaries, also
incorporated in Delaware, include Delmarva Energy Company, Delmarva Industries,
Inc., Delmarva Services Company, and Delmarva Capital Investments, Inc. For a
discussion of the Company's subsidiaries, see "Subsidiaries" on page I-11.
The Company is a public utility which provides electric service on the
Delmarva Peninsula in an area consisting of about 5,700 square miles with a
population of approximately one million. The Company also provides gas service
in an area consisting of about 275 square miles with a population of
approximately 457,000 in northern Delaware, including the City of Wilmington.
SEGMENT INFORMATION
See Note 17 of the Notes to Consolidated Financial Statements contained in
the Company's 1993 Annual Report to Stockholders filed as Exhibit 13.
COMPETITION
Competition is increasing for certain electric and gas energy markets
historically served by regulated utilities. In recent years, changing laws and
governmental regulations, interest in self-generation, and competition from
nonregulated energy suppliers are providing some utility customers with
alternative sources to satisfy their electric and gas needs.
Electric 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.
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 wholesale (resale) electricity producers and also
provided for the creation of a new category of electric power producers called
exempt wholesale generators (EWGs). These provisions of the Energy Act have
enhanced the ability of utilities and non-utility generators to compete to
serve resale customers currently served by a particular utility. Partly as a
result of the Energy Act, industry-wide resale markets are experiencing
increased competition. In 1993, gross electric revenues from the Company's
resale business were $105.0 million or 13.0% of billed electric sales revenues.
In response to the changing environment in the electric utility industry, the
Company has modified existing strategies and also developed new strategies.
From a customer or market perspective, the Company has concluded that focusing
on growing the retail portion of the business provides the best opportunity to
meet the twin objectives of satisfying customers' needs while providing a fair
return to shareholders. During 1993, the Company began to develop new products
and services for its retail markets and to hold preliminary discussions with
certain municipalities in Delaware to either purchase their electric systems or
enter into long-term supply contracts. In December 1993, the Company offered
$103.5 million to purchase the electric system of the City of Dover, Delaware
(Dover). Dover has approximately 18,500 electric customers and annual revenues
from electricity sales of about $37 million. Although the Company expects that
the impact on earnings from the potential purchase would be minimal over the
first year or two, incremental earnings are
I-1
expected once economies of scale are achieved. It is the Company's
understanding that other parties have shown interest in the generation segment
of Dover's business, but none have shown interest in purchasing Dover's entire
electric system. In February 1994, PECO Energy Company (PECO), formerly known
as Philadelphia Electric Company, announced that it is evaluating its strategic
alternatives with respect to Conowingo Power Company (COPCO), its Maryland
subsidiary, including determining the level of interest that other companies
may have in acquiring COPCO. The Company has expressed an interest to PECO in
acquiring COPCO and will seek to participate in an acquisition process if such
a process is commenced. See "Other Regulatory Matters--Conowingo Power Company"
on page I-15 for a further discussion of certain regulatory proceedings related
to COPCO in which the Company has intervened.
Although the Energy Act permits competition for wholesale customers only,
competitive forces exist within the retail market and are expected to increase.
Large retail customers (i.e. commercial and industrial customers) have choices
to reduce their energy costs, including self-generation and relocation to the
service territories of other utilities with lower rates. In addition,
regulatory authorities may permit the retail wheeling of electricity, thereby
permitting utilities and non-utility generators to compete to serve large
retail customers currently served by a particular utility. The Company is
positioned well for these competitive forces. The Company's prices for large
retail customers are among the lowest in the region and are competitive with
alternative sources of energy such as self-generation. The Company's average
price for commercial customers in 1992 was 7.04 cents per kilowatt hour (kwh)
compared to a regional average of 8.64 cents per kwh. The Company's average
price for industrial customers in 1992 was 4.63 cents per kwh compared to a
regional average of 6.59 cents per kwh. These regional averages are based on
1992 data for 27 utilities within a 300 mile radius of the Company. In order to
keep customer prices competitive, the Company is stepping up its efforts to
reduce costs.
The Company believes it should have the ability to offer flexible pricing in
order to compete to serve large retail customers. Such changes in pricing
methods could require modification to the existing regulatory process. In
Delaware, the Governor has convened a task force "to recommend reforms to the
existing regulatory process, structure and organization that will improve
utility efficiency and encourage utility innovation, while assuring continued
availability of utility services at affordable and competitive prices." The
task force includes representatives from the Delaware Public Service Commission
(DPSC), utilities (including the Company), industrial customers, government,
and the public. The task force plans to issue recommendations that can be
introduced as legislation in June 1994 in the General Assembly.
In the resale market, the Company is seeking to reduce the risk associated
with a customer switching energy suppliers on short notice because providing
electricity service requires investments in capital-intensive facilities which
have long lives and require long lead-times for construction. In the Company's
most recent resale base rate case, its resale customers agreed to provide a
two-year notice for load reductions up to 30% and a five-year notice for load
reductions greater than 30%.
Prior to this agreement, Old Dominion Electric Cooperative (ODEC), a resale
customer, advised the Company that it would purchase up to 150 megawatts (MW)
from another utility, beginning January 1, 1995. The Company is continuing to
negotiate a partial-requirements service agreement (to serve the balance of
ODEC's load) and a transmission service agreement (to transport the electricity
ODEC plans to purchase from another utility) to become effective January 1,
1995. The maximum reduction in annual non-fuel revenues that could result from
ODEC's purchase of 150 MW from another utility is estimated to be about $24
million or $0.24 per share based on projected shares outstanding in 1995. To
mitigate the potential impact of this loss of business and expected increases
in operating costs, the Company is pursuing off-system sales of capacity and
energy (targeted increase in revenues: $10-$20 million), intensifying cost
control efforts (targeted decrease in costs: $15-$20 million), and if
necessary, may apply for increases in customer rates (targeted increase in
revenues: $10-$15 million). The Company expects that some combination of these
strategies will reduce, or possibly eliminate, the adverse earnings per share
effect; however, the ultimate effect on future earnings depends on the degree
of success experienced by the Company in implementing its strategies.
I-2
Gas Business
As a result of FERC initiatives, the interstate gas pipeline system has been
opened further to permit the transportation of natural gas by end users,
including the Company's gas customers. The Company has in place local
transportation tariffs to complement this interstate pipeline service. As a
result, some Company gas customers now buy gas directly from producers and
transport the gas to their facilities in Delaware, paying a transportation fee
to the Company for the use of the Company's gas transmission and distribution
facilities.
An issue contested in the Company's most recent gas base rate case involved
the conditions under which firm customers would be able to switch to non-firm
service such as Interruptible Gas Transportation (IGT) service. The Company's
tariff in effect prior to this case did not allow firm customers to switch to
non-firm service. The Company had proposed in this case to allow firm customers
to switch to non-firm service with three years' advance notice. Intervenors in
the case, comprised of a group of large firm and non-firm industrial gas
customers, sought DPSC approval to allow switching to non-firm service with
little or no prior notice. In July 1993, the DPSC approved a three-year notice
requirement for firm customers switching to non-firm service. This notice
period will mitigate the effect on the Company's results of operations of
customers switching from firm to non-firm service.
In a related matter, during the proceedings in the Company's most recent gas
base rate case, the Company's largest firm gas customer filed a complaint in
the Delaware Chancery Court seeking rescission of its current firm service
agreement with the Company and other relief, including non-firm service as an
IGT customer. This case was settled in October 1993, with the customer agreeing
for a three-year period to transport or pay for a minimum amount of gas equal
to 75% of the average amount of gas it has taken over the past three years.
This settlement will not have a material impact on the Company's results of
operations.
ELECTRIC OPERATIONS
Installed Capacity
The net installed summer electric generating capacity available to the
Company to serve its peak load as of December 31, 1993 is presented below. The
Company plans to maintain a balanced approach to energy supply, including
conservation and load management, purchases of capacity and energy from other
utilities and nonutility generators, and construction of new generating
capacity. For a discussion of the energy supply plan, see "Challenge 2000 Plan"
which begins on page I-4.
% OF
INSTALLED SUMMER CAPACITY MEGAWATTS TOTAL
------------------------- --------- -----
Coal Fired................................................. 1,141 40
Oil-Fired.................................................. 595 21
Combustion Turbines/Combined Cycle......................... 511 18
Nuclear.................................................... 321 11
Peaking Units.............................................. 183 6
Purchased Capacity......................................... 48 2
Customer-owned Capacity.................................... 57 2
----- ---
Total.................................................... 2,856 100
===== ===
The net generating capacity available for operations at any time may be less
than the total net installed generating capacity due to generating units being
temporarily out of service for inspection, maintenance, repairs, or unforeseen
circumstances. See "Item 2--Properties" on page I-22 for a detailed listing of
net installed generating capacity by station.
I-3
Power Pool
The Company is a member of the Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM Interconnection). Under the PJM
Interconnection Agreement, the Company's generation and transmission facilities
are operated on an integrated basis with those of seven other utilities in
Pennsylvania, New Jersey, Maryland, and the District of Columbia. This power
pool was formed for the purpose of improving the reliability and operating
economies of the systems in the group and to provide capital economies by
permitting the sharing of reserve requirements on a group basis. The Company
estimates that its fuel savings associated with energy transactions within the
pool amounted to $9.0 million during 1993.
The PJM Interconnection's installed capacity as of December 31, 1993 was
55,575 MW. The PJM Interconnection experienced a new all time peak demand of
46,429 MW on July 8, 1993, which resulted in a summer reserve margin of 19.4%
(based on installed capacity of 55,440 MW on that date). The previous all-time
peak demand of 45,870 MW was set on July 23, 1991.
The Company is also a party to the Mid-Atlantic Area Coordination Agreement
which provides 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 1993 was 2,544 MW on July 9th, which surpassed the
Company's previous peak demand of 2,430 MW on July 23, 1991. Because adequate
generation was available at the time, this peak does not reflect full
implementation of the Company's demand-side programs, including the curtailment
of large interruptible customers. The Company's PJM Interconnection reserve
obligation 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 2,329 MW. Based upon this estimated peak and the Company's installed
generating capacity of 2,856 MW at the time, the Company's reserve margin would
have been 22.6%. The Company's PJM Interconnection reserve obligation varies
from year to year but is typically around 18%.
The Company's installed capacity obligation is established under the PJM
Interconnection Agreement. Capacity deficiency charges may be incurred under
the agreement if a member's installed capacity is less than its obligation. As
a result of unpredicted changes in both load and capacity availability
experienced during the previous PJM Interconnection planning period (June 1,
1992 through May 31, 1993), the Company expects to incur a capacity deficiency
charge for the 1992-93 period. The Company has accrued a liability of $570,000
for the estimated amount of the charge. The Company limited this charge by
purchasing PJM Interconnection capacity credits from one utility and trading
capacity credits with another utility. The trade provided the Company with a
credit towards 1992-93 PJM Interconnection capacity requirements and, in
return, the Company will provide an equivalent credit to the other utility in a
future period. The Company does not expect to incur a capacity deficiency
charge during the 1993-94 PJM Interconnection planning period; however, the
Company has entered into an agreement with another utility to acquire up to 85
MW of capacity credit for the period, should the need arise.
Challenge 2000 Plan
The Challenge 2000 Plan reflects the Company's strategy for meeting
customers' energy needs while minimizing adverse impacts on the environment and
keeping prices competitive. The key elements of the Challenge 2000 Plan are
flexibility and balance. The plan can be accelerated, slowed, or modified to
respond to changing energy demands, changing markets including the effects of
competition, fluctuating fuel prices, emerging technologies, and changing laws
and governmental regulations. The plan combines customer-oriented program
alternatives, called demand-side options, and generation alternatives using
emerging and existing technologies, called supply-side options. The strategy
can be characterized as "Save Some, Buy Some, Build Some."
I-4
As of the end of 1993, the demand-side programs ("Save Some") of the
Challenge 2000 Plan had enrolled about 66,000 residential customers and about
500 commercial and industrial customers who in aggregate provide the Company
with the ability to reduce its peak by approximately 225 MW. During 1992, for
residential customers, the Company developed four new conservation programs,
which include the sale of energy efficient products at below market prices
(e.g., compact fluorescent bulbs and water heating accessories) and rebates for
the installation of high efficiency central air conditioning and heat pumps.
