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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, 1994
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)
800 KING STREET, P. O. BOX 231
WILMINGTON, DELAWARE
(ADDRESS OF PRINCIPAL EXECUTIVE 19899
OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 302-429-3359
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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
------------------- -----------------------------------------
FIRST MORTGAGE BONDS (SERIES NEW YORK STOCK EXCHANGE AND
ISSUED PRIOR TO 1968) PHILADELPHIA STOCK EXCHANGE.
PREFERRED STOCK, CUMULATIVE, PAR PHILADELPHIA STOCK EXCHANGE
VALUE $100.00 (SERIES ISSUED
PRIOR TO 1978)
COMMON STOCK, PAR VALUE $2.25 NEW YORK STOCK EXCHANGE AND
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
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM
405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO
THE BEST OF THE REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION
STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY
AMENDMENT TO THIS FORM 10-K. [X]
THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE
REGISTRANT AS OF FEBRUARY 28, 1995 WAS $1,186,293,276.
AS OF FEBRUARY 28, 1995, THERE WERE ISSUED AND OUTSTANDING 59,849,876 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 1994 ANNUAL REPORT TO STOCKHOLDERS OF DELMARVA
INFORMATION) AND POWER & LIGHT COMPANY.
II (ITEMS 6, 7 AND
8)
III PORTIONS OF THE DEFINITIVE PROXY STATEMENT FOR THE ANNUAL
MEETING OF STOCKHOLDERS OF DELMARVA POWER & LIGHT COMPANY, TO BE
HELD MAY 25, 1995, WHICH DEFINITIVE PROXY STATEMENT IS EXPECTED
TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OR
ABOUT APRIL 20, 1995.
IV PORTIONS OF THE 1994 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
Operating Statistics......................................... I-1
Strategic Plans for Competition.............................. I-1
Electric Operations.......................................... I-4
Installed Capacity........................................ I-4
Power Pool................................................ I-5
Reserve Margin............................................ I-5
Challenge 2000 Plan....................................... I-6
Power Plants................................................. I-7
Nuclear................................................... I-7
Peach Bottom Units........................................ I-7
Salem Units............................................... I-8
Life Extensions and Repowerings........................... I-9
Purchased Power.............................................. I-9
Cost of Output for Load...................................... I-10
Fuel Supply for Electric Generation.......................... I-10
Coal...................................................... I-10
Oil....................................................... I-10
Gas....................................................... I-10
Nuclear................................................... I-11
Gas Operations............................................... I-12
Subsidiaries................................................. I-12
Regulatory and Rate Matters.................................. I-13
Base Rate Proceedings..................................... I-13
Fuel Adjustment Clauses................................... I-14
Other Regulatory Matters.................................. I-16
Construction and Financing Program........................... I-17
Environmental Matters........................................ I-18
Construction Expenditures................................. I-18
Clean Air Act............................................. I-18
Salem Operating Permit.................................... I-19
Water Quality Regulations................................. I-19
Hazardous Substances...................................... I-20
Emerging Environmental Issues............................. I-21
Subsidiaries.............................................. I-21
Retail Franchises............................................ I-21
Number of Employees.......................................... I-22
Executive Officers of the Registrant......................... I-22
Item 2. Properties....................................................... I-23
Item 3. Legal Proceedings................................................ I-24
Item 4. Submission of Matters to a Vote of Security Holders.............. I-25
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
PART III
Item 10. Directors and Executive Officers of the Registrant............ III-1
Item 11. Executive Compensation........................................ III-1
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................... III-1
Item 13. Certain Relationships and Related Transactions................ III-1
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K........................................................... IV-1
Signatures.............................................................. IV-4
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 is predominantly a public utility
that provides electric service on the Delmarva Peninsula in an area consisting
of about 5,700 square miles with a population of approximately 1.0 million. The
Company also provides gas service in an area consisting of about 275 square
miles with a population of approximately 464,000 in northern Delaware,
including the City of Wilmington. In addition, the Company has wholly-owned
subsidiaries engaged in nonutility activities. These 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-12.
SEGMENT INFORMATION
See Note 20 to the Consolidated Financial Statements contained in the
Company's 1994 Annual Report to Stockholders filed as Exhibit 13.
OPERATING STATISTICS
A Schedule of Operating Statistics for the three years ended December 31,
1994 can be found on page IV-3. This schedule provides electric and gas sales
and revenue data.
STRATEGIC PLANS FOR COMPETITION
Competition exists and is expected to increase for certain electric and gas
energy markets historically served by regulated utilities. In recent years,
changing laws and governmental regulations, interest in self-generation, and
competition from other utilities as well as nonregulated energy suppliers are
providing some customers with alternative sources to satisfy their electric and
gas needs.
Electric Business Overview
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. While the Company's resale business accounted for 13% of
its 1994 electric revenues, neighboring utilities' resale revenues average only
1% to 2% of their electric revenues. Thus, compared to these utilities, the
Company has higher resale market risk.
The Company has reduced its resale market risk through extended service
contracts and longer notice provisions for load reductions. The Company has
signed electric supply contracts with eight of its nine municipal customers for
extended terms of eight to twenty years. These eight customers represented
about 95% of 1994 municipal revenues or about 4% of total 1994 electric
revenues. The Company also has signed
I-1
agreements with its other electric resale customers, representing about 9% of
total 1994 electric revenues, which require two years notice for load
reductions up to 30% and five years notice for load reductions greater than
30%.
Although the Energy Act only permits competition for wholesale customers,
several changes affecting competition in retail markets are developing. First,
large retail customers (i.e. commercial and industrial customers) are more
actively pursuing choices to reduce their energy costs through special
contracts, self-generation or cogeneration, the use of alternate fuel sources
such as natural gas, and the location, relocation, expansion, or downsizing of
their facilities. Second, both state legislatures and regulatory commissions
are beginning to explore the retail wheeling of electricity, which would permit
other utilities and non-utility generators to compete to serve large retail
customers currently served by a particular utility. For example, the California
Public Utility Commission has decided that widespread retail competition is
desirable and set forth a schedule which would permit the largest industrial
customers to choose an electric supplier in 1996. The California plan also
would make competitive choice of electric suppliers available to all retail
customers, including residential customers, by the year 2002. Maryland, New
Jersey, and Pennsylvania are beginning to consider what changes in regulatory
policies might be appropriate, and whether retail customers should be able to
purchase electricity from sources other than their local utility. For a summary
of recommendations for reform within the utility industry in Delaware, see
"Other Regulatory Matters--Delaware Task Force on Regulation" on page I-16.
Finally, FERC policy now requires that transmission services be offered to
wholesale customers and third parties under terms and conditions that are
comparable to the transmission services the Company provides to itself to
transmit power to its customers. As part of the Company's filing with the FERC
for approval of the purchase of Conowingo Power Company (discussed below), the
Company has proposed to offer comparable transmission services.
The Company is well positioned for competition in the retail markets. 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 1993 was 7.18 cents per
kilowatt hour (kwh) compared to a regional average of 8.71 cents per kwh. The
Company's average price for industrial customers in 1993 was 4.69 cents per kwh
compared to a regional average of 6.65 cents per kwh. These regional averages
are based on 1993 data for 27 utilities within a 300 mile radius of the
Company. Should retail wheeling become a reality, downward pressure on market
prices would be expected due to excess generating capacity in the northeast
region. The Company projects that this excess generating capacity will be
exhausted shortly after the year 2000.
Gas Business Overview
As a result of FERC initiatives, the interstate gas pipeline system has been
opened to permit the transportation of natural gas by end users, including the
Company's gas customers. The Company has adopted 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. The Company has
reduced its firm gas market risk through a three-year notice requirement for
firm customers switching to transportation or other non-firm service. For a
discussion of an additional matter related to competition, see "Other
Regulatory Matters--Natural Gas Restructuring Filing" on page I-16.
Market-Driven Strategies
Recognizing changes in the utility industry, the Company has implemented
market-driven strategies and segmented markets according to customer needs and
buying patterns. The major market segments are the core market, the competitive
market, and the commodity market as discussed below.
The core market segment, which represents about 60% of the Company's electric
sales revenues, is comprised of residential and small- to medium-size
commercial and industrial customers. The Company's
I-2
strategies for growth in the core market focus on sustaining relative price
stability, maintaining superior customer service, and expanding and growing
energy-related value added products and services.
The competitive market segment, which represents about 25% of the Company's
electric sales revenues, consists of large commercial and industrial (retail)
and service-oriented resale customers. The Company's goal for this segment is
to grow and secure existing relationships and to position the Company to take
advantage of competitive opportunities. As previously discussed, prices charged
to current Company commercial and industrial customers are among the lowest in
the region.
The commodity market segment, which represents about 15% of the Company's
electric sales revenues, consists of energy intensive industrial and price-
focused resale customers. As previously discussed, the Company has negotiated
electric supply contracts with its resale customers, reducing market risk in
the commodity market.
"Three-Legged Stool"
In 1994, the Company announced its "Three-Legged Stool" strategy, which
includes three initiatives designed to aid the Company in achieving its
financial goals of maintaining the current dividend level, growing earnings,
and earning a return on equity of at least 11.5%, while keeping prices
competitive. The three initiatives are as follows: (1) reduce costs by $15
million to $20 million; (2) increase non-fuel revenues by $10 million to $20
million through short-term energy and capacity sales to regional utilities and
additional retail sales; (3) increase non-fuel revenues through $10 million to
$15 million of targeted price increases. The amounts of the cost reductions and
revenue increases are based on comparison to an earlier projection of the
Company's 1995 financial results. The Company expects that its targeted total
of cost reductions and revenue increases of $40 to $45 million will be
achieved, allowing the Company to meet its financial goals despite lower
expected sales revenues from resale customers in 1995. Non-fuel revenues from
resale customers will decrease approximately $28 million due to Old Dominion
Electric Cooperative's (ODEC) decision to purchase about one-half of its
electricity from another utility beginning in 1995 and price incentives offered
to other resale customers to secure extended purchase commitments. The
Company's initiatives are discussed further below.
