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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, 1995
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
(Exact name of registrant as specified in its charter)
Pennsylvania 23-0970240
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P.O. Box 8699
2301 Market Street, Philadelphia, PA (215) 841-4000
(Address of principal executive offices) (Registrant's telephone number,
including area code)
19101
(Zip Code)
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Securities registered pursuant to Section 12(b) of the Act:
First and Refunding Mortgage Bonds (Registered on the New York
Stock Exchange):
6 1/8% Series due 1997 (*) 7 3/8% Series due 2000 6 1/2% Series due 2003 7 1/8% Series due 2023
5 3/8% Series due 1998 5 5/8% Series due 2001 6 3/8% Series due 2005 7 3/4% Series 2 due 2023
7 1/4% Series due 2024
__________________
(*) Also registered on the Philadelphia Stock Exchange
Cumulative Preferred Stock -- without par value (Registered on the New York
and Philadelphia Stock Exchanges):
$7.96 Series $4.68 Series $4.40 Series $4.30 Series
$3.80 Series
Common Stock -- without par value (Registered on the New York and
Philadelphia Stock Exchanges)
9.00% Cumulative Monthly Income Preferred Securities, Series B, $25 stated
value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by the
Company (Registered on the New York Stock Exchange)
Trust Receipts of PECO Energy Capital Trust I, each representing a 8.72%
Cumulative Monthly Income Preferred Security, Series B, $25 stated value, issued
by PECO Energy Capital, L.P. and unconditionally guaranteed by the Company
(Registered on the New York Stock Exchange)
Securities registered pursuant to Section 12(g) of the Act:
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. [ ]
The aggregate market value of the registrant's common stock (only voting
stock) held by non-affiliates of the registrant was $6,832,147,699 at January
31, 1996.
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: 222,255,816 shares outstanding at
January 31, 1996.
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DOCUMENTS INCORPORATED BY REFERENCE (In Part)
Annual Report of PECO Energy Company to Shareholders for the year 1995
is incorporated in part in Parts I, II and IV hereof, as specified herein.
Proxy Statement of PECO Energy Company in connection with its
1996 Annual Meeting of Shareholders is incorporated in part in
Part III hereof, as specified herein.
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TABLE OF CONTENTS
Page No.
PART I
ITEM 1. BUSINESS.......................................................1
The Company....................................................1
Electric Operations............................................1
General...................................................1
Limerick Generating Station...............................4
Peach Bottom Atomic Power Station.........................5
Salem Generating Station..................................6
Fuel...........................................................8
Nuclear...................................................8
Coal.....................................................10
Oil......................................................11
Natural Gas..............................................11
Gas Operations................................................11
Segment Information...........................................12
Rate Matters..................................................12
Construction..................................................14
Capital Requirements and Financing Activities.................15
Employee Matters..............................................16
Environmental Regulations.....................................17
Water....................................................17
Air......................................................17
Solid and Hazardous Waste................................18
Costs....................................................22
Competition...................................................22
Telecommunications............................................24
PECO Energy Capital Corp. and Related Entities................24
Executive Officers of the Registrant..........................25
ITEM 2. PROPERTIES....................................................27
ITEM 3. LEGAL PROCEEDINGS.............................................29
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...........30
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS..............................30
ITEM 6. SELECTED FINANCIAL DATA.......................................31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS......................31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...................31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE...................31
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............31
ITEM 11. EXECUTIVE COMPENSATION........................................31
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT...............................................32
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................32
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K.................................................33
Financial Statements and Financial Statement Schedule.........33
REPORT OF INDEPENDENT ACCOUNTANTS.............................34
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS..............35
Exhibits......................................................36
Reports on Form 8-K...........................................39
SIGNATURES
i
PART I
ITEM 1. BUSINESS
The Company
PECO Energy Company (Company), incorporated in Pennsylvania in 1929, is an
operating utility which provides electric and gas service to the public in
southeastern Pennsylvania. The total area served by the Company covers 2,107
square miles. Electric service is supplied in an area of 1,972 square miles with
a population of about 3,700,000, including 1,600,000 in the City of
Philadelphia. Approximately 94% of the electric service area and 64% of retail
kilowatthour (kWh) sales are in the suburbs around Philadelphia, and 6% of the
service area and 36% of such sales are in the City of Philadelphia. 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 has the
necessary franchise rights, which are generally non-exclusive, to operate in the
areas served.