For commercial and industrial customers, the Company also developed four new
conservation programs, which include rebates for energy efficient new
commercial construction and motors. Following Maryland Public Service
Commission (MPSC) approval in November 1992, the Company began implementing the
programs in Maryland effective January 1, 1993. Following DPSC approval in
September 1993, the Company began implementing the programs in Delaware
effective January 1, 1994. In November 1993, the Company filed for approval of
these new conservation programs with the Virginia State Corporation Commission
(VSCC). The Company expects a decision by the VSCC in April 1994.
The supply-side portion of the Challenge 2000 Plan combines the use of power
purchased from utility and nonutility generating companies ("Buy Some") and the
construction of new generating capacity by the Company ("Build Some").
In 1992, as part of the "Buy Some" portion of the Challenge 2000 Plan, the
Company began the purchase of 48 MW of peaking capacity for 26 years from the
Delaware City Power Plant owned by Star Enterprise (Star). In December 1992,
the Company filed with the DPSC and MPSC for the approval of two agreements for
the purchase of 198 MW of baseload capacity for 30 years from two non-utility
generators--165 MW from the Delaware Clean Energy Project (DCEP) beginning at
the Company's option in 1996 or 1997 and 33 MW from National Energy Resources
Corporation (NERC) beginning in 1997. The MPSC approved the agreements in March
1993. In April 1993, the DPSC issued an order which neither approved nor
disapproved the agreements. In June 1993, the Company terminated the NERC
contract because the project's sponsor failed to post a security deposit
required under the contract. In response to changes in the Company's load
forecast, in November 1993, the Company and DCEP amended their agreement to
delay the purchase of the capacity, while preserving an option (until November
1, 1994) to cancel the agreement. Purchases from other non-utility generators
to start near the year 2000 are being considered.
In May 1993, as part of the "Build Some" portion of the Challenge 2000 Plan,
the Company placed into service a 175 MW combined cycle addition to the Hay
Road combustion turbines (CTs). Also in January 1994, the MPSC granted
conditionally to the Company a Certificate of Public Convenience and Necessity
(CPCN). The CPCN preserves the Company's option to construct and operate a 300
MW pulverized coal baseload unit in Dorchester County, Maryland, which would be
placed in commercial operation by the year 2000 or later. The power plant, as
currently planned, has an estimated construction cost of $566 million,
excluding $129 million of allowance for funds used during construction (AFUDC).
The Company also has a power plant life extension program and repowering plans
to extend the operating lives of certain generating units. For a further
discussion of the Company's "Build Some" plans, see "Life Extensions and
Repowerings" on page I-7.
The table on the following page summarizes the latest peak load and capacity
forecast of the Challenge 2000 Plan over the current and next five PJM
Interconnection planning years, which began on June 1, 1993. The Company
periodically reviews and updates its forecast to reflect changes in peak load
and capacity estimates. The Company expects to meet PJM Interconnection
capacity reserve obligations in these future planning years.
I-5
PEAK LOAD (MW) CAPACITY (MW)
PJM --------------------- ----------------------
PLANNING GROSS NET
YEAR SUMMER TOTAL SUMMER TOTAL TOTAL TOTAL RESERVE
BEGINNING COMPANY "SAVE COMPANY "BUY "BUILD INSTALLED MARGIN
JUNE 1 PEAK SOME" PEAK SOME" SOME" CAPACITY (%)
--------- ------- ----- ------- ----- ------ --------- -------
1993 2,555 226 2,329 48 2,808 2,856 22.6%
1994 2,618 237 2,381 48 2,758* 2,806* 17.8%
1995 2,530 243 2,287 48 2,814 2,862 25.1%
1996 2,593 251 2,342 48 2,818 2,866 22.4%
1997 2,654 260 2,394 48 2,818 2,866 19.7%
1998 2,719 269 2,450 48 2,818 2,866 17.0%
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* The 50 MW reduction is due to capacity provided to another utility in
accordance with a capacity trade agreement.
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 (AE), and Public Service
Electric and Gas Company (PSE&G). The Peach Bottom units are operated by PECO
and have a combined summer capacity of 2,086 MW, of which the Company is
entitled to 157 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 continuous demonstrations 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, see
Note 6 of the Notes to Consolidated Financial Statements contained in the
Company's 1993 Annual Report to Stockholders filed as Exhibit 13.
Peach Bottom Units
On March 19, 1993, the NRC issued its Systematic Assessment of Licensee
Performance (SALP) Report on the performance of activities at Peach Bottom for
the period August 4, 1991 through October 31, 1992. A SALP Report evaluates
seven functional areas which are assigned ratings of "1", "2", or "3", with "1"
being the highest rating and "3" the lowest rating, although still acceptable.
Peach Bottom earned a rating of "1" in the areas of Emergency Preparedness and
Security and Safeguards, a rating of "2, Improving" in the areas of Plant
Operations and Radiological Controls, and a rating of "2" in the other three
functional areas. These numerical results were the same as the last SALP Report
except the areas of Plant Operations and Radiological Controls, which showed an
improving trend. The SALP Report stated that both units continued to operate in
a safe manner and that performance improvements and the correction of
previously identified deficiencies were indicated in most areas. The SALP
Report also noted several weaknesses warranting continued management attention,
including the areas of plant performance monitoring and engineering and
technical support.
In July 1992, the NRC issued an information notice alerting utilities owning
boiling water reactors (BWRs), including the owners of Peach Bottom, to
potential inaccuracies in water-level instrumentation during and after rapid
depressurization events. In May 1993, the NRC issued a bulletin requiring BWR
owners to, among other things, install instrumentation modifications during the
first cold shutdown of the
I-6
plant occurring after July 30, 1993. These modifications were implemented on
Unit 2 in August 1993 and on Unit 3 in November 1993.
Salem Units
On September 1, 1993, the NRC issued its SALP Report on the performance of
activities at Salem for the period December 29, 1991 through June 19, 1993. The
NRC assigned ratings of "1" to Security and Radiological Controls, "1,
Declining" to Emergency Preparedness, and "2" to the four other functional
areas. These numerical results were the same as the last SALP Report except for
the areas of Radiological Controls, which improved from "2, Improving" to "1",
and Emergency Preparedness, which showed a declining trend. The NRC noted that
Salem's performance during the period was good; however, a substantial number
of operational challenges occurred which warranted additional management
attention.
In order to improve Salem's materiel condition, plant and personnel
performance, and to address the NRC's concerns in its October 1990 SALP Report,
the Salem owners, including the Company, are in the process of augmenting plans
to improve Salem's materiel condition, upgrade procedures, and enhance
personnel performance. The Company's share of these planned plant additions and
improvements for 1994-1998 are reflected in the Company's estimates of
construction expenditures for such periods. The planned improvements are
expected to coincide with plant operating schedules.
See page I-18 for a discussion on the cooling systems at Salem.
Hay Road
On June 1, 1993, Hay Road Unit 4, with a capacity of 175 MW, was placed in
service at a total cost of $137.6 million, excluding $12.4 million of AFUDC.
Hay Road Unit 4 is a combined cycle unit which uses exhaust heat from the three
existing Hay Road CTs as its energy source. With the addition of Hay Road Unit
4, the entire Hay Road facility provides 511 MW of capacity, or approximately
18% of the Company's installed capacity.
Life Extensions and Repowerings
The Company is conducting a life extension program on its older major
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 are being implemented during scheduled
maintenance outages. Edge Moor Unit 5 and Vienna Unit 8 will undergo
conditional assessment surveys beginning in 1996. Construction expenditures on
these projects for the five-year period 1994-1998 are expected to total
approximately $29 million, excluding AFUDC.
The Company also plans to repower Indian River Units 1 and 2 utilizing
circulating fluidized bed technology. The units will be repowered in a phased-
construction approach and are expected to be completed in 2003. The repowering
will extend the operating life of each unit by 30 years and also will reduce
emissions. Construction expenditures on these projects for the five-year period
1994-1998 are expected to be approximately $36 million, excluding AFUDC.
PURCHASED POWER
The Company purchases coal-fired energy from the Allegheny Power System (APS)
on an economic basis to replace higher-cost generation from the Company's oil-
fired units. The Company also purchases 200 MW of energy from PECO under a
short-term agreement, extending through December 31, 1994. The
I-7
Company receives additional energy from PECO (above 200 MW) as the energy is
available. The Company's estimated fuel savings from these purchases amounted
to $4.1 million during 1993.
The Company also has purchased 48 MW of long-term capacity as discussed under
"Challenge 2000 Plan" which begins on page I-4.
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. The Company uses coal as its predominant fuel source.
Corresponding values for purchased power and for net interchange (purchases
less sales) as a member of the PJM Interconnection are also listed.
GENERATION 1993 1992 1991
---------- ---------------- -------------- --------------
1,000 $/ 1,000 $/ 1,000 $/
UNIT FUEL TYPE MWH MWH % MWH MWH % MWH MWH %
-------------- ------ --- --- ------ --- --- ------ --- ---
Coal-fired................... 6,028 18 47 4,696 19 39 5,499 20 45
Oil-fired.................... 2,343 24 18 1,713 26 14 1,761 30 15
Nuclear...................... 1,883 7 14 1,696 7 14 1,827 8 15
Natural Gas.................. 1,010 23 8 443 32 4 866 26 7
------ --- --- ------ --- --- ------ --- ---
Total Company Generation... 11,264 18 87 8,548 18 71 9,953 20 82
PURCHASES/INTERCHANGE
---------------------
Purchases.................... 3,200 22 25 2,826 22 23 1,595 23 13
Net Interchange.............. (1,568) (30) (12) 755 7 6 562 4 5
------ --- --- ------ --- --- ------ --- ---
Total Output for Load...... 12,896 18 100 12,129 19 100 12,110 19 100
====== === === ====== === === ====== === ===
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.
Coal
Edge Moor Units 3 and 4, and the Indian River, Keystone and Conemaugh
generating stations are coal-fired. As of December 31, 1993, a maximum of 97%
of the Company's coal requirements were under supply contracts. During 1993,
21% of the coal was purchased under short-term contracts (less than three
years), 70% under long-term contracts (up to ten years), and the balance was
obtained through spot purchases. 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 is currently
being supplied under a two-year contract which expires in 1994. The Company
expects to negotiate a new contract in 1994 with similar terms. Any amount over
75% of requirements may be purchased in the spot market. Natural gas is
utilized when economically feasible. The fuel supply contract for the Vienna
Generating Station, which expires in 1995, provides from 70% to 100% of that
station's requirements. Any amount over 70% of requirements may be purchased in
the spot market.
Gas
Natural gas, which is the primary fuel for the three 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-10.
I-8
Additional natural gas is purchased on an interruptible basis from one of the
Company's pipeline suppliers. The secondary fuel for the Hay Road CTs is
kerosene which is purchased in the spot market.
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, enrichment of that gas, conversion of the
enriched gas to fuel pellets, fabrication of fuel assemblies, 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
which will satisfy the fuel requirements of Peach Bottom through 1996. PSE&G
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. The table below summarizes the years through which PECO and
PSE&G have contracted for the other segments of the nuclear fuel supply cycle.
CONVERSION ENRICHMENT FABRICATION
---------- ---------- -----------
Peach Bottom Unit 2........................ 1997 2008(1) 1999
Peach Bottom Unit 3........................ 1997 2008(1) 1998
Salem Unit 1............................... 2000 1998(2) 2004
Salem Unit 2............................... 2000 1998(2) 2005
- --------
(1) PECO has exercised its option to remain uncommitted under the United States
Enrichment Corporation (USEC) enrichment contract from 2000-2002; however,
this action does not exclude USEC enrichment services from consideration
during this period. PECO does not anticipate any difficulties in obtaining
necessary enrichment services for Peach Bottom.
(2) 100% coverage through 1998 and 30% through 2001. PSE&G has exercised its
option to remain uncommitted under the USEC enrichment contract from 1999-
2002; however, this action does not exclude USEC enrichment services from
consideration during this period. PSE&G does not anticipate any
difficulties in obtaining necessary enrichment services for Salem.