Cost Initiatives
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The Company's voluntary 1994 early retirement offer, which has reduced the
workforce by 10.5%, is expected to result in annual cost savings of $13 million
to $17 million. In order to capture these savings, the Company identified areas
where work could be streamlined, reduced, or eliminated. In addition, the
Company's 1995 budget is structured to attain savings of approximately $13
million in other operation and maintenance expenses and capital-related costs.
For a further discussion of the early retirement offer, see Note 4 to the
Consolidated Financial Statements of the 1994 Annual Report to Stockholders
filed as Exhibit 13.
Sales Initiatives
-----------------
In December 1992, General Motors, one of the Company's largest electric and
gas customers, announced plans to close its Delaware manufacturing plant in
1996. In November 1994, General Motors announced that it will continue to
operate the plant through 1998. General Motor's decision, a regional
unemployment rate which is improving and less than the national average, and
other indicators signal that the economy of the Company's service territory is
improving. Due to the improving economy and opportunities which involve
expanded products and services, the Company expects that 1995 sales revenues
will be higher than previously projected and contribute to the sales
initiative.
On May 24, 1994, the Company entered into an agreement with PECO Energy
Company (PECO) to buy its Maryland retail electric subsidiary, Conowingo Power
Company (COPCO), for $150 million. This purchase is contingent upon various
regulatory approvals, which the Company expects to receive by mid-1995. The
COPCO purchase will add approximately 35,000 new electric retail customers,
equivalent to 9%
I-3
of the Company's current customer base. The Company plans to finance the
purchase with approximately 50% long-term debt and 50% common equity. The
Company expects the COPCO purchase will contribute $0.04 to $0.06 of
incremental earnings per share by 1997. For a further discussion of the
purchase of COPCO and associated power purchase agreements with PECO, see
"Challenge 2000 Plan" on page I-6, "Other Regulatory Matters--Purchase of
COPCO" on page I-16, and Note 6 to the Consolidated Financial Statements of the
1994 Annual Report to Stockholders filed as Exhibit 13.
The Company proposed to purchase the electric system of the City of Dover,
Delaware in 1993 for $103.5 million. On November 23, 1994, Dover's City Council
requested proposals from utilities and independent power producers for power
purchase agreements and potentially the purchase of, or the operation and
maintenance of, the city's generating facilities. The capacity required to
serve the city would be approximately 140 megawatts (MW) plus reserve
requirements. On January 30, 1995, the Company filed a proposal in response to
Dover's request. City officials expect to decide on a future power source in
the summer of 1995.
Price Initiatives
-----------------
In 1994, the Company filed applications with the Delaware Public Service
Commission (DPSC) and Maryland Public Service Commission (MPSC) for increases
in electric base rates of $13.5 million and $3.9 million, respectively. The
Company subsequently revised its proposed Delaware electric base rate increase
to $11.1 million. As further discussed under "Base Rate Proceedings" on page I-
13, both these cases are designed to recover the cost of "limited issues,"
which are primarily costs imposed by government and are outside the reasonable
control of the Company. Net of related decreases in fuel rates, prices would
increase 1.3% in Delaware and 1.1% in Maryland under the Company's proposals.
Even with these proposed price increases, the Company's prices are expected to
remain well below the regional average. The Hearing Examiners in Delaware and
Maryland issued their reports recommending no increases. The Company filed
appeals to these recommendations. Decisions on the cases are expected in late
March or April 1995.
On October 18, 1994, the DPSC approved a settlement agreement for a $3.1
million, or 3.1% increase in gas base rates. The increase became effective
November 1, 1994, when lower fuel rates also became effective. The reduced fuel
rates combined with the base rate increase resulted in a net average decrease
of 1.75%.
Certain Other Potential Ramifications of Competition
Traditionally, prices charged to utility customers are designed to recover a
regulated utility's costs of providing service. Generally accepted accounting
principles require regulated utilities that have cost-of-service pricing to
defer the recognition of certain costs which are being or are probable of being
recovered from customers. These deferred costs are often referred to as
"regulatory assets." (Refer to Note 1 to the Consolidated Financial Statements
contained in the Company's 1994 Annual Report to Stockholders filed as Exhibit
13 for additional information on regulatory assets.) As the utility industry
shifts from traditional cost-of-service pricing to prices set by competitive
market forces or alternate innovative regulatory methods, regulatory assets,
and possibly other utility assets, could be required to be written down. The
Company cannot predict the amount, if any, of such a write-down; however, it
could be material. The Company's regulatory assets as a percentage of total
assets or stockholders' equity are substantially lower than the averages for
the utility industry.
ELECTRIC OPERATIONS
Installed Capacity
The net installed summer electric generating capacity available to the
Company to serve its peak load as of December 31, 1994, 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
I-4
and non-utility generators, and construction of new generating capacity. For a
discussion of the energy supply plan, see "Challenge 2000 Plan" on page I-6.
% OF
INSTALLED SUMMER CAPACITY MEGAWATTS TOTAL
------------------------- --------- -----
Coal Fired................................................. 1,141 41
Oil-Fired.................................................. 595 21
Combustion Turbines/Combined Cycle......................... 511 18
Nuclear.................................................... 321 11
Peaking Units.............................................. 183 7
Purchased Capacity......................................... 48 2
Customer-owned Capacity.................................... 57 2
----- ---
Subtotal................................................. 2,856 102
Capacity Transferred to Another Utility.................... (50) (2)
----- ---
Total.................................................... 2,806 100
===== ===
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-23 for a detailed listing of
net installed generating capacity by station.
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 $15.4 million during 1994.
The PJM Interconnection's installed capacity as of December 31, 1994, was
56,073 MW. The PJM Interconnection peak demand during 1994 was 45,992 MW on
July 8th, which resulted in a summer reserve margin of 21.4% (based on
installed capacity of 55,851 MW on that date). The all-time peak demand of
46,429 MW was set on July 8, 1993 and resulted in a summer reserve margin of
19.4% (based on installed capacity of 55,440 MW on that date).
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 1994 was 2,551 MW on July 8th, which surpassed the
Company's previous peak demand of 2,544 MW on July 9, 1993. Because adequate
generation was available at the time, these peaks do not reflect full
implementation of the Company's demand-side programs, including the curtailment
of large interruptible customers. The Company's PJM Interconnection 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 2,389 MW in 1994. Based upon this estimated peak and the Company's installed
generating capacity of 2,806 MW at the time, the Company's reserve margin would
have been 17.5%. The Company's PJM Interconnection reserve obligation varies
from year to year but is typically around 18%.
I-5
Challenge 2000 Plan
The Challenge 2000 Plan reflects the Company's strategy to provide an
adequate, reliable supply of electricity to customers, while minimizing adverse
impacts on the environment and keeping prices competitive. The Company's plan,
which is updated annually, is based on forecasts of demand for electricity in
the service territory and reserve requirements of the PJM Interconnection. The
Company's plan emphasizes balance and flexibility, and may be accelerated,
slowed, or altered in response to changing energy demands, fluctuating fuel
prices, and emerging technologies. The plan combines customer-oriented load
management and strategic conservation programs ("Save Some"), short-term power
purchases and long-term power contracts ("Buy Some"), and new or renovated
power plants ("Build Some"). The Company's current plan closely matches
customers' energy requirements and does not require large investments for new
resources during the next two years.
As of the end of 1994, the demand-side programs ("Save Some") of the
Challenge 2000 Plan had enrolled about 80,000 residential customers and about
1,000 commercial and industrial customers who in aggregate provide the Company
with the ability to reduce its peak by approximately 240 MW. On March 31, 1994,
following the approval of the Virginia State Corporation Commission (VSCC), the
Company implemented five new conservation programs in Virginia. Included were
two programs for residential customers, promoting high-efficiency cooling
equipment and new home construction standards, and three programs for
commercial and industrial customers, promoting high-efficiency lighting and
cooling technologies. The Company previously implemented conservation programs
in Delaware and Maryland.
As part of the "Buy Some" portion of the Challenge 2000 Plan, the Company is
purchasing 48 MW of peaking capacity through May 2018 from the Delaware City
Power Plant owned by Star Enterprise (Star). On October 27, 1994, the Company
canceled an agreement with the Delaware Clean Energy Project which would have
provided 165 MW of capacity for 30 years beginning in 1999. The decision to
terminate the agreement was based on uncertainties associated with the
Company's load requirements, a general decline in wholesale market prices, and
absence of need for long-term capacity. The capacity and energy that will be
required to serve COPCO subsequent to the planned acquisition will be purchased
from PECO. The power purchase, which is contingent on closing of the
acquisition, is expected to provide 205 MW of capacity beginning in 1996 or
later, increasing to 259 MW by the end of the contract in 2006. Short-term
purchases during the period 1998-2000 are also being contemplated to meet
capacity obligations during the repowering outages at the Indian River Power
Plant. The repowering plans are further discussed under "Life Extensions and
Repowerings" on page I-9.
In June 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). The Company has a power plant life extension
program and repowering plans to extend the operating lives of certain
generating units as further discussed under "Life Extensions and Repowerings"
on page I-9.
I-6
The table below summarizes the latest peak load and capacity forecast of the
Challenge 2000 Plan over the current and next five PJM Interconnection planning
periods, which begin on June 1 of each year. The Company periodically reviews
and updates its forecast to reflect changes in peak load and capacity
estimates, and the table incorporates the effect of the planned acquisition of
COPCO and the associated power purchase agreement with PECO, starting in 1996.
