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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
OR
( ) 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 1-1401
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PECO ENERGY COMPANY
(formerly known as Philadelphia Electric Company)
(Exact name of registrant as specified in its charter)
Pennsylvania
(State or other jurisdiction of incorporation or organization)
P.O. Box 8699
2301 Market Street, Philadelphia, PA
(Address of principal executive offices)
23-0970240
(I.R.S. Employer Identification No.)
19101
(Zip Code)
(215) 841-4000
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
PECO Energy Company (Securities below are registered on the New York and
Philadelphia Stock Exchanges)
First and Refunding Mortgage Bonds:
4-1/2% Series due 1994 7-1/2% Series due 1999 7-1/8% Series due 2023
8-3/4% Series due 1994 5-5/8% Series due 2001 7-3/4% Series 2 due 2023
6-1/8% Series due 1997 6-1/2% Series due 2003 7-1/4% Series due 2024
5-3/8% Series due 1998 6-3/8% Series due 2005
Cumulative Preferred Stock - without par value:
$9.875 Series $7.75 Series $4.30 Series
$7.96 Series $7.00 Series $3.80 Series
$7.85 Series $4.68 Series
$7.80 Series $4.40 Series
Common Stock - without par value
PECO Energy Power Company (a wholly owned subsidiary) Debentures 4-1/2%
Series due 1995 (Registered on the Philadelphia Stock Exchange)
Securities registered pursuant to Section 12(g) of the Act:
PECO Energy Company
Cumulative Preferred Stock - without par value:
$7.48 Series $6.12 Series
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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 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 registrant's common stock (only
voting stock) held by non-affiliates of the registrant was $6,393,737,314
at January 31, 1994.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock as of the latest practicable date.
Common Stock - without par value: 221,520,099 shares outstanding at
January 31, 1994.
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DOCUMENTS INCORPORATED BY REFERENCE (In Part)
Annual Report of PECO Energy Company to Shareholders for the year 1993
is incorporated in part in Parts I, II and IV hereof, as specified herein.
Proxy Statement of PECO Energy Company in connection with its 1994 Annual
Meeting of Shareholders is incorporated in part in Part III hereof, as
specified herein.
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TABLE OF CONTENTS
Page
No.
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PART I
ITEM 1. BUSINESS.................................................... 1
The Company................................................. 1
Electric Operations......................................... 1
General................................................... 1
Limerick Generating Station............................... 4
Peach Bottom Atomic Power Station ........................ 6
Salem Generating Station ................................. 7
Fuel ....................................................... 7
Nuclear .................................................. 8
Coal...................................................... 10
Oil....................................................... 10
Natural Gas .............................................. 10
Gas Operations.............................................. 11
Segment Information......................................... 11
Rate Matters................................................ 12
Construction................................................ 14
Capital Requirements and Financing Activities............... 15
Employee Matters............................................ 17
Environmental Regulations................................... 17
Water .................................................... 17
Air....................................................... 18
Solid and Hazardous Waste................................. 19
Costs .................................................... 21
Competition................................................. 22
Executive Officers of the Registrant ....................... 23
ITEM 2. PROPERTIES.................................................. 25
ITEM 3. LEGAL PROCEEDINGS........................................... 27
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ........ 28
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS....................................... 28
ITEM 6. SELECTED FINANCIAL DATA .................................... 28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS ...................... 28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 28
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE ...................... 28
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 29
ITEM 11. EXECUTIVE COMPENSATION...................................... 29
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT ............................................... 29
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............. 29
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K ................................................. 30
Financial Statements and Financial Statement Schedules...... 30
REPORT OF INDEPENDENT ACCOUNTANTS........................... 31
SCHEDULE V - UTILITY PLANT.................................. 32
SCHEDULE VI - ACCUMULATED DEPRECIATION OF UTILITY PLANT .... 35
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS........... 38
Exhibits.................................................... 39
Reports on Form 8-K......................................... 42
SIGNATURES
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PART I
ITEM 1. BUSINESS
The Company
PECO Energy Company (Company), formerly known as Philadelphia Electric
Company, incorporated in Pennsylvania in 1929, is an operating utility
which provides electric and gas service to the public in southeastern
Pennsylvania. Two subsidiaries own, and a third subsidiary operates, the
Conowingo Hydro-Electric Project (Conowingo Project), and one distribution
subsidiary provides electric service to the public in certain areas of
northeastern Maryland adjacent to the Conowingo Project.
The total area served by the Company and its subsidiaries covers 2,475
square miles. Electric service is supplied in an area of 2,340 square
miles with a population of about 3,700,000, including 1,600,000 in the
City of Philadelphia. Approximately 95% of the electric service area and
64% of retail kilowatthour (kWh) sales are in the suburbs around
Philadelphia and in northeastern Maryland, and 5% of the service area and
36% of such sales are in the City of Philadelphia. In 1993, approximately
60% of the Company's electric output was generated from nuclear sources.
The Company estimates for 1994 that 59% of its electric output will be
generated from nuclear sources (see "Fuel"). Natural gas service is
supplied in a 1,475-square-mile area of southeastern Pennsylvania adjacent
to Philadelphia with a population of 1,900,000. The Company and its
subsidiaries hold franchises to the extent necessary to operate in the
areas served.
The Company is subject to regulation by the Pennsylvania Public
Utility Commission (PUC) as to rates, issuances of securities and certain
other aspects of the Company's operations and by the Federal Energy
Regulatory Commission (FERC) as to wholesale and interstate electric rates
and as to licensing jurisdiction over the Company's Muddy Run Pumped
Storage Project. Specific operations of the Company are also subject to
the jurisdiction of various other federal, state, regional and local
agencies, including the United States Nuclear Regulatory Commission (NRC),
the United States Environmental Protection Agency (EPA), the United States
Department of Energy (DOE), the Delaware River Basin Commission and the
Pennsylvania Department of Environmental Resources (PDER). The Company's
utility subsidiaries are subject to similar regulation, including the
licensing jurisdiction of the FERC over the Conowingo Project. Due to its
ownership of subsidiary-company stock, the Company is a holding company as
defined by the Public Utility Holding Company Act of 1935 (1935 Act);
however, it is predominantly an operating company and, by filing an
exemption statement annually, is exempt from all provisions of the 1935
Act, except Section 9(a)(2) relating to the acquisition of securities of a
public utility company.
Electric Operations
General
During 1993, 90.4% of the Company's operating revenues and 94.3% of
its operating income were from electric operations. Electric sales and
operating revenues for 1993 by classes of customers are set forth below:
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Operating
Sales Revenues
(millions of kWh) (millions of $)
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Residential................... 10,657 $1,354.1
Small commercial and
industrial.................. 5,773 678.9
Large commercial and
industrial.................. 15,935 1,164.0
Other......................... 771 161.2
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Service territory........... 33,136 3,358.2
Interchange sales ............ 457 14.3
Sales to other utilities...... 8,670 232.9
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Total....................... 42,263 $3,605.4
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In 1993, 97.7% of the Company's service territory operating revenues
were from Company sales in Pennsylvania and 2.3% were from sales by the
Company's wholly owned subsidiary Conowingo Power Company (COPCO) in
Maryland. On February 15, 1994, the Company announced that it is
evaluating strategic alternatives with respect to COPCO, including the
possible sale of COPCO to other companies. The Company has made no
determination at this time to sell COPCO and may, in fact, retain
ownership of COPCO. See "Rate Matters."
For 1993, sales to other utilities consisted of negotiated agreements
to sell 799 megawatts (MW) of near-term excess capacity and/or associated
energy. See "Rate Matters." All of these agreements are either for
ongoing, short-duration purchases of energy only or expire during 1994.
The Company expects to renew these agreements or negotiate new agreements
in 1994.
The net installed electric generating capacity (summer rating) of the
Company and its subsidiaries at December 31, 1993 was as follows:
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Type of Capacity Megawatts % of Total
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Nuclear................................. 3,938 44.4%
Mine-mouth, coal-fired.................. 709 8.0
Service-area, coal-fired................ 690 7.8
Oil-fired............................... 1,176 13.2
Gas-fired............................... 201 2.3
Hydro (includes pumped storage)......... 1,350 15.2
Internal combustion..................... 813 9.1
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Total............................... 8,877(1)(2) 100.0%
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(1) Includes capacity sold to other utilities.
(2) See "Fuel" for sources of fuels used in electric generation.
The maximum hourly demand on the Company's system was 7,100 MW which
occurred on July 8, 1993. The Company estimates its generating reserve
margin for 1994 to be 28%. This is based on the most recent annual
peak-load forecast, which assumes normal peak weather conditions and the
sale to other utilities of 400 MW of capacity not included in rate base.
The Company is a member of the Pennsylvania-New Jersey-Maryland
Interconnection (PJM), which fully integrates, on the basis of relative
cost of generation, the bulk-power generating and transmission operations
of eleven investor-owned electric utilities serving more than 22 million
people in a 50,000-square-mile territory. In addition, PJM companies
coordinate planning and install facilities to obtain the greatest
practicable degree of reliability, compatible economy, and other
advantages from the pooling of their respective electric system loads,
transmission facilities and generating capacity. PJM uses the
split-savings method in pricing and accounting to provide an economic
method of energy interchange among its members. Under this arrangement,
PJM energy is exchanged among PJM member utilities at a price which
represents the average of the producer's cost of generating the
electricity dispatched and the buyer's replacement cost, or the cost
avoided by making the purchase.
The maximum PJM demand of 46,429 MW occurred on July 8, 1993 when
PJM's installed capacity (summer rating) was 55,440 MW. The Company's
installed capacity for 1994-97 is expected to be sufficient to supply its
PJM reserve margin share during that period.
The Company has made arrangements for the purchase of other companies'
power during 1994. The source of the amount reserved each week depends on
the availability of excess coal-fired capacity, PJM's import capability
from these companies and the Company's economic need for additional power.
The Company's nuclear energy is generated by Limerick Generating
Station (Limerick) Units No. 1 and No. 2 and Peach Bottom Atomic Power
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Station (Peach Bottom) Units No. 2 and No. 3, which are operated by the
Company, and by Salem Generating Station (Salem) Units No. 1 and No. 2,
which are operated by Public Service Electric and Gas Company (PSE&G). The
Company owns 100% of Limerick, 42.49% of Peach Bottom and 42.59% of Salem.
Limerick Units No. 1 and No. 2 each has a capacity of 1,055 MW; Peach
Bottom Unit No. 2 has a capacity of 1,051 MW, of which the Company is
entitled to 447 MW; Peach Bottom Unit No. 3 has a capacity of 1,035 MW, of
which the Company is entitled to 439 MW; and Salem Units No. 1 and No. 2
each has a capacity of 1,106 MW, of which the Company is entitled to 471
MW of each unit.
The Price-Anderson Act, as amended (Price-Anderson Act), sets the
limit of liability of approximately $9.4 billion for claims that could
arise from an incident involving any licensed nuclear facility in the
nation. The limit is subject to increase to reflect the effects of
inflation and changes in the number of licensed reactors. All utilities
with nuclear generating units, including the Company, have obtained
coverage for these potential claims through a combination of private
insurances of $200 million and mandatory participation in a financial
protection pool. Under the Price-Anderson Act, all nuclear reactor
licensees can be assessed up to $76 million per reactor per incident,
payable at no more than $10 million per reactor per incident per year.
This assessment is subject to inflation, state premium taxes and an
additional surcharge of 5% if the total amount of claims and legal costs
exceeds the basic assessment. If the damages from an incident at a
licensed nuclear facility exceed $9.4 billion, the President of the United
States is to submit to Congress a plan for providing additional
compensation to the injured parties. Congress could impose further
revenue-raising measures on the nuclear industry to pay claims. The
Price-Anderson Act and the extensive regulation of nuclear safety by the
NRC do not preempt claims under state law for personal, property or
punitive damages related to radiation hazards.
Although the NRC requires the maintenance of property insurance on
nuclear power plants in the amount of $1.06 billion or the amount
available from private sources, whichever is less, the Company maintains
coverage in the amount of its $2.75 billion proportionate share for each
station. The Company's insurance policies provide coverage for
decontamination liability expense, premature decommissioning, and loss or
damage to its nuclear facilities. These policies require that insurance
proceeds first be applied to assure that the facility, following
an accident, is in a safe and stable condition and can be maintained in
such condition. Within 30 days of stablizing the reactor, the licensee
must submit a report to the NRC which provides a clean-up plan including
the identification of all clean-up operations necessary to decontaminate
the reactor to either permit the resumption of operations or
decommissioning of the facility. Under the Company's insurance policies,
proceeds not already expended to place the reactor in a stable condition
must be used to decontaminate the facility. If the decision is made to
decommission the facility, a portion of the insurance proceeds must be
allocated to a fund which the Company is required by the NRC to maintain
to provide funds for decommissioning the facility. These proceeds would be
paid to the fund to make up any difference between the amount of money in
the fund at the time of the early decommissioning and the amount that
would be in the fund if contributions had been made over the normal life
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of the facility. The Company is unable to predict what effect these
requirements may have on when insurance proceeds would be made available
to the Company for the Company's bondholders and the amount of such
proceeds which would be available. Under the terms of the various
insurance agreements, the Company could be assessed up to $35 million for
losses incurred at any plant insured by the insurance companies. The
Company is self-insured to the extent that any losses may exceed the
amount of insurance maintained. Any such losses, if not recovered through
the ratemaking process, could have a material adverse effect on the
Company's financial condition.
The Company is a member of an industry mutual insurance company which
provides replacement power cost insurance in the event of a major
accidental outage at a nuclear station. The policy contains a twenty-one
week waiting period before recovery of costs can commence. The premium for
this coverage is subject to an assessment for adverse loss experience. The
Company's maximum share of any assessment is $17 million per year.
NRC regulations require that licensees of nuclear generating
facilities must demonstrate that funds will be available in certain
minimum amounts, established by a formula provided in the regulations, at
the end of the life of the facility to decommission the facility. The PUC,
based on estimates of decommissioning costs for each of the nuclear
facilities in which the Company has an ownership interest, permits the
Company to collect from its customers and deposit in segregated accounts
amounts which, together with earnings thereon, will be necessary to
decommission such nuclear facilities. The Company's ownership portion of
decommissioning costs is approximately $643 million, expressed in 1990
dollars, which the Company believes would be substantially unchanged at
December 31, 1993. The Company believes that the ultimate cost of
decommissioning these facilities will continue to be recoverable through
rates, but such recovery is not assured.
Limerick Generating Station
Limerick Unit No. 1 achieved a capacity factor of 95% in 1993 and 68%
in 1992. Limerick Unit No. 2 achieved a capacity factor of 81% in 1993 and
91% in 1992. Limerick Units No. 1 and No. 2 are each on a 24-month
refueling cycle. The last refueling outages for Units No. 1 and No. 2 were
in 1994 and 1993, respectively.
On November 5, 1993, the NRC issued its periodic Systematic Assessment
of Licensee Performance (SALP) Report for Limerick for the period March
15, 1992 to September 25, 1993. The Report was issued under the revised
SALP process in which the number of assessment areas has been reduced from
seven to four: Operations, Engineering, Maintenance, and Plant Support.
The area of Plant Support includes: radiological controls, security,
emergency preparedness, fire protection, chemistry and housekeeping.
Limerick received ratings of "1," the highest of the three rating
categories, in the two functional areas of Operations and Engineering. The
areas of Maintenance and Plant Support received ratings of "2." The NRC
stated that overall, it observed an excellent level of performance at
Limerick. It noted continued strong performance in the Operations and
Engineering areas and improvement in the Maintenance area. The NRC noted,
however, that in the Maintenance area, personnel errors, a weakness from
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the last SALP period, continued throughout the SALP period. Although the
NRC recognized the implementation of initiatives by the Company to improve
maintenance performance, it stated that such initiatives had not been in
place long enough to be judged effective. In the area of Plant Support,
the NRC stated that security, emergency preparedness, fire protection,
chemistry and housekeeping continue to be very effective and contributed
to safe plant performance. The NRC noted, however, performance weaknesses
in the radiation controls area through the SALP period. The Company has
taken and is taking actions to address the weaknesses discussed in the
SALP Report.
By letter dated December 8, 1992, the NRC imposed a civil penalty of
$25,000 on the Company based upon a decision by a United States Department
of Labor Administrative Law Judge (ALJ) that the Company's security
subcontractor unlawfully discriminated against one of its former
employees. The ALJ concluded that the employee was required to undergo a
psychological evaluation and subsequently was discharged by the security
subcontractor in retaliation for raising safety concerns regarding
security operations at Limerick. The security subcontractor is appealing
the decision of the ALJ to the Secretary of Labor. The Company has not
paid the NRC penalty pending the final decision in the matter.