In conformity with the Nuclear Waste Policy Act (NWPA), PECO and PSE&G
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 a tenth of one cent per kilowatthour (kWh) of nuclear generation
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 Federal Government was to begin accepting spent
fuel for permanent offsite storage no later than 1998. However, in December
1989, the DOE announced that it would not be able to open a permanent, high-
level nuclear waste storage facility until 2010, at the earliest. The DOE has
stated that it would seek legislation from Congress for the temporary storage
of spent nuclear fuel for utilities beginning in 1998 or soon thereafter. The
Company cannot predict when the temporary or permanent storage sites will
become available.
PECO has advised the Company that Peach Bottom has adequate on-site temporary
storage capability until 1998 for Unit 2 and 1999 for Unit 3. Options for
expansion of storage capacity are being investigated by PECO. PSE&G has advised
the Company that Salem has adequate on-site temporary storage capability
through March 1998 for Unit 1 and March 2002 for Unit 2. PSE&G expects to
extend storage capacity at Salem Units 1 and 2 through March 2008 and March
2012, respectively, through a reracking project it began in 1992.
I-9
The Energy Act provides, among other things, for the creation of a
Decontamination & Decommissioning (D&D) Fund to pay for the future cleanup of
DOE gaseous diffusion enrichment facilities. This plan is to be funded by both
domestic utilities and the Federal Government. Domestic utilities will pay an
aggregate amount of $150 million each year, adjusted annually for inflation,
into the D&D Fund based on their past purchases from the DOE Uranium Enrichment
Enterprise. This will continue for 15 years or until $2.25 billion, adjusted
annually for inflation, is collected. The Company accrued a liability and
corresponding regulatory asset of $8.1 million, representing its share of the
$2.25 billion. The Energy Act provides that this cost is to be recoverable in
the same manner as other fuel costs. The Company recovers fuel costs through
fuel adjustment clause revenues as discussed on page I-13. In 1993, the Company
made its first fund payment and began amortizing the D&D Fund cost to fuel
expense. The DPSC issued an order approving recovery of these costs through the
fuel adjustment clause. The MPSC, VSCC, and FERC have not yet addressed these
costs. The liability accrued for the Company's share of the D&D Fund cost was
$7.6 million as of December 31, 1993.
GAS OPERATIONS
During 1993, the average production cost of all gas sold was $3.22 per
thousand cubic feet (Mcf), compared with $2.70 per Mcf in 1992 and $2.69 per
Mcf in 1991. The Company's maximum 24-hour system capability, including natural
gas purchases, storage deliveries, and the planned send out of its local peak
shaving plant, is 145,591 Mcf. The maximum 1993 daily firm sendout, which
occurred on February 19, 1993, was 118,186 Mcf. The Company experienced a new
all-time peak daily firm sendout of 158,512 Mcf on January 19, 1994. Emergency
peak shaving equipment was used to meet the peak demand. The Company's previous
all-time peak daily firm sendout of 119,284 Mcf had occurred on January 21,
1985.
The gas requirements of the Company are purchased primarily under contracts
with three pipeline suppliers. The Company is entitled to receive the following
volumes of gas per day under its various contracts.
NUMBER OF EXPIRATION DAILY
CONTRACTS DATES MCF
--------- ---------- -------
Supply.......................................... 4 1996-2004 21,615
Transportation.................................. 2 2004 56,544
Storage......................................... 4 1995-2004 42,432
Local Peak Shaving.............................. -- -- 25,000
-------
Total......................................... 145,591
=======
The Company also purchases gas from pipelines and producers primarily under
one- to five-year agreements. To provide supplemental gas, the Company has its
own liquefied natural gas plant for liquefaction, storage, and re-gasification
of natural gas. The plant has a maximum planned daily sendout of 25,000 Mcf.
In 1992, the FERC issued Order No. 636 which requires the "unbundling" of
interstate pipeline services, thereby giving gas distribution companies (such
as the Company) greater options for gas supply, transportation, and storage.
The Company has restructured its gas portfolio in response to FERC Order No.
636 but no major changes were required. FERC Order No. 636 also permits
pipeline companies to include in their rates the transition costs of unbundling
their services. The Company estimates that such transition costs will be
approximately $2 million, in aggregate, and expects such costs to be collected
from its gas customers.
NON-REGULATED UTILITY BUSINESS (STEAM UTILITY)
Through 1991, the Company owned and operated an electric generating plant
which supplied electricity and steam to an adjacent refinery owned by Star at
Delaware City, Delaware. As previously reported, the Company sold this plant to
Star in 1991. The Company entered into a contract with Star to operate the
power
I-10
plant for a fee from January 1992 through June 1995. Commencing in January
1993, the power plant is being operated through one of the Company's
nonregulated subsidiaries. If the contract with Star is not renewed, there
would not be a material impact on the Company's results of operations. See page
I-24 for a discussion of litigation instituted by Star against the Company
related to the operations of the plant prior to its sale to Star.
The Company also sells process steam to the DuPont Company's Edge Moor,
Delaware manufacturing plant via a pipeline from the Company's Edge Moor Power
Plant.
SUBSIDIARIES
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. As of
December 31, 1993, the combined stockholder's equity of Delmarva Energy Company
and Delmarva Industries, Inc. was $3.4 million.
Delmarva Services Company, a wholly-owned subsidiary, leases an office
building to the Company. As of December 31, 1993, the stockholder's equity of
Delmarva Services Company was $5.1 million.
Delmarva Capital Investments, Inc. (Delcap) is a wholly-owned subsidiary of
the Company that has invested in leveraged equipment leases, alternative energy
projects, real estate projects, landfill and waste-hauling companies and has
also undertaken operation and maintenance contracts for alternative energy and
related projects. Opportunities to grow Delcap's operating businesses and
participate in other energy-related businesses, in conjunction with Company
goals, are being pursued. Certain Company contributions have and may be
required in pursuit of these opportunities. During 1993, Delcap made dividend
payments of $3 million to the Company. As of December 31, 1993, the
stockholder's equity of Delcap was $37.0 million. Of this amount, landfill and
waste-hauling represented the largest component at about $21.3 million. The
balance consisted primarily of investments in leveraged leases, limited
partnerships, and real estate.
For a further discussion of the Company's subsidiaries see the Nonutility
Subsidiaries section of Management's Discussion and Analysis of Financial
Condition and Results of Operations and Note 16 of the Notes to Consolidated
Financial Statements of the 1993 Annual Report to Stockholders filed as Exhibit
13.
REGULATORY AND RATE MATTERS
The Company is subject to regulation with respect to its retail sales of
electricity by the DPSC, MPSC, and the VSCC, each of which have broad powers
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. FERC exercises jurisdiction with
respect to the Company's accounting systems and policies, and the wholesale
(resale) transmission and sale of electric energy. FERC also regulates the
price and other terms of transportation of natural gas purchased by the
Company. The percentage of utility operating revenues (electric and gas)
regulated by each Commission for the year ended December 31, 1993 was as
follows: DPSC 64%; MPSC 22%; VSCC 3%; and FERC 11%.
BASE RATE PROCEEDINGS
The Company's most recent filings for electric base rate increases were made
on October 30, 1992 in its Delaware retail, Maryland retail, and resale (FERC)
jurisdictions and on May 7, 1993 in its Virginia retail jurisdiction. These
increases, as filed, reflected a requested 12.5% return on common equity
(12.23% for Virginia retail) and recovery of higher costs, including: the cost
of the new Hay Road Unit 4 combined-cycle power plant; the expense increase
associated with the cost of postretirement benefits under Statement of
Financial Accounting Standards (SFAS) No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions;" and other items including general
inflation. The increases which have resulted from these filings are being
mitigated by fuel savings attributed to Hay Road Unit 4 combined cycle
operation.
I-11
These base rate proceedings, as well as other material base rate proceedings
in process since January 1, 1993, are discussed on the following pages.
The Company does not anticipate filing for an increase in electric base rates
which would become effective in 1994 in any of its jurisdictions. The Company
plans to file for an increase in gas base rates during the second quarter of
1994.
Delaware Electric Rates
DOCKET NO. 92-85
On October 30, 1992, partly based on forecasted data, the Company filed an
application for an annual $41.6 million increase in base rates. This increase
was expected to be offset by estimated fuel savings of approximately $5.2
million related to Hay Road Unit 4 combined cycle operation, resulting in a net
increase of $36.4 million or 8.5%. During the rate case, the Company lowered
its rate increase request to $36.6 million (before fuel savings) based on
updated information and a 12% return on equity.
On October 5, 1993, the DPSC approved a settlement for a $24.9 million
increase which reflects an 11.5% return on equity. When offset by the fuel
savings associated with Hay Road Unit 4, which were included in the lower fuel
rates that became effective in June 1993, customer rates increased
approximately 3.7%.
Delaware Gas Rates
DOCKET NO. 91-24
On July 2, 1991, the Company filed an application for an annual $4.8 million
or 6.5% increase in base rates. The requested increase became effective
February 2, 1992, subject to refund. On June 8, 1993, the DPSC approved an
increase of $4.1 million or 5.6%, reflecting a 12.5% return on equity.
An issue contested in this case involved the conditions under which firm
customers would be able to switch to non-firm service such as Interruptible Gas
Transportation (IGT) service. For a discussion of the outcome of this issue,
see "Competition--Gas Business" on page I-3.
Maryland Electric Rates
CASE NO. 8492
On October 30, 1992, partly based on forecasted data, the Company filed an
application for an annual $14.6 million increase in base rates. When updated
for actual data, the revenue request was $12.0 million. On April 1, 1993, the
MPSC approved a settlement agreement for a $7.8 million increase effective
April 1, 1993, two months earlier than expected. Although a specific return on
equity was not specified in the settlement agreement, the Company believes that
the implied return on equity approaches 12%. When offset by the fuel savings
associated with Hay Road Unit 4, which were included in the lower fuel rates
that became effective in April 1993, customer rates increased 2.3%.
Virginia Electric Rates
CASE NO. PUE920040
On May 27, 1992, the Company filed an application for an expedited $1.5
million annual increase in base rates. This request became effective on July 1,
1992, subject to refund. On April 7, 1993, the VSCC approved an increase of
$1.15 million or 5.1%, reflecting an 11.5% return on equity.
I-12
CASE NO. PUE930036
On May 7, 1993, the Company filed an application for an annual $2.3 million
increase in base rates. The requested increase became effective October 5,
1993, subject to refund. On February 23, 1994, the VSCC approved a settlement
for an increase of $1.3 million or 7.2%, reflecting an 11.05% return on equity.
Resale Electric Rates
DOCKET NO. ER92-236-000
On December 20, 1991, the Company filed an application with FERC for an
annual $5 million or 5.3% increase in base rates. On February 18, 1992, FERC
issued an order permitting the Company to put a base rate increase of $4.8
million into effect on February 19, 1992, subject to refund. On June 29, 1993,
the FERC approved a settlement agreement for an increase of $4.125 million or
4.4% effective February 19, 1992. A specific return on equity was not stated in
the settlement agreement approved by FERC.
DOCKET NO. ER93-96-000
On October 30, 1992, the Company filed an application with FERC for an annual
$5.6 million increase in base rates. This increase was expected to be offset by
fuel savings of approximately $1.6 million related to Hay Road Unit 4 combined
cycle operation, resulting in a net increase of approximately $4.0 million or
3.8%. On June 3, 1993, at the Company's request, an interim increase of $4.0
million became effective, subject to refund. The Company has reached settlement
agreements with all of its resale customers allowing for an increase of $1.5
million or 1.5%. The difference between the amount reached in the settlement
agreements and the Company's original request is primarily due to a lower
return on equity. The settlement agreements also provide for a moratorium on
rate design and longer termination notice periods. The resale customers agreed
to provide a two-year notice for up to a 30% load reduction and a five-year
notice for greater than a 30% load reduction. The FERC is expected to rule on
these agreements during the second quarter of 1994.
FUEL ADJUSTMENT CLAUSES
The Company's tariffs 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 are generally subject to base rate recovery. The present status or
results of significant fuel rate issues are discussed below. As of December 31,
1993, the Company had accrued fuel disallowance reserves which adequately
provide for any disallowances of fuel costs and penalties related to the issues
discussed below.
Delaware
The DPSC has a Power Plant Performance Program (PPPP) under which the Company
can receive financial rewards or penalties based on the performance of its 15
major generating units. The maximum level or "cap" for penalties and rewards is
limited to two percent (2%) of the total equity investment in the 15 units or
approximately $3.2 million. The PPPP compares actual performance (defined as
the three-year average equivalent availability factor (EAF) for fossil units or
capacity factor (CF) for nuclear units) with a predetermined EAF/CF target for
each generating unit.