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 (%)
--------- ------- ----- ------- ----- ------ --------- -------
1994 2,629 240 2,389 48 2,758 2,806 17.5%
1995 2,527 242 2,285 48 2,805 2,853 24.9%
1996 2,769 251 2,518 253 2,810 3,063 21.6%
1997 2,832 264 2,568 260 2,810 3,070 19.5%
1998 2,900 277 2,623 290 2,810 3,100 18.2%
1999 2,970 291 2,679 446 2,721 3,167 18.2%
POWER PLANTS
Nuclear
The Company's nuclear capacity is provided by Peach Bottom Atomic Power
Station (Peach Bottom) Units 2 and 3 and by Salem Nuclear Generating Station
(Salem) Units 1 and 2. The Company jointly owns these units, as tenants in
common, with PECO, Atlantic City Electric Company, and Public Service Electric
and Gas Company (PSE&G). The Peach Bottom units are operated by PECO and have a
combined summer capacity of 2,086 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 that continuous demonstrations be made to the NRC that plant
operations meet applicable requirements. The NRC has the ultimate authority to
determine whether any nuclear generating unit may operate.
For a discussion of the Company's funding of its share of the estimated
future cost of decommissioning the Peach Bottom and Salem nuclear reactors, see
Note 8 to the Consolidated Financial Statements contained in the Company's 1994
Annual Report to Stockholders filed as Exhibit 13.
As by-products of their operations, nuclear generating units, including the
Peach Bottom and Salem units, produce low level radioactive waste (LLRW). Such
waste includes paper, plastics, protective clothing, and other materials which
must be properly disposed. Prior to July 1994, PECO and PSE&G disposed of such
materials at a federally licensed permanent disposal facility in South
Carolina. However, in accordance with the Low Level Radioactive Waste Policy
Act, as amended, disposal sites have exercised their authority to either cease
operations or deny access to states which are not members of their regional
compact. Effective July 1, 1994, LLRW from Peach Bottom and Salem could no
longer be disposed at the South Carolina site and is being stored temporarily
on site until Pennsylvania and New Jersey provide permanent disposal sites.
Both these states are in the process of locating suitable sites. The on-site
facilities at PECO and PSE&G have capacity for at least five years' storage.
Peach Bottom Units
On March 28, 1994, the NRC approved PECO's request to extend the expiration
dates of the Facility Operating Licenses for Peach Bottom Units 2 and 3 by
approximately six years to August 2013 and July 2014, respectively.
I-7
On June 29, 1994, the NRC issued its Systematic Assessment of Licensee
Performance (SALP) Report on the performance of activities at Peach Bottom for
the period November 1, 1992, to April 30, 1994. This SALP was conducted under
the revised process in which the number of assessment areas has been reduced
from seven to four. The numeric rating criteria remains unchanged with "1"
being the highest rating and "3" the lowest rating, although still acceptable.
Under the recent SALP, Peach Bottom earned a rating of "1" in Operations and a
rating of "2" in each of the other three areas: Maintenance, Engineering, and
Plant Support. Overall, the NRC found continued improvement in performance
during the period. The NRC stated that enhancement in problem identification
and resolution, good control of refuelings and outages, and excellent oversight
by plant management of day-to-day activities in a manner that ensured safer
operation of the units contributed to the improvement. Despite the overall
improvement, the NRC noted that some areas require continued management
attention and that management needs to continue to encourage plant personnel at
all levels to identify existing, and sometimes longstanding, problems so that
priorities can be established and effective corrective actions implemented. The
NRC also noted instances of personnel inattention to detail and failure to
follow procedures which warranted additional management attention. PECO has
informed the Company that it has taken and is taking actions to address the
weaknesses discussed in the SALP Report.
PECO has informed the Company that on October 18, 1994, the NRC held an
enforcement conference to discuss a violation at Peach Bottom. An emergency
service water valve was left closed and unattended for approximately 45 minutes
during testing, which would have prevented safety-related equipment from
receiving the proper cooling flow in an emergency. On November 21, 1994, PECO
received a Notice of Violation for this incident, including a civil penalty of
$87,500.
PECO has informed the Company that in October 1990, General Electric Company
(GE) reported that crack indications were discovered near the seam welds of the
core shroud assembly in a GE Boiling Water Reactor (BWR) located outside the
United States. As a result, GE issued a letter requesting that the owners of GE
BWR plants take interim corrective actions, including a review of fabrication
records and visual examinations of accessible areas of the core shroud seam
welds. Peach Bottom Unit 3 was examined in October 1993 during the last
refueling outage and crack indications were identified at two locations. In
November 1993, PECO presented its findings to the NRC and provided
justification for continued operation of Unit 3 for another two-year cycle with
crack indications. Peach Bottom Unit 2 was examined in October 1994 during its
last refueling outage and the inspection revealed a minimal number of flaws. In
November 1994, PECO submitted its findings to the NRC and provided
justification for continued operation of Unit 2. PECO is participating in a GE
BWR Owners Group to develop long-term corrective actions.
Salem Units
As a result of the NRC investigation following the reactor shutdown of Salem
Unit 1 in April 1994, PSE&G was fined $500,000 for violations relating to (1)
the failure to identify and correct significant conditions adverse to quality
at the facility related to spurious steam flow signals and inoperable
atmospheric relief valves, both of which, the NRC concluded, led to unnecessary
safety injections during the event; (2) the failure to identify and correct
significant conditions adverse to quality at the facility related to providing
adequate training, guidance and procedures for the operators to cope with the
event; and (3) the failure by supervisors to exercise appropriate command and
control of the operations staff and the reactor during the event. On November
1, 1994, PSE&G responded to the violations and paid the fine.
On January 3, 1995, the NRC issued its SALP Report on the performance of
activities at Salem for the period June 30, 1993, to November 5, 1994. The NRC
assigned ratings of "3" to the Operations and Maintenance areas, "2" to
Engineering, and "1" to Plant Support. The NRC noted that "overall performance
has declined and we are particularly concerned with the challenges to plant
systems and operators caused by repetitive equipment problems and personnel
errors that had the potential to, or actually did, adversely affect plant or
personnel safety. Notwithstanding, we recognize that [PSE&G] has, within the
last year, initiated
I-8
several comprehensive actions that have the potential to improve overall plant
performance. However, while we acknowledge some recent incremental performance
gains, these efforts have not yet resulted in any noticeable change in overall
performance."
PSE&G has informed the Company that it is taking significant steps to address
performance shortfalls at Salem. In 1993, a comprehensive performance
assessment team identified areas of weakness through an in-depth investigation
of common causes and events. Corrective action plans and effectiveness measures
were then initiated in 1994 and are ongoing, along with additional measures
designed to achieve a change in Salem's performance. Personnel performance is
being addressed through improved supervisory training and increased monitoring
of work activities, improved operational command and control, and the
reorganization and increased staffing of Salem. PSE&G has established a goal of
safe, uneventful operation to be achieved through enhanced self-assessment and
corrective action processes, resolution of long-standing equipment problems,
improved independent oversight of plant operations and improved root-cause
analysis of plant problems. In furtherance of these goals, PSE&G has
reorganized the operational structure of its Nuclear Department and recruited a
new chief nuclear officer from outside PSE&G. In addition, PSE&G's parent
company, Public Service Enterprise Group, Incorporated (Enterprise), has
strengthened oversight of nuclear plant operations by establishing a standing
Nuclear Committee of its Board of Directors.
PSE&G also has informed the Company that on March 21, 1995, representatives
of the NRC met with the Boards of Directors of Enterprise and PSE&G to discuss
the need for continued improvements in equipment reliability and staff
performance. PSE&G cannot predict what further actions, if any, the NRC may
take or require to improve Salem's performance.
See page I-19 for a discussion on the status of the operating permit at
Salem.
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 surveys
beginning in 1996. Construction expenditures on these projects for the five-
year period 1995-1999 are expected to total approximately $45 million,
excluding allowance for funds used during construction (AFUDC).
The Company also plans to repower Indian River Units 1 and 2 utilizing
circulating fluidized bed technology. These projects, which will be performed
during consecutive two-year outages beginning in 1999, will extend the
operating life of each unit by 20 years and reduce emissions. Construction
expenditures on these projects for the five-year period 1995-1999 are expected
to be approximately $88 million, excluding AFUDC.
PURCHASED POWER
The Company purchases coal-fired energy from the Allegheny Power System 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, 1995. The 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 $3.8 million during
1994.
The Company also has purchased 48 MW of long-term capacity and has entered
into a power purchase agreement with PECO associated with its acquisition of
COPCO as discussed under "Challenge 2000 Plan" on page I-6.
I-9
COST OF OUTPUT FOR LOAD
The following table sets forth the Company's annual generation output, fuel
cost per megawatt hour (MWh), and generation mix by unit fuel type for all
Company-owned facilities. Coal is the Company's predominant fuel. Corresponding
values for purchased power and for net interchange (purchases less sales) as a
member of the PJM Interconnection are also listed.
GENERATION 1994 1993 1992
---------- ---------------- ---------------- --------------
1,000 $/ 1,000 $/ 1,000 $/
UNIT FUEL TYPE MWH MWH % MWH MWH % MWH MWH %
-------------- ------ --- --- ------ --- --- ------ --- ---
Coal-fired............... 5,499 18 42 6,028 18 47 4,696 19 39
Oil-fired................ 1,998 27 15 2,343 24 18 1,713 26 14
Nuclear.................. 2,052 8 16 1,883 7 14 1,696 7 14
Natural Gas (1).......... 2,033 19 15 1,010 23 8 443 32 4
------ --- --- ------ --- --- ------ --- ---
Total Company
Generation............ 11,582 18 88 11,264 18 87 8,548 18 71
PURCHASES/INTERCHANGE
---------------------
Purchases................ 2,873 23 22 3,200 22 25 2,826 22 23
Net Interchange.......... (1,328) (32) (10) (1,568) (30) (12) 755 7 6
------ --- --- ------ --- --- ------ --- ---
Total Output for Load.. 13,127 17 100 12,896 18 100 12,129 19 100
====== === === ====== === === ====== === ===
- --------
(1) Includes the output of a 175 MW combined cycle unit, Hay Road Unit 4,
effective June 1, 1993.