On July 24, 1992, the NRC issued an information notice alerting
utilities owning boiling water reactors (BWRs) to potential inaccuracies
in water-level instrumentation during and after rapid depressurization
events. On May 28, 1993, the NRC issued a bulletin requesting utilities
owning BWRs to, among other things, install certain hardware modifications
at the next cold shutdown of the BWR after July 30, 1993 to ensure
accurate functioning of the water-level instrumentation. These hardware
modifications were made on Peach Bottom Unit No. 2 in August 1993, Peach
Bottom Unit No. 3 in November 1993 and Limerick Unit No. 1 in September
1993. The hardware modifications for Limerick Unit No. 2 will be made
during the next cold shutdown of that unit.
The NRC has raised concerns that the Thermo-Lag 330 fire barrier
systems used to protect cables and equipment may not provide the necessary
level of fire protection and requested licensees to describe short- and
long-term measures being taken to address this concern. The Company has
informed the NRC that it has taken short-term compensatory actions to
address the inadequacies of the Thermo-Lag barriers installed at Limerick
and Peach Bottom and is participating in an industry-coordinated program
to provide long-term corrective solutions. By letter dated December 21,
1992, the NRC stated that the Company's interim actions were acceptable.
By letter dated December 22, 1993, the NRC requested additional
information on the Company's long-term measures to address Thermo-Lag 330
fire barrier issues. The Company provided a response outlining its
Thermo-Lag program and committing to provide a status report to the NRC by
September 30, 1994. The Company cannot predict, at this time, what effect
this matter will have on the operations of Limerick and Peach Bottom.
Water for the operation of Limerick is drawn from the Schuylkill River
adjacent to Limerick and from the Perkiomen Creek, a tributary of the
Schuylkill River. During certain periods of the year, generally the summer
months but possibly for as much as six months or more in some years, the
Company would not be able to operate Limerick without the use of
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supplemental cooling water due to existing regulatory water withdrawal
constraints applicable to the Schuylkill River and the Perkiomen Creek.
Supplemental cooling water for Limerick is provided by a supplemental
cooling water system which draws water from the Delaware River. The
supplemental cooling water system for Limerick includes the following
components: (1) the Point Pleasant Pumping Station (to withdraw water from
the Delaware River) and a two and one-half-mile transmission main from the
Point Pleasant Pumping Station to the Bradshaw Reservoir (Point Pleasant
Project); (2) the Bradshaw Reservoir, a 25-million-gallon reservoir and
pumping station which receives water from the Point Pleasant Project and
acts as a dividing point for water for Limerick and for the public supply
systems of two Montgomery County water authorities; (3) a seven-mile
pipeline between the Bradshaw Reservoir and the east branch of the
Perkiomen Creek (East Branch); (4) a water treatment facility to provide
disinfection of Delaware River water; (5) approximately 24 miles of the
East Branch and the main branch of the Perkiomen Creek; (6) a pumping
station on the main branch of the Perkiomen Creek; and (7) an eight-mile
transmission main from the pumping station on the Perkiomen Creek to
Limerick.
Opposition to the Point Pleasant Project from various groups,
including Bucks County and the Neshaminy Water Resources Authority (NWRA),
a municipal authority created by Bucks County which had contracted to
construct the Point Pleasant Project, resulted in protracted litigation in
the Court of Common Pleas of Bucks County (Court of Common Pleas) and
numerous appeals of the decisions of that court. In May 1988, the Bucks
County Commissioners voted to end their opposition to the Point Pleasant
Project and enacted an ordinance to enable Bucks County to acquire and
manage the NWRA's projects, including the Point Pleasant Project. On May
26, 1988, in an action brought by Bucks County against the NWRA and its
board members to enforce the ordinance, the Court of Common Pleas ordered
the NWRA to transfer its projects, including the Point Pleasant Project,
to Bucks County. Certain intervenors appealed to the Commonwealth Court,
which dismissed the appeal on procedural grounds. The intervenors have
filed a petition in the Court of Common Pleas to cure the procedural
defect.
All permits for the construction and operation of the supplemental
cooling water system have been obtained. As described below, the issuances
of certain permits have been appealed. Certain of the permits relating to
operation of the system must be renewed periodically.
On July 14, 1988, the PDER issued a National Pollutant Discharge
Elimination System (NPDES) permit to the Company relating to the discharge
of Delaware River water into the East Branch. The Company filed an appeal
with respect to the temperature constraints and the limitations on
discharges of certain impurities of the NPDES permit with the
Environmental Hearing Board (EHB) on August 12, 1988. Certain
environmental groups also filed permit appeals with the EHB. In order to
comply with the conditions of its NPDES permit, the Company installed a
water treatment facility to provide seasonal cooling and disinfection of
the Delaware River water discharged into the East Branch. On March 31,
1992, the Company and PDER agreed to a settlement of the Company's appeal
by entering into a Consent Adjudication, which is subject to approval by
the EHB. The Consent Adjudication would resolve all issues in the
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Company's appeal but would not affect the appeal by certain environmental
groups from the NPDES permit. No action on the Company's Consent
Adjudication has been taken by the EHB.
In July 1993, the PDER reissued the Company's NPDES permit. The
reissued permit has conditions that are in certain instances less
stringent than those set forth in the original permit.
On February 12, 1988, the PDER extended various existing permits and
issued new stream encroachment permits and water allocation permits with
respect to the supplemental cooling water system. Intervenors appealed the
February 12, 1988 order to the EHB, which dismissed all appeals except
certain appeals relating to the erosive impact of the supplemental cooling
water system on the East Branch. These appeals have been stayed pending
disposition of other litigation concerning the erosion issue, which was
concluded in April 1992. In addition, appeals by an intervenor from
interim permit extension decisions of the PDER on June 26, 1987 and an
appeal of a 1982 water quality certification remain pending before the EHB
but have been inactive.
The Company has also entered into an agreement which expires on
December 31, 1994 with a municipality to secure a backup source of water
for the interim operation of Limerick should water from the supplemental
cooling water system not be available; however, this backup source is
capable of providing only enough cooling water to operate both Limerick
units simultaneously at 70% of rated capacity for short periods of time.
Peach Bottom Atomic Power Station
Peach Bottom Unit No. 2 achieved a capacity factor of 84% in 1993 and
61% in 1992. Peach Bottom Unit No. 3 achieved a capacity factor of 70% in
1993 and 78% in 1992. Peach Bottom Units No. 2 and No. 3 are each on a
24-month refueling cycle. The last refueling outages for Units No. 2 and
No. 3 were in 1992 and 1993, respectively.
On March 19, 1993, the NRC issued its periodic SALP Report on the
performance of activities at Peach Bottom for the period August 4, 1991
through October 31, 1992. Peach Bottom received ratings of "1" in the
area of Emergency Preparedness and the area of Security and Safeguards.
The areas of Plant Operations and Radiological Controls received ratings
of "2, Improving." Each of the other three functional areas
(Maintenance/Surveillance; Engineering/Technical Support; and Safety
Assessment/Quality Verification) received ratings of "2." Except for the
ratings in the areas of Plant Operations and Radiological Controls (each
previously rated "2"), these were the same ratings as those received in
the prior SALP Report. The SALP Report stated that management continued to
maintain a strong safety perspective throughout the assessment period and
fostered broad-based performance improvements that led to stronger
programs in most functional areas. The SALP Report further stated that
many of the programmatic weaknesses identified during the previous
assessment period have either been eliminated or performance has been
improved. For example, the SALP Report stated that fundamental problems
with the quality of root-cause analysis noted during the last two periods
have been resolved and that Peach Bottom's root-cause analysis
capabilities now constitute a strength. In addition, the SALP Report
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stated that licensed operators staffing and training continued to
strengthen, contributing to improved Plant Operations performance. The
SALP Report noted, however, that while overall progress in improving
performance was clearly evident throughout the period, several weaknesses
warranting continued management attention were identified. Among the areas
identified for improvement were plant performance monitoring and
engineering and technical support.
During 1983 outages, cracks in the piping of the residual heat removal
and reactor recirculating water systems were discovered at Peach Bottom
Unit No. 3 resulting from a generic problem with BWRs. Repairs, which
involved the replacement of piping, required extended outages at the Unit.
In February 1989, the Company, on behalf of the co-owners of Peach Bottom,
filed a proof of loss with Nuclear Electric Insurance Limited (NEIL) for
replacement power costs associated with Unit No. 3 outages. On January 19,
1993, the arbitrators issued a decision in favor of NEIL and denied the
Company's claim. On April 19, 1993, the Company filed a motion in the
United States District Court for the Southern District of New York to
vacate the arbitration decision.
On May 21, 1992, the Company filed a request with the NRC to amend its
Facility Operating Licenses for Peach Bottom Units No. 2 and No. 3 to
extend the expiration dates to August 2013 and July 2014, respectively, 40
years from the dates of issuance. The current operating licenses expire 40
years from the dates of issuance of the construction permits for the
Units. If the NRC grants the Company's request, the operating license for
Unit No. 2 will be extended approximately five years, six months and the
operating license for Unit No. 3 will be extended approximately six years,
five months.
By letter dated June 23, 1993, the Company submitted a request to the
NRC to rerate the authorized maximum reactor core power levels of both
Peach Bottom units by 5% to 3,458 megawatts thermal (Mwt) from the current
limits of 3,293 Mwt. The analyses and evaluations supporting this request
were completed using generic guidelines approved by the NRC. If the
request is approved, the associated hardware changes will be made on Unit
No. 2 during the planned fall 1994 refueling outage and on Unit No. 3
during the planned fall 1995 refueling outage.
In addition to the matters discussed above, see "Electric Operations-
Limerick Generating Station" for a discussion of certain matters which
affect both Peach Bottom and Limerick.
Salem Generating Station
Salem Unit No. 1 achieved a capacity factor of 60% in 1993 and 54% in
1992. Salem Unit No. 2 achieved a capacity factor of 57% in 1993 and 49%
in 1992. Salem Units No. 1 and No. 2 are each on an 18-month refueling
cycle. The last refueling outages for Units No. 1 and No. 2 were in 1993.
The Company has been informed by PSE&G that on September 1, 1993, the
NRC furnished PSE&G with its periodic SALP Report for Salem. The operating
period reviewed was from December 29, 1991 through June 19, 1993. Salem
received ratings of "1" in the areas of Radiological Controls and
Security. The area of Emergency Preparedness received a rating of "1,
9
12
Declining." The areas of Plant Operations; Maintenance/ Surveillance;
Engineering/Technical Support; and Safety Assessment/ Quality Verification
received ratings of "2." The NRC concluded that PSE&G's performance
during the period was good and noted an improvement over the last rating
period in the area of Radiological Controls. The NRC noted, however, that
Salem had a number of substantial operational challenges during the period
and that additional management attention is warranted to reduce the
frequency of such operational challenges.
The Company has been informed by PSE&G that, by letter dated March 9,
1994, the NRC imposed a civil penalty of $50,000 for eight violations for
failure to follow procedures at Salem related to the control of
maintenance of work activities. The NRC stated that, while none of the
violations were significant from a nuclear safety perspective, some of the
violations demonstrated the potential to cause physical harm to
individuals. In addition, the NRC stated that collectively, the violations
demonstrated that weaknesses exist in the maintenance and control of work
process activities, which could, under other circumstances, adversely
affect the operability of safety related equipment at Salem. The NRC
required PSE&G to respond to the alleged violations within 30 days and
document the specific corrective actions that have been and will be taken.
In order to improve Salem's materiel condition, plant and personnel
performance and address the NRC's concerns expressed in its October 1990
SALP Report, the Salem owners, including the Company, are in the process
of augmenting plans to improve Salem's materiel condition, upgrade
procedures and enhance personnel performance. The Company's share of the
plan's capital requirements for 1994 and for 1995-97 are reflected in the
Company's most recent estimates of capital expenditures for plant
additions and improvements for such periods. The planned improvements are
being managed by PSE&G as a discrete project and are expected to coincide
with plant operating schedules.
In addition to the matters discussed above, see "Environmental
Regulations-Water" for a discussion of possible installation of cooling
towers at Salem.
Fuel
The following table shows the Company's sources of electric output for
1993 and as estimated for 1994:
10
13
1993 1994 (Est.)
--------------------
Nuclear....................................................... 60.2% 58.7%
Mine-mouth, coal-fired........................................ 10.6 10.8
Service-area, coal-fired...................................... 5.9 9.5
Oil-fired..................................................... 5.2 2.6
Gas-fired..................................................... 1.4 1.3
Hydro (includes pumped storage)............................... 2.2 2.7
Internal combustion........................................... 0.1 0.1
Purchased, interchange and nonutility generated............... 14.4 14.3
------------------
100.0% 100.0%
==================
The following table shows the Company's average fuel cost used to
generate electricity:
1989 1990 1991 1992 1993
--------------------------------------------------
Nuclear
Cost per million Btu(1)..................... $ 0.84(2) $ 0.79(2) $ 0.64 $ 0.53 $ 0.56
Coal
Mine-mouth plants
Cost per ton.............................. 34.95 36.93 37.26 33.75 30.53
Cost per million Btu...................... 1.43 1.52 1.51 1.36 1.24
Service-area plants
Cost per ton.............................. 48.31 51.67 50.24 45.25 43.38
Cost per million Btu...................... 1.90 2.06 2.00 1.78 1.66
Oil
Residual
Cost per barrel........................... 19.12 21.70 19.42 15.94 15.87
Cost per million Btu...................... 3.08 3.44 3.11 2.53 2.50
Distillate
Cost per barrel........................... 23.36 30.37 29.90 24.96 27.21
Cost per million Btu...................... 3.98 5.20 5.12 4.26 4.15
Gas
Cost per mcf.............................. - - - 3.05 2.86
Cost per million Btu...................... - - - 2.96 2.77
----------
(1) British thermal unit.
(2) Reflects reclassification of spent-fuel cost for comparative purposes.
Nuclear
The cycle of production and utilization of nuclear fuel includes the
mining and milling of uranium ore; the conversion of uranium concentrates
11
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to uranium hexafluoride; the enrichment of the uranium hexafluoride; the
fabrication of fuel assemblies; and the utilization of the nuclear fuel in
the generating station reactor. The Company has contracts for uranium
concentrates which will satisfy the fuel requirements of Limerick and
Peach Bottom through 1996. The Company's contracts for uranium
concentrates are allocated to Limerick and Peach Bottom on an as-needed
basis. PSE&G has informed the Company that it presently has under contract
sufficient uranium concentrates to fully meet the current projected
requirements for Salem through 2000 and 60% of the requirements through
2002. The following table summarizes the years through which the Company
and PSE&G have contracted for the other segments of the nuclear fuel
supply cycle.
Conversion Enrichment Fabrication
--------------------------------------
Limerick Unit No. 1............. 1997 2014(1) 1996
Limerick Unit No. 2............. 1997 2014(1) 1997
Peach Bottom Unit No. 2......... 1997 2008(1) 1999
Peach Bottom Unit No. 3......... 1997 2008(1) 1998
Salem Unit No. 1................ 2000 (2) 2004
Salem Unit No. 2................ 2000 (2) 2005
----------
(1) The Company has exercised its option to remain uncommitted under the
United States Enrichment Corporation (USEC) enrichment contract from
2000 to 2002. This action, however, does not exclude USEC enrichment
services from consideration in this period. The Company does not
anticipate any difficulties in obtaining necessary enrichment services
for its Limerick and Peach Bottom Units.
(2) Represents 100% of enrichment requirements through 1998 and 30%
through 2001. Similar to the Company's actions discussed in note (1)
above, the Company has been informed by PSE&G that PSE&G has exercised
its option to remain uncommitted under its USEC enrichment contract
from 1999 to 2002.
On March 1, 1993, the Company entered into an agreement with the Long
Island Power Authority (LIPA) and other parties, subsequently revised on
September 14, 1993, to receive $46 million as compensation for accepting
slightly irradiated fuel from the Shoreham Nuclear Power Station on Long
Island, New York, for use at Limerick. The Company is to receive the $46
million in installments as the shipments of nuclear fuel are accepted. The
first of the 33 shipments arrived at Limerick on September 28, 1993.
Nineteen shipments of fuel were completed prior to the suspension of
shipments to accommodate the refueling outage of Limerick Unit No. 1.
Shipments of the remaining fuel are scheduled to resume after completion
of the refueling outage. The Company estimates that the acquisition of the
fuel will result in benefits to the Company's customers of $70 million
over the next 12 to 15 years due to reduced fuel-purchase requirements.