I-13
Results under the PPPP for calendar year 1992 were a penalty of $514,000,
primarily due to an extended outage at Indian River Unit 4 from September 28,
1992 through January 13, 1993. Results under the PPPP for 1993 are expected to
result in a reward of approximately $80,000.
In November 1992, the Company made its annual retail fuel adjustment filing
for 1993. This case was settled in October 1993 and resulted in the
disallowance of $515,000 of net replacement power costs associated with the
Salem Unit 2 turbine overspeed outage which lasted from November 9, 1991
through May 10, 1992. The settlement also provides for the avoidance of
penalties under the PPPP for Salem Unit 2 estimated at $265,000 for the years
1992-1994. Thus, the net incremental replacement power costs which the Company
will absorb through this settlement, based on its estimates, are $250,000.
The DPSC has a three-year gas incentive program which was scheduled to end in
July 1993. In a filing made in September 1993, the Company recommended that the
gas incentive program be continued. It is expected that the DPSC will make a
ruling in the second quarter of 1994. Under the program, the Company can
receive a maximum $300,000 annual reward (penalty) if unaccounted-for gas
volumes are below (above) 2.5% of total gas sendout volumes with a deadband of
plus or minus 0.5%. The most recent period subject to this program was the
twelve months ended July 1993. Since unaccounted-for gas volumes were within
the deadband, there was neither a reward nor a penalty.
Maryland
The MPSC has a Generating Unit Performance Program (GUPP) for the Company's
15 major generating units. The GUPP does not have automatic rewards or
penalties. It is used to assess the overall performance of these units. When
the aggregate performance of these units equals or exceeds a predetermined
system standard, as established by the MPSC, there is a rebuttable presumption
of satisfactory performance. When the overall system standard is not met, the
individual performance of each unit is compared to its specific performance
standard. The MPSC could then institute an investigation into the performance
levels of those units that operated below their respective standards and
disallow certain fuel costs.
The Company's 1992 GUPP results indicated that the system performance
standard was not met, primarily due to Indian River Unit 4 and Salem Unit 2 not
meeting their individual performance standards. These results were addressed in
the Company's June 1993 retail fuel adjustment filing. On March 8, 1994, the
MPSC issued an order approving a settlement agreement resulting in a $164,000
disallowance of replacement power costs.
In February 1994, the Company filed its calculation of the 1993 GUPP results
indicating that the system performance result met the aggregate performance
standard.
As previously reported, in April 1992 the Company made a retail fuel
adjustment filing. The single contested issue was the methodology used by the
Company to price natural gas burned for electric generation. Other parties had
recommended disallowances ranging from $0.8--$1.2 million for the period May
1989 through December 1992. A settlement was reached in 1993 resulting in a
$60,000 disallowance of fuel costs.
Resale
The Company has incurred certain mine closing costs that it has been
recovering from resale customers through its wholesale fuel adjustment clause
(FAC). FERC staff has issued a preliminary audit report which recommends that
the Company recompute the cost of fuel used in FAC billings to wholesale
customers by eliminating the mine closing costs beginning in 1989 and make
refunds with interest for any overbilled amounts. In the event of an
unfavorable ruling, the amount subject to refund would be approximately
$600,000.
On May 19, 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. The Company believes the complaint is without
merit and has filed an answer which includes a motion seeking dismissal of the
complaint.
I-14
OTHER REGULATORY MATTERS
Conowingo Power Company
In September 1993, the MPSC initiated a proceeding to investigate COPCO's
practice of purchasing all of its wholesale electric requirements from its
parent PECO, which is the sole owner of COPCO. In October
1993, PECO and its affiliate Susquehanna Electric Company (SE) filed a rate
schedule with the FERC which seeks to recover the costs of "stranded
investment" in the event COPCO purchases electricity from sources other than
PECO and SE. Also in November 1993, PECO and SE filed tariffs with the FERC
which seek to establish charges for electricity supplied by sources other than
PECO and SE and transmitted across PECO and SE's transmission lines. As a
potential supplier of electricity to COPCO, the Company has intervened in the
Maryland and the FERC proceedings described above. On March 10, 1994, in the
FERC proceeding related to the establishment of a "stranded investment" charge,
PECO made a settlement offer which provides that, among other matters, it would
conduct a solicitation for COPCO's long-term power supply needs effective
January 2006, enter into a power supply agreement with COPCO effective January
1996 with a rate discounted from PECO's current rate, and withdraw its
"stranded investment" filing with the FERC. Following a review of the offer, on
March 22, 1994, the Company responded to PECO's proposal with an offer in which
the Company, among other matters, offered to purchase COPCO and enter into a
long-term supply contract with PECO for at least 100 MW based on current market
prices. The Company is unable to predict the outcome of the proceedings at the
MPSC or at the FERC.
Maryland Management Audit
In March 1993, the MPSC began a focused management audit of seven areas of
the Company's management and operations: affiliated transactions, the Company's
relationship with the Maryland jurisdiction, management and organization,
strategic planning, compensation and benefits, conservation efforts, and
customer service. Focused management audits are conducted periodically by state
public service commissions as part of the overall regulatory process. The
Company last underwent such an audit in 1978 by the DPSC.
The MPSC focused management audit was completed in August 1993. The overall
assessment of the Company, in the areas reviewed, was that "Delmarva has
successfully created a corporate culture that has resulted in the achievement
of its long-term goals. The findings and the conduct experienced throughout the
study reflect a well-managed company." The audit also supported the Company's
efforts to fully develop and implement a market-oriented strategy in order to
effectively face the unprecedented changes occurring in the utility industry.
Findings in all seven audit areas generally were favorable. Thirty-one
recommendations were made to the Company and thirty were accepted by the
Company for follow-up.
Delaware Task Force on Regulation
For a discussion of the Public Utility Regulatory Task Force which is
reviewing the regulatory process in Delaware, see "Competition--Electric
Business" which begins on page I-1.
CONSTRUCTION AND FINANCING PROGRAM
Construction expenditures for the period 1991-1993, excluding $26 million of
AFUDC, and estimated construction expenditures for the period 1994-1998,
excluding $29 million of AFUDC, are shown in the following table:
CALENDAR YEAR (DOLLARS IN THOUSANDS)
-----------------------------------------------------
1996-
1991 1992 1993 1994 1995 1998
-------- -------- -------- -------- -------- --------
Electric Facilities:
Production.......... $ 97,300 $125,800 $ 69,100 $ 59,400 $ 71,300 $222,600
Transmission........ 14,900 12,200 17,300 23,300 14,600 54,000
Distribution........ 41,200 43,000 40,300 40,300 49,400 155,500
Gas Facilities........ 17,900 14,300 17,000 16,900 18,200 59,500
General Facilities.... 10,500 12,100 16,300 15,400 25,400 69,100
-------- -------- -------- -------- -------- --------
$181,800 $207,400 $160,000 $155,300 $178,900 $560,700
======== ======== ======== ======== ======== ========
I-15
Capital requirements for the period 1994-1995 are estimated to be $395
million, including $25 million for the maturity of First Mortgage Bonds in 1994
and $334 million for utility construction (excluding AFUDC). The Company
anticipates that during the period 1994-1995 approximately $250 million will be
generated internally, which represents 63% of total capital requirements and
75% of construction requirements. Capital requirements for the period 1996-1998
are estimated to be $677 million, including $57 million for the maturity of
long-term debt and $561 million for utility construction (excluding AFUDC). The
Company anticipates that during the period 1996-1998 $431 million will be
generated internally, which represents 64% of total capital requirements and
77% of construction requirements. The balance for both periods is expected to
be provided by the sale of long-term debt and equity securities. The types,
amounts, and times of such sales will depend upon future market conditions and
the Company's target capital structure.
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, 1993, these provisions would have permitted the
Company to issue approximately $107 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, 1993
was 7.19. The issuance of First Mortgage Bonds by the Company also is limited
in the Mortgage by 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 an issuance of preferred stock be 1.50 or greater. This ratio
was 2.62 for the twelve months ended December 31, 1993.
The Company does not expect that any of these limitations will restrict its
ability to issue unsecured debt, First Mortgage Bonds, and preferred stock in
the amounts necessary to meet its anticipated capital requirements.
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 1989-1993 are shown below.
YEAR ENDED DECEMBER 31,
----------------------------
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
Ratio of Earnings to Fixed Charges (SEC Meth-
od)........................................... 3.47X 3.03X 2.58X 2.03X 3.01X
Ratio of Earnings to Fixed Charges and Pre-
ferred Dividends (SEC Method)................. 2.88X 2.51X 2.24X 1.69X 2.52X
Under the SEC Methods, earnings, including AFUDC, have been computed by
adding the amount of income taxes and fixed charges to net income. 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. Fixed charges include gross interest
expense and the estimated interest component of rentals. Excluding the write-
off of an investment in certain non-regulated subsidiary projects, the ratios
of earnings to fixed charges and earnings to fixed charges and preferred
dividends for the year ended December 31, 1990 would be 2.89X and 2.41X,
respectively. 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. Excluding the gain from the Company's share of
a settlement reached in the lawsuit against PECO in connection with the
shutdown of Peach Bottom, the ratios of earnings to fixed charges and earnings
to fixed charges and preferred dividends for the year ended December 31, 1992
would be 2.78X and 2.30X, respectively.
I-16
For further information on the Company's financing program, see Notes 7
through 9 of the Notes to Consolidated Financial Statements and the Liquidity
and Capital Resources section of Management's Discussion and Analysis of
Financial Condition and Results of Operations of the 1993 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, solid
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, construction 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 environmental compliance, primarily with the
Clean Air Act Amendments of 1990 (The Clean Air Act), for the years 1994-1995
are estimated at $44 million (excluding AFUDC) and for the years 1996-1998 are
estimated at $65 million (excluding AFUDC). These amounts have been included
in the Company's estimates of construction expenditures under "Construction
and Financing Program" which begins on page I-15.
Clean Air Act
Title IV, Acid Rain Provisions, will require sulfur dioxide (SO/2/) and
oxides of nitrogen (NOx) emission reductions from some wholly and jointly-
owned generating units in two phases. Phase I and Phase II implementation will
be in 1995 and 2000, respectively. Regarding SO/2/ reductions, the two coal
fired units at the jointly-owned Conemaugh Power Plant are the Company's only
Phase I units. Flue gas desulfurization (FGD) units are under construction at
the facility and are expected to be completed in December 1994 and November
1995. The current project forecast is $377 million, of which the Company's
share is $14 million. The remainder of the Company's wholly and jointly-owned
fossil fired units are expected to meet Phase II emission limits through some
combination of fuel switching, FGD, repowering, environmental dispatch and/or
SO/2/ allowance trading.
In addition to SO/2/ reductions, NOx emissions from coal units are limited
by Title IV. Draft regulations for Phase I coal-fired units have been issued
by the Environmental Protection Agency (EPA) and can be satisfied through
operational changes and the use of low-NOx burner technology. Compliance for
the two coal fired units at the Conemaugh Power Plant, which are the Company's
only Phase I NOx units, is included in the SO/2/ compliance project discussed
above. Phase II NOx control regulations will not be promulgated by the EPA
until 1997. It is likely that the NOx reductions required under this title of
the Clean Air Act will be achieved through compliance with Title I
requirements as discussed below.
Control of NOx emissions from major stationary sources will also be required
by the Title I ozone nonattainment provisions of the Clean Air Act. In order
to attain the national ambient air quality standard for ozone, the States of
Delaware, Maryland, and Virginia are required by the EPA to promulgate
Reasonably Available Control Technology (RACT) regulations for existing
sources that are located within ozone nonattainment regions or are within the
Northeast Ozone Transport Region. These regulations would require additional
equipment on certain generating facilities. The Company's generating
facilities in Virginia are not anticipated to be affected by RACT rules, as
they are located in ozone attainment areas and are outside the Northeast Ozone
Transport Region.