FUEL SUPPLY FOR ELECTRIC GENERATION
The Company's electric generating capacity by fuel type is shown under
"Electric Operations--Installed Capacity," on page I-4.
Coal
Edge Moor Units 3 and 4, and the Indian River, Keystone and Conemaugh
generating stations are coal-fired. As of December 31, 1994, a maximum of 84%
of the Company's coal requirements were under supply contracts. During 1994,
34% of the coal was purchased under short-term contracts (less than three
years), 52% 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 1996. 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. The Company expects to negotiate a new contract in 1995 with
similar terms.
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-12. Additional natural gas
is purchased on a firm or interruptible basis from one of the Company's
pipeline suppliers. The secondary fuel for the Hay Road CTs is kerosene, which
is purchased in the spot market.
I-10
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 2002. In
February 1995, two companies which supply uranium concentrates to PECO filed
petitions for bankruptcy under Chapter 11 of the Bankruptcy Code. The two
companies supply approximately half of PECO's 1995 and 1996 requirements for
uranium concentrates. In addition, one of the companies is under contract to
supply approximately 25% of PECO's uranium concentrate requirements for the
period 1997 to 2002. PECO has made alternative arrangements with other
suppliers to satisfy its short-term requirements for uranium concentrates. For
the longer-term, PECO is evaluating its requirements and potential supply
sources, including the two suppliers which have filed petitions for bankruptcy.
PECO does not anticipate any difficulties in obtaining its requirements for
uranium concentrates. PSE&G also has informed the Company that it has contracts
for uranium concentrates which will satisfy the fuel requirements of Salem
fully through 2000 and, thereafter, 60% through 2002. PSE&G does not anticipate
any difficulties in obtaining its requirements for uranium concentrates. The
table below summarizes the years through which PECO and PSE&G have contracted
for the other segments of the nuclear fuel supply cycle.
CONVERSION ENRICHMENT FABRICATION
---------- ---------- -----------
Peach Bottom Unit 2........................ 1997 (1) 1999
Peach Bottom Unit 3........................ 1997 (1) 1998
Salem Unit 1............................... 2000 (2) 2004
Salem Unit 2............................... 2000 (2) 2005
- --------
(1) PECO is committed for enrichment services under contract with the United
States Enrichment Corporation. The commitments represent 100% of the
enrichment requirements through 1998 and 70% through 1999. PECO does not
anticipate any difficulties in obtaining necessary enrichment services for
Peach Bottom.
(2) 100% coverage through 1998; approximately 50% coverage through 2002; and
approximately 30% coverage through 2004. PSE&G does not anticipate any
difficulties in obtaining necessary enrichment services for Salem.
In conformity with the Nuclear Waste Policy Act of 1982 (NWPA), PECO and
PSE&G entered into contracts with the United States Department of Energy (DOE)
on behalf of the joint owners providing that the Federal Government shall for a
fee take title to, transport, and dispose of spent nuclear fuel and high level
radioactive waste from the Salem and Peach Bottom reactors. The Company is
collecting one-tenth of one cent per kWh of nuclear generation net of station
use from electric customers through fuel rates to provide for the future cost
of spent nuclear fuel disposal and is paying such amounts to the DOE. The DOE
may revise this charge as necessary to ensure full cost recovery of nuclear
fuel disposal. Under the NWPA, the Federal Government was to begin accepting
spent fuel for permanent off-site 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. In
October 1990, the NRC determined that spent nuclear fuel generated in any
reactor can be stored safely and without significant environmental impact in
reactor facility storage pools or in independent spent nuclear fuel storage
installations located at or away from reactor sites for at least 30 years
beyond the licensed life for operation (which may include the term of a revised
or renewed license). In May 1994, the DOE issued a Notice of Inquiry in which
it took the position that it has no legal obligation to begin accepting spent
fuel until it has a suitable storage facility in operation.
I-11
In June 1994, two separate lawsuits were filed by a group of states and Public
Utility Commissions and a group of utilities, respectively, in the U.S. Court
of Appeals for the District of Columbia Circuit to compel the DOE to accept
spent fuel by 1998. The Company is not a party to the lawsuit brought by the
group of utilities. The Company cannot predict when the DOE sponsored 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, pursuant to a license from the NRC to replace the existing
high-density racks in the spent-fuel storage pools of Salem Units 1 and 2 with
maximum-density racks, it will extend the storage capability of Salem Unit 1
through March 2008 and Salem Unit 2 through March 2012.
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 through 2008 or until $2.25 billion, adjusted
annually for inflation, is collected. In 1992, 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-14. The liability for
the Company's share of the D&D Fund cost was $7.2 million as of December 31,
1994.
GAS OPERATIONS
During 1994, the average production cost of all gas sold was $3.06 per
thousand cubic feet (Mcf), compared with $3.22 per Mcf in 1993 and $2.70 per
Mcf in 1992. 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 148,957 Mcf. With the use of emergency peak shaving
capabilities at its local peak shaving plant, the Company's maximum daily
sendout capacity is 168,957 Mcf. The Company experienced a new all-time peak
daily firm sendout of 158,512 Mcf on January 19, 1994, during extreme weather
conditions. Emergency peak shaving 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 21,730
Transportation.................................. 3 2004 59,795
Storage......................................... 4 1995-2004 42,432
Local Peak Shaving.............................. -- -- 25,000
-------
Total......................................... 148,957
=======
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 sendout of 25,000 Mcf per day
and emergency capability of 45,000 Mcf per day.
SUBSIDIARIES
Delmarva Capital Investments, Inc. (Delcap) is a wholly-owned subsidiary of
the Company that has invested in leveraged equipment leases, landfill and
waste-hauling companies, alternative energy projects, real estate projects and
has also undertaken operation and maintenance contracts for alternative energy
and
I-12
related projects. A Delcap subsidiary operates and maintains Star's Delaware
City Power Plant from which the Company purchases peaking capacity.
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 1994, Delcap made dividend payments of $8 million
to the Company. As of December 31, 1994, its stockholder's equity was $32.7
million, of which landfill and waste-hauling represented about $22.8 million.
Delmarva Services Company, a wholly-owned subsidiary of the Company, leases
an office building to the Company. As of December 31, 1994, its stockholder's
equity was $5.6 million.
Delmarva Energy Company and Delmarva Industries, Inc. are wholly-owned
subsidiaries of the Company and are partners in joint venture oil and gas
exploration and development programs in New York, Ohio, and Pennsylvania. As of
December 31, 1994, their combined stockholder's equity was $2.1 million.
For a further discussion of the Company's subsidiaries see "Environmental
Matters--Subsidiaries" on page I-21 as well as the Nonutility Subsidiaries
section of Management's Discussion and Analysis of Financial Condition and
Results of Operations and Notes 1, 5, and 19 to the Consolidated Financial
Statements of the 1994 Annual Report to Stockholders filed as Exhibit 13.
REGULATORY AND RATE MATTERS
The Company is subject to regulation with respect to its retail utility sales
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. The FERC exercises jurisdiction with respect to
the Company's accounting systems and policies, and the transmission and
wholesale (resale) sale of electricity. The FERC also regulates the price and
other terms of transportation of natural gas purchased by the Company. The
percentage of electric and gas utility operating revenues regulated by each
Commission for the year ended December 31, 1994, was as follows: DPSC 64%; MPSC
22%; VSCC 3%; and FERC 11%.
BASE RATE PROCEEDINGS
The Company's most recent base rate filings are discussed below:
Delaware (Docket No. 94-84)
On August 16, 1994, the Company filed an application with the DPSC for a
$13.5 million "limited issue" increase in electric base rates. The Company
subsequently revised the amount of the proposed increase to $11.1 million. The
proposed increase, when netted with fuel savings related to reduction in load
by a resale customer (ODEC) beginning in 1995, is $6.4 million or 1.3%. This
"limited issue" increase is designed to recover costs specific to the Company's
compliance with the Clean Air Act Amendments of 1990, the 1% increase in the
marginal federal income tax rate to 35% during 1993, demand side management and
conservation programs, and an increase in funding for nuclear decommissioning
based on the current NRC minimum funding requirements. The DPSC staff and other
parties to the case have recommended that no revenue increase be granted due to
the Company's current return earned from its Delaware electric operations.
However, the DPSC staff has suggested that if the DPSC decides to consider a
"limited issue" approach, an alternative to approving a rate increase would be
to instead authorize a $9 million increase if monthly or quarterly 1995
earnings fall below certain levels. On March 1, 1995, the Hearing Examiner
issued his report recommending no change in current rates. On March 16, 1995,
the Company filed exceptions to the Hearing Examiner's report. The Company
expects a DPSC decision on the case in late March 1995.
Maryland (Case No. 8676)
On September 1, 1994, the Company filed an application with the MPSC for a
$3.9 million "limited issue" increase in electric base rates. The proposed
increase, when netted with ODEC related fuel savings, is $2.2 million or 1.1%.