The fuel will be stored at Limerick's spent-fuel pool pending its use at
Limerick beginning in 1994 and extending beyond 2005. On September 21,
1993, the State of New Jersey filed suit in the United States District
Court for the District of New Jersey (New Jersey District Court) seeking a
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15
stay of shipments of fuel because of alleged failures of federal agencies
to fully review the proposed shipping plan under the National
Environmental Policy Act (NEPA) and the Coastal Zone Management Act
(CZMA). The New Jersey District Court refused to halt the shipments and
New Jersey has appealed to the United States Court of Appeals for the
Third Circuit (Appeals Court). The Appeals Court affirmed the New Jersey
District Court decision to dismiss the suit and subsequently denied a
request for rehearing. New Jersey has also requested that the NRC halt
shipments until the NRC further reviews the fuel transfer under the NEPA
and CZMA. The NRC has refused these requests.
The commercial reprocessing and recycling of the plutonium produced in
the United States nuclear power programs have been delayed indefinitely.
There are no commercial facilities for the reprocessing of spent nuclear
fuel currently in operation in the United States, nor has the NRC licensed
any such facilities. The spent-fuel storage pools for Limerick have
sufficient capacity to permit storage through 1999. Reracking of the
spent-fuel storage pools at Limerick, which will extend storage capacity
to approximately 2010, is in the preliminary stages. The new configuration
will be designed to accommodate rod consolidation. Spent-fuel racks at
Peach Bottom have storage capacity until 1998 for Unit No. 2 and 1999 for
Unit No. 3. Options for expansion of storage capacity at both Limerick and
Peach Bottom beyond the pertinent dates, including the viability of rod
consolidation, are being investigated. The Company has been informed by
PSE&G that the spent-fuel storage capacity at Salem will permit storage of
spent fuel through March 1998 for Salem Unit No. 1 and March 2002 for
Salem Unit No. 2. PSE&G has developed an integrated strategy to meet the
longer-term spent-fuel storage needs for Salem. PSE&G plans to replace the
existing high-density racks in the spent-fuel storage pools of Salem Units
No. 1 and No. 2 with maximum density racks. The reracking project
commenced in early 1992 and is expected to extend the storage capability
of Salem Units No. 1 and No. 2 through March 2008 and March 2012,
respectively.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the federal
government was to begin accepting spent fuel for permanent off-site
storage no later than 1998. The DOE has stated that there is no legal
obligation under the NWPA to begin accepting spent fuel absent an
operational repository or other facility constructed under the NWPA. The
DOE acknowledges, however, that it may have created the expectation of
such a commitment on the part of utilities by issuing certain regulations
and projected waste acceptance schedules. The DOE has stated that it will
not be able to open a permanent, high-level nuclear waste repository until
2010, at the earliest. The DOE stated that the delay was a result of its
seeking new data about the suitability of the proposed repository site at
Yucca Mountain, Nevada, opposition to this location for the repository and
the DOE's revision of its civilian nuclear waste program. The DOE stated
that it would seek legislation from Congress for the construction of a
temporary storage facility which would accept spent nuclear fuel from
utilities beginning in 1998 or soon thereafter. Although progress is being
made at Yucca Mountain and several communities have expressed interest in
providing a temporary storage site, the Company cannot predict when the
temporary federal storage facilities or permanent repository will become
available. The DOE is exploring options to address delays in the currently
projected waste acceptance schedules. The options under consideration by
13
16
the DOE include offsetting a portion of the financial burden associated
with the costs of continued on-site storage of spent fuel after 1998 and
the issuance by the DOE to utilities of multi-purpose canisters for
on-site storage. Under the NWPA, the DOE is authorized to assess utilities
for the cost of nuclear fuel disposal. The current cost of such disposal
is one mill per kWh of net nuclear generation. The 1993 charge collected
by the Company from its customers for spent-fuel disposal was $23 million.
The DOE may revise this charge as necessary for full-cost recovery of
nuclear fuel disposal.
The National Energy Policy Act of 1992 (Energy Act) states, among
other things, that utilities with nuclear reactors must pay for the
decommissioning and decontamination of the DOE nuclear fuel enrichment
facilities. The total costs to domestic utilities are estimated to be $150
million per year for 15 years, of which the Company's share is $5 million
per year. The Energy Act provides that these costs are to be recoverable
in the same manner as other fuel costs. The Company has recorded the
liability and a related regulatory asset of $69 million for such costs at
December 31, 1993. The Company is currently recovering these costs through
the Energy Cost Adjustment (ECA).
The Company believes that the ultimate costs of decommissioning and
decontamination, spent-fuel disposal and any assessment under the Energy
Act will continue to be recoverable through rates, although such recovery
is not assured.
Coal
The Company has a 20.99% ownership interest in Keystone Station
(Keystone) and a 20.72% ownership interest in Conemaugh Station
(Conemaugh), coal-fired, mine-mouth generating stations in western
Pennsylvania, operated by Pennsylvania Electric Company. A majority of
Keystone's fuel requirements is supplied by one coal company under a
contract which expires on December 31, 2004. The contract calls for
varying amounts of coal purchases as follows: between 3,000,000 and
3,500,000 tons for each of the years 1994 through 1999; and a total of
6,500,000 tons for the years 2000 through 2004. At December 31, 1993,
approximately 63% of Conemaugh's fuel requirements were secured by a
long-term contract and several short-term contracts.
The Company customarily enters into medium-term contracts for a
significant portion of its coal requirements and makes spot purchases for
the balance of coal required by its Philadelphia-area, coal-fired units at
Eddystone Station (Eddystone) and Cromby Station (Cromby). At January 1,
1994, the Company had contracts with two suppliers for 600,000 tons per
year or approximately 55% of expected annual requirements. One contract
expires on September 30, 1994 and the other expires on December 31, 1994
with an option to extend for one additional year if the Company and the
supplier so agree.
The coal requirements of each station not covered by existing
contracts are met through additional short-term contracts or spot
purchases from local suppliers.
Oil
The Company customarily enters into yearly purchase orders with its
various oil suppliers for the bulk of its requirements and makes spot
purchases for the balance. At present, the Company's purchase orders are
14
17
sufficient to meet the estimated residual fuel oil needs of its oil-fired
generating units through April 1994, when current orders end and new
yearly orders begin. Purchase orders for distillate fuel oil are expected
to meet the Company's needs through September 1994, when current orders
end and new yearly orders begin.
Natural Gas
The Company supplies natural gas for Cromby Unit No. 2 under a City
Gate Sales tariff approved by the PUC and through spot purchases made on
the open market. A limited amount of natural gas is used in auxiliary
boilers and pollution control equipment at Eddystone. In 1993, the Company
began converting Eddystone Units No. 3 and No. 4 to allow the use of oil
or natural gas.
Gas Operations
During 1993, 9.6% of the Company's operating revenues and 5.7% of its
operating income were from gas operations. Gas sales and operating
revenues for 1993 by classes of customers are set forth below:
Operating
Sales Revenues
(mmcf) (millions of $)
-------------------------
Residential................................. 1,637 $ 15.0
House heating............................... 30,687 205.5
Commercial and industrial................... 22,943 124.2
Other....................................... 5,656 15.2
--------------------
Total gas sales........................... 60,923 359.9
Gas transported for customers............... 22,946 22.8
--------------------
Total gas sales and transported......... 83,869 $382.7
====================
The Company's natural gas supply is provided by purchases from a
number of suppliers for terms ranging from 2 to 10 years. These purchases
are delivered under several long-term firm transportation contracts with
Texas Eastern Transmission Corporation (Texas Eastern) and
Transcontinental Gas Pipe Line Corporation (Transcontinental). The
Company's aggregate annual entitlement under these firm contracts is 69.3
million dekatherms. Peak gas is provided by the Company's liquefied
natural gas facility and propane-air plant (see "ITEM 2. PROPERTIES").
Through service agreements with Texas Eastern, Transcontinental,
Equitrans, Inc. and CNG Transmission Corporation, underground storage
capacity of 17.2 million dekatherms is under contract to the Company.
Natural gas from underground storage represents approximately 40% of the
Company's anticipated 1993-94 heating season supplies.
15
18
The FERC, under Order 636, has "restructured" the interstate gas
pipeline industry with the last pipeline companies implementing their
restructurings on November 1, 1993. The Company has replaced pipeline
bundled supply contracts with separate contracts for pipeline
transportation capacity and for gas supplies to be transported on the
pipeline systems. The FERC decided that interstate pipeline companies
should recover virtually all their costs of providing transportation
service in the form of fixed "reservation charges" that do not vary with
throughput on the pipeline systems. The FERC also has authorized pipeline
tariff provisions that reduce the pipelines' liability for failure to meet
delivery commitments. These federal regulatory changes have increased, and
are expected to continue to increase, the market and regulatory risks of
the Company's gas distribution operations.
The FERC's restructuring initiative is also creating "transition
costs," which principally consist of "gas supply realignment costs,"
reflecting contractual liabilities to natural gas producers caused by
pipeline companies' inability to continue to purchase natural gas for
resale under traditional bundled supply contracts. The FERC is authorizing
pipeline companies to recover these costs from their distribution
customers, such as the Company. In 1993, the PUC reversed a policy which
might have precluded the Company from fully recovering these costs from
its customers. The PUC will now permit the opportunity for full rate
recovery and the Company has filed with the PUC to begin recovery of such
costs.
The Company's wholly owned subsidiary Eastern Pennsylvania Exploration
Company is a party to several joint ventures formed to find and produce
natural gas in the Gulf Coast area and the Appalachian region. For 1993,
the Company's total net investment in connection with such programs
amounted to approximately $600,000. These joint ventures do not contribute
significantly to the Company's natural gas supply.
Segment Information
Segment information is incorporated herein by reference to note 16 of
Notes to Consolidated Financial Statements included in the Company's
Annual Report to Shareholders for the year 1993.
Rate Matters
In 1993, approximately 93% of the Company's electric sales revenue and
100% of its gas sales revenue were derived pursuant to rates regulated by
the PUC. The PUC establishes through regulatory proceedings the base rates
which the Company may charge for electric and gas service in Pennsylvania.
In addition, the PUC regulates various fuel and tax adjustment clauses
applicable to customers' bills. The Company's wholesale electric rates are
regulated by the FERC. The retail rates of COPCO are regulated by the
Maryland Public Service Commission (MdPSC).
The Company's last base-rate case, intended primarily to recover costs
associated with Limerick Unit No. 2 and associated common facilities, was
filed in 1989. As part of the base-rate case, the Company voluntarily
excluded 400 MW of capacity from base rates. As part of the order dated
April 19, 1990, the PUC concluded that the Company had an additional 399
16
19
MW of near-term excess capacity for which the Company was denied a return
on common equity. As a result, the Company has 799 MW of near-term excess
capacity and associated energy which are available for off-system sales.
For information concerning the Company's present arrangements for
off-system sales, see "Electric Operations-General."
On April 5, 1991, the PUC approved the settlement of all appeals
arising from the Limerick Unit No. 2 rate case. The settlement allows the
Company to retain for shareholders any proceeds above the average energy
cost for sales of up to 399 MW of capacity and/or associated energy.
Beginning on April 1, 1994, the settlement provides for the Company to
share in the benefits which result from the operation of both Limerick
Unit No. 1 and Unit No. 2 through the retention of 16.5% of the energy
savings. Through 1994, the Company's potential benefit from the sale of up
to 399 MW of capacity and/or associated energy and the retained Limerick
energy savings is limited to $106 million per year, with any excess
accruing to customers. Beginning in 1995, in addition to retaining the
first $106 million, the Company will share in any excess above $106
million with the Company's share of the excess being 10% in 1995, 20% in
1996 and 30% in 1997 and thereafter. As a part of the settlement, the
Company agreed not to file an electric base-rate increase before April
1994, except as allowed by the PUC or for emergency or single-issue rate
filings to recover costs associated with new legislation or regulations.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," which requires the
recognition of the expected costs of the benefits during the years
employees render service, but not later than the date eligible for
retirement, under the prescribed accrual method. For 1992 and prior, the
Company recognized these costs on a pay-as-you-go basis. The Company is
currently recovering in base rates the pay-as-you-go costs. The transition
obligation resulting from the adoption of SFAS No. 106 was $505 million as
of January 1, 1993, which represents the previously unrecognized
accumulated non-pension post-retirement benefits obligation. The
transition obligation is being amortized on a straight-line basis over an
allowed 20-year period. The annual accrual for non-pension postretirement
benefits costs (including amortization of the transition obligation) is
$83 million. The Company's comparable pay-as-you-go costs for these
benefits were $31 million in 1993. On September 11, 1992, the Company
filed with the PUC a request for a 1.5% electric base-rate increase
designed to recover the costs associated with the implementation of SFAS
No. 106. On March 25, 1993, the PUC issued a policy statement for
implementation of SFAS No. 106 which states that the PUC "intends to move
all jurisdictional utilities to SFAS No. 106 accrual accounting for
ratemaking purposes within approximately five years and to allow the
recovery in base rates of all deferred amounts in approximately 20 years
to the extent that costs are prudently incurred and examined in a
base-rate proceeding prior to rate recognition."
On September 2, 1993, the PUC issued an order denying the Company
current recovery of SFAS No. 106 costs, stating that the settlement of all
appeals arising from the PUC's 1990 Limerick Unit No. 2 order precluded
the Company from seeking an increase in electric base rates for these
costs before April 1, 1994. The September 2, 1993 order authorized the
17
20
Company to defer the additional SFAS No. 106 expense as a regulatory asset
in accordance with the PUC policy statement. On September 30, 1993, the
Company filed with the Commonwealth Court of Pennsylvania (Commonwealth
Court) a petition for review of the PUC's final order.
The Company's future earnings will be adversely affected to the extent
that the Company is not ultimately permitted to recover the additional
non-pension postretirement benefits costs resulting from the adoption of
SFAS No. 106 through the ratemaking process. While non-pension
postretirement benefits costs traditionally have been reflected in rates
on a pay-as-you-go basis, recovery of the deferred costs through the
ratemaking process is not assured. For additional information concerning
SFAS No. 106, see notes 2, 4 and 6 of Notes to Consolidated Financial
Statements included in the Company's Annual Report to Shareholders for the
year 1993.
In accordance with a Declaratory Order of the PUC, the Company
deferred approximately $91 million of operating and maintenance expenses,
depreciation and accrued carrying charges on its capital investment in
Limerick Unit No. 2 and 50% of Limerick common facilities during the
period from January 8, 1990, the commercial operation date of Limerick
Unit No. 2, until April 20, 1990, the effective date of the Limerick Unit
No. 2 rate order. Recovery of such costs deferred pursuant to the
Declaratory Order will be addressed by the PUC in a subsequent electric
rate case, although such recovery is not assured. Disallowance by the PUC
of all or part of these costs deferred pending regulatory approval would
result in an immediate charge to expense.
The Company and COPCO recover fuel and gas costs through base rates
and various automatic adjustment clauses. Regulatory audits of the
operation of the adjustment clauses are conducted to determine if refunds
to or recoupments from customers are necessary as a result of over- or
under-collections of fuel costs. In addition, the PUC may investigate
outages of electric generating units which exceed 120 days to determine
whether to deny the recovery of replacement power costs.
For Pennsylvania electric retail customers, the Company's ECA provides
for recovery of 100% of the difference between the Company's costs of
fuel, energy interchange and purchased power and the costs billed to
customers in base rates. On February 25, 1994, the Company filed its new
ECA to become effective April 1, 1994. The ECA filing proposes a change
from a credit value of 7.600 mills per kWh to a credit value of 5.647
mills per kWh, which represents an increase in annual revenue of
approximately $64 million. The approval of the ECA is pending before the
PUC. The ECA also incorporates a nuclear performance standard which allows
for financial bonuses or penalties depending on whether the Company's
system nuclear capacity factor exceeds or falls below a specified range.
If the capacity factor is within the range of 60% to 70%, there is no
bonus or penalty. If the capacity factor exceeds 70%, then progressive
bonuses are allowed. If the capacity factor falls below 60%, then
progressive penalties are imposed. The bonuses or penalties are based upon
average system replacement energy costs. For the year ended December 31,
1993, the Company's system nuclear capacity factor was 78%, which entitled
the Company to a bonus of approximately $10 million.
18
21
On May 28, 1993, the Company filed Purchased Gas Cost (PGC) No. 10
rates for the period December 1, 1993 through November 30, 1994, which
reflect a $0.97 per thousand cubic feet (mcf) increase in natural gas
sales rates. On October 28, 1993, the PUC voted to approve the Joint
Stipulation for Partial Settlement setting a $0.85 per mcf increase, which
represents an increase in annual revenue of $49.9 million, and to exclude
from the final PGC No. 10 rates $1.3 million relating to one issue
involving an Office of Consumer Advocate (OCA) allegation that such amount
represented excess peak-day capacity. On November 4, 1993, the Company and
the OCA reached an agreement to defer the issue of recovery of the $1.3
million to the next PGC proceeding. The agreement is pending before the
PUC.