The Delaware Department of Natural Resources and Environmental Control
(DNREC) promulgated NOx RACT regulations in January 1993. The Company, along
with several other affected parties, appealed the regulations. Pursuant to a
settlement between the appellants and DNREC, DNREC issued amended regulations
in November 1993, which are satisfactory to the Company. These regulations are
subject to
I-17
approval by the EPA. In order to comply with the DNREC NOx RACT regulations, in
November 1993 the Company filed a proposal with DNREC to make operating changes
in, and to install additional equipment on, certain generating facilities,
including installation of low NOx burner technology on Edge Moor Units 4 and 5
and Indian River Units 3 and 4. The generating capacities of these plants are
not expected to be affected by these changes.
In Maryland, RACT regulations were promulgated in the fall of 1992. The
Company has submitted a RACT proposal for its Maryland facilities which relies
on improving existing combustion system operations to minimize NOx emissions.
The anticipated capital cost for compliance with the Company's Delaware and
Maryland RACT proposals is approximately $35 million. Because of uncertainties
as to the final RACT regulations and as to the revisions which may be required
to the Company's RACT proposals, it is possible that additional costs will be
incurred at these and other facilities to further control NOx emissions.
However, the Company cannot predict the additional costs, if any, that may be
incurred.
The Company is in the process of installing continuous emissions monitoring
equipment on its affected Title IV units and units subject to certain Title I
NOx RACT rules by December 31, 1994. It is estimated that the construction
expenditures for such monitors will be approximately $7 million.
The Clean Air Act also imposes operating permit fees on affected sources. The
Company's permit fees are anticipated to be approximately $750,000 per year,
when the program is fully implemented in the mid-1990's.
To help attain ambient air quality standards, the Clean Air Act mandates that
the emission of certain air pollutants associated with the construction of new
sources or modifications to 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.
The Company anticipates that the costs of complying with the Clean Air Act
will be recoverable from its customers.
Salem Nuclear Generating Station
In June 1993, the New Jersey Department of Environmental Protection and
Energy (NJDEPE) issued a draft permit that would require PSE&G to undertake
various measures to protect aquatic life in the Delaware Estuary and to provide
broad-ranging ecological benefits. Such measures include the restoration and/or
enhancement of 10,000 acres of marshlands, modifications to Salem's intake
screens, and a comprehensive biological monitoring program. The draft permit
would not require PSE&G to construct closed-cycle cooling towers, as was
originally proposed under a 1990 NJDEPE draft permit and which PSE&G believes
are unnecessary. The estimated cost of compliance with the draft permit is
approximately $90 million of which the Company's share would be $6.7 million.
The estimated cost for closed-cycle cooling towers, based on natural draft and
forced draft technologies, range from $720 million to $2 billion, including the
cost of replacement power while the units are shut down during construction, of
which the Company's share would be from $53 to $148 million.
The NJDEPE received a substantial number of comments on the draft permit
including a large number of suggestions that the draft permit be changed to
require closed-cycle cooling towers. The comments to the NJDEPE also made a
variety of claims as to alleged legal defects in the draft permit. NJDEPE has
stated that it intends to issue a final permit in the second quarter of 1994.
The EPA has authority to veto the issuance of a final permit by the NJDEPE, and
action by the EPA cannot be predicted. If a final permit is issued which
maintains the terms of the draft permit, additional permits from various
agencies will be required for implementation, as to which no assurance can be
given. The Company cannot predict the outcome of this matter.
Water Quality Regulations
DNREC and the Maryland Department of the Environment (MDE) have proposed
major changes to water quality regulations which emphasize increased control of
toxic pollutants and signal a shift away from
I-18
existing technology-based standards. In addition, DNREC has proposed increased
restrictions on thermal discharge limits. In Delaware, regulations have been
issued and are in effect. In Maryland, the MDE has issued proposed regulations
for comment. As part of this process, one discharge from the Indian River Power
Plant was included on a Delaware list of suspected toxic pollutant discharges
and one discharge from the Vienna Power Plant was added to the Maryland toxic
discharge list by the EPA. National Pollutant Discharge Elimination System
(NPDES) permit modifications for each plant are expected in 1994. The cost of
complying with the final modified Delaware and Maryland regulations is not
expected to be material.
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. Between 1976 and 1979, the Company submitted to DNREC the
results of environmental impact studies which demonstrated compliance with the
Act. DNREC is in the process of updating the Company's studies to determine if
the systems are in compliance. These studies are expected to take one to two
years. If it should be determined that the intake and/or discharge systems are
not in compliance with the Act, construction expenditures to modify the systems
could be from $3 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 remediate 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 contractor screening and
audit process.
The Company currently is a potentially responsible party (PRP) at one federal
Superfund site in Philadelphia, Pennsylvania (the Metal Bank/Cottman Avenue
site) where it had sent scrap transformers for reclamation. The site is alleged
to be contaminated with PCBs and other hazardous wastes. The Company and other
utilities formed a PRP group and signed an Administrative Order on Consent with
the EPA to finance and conduct a Remedial Investigation/Feasibility Study
(RI/FS) to determine the need for any additional cleanup. The study is expected
to be completed in the fall of 1994. The Company's allocated share of the PRP
group is 0.24 percent. The total cost of the RI/FS is estimated to be
approximately $5.2 million, making the Company's share approximately $12,000.
The cleanup remedy and total costs are not yet known; however, based on the
Company's allocated share of the potential liability, total cleanup costs to be
incurred by the Company are not expected to be material.
The Company also 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. In the past, the Company allegedly had contracted with certain
waste haulers to dispose of waste oil. These waste haulers contend that certain
volumes of waste oil that they sent to these sites originated from the Company.
Because evidence linking the Company to the sites is weak and the volume of
waste oil purportedly sent to the sites is small, the Company does not expect
its share of total cleanup costs, if any, for both sites to exceed $75,000.
The Company's former coal gasification sites in Wilmington and New Castle
have been placed on Delaware's list of state superfund sites by DNREC. Also,
the Company's former coal gasification site in Cambridge has been placed on
Maryland's list of state superfund sites by MDE. Until investigations are
completed, it cannot be determined whether remediation at the New Castle and
Cambridge sites will be necessary and, if so, what the resultant costs will be.
The Company completed its own investigation and risk assessment of the
Wilmington coal gasification site in 1987. Based on the results of that study,
which were submitted to DNREC, the Company determined that the site posed a
minimal risk to the environment and the surrounding community. DNREC has now
advised the Company that additional field sampling will be required so that an
updated risk assessment of the site and other adjacent areas can be completed.
The Company is cooperating with DNREC in developing and conducting the
assessment, which is expected to be completed in the fall of 1994 at a total
cost of approximately $250,000. If sufficient site contamination and/or risk to
the environment is identified, the
I-19
Company may be required to incur costs for site remediation. If remediation
should consist of paving the site, the cost would be approximately $500,000.
Additional costs could be incurred if paving the site is not sufficient to
mitigate contamination. However, until the risk assessment is completed, the
Company cannot predict what actions and related costs, if any, may be required
to remediate the site.
The Company anticipates that risk assessment and any remediation costs will
be recoverable from its customers.
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 that could affect the electric utility industry
is the emission of "greenhouse gases," in particular the release of carbon
dioxide from generating facilities into the atmosphere which 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 greenhouse gas emissions
while satisfying its customers' growing demand for energy. Specific actions
include supporting scientific research, continuing its balanced environmental
stewardship/energy resource plans (the Challenge 2000 Plan), and enhancing
energy conservation in the Company's operations. President Clinton's Climate
Change Action Plan introduced in October 1993 relies primarily on voluntary
initiatives. Should mandatory emissions limitations or a "carbon tax" be
imposed, the Company's operations could be affected. However, 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. The Company believes
that its subsidiaries are in substantial compliance with all environmental
regulations.
RETAIL FRANCHISES
The Company holds franchises, which are for the most part unlimited in time,
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 generally has perpetual franchises 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 has 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, 1993 was
2,810.
A total of 1,613 employees are represented by the International Brotherhood
of Electrical Workers Locals 1238 (Northern) and 1307 (Southern). Local 1238
and 1307 contracts with the Company expire on December 15, 1994 and June 25,
1995, respectively.
I-20
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, and positions of all of the executive officers of the
Company as of December 31, 1993 are listed below along with their business
experience during the past five years. Officers are elected annually by the
Board of Directors at the meeting of directors immediately following the Annual
Meeting of Stockholders. There are no family relationships among these
officers, nor any arrangement or understanding between any officer and any
other person pursuant to which the officer was selected.
EXECUTIVE OFFICERS OF THE REGISTRANT
(AS OF DECEMBER 31, 1993)
BUSINESS EXPERIENCE
NAME, AGE AND POSITION DURING PAST 5 YEARS
---------------------- -------------------
Howard E. Cosgrove, 50................. Elected 1992. President and Chief Operating Officer
Chairman of the Board, President, and from 1991 to 1992; Executive Vice President from 1985
Chief Executive Officer and Director to 1991.
H. Ray Landon, 58...................... Elected 1988.
Executive Vice President and Director
Ralph E. Klesius, 51................... Elected 1992. Vice President, Engineering from 1988
Senior Vice President and to 1992.
Environmental Compliance Officer
Thomas S. Shaw, 46..................... Elected 1992. Vice President/President, Delmarva
Senior Vice President/President, Capital Investments, Inc. from 1991 to 1992;
Delmarva Capital Investments, Inc. Vice President, Gas Division from 1990 to 1991;
Vice President, Production from 1984 to 1990.
Barbara S. Graham, 45.................. Elected 1992. Treasurer from 1987 to 1992.
Vice President and Chief Financial
Officer
Donald E. Cain, 48..................... Elected 1988.
Vice President, Administration
Paul S. Gerritsen, 48.................. Elected 1992. Vice President and Chief Financial Officer
Vice President, Strategic Energy from 1987 to 1992.
Markets, Pricing and Regulation
Kenneth K. Jones, 57................... Elected 1987.
Vice President, Planning
Wayne A. Lyons, 54..................... Elected 1990. Vice President from 1985 to 1990.
Vice President, Division Operations
Frank J. Perry, 50..................... Elected 1990. Vice President, Gas Division from
Vice President, Production 1986 to 1990.
Jack Urban, 50......................... Elected 1991. General Manager, Production Services
Vice President, Gas Division from 1990 to 1991; General Manager, Fuel Supply from
1984 to 1990.
James P. Lavin, 46..................... Elected 1993. Comptroller-Corporate and Chief
Comptroller and Chief Accounting Accounting Officer from 1989 to 1993; Assistant
Officer Comptroller from 1983 to 1989.
I-21
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 generating capacity available to the Company to serve its peak load
as of December 31, 1993.
NET INSTALLED
SUMMER
GENERATING
CAPACITY
STATION LOCATION (KILOWATTS)
------- -------- -------------
COAL-FIRED
Edge Moor...................... Wilmington, DE.................. 251,000
Indian River................... Millsboro, DE................... 764,000
Conemaugh...................... New Florence, PA................ 63,000(A)
Keystone....................... Shelocta, PA.................... 63,000(A)
---------
1,141,000
---------
OIL-FIRED
Edge Moor...................... Wilmington, DE.................. 444,000
Vienna......................... Vienna, MD...................... 151,000
---------
595,000
---------
COMBUSTION TURBINES/COMBINED CY-
CLE
Hay Road....................... Wilmington, DE.................. 511,000
---------
NUCLEAR
Peach Bottom................... Peach Bottom Twp., PA........... 157,000(A)
Salem.......................... Lower Alloways Creek Twp., NJ... 164,000(A)
---------
321,000
---------
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)
---------
Total.......................... 2,855,800
=========
- --------
(A) Company portion of jointly owned plants.
(B) Represents capacity owned by a refinery customer which is available to the
Company to serve its peak load.
I-22
Major transmission and distribution lines owned and in service are as
follows:
VOLTAGE CIRCUIT MILES
------- -------------
Transmission:
500 kV..................................................... 16
230 kV..................................................... 247
138 kV..................................................... 426
69 kV..................................................... 714
Distribution:
34 kV..................................................... 109
25 kV and below........................................... 8,999
The Company's electric transmission and distribution system includes 1,338
transmission poleline miles of overhead lines, 5 transmission cable miles of
underground cables, 6,634 distribution poleline miles of overhead lines, and
4,294 cable miles of distribution 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 planned 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:
Transmission Mains...................................... 111*
Distribution Mains...................................... 1,284
Service Lines........................................... 1,012
--------
* 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
In October 1992, the Company's largest firm gas customer filed a complaint in
the Delaware Chancery Court seeking rescission of its current firm service
agreement with the Company and other relief, including non-firm service as an
interruptible Gas Transportation customer. For a discussion of the outcome of
this case, see "Competition--Gas Business" on page I-3.