This "limited issue" increase is designed to recover costs similar to those in
the Delaware "limited issue" case, except for demand side management and
conservation program costs which
I-13
are recoverable from Maryland customers through a surcharge. The MPSC staff's
testimony proposes a rate decrease of $9.6 million, reflecting a historical
test year, a lower return on equity, and certain adjustments which are beyond
the scope of the limited-issue filing. On February 3, 1995, the Hearing
Examiner issued his proposed order recommending no change in current rates. On
March 6, 1995, the Company filed an appeal to the Hearing Examiner's proposed
order. The Company expects a MPSC decision on the case in April 1995.
The Company's most recent base rate increases are summarized below. Gas base
rates were increased during 1994 to recover higher operating costs and
investment levels than were reflected in previous rates. Electric base rates
were increased during 1993 to recover higher costs associated with completion
of Hay Road Unit 4, postretirement benefit costs under Statement of Financial
Accounting Standards (SFAS) No. 106, and other items, including general
inflation.
DELAWARE VIRGINIA DELAWARE MARYLAND SYSTEM
RETAIL RETAIL RETAIL RETAIL RESALE
GAS ELECTRIC ELECTRIC ELECTRIC ELECTRIC
DOCKET 94-22 PUE 930036 DOCKET 92-85 CASE 8492 ER 93-96
------------ ---------- ------------ --------- --------
(DOLLARS IN THOUSANDS)
Company Filing
Date of Filing........ 5/6/94 5/7/93 10/30/92 10/30/92 10/30/92
Revenue Increase
Filed................ $4,200 $2,315 $36,554 $11,961 $5,566
Percent Increase
Filed................ 4.10% 10.06% 8.48% 6.55% 5.44%
Interim Rates
Date Effective........ 7/5/94 10/5/93 6/1/93 -- 6/3/93
Revenue Increase...... $1,000 $2,315 $35,377 -- $4,000
Commission Order
Date of Order......... 10/18/94 2/23/94 10/5/93 3/26/93 -- (4)
Date Effective........ 11/1/94 10/5/93 6/1/93 4/1/93(3) 6/3/93
Revenue Increase Al-
lowed................ $3,100(1) $1,281 $24,900(2) $7,800(3) $1,500(4)
Percent Increase Al-
lowed................ 3.15%(1) 5.41% 5.80%(2) 4.27%(3) 1.47%
Return on Common Eq-
uity Allowed......... 11.50% 11.05% 11.50% N.A.(3) N.A.
- --------
(1) Reduced fuel rates also became effective November 1, 1994. The reduced fuel
rates, when combined with the base rate increase, resulted in a net average
decrease of 1.75%.
(2) 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 3.7%.
(3) The effective date of the increase was two months earlier than expected.
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%. Although a specific return on equity was not
specified, the Company believes that the implied return on equity
approaches 12%.
(4) The base rate increase was reached through settlement agreements with all
resale customers. The agreements were approved by the FERC between June and
December 1994 and also provided for longer termination notice periods (a
two-year notice for up to 30% load reduction and a five-year notice for
greater than 30% load reduction).
FUEL ADJUSTMENT CLAUSES
The Company's tariffs generally include fuel adjustment clauses that permit
the collection of the costs of fuel burned in generating stations and the
variable (energy) costs of purchased and net interchange power from the
Company's retail and resale electric customers, and the costs of natural gas
from its gas customers. Fuel costs are deferred and charged to operations on
the basis of fuel costs included in customer billings under the Company's
tariffs. For the Delaware, Virginia, and FERC jurisdictional customers, the
clauses are based upon estimated annual fuel costs. For the Maryland
jurisdictional customers, the clause is based on historical average costs.
Supporting data are filed with and audited by the various commissions and
formal hearings are held at periodic intervals as required by law. Fixed costs
(capacity or demand charges) associated with purchased power transactions
entered into for reliability reasons are generally subject to base rate
recovery. The present status or results of significant fuel rate issues are
discussed below. As of December 31,
I-14
1994, 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 rewards or penalties is
limited to two percent (2%) of the total equity investment in the 15 units or
approximately $3.7 million. The PPPP compares actual performance (defined as
the three-year average equivalent availability factor for fossil units or
capacity factor for nuclear units) with a predetermined target for each
generating unit. Results under the PPPP for calendar year 1993 were a reward of
$80,000. Preliminary calculations under the PPPP for 1994 result in a penalty
of approximately $350,000 due primarily to various outages between 1992 and
1994 at Salem Units 1 and 2 and Indian River Unit 4. Should the Company's 1995
annual retail fuel adjustment filing result in the disallowance of certain
replacement power costs (as discussed below), then the PPPP penalty for 1994 is
estimated at approximately $200,000. PPPP reward or penalty amounts are
reflected in base rates as an additional charge or credit in the second year
after the program year (i.e. the 1993 reward is being reflected in calendar
year 1995 base rates as an additional charge, and the expected 1994 penalty
would be reflected in calendar year 1996 as a credit to base rates).
In October 1994, the Company made its annual retail fuel adjustment filing
for 1995. DPSC staff has recommended a disallowance of approximately $800,000
of net replacement power costs associated with the Salem Unit 1 outage which
lasted from April 7, 1994 to June 4, 1994.
The DPSC has a gas incentive program whereby the Company can receive a
maximum $300,000 annual reward or penalty if unaccounted-for gas volumes are
below or above 2.5% of total gas sendout volumes with a deadband of plus or
minus 0.5%. For the twelve months ended July 1993, unaccounted-for gas volumes
were within the deadband resulting in neither a reward nor a penalty. For the
twelve months ended July 1994, unaccounted-for gas volumes were 1.1% of sendout
resulting in the maximum reward amount. The reward is being collected through a
base rate charge during the twelve-month period beginning November 1994. On
March 21, 1995, the DPSC eliminated the gas incentive program with respect to
rates effective November 1995.
Maryland
The MPSC has a Generating Unit Performance Program (GUPP) which is used to
assess the overall performance of the Company's 15 major generating units. The
GUPP does not result in automatic rewards or penalties. When an overall system
performance standard is not met, the MPSC could institute an investigation into
the performance levels of those units that operated below their individual
performance standards and disallow certain fuel costs. The Company's
calculation of the 1993 and 1994 GUPP results indicated that the overall system
performance standard was met.
Resale
The Company incurred certain mine closing costs that it recovered from resale
customers through its wholesale fuel adjustment clause. The FERC staff issued
an audit report in 1994 which required that the Company recompute the cost of
fuel used in fuel adjustment clause billings to wholesale customers by
eliminating the mine closing costs beginning in 1989 and make refunds with
interest for any overbilled amounts. In accordance with the audit report, on
December 27, 1994, the Company refunded $897,000, including interest, to its
resale customers.
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. It is anticipated that the FERC will rule on the motion in the third
quarter of 1995.
I-15
OTHER REGULATORY MATTERS
Purchase of COPCO
For a discussion of the Company's purchase of COPCO, see "Competition--"Three
Legged Stool', Sales Initiatives" on page I-3 and Note 6 to the Consolidated
Financial Statements contained in the Company's 1994 Annual Report to
Stockholders filed as Exhibit 13. The Company's purchase of COPCO is contingent
on various regulatory approvals. The DPSC and MPSC approved the Company's
filings for regulatory approval on November 22, 1994, and January 18, 1995,
respectively. The Company expects the VSCC and FERC will approve the Company's
filings by mid-1995.
Transmission Rate Filing
As part of the Company's filing with the FERC for approval of the purchase of
COPCO, the Company has proposed to offer comparable transmission services.
Delaware Task Force on Regulation
In 1993, the Governor of Delaware 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 included representatives from the DPSC, utilities
(including the Company), industrial customers, government, and the public. In
June 1994, the task force issued its report to the Governor which included the
following recommendations:
(1) Replace the current five-member, part-time DPSC with three full-time
commissioners and expand the Staff in order to manage the regulatory
process more effectively, examine policy issues more thoroughly, and reduce
the use of outside consultants and attorneys.
(2) Provide the DPSC with the authority to deregulate competitive
markets, implement alternative forms of regulation, and allow economic
development rates.
(3) Pass legislation which would encourage the DPSC to resolve matters
through the use of settlements.
(4) Strengthen the role of the Office of the Public Advocate (OPA) and
provide the OPA with an in-house legal and regulatory research staff.
(5) Have the DPSC Staff, OPA, utilities, and other interested parties
submit annual progress reports to the DPSC citing any advances and cost
savings achieved and setbacks experienced toward fully implementing the
task force's recommendations.
Legislation, which the Governor supports, has been filed with the 1995
session of the General Assembly to implement items 2 and 3 above.
Natural Gas Restructuring Filing
On March 1, 1995, the Company filed an application with the DPSC to
restructure the Company's natural gas pricing and service options. Although the
Company is not requesting a change in total revenues, through the redesign of
gas rates and modification of the gas cost adjustment mechanism, revenues among
various classes of customers would be reallocated to more accurately reflect
the cost of serving those customers. The changes would result in an increase in
gas prices for residential and low volume commercial customers and a decrease
for most other commercial and industrial customers. The Company also is
proposing to unbundle and separately price several services so that eligible
customers, such as large commercial and industrial customers, can elect to use
and pay for only the services they need. A DPSC ruling is expected in 1996.
I-16
CONSTRUCTION AND FINANCING PROGRAM
Utility construction expenditures for the period 1992-1994, excluding $24
million of AFUDC, and estimated utility construction expenditures for the
period 1995-1999, excluding $36 million of AFUDC, are shown in the following
table:
CALENDAR YEAR (DOLLARS IN THOUSANDS)
-----------------------------------------------------
1997-
1992 1993 1994 1995 1996 1999
-------- -------- -------- -------- -------- --------
Electric Facilities:
Production.......... $125,800 $ 69,100 $ 54,300 $ 50,400 $ 42,300 $269,000
Transmission........ 12,200 17,300 26,400 11,600 11,700 27,600
Distribution........ 43,000 40,300 37,800 36,600 36,000 126,200
Gas Facilities........ 14,300 17,000 19,400 14,000 20,900 36,000
General Facilities.... 12,100 16,300 16,200 16,800 23,100 72,200
-------- -------- -------- -------- -------- --------
$207,400 $160,000 $154,100 $129,400 $134,000 $531,000
======== ======== ======== ======== ======== ========
Capital requirements for the period 1995-1996 are estimated to be $448
million, including $150 million for the purchase of COPCO and $263 million for
utility construction, excluding AFUDC. The Company anticipates that during the
period 1995-1996, approximately $267 million will be generated internally,
which represents 90% of estimated capital requirements, adjusted to exclude the
COPCO acquisition, and 102% of estimated utility construction expenditures.