The Company is authorized under a general order of the PUC to add a
State Tax Adjustment Surcharge to customers' bills to reflect the cost of
increases or decreases in certain state taxes not recovered in base rates.
On November 1, 1991, the FERC issued an order denying in part a waiver
of certain fuel adjustment clause regulations which the Company had filed
and directing refunds and a recalculation of fuel adjustment clause
charges. These recalculations affect the fuel charges billed to COPCO, at
the wholesale level, by the Company and its wholly owned subsidiary
Susquehanna Electric Company (SECO). In 1992, the Company refunded $1.3
million to COPCO. On August 27, 1993, the Company received FERC approval
of the amount refunded.
On October 2, 1990, the PUC issued an order initiating an
investigation into Demand-Side Management (DSM) by electric utilities.
Generally, DSM programs involve utilities providing assistance or
incentives to customers to encourage them to conserve energy and reduce
peak demand. On December 1, 1993, the PUC issued an order establishing a
special DSM cost-recovery mechanism for a five-year period. The order will
permit surcharge recovery of DSM program costs and allow utilities to earn
an incentive on kWh saved from DSM. The order will also permit utilities
to defer "lost revenues," with interest, for eventual recovery in the
next base-rate case. The OCA and the Pennsylvania Energy Office have filed
Petitions for Reconsideration and Clarification of the PUC's order and a
coalition of large industrial customers has filed an appeal with the
Commonwealth Court arguing that the PUC's order violates Pennsylvania
public utility laws. In accordance with the PUC's Declaratory Order, the
Company filed its DSM program plan with the PUC on March 14, 1994.
On September 14, 1993, the MdPSC instituted a proceeding to
investigate the strategic electric acquisition practices and long-range
electric supply planning of COPCO. The investigation is the result of an
order by the MdPSC on January 27, 1992 in connection with COPCO's last
base-rate case requiring that COPCO perform a study of its power supply
alternatives. Currently, COPCO purchases all of its power from the Company
and SECO, representing approximately 2% of the Company's annual revenues.
On January 26, 1993, COPCO filed its study with the MdPSC. Following a
review of the study by the MdPSC's Technical Staff and receipt of comments
from other parties, the MdPSC concluded that the above-mentioned
proceeding should be initiated to address several issues, including
competitive bidding of COPCO's power supply. Hearings are scheduled to
commence in September 1994.
19
22
On October 6, 1993, the Company filed with the FERC a proposed change
to the Tripartite Agreement under which the Company and SECO provide
electricity at wholesale to COPCO. The filing proposes to add an exit fee
for the recovery from COPCO of the stranded investment costs that the
Company would incur if COPCO were to purchase all or part of its power
supply needs from a source other than the Company. The exit fee is
calculated using a formula, based in part on the Company's existing fixed
charges to COPCO, installed generating capacity and current discount rate.
On December 2, 1993, the FERC issued an order that accepted and suspended
the Company's filing and set the matter for hearings, which are scheduled
to commence in August 1994.
On November 17, 1993, the Company filed with the FERC a transmission
service tariff to make available its transmission system to enable
third-party suppliers to sell power at wholesale to COPCO. On January 14,
1994, the FERC issued a deficiency letter requesting additional
explanation of and support for the Company's filing. The Company's
response is required to be filed by April 8, 1994.
Construction
The Company maintains a construction program designed to meet the
projected requirements of its customers and to provide service
reliability, including the timely replacement of existing facilities. The
Company's current construction program includes no new generating
facilities. During the five years 1989-93, gross property additions
(excluding capital leases) amounted to $3.0 billion and retirements
amounted to $227 million, resulting in a net increase of approximately 23%
in the Company's utility plant. Investment for new plant and equipment in
1993 amounted to $575 million. At December 31, 1993, construction work in
progress, excluding nuclear fuel, aggregated $381 million.
The following table shows the Company's most recent estimates of
capital expenditures for plant additions and improvements for 1994 and for
1995-97. These estimates do not include capital expenditures which may be
required for the possible installation of cooling towers at Salem (see
"Environmental Regulations-Water").
20
23
(Millions of Dollars)
---------------------
1994 1995-97
-------------------
Electric:
Production.................................. $222 $ 527
Nuclear fuel................................ 62 216
Transmission and distribution .............. 157 450
Other electric ............................. 5 9
------------------
Total Electric.......................... 446 1,202
Gas ............................................ 58 174
Other .......................................... 71 102
------------------
Total................................... $575 $1,478
==================
Nuclear fuel requirements exclude the Company's share of the requirements
for Peach Bottom and Salem which are provided by an independent fuel
company under a capital lease. See note 14 of Notes to Consolidated
Financial Statements included in the Company's Annual Report to
Shareholders for the year 1993.
Capital Requirements and Financing Activities
The following table shows the Company's most recent estimates of
capital requirements for 1994 and for 1995-97.
(Millions of Dollars)
---------------------
1994 1995-97
-----------------
Construction........................................ $575 $1,478
Long-term debt maturities and sinking funds (1)..... 252 162
----------------
Total Capital Requirements.................. $827 $1,640
================
----------
(1) Does not include $692 million of term loans that are expected to be
replaced or extended prior to maturity.
The Company expects to meet substantially all of its capital
requirements for 1994 and for 1995-97 with internally generated funds. The
estimates of capital requirements do not include any amounts for
refundings of higher-dividend preferred stock or higher-interest debt,
which refundings are dependent on future market conditions and internal
cash generation.
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In 1993, the Company's financing activities consisted of:
(Millions of Dollars)
---------------------
First and Refunding Mortgage Bonds:
6-5/8% due 2003.........................................$ 250.0
7-3/4% due 2023......................................... 100.0
6-1/2% due 2003......................................... 200.0
7-3/4% due 2023......................................... 250.0
5-3/8% due 1998......................................... 225.0
6-3/8% due 2005......................................... 75.0
7-1/8% due 2023......................................... 200.0
7-1/4% due 2024......................................... 225.0
5-5/8% due 2001......................................... 250.0
Pollution Control Bonds:
Floating Rate due 2012(1)............................... 154.2
Floating Rate due 2016.................................. 42.6
Floating Rate due 2025 ................................. 23.0
Preferred Stock:
$7.48 Cumulative Preferred Stock ....................... 50.0
$6.12 Cumulative Preferred Stock........................ 92.7
---------
Total...............................................$2,137.5
=========
----------
(1) Secured by First and Refunding Mortgage Bonds.
During 1993, $2.1 billion of long-term debt and preferred stock were
sold to replace debt and preferred stock carrying significantly higher
rates of interest and dividends. Also during 1993, the Company utilized
internally generated cash to repay $154 million of debt and to redeem $45
million of preferred stock.
Under the Company's mortgage (Mortgage), additional mortgage bonds may
not be issued on the basis of property additions or cash deposits unless
earnings before income taxes and interest during 12 consecutive calendar
months of the preceding 15 calendar months from the month in which the
additional mortgage bonds are issued are at least two times the pro forma
annual interest on all mortgage bonds outstanding and then applied for.
For the purpose of this test, the Company has not included Allowance for
Funds Used During Construction which is included in net income in the
Company's consolidated financial statements in accordance with the
prescribed system of accounts. The coverage under the earnings test of the
Mortgage for the 12 months ended December 31, 1993 was 4.20 times.
Earnings coverages under the Mortgage for the calendar years 1992 and 1991
were 3.31 and 3.93 times, respectively. At December 31, 1993, the most
restrictive issuance test of the Mortgage related to available property
additions. At December 31, 1993, the Company had at least $918 million of
available property additions against which $551 million of mortgage bonds
could have been issued. In addition, at December 31, 1993, the Company was
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entitled to issue approximately $3.2 billion of mortgage bonds without
regard to the earnings and property additions tests against previously
retired mortgage bonds.
Under the Company's Amended and Restated Articles of Incorporation
(Articles), the issuance of additional preferred stock requires an
affirmative vote of the holders of two-thirds of all preferred shares
outstanding unless certain tests are met. Under the most restrictive of
these tests, additional preferred stock may not be issued without such a
vote unless earnings after income taxes but before interest on debt during
12 consecutive calendar months of the preceding 15 calendar months from
the month in which the additional shares of stock are issued are at least
1.5 times the aggregate of the pro forma annual interest and preferred
stock dividend requirements on all indebtedness and preferred stock.
Coverage under this earnings test of the Articles for the 12 months ended
December 31, 1993 was 2.47 times. Earnings coverage under the Articles for
the calendar years 1992 and 1991 was 2.00 and 1.95 times, respectively.
The following table sets forth the Company's ratios of earnings to
fixed charges and the ratios of earnings to combined fixed charges and
preferred stock dividends for the periods indicated:
1989 1990(1) 1991 1992 1993
---------------------------------------
Ratio of Earnings to Fixed Charges.............. 2.08 1.31 2.55 2.43 3.15
Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividends .................... 1.77 1.04 2.14 2.06 2.67
----------
(1) Reflects one-time charges against income associated with various
disallowances made by the PUC in the electric rate case for Limerick
Unit No. 2 and the Company's 1990 Early Retirement Plan and a one-time
after-tax addition to income associated with the cumulative effect of
an accounting change for unbilled operating revenues.
For purposes of these ratios, (i) earnings consist of income from
continuing operations before income taxes and fixed charges and (ii) fixed
charges consist of all interest deductions and the financing costs
associated with capital leases.
At December 31, 1993, the Company had a total of $589 million
outstanding under unsecured loan agreements with banks with maturities
ranging from 1994 to 1997. Most of the Company's unsecured debt agreements
contain cross-default provisions to the Company's other debt obligations.
At December 31, 1993, the Company and its subsidiaries had formal and
informal lines of credit with banks aggregating $351 million against which
$119 million of short-term debt was outstanding. The Company does not have
formal compensating balance arrangements with these banks. The Company has
a $150 million commercial paper program, and at December 31, 1993, there
was no commercial paper outstanding.
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Employee Matters
The Company and its subsidiaries had 9,391 employees at December 31,
1993.
On June 10 and 11, 1993, the National Labor Relations Board (NLRB)
conducted a certification election in which certain non-management
employees had the opportunity to choose to be represented by the
International Brotherhood of Electrical Workers (IBEW), the Independent
Group Association (IGA) or to continue not to be represented by a union.
On June 12, 1993, the NLRB announced that the Company employees voted to
continue to not be represented by a union. Of the 6,400 employees eligible
to vote, 95.5% cast ballots. Employees cast 3,530 votes for "no union";
1,260 votes for the IBEW; and 719 votes for the IGA. On June 23, 1993, the
NLRB certified the results of the balloting.
Environmental Regulations
Environmental controls at the federal, state, regional and local
levels have a substantial impact on the Company's operations due to the
cost of installation and operation of equipment required for compliance
with such controls. In addition to the matters discussed below, see
"Electric Operations-General" and "Electric Operations-Limerick
Generating Station."
An environmental issue with respect to construction and operation of
electric transmission and distribution lines and other facilities is
whether exposure to electric and magnetic fields (EMF) causes adverse
human health effects. A large number of scientific studies have examined
this question and certain studies have indicated an association between
exposure to EMF and adverse health effects, including certain types of
cancer. However, the scientific community still has not reached a
consensus on the issue. Additional research intended to provide a better
understanding of EMF is continuing. The Company supports further research
in this area and is funding, monitoring and participating in such
studies. The Company cannot predict at this time what effect, if any, this
matter will have on future operations.
Water
The Company has received NPDES permits as required under federal and
state laws for the discharge of effluents from its generating stations.
These permits must be renewed periodically and, as necessary, the Company
has filed applications for renewal.
In 1991, the Company completed the modification of the cooling water
intake screens at Eddystone Units No. 1 and No. 2 to satisfy the
requirements of the PDER and the EPA. At the request of the PDER and the
Pennsylvania Fish Commission, the Company extended the fish impingement
study concerning Eddystone Units No. 3 and No. 4 intake screens until
November 1992 to determine whether any additional requirements were
necessary to comply with federal water pollution standards. In April 1993,
the final report on the impingement study was submitted to the PDER. The
final report concluded that no further actions were required concerning
Eddystone Units No. 3 and No. 4.
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The Company has been informed by PSE&G that, on October 3, 1990, the
New Jersey Department of Environmental Protection (now the New Jersey
Department of Environmental Protection and Energy (NJDEPE)) issued a draft
New Jersey discharge to surface water permit for Salem Units No. 1 and No.
2. The draft permit incorporated numerous new and more stringent terms and
conditions than the existing water discharge permit for Salem, including
the immediate shutdown of both Salem units pending retrofitting with
cooling towers. In response to the 1990 draft permit, PSE&G submitted
extensive written comments to the NJDEPE regarding the ecological effects
of Salem's operations, and the nature, scope, and costs of retrofitting
Salem with cooling towers. The estimated cost of cooling towers, including
the cost of replacement power during the construction periods, based on
natural draft and forced draft technologies, ranges from $720 million to
$2 billion of which the Company's share would be 42.59%. PSE&G's comments
demonstrated that Salem was not having and would not have an adverse
environmental impact and that the construction of cooling towers would be
an inappropriate solution. To resolve the NJDEPE's concerns, PSE&G also
developed and submitted a supplement to the permit renewal application
setting forth alternative measures to the installation of cooling towers
that would protect aquatic life in the Delaware Estuary and provide
broad-ranging ecological benefits. PSE&G proposed intake screen
modifications to reduce fish losses, a study of deterrent systems to
divert fish from the intake and a limit on intake flow of 3.024 billion
gallons per day. In addition, PSE&G proposed conservation measures,
including the restoration of up to 10,000 acres of degraded wetlands and
the installation of fish ladders to allow fish to reach upstream spawning
areas. Finally, PSE&G proposed a comprehensive biological monitoring
program to expand existing knowledge of the Delaware Estuary and to
monitor station impacts. In June 1993, the NJDEPE issued a revised draft
permit for Salem which contained the alternative measures proposed by
PSE&G with certain modifications. The public comment period on the revised
draft permit closed January 15, 1994. The NJDEPE has received a
significant number of comments on the draft permit from a wide variety of
interests. These comments include a number of suggestions to the NJDEPE
for changes in permit terms. In addition, the comments to the NJDEPE
include a variety of claims as to alleged legal defects in the draft
permit, including failure to comply with applicable standards under the
Clean Water Act, failure to assure consistency with applicable Coastal
Zone Management Plans, failure to comply with requirements of the Delaware
River Basin Commission, and failure to comply with procedural requirements
of New Jersey and federal law. On January 15, 1994, PSE&G filed extensive
comments with the NJDEPE to respond to comments opposing the issuance of
the final permit with terms materially different than those found in the
draft permit. The NJDEPE has stated that it intends to issue a final
permit in the second quarter of 1994, but no assurances can be given as to
when or in what manner the NJDEPE will act on the issuance of a final
permit. The EPA has authority to veto the issuance of a final permit by
the NJDEPE. Action by the EPA cannot be predicted. Certain environmental
groups have also petitioned the EPA to veto any final permit that does not
require cooling towers and to withdraw the NJDEPE's permitting authority
under the Clean Water Act. If a final permit embodying the alternative
measures is issued, additional permits from various agencies will be
required for implementation. No assurance can be given as to the issuance
of such permits. The estimated costs of compliance with the revised draft
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permit is approximately $75 million of which the Company's share would be
42.59% or $32 million.
Air
Air quality regulations promulgated by the PDER and the City of
Philadelphia in accordance with the federal Clean Air Act impose
restrictions on emission of particulates, sulfur dioxide (SO2) and other
pollutants and require permits for operation of emission sources. Such
permits have been obtained by the Company and must be renewed
periodically. Under the Clean Air Act Amendments of 1990 (Amendments) new
permits will have to be obtained.
The Amendments establish a comprehensive and complex national program
to substantially reduce air pollution over the next decades. The
Amendments include a two-phase program to reduce acid rain effects by
significantly reducing emissions of SO2 and nitrogen oxides (NOx) from
electric power plants. A flue-gas desulfurization system (scrubbers) is
being installed at Conemaugh to reduce SO2 emissions to meet the 1995
Phase I requirements. The Company's share of the capital costs to
construct the scrubbers and make other related improvements at Conemaugh
are estimated to be $78 million. Keystone is not covered by the Phase I
SO2 and NOx limits of the Amendments. Capital expenditures in amounts
similar to those required for Conemaugh, however, may also be necessary
for Keystone to meet, by January 1, 2000, the Phase II SO2 and NOx limits.