In November 1992, DCTC-Glendon, Inc., a subsidiary of the Company, filed a
lawsuit in the U.S. District Court for the Eastern District of Pennsylvania
against Energenics/Glendon, Inc. (EGI) and Joseph M. Reibman (Reibman), the
sole shareholder of EGI. In July 1993, the court entered an order granting
EGI's and Reibman's motion to file omitted counterclaims and add counterclaim
defendants, including the Company, various subsidiaries of the Company, and
certain individual officers and employees of the Company and its subsidiaries.
In February 1994, DCTC-Glendon, Inc., Delcap, Reibman and the counterclaim
defendants settled the litigation and all claims made by the parties were
dismissed with prejudice.
In June 1993, the Delaware Coastal Zone Industrial Control Board (the
"Board") adopted regulations (the "Regulations") under Delaware's Coastal Zone
Act which would, among other things, prohibit the Company from constructing new
power-generating facilities or expanding any of its existing power-generating
facilities outside a designated boundary. In July 1993, the Company filed a
complaint in the Delaware Superior Court seeking to have the Regulations
declared null and void. In addition, the Company joined with
I-23
other affected parties in filing a complaint in July 1993 in the Delaware
Chancery Court. The Chancery Court complaint alleges procedural violations of
the Freedom of Information Act by the Board in the passage of the Regulations
and requests that the Regulations be declared null and void. The Company cannot
predict the outcome of either of these lawsuits.
On December 14, 1993, Star filed a complaint against the Company in Delaware
Chancery Court alleging that the Company overcharged it for pension and tax-
related costs under a contract entered into by the parties' predecessors in
1955. The complaint asks for a refund and damages totalling $9.3 million. While
the Company believes that it did not overcharge Star and is defending its
position, it cannot predict the outcome of the lawsuit.
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
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 1993 and 1992.
1993 1992
---------------------- -----------------------
PRICE PRICE
DIVIDEND ------------- DIVIDEND --------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ------ ------ -------- ------- ------
First Quarter.................... $.38 1/2 $24 22 1/8 $.38 1/2 $21 1/2 $20
Second Quarter................... .38 1/2 24 1/8 21 1/2 .38 1/2 22 7/8 20 1/2
Third Quarter.................... .38 1/2 25 7/8 23 1/8 .38 1/2 23 3/4 22 1/2
Fourth Quarter................... .38 1/2 25 5/8 21 1/4 .38 1/2 23 7/8 22 1/8
The Company had 58,225 registered holders of common stock as of December 31,
1993.
The Charter and the Mortgage securing the Company's outstanding bonds contain
restrictions on the payment of dividends on common stock which would become
applicable if its capital and retained earnings fall below certain specific
levels or if preferred stock dividends are in arrears.
The retained earnings available for dividends on common stock as of December
31, 1993 were approximately $223,814,000 under the most restrictive of these
provisions.
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 Management's Discussion and Analysis of Financial
Condition and Results of Operations included in the 1993 Annual Report to
Stockholders, incorporated by reference herein.
ITEM 6. SELECTED FINANCIAL DATA
This information is contained on page 18 of the 1993 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 19 through 26 of the 1993 Annual
Report to Stockholders filed herein as Exhibit 13, which portion of such Annual
Report is hereby incorporated by reference herein. Refer to the "Competition"
section of Part I herein for an update to the disclosure included in the
"Competition" section of Management's Discussion and Analysis of Financial
Condition and Results of Operations concerning strategies to mitigate the
expected loss of revenues in 1995 due to the decision of a resale customer
(ODEC) to purchase up to 150 MW from another utility.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements, notes 1 through 18 to consolidated
financial statements, and related report thereon of Coopers & Lybrand,
independent accountants, appear on pages 27 through 46 of the 1993 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
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
Delmarva Power & Light Company
Wilmington, Delaware
Our report, which includes an explanatory paragraph regarding the Company's
changes in its methods of accounting for unbilled revenues, income taxes, and
postretirement benefits other than pensions, on the consolidated financial
statements of Delmarva Power & Light Company has been incorporated by reference
in this Form 10-K from page 27 of the 1993 Annual Report to Stockholders of
Delmarva Power & Light Company. In connection with our audits of such financial
statements, we have also audited the related financial statement schedules
listed in the index in Item 14 of this Form 10-K.
In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects, the information required to be
included therein.
Coopers & Lybrand
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 4, 1994
II-2
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 21, 1994, 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 21,
1994.
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 21, 1994.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
III-1
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 1993 Annual Report to Stockholders filed as Exhibit 13
hereto and incorporated herein by reference.
1993
ANNUAL REPORT
FINANCIAL STATEMENT (PAGE)
------------------- -------------
Consolidated Statements of Income for the three years ended
December 31, 1993............................................ 28
Consolidated Statements of Cash Flows for the three years
ended December 31, 1993...................................... 29
Consolidated Balance Sheets as of December 31, 1993 and 1992.. 30 and 31
Consolidated Statements of Capitalization as of December 31,
1993 and 1992................................................ 32
Consolidated Statements of Changes in Common Stockholders' Eq-
uity for the three years ended December 31, 1993............. 33
Notes to Consolidated Financial Statements.................... 34 to 46
2. Financial Statement Schedules--The following financial statement
schedules are contained in Part IV of this report.
1993
FORM 10K
SCHEDULE (PAGE)
-------- -------------
V Utility Plant Property for the three years ended December
31, 1993................................................... IV-3 to IV-8
VI Consolidated Accumulated Depreciation and Amortization
(Utility Plant) for the
three years ended December 31, 1993........................ IV-9 to IV-11
IX Short-Term Borrowings for the three years ended December
31, 1993................................................... IV-12
X Supplemental Income Statement Information for the three
years ended December 31, 1993.............................. IV-13
All other schedules have been omitted since the required information is
not present or 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, 1993 can be found on page IV-14 of this report.
4. Exhibits
EXHIBIT
NUMBER
-------
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.
3-D Copy of the Company's By-Laws as amended September 30, 1993.
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
Registation Statement No. 33-39756.)
4-C Copies of the Seventieth through Seventy-Fourth Supplemental
Indentures. (Filed with Registration Statement No. 33-24955.)
IV-1
EXHIBIT
NUMBER
-------
4-D Copies of the Seventy-Fifth through the Seventy-Seventh Supplemental
Indentures. (Filed with Registration Statement No. 33-39756.)
4-E Copies of the Seventy-Eighth and Seventy-Ninth Supplemental
Indentures. (Filed with Registration Statement No. 33-46892.)
4-F Copy of the Eightieth Supplemental Indenture. (Filed with
Registration Statement No. 33-49750.)
4-G Copy of the Eighty-First Supplemental Indenture. (Filed with
Registration Statement No. 33-57652.)
4-H Copy of the Eighty-Second Supplemental Indenture. (Filed with Form
10-K for the year ended December 31, 1992.)
4-I Copy of the Eighty-Third Supplemental Indenture. (Filed with
Registration Statement No. 33-50453.)
4-J Copy of the Eighty-Fourth Supplemental Indenture.
4-K Copy of the Eighty-Fifth Supplemental Indenture.
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.)
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.)
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.)
10-D 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.)
10-E 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.)
10-F Copy of the severance agreement with members of management.
10-G Copy of the current listing of members of management who have signed
the severance agreement.
10-H Copy of the Management Life Insurance Plan amended and restated as
of January 1, 1992. (Filed with Form 10-K for the year ended
December 31, 1991.)
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 1993 Annual Report to Stockholders which are
incorporated by reference in this Form 10-K.
23 Consent of Independent Accountants.
b) Reports on Form 8-K (filed during the reporting period):
A Report on Form 8-K dated October 28, 1993, containing a press release
of the Company concerning third quarter earnings, was filed with the
Commission.
IV-2
DELMARVA POWER & LIGHT COMPANY
SCHEDULE V--UTILITY PLANT PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1993
(THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ------------------------------------------------------------------------------------------------
OTHER CHANGES--DEBIT
AND/OR (CREDIT)
----------------------------
ADJUST-
TRANSFERS MENTS OF
BALANCE AT ADDITIONS RETIRE- BETWEEN PRIOR YEARS' BALANCE AT
BEGINNING OF AT COST MENTS OR ACCOUNTS ADDITIONS OR CLOSE OF
CLASSIFICATION PERIOD (A) SALES (B) RETIREMENTS(E) PERIOD
- ------------------------------------------------------------------------------------------------
Utility Plant:
Electric:
Plant in Service:
Intangible........... $ 7,564 $ 6 $ -- $ -- $ (3) $ 7,567
Production........... 1,295,963 180,297 9,827 2,754 (893) 1,468,294
Transmission......... 329,029 15,964 1,698 1,517 251 345,063
Distribution......... 653,109 37,626 6,000 214 336 685,285
General.............. 58,962 4,093 7,426 (1,877) 423 54,175
Construction work in
progress............. 174,395 134,130 -- (239,568)(c) 2,684 71,641
Plant held for future
use.................. 732 3,403 -- (3,317) (86) 732
Electric plant
acquisition
adjustment........... 510 -- -- -- (119)(d) 391
Salem nuclear fuel.... 8,289 -- -- -- -- 8,289
Nuclear fuel lease.... 85,893 7,384 -- -- -- 93,277
---------- -------- ------- --------- ------ ----------
2,614,446 382,903 24,951 (240,277) 2,593 2,734,714
---------- -------- ------- --------- ------ ----------
Gas:
Plant in Service:
Intangible........... 1,135 -- -- -- -- 1,135
Production........... -- -- -- -- -- --
Storage.............. 8,447 148 -- -- (1) 8,594
Transmission......... 17,032 865 73 25 2 17,851
Distribution......... 132,803 12,486 740 (25) 26 144,550
General.............. 3,722 338 153 130 -- 4,037
Construction work in
progress............. 3,159 16,053 -- (13,687)(c) 875 6,400
---------- -------- ------- --------- ------ ----------
$ 166,298 $ 29,890 $ 966 $ (13,557) $ 902 $ 182,567
---------- -------- ------- --------- ------ ----------
IV-3
DELMARVA POWER & LIGHT COMPANY
SCHEDULE V -- UTILITY PLANT PROPERTY -- (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31, 1993
(THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ------------------------------------------------------------------------------------------------
OTHER CHANGES--DEBIT
AND/OR (CREDIT)
----------------------------
ADJUST-
TRANSFERS MENTS OF
BALANCE AT ADDITIONS RETIRE- BETWEEN PRIOR YEARS' BALANCE AT
BEGINNING OF AT COST MENTS OR ACCOUNTS ADDITIONS OR CLOSE OF
CLASSIFICATION PERIOD (A) SALES (B) RETIREMENTS(E) PERIOD
- ------------------------------------------------------------------------------------------------
Common:
Plant in Service:
Organization.......... $ 736 $ -- $ -- $ -- $ -- $ 736
Intangible............ 20,667 198 -- (11) -- 20,854
Land and land rights.. 2,334 254 -- (37) -- 2,551
Structures and
improvements......... 45,319 466 270 (6) -- 45,509
Office furniture and
equipment............ 42,077 6,581 14,600 1,202 (25) 35,235
Transportation and
power operated
equipment............ 2,090 50 69 -- -- 2,071
Stores equipment...... 178 -- 12 -- -- 166
Tools, shop and garage
equipment............ 855 288 32 -- -- 1,111
Communications
equipment............ 13,441 952 1,151 646 (106) 13,782
Miscellaneous equip-
ment................. 155 19 7 -- -- 167
Construction work in
progress.............. 10,290 13,268 -- (10,726)(c) 128 12,960
---------- -------- ------- --------- ------ ----------
138,142 22,076 16,141 (8,932) (3) 135,142
---------- -------- ------- --------- ------ ----------
Total............... $2,918,886 $434,869 $42,058 $(262,766) $3,492 $3,052,423
========== ======== ======= ========= ====== ==========
- --------
(a) Construction and nuclear fuel expenditures, including AFUDC.
(b) Includes transfers from construction work in progress and transfers of
land and facilities to/from non-utility property, plant held for future
use or other functions.
(c) Transfers to plant in service.
(d) Amortization of acquisition adjustment which is charged against utility
operating income.