Capital requirements for the period 1997-1999 are estimated to be $690 million,
including $531 million for utility construction, excluding AFUDC, and $86
million for the maturity of long-term debt. The Company anticipates that during
the period 1997-1999, $449 million will be generated internally, which
represents 65% of estimated capital requirements and 85% of estimated utility
construction expenditures. The forecasted internally generated funds are net of
expected power purchase commitments, including the planned purchase from PECO
associated with the COPCO acquisition. The Company plans to finance the COPCO
acquisition with approximately 50% long-term debt and 50% common stock sold
through its Dividend Reinvestment and Common Share Purchase Plan over
approximately three years. The balance of capital requirements 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, 1994, these provisions would have permitted the
Company to issue approximately $70 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, 1994
was 7.22. 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 2.38 for the twelve months ended December 31, 1994.
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.
I-17
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 1990-1994 are shown below.
YEAR ENDED DECEMBER 31,
-----------------------------
1994 1993 1992 1991 1990
----- ----- ----- ----- -----
Ratio of Earnings to Fixed Charges (SEC
Method)...................................... 3.49X 3.47X 3.03X 2.58X 2.03X
Ratio of Earnings to Fixed Charges (SEC
Method) as Adjusted (1)...................... 3.74X 3.47X 2.78X 2.58X 2.89X
Ratio of Earnings to Fixed Charges and
Preferred Dividends (SEC Method)............. 2.85X 2.88X 2.51X 2.24X 1.69X
Ratio of Earnings to Fixed Charges and
Preferred Dividends (SEC Method) as Adjusted
(1).......................................... 3.05X 2.88X 2.30X 2.24X 2.41X
- --------
(1) Adjusted ratios reflect the following pre-tax amounts: for 1994, the
exclusion of an early retirement offer charge of $17.5 million; for 1992,
the exclusion of the gain from the Company's share of a settlement reached
in the lawsuit against PECO in connection with the shutdown of Peach
Bottom of $18.5 million; and for 1990, the exclusion of the write-off of
an investment in certain non-regulated subsidiary projects of $62.5
million.
Under the SEC Methods, earnings, including AFUDC, have been computed by
adding income taxes and fixed charges to net income. Fixed charges include
gross interest expense and the estimated interest component of rentals. For
the ratio of earnings to fixed charges and preferred dividends, preferred
dividends represent annualized preferred dividend requirements multiplied by
the ratio that pre-tax income bears to net income. Net income and income taxes
related to the cumulative effect of a change in accounting for unbilled
revenues recorded in 1991 are excluded from the computation of these ratios.
For further information on the Company's financing program, see Notes 10
through 12 to the Consolidated Financial Statements and the Liquidity and
Capital Resources section of Management's Discussion and Analysis of Financial
Condition and Results of Operations in the 1994 Annual Report to Stockholders
filed as Exhibit 13.
ENVIRONMENTAL MATTERS
The Company is subject to regulation with respect to the environmental
effects of its operations, including air and water quality control, oil
pollution control, and solid and hazardous waste disposal, and limitation on
land use by various federal, regional, state, and local authorities. Permits
are required for the Company's construction projects and existing facilities.
The Company has incurred, and expects to continue to incur, 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 1995-1999
are estimated at $77 million (excluding AFUDC). These amounts have been
included in the Company's estimates of utility construction expenditures under
"Construction and Financing Program" on page I-17.
Clean Air Act
The Clean Air Act requires utilities and other industries to reduce
significantly emissions of air pollutants such as sulfur dioxide (SO/2/) and
oxides of nitrogen (NOx). Title IV of the Clean Air Act, the acid rain
provisions, establish a two-phase program under which certain utility units
must reduce SO/2/ and NOx emissions in 1995 (Phase I) and other utility units
must reduce SO/2/ and NOx emissions beginning in the year 2000 (Phase II).
Emission reductions at the jointly-owned Conemaugh Power Plant, the only units
I-18
required to comply with Title IV in 1995, will be achieved through installation
and operation of flue gas desulfurization (FGD) systems. The remainder of the
Company's wholly- and jointly-owned fossil fuel fired units are expected to
meet Phase II emission limits through a combination of fuel switching, FGD,
repowering, environmental dispatch and SO/2/ allowance trading.
In addition to complying with Title IV federal requirements, as major sources
of NOx emissions, Company facilities must comply with Clean Air Act Title I
ozone nonattainment provisions designed to attain the National Ambient Air
Quality Standard for Ozone. Title I requires states to promulgate Reasonably
Available Control Technology (RACT) regulations for existing sources located
within ozone nonattainment areas or within the Northeast Ozone Transport Region
(NOTR). Company facilities in Delaware and Maryland must comply with RACT
requirements because they are in the NOTR. The Company proposes to comply with
the NOx RACT requirements by undertaking certain operating changes and the
installation of low NOx burner technology. The Company's Delaware and Maryland
RACT proposals have not yet been approved by the EPA as part of each State's
respective State Implementation Plan. Consequently, it is possible that
additional costs may be incurred at these facilities to further control NOx as
part of the RACT effort.
"Post-RACT" NOx emission reductions may also be imposed on Company facilities
as a result of a Memorandum of Understanding (MOU) signed by a majority of
members of the Ozone Transport Commission. The MOU would require sources to
meet certain emission limitations or to reduce NOx emissions up to 65% below
1990 levels by 1999. Under the MOU, states would be required to impose even
further NOx reductions by 2003 if necessary. While the provisions of the MOU
have not been implemented by regulations in Delaware or Maryland, the Company
will likely be required to install post-combustion NOx control equipment on
some or all of the Company's major generating units. At this time, the Company
cannot determine the potential operating impacts and anticipated costs
associated with this "post-RACT" initiative.
To help attain air quality standards, the Clean Air Act mandates that the
emission of certain air pollutants by new sources or increased emissions from
existing facilities be offset by reductions in similar emissions from existing
sources. Such requirements may affect the Company's ability to locate,
construct, and expand generating facilities in the future.
The Company anticipates that the costs of complying with the Clean Air Act
will be recoverable from its customers.
Salem Operating Permit
On July 20, 1994, the New Jersey Department of Environmental Protection and
Energy (NJDEPE) issued a final five-year permit, effective September 1, 1994,
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 final permit does not require PSE&G to
construct closed-cycle cooling towers, which were originally proposed under a
1990 NJDEPE draft permit and which PSE&G believes are unnecessary. PSE&G has
informed the Company that the NJDEPE has granted the requests of certain
parties, including the State of Delaware, for hearings with the NJDEPE
challenging the final permit, which are pending before the New Jersey Office of
Administrative Law. The EPA, which has authority to review the final permit
issued by the NJDEPE, has completed its review and has not raised any
objections. PSE&G is implementing the permit. Additional permits from various
agencies are required to be obtained to implement the permit. No assurances can
be given as to the receipt of any such additional permits. The estimated
capital cost of compliance with the final permit is approximately $100 million,
of which the Company's share is 7.41%.
Water Quality Regulations
DNREC and the Maryland Department of the Environment (MDE) have promulgated
major changes to water quality regulations which emphasize increased control of
toxic pollutants and signal a shift away
I-19
from technology-based standards. In addition, DNREC has proposed increased
restrictions on thermal discharge limits. 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 1995. 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 cost up to $47 million.
Hazardous Substances
The disposal of Company-generated hazardous substances can result in costs to
clean up facilities found to be contaminated due to past disposal practices.
Federal and State statutes authorize governmental agencies to compel
responsible parties to 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 waste disposal contractor
screening and audit process.
The Company is a potentially responsible party (PRP) at a federal Superfund
site in Philadelphia, Pennsylvania (the Metal Bank/Cottman Avenue site), a
member of a de minimis PRP group at a federal Superfund site in Jamestown,
North Carolina (the Seaboard Chemical site), and alleged to be a third-party
contributor at two other federal Superfund sites (the Bridgeport Rental and Oil
Services site in Logan Township, New Jersey and the Berks Associates site in
Douglassville, Pennsylvania). Because the Company's imputed share of the
potential liabilities at these sites is small, the Company does not expect its
share of cleanup costs at these sites, either separately or cumulatively, to be
material.
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 and are
discussed below. Also, the Company's former coal gasification site in Cambridge
has been placed on Maryland's list of state superfund sites by the MDE. While
the MDE has not acted on the Cambridge site to date, the EPA recommended the
site for "no further action" in 1990.
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. In 1992, DNREC
advised the Company that additional sampling was required so that an updated
risk assessment could be completed. The Facility Evaluation and risk assessment
were completed in August 1994 and submitted to DNREC for review. Once DNREC
finishes their review of the report and risk assessment, the Company may be
required to incur costs for cleanup.
The Company's New Castle coal gasification site represents a 3-acre portion
within a 41-acre marsh currently being investigated by DNREC. Sediment sample
results indicate that low levels of contaminates were found throughout the
marsh. These contaminates could have originated from a number of sources within
the marsh area or from surface runoff from adjacent roadways. Once DNREC
completes the Facility Evaluation report, the Company may be required to incur
certain costs for further investigation.