The Company's service-area, coal-fired generating units at Eddystone
and Cromby are equipped with scrubbers and their emissions meet the SO2
limits of both Phase I and Phase II of the Amendments. The Company,
however, will be required to comply with the NOx emission limitations of
the Amendments by May 31, 1995 for these units, all of which are in an
ozone nonattainment area. The Company estimates that installing low-NOx
burners, which is one of the possible technologies and lowest in cost, on
all of its oil and gas sources would require a capital expenditure of $21
million. The cost of compliance could be less if the Company is not
required to make modifications to all of its units or implements a system
which permits credits or averaging among sources. If, however, further
technological improvements are required, the cost of compliance could be
substantially higher. As a result of its prior investments in scrubbers
for Eddystone and Cromby and its investment in nuclear generating
capacity, the Company believes that compliance with the Amendments will
have less impact on the Company's electric rates than on the rates of
other Pennsylvania utilities which are more dependent on coal-fired
generation.
Many other provisions of the Amendments will affect the Company's
business. The Amendments establish stringent new control measures for
areas which are designated as not meeting national ambient air quality
standards; establish limits on the purchase and operation of motor
vehicles and require increased use of alternative fuels; provide for
stringent controls on emissions of toxic air pollutants and the possible
future designation of some utility emissions as toxic; establish new
permit and monitoring requirements for sources of air emissions; and
provide for significantly increased enforcement power, and civil and
criminal penalties.
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Solid and Hazardous Waste
The Comprehensive Environmental Response, Compensation, and Liability
Act of 1980 and the Superfund Amendments and Reauthorization Act of 1986
(collectively CERCLA) authorize the EPA to cause "potentially responsible
parties" (PRPs) to conduct (or for the EPA to conduct at the PRPs'
expense) remedial action at waste disposal sites that pose a hazard to
human health or the environment. Parties contributing hazardous substances
to a site or owning or operating a site typically are viewed as jointly
and severally liable for conducting or paying for remediation and for
reimbursing the government for related costs incurred. PRPs may agree to
allocate liability among themselves, or a court may perform that
allocation according to equitable factors deemed appropriate.
By notice issued in November 1986, the EPA notified over 800 entities,
including the Company, that they may be PRPs under CERCLA with respect to
releases of radioactive and/or toxic substances from the Maxey Flats
disposal site, a low-level radioactive waste disposal site near Moorehead,
Kentucky, where certain of the Company's wastes were deposited.
Approximately 90 PRPs, including the Company, formed a steering committee
and entered into an administrative consent order with the EPA to conduct a
remedial investigation and feasibility study (RI/FS), which was
substantially revised based on the EPA comments. In September 1991,
following public review and comments, the EPA issued a Record of Decision
in which it selected a natural stabilization remedy for the Maxey Flats
disposal site. The steering committee has preliminarily estimated that
implementing the EPA proposed remedy at the Maxey Flats site would cost
$60- $70 million in 1993 dollars. Negotiations are continuing between the
EPA and the steering committee to determine the role of the steering
committee in implementing the selected remedy and the share of any costs
which will be allocated to the PRPs represented by the steering committee.
On March 17, 1993, the private PRPs, together with several federal PRPs,
and the Commonwealth of Kentucky made offers to the EPA to perform and
fund a portion of the remedial activities at the site. In a letter dated
September 2, 1993, the EPA notified the federal and private PRPs and the
Commonwealth of Kentucky that their respective offers to perform and fund
a portion of the remedial activities at the site form the basis of further
negotiations for implementing the remedial plan and such negotiations have
commenced. The Company cannot predict what cost it may incur as part of
the cleanup of the site. The Company's share of the cost of the RI/FS
(estimated to be $4.5 million net of contributions by the Department of
Defense and the DOE) will be based on its percentage of waste deposited at
the site, which is presently estimated by the steering committee to be
1.07%.
By notice issued in December 1987, the EPA notified several entities,
including the Company, that they may be PRPs under CERCLA with respect to
wastes resulting from the treatment and disposal of transformers and/or
miscellaneous electrical equipment at a site located in Philadelphia,
Pennsylvania (the Metal Bank of America site), during the period 1970-72.
Several of the PRPs, including the Company, have formed a steering
committee to investigate the nature and extent of possible involvement in
this matter. On May 29, 1991, a Consent Order was issued by the EPA
pursuant to which the members of the steering committee agree to perform
the RI/FS as described in the work plan issued with the Consent Order. The
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remedial investigation is currently proceeding at the site in accordance
with the work plan approved under the Consent Order. During the course of
the site investigation, it became necessary to perform additional sampling
and analytical work and to modify the scope of the work to address
concerns raised by the EPA and its contractors and to properly
characterize the site. Due to these changes, it is currently estimated
that the technical, administrative and legal costs necessary for
investigation of the site and preparation of the RI/FS may total between
$4 and $5 million and the schedule for the RI/FS will be extended. The
Company's share of such costs will be approximately 30%.
The EPA has notified the Company that it is a PRP for part of the
cleanup costs at a site (Berks Associates/Douglassville site) where wastes
generated by the Company may have been deposited by others and has
requested extensive information on the characteristics of the material
sent to the site and the processes which generated the material. In August
1991, the EPA filed suit in the United States District Court for the
Eastern District of Pennsylvania (Eastern District Court) against 36 named
PRPs, not including the Company, seeking a declaration that these PRPs are
jointly and severally liable for cleanup of the Berks
Associates/Douglassville site and for costs already expended by the EPA on
the site. Simultaneously, the EPA issued an Administrative Order against
the same named defendants, not including the Company, which requires the
PRPs named in the Administrative Order to commence cleanup of a portion of
the site. It is estimated that the cleanup of this portion of the site
will cost approximately $2 million. Although the Company was not named as
a respondent in the Administrative Order issued by the EPA, it joined a
group of the named respondents and several other PRPs who were not named
as respondents, and contributed money to the group to conduct the cleanup
activities required by the Administrative Order. On September 29, 1992,
the Company, along with 169 other parties, was served with a third-party
complaint joining these parties as additional defendants. Subsequently, an
additional 150 parties were joined as defendants. On June 30, 1993, the
EPA issued a further Administrative Order which directed certain
defendants to implement a remedial plan which calls for incineration of
large quantities of contaminated soil from part of the site at an
estimated cost of $40-60 million. The PRP group, including both named and
additional defendants, are negotiating with the EPA to consider an
alternative remedy for the site which could be implemented at
substantially less cost than the remedy selected by the EPA. The EPA has
deferred the effectiveness of its June 30 Administrative Order while
settlement negotiations are continuing. On October 27, 1993, the PDER
filed a motion to intervene as a plaintiff in the Eastern District Court
suit claiming investigative and remedial cost reimbursement and natural
resource damages. The motion is pending before the Eastern District Court.
The Company has been notified by groups of PRPs at two sites (the
Spectron site and the Metro Container site) that the Company has been
identified as having sent hazardous substances to these sites. The Company
has been requested by these PRPs to contribute to the costs of certain
removal activities undertaken by the PRPs pursuant to consent orders
issued by the EPA. The Company has contributed to the removal costs at one
site. The amount of the Company's contribution, if any, to the other site
has not yet been determined. The EPA has not yet determined if further
cleanup activities will be required at these two sites.
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In April 1990, the Company received a notice from the NJDEPE which
alleges that the Company is potentially liable for certain cleanup costs
at the Gloucester Environmental Management Services, Inc. (GEMS) site
located in New Jersey because wastes generated by the Company are alleged
to have been deposited at the site by a third party. The Company has also
been added as a defendant in a suit commenced by the NJDEPE several years
ago, which now names several hundred defendants, and which relates to the
GEMS site. The Company has joined a pre-existing group of PRPs which is
dealing with the NJDEPE on these matters.
On October 16, 1989, the EPA and the NJDEPE commenced a civil action
in the New Jersey District Court against 26 defendants, not including the
Company, alleging the right to collect past and future response costs for
cleanup of the Helen Kramer landfill located in New Jersey. In October
1991, the direct defendants joined the Company and over 100 other parties
as third-party defendants. The third-party complaint alleges that the
Company generated materials containing hazardous substances that were
transported to and disposed at the landfill by a third party.
In July 1992, the Company received a notice from a group of PRPs
performing remediation at the Blosenski Landfill Superfund Site that the
group considers the Company to be a PRP. The PRP group requested the
Company to join the existing PRP group or face legal action by the group
to compel the Company to contribute to past and future clean-up costs. The
Company investigated its involvement with this site and has been unable to
identify a basis for concluding that the Company is liable for remediation
costs at this site. Consequently, the Company has notified the PRP group
that it does not, at this time, intend to join the Blosenski PRP group.
The Blosenski PRP group served the Company with a subpoena seeking certain
information from the Company concerning its involvement with this site.
The Company responded to some of the requests and has objected to others.
In November 1992, the Company received a subpoena from the
non-government parties (party participants) in a consolidated action
relating to the Bridgeport Rental and Oil Services Superfund (BROS) site
requesting information on various haulers. The party participants have
information which they believe connects the Company to the site. At the
invitation of the party participants, the Company is participating in a
"voluntary, informal, non-litigated settlement/mediation process." In
April 1993, the Company received a Request for Information from the EPA
regarding potential use of the BROS site. On May 27, 1993, the Company
filed its response with the EPA. The voluntary participants are presently
engaged in a mediation process with the governmental parties.
In March 1994, the Company received a notice from the EPA that it may
be a di minimus PRP with respect to hazardous substances deposited by a
third party at a site (Jack's Creek/Sitkin Smelting Facility) located in
Mifflin County, Pennsylvania. Currently, the EPA has identified over 590
entities that may be PRPs with respect to this site. The Company is
investigating its involvement with this site.
On March 3, 1989, the Company received a Notice of Violation from the
PDER for soil contamination at one of the Company's maintenance
facilities. The Company suspects that the contamination was caused by
leakage of transformer dielectric fluid. The PDER required the Company to
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initiate sampling to determine the scope of the contamination. The Company
conducted sampling and ground water monitoring and submitted the results
to the PDER on November 18, 1991. The Company has identified the presence
of oil and polychlorinated byphenols (PCBs) at the site. On February 19,
1993, the Company submitted to the PDER a revised remedial clean-up
strategy. On March 9, 1993, the PDER accepted the Company's revised
remedial clean-up strategy. The Company is implementing the remedial
clean-up strategy accepted by the PDER, which is expected to cost
approximately $2 million over a period of 3 to 5 years.
In addition, an evaluation of all Company sites for potential
environmental clean-up liability is in progress, including approximately
20 sites where manufactured gas plant activities may have resulted in site
contamination. Past activities at several sites have resulted in actual
site contamination. The Company is presently engaged in performing
detailed evaluations at certain of these sites to define the nature and
extent of the contamination, to determine the necessity of remediation and
to identify possible remediation alternatives. The Company has also
responded to various governmental requests, principally those of the EPA
pursuant to CERCLA, for information with respect to the possible deposit
of Company waste materials at various disposal, processing and other
sites.
In addition, the Company is in the process of complying with the
Resource Conservation and Recovery Act (RCRA) which governs treatment,
storage and disposal of solid and hazardous wastes.
On February 22, 1993, the Company received a draft Corrective Action
Order from the EPA under RCRA. The draft order requires the Company to
investigate the extent of alleged releases of hazardous wastes and to
evaluate corrective measures, if necessary, for a site located along the
Delaware River in Chester, Pennsylvania, which had previously been leased
to Chem Clear, Inc. Chem Clear operated an industrial waste water
pretreatment facility on the site. On June 4, 1993, the Company executed a
final Corrective Action Order in which the Company agreed to investigate
the extent of alleged releases of hazardous wastes and to evaluate
corrective measures, if necessary. The Company estimates that compliance
with the Corrective Action Order will cost $2 million over a period of
five years. Until completion of the required investigation, the Company is
unable to predict the nature and cost of any potential corrective action.
Costs
The Company's budget for capital requirements for 1994 and its most
recent estimate of capital requirements for 1995-97 for compliance with
environmental requirements total $68 million. This estimate does not
include amounts that the Company may be required to spend for its share of
any cooling towers that may be required at Salem or for its share of
scrubbers or other systems at Keystone to comply with the Amendments. In
addition, the Company may be required to make significant additional
expenditures not presently determinable.
At December 31, 1993, the Company had accrued $17 million for various
investigation and remediation costs that can be reasonably estimated. The
Company cannot currently predict whether it will incur other significant
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33
liabilities for additional remediation costs at sites presently identified
or additional sites which may be identified by the Company, environmental
agencies or others.
The Company will ultimately seek to recover through the ratemaking
process all capital costs and any increased operating costs, including
those associated with environmental compliance and remediation, although
such recovery is not assured.
Competition
The Company generally has the right through franchises to provide
electric or gas service to the public within its service areas. The
Company is required by federal and state law to purchase electricity
generated by qualifying facilities (such as cogenerators and small power
producers). Certain businesses within the Company's service territory also
generate all or a portion of their own electrical requirements.
The electric utility industry, in particular power generation to serve
the needs of large users such as municipal customers and for off-system
sales, has become increasingly competitive. Companies that are able to
provide energy at a lower cost are likely to benefit from this
competition. Competitors include cogenerators, independent power producers
and other utilities. Nonutility generation has resulted, and in the future
could result, in the loss of revenues from industrial customers. These
factors will continue to challenge the Company to maintain current revenue
levels.
The Energy Act is designed, among other things, to promote competition
among utility and non-utility generators by amending the 1935 Act to
exempt a new class of independent power producers (exempt wholesale
generators) which are not subject to regulation under the 1935 Act. The
Energy Act also amends the Federal Power Act to allow the FERC to order
wholesale wheeling to provide utilities and non-utility generators with
access to utility transmission facilities. The provisions direct the FERC
to set prices for wheeling to allow utilities to recover all legitimate
verifiable and economic costs for providing wheeling services, including
the cost of expanding their transmission facilities to accommodate
required transmission access. The costs are to be recovered from the
company whose electricity is being wheeled rather than from the utilities'
native-load retail customers. In addition, the Energy Act restricts the
FERC's ability to order wheeling if it would not be in the public interest
or would impair the ability of a utility to provide reliable power to its
existing customers. Although the FERC is prohibited under the Energy Act
from ordering retail wheeling, the prohibition does not extend to state
utility commissions. Retail wheeling would challenge the Company to assure
that it continues to be the provider of service to its large commercial
and industrial customers and that it positions itself to take advantage of
opportunities to expand its customer base by marketing its reliable power
sources.
The Company is currently involved in proceedings before the MdPSC and
the FERC concerning the continued purchase by COPCO of all of its power
from the Company. See "Rate Matters" for a discussion of the MdPSC and
the FERC proceedings.
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In September 1993, the Board of Directors of the Company approved a
plan to reorganize the Company's operations to better enable it to meet
the challenges of a competitive environment. The Company's operations will
be divided into five strategic business units by January 1, 1995. The
business units will be Consumer Energy Services Group, Bulk Power
Enterprises Group, Power Generation Group, Nuclear Generation Group, and
Gas Services Group. The plan calls for each business unit to eventually
operate as an individual profit center, separate from the other business
units.
In October, in response to its perception of business risk created by
intensifying competition within the electric utility industry, the
Standard & Poor's (S&P) rating agency tightened the financial ratio
benchmarks it uses to rate electric utility company debt. This action has
affected a significant portion of the investor-owned electric utility
industry. Although the Company's current debt ratings have been affirmed
by S&P, the Company's outlook, along with 47 other electric utilities, has
been changed from "stable" to "negative." The Company and 21 other
electric utilities have had their business positions categorized as
"below average." S&P determined the Company's business position to be
"below average" because it is considered to be a high-cost producer of
electricity with a high dependency on its nuclear generation. Also, the
perceived outlook for the economy of the Company's service territory and
the Northeast in general contributed to this characterization.
Moody's Investors Services (Moody's) has also announced that the
changing electric utility business environment could, over the next three
to five years, lead to bond rating downgrades. Moody's also believes that
business risk in the electric utility industry is rising due to
deregulation and the resulting competition.
The Company's gas business experiences competition from suppliers of
other energy sources, primarily fuel oil and electricity. The Company's
interruptible gas rates provide "flexible" pricing which allows for
monthly rate changes to match the pricing of competing fuel sources,
provided that the rates remain within a PUC-approved range.