(e) Includes transfers between functions and adjustments to prior closings.
IV-4
DELMARVA POWER & LIGHT COMPANY
SCHEDULE V -- UTILITY PLANT PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1992
(THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -------------------------------------------------------------------------------------------------
OTHER CHANGES--DEBIT
AND/OR (CREDIT)
----------------------------
ADJUST-
TRANSFERS MENTS OF
BALANCE AT ADDITIONS RETIRE- BETWEEN PRIOR YEARS' BALANCE AT
BEGINNING OF AT COST MENTS OR ACCOUNTS ADDITIONS OR CLOSE OF
CLASSIFICATION PERIOD (A) SALES (B) RETIREMENTS(E) PERIOD
- -------------------------------------------------------------------------------------------------
Utility Plant:
Electric:
Plant in Service:
Intangible........... $ 7,711 $ 2 $ 149 $ -- $ -- $ 7,564
Production........... 1,259,582 39,234 3,221 14 354 1,295,963
Transmission......... 326,078 6,141 853 (2,129) (208) 329,029
Distribution......... 614,207 41,224 6,624 3,811 491 653,109
General.............. 55,362 5,489 152 (1,687) (50) 58,962
Construction work in
progress............. 78,129 193,060 -- (92,797)(c) (3,997) 174,395
Plant held for future
use.................. 631 336 -- (235) -- 732
Electric plant
acquisition
adjustment........... 629 -- -- -- (119)(d) 510
Salem nuclear fuel.... 8,289 -- -- -- -- 8,289
Nuclear fuel lease.... 78,765 7,128 -- -- -- 85,893
---------- -------- ------- -------- ------- ----------
2,429,383 292,614 10,999 (93,023) (3,529) 2,614,446
---------- -------- ------- -------- ------- ----------
Gas:
Plant in Service:
Intangible........... 1,186 -- 51 -- -- 1,135
Production........... -- -- -- -- -- --
Storage.............. 7,584 863 -- -- -- 8,447
Transmission......... 15,298 1,832 90 (8) -- 17,032
Distribution......... 118,582 15,273 1,060 8 -- 132,803
General.............. 3,614 61 -- 47 -- 3,722
Construction work in
progress............. 6,768 14,079 -- (18,043)(c) 355 3,159
---------- -------- ------- -------- ------- ----------
153,032 32,108 1,201 (17,996) 355 166,298
---------- -------- ------- -------- ------- ----------
Steam:
Plant in Service:
Production........... -- -- -- -- -- --
Transmission......... 108 -- -- (108) -- --
Distribution......... -- -- -- -- -- --
General.............. -- -- -- -- -- --
Construction work in
progress............. 74 -- -- -- (74)(f) --
---------- -------- ------- -------- ------- ----------
$ 182 $ -- $ -- $ (108) $ (74) $ --
---------- -------- ------- -------- ------- ----------
IV-5
DELMARVA POWER & LIGHT COMPANY
SCHEDULE V -- UTILITY PLANT PROPERTY -- (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31, 1992
(THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ------------------------------------------------------------------------------------------------
OTHER CHANGES--DEBIT
AND/OR (CREDIT)
----------------------------
ADJUST-
TRANSFERS MENTS OF
BALANCE AT ADDITIONS RETIRE- BETWEEN PRIOR YEARS' BALANCE AT
BEGINNING OF AT COST MENTS OR ACCOUNTS ADDITIONS OR CLOSE OF
CLASSIFICATION PERIOD (A) SALES (B) RETIREMENTS(E) PERIOD
- ------------------------------------------------------------------------------------------------
Common:
Plant in Service:
Organization.......... $ 736 $ -- $ -- $ -- $ -- $ 736
Intangible............ 22,881 168 2,467 -- 85 20,667
Land and land rights.. 2,354 -- -- -- (20) 2,334
Structures and
improvements......... 45,156 163 -- -- -- 45,319
Office furniture and
equipment............ 41,258 858 -- (4) (35) 42,077
Transportation and
power operated
equipment............ 2,723 -- 633 -- -- 2,090
Stores equipment...... 178 -- -- -- -- 178
Tools, shop and garage
equipment............ 907 7 -- (59) -- 855
Communications
equipment............ 13,301 140 -- -- -- 13,441
Miscellaneous
equipment............ 119 10 -- 26 -- 155
Construction work in
progress.............. 1,728 10,415 -- (1,360)(c) (493) 10,290
---------- -------- ------- --------- ------- ----------
131,341 11,761 3,100 (1,397) (463) 138,142
---------- -------- ------- --------- ------- ----------
Total............... $2,713,938 $336,483 $15,300 $(112,524) $(3,711) $2,918,886
========== ======== ======= ========= ======= ==========
- --------
(a) Construction and nuclear fuel expenditures, including AFUDC.
(b) Includes transfers from construction work in progress and transfers of
land and facilities to/from non-utility property, plant held for future
use or other functions.
(c) Transfers to plant in service.
(d) Amortization of acquisition adjustment which is charged against utility
operating income.
(e) Includes transfers between functions and adjustments to prior closings.
(f) Reclassified to other property for financial reporting purposes.
IV-6
DELMARVA POWER & LIGHT COMPANY
SCHEDULE V -- UTILITY PLANT PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1991
(THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ----------------------------------------------------------------------------------------------------
OTHER CHANGES--DEBIT
AND OR (CREDIT)
----------------------------
ADJUST-
TRANSFERS MENTS OF
BALANCE AT ADDITIONS RETIRE- BETWEEN PRIOR YEARS' BALANCE AT
BEGINNING OF AT COST MENTS OR ACCOUNTS ADDITIONS OR CLOSE OF
CLASSIFICATION PERIOD (A) SALES (B) RETIREMENTS(E) PERIOD
- ----------------------------------------------------------------------------------------------------
Utility Plant:
Electric:
Plant in Service:
Intangible........... $ 7,661 $ 50 $ -- $ -- $ -- $ 7,711
Production........... 1,158,377 115,049 13,752 (58) (34) 1,259,582
Transmission......... 309,927 16,513 196 (318) 152 326,078
Distribution......... 582,099 36,912 6,271 (70) 1,537 614,207
General.............. 52,745 3,143 206 (214) (106) 55,362
Construction work in
progress............. 90,198 146,092 -- (170,710)(c) 12,549 78,129
Plant held for future
use.................. 559 74 -- -- (2) 631
Electric plant
acquisition
adjustment........... 829 -- -- -- (200)(d) 629
Salem nuclear fuel.... 8,289 -- -- -- -- 8,289
Nuclear fuel lease.... 71,412 7,353 -- -- -- 78,765
---------- -------- ------- --------- ------- ----------
2,282,096 325,186 20,425 (171,370) 13,896 2,429,383
---------- -------- ------- --------- ------- ----------
Gas:
Plant in Service:
Intangible........... 1,186 -- -- -- -- 1,186
Production........... 1,957 51 1,599 (409) -- --
Storage.............. 7,475 103 30 36 -- 7,584
Transmission......... 13,569 1,814 49 (20) (16) 15,298
Distribution......... 106,945 11,958 715 278 116 118,582
General.............. 3,179 105 -- 330 -- 3,614
Construction work in
progress............. 3,098 17,601 -- (14,033)(c) 102 6,768
---------- -------- ------- --------- ------- ----------
137,409 31,632 2,393 (13,818) 202 153,032
---------- -------- ------- --------- ------- ----------
Steam:
Plant in Service:
Production........... 23,738 284 24,022 -- -- --
Transmission......... 458 -- 350 -- -- 108
Distribution......... 746 -- 746 -- -- --
General.............. 40 -- 40 -- -- --
Construction work in
progress............. 239 1,681 -- (284)(c) (1,562) 74
---------- -------- ------- --------- ------- ----------
$ 25,221 $ 1,965 $25,185(f) $ (284) $(1,562) $ 182
---------- -------- ------- --------- ------- ----------
IV-7
DELMARVA POWER & LIGHT COMPANY
SCHEDULE V -- UTILITY PLANT PROPERTY -- (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31, 1991
(THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ------------------------------------------------------------------------------------------------
OTHER CHANGES--DEBIT
AND/OR (CREDIT)
----------------------------
ADJUST-
TRANSFERS MENTS OF
BALANCE AT ADDITIONS RETIRE- BETWEEN PRIOR YEARS' BALANCE AT
BEGINNING OF AT COST MENTS OR ACCOUNTS ADDITIONS OR CLOSE OF
CLASSIFICATION PERIOD (A) SALES (B) RETIREMENTS(E) PERIOD
- ------------------------------------------------------------------------------------------------
Common:
Plant in Service:
Organization.......... $ 736 $ -- $ -- $ -- $ -- $ 736
Intangible............ 20,917 1,964 -- -- -- 22,881
Land and land rights.. 2,350 4 -- -- -- 2,354
Structures and
improvements......... 44,931 241 5 -- (11) 45,156
Office furniture and
equipment............ 38,147 3,275 -- 383 (547) 41,258
Transportation and
power operated
equipment............ 3,584 -- 818 (43) -- 2,723
Stores equipment...... 173 5 -- -- -- 178
Tools, shop and garage
equipment............ 747 121 4 43 -- 907
Communications
equipment............ 11,495 1,329 -- -- 477 13,301
Miscellaneous
equipment............ 120 -- -- -- (1) 119
Construction work in
progress.............. 2,375 7,012 -- (7,971)(c) 312 1,728
---------- -------- ------- --------- ------- ----------
125,575 13,951 827 (7,588) 230 131,341
---------- -------- ------- --------- ------- ----------
Total............... $2,570,301 $372,734 $48,803 $(193,060) $12,766 $2,713,938
========== ======== ======= ========= ======= ==========
- --------
(a) Construction and nuclear fuel expenditures, including AFUDC.
(b) Includes transfers from construction work in progress and transfers of
land and facilities to/from non-utility property, plant held for future
use or other functions.
(c) Transfers to plant in service.
(d) Amortization of acquisition adjustment which is charged against utility
operating income.
(e) Includes transfers between functions and adjustments to prior closings.
(f) Includes sale of Delaware City Plant.
IV-8
DELMARVA POWER & LIGHT COMPANY
SCHEDULE VI -- CONSOLIDATED ACCUMULATED DEPRECIATION AND AMORTIZATION
(UTILITY PLANT)
FOR THE YEAR ENDED DECEMBER 31, 1993
(THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ------------------------------------------------------------------------------------------
ADDITIONS
------------------------
CHARGED TO
OPERATING
BALANCE AT EXPENSES IN CHARGED TO BALANCE AT
BEGINNING STATEMENT OF OTHER RETIRE- OTHER CLOSE OF
DESCRIPTION OF PERIOD INCOME ACCOUNTS(A) MENTS(B) CHANGES PERIOD
- ------------------------------------------------------------------------------------------
Depreciation -- Utility
Plant:
Electric............... $806,025 $ 84,514 $894 $25,342 $677 $866,768
Gas.................... 47,616 5,551 -- 1,254 (2) 51,911
Common................. 41,140 9,281 (2) 15,987 150 34,582
-------- -------- ---- ------- ---- --------
894,781 99,346 892(a) 42,583 825 953,261
Amortization of Electric
Plant in Service....... 13,213 299 -- -- -- 13,512
Amortization of Gas
Plant in Service....... 1,135 -- -- -- -- 1,135
Amortization of Common
Plant in Service....... 20,740 772 -- 69 -- 21,443
-------- -------- ---- ------- ---- --------
$929,869 $100,417 $892 $42,652 $825 $989,351
======== ======== ==== ======= ==== ========
Amortization of Nuclear
Fuel Assemblies........ $ 8,289 $ -- $ -- $ -- $ -- $ 8,289
Amortization of Nuclear
Fuel Lease............. 49,111 10,261 -- -- -- 59,372
-------- -------- ---- ------- ---- --------
$ 57,400 $ 10,261 $ -- $ -- $ -- $ 67,661
======== ======== ==== ======= ==== ========
- --------
(a) Charged to clearing accounts for which subsequent distribution was made
to operating and other accounts.
(b) Includes removal cost net of salvage.