In 1994, the Company accrued a liability of $2 million representing its
estimate of site study and cleanup costs for all of the above Federal and State
Superfund sites.
I-20
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. As part of President Clinton's
climate challenge action plan introduced in October 1993, a climate challenge
program was developed. Under this program, the DOE and electric utilities will
explore and promote ways in which electric utilities can voluntarily reduce,
limit, avoid or offset emissions of carbon dioxide and other greenhouse gases.
The Company agreed to participate in this program. Should mandatory emissions
limitations or a "carbon tax" be imposed, the Company's operations could be
affected. The Company cannot predict the outcome of this issue.
Subsidiaries
Certain of the Company's subsidiaries are also subject to regulations with
respect to the environmental effects of their operations, including air and
water quality control, solid waste disposal, and limitation on land use by
various federal, regional, state, and local authorities. One of the Company's
indirect subsidiaries, Pine Grove Landfill, Inc. (Pine Grove), which owns and
operates a solid waste disposal facility in Pennsylvania, entered into a
Consent Order and Agreement, dated March 3, 1995, with the Pennsylvania
Department of Environmental Resources (PADER) which addresses alleged past
violations of State solid waste management and air quality regulations due to
odors emanating from its waste disposal facility. The terms of the Consent
Order and Agreement provide for the payment by Pine Grove of a $22,000 civil
penalty and the costs of certain environmental services and facility
enhancements. Pine Grove's management believes it has corrected the odor
problem at the disposal facility. Pine Grove's management cannot predict the
nature of any actions which PADER may take in the event of future odor
emissions under authority PADER possesses to impose fines upon, close, limit
expansion of, or order changes in the business practices at, the disposal
facility. The Company believes that its other subsidiaries are in substantial
compliance with all environmental regulations.
RETAIL FRANCHISES
The franchises discussed below could be impacted by legislation promoting the
retail wheeling of electricity. For a further discussion on the development of
competition in retail markets, see "Strategic Plans for Competition--Electric
Business Overview," on page I-1.
The Company holds franchises, which for the most part are perpetual, for the
rendition of retail electric and gas service in certain designated areas and
municipalities in the State of Delaware, pursuant to legislative enactments of
the General Assembly and to consents, orders, and permits from various public
bodies and municipal authorities.
The Company holds franchises, which for the most part are perpetual, for the
rendition of retail electric service in all of its assigned territories in the
State of Maryland, pursuant to Maryland law and appropriate orders of the MPSC.
I-21
The Company holds perpetual franchises for the rendition of retail electric
service in certain designated areas of the Commonwealth of Virginia, pursuant
to appropriate orders of the VSCC under the Virginia Public Utility Facilities
Act. It also has franchises for the rendition of retail electric service within
other municipalities which are not perpetual, but which are expected to be
renewed at their expiration dates.
In Pennsylvania, the Company holds certificates of public convenience from
the Pennsylvania Public Utility Commission to own and exercise rights with
respect to its interests in certain electric generating stations and
transmission lines located in the State.
NUMBER OF EMPLOYEES
The number of full time employees of the Company at January 1, 1995, was
2,487.
A total of 1,435 employees are represented by the International Brotherhood
of Electrical Workers Locals 1238 (Northern) and 1307 (Southern) whose
contracts with the Company expire on December 15, 1996 and June 25, 1995,
respectively.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, and positions of all of the executive officers of the
Company as of January 1, 1995 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 JANUARY 1, 1995)
BUSINESS EXPERIENCE
NAME, AGE AND POSITION DURING PAST 5 YEARS
---------------------- -------------------
Howard E. Cosgrove, 51........ Elected 1992. President and Chief Operating
Chairman of the Board, Officer from 1991 to 1992; Executive Vice
President, and Chief President from 1985 to 1991.
Executive Officer and
Director
H. Ray Landon, 59............. Elected 1988.
Executive Vice President and
Director
Ralph E. Klesius, 52.......... Elected 1992. Vice President, Engineering from
Senior Vice President and 1988 to 1992.
Environmental Compliance
Officer
Thomas S. Shaw, 47............ Elected 1992. Vice President/President, Delmarva
Senior Vice Capital Investments, Inc. from 1991 to 1992;
President/President, Delmarva Vice President, Gas Division from 1990 to 1991;
Capital Investments, Inc. Vice President, Production from 1984 to 1990.
Barbara S. Graham, 46......... Elected 1995. Vice President and Chief Financial
Senior Vice President, Officer from 1992 to 1994. Treasurer from 1987
Treasurer, and Chief to 1992.
Financial Officer
Donald E. Cain, 49............ Elected 1988.
Vice President,
Administration
Paul S. Gerritsen, 49......... Elected 1993. Vice President and Chief Financial
Vice President Officer from 1987 to 1992.
Wayne A. Lyons, 55............ Elected 1990. Vice President from 1985 to 1990.
Vice President, Division
Operations
(Continued)
I-22
BUSINESS EXPERIENCE
NAME, AGE AND POSITION DURING PAST 5 YEARS
---------------------- -------------------
Frank J. Perry, 51............. Elected 1990. Vice President, Gas Division from
Vice President, Production 1986 to 1990.
Jack Urban, 51................. Elected 1991. General Manager, Production
Vice President, Gas Division Services from 1990 to 1991; General Manager,
Fuel Supply from 1984 to 1990.
James P. Lavin, 47............. Elected 1993. Comptroller-Corporate and Chief
Comptroller and Chief Accounting Officer from 1989 to 1993.
Accounting Officer
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, 1994.
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
CYCLE
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
(Continued)
I-23
NET INSTALLED
SUMMER
GENERATING
CAPACITY
STATION LOCATION (KILOWATTS)
------- -------- -------------
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.
Major transmission and distribution lines owned and in service are as
follows:
VOLTAGE CIRCUIT MILES
------- -------------
Transmission:
500 kV..................................................... 16
230 kV..................................................... 247
138 kV..................................................... 450
69 kV..................................................... 715
Distribution:
34 kV..................................................... 95
25 kV and below........................................... 8,042
The Company's electric transmission and distribution system includes 1,362
transmission poleline miles of overhead lines, 5 transmission cable miles of
underground cables, 6,375 distribution poleline miles of overhead lines, and
5,073 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 maximum planned daily
sendout capacity of 25,000 Mcf per day.
The Company also owns four natural gas city gate stations at various
locations in its gas service territory. These stations have a total sendout
capacity of 125,000 Mcf per day.
The following table sets forth the Company's gas pipeline miles:
Transmission Mains............................................... 110*
Distribution Mains............................................... 1,362
Service Lines.................................................... 1,039
--------
* 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 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-24
other affected parties in filing a complaint in July 1993 in the Delaware
Chancery Court. The Chancery Court complaint alleged procedural violations of
the Freedom of Information Act by the Board in the passage of the Regulations
and requested that the Regulations be declared null and void. The proceedings
in the Superior Court were suspended pending the outcome of the Chancery Court
case. On May 19, 1994, the Chancery Court found for the Company and the other
plaintiffs by declaring the Regulations null and void on procedural grounds.
The proceedings in the Superior Court will remain open pending the issuance of
new regulations by the Board.
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 asked for a refund and damages totalling $9.3 million. On
October 20, 1994, Star and the Company signed a settlement agreement resolving
Star's claims. The settlement does not have a material effect on the Company's
financial position or results of operations.
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-25
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 1994 and 1993.
1994 1993
------------------------ ----------------------
PRICE PRICE
DIVIDEND --------------- DIVIDEND -------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ------- ------- -------- ------ ------
First Quarter................... $.38 1/2 $23 5/8 $20 1/2 $.38 1/2 $24 22 1/8
Second Quarter.................. .38 1/2 21 16 7/8 .38 1/2 24 1/8 21 1/2
Third Quarter................... .38 1/2 20 17 3/4 .38 1/2 25 7/8 23 1/8
Fourth Quarter.................. .38 1/2 19 1/4 17 5/8 .38 1/2 25 5/8 21 1/4
The Company had 58,073 registered holders of common stock as of December 31,
1994.
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 1994 Annual Report to
Stockholders, incorporated by reference herein.
ITEM 6. SELECTED FINANCIAL DATA
This information is contained on page 20 of the 1994 Annual Report to
Stockholders filed herein as Exhibit 13, which portion of such Annual Report is
hereby incorporated by reference herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This information is contained on pages 21 through 29 of the 1994 Annual
Report to Stockholders filed herein as Exhibit 13, which portion of such Annual
Report is hereby incorporated by reference herein.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements, notes 1 through 21 to consolidated
financial statements, and related report thereon of Coopers & Lybrand L.L.P.,
independent accountants, appear on pages 30 through 49 of the 1994 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
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 20, 1995, 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 20,
1995.
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 20, 1995.
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 1994 Annual Report to Stockholders filed as Exhibit 13
hereto and incorporated herein by reference.
1994
ANNUAL REPORT
FINANCIAL STATEMENT (PAGE)
------------------- -------------
Consolidated Statements of Income for the three years ended
December 31, 1994............................................ 31
Consolidated Balance Sheets as of December 31, 1994 and 1993.. 32 and 33
Consolidated Statements of Cash Flows for the three years
ended December 31, 1994...................................... 34
Consolidated Statements of Capitalization as of December 31,
1994 and 1993................................................ 35
Consolidated Statements of Changes in Common Stockholders' Eq-
uity for the three years ended December 31, 1994............. 36
Notes to Consolidated Financial Statements.................... 37 to 49
2. Financial Statement Schedules--Pursuant to SEC Financial Reporting
Release No. 44, the Company has omitted previously required financial
statement schedules from this report.
3. Schedule of Operating Statistics for the three years ended December
31, 1994 can be found on page IV-3 of this report.