The Company is subject to regulation by the Pennsylvania Public Utility
Commission (PUC) as to retail electric and gas rates, issuances of securities
and certain other aspects of the Company's operations and by the Federal Energy
Regulatory Commission (FERC) as to wholesale electric and transmission rates.
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
Protection (PDEP). The Company's Muddy Run Pumped Storage Project and the
Conowingo Hydroelectric Project are subject to the licensing jurisdiction of the
FERC. 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 1995, 90.2% of the Company's operating revenues and 93.5% of its
operating income were from electric operations. Electric sales and operating
revenues for 1995 by class of customer are set forth below:
Operating
Sales Revenues
(millions of kWh) (millions of $)
Residential ................... 10,859 $1,401
Small commercial and industrial 6,299 739
Large commercial and industrial 15,976 1,147
Other ......................... 860 137
------ ------
Service territory ........ 33,994 3,424
Interchange sales ............. 496 17
Sales to other utilities ...... 14,041 334
------ ------
Total .................... 48,531 $3,775
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Energy from the Company's installed generating capacity together with power
purchases are utilized to satisfy the requirements of jurisdictional customers,
to meet sales commitments to other utilities and to make spot sales.
1
The net installed electric generating capacity (summer rating) of the
Company and its subsidiaries at December 31, 1995 was as follows:
Type of Capacity Megawatts % of Total
Nuclear ....................... 4,040 44.5%
Mine-mouth, coal-fired ........ 709 7.8
Service-area, coal-fired ...... 725 8.0
Oil-fired ..................... 1,176 13.0
Gas-fired ..................... 201 2.2
Hydro (includes pumped storage) 1,392 15.3
Internal combustion ........... 835 9.2
----- -----
Total ..................... 9,078(1)(2) 100.0%
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<FN>
- ---------------
(1) Includes capacity available for sale to other utilities.
(2) See "Fuel" for sources of fuels used in electric generation.
</FN>
As a result of the developing wholesale generation market, the Company has
increased both its wholesale power purchases and sales. In the ordinary course
of its business, the Company enters into long-term and short-term commitments to
buy and sell power. At December 31, 1995, the Company had 1,199 megawatts (MW)
of installed generating capacity available for sales to others. In addition,
during 1995, the Company entered into an agreement to purchase energy associated
with 300 MW from 1996 through 2000 from an unaffiliated utility. The Company
also has agreements with other utilities to sell energy and/or capacity. The
Company has long-term agreements over the next five years with unaffiliated
utilities to sell energy associated with 1,185 MW of capacity. These power sales
agreements extend from 1996 to 2023. See note 4 of Notes to Consolidated
Financial Statements included in the Company's Annual Report to Shareholders for
the year 1995.
Annual and quarterly operating results can be significantly affected by
weather. Traditionally, sales of electricity are higher in the first and third
quarters due to colder weather and warmer weather, respectively. The maximum
hourly demand on the Company's system was 7,244 MW which occurred on August 4,
1995. The Company estimates its generating reserve margin for 1996 to be 26%.
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.
The Company is a member of the Pennsylvania-New Jersey-Maryland
Interconnection Association (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. The maximum PJM demand of 48,524 MW occurred on August 2,
1995 when PJM's installed capacity (summer rating) was 55,962 MW. The Company's
installed capacity for 1996-99 is expected to be sufficient for the Company to
meet its obligation to supply its PJM reserve margin share during that period.
During 1995, the Company notified the FERC of its intention to propose
initiatives to increase wholesale electric competition in the Mid-Atlantic
region served by PJM. See "Competition."
The Company's nuclear-generated electricity is supplied by Limerick
Generating Station (Limerick) Units No. 1 and No. 2 and Peach Bottom Atomic
Power 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 1,115 MW; Peach Bottom Units No. 2
and No. 3 each has a capacity of 1,093 MW, of which the Company is entitled to
464 MW of each unit; 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.
2
The Company's nuclear generating facilities represent approximately 45% of
its installed generating capacity and 65% of its investment in electric plant.
In 1995, approximately 50% of the Company's electric output was generated from
nuclear sources. Changes in regulations by the NRC that require a substantial
increase in capital expenditures for the Company's nuclear generating facilities
or that result in increased operating costs of nuclear generating units could
adversely affect the Company.
The Price-Anderson Act sets the limit of liability of approximately $8.9
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 $79 million per reactor per incident, payable at no more than $10 million per
reactor per incident per year. This assessment is subject to inflation and state
premium taxes. If the damages from an incident at a licensed nuclear facility
exceed $8.9 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, following an
accident, the facility is in a safe and stable condition and can be maintained
in such condition. Within 30 days of stabilizing 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 permit either 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 will 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 have been in the fund if contributions had been made over the normal
life of the facility. The Company is unable to predict what effect these
requirements may have on the timing of the availability of insurance proceeds 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 $46 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 or results of operations.