32
35
Executive Officers of the Registrant
Age at Effective Date of Election
Name Dec. 31, 1993 Position to Present Position
---------------------------------------------------------------------------------------------------------------------------
J. F. Paquette, Jr...... 59 Chairman and Chief Executive Officer April 16, 1990
C. A. McNeill, Jr. ..... 54 President and Chief Operating Officer April 16, 1990
W. L. Bardeen........... 55 Senior Vice President and Group March 1, 1994
Executive - Consumer Energy
Services Group
J. W. Durham............ 56 Senior Vice President and General Counsel October 24, 1988
W. J. Kaschub........... 51 Senior Vice President-Human Resources June 10, 1991
G. S. King.............. 53 Senior Vice President-Corporate and October 1, 1992
Public Affairs
K. G. Lawrence.......... 46 Senior Vice President-Finance and Chief March 1, 1994
Financial Officer
J. M. Madara, Jr........ 50 Senior Vice President and Group March 1, 1994
Executive - Power Generation Group
D. M. Smith............. 60 Senior Vice President - Nuclear Generation March 1, 1994
Group and Chief Nuclear Officer
A. J. Weigand........... 55 Senior Vice President and Group March 1, 1994
Executive - Bulk Power Enterprises
G. S. Cucchi............ 44 Vice President - Planning and March 1, 1994
Performance
D. R. Helwig............ 42 Vice President-Limerick Generating July 20, 1992
Station
T. P. Hill, Jr.......... 45 Vice President and Controller January 1, 1991
K. C. Holland........... 41 Vice President - Information Systems March 21, 1994
R. B. Horne............. 59 Vice President - Chester County Division March 1, 1994
A. G. Mikalauskas....... 57 Vice President -Transmission and March 1, 1994
Distribution Services
G. C. Miller............ 49 Vice President - Philadelphia, North March 1, 1994
Division
G. R. Rainey............ 44 Vice President-Peach Bottom Atomic November 24, 1993
Power Station
M. T. Riley, Jr......... 56 Vice President - Philadelphia, South March 1, 1994
Division
M. W. Rimerman.......... 64 Vice President-Finance and Treasurer November 26, 1990
C. C. Rogala............ 47 Vice President - Delaware County March 1, 1994
Division
W. H. Smith, III........ 45 Vice President-Planning and Performance May 1, 1992
A. J. Solecki........... 53 Vice President-Support Services March 1, 1993
T. C. Stapleford........ 56 Vice President - Montgomery County March 1, 1994
Division
W. J. Williams.......... 52 Vice President- Bucks County Division March 1, 1994
L. S. Binder............ 56 Secretary July 1, 1978
33
36
The present term of office of each of the above executive officers
extends to the first meeting of the Company's Board of Directors after the
next annual election of Directors (scheduled to be held April 13, 1994).
Prior to his election to his current position with the Company, Mr.
Paquette was Chairman, President and Chief Executive Officer of the
Company.
Prior to his election to his current position with the Company, Mr.
McNeill was Executive Vice President-Nuclear of the Company.
Prior to his election to his current poistion with the Company, Mr.
Bardeen was Senior Vice President - Finance and Chief Financial Officer.
Prior to joining the Company in February 1992, Mr. Bardeen was Vice
President-Finance and Controller for Bell Atlantic Corporation.
Prior to joining the Company in June 1991, Mr. Kaschub was Vice
President of Human Resources with GTE North Incorporated.
Prior to joining the Company in October 1992, Mrs. King served as
Commissioner of the United States Social Security Administration since
August 1989. From March 1988 to August 1989, Mrs. King was Executive Vice
President of Gogal & Associates, a Washington D.C. consulting firm.
Prior to his election to his current position with the Company, Mr.
Lawrence was Vice President-Gas Operations and Vice President-Commercial
Operations.
Prior to his election to his current position with the Company, Mr.
Madara was Vice President-Production, Assistant Manager-Mechanical
Engineering and General Manager-Nuclear Quality Assurance.
Prior to his election to his current position with the Company, Mr. D.
M. Smith was Senior Vice President-Nuclear and Vice President-Peach Bottom
Atomic Power Station.
Prior to his election to his current position with the Company, Mr.
Weigand was Vice President-Transmission and Distribution Systems and Vice
President-Engineering and Production.
Prior to joining the Company in March 1994, Mrs. Holland was Director
of Technology Services and Director of Business Systems and Operations at
SmithKline Beecham, Inc.
Prior to their election to the positions shown above, the following
executive officers held other positions with the Company since January 1,
1989: Mr. Cucchi was Director of System Planning and Performance, Manager
of System Planning and Performance and Supervising Engineer of System
Planning and Performance; Mr. Helwig was Vice President-Nuclear
Engineering and Services, Vice President-Nuclear Services, Assistant to
the Executive Vice President-Nuclear, and General Manager of Nuclear
Quality Assurance; Mr. Hill was Controller and Manager of Rates; Mr. Horne
was Division Manager - Chester County and General Manager - Chester
County; Mr. Mikalauskas was Vice President - Customer and Marketing
Services, Vice President-Commercial Operations and Vice President-Electric
34
37
Transmission and Distribution; Mr. Miller was Division Superintendent -
Transmisison and Distribution, Manager - Transmission and Distribution
Services, and General Manager - Philadelphia, North Division; Mr. Rainey
was Vice President-Nuclear Services, Plant Manager-Eddystone Generating
Station and Maintenance Superintendent-Peach Bottom; Mr. Riley was General
Manager - Philadelphia, South Division, Station Manager - Cromby Generating
Station, and Assistant Station Superintendent - Eddystone Generating
Station; Mr. Rimerman was Vice President-Finance and Accounting and Vice
President-Finance; Mr. Rogala was General Manager - Delaware
County Division and Manager - Customer Service Accounts; Mr. W. H. Smith,
III was Manager-Corporate Strategy and Performance, General Manager-Human
Resources, Director-Organization Change Task Force, Manager-Purchasing;
Mr. Solecki was Vice President-Information Systems and General Services;
Mr. Stapleford was General Manager - Montgomery County Division and
Manager - Purchasing; and Mr. Williams was Division Manager - Bucks
County, Manager Transmission, and Distribution Operations and Electric
Superintendent.
There are no family relationships among directors or executive
officers of the Company.
ITEM 2. PROPERTIES
The principal plants and properties of the Company are subject to the
lien of the Mortgage under which the Company's First and Refunding
Mortgage Bonds are issued.
The following table sets forth the Company's net electric generating
capacity by station at December 31, 1993:
35
38
Net Generating Estimated
Capacity (1) Retirement
Station Location (Kilowatts) Year
-------------------------------------------------------------------------------------------------------------------
Nuclear
Limerick.................................. Limerick Twp., PA............... 2,110,000 2024, 2029
Peach Bottom.............................. Peach Bottom Twp., PA........... 886,000(2) 2014
Salem..................................... Hancock's Bridge, NJ............ 942,000(2) 2016, 2020
Hydro
Conowingo................................. Harford Co., MD................. 470,000 2014
Pumped Storage
Muddy Run.................................. Lancaster Co., PA............... 880,000 2014
Fossil (Steam Turbines)
Cromby.................................... Phoenixville, PA................ 345,000 2004
Delaware.................................. Philadelphia, PA................ 250,000 (3)
Eddystone................................. Eddystone, PA................... 1,306,000 2009, 2010, 2011
Schuylkill................................ Philadelphia, PA................ 166,000 (3)
Conemaugh................................. New Florence, PA................ 352,000(2) 2005, 2006
Keystone.................................. Shelocta, PA.................... 357,000(2) 2002, 2003
Fossil (Gas Turbines)
Chester................................... Chester, PA..................... 39,000 (3)
Croydon................................... Bristol Twp., PA................ 369,000 (3)
Delaware.................................. Philadelphia, PA................ 54,000 (3)
Eddystone................................. Eddystone, PA................... 56,000 (3)
Falls..................................... Falls Twp., PA.................. 45,000 (3)
Moser..................................... Lower Pottsgrove Twp., PA....... 45,000 (3)
Richmond.................................. Philadelphia, PA................ 96,000 (3)
Schuylkill................................ Philadelphia, PA................ 28,000 (3)
Southwark................................. Philadelphia, PA................ 52,000 (3)
Salem..................................... Hancock's Bridge, NJ............ 16,000(2) 1996
Fossil (Internal Combustion)
Cromby.................................... Phoenixville, PA................ 2,750 (3)
Delaware.................................. Philadelphia, PA................ 2,750 (3)
Schuylkill................................ Philadelphia, PA................ 2,800 (3)
Keystone.................................. Shelocta, PA.................... 2,300(2) 2003
Conemaugh................................. New Florence, PA................ 2,300(2) 2006
---------
Total....................................................................... 8,876,900
=========
----------
(1) Summer rating.
(2) Company portion.
(3) Retirement dates are under on-going review by the Company. Current
plans call for the continued operation of these plants beyond 1994.
36
39
The following table sets forth the Company's major transmission and
distribution lines in service at December 31, 1993:
Voltage in Kilovolts (Kv) Conductor Miles
--------------------------------------------------------------------------
Transmission:
500 Kv.................................................. 844
220 Kv ................................................. 1,583
132 Kv ................................................. 417
66 Kv.................................................. 441
33 Kv and below........................................ 38
Distribution:
220 Kv.................................................. 109
132 Kv.................................................. 55
66 Kv.................................................. 150
33 Kv and below........................................ 51,958
At December 31, 1993, the Company's principal electric distribution
system included 12,294 pole-line miles of overhead lines and 19,595 cable
miles of underground cables.
The Company has undertaken a 10-year program to implement a 34 Kv
distribution system for a large portion of outlying suburban areas. These
areas are now primarily served by a combination of 4 Kv distribution
circuits, which are being phased out, and direct connections to 34 Kv
subtransmission lines, which are being converted to 34 Kv distribution
circuits. The new system is designed to improve the Company's ability to
meet the growing load requirements of suburban areas, improve system
reliability and reduce service interruptions.
The following table sets forth the Company's gas pipeline miles at
December 31, 1993:
Pipeline Miles
--------------
Transmission................................................ 35
Distribution................................................ 5,285
Service Piping.............................................. 4,448
-----
Total................................................... 9,768
=====
The Company has a liquefied natural gas facility located in West
Conshohocken, Pennsylvania which has a storage capacity of 1,200,000 mcf
and a sendout capacity of 200,000 mcf/day and a propane-air plant located
in Chester, Pennsylvania, with a tank storage capacity of 1,980,000
gallons and a peaking capability of 30,000 mcf/day. In addition, the
Company owns 19 natural gas city gate stations at various locations
throughout its gas service territory.
The Company owns an office building in downtown Philadelphia, in which
it maintains its headquarters, and also owns or leases elsewhere in its
37
40
service area a number of properties which are used for office, service and
other purposes. Information regarding rental and lease commitments is
incorporated herein by reference to note 14 of Notes to Consolidated
Financial Statements included in the Company's Annual Report to
Shareholders for the year 1993.
The Company maintains property insurance against loss or damage to its
principal plants and properties by fire or other perils, subject to
certain exceptions. Although it is impossible to determine the total
amount of the loss that may result from an occurrence at a nuclear
generating station, the Company maintains its $2.75 billion proportionate
share for each station. Under the terms of the various insurance
agreements, the Company could be assessed up to $35 million for property
losses incurred at any plant insured by the insurance companies (see
"ITEM 1. BUSINESS-Electric Operations"). The Company is self-insured to
the extent that any losses may exceed the amount of insurance maintained.
Any such losses, if not recovered through the ratemaking process, could
have a material adverse effect on the Company's financial condition.
ITEM 3. LEGAL PROCEEDINGS
On April 11, 1991, 33 former employees of the Company filed an amended
class action suit against the Company in the Eastern District Court on
behalf of approximately 141 persons who retired from the Company between
January and April 1990. The lawsuit, filed under the Employee Retirement
Income Security Act (ERISA), alleges that the Company fraudulently and/or
negligently misrepresented or concealed facts concerning the Company's
1990 Early Retirement Plan and thus induced the plaintiffs to retire or
not to defer retirement immediately before the initiation of the Early
Retirement Plan, thereby depriving the plaintiffs of substantial pension
and salary benefits. On June 6, 1991, the plaintiffs filed amended
complaints adding additional plaintiffs. The lawsuit names the Company,
the Company's Service Annuity Plan (SAP) and two Company officers as
defendants. The plaintiffs seek approximately $20 million in damages
representing, among other things, increased pension benefits and nine
months' salary pursuant to the terms of the Early Retirement Plan, as well
as punitive damages. On July 29, 1992, the Eastern District Court granted
the Company's motion for summary judgment and entered judgment in favor of
the Company. On May 26, 1993, the Appeals Court reversed the grant of
summary judgment and remanded the case to the Eastern District Court. On
October 18, 1993, the Company filed a petition for a writ of certiorari to
the United States Supreme Court, asking the Court to hear the case, which
petition was denied. The ultimate outcome of this matter is not expected
to have a material adverse effect on the Company's financial condition.
On May 2, 1991, 37 former employees of the Company filed an amended
class action suit against the Company, the SAP and three former Company
officers in the Eastern District Court on behalf of 147 former employees
who retired from the Company from January through June 1987. The lawsuit
was filed under ERISA and concerns the August 1, 1987 amendment to the
SAP. The plaintiffs claim that the Company concealed or misrepresented the
fact that the amendment to the SAP was planned to increase retirement
benefits and, as a consequence, they retired prior to the amendment to the
SAP and were deprived of significant retirement benefits. The complaint
does not specify any dollar amount of damages. On July 29, 1992, the
Eastern District Court granted the Company's motion for summary judgment
38
41
and entered judgment in favor of the Company. On May 26, 1993, the Appeals
Court reversed the grant of summary judgment and remanded the case to the
Eastern District Court. On October 18, 1993, the Company filed a petition
for a writ of certiorari to the United States Supreme Court, asking the
Court to hear the case, which petition was denied. The ultimate outcome of
this matter is not expected to have a material adverse effect on the
Company's financial condition.
On May 25, 1993, the Company received a letter from attorneys on
behalf of a shareholder demanding that the Company's Board of Directors
commence legal action against certain Company officers and directors with
respect to the Company's credit and collections practices. The basis of
the demand is the findings and conclusions contained in the Credit and
Collection section of the May 1991 PUC Management Audit Report prepared by
Ernst & Young. At its June 28, 1993 meeting, the Board of Directors
appointed a Special Committee of Directors to consider whether such legal
action is the best interests of the Company and its shareholders. On March
14, 1994, upon the recommendation of the report of the Special Committee,
the Board of Directors adopted a resolution refusing the shareholder demand
set forth in the May 25, 1993 demand letter, and authorizing and directing
officers of the Company to take all steps necessary to terminate the
derivative suit discussed below.
On July 26, 1993, attorneys on behalf of two shareholders filed a
shareholder derivative action in the Court of Common Pleas of Philadelphia
County against several of the Company's present and former officers
alleging mismanagement, waste of corporate assets and breach of fiduciary
duty in connection with the Company's credit and collections practices. A
similar suit by the same plaintiffs previously had been withdrawn while on
appeal after dismissal by the court for failure to first serve a demand on
the Company's Board of Directors. This action is also based on the
findings and conclusions contained in the Credit and Collection section of
the May 1991 PUC Management Audit Report prepared by Ernst & Young. The
plaintiffs seek, among other things, an unspecified amount of damages and
the awarding to the plaintiffs of the costs and disbursements of the
action, including attorneys' fees. On September 30, 1993, the Company
filed preliminary objections asking that the action be dismissed on the
grounds that it is premature. On December 6, 1993, the court denied the
Company's preliminary objections. Any monetary damages which may be
recovered, net of expenses, would be paid to the Company because the
lawsuit is brought derivatively by shareholders on behalf of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
39
42
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock is listed on the New York and Philadelphia
Stock Exchanges. At January 31, 1994, there were 219,644 owners of record
of the Company's common stock. The information with respect to the prices
of and dividends on the Company's common stock for each quarterly period
during 1992 and 1993 is incorporated herein by reference to "Operating
Statistics" in the Company's Annual Report to Shareholders for the year
1993.
The book value of the Company's common stock at December 31, 1993 was
$19.25 per share.
Dividends may be declared on common stock out of funds legally
available for dividends whenever full dividends on all series of preferred
stock outstanding at the time have been paid or declared and set apart for
payment for all past quarter-yearly dividend periods. No dividends may be
declared on common stock, however, at any time when the Company has failed
to satisfy the sinking fund obligations with respect to certain series of
the Company's preferred stock. Future dividends on common stock will
depend upon earnings, the Company's financial condition and other factors,
including the availability of cash.
The Company's Articles prohibit payment of any dividend on, or other
distribution to the holders of, common stock if, after giving effect
thereto, the capital of the Company represented by its common stock
together with its Other Paid-In Capital and Retained Earnings is, in the
aggregate, less than the involuntary liquidating value of its then
outstanding preferred stock. At December 31, 1993, such capital ($4.26
billion) amounted to about 7 times the liquidating value of the
outstanding preferred stock ($609 million).