4. Exhibits
EXHIBIT
NUMBER
-------
2 Stock Purchase Agreement between PECO Energy Company and Delmarva
Power & Light Company related to the acquisition of Conowingo Power
Company.
3-A Copy of the Restated Certificate and Articles of Incorporation
effective as of April 12, 1990. (Filed with Registration Statement
No. 33-50453.)
3-B Copy of the Company's Certificate of Designation and Articles of
Amendment establishing the 7 3/4% Preferred Stock--$25 Par. (Filed
with Registration Statement No. 33-50453.)
3-C Copy of the Company's Certificate of Designation and Articles of
Amendment establishing the 6 3/4% Preferred Stock. (Filed with
Registration Statement No. 33-53855.)
3-D Copy of the Company's By-Laws as amended September 30, 1993. (Filed
with Form 10-K for the year ended December 31, 1993, File No. 1-
1405.)
4-A Copy of the Mortgage and Deed of Trust of Delaware Power & Light
Company to the New York Trust Company, Trustee, (Chemical Bank,
successor Trustee) dated as of October 1, 1943 and copies of the
First through Sixty-Eighth Supplemental Indentures thereto. (Filed
with Registration Statement No. 33-1763.)
4-B Copy of the Sixty-Ninth Supplemental Indenture. (Filed with
Registration Statement No. 33-39756.)
4-C Copies of the Seventieth through Seventy-Fourth Supplemental
Indentures. (Filed with Registration Statement No. 33-24955.)
4-D Copies of the Seventy-Fifth through the Seventy-Seventh Supplemental
Indentures. (Filed with Registration Statement No. 33-39756.)
4-E Copies of the Seventy-Eighth and Seventy-Ninth Supplemental
Indentures. (Filed with Registration Statement No. 33-46892.)
IV-1
EXHIBIT
NUMBER
-------
4-F Copy of the Eightieth Supplemental Indenture. (Filed with
Registration Statement No. 33-49750.)
4-G Copy of the Eighty-First Supplemental Indenture. (Filed with
Registration Statement No. 33-57652.)
4-H Copy of the Eighty-Second Supplemental Indenture. (Filed with
Registration Statement No. 33-63582.)
4-I Copy of the Eighty-Third Supplemental Indenture. (Filed with
Registration Statement No. 33-50453.)
4-J Copies of the Eighty-Fourth through Eighty-Eighth Supplemental
Indentures. (Filed with Registration Statement No. 33-53855.)
10-A Copy of the Management Incentive Compensation Plan amended and
restated as of January 1, 1992. (Filed with Form 10-K for the year
ended December 31, 1991, File No. 1-1405.)
10-B Copy of an amendment to the Management Incentive Compensation Plan
adopted by the Board of Directors on January 28, 1993, effective as
of January 1, 1993. (Filed with Form 10-K for the year ended
December 31, 1992, File No. 1-1405.)
10-C Copy of the Supplemental Executive Retirement Plan, revised as of
October 29, 1991. (Filed with Form 10-K for the year ended December
31, 1992, File No. 1-1405.)
10-D Copies of amendments to the Supplemental Executive Retirement Plan,
effective June 15, 1994, and November 1, 1994.
10-E Copy of the Long Term Incentive Plan amended and restated as of
January 1, 1992. (Filed with Form 10-K for the year ended December
31, 1991, File No. 1-1405.)
10-F Copy of an amendment to the Long Term Incentive Plan adopted by the
Board of Directors on January 28, 1993, effective as of January 1,
1993. (Filed with Form 10-K for the year ended December 31, 1992,
File No. 1-1405.)
10-G Copy of the severance agreement with members of management.
10-H Copy of the current listing of members of management who have signed
the severance agreement.
10-I Copy of the Management Life Insurance Plan amended and restated as
of January 1, 1992. (Filed with Form 10-K for the year ended
December 31, 1991, File No. 1-1405.)
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 1994 Annual Report to Stockholders which are
incorporated by reference in this Form 10-K.
23 Consent of Independent Accountants.
27 Financial Data Schedule.
(b) Reports on Form 8-K (filed during the reporting period):
A Report on Form 8-K dated October 17, 1994, containing a press release
announcing the results of the early retirement offer, was filed with the
Commission.
IV-2
DELMARVA POWER & LIGHT COMPANY
OPERATING STATISTICS
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
The table below sets forth selected financial and operating statistics for
the electric and gas divisions for the three years ended December 31, 1994.
1994 1993 1992
---------- ---------- ----------
ELECTRIC:
Electricity generated and purchased (MWh):
Generated................................ 11,581,929 11,264,540 8,548,233
Purchased................................ 3,766,169 3,857,133 4,579,521
Interchange deliveries................... (2,220,898) (2,225,384) (998,679)
---------- ---------- ----------
Total output for load................... 13,127,200 12,896,289 12,129,075
========== ========== ==========
Electric sales (MWh):
Residential.............................. 3,578,743 3,499,387 3,228,237
Commercial............................... 3,461,058 3,336,847 3,140,149
Industrial............................... 3,248,131 3,232,233 3,115,677
Resale................................... 2,166,154 2,131,920 1,987,393
Other sales (1).......................... 50,996 79,843 49,355
---------- ---------- ----------
Total sales............................. 12,505,082 12,280,230 11,520,811
Losses and miscellaneous system uses...... 622,118 616,059 608,264
---------- ---------- ----------
Total disposition of energy.............. 13,127,200 12,896,289 12,129,075
========== ========== ==========
Operating revenue (thousands):
Residential.............................. $312,224 $305,446 $273,463
Commercial............................... 242,506 237,785 220,659
Industrial............................... 145,594 150,178 144,094
Resale................................... 105,350 104,983 96,491
Other sales revenues (2)................. 6,816 9,716 7,142
Interchange deliveries................... 62,388 61,437 30,606
Miscellaneous revenues................... 8,237 6,118 7,720
---------- ---------- ----------
Total revenues.......................... $883,115 $875,663 $780,175
========== ========== ==========
Number of customers (end of period):
Residential.............................. 347,997 342,710 336,076
Commercial............................... 44,060 43,324 42,427
Industrial............................... 699 715 726
Resale................................... 12 12 12
Other.................................... 604 593 578
---------- ---------- ----------
Total customers......................... 393,372 387,354 379,819
========== ========== ==========
Average annual use per residential cus-
tomer (kWh)(3)........................... 10,359 10,336 9,680
Average annual revenue per residential
customer (3)............................. $903.74 $902.14 $820.02
Average revenue per kWh (cents):
Residential.............................. 8.7 8.7 8.5
Commercial............................... 7.0 7.1 7.0
Industrial............................... 4.5 4.7 4.6
GAS:
Gas sales (Mcf)........................... 18,087 18,066 17,013
Gas transported (Mcf)..................... 2,255 1,539 3,155
Gas revenue (thousands)................... $107,906 $94,944 $83,869
Number of customers (end of period):
Residential.............................. 88,518 86,027 82,996
Commercial............................... 6,982 6,751 6,500
Industrial............................... 150 150 152
Interruptible and other.................. 12 12 11
---------- ---------- ----------
Total customers......................... 95,662 92,940 89,659
========== ========== ==========
Residential gas service:
Average annual use per customer (Mcf)(3). 88.55 86.85 88.71
Average annual revenue per customer (3).. $632.11 $558.59 $526.94
Average revenue per Mcf.................. $7.14 $6.43 $5.94
- --------
(1)Includes unbilled sales.
(2)Includes unbilled revenues.
(3)Based on average number of customers during period.
IV-3
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Delmarva Power & Light Company
(Registrant)
Dated: March 23, 1995
By /s/ Barbara S. Graham
----------------------------------
(Barbara S. Graham, Senior Vice
President, Treasurer, 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 23, 1995
..................................... President, Chief
(Howard E. Cosgrove) Executive Officer,
and Director
/s/ (H. Ray Landon) Executive Vice March 23, 1995
..................................... President and
(H. Ray Landon) Director
/s/ (Barbara S. Graham) Senior Vice President, March 23, 1995
..................................... Treasurer, and Chief
(Barbara S. Graham) Financial Officer
/s/ (James P. Lavin) Comptroller and Chief March 23, 1995
..................................... Accounting Officer
(James P. Lavin)
/s/ (Michael G. Abercrombie) Director March 23, 1995
.....................................
(Michael G. Abercrombie)
/s/ (Robert D. Burris) Director March 23, 1995
.....................................
(Robert D. Burris)
/s/ (Audrey K. Doberstein) Director March 23, 1995
.....................................
(Audrey K. Doberstein)
/s/ (Michael B. Emery) Director March 23, 1995
.....................................
(Michael B. Emery)
Director
.....................................
(James H. Gilliam, Jr.)
/s/ (Sarah I. Gore) Director March 23, 1995
.....................................
(Sarah I. Gore)
/s/ (James C. Johnson) Director March 23, 1995
.....................................
(James C. Johnson)
/s/ (James T. McKinstry) Director March 23, 1995
.....................................
(James T. McKinstry)
IV-4
DELMARVA POWER & LIGHT COMPANY
1994 ANNUAL REPORT ON FORM 10-K
EXHIBIT INDEX
Exhibit Page
Number Description Number
- ------ ----------- ------
2 Stock Purchase Agreement between PECO
Energy Company and Delmarva Power & Light
Company related to the acquisition of
Conowingo Power Company.
10-D Copies of Amendments to the Supplemental
Executive Retirement Plan, effective
June 15, 1994, and November 1, 1994.
10-G Copy of the severance agreement with
members of management.
10-H 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 1994 Annual Report
to Stockholders which are incorporated by
reference in this Form 10-K.
23 Consent of Independent Accountants.
27 Financial Data Schedule.