IV-9
DELMARVA POWER & LIGHT COMPANY
SCHEDULE VI -- CONSOLIDATED ACCUMULATED DEPRECIATION AND AMORTIZATION (UTILITY
PLANT)
FOR THE YEAR ENDED DECEMBER 31, 1992
(THOUSANDS OF DOLLARS)
- -------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -------------------------------------------------------------------------------------------
ADDITIONS
------------------------
CHARGED TO
OPERATING
BALANCE AT EXPENSES IN CHARGED TO BALANCE AT
BEGINNING STATEMENT OF OTHER RETIRE- OTHER CLOSE OF
DESCRIPTION OF PERIOD INCOME ACCOUNTS(A) MENTS(B) CHANGES PERIOD
- -------------------------------------------------------------------------------------------
Description -- Utility
Plant:
Electric............... $735,617 $78,267 $854 $12,911 $ 4,198 $806,025
Gas.................... 43,950 5,109 -- 1,445 2 47,616
Steam & Electric
(Refinery
Service).............. 107 -- -- -- (107) --
Common................. 32,786 8,371 -- 16 (1) 41,140
-------- ------- ---- ------- ------- --------
812,460 91,747 854 14,372 4,092 894,781
Amortization of Electric
Plant in Service....... 13,072 289 -- 148 -- 13,213
Amortization of Gas
Plant in Service....... 1,186 -- -- 51 -- 1,135
Amortization of Common
Plant in Service....... 23,134 700 -- 3,094 -- 20,740
-------- ------- ---- ------- ------- --------
$849,852 $92,736 $854 $17,665 $ 4,092 $929,869
======== ======= ==== ======= ======= ========
Amortization of Nuclear
Fuel Assemblies........ $ 8,289 $ -- $ -- $ -- $ -- $ 8,289
Amortization of Nuclear
Fuel Lease............. 38,880 10,231 -- -- -- 49,111
-------- ------- ---- ------- ------- --------
$ 47,169 $10,231 $ -- $ -- $ -- $ 57,400
======== ======= ==== ======= ======= ========
- --------
(a) Charged to clearing accounts for which subsequent distribution was made
to operating and other accounts.
(b) Includes removal cost net of salvage.
IV-10
DELMARVA POWER & LIGHT COMPANY
SCHEDULE VI -- CONSOLIDATED ACCUMULATED DEPRECIATION AND AMORTIZATION (UTILITY
PLANT)
FOR THE YEAR ENDED DECEMBER 31, 1991
(THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ----------------------------------------------------------------------------------------------
ADDITIONS
------------------------
CHARGED TO
OPERATING
BALANCE AT EXPENSES IN CHARGED TO BALANCE AT
BEGINNING STATEMENT OF OTHER RETIRE- OTHER CLOSE OF
DESCRIPTION OF PERIOD INCOME ACCOUNTS(A) MENTS(B) CHANGES PERIOD
- ----------------------------------------------------------------------------------------------
Depreciation -- Utility
Plant:
Electric............... $683,476 $73,693 $374 $21,496 $ (430) $735,617
Gas.................... 41,845 4,739 -- 2,833 199 43,950
Steam and Electric
(Refinery Service).... 24,913 7 -- 24,813(c) -- 107
Common................. 25,288 7,513 (4) 10 (1) 32,786
-------- ------- ---- ------- ------- --------
775,522 85,952 370 49,152 (232) 812,460
Amortization of Electric
Plant in Service....... 12,341 731 -- -- -- 13,072
Amortization of Gas
Plant in Service....... 1,186 -- -- -- -- 1,186
Amortization of Common
Plant in Service....... 23,370 561 -- 797 -- 23,134
-------- ------- ---- ------- ------- --------
$812,419 $87,244 $370 $49,949 $ (232) $849,852
======== ======= ==== ======= ======= ========
Amortization of Nuclear
Fuel Assemblies........ $ 8,289 $ -- $ -- $ -- $ -- $ 8,289
Amortization of Nuclear
Fuel Lease............. 28,638 10,242 -- -- -- 38,880
-------- ------- ---- ------- ------- --------
$ 36,927 $10,242 $ -- $ -- $ -- $ 47,169
======== ======= ==== ======= ======= ========
- --------
(a) Charged to clearing accounts for which subsequent distribution was made
to operating and other accounts.
(b) Includes removal cost net of salvage.
(c) Includes sale of Delaware City Plant.
IV-11
DELMARVA POWER & LIGHT COMPANY
SCHEDULE IX -- SHORT-TERM BORROWINGS
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
- ---------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ---------------------------------------------------------------------------------------------------------------------
CATEGORY OF BALANCE WEIGHTED MAXIMUM AMOUNT AVERAGE AMOUNT WEIGHTED AVERAGE
SHORT-TERM AT END AVERAGE OUTSTANDING OUTSTANDING INTEREST RATE
BORROWINGS OF YEAR INTEREST RATE DURING THE YEAR DURING THE YEAR DURING THE YEAR
- ---------------------------------------------------------------------------------------------------------------------
Year Ended
December 31,
1993... Commercial Paper 0 0 $24,400,000 $2,553,469 3.21%
LPA (c) 0 0 $23,000,000 $4,381,071 3.21%
Bank Loans (d) 0 0 0 0 0
1992... Commercial Paper 0 0 $16,000,000 $2,808,778 3.93%
LPA (c) $17,000,000 3.34% $21,500,000 $2,461,128 3.82%
Bank Loans (d) 0 0 $11,050,000 $1,681,000 8.14%
1991... Commercial Paper 0 0 $18,000,000 $2,149,000 6.26%
LPA (c) 0 0 $19,000,000 $2,844,000 6.76%
Bank Loans (d) $11,050,000 8.69% $11,050,000 $8,863,000 9.50%
- --------
(a) Average daily balance based on 365 days.
(b) Weighted average monthly rates for debt outstanding.
(c) Loan Participation Agreements--Short-term bank loans which are
remarketed to investors.
(d) Subsidiary debt.
IV-12
DELMARVA POWER & LIGHT COMPANY
SCHEDULE X -- SUPPLEMENTAL INCOME STATEMENT INFORMATION FOR THE THREE YEARS
ENDED DECEMBER 31, 1993 (THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
COLUMN A COLUMN B
- --------------------------------------------------------------------------------
1993 1992 1991
- --------------------------------------------------------------------------------
Maintenance............................................. $74,196 $75,215 $67,130
======= ======= =======
Taxes other than income taxes:
Delaware utility tax.................................. $12,587 $11,732 $11,473
Property taxes........................................ 10,771 10,165 9,069
Payroll taxes......................................... 6,619 6,591 6,424
Gross receipts taxes.................................. 5,753 5,382 5,086
Franchise and other taxes............................. 1,689 3,167 2,866
------- ------- -------
Total............................................... $37,419 $37,037 $34,918
======= ======= =======
- --------
Note: Other information has been omitted since the required information either
is not present in amounts sufficient to require submission or is included
in the respective financial statements or the notes thereto.
IV-13
DELMARVA POWER & LIGHT COMPANY
OPERATING STATISTICS
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
The table below sets forth selected financial and operating statistics for
the electric and gas divisions for the three years ended December 31, 1993.
1993 1992 1991
---------- ---------- ----------
ELECTRIC:
Electricity generated and purchased (MWh):
Generated................................ 11,264,540 8,548,233 9,952,596
Purchased................................ 3,857,133 4,579,521 3,270,816
Interchange deliveries................... (2,225,384) (998,679) (1,113,423)
---------- ---------- ----------
Total output for load................... 12,896,289 12,129,075 12,109,989
========== ========== ==========
Electric sales (MWh):
Residential.............................. 3,499,387 3,228,237 3,236,616
Commercial............................... 3,336,847 3,140,149 3,098,599
Industrial............................... 3,232,233 3,115,677 3,105,338
Other sales of electricity............... 2,211,763 2,036,748 2,019,727
---------- ---------- ----------
Total sales............................. 12,280,230 11,520,811 11,460,280
Losses and miscellaneous system uses...... 616,059 608,264 649,709
---------- ---------- ----------
Total disposition of energy.............. 12,896,289 12,129,075 12,109,989
========== ========== ==========
Operating revenue (thousands):
Residential.............................. $305,446 $273,463 $275,888
Commercial............................... 237,785 220,659 218,558
Industrial............................... 150,178 144,094 144,272
Other sales of electricity............... 111,781 102,690 104,819
Interchange deliveries................... 61,437 30,606 33,523
Other electric revenues.................. 9,036 8,663 7,539
---------- ---------- ----------
Total revenues.......................... $875,663 $780,175 $784,599
========== ========== ==========
Number of customers (end of period):
Residential.............................. 342,710 336,076 330,632
Commercial............................... 43,324 42,427 41,539
Industrial............................... 715 726 753
Other.................................... 605 590 578
---------- ---------- ----------
Total customers......................... 387,354 379,819 373,502
========== ========== ==========
Average annual use per residential cus-
tomer (kWh)(1)........................... 10,336 9,680 9,843
Average annual revenue per residential
customer (1)............................. $902.14 $820.02 $838.98
Average revenue per kWh (cents):
Residential.............................. 8.7 8.5 8.5
Commercial............................... 7.1 7.0 7.1
Industrial............................... 4.6 4.6 4.6
GAS:
Gas sales (Mcf)........................... 18,066 17,013 15,574
Gas transported (Mcf)..................... 1,539 3,155 2,610
Gas revenue (thousands)................... $94,944 $83,869 $71,222
Number of customers (end of period):
Residential.............................. 86,027 82,996 80,874
Commercial............................... 6,751 6,500 6,313
Industrial............................... 150 152 154
Other.................................... 12 11 10
---------- ---------- ----------
Total customers......................... 92,940 89,659 87,351
========== ========== ==========
Residential gas service:
Average annual use per customer (Mcf)(1). 86.85 88.71 80.24
Average annual revenue per customer (1).. $558.59 $526.94 $446.07
Average revenue per Mcf.................. $6.43 $5.94 $5.56
- --------
(1) Based on average number of customers during period.
IV-14
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Delmarva Power & Light Company
(Registrant)
Dated: March 22, 1994 /s/ Barbara S. Graham
By__________________________________
(Barbara S. Graham, Vice President
and Chief Financial Officer)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATE INDICATED.
SIGNATURE TITLE DATE
/s/ (Howard E. Cosgrove) Chairman of the Board, March 22, 1994
..................................... President, Chief
(Howard E. Cosgrove) Executive Officer,
and Director
/s/ (H. Ray Landon) Executive Vice March 22, 1994
..................................... President and
(H. Ray Landon) Director
/s/ (Barbara S. Graham) Vice President and March 22, 1994
..................................... Chief Financial
(Barbara S. Graham) Officer
/s/ (James P. Lavin) Comptroller and Chief March 22, 1994
..................................... Accounting Officer
(James P. Lavin)
/s/ (Michael G. Abercrombie) Director March 22, 1994
.....................................
(Michael G. Abercrombie)
/s/ (Elwood P. Blanchard, Jr.) Director March 22, 1994
.....................................
(Elwood P. Blanchard, Jr.)
/s/ (Robert D. Burris) Director March 22, 1994
.....................................
(Robert D. Burris)
/s/ (Audrey K. Doberstein) Director March 22, 1994
.....................................
(Audrey K. Doberstein)
/s/ (James H. Gilliam, Jr.) Director March 22, 1994
.....................................
(James H. Gilliam, Jr.)
/s/ (Sarah I. Gore) Director March 22, 1994
.....................................
(Sarah I. Gore)
/s/ (James C. Johnson, III) Director March 22, 1994
.....................................
(James C. Johnson, III)
/s/ (James T. McKinstry) Director March 22, 1994
.....................................
(James T. McKinstry)
IV-15
DELMARVA POWER & LIGHT COMPANY
1993 ANNUAL REPORT ON FORM 10-K
EXHIBIT INDEX
Exhibit Page
Number Description Number
- ------ ----------- ------
3-C Copy of the Company's Certificate of
Designation and Articles of Amendment
establishing the 6 3/4% Preferred Stock.
3-D Copy of the Company's By-laws as amended
September 30, 1993.
4-J Copy of the Eighty-Fourth Supplemental
Indenture.
4-K Copy of the Eighty-Fifth Supplemental
Indenture.
10-F Copy of the severance agreement with
members of management.
10-G Copy of the current listing of members
of management who have signed the severance
agreement.
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 1993 Annual Report
to Stockholders which are incorporated by
reference in this Form 10-K.
23 Consent of Independent Accountants.