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data for each of the last five years for the
Company and its subsidiaries is incorporated herein by reference to
"Financial Statistics" and "Operating Statistics" in the Company's
Annual Report to Shareholders for the year 1993.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The information with respect to this caption is incorporated herein by
reference to "Management's Discussion and Analysis of Financial Condition
and Results of Operations" in the Company's Annual Report to Shareholders
for the year 1993.
40
43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information with respect to this caption is incorporated herein by
reference to "Consolidated Financial Statements" and "Financial
Statistics" in the Company's Annual Report to Shareholders for the year
1993.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
41
44
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Identification of Directors.
The information required for Directors is included in the Proxy
Statement of the Company in connection with its 1994 Annual Meeting of
Shareholders to be held April 13, 1994, under the heading "Proposal 1.
Election of Directors" and is incorporated herein by reference.
(b) Identification of Executive Officers.
The information required for Executive Officers is set forth in "ITEM
1. BUSINESS-Executive Officers of the Registrant" of this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The information with respect to this caption is included in the Proxy
Statement of the Company in connection with its 1994 Annual Meeting of
Shareholders to be held April 13, 1994, under the heading "Proposal 1.
Election of Directors" and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information with respect to this caption is included in the Proxy
Statement of the Company in connection with its 1994 Annual Meeting of
Shareholders to be held April 13, 1994, under the heading "Proposal 1.
Election of Directors" and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information with respect to this caption is included in the Proxy
Statement of the Company in connection with its 1994 Annual Meeting of
Shareholders to be held April 13, 1994, under the heading "Proposal 1.
Election of Directors" and is incorporated herein by reference.
42
45
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Financial Statement Schedules
Reference (Page)
--------------------------------
Form 10-K Annual Report
Index Annual Report to Shareholders
- -----------------------------------------------------------------------------------------------------
Data incorporated by reference from the Annual Report to
Shareholders for the year 1993:
Report of Independent Accountants....................... - 18
Consolidated Statements of Income for the years ended
December 31, 1993, 1992 and 1991...................... - 19
Consolidated Balance Sheets as of December 31, 1993 and
1992.................................................. - 20
Consolidated Statements of Cash Flows for the years
ended December 31, 1993, 1992 and 1991................ - 22
Consolidated Statements of Changes in Common
Shareholders' Equity and Preferred Stock for the years
ended December 31, 1993, 1992 and 1991................ - 23
Notes to Consolidated Financial Statements.............. - 24
Data submitted herewith:
Report of Independent Accountants....................... 31 -
Schedule V - Utility Plant for the years ended
December 31, 1993, 1992 and 1991........ 32 -
Schedule VI - Accumulated Depreciation of Utility
Plant for the years ended December 31,
1993, 1992 and 1991..................... 35 -
Schedule VIII - Valuation and Qualifying Accounts for
the years ended December 31, 1993, 1992
and 1991................................ 38 -
All other schedules are omitted since the required information is not
present or is not present in amounts sufficient to require submission of
the schedule, or because the information required is included in the
consolidated financial statements and notes thereto.
With the exception of the consolidated financial statements and the
independent accountants' report listed in the above index and the
information referred to in Items 1, 2, 5, 6, 7 and 8, all of which is
included in the Company's Annual Report to Shareholders for the year 1993
and incorporated by reference into this Form 10-K Annual Report, the
Annual Report to Shareholders for the year 1993 is not to be deemed
"filed" as part of this Form 10-K.
43
46
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors
PECO Energy Company:
Our report on the consolidated financial statements of PECO Energy
Company has been incorporated by reference in this Form 10-K from page 18
of the 1993 Annual Report to Shareholders of PECO Energy Company. In
connection with our audits of such financial statements, we have also
audited the related financial statement schedules listed in the index in
Item 14 of this Form 10-K.
In our opinion, the financial statement schedules referred to above,
when considered in relation to the basic financial statements taken as a
whole, present fairly, in all material respects, the information required
to be included therein.
COOPERS & LYBRAND
2400 Eleven Penn Center
Philadelphia, Pennsylvania
January 31, 1994
44
47
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE V-UTILITY PLANT
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1993
Column A Column B Column C Column D Column E Column F
- ------------------------------------------------------------------------------------------------------------------------------
Balance at Balance at
Beginning of Additions Other End of
Classification Period at Cost Retirements Changes Period
- -------------------------------------------------------------------------------------------------------------------------------
UTILITY PLANT IN SERVICE AND HELD FOR FUTURE USE
ELECTRIC
Plant in Service
Intangible......................................... $ 30,982
Production......................................... 9,711,722
Transmission....................................... 760,348
Distribution....................................... 2,498,925
General............................................ 91,812
-------------------------------------------------------------------
TOTAL ELECTRIC PLANT IN SERVICE...................... 13,093,789
-------------------------------------------------------------------
Plant Held for Future Use............................ 8,299
-------------------------------------------------------------------
TOTAL ELECTRIC UTILITY PLANT........................... 13,102,088
-------------------------------------------------------------------
GAS
Plant in Service
Intangible......................................... 50
Production......................................... 12,875
Storage............................................ 16,294
Distribution....................................... 808,624
General............................................ 5,360
-------------------------------------------------------------------
TOTAL GAS PLANT IN SERVICE........................... 843,203
-------------------------------------------------------------------
Plant Held for Future Use ........................... 2
-------------------------------------------------------------------
TOTAL GAS UTILITY PLANT................................ 843,205
-------------------------------------------------------------------
COMMON
Plant in Service
Intangible......................................... 20,890
Land and Land Rights............................... 4,345
Structures and Improvements........................ 126,643
Office Furniture and Equipment..................... 20,707
Transportation .................................... 15,305
Tools and Miscellaneous Equipment.................. 15,469
-------------------------------------------------------------------
TOTAL COMMON PLANT IN SERVICE........................ 203,359
-------------------------------------------------------------------
Plant Held for Future Use............................ 388
-------------------------------------------------------------------
TOTAL COMMON UTILITY PLANT............................. 203,747
-------------------------------------------------------------------
TOTAL UTILITY PLANT IN SERVICE AND HELD FOR FUTURE USE... 14,149,040
-------------------------------------------------------------------
CONSTRUCTION WORK IN PROGRESS
Electric............................................. 318,641
Gas.................................................. 13,531
Common............................................... 49,075
-------------------------------------------------------------------
TOTAL CONSTRUCTION WORK IN PROGRESS ..................... 381,247
-------------------------------------------------------------------
NUCLEAR FUEL (NET OF AMORTIZATION)....................... 179,529
-------------------------------------------------------------------
TOTAL UTILITY PLANT IN SERVICE, HELD FOR FUTURE USE,
CONSTRUCTION WORK IN PROGRESS AND NUCLEAR FUEL......... 14,709,816
-------------------------------------------------------------------
CAPITALIZED LEASES
Nuclear Fuel......................................... 193,674
Electric Plant....................................... 1,028
-------------------------------------------------------------------
TOTAL LEASED PLANT....................................... 194,702
-------------------------------------------------------------------
TOTAL.................................................... $14,488,553 $507,653 $31,895 $(59,793) $14,904,518
===================================================================
<FN>
- ----------
(1) There were no project additions in excess of 2% of total assets.
Note: The detailed information required by Columns B, C, D and E is omitted since neither the total additions nor the total
deductions amount to more than 10% of the closing balance of total utility plant.
45
48
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE V- UTILITY PLANT
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1992
Column A Column B Column C Column D Column E Column F
- --------------------------------------------------------------------------------------------------------------------------------
Balance at Balance at
Beginning of Additions Other End of
Classification Period at Cost Retirements Changes Period
- ---------------------------------------------------------------------------------------------------------------------------------
UTILITY PLANT IN SERVICE AND HELD FOR FUTURE USE
ELECTRIC
Plant in Service
Intangible......................................... $ 3,566
Production......................................... 9,572,437
Transmission....................................... 755,289
Distribution....................................... 2,381,028
General............................................ 77,064
--------------------------------------------------------------------
TOTAL ELECTRIC PLANT IN SERVICE...................... 12,789,384
--------------------------------------------------------------------
Plant Held for Future Use............................ 8,005
--------------------------------------------------------------------
TOTAL ELECTRIC UTILITY PLANT........................... 12,797,389
--------------------------------------------------------------------
GAS
Plant in Service
Intangible.......................................... 50
Production.......................................... 6,424
Storage............................................. 16,340
Distribution........................................ 754,070
General............................................. 4,822
--------------------------------------------------------------------
TOTAL GAS PLANT IN SERVICE........................... 781,706
--------------------------------------------------------------------
Plant Held for Future Use ........................... 2
--------------------------------------------------------------------
TOTAL GAS UTILITY PLANT................................ 781,708
--------------------------------------------------------------------
COMMON
Plant in Service
Intangible......................................... 677
Land and Land Rights............................... 4,565
Structures and Improvements........................ 117,262
Office Furniture and Equipment..................... 18,003
Transportation Equipment........................... 6,328
Tools and Miscellaneous Equipment.................. 14,838
--------------------------------------------------------------------
TOTAL COMMON UTILITY PLANT IN SERVICE................ 161,673
--------------------------------------------------------------------
Plant Held for Future Use............................ 388
--------------------------------------------------------------------
TOTAL COMMON UTILITY PLANT............................. 162,061
--------------------------------------------------------------------
TOTAL UTILITY PLANT IN SERVICE AND HELD FOR FUTURE USE... 13,741,158
--------------------------------------------------------------------
CONSTRUCTION WORK IN PROGRESS
Electric........................................... 295,139
Gas................................................ 11,813
Common............................................. 41,840
--------------------------------------------------------------------
TOTAL CONSTRUCTION WORK IN PROGRESS ..................... 348,792
--------------------------------------------------------------------
NUCLEAR FUEL (NET OF AMORTIZATION)....................... 188,609
--------------------------------------------------------------------
TOTAL UTILITY PLANT IN SERVICE, HELD FOR FUTURE USE, ....
CONSTRUCTION WORK IN PROGRESS AND NUCLEAR FUEL.......... 14,278,559
--------------------------------------------------------------------
CAPITALIZED LEASES
Nuclear Fuel....................................... 208,761
Electric Plant..................................... 1,233
--------------------------------------------------------------------
TOTAL LEASED PLANT....................................... 209,994
--------------------------------------------------------------------
TOTAL.................................................... $14,089,350 $514,200(1) $60,095 $(54,902) $14,488,553
====================================================================
<FN>
- ----------
(1) There were no project additions in excess of 2% of total assets.
Note: The detailed information required by Columns B, C, D and E is omitted since neither the total additions nor the total
deductions amount to more than 10% of the closing balance of total utility plant.
46
49
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE V-UTILITY PLANT
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1991
Column A Column B Column C Column D Column E Column F
- -------------------------------------------------------------------------------------------------------------------------------
Balance at Balance at
Beginning of Additions Other End of
Classification Period at Cost Retirements Changes Period
- ------------------------------------------------------------------------------------------------------------------------------
UTILITY PLANT IN SERVICE AND HELD FOR FUTURE USE
ELECTRIC
Plant in Service
Intangible......................................... $ 3,566
Production......................................... 9,414,766
Transmission....................................... 710,398
Distribution....................................... 2,249,816
General............................................ 66,153
-------------------------------------------------------------------
TOTAL ELECTRIC PLANT IN SERVICE...................... 12,444,699
-------------------------------------------------------------------
Plant Held for Future Use............................ 6,675
-------------------------------------------------------------------
TOTAL ELECTRIC UTILITY PLANT........................... 12,451,374
-------------------------------------------------------------------
GAS
Plant in Service
Intangible......................................... 50
Production......................................... 6,426
Storage............................................ 16,170
Distribution....................................... 692,150
General............................................ 2,495
-------------------------------------------------------------------
TOTAL GAS PLANT IN SERVICE........................... 717,291
-------------------------------------------------------------------
Plant Held for Future Use ........................... 2
-------------------------------------------------------------------
TOTAL GAS UTILITY PLANT................................ 717,293
-------------------------------------------------------------------
COMMON
Plant in Service
Intangible......................................... 677
Land and Land Rights............................... 4,565
Structures and Improvements........................ 112,631
Office Furniture and Equipment..................... 20,179
Transportation Equipment........................... 5,783
Tools and Miscellaneous Equipment.................. 14,612
-------------------------------------------------------------------
TOTAL COMMON UTILITY PLANT IN SERVICE................ 158,447
-------------------------------------------------------------------
Plant Held for Future Use............................ 388
-------------------------------------------------------------------
TOTAL COMMON UTILITY PLANT............................. 158,835
-------------------------------------------------------------------
TOTAL UTILITY PLANT IN SERVICE AND HELD FOR FUTURE USE... 13,327,502
-------------------------------------------------------------------
CONSTRUCTION WORK IN PROGRESS
Electric............................................. 323,398
Gas.................................................. 8,431
Common............................................... 16,704
-------------------------------------------------------------------
TOTAL CONSTRUCTION WORK IN PROGRESS ..................... 348,533
-------------------------------------------------------------------
NUCLEAR FUEL (NET OF AMORTIZATION)....................... 189,566
-------------------------------------------------------------------
TOTAL UTILITY PLANT IN SERVICE, HELD FOR FUTURE USE,
CONSTRUCTION WORK IN PROGRESS AND NUCLEAR FUEL......... 13,865,601
-------------------------------------------------------------------
CAPITALIZED LEASES
Nuclear Fuel......................................... 222,346
Electric Plant....................................... 1,403
-------------------------------------------------------------------
TOTAL LEASED PLANT....................................... 223,749
-------------------------------------------------------------------
TOTAL.................................................... $13,784,066 $420,223 (1) $53,671 $(61,268) $14,089,350
===================================================================
<FN>
- ----------
(1) There were no project additions in excess of 2% of total assets.
Note: The detailed information required by Columns B, C, D and E is omitted since neither the total additions nor the total
deductions amount to more than 10% of the closing balance of total utility plant.
47
50
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VI-ACCUMULATED DEPRECIATION OF UTILITY PLANT
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1993
Column A Column B Column C Column D Column E Column F
- --------------------------------------------------------------------------------------------------------------------------------
Balance Changes Balance
Beginning Add End
Description of Year Depreciation Retirements (Deduct) (1) of Year
- --------------------------------------------------------------------------------------------------------------------------------
ELECTRIC
Production.................................. $2,328,260 $313,003 $15,112 $(11,925) $2,614,226
Transmission................................ 268,487 13,336 1,624 116 280,315
Distribution................................ 713,084 56,507 10,062 (9,702) 749,827
General..................................... 23,355 3,446 520 (773) 25,508
-------------------------------------------------------------------------
Total..................................... 3,333,186 386,292 27,318 (22,284) 3,669,876
=========================================================================
GAS
Production.................................. 2,406 473 0 0 2,879
Distribution................................ 174,556 22,248 2,979 (1,836) 191,989
Storage .................................... 12,893 526 44 (1) 13,374
General..................................... 1,122 136 8 0 1,250
-------------------------------------------------------------------------
Total................................... 190,977 23,383 3,031 (1,837) 209,492
-------------------------------------------------------------------------
COMMON.......................................... 63,154 6,680 1,551 (846) 67,437
-------------------------------------------------------------------------
Total................................... $3,587,317 416,355 $31,900 $(24,967) $3,946,805
=========================================================================
Depreciation charged to transportation ..................... (851)
Amortization of anti-trust.................................. (16)
Amortization of Conowingo Project relicensing costs......... 100
Limerick Unit No. 1 disallowance............................ (10,319)
Limerick Unit No. 2 disallowance............................ (4,424)
Amortization of Limerick Unit No. 1 declaratory
order..................................................... 14,750
Amortization of Limerick 50% common facilities
deferred depreciation and carrying charges................ 7,897
Amortization of nuclear design basis ....................... 1,460
--------
Depreciation charged to operating expenses (2)..............$424,952
========
----------
(1) Other Changes
Limerick disallowance............................ $(14,743)
Removal cost net of salvage...................... (15,257)
Amortization of Conowingo Project
relicensing costs............................. 100
Interest on decommissioning funds................ 5,708
Miscellaneous.................................... (775)
--------
Total Other Changes ......................... $(24,967)
========
(2) Includes the provision for decommissioning nuclear plants of $20,255.
48
51
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VI-ACCUMULATED DEPRECIATION OF UTILITY PLANT
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1992
Column A Column B Column C Column D Column E Column F
- --------------------------------------------------------------------------------------------------------------------------------
Balance Changes Balance
Beginning Add End
Description of Year Depreciation Retirements (Deduct) (1) of Year
- --------------------------------------------------------------------------------------------------------------------------------
ELECTRIC
Production.................................. $2,065,990 $306,319 $29,512 $(14,537) $2,328,260
Transmission................................ 262,411 13,072 6,655 (341) 268,487
Distribution................................ 677,910 55,685 12,245 (8,266) 713,084
General..................................... 22,086 3,209 1,875 (65) 23,355
-------------------------------------------------------------------------
Total..................................... 3,028,397 378,285 50,287 (23,209) 3,333,186
=========================================================================
GAS
Production.................................. 2,168 280 9 (33) 2,406
Distribution................................ 157,566 21,503 2,791 (1,722) 174,556
Storage..................................... 12,449 530 77 (9) 12,893
General..................................... 1,034 108 20 - 1,122
-------------------------------------------------------------------------
Total................................... 173,217 22,421 2,897 (1,764) 190,977
-------------------------------------------------------------------------
COMMON.......................................... 65,574 4,684 6,910 (194) 63,154
-------------------------------------------------------------------------
Total................................... $3,267,188 405,390 $60,094 $(25,167) $3,587,317
=========================================================================
Depreciation charged to transportation ..................... (452)
Amortization of anti-trust.................................. (19)
Amortization of Conowingo Project relicensing costs......... 100
Limerick Unit No. 1 disallowance............................ (10,319)
Limerick Unit No. 2 disallowance............................ (4,424)
Amortization of Limerick Unit No. 1 declaratory order....... 14,750
Amortization of Limerick 50% common facilities
deferred depreciation and carrying charges................ 7,897
Amortization of nuclear design basis........................ 856
--------
Depreciation charged to operating expenses (2)..............$413,779
========
----------
(1) Other Changes
Limerick disallowance................................. $(14,743)
Removal cost net of salvage........................... (17,456)
Amortization of Conowingo Project relicensing costs... 100
Interest on decommissioning funds..................... 6,932
--------
Total Other Changes .............................. $(25,167)
========
(2) Includes the provision for decommissioning nuclear plants of $20,255.
49
52
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VI-ACCUMULATED DEPRECIATION OF UTILITY PLANT
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1991
Column A Column B Column C Column D Column E Column F
- -------------------------------------------------------------------------------------------------------------------------------
Other
Balance Changes Balance
Beginning of Add End of
Description Year Depreciation Retirements (Deduct) (1) Year
- --------------------------------------------------------------------------------------------------------------------------------
ELECTRIC
Production.................................. $1,809,514 $300,434 $29,574 $(14,384) $2,065,990
Transmission................................ 253,410 12,630 3,201 (428) 262,411
Distribution................................ 648,075 53,153 16,352 (6,966) 677,910
General..................................... 20,494 1,807 139 (76) 22,086
-------------------------------------------------------------------------
Total..................................... 2,731,493 368,024 49,266 (21,854) 3,028,397
-------------------------------------------------------------------------
GAS
Production.................................. 1,893 275 - - 2,168
Distribution................................ 144,380 19,585 4,044 (2,355) 157,566
Storage Plant............................... 11,956 519 31 5 12,449
General..................................... 959 75 - - 1,034
-------------------------------------------------------------------------
Total................................... 159,188 20,454 4,075 (2,350) 173,217
-------------------------------------------------------------------------
COMMON.......................................... 60,739 4,738 327 424 65,574
-------------------------------------------------------------------------
Total................................... $2,951,420 393,216 $53,668 $(23,780) $3,267,188
========================================================================
Depreciation charged to transportation ..................... (632)
Amortization of anti-trust.................................. (34)
Amortization of Conowingo Project relicensing costs......... 100
Limerick Unit No. 1 disallowance............................ (10,319)
Limerick Unit No. 2 disallowance............................ (4,424)
Amortization of Limerick Unit No. 1 declaratory order....... 14,750
Amortization of Limerick 50% common facilities'
deferred depreciation and carrying charges................ 7,897
Other....................................................... 18
--------
Depreciation charged to operating expenses (2)..............$400,572
========
----------
(1) Other Changes:
Limerick disallowances..................................$(14,743)
Removal cost, net of salvage............................ (14,933)
Amortization of Conowingo Project relicensing costs..... 100
Interest on decommissioning funds....................... 5,796
--------
Total Other Changes ................................$(23,780)
========
(2) Includes the provision for decommissioning nuclear plants of $20,027.
50
53
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE VIII-VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
Column A Column B Column C-Additions Column D Column E
- ---------------------------------------------------------------------------------------------------------------------
Charged to
Balance at Charged to Other Balance at
Beginning of Costs and Accounts Deductions End of
Description Period Expenses -Describe -Describe (1) Period
- ----------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 1993
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS $17,916 $40,758 $ -- $43,588 $15,086
------------------------------------------------------------------------
TOTAL................. $17,916 $40,758 $ -- $43,588 $15,086
========================================================================
FOR THE YEAR ENDED DECEMBER 31, 1992
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS $30,028 $42,195 $ -- $54,307 $17,916
------------------------------------------------------------------------
TOTAL............................. $30,028 $42,195 $ -- $54,307 $17,916
========================================================================
FOR THE YEAR ENDED DECEMBER 31, 1991
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS $30,000 $50,036 $ -- $50,008 $30,028
------------------------------------------------------------------------
TOTAL............................. $30,000 $50,036 $ -- $50,008 $30,028
========================================================================
<FN>
----------
(1) Write-off of individual accounts receivable.
51
54
Exhibits
Certain of the following exhibits have been filed with the Securities
and Exchange Commission (Commission) pursuant to the requirements of the
Acts administered by the Commission. Such exhibits are identified by the
references following the listing of each such exhibit and are incorporated
herein by reference under Rule 24 of the Commission's Rules of Practice.
Certain other instruments which would otherwise be required to be listed
below have not been so listed because such instruments do not authorize
securities in an amount which exceeds 10% of the total assets of the
Company and its subsidiaries on a consolidated basis and the Company agrees
to furnish a copy of any such instrument to the Commission upon request.
Exhibit No. Description
- --------------------------
3-1 Amended and Restated Articles of Incorporation of PECO Energy
Company.
3-2 Bylaws of the Company, adopted February 26, 1990 and amended
January 24, 1994.
4-1 First and Refunding Mortgage dated May 1, 1923 between The
Counties Gas and Electric Company (predecessor to the Company)
and Fidelity Trust Company, Trustee (First Fidelity Bank,
National Association, successor), (Registration No. 2-2881,
Exhibit B-1).
4-2 Supplemental Indentures to the Company's First and Refunding
Mortgage:
52
55
Dated as of File Reference Exhibit No.
- ------------------------------------------------------------------------------
September 1, 1926 2-2881 B-1(a)
May 1, 1927 2-2881 B-1(b)
May 1, 1927 2-2881 B-1(c)
November 1, 1927 2-2881 B-1(d)
January 31, 1931 2-2881 B-1(e)
February 1, 1931 2-2881 B-1(f)
March 1, 1937 2-2881 B-1(g)
December 1, 1941 2-4863 B-1(h)
November 1, 1944 2-5472 B-1(i)
December 1, 1946 2-6821 7-1(j)
February 1, 1948 2-7381 7-1(k)
January 1, 1952 2-9329 4(b)-13
May 1, 1953 2-10201 4(b)-14
December 1, 1953 2-10568 4(b)-15
April 1, 1955 2-11536 2(b)-16
September 1, 1957 2-13562 2(b)-17
May 1, 1958 2-14020 2(b)-18
December 1, 1958 2-14528 2(b)-19
October 1, 1959 2-15609 2(b)-20
May 1, 1964 2-25628 4(b)-21
October 15, 1966 2-25628 4(b)-22
June 1, 1967 2-26430 2(b)-23
October 1, 1967 2-28242 2(b)-23
March 1, 1968 2-34051 2(b)-24
September 10, 1968 2-34051 2(b)-25
August 15, 1969 2-35939 2(b)-26
February 1, 1970 2-37020 2(b)-27
May 1, 1970 2-38849 2(b)-28
December 15, 1970 2-41081 2(b)-29
August 1, 1971 2-42402 2(b)-30
December 15, 1971 2-44195 2(b)-31
June 15, 1972 2-46625 2(b)-32
January 15, 1973 2-49842 2(b)-33
January 15, 1974 2-49849 2(b)-34
October 15, 1974 2-51887 2(b)-35
April 15, 1975 2-54182 2(b)-36
August 1, 1975 2-55423 2(b)-37
March 1, 1976 2-56749 2(b)-38
August 1, 1976 2-58198 2(b)-39
February 1, 1977 2-58198 2(b)-40
March 15, 1977 2-59177 2(b)-41
July 15, 1977 2-60743 2(b)-42
March 15, 1978 2-65604 2(b)-43
October 15, 1979 2-69086 (b)(1)-49
October 15, 1980 2-72802 4-45
March 1, 1981 2-72802 4-46
March 1, 1981 2-72802 4-47
July 1, 1981 2-76238 4-48
53
56
Dated as of File Reference Exhibit No.
- -----------------------------------------------------------------------------
September 15, 1981 2-76238 4-49
April 1, 1982 2-79269 4-50
October 1, 1982 2-83875 4-51
June 15, 1983 1983 Form 10-K 4-2(a)
November 15, 1984 1984 Form 10-K 4-2(a)
December 1, 1984 1984 Form 10-K 4-2(b)
May 15, 1985 1985 Form 10-K 4-2(a)
October 1, 1985 1985 Form 10-K 4-2(b)
November 15, 1985 1985 Form 10-K 4-2(c)
November 15, 1985 1985 Form 10-K 4-2(d)
June 1, 1986 1986 Form 10-K 4-2(a)
November 1, 1986 1986 Form 10-K 4-2(b)
November 1, 1986 1986 Form 10-K 4-2(c)
April 1, 1987 33-14613 4(c)-62
July 15, 1987 Form 8-K dated July 21, 1987 4(c)-63
July 15, 1987 Form 8-K dated July 21, 1987 4(c)-64
August 1, 1987 33-17438 4(c)-65
October 15, 1987 Form 8-K dated October 7, 1987 4(c)-66
October 15, 1987 Form 8-K dated October 7, 1987 4(c)-67
April 15, 1988 Form 8-K dated April 11, 1988 4(e)-68
April 15, 1988 Form 8-K dated April 11, 1988 4(e)-69
June 15, 1989 33-31289 4(e)-70
October 1, 1989 Form 8-K dated October 6, 1989 4(e)-71
October 1, 1989 Form 8-K dated October 6, 1989 4(e)-72
October 1, 1989 Form 8-K dated October 18, 1989 4(e)-73
October 15, 1990 1990 Form 10-K 4(e)-74
October 15, 1990 1990 Form 10-K 4(e)-75
April 1, 1991 1991 Form 10-K 4(e)-76
December 1, 1991 1991 Form 10-K 4(e)-77
January 15, 1992 Form 8-K dated January 27, 1992 4(e)-78
April 1, 1992 March 31, 1992 Form 10-Q 4(e)-79
April 1, 1992 March 31, 1992 Form 10-Q 4(e)-80
June 1, 1992 June 30, 1992 Form 10-Q 4(e)-81
June 1, 1992 June 30, 1992 Form 10-Q 4(e)-82
July 15, 1992 June 30, 1992 Form 10-Q 4(e)-83
September 1, 1992 1992 Form 10-K 4(e)-84
September 1, 1992 1992 Form 10-K 4(e)-85
March 1, 1993 1992 Form 10-K 4(e)-86
March 1, 1993 1992 Form 10-K 4(e)-87
May 1, 1993 March 31, 1993 Form 10-Q 4(e)-88
May 1, 1993 March 31, 1993 Form 10-Q 4(e)-89
May 1, 1993 March 31, 1993 Form 10-Q 4(e)-90
August 15, 1993 Form 8-A dated August 19, 1993 4(e)-91
August 15, 1993 Form 8-A dated August 19, 1993 4(e)-92
August 15, 1993 Form 8-A dated August 19, 1993 4(e)-93
November 1, 1993 Form 8-A dated October 27, 1993 4(e)-94
November 1, 1993 Form 8-A dated October 27, 1993 4(e)-95
54
57
4-3 Deposit Agreement with respect to $7.96 Cumulative Preferred
Stock (Form 8-K dated October 20, 1992, Exhibit 4-5).
4-4 PECO Energy Company Dividend Reinvestment and Stock Purchase
Plan, as amended January 28, 1994 (Post-Effective Amendment
No. 1 to Registration No. 33-43523, Exhibit 28).
10-1 Pennsylvania-New Jersey-Maryland Interconnection Agreement
dated September 26, 1956 (Registration No. 2-13340, Exhibit
13-40) and agreements supplemental thereto:
Dated as of File Reference Exhibit No.
-----------------------------------------------------------------------------
March 1, 1965 2-38342 5-1(a)
January 1, 1971 2-40368 5-1(b)
June 1, 1974 2-51887 5-1(c)
September 1, 1977 1989 Form 10-K 10-1(a)
October 1, 1980 1989 Form 10-K 10-1(b)
June 1, 1981 1989 Form 10-K 10-1(c)
10-2 Agreement, dated November 24, 1971, between Atlantic City
Electric Company, Delmarva Power & Light Company, Public
Service Electric and Gas Company and the Company for ownership
of Salem Nuclear Generating Station (1988 Form 10-K, Exhibit
10-3); supplemental agreement dated September 1, 1975; and
supplemental agreement dated January 26, 1977 (1991 Form 10-K,
Exhibit 10-3).
10-3 Agreement, dated November 24, 1971, between Atlantic City
Electric Company, Delmarva Power & Light Company, Public
Service Electric and Gas Company and the Company for ownership
of Peach Bottom Atomic Power Station; supplemental agreement
dated September 1, 1975; and supplemental agreement dated
January 26, 1977 (1988 Form 10-K, Exhibit 10-4).
10-4 Deferred Compensation and Supplemental Pension Benefit Plan
(1981 Form 10-K, Exhibit 10-16).*
10-5 Philadelphia Electric Company Stock Price Appreciation Plan,
effective June 1, 1988 (1988 Form 10-K, Exhibit 4-7).*
10-6 Philadelphia Electric Company 1989 Long-Term Incentive Plan
(Registration No. 33-30317, Exhibit 28).*
12-1 Ratio of Earnings to Fixed Charges.
12-2 Ratio of Earnings to Combined Fixed Charges and Preferred
Dividends.
55
58
13 Management's Discussion and Analysis of Financial Condition
and Results of Operations, Consolidated Financial Statements,
Notes to Consolidated Financial Statements, Financial
Statistics, and Operating Statistics of the Annual Report to
Shareholders for the year 1993.
22 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
24 Powers of Attorney.
----------
* Compensatory plans or arrangements in which directors or officers of the
Company participate and which are not available to all employees.
Reports on Form 8-K
During the quarter ended December 31, 1993, the Company filed a
Current Report on Form 8-K, dated December 28, 1993 reporting information
under "ITEM 5. OTHER EVENTS" relating to the Company's name change.
Subsequent to December 31, 1993, the Company filed no Current Reports
on Form 8-K.
56
59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant, PECO ENERGY COMPANY, has duly caused
this annual report to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Philadelphia, and Commonwealth
of Pennsylvania, on the 16th day of March 1994.
PECO ENERGY COMPANY
By /s/ J. F. PAQUETTE, JR.
------------------------------------------
J. F. Paquette, Jr., Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934,
this annual report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date
- --------------------------------------------------------------------------------------------------
/s/ J. F. PAQUETTE, JR. Chairman of the Board and
- ---------------------------------- Director (Principal Executive
J. F. Paquette, Jr. Officer) March 16, 1994
/s/ C. A. MCNEILL, JR. President and Director
- ---------------------------------- (Principal Operating Officer) March 16, 1994
C. A. McNeill, Jr.
/s/ K. G. LAWRENCE Senior Vice President
- ---------------------------------- (Principal Financial and
K. G. Lawrence Accounting Officer) March 16, 1994
This annual report has also been signed below by C. A. McNeill, Jr.,
Attorney-in-Fact, on behalf of the following Directors on the date
indicated:
SUSAN W. CATHERWOOD ROBERT D. HARRISON
M. WALTER D'ALESSIO JOSEPH C. LADD
R. G. GILMORE EDITHE J. LEVIT
R. H. GLANTON KINNAIRD R. MCKEE
JAMES A. HAGEN JOSEPH J. MCLAUGHLIN
NELSON G. HARRIS JOHN M. PALMS
RONALD RUBIN
By /s/ C. A. MCNEILL, JR.
----------------------------
C. A. McNeill, Jr., March 16, 1994
Attorney-in-Fact