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 21-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 $14 million per year.
NRC regulations require that licensees of nuclear generating facilities
demonstrate that funds will be available in certain minimum amounts 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 used to decommission such nuclear facilities. The
Company's ownership portion of decommissioning costs is approximately $643
million expressed in 1990 dollars to be collected over the life of each
generating unit. Under current rates, which reflect decommissioning costs of
$643 million, the
3
Company collects and expenses approximately $20 million annually from customers
for decommissioning the Company's ownership portion of its nuclear units. At
December 31, 1995, the Company held $223 million in trust accounts, representing
amounts recovered from customers and net realized and unrealized investment
earnings thereon, to fund future decommissioning costs. Based on a recent
Company study, the Company's share of the cost to decommission its nuclear units
is estimated to be $1.2 billion in 1995 dollars. The Company will ultimately
seek to recover through the ratemaking process increased decommissioning costs,
although such recovery is not assured. In February 1996, the Financial
Accounting Standards Board (FASB) issued an Exposure Draft entitled "Accounting
for Certain Liabilities Related to Closure or Removal of Long-Lived Assets,"
which proposes, among other things, changes in the recognition, measurement and
classification of decommissioning costs for nuclear generating stations. The
proposed statement would be effective for years beginning after December 15,
1996, and applies to all entities having either legal or constructive
obligations (defined as an obligation which the entity has "little or no
discretion to avoid") for closure or removal of long-lived assets. The FASB is
expected to issue a final pronouncement by the end of 1996. For additional
information concerning nuclear decommissioning, see note 4 of Notes to
Consolidated Financial Statements included in the Company's Annual Report to
Shareholders for the year 1995.
Limerick Generating Station
Limerick Unit No. 1 achieved a capacity factor of 88% in 1995 and 85% in
1994. Limerick Unit No. 2 achieved a capacity factor of 85% in 1995 and 93% in
1994. 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 1996 and 1995,
respectively.
On May 24, 1995, the NRC issued its periodic Systematic Assessment of
Licensee Performance (SALP) Report for Limerick for the period September 26,
1993 through April 1, 1995. Limerick achieved ratings of "1," the highest of the
three rating categories, in all four functional areas - Operations, Maintenance,
Engineering and Plant Support. The NRC stated that, overall, it observed an
excellent level of performance at Limerick. The NRC noted continued strong
performance in the Operations and Engineering areas during this SALP period and
improved performance was noted in the Maintenance and Plant Support areas. The
NRC stated that factors contributing to this level of performance included
excellent management oversight, along with excellent interdepartmental
communication and coordination of activities. Particularly, the NRC noted the
Company's excellent planning and execution of the two refueling outages during
the SALP period and the aggressive use of probabilistic safety assessment in
scheduling outage and non-outage maintenance activities. The NRC also stated
that, in recognition of Limerick's superior performance, the next SALP period
for Limerick has been extended to 24 months and both the number of resident NRC
inspectors and planned total inspection hours have been reduced.
In October 1990, General Electric Company (GE) reported that crack
indications were discovered near the seam welds of the core shroud assembly in a
GE Boiling Water Reactor (BWR) located outside the United States. As a result,
GE issued a letter requesting that the owners of GE BWRs take interim corrective
actions, including a review of fabrication records and visual examinations of
accessible areas of the core shroud seam welds. Each of the reactors at Limerick
and Peach Bottom is a GE BWR. Initial examination of Limerick Unit No. 1 was
completed during the February 1996 refueling outage. Although crack indications
were identified at one location, the Company concluded that there is a
substantial margin for each core shroud weld to allow for continued operation of
Unit No. 1 for a minimum of the next two operating cycles. Initial examination
of Unit No. 2 has been scheduled for the refueling outage planned for January
1999 in accordance with industry experience and guidance. Peach Bottom Unit No.
3 was initially examined during its refueling outage in the fall of 1993.
Although crack indications were identified at two locations, the Company
presented its finding to the NRC and recommended continued operation of Unit No.
3 for a two-year cycle. Unit No. 3 was re-examined during its last refueling
outage in the fall of 1995 and the extent of cracking identified was determined
to be within industry-established guidelines. In a letter to the NRC dated
November 3, 1995, the Company concluded that there is a substantial margin for
each core shroud weld to allow for continued operation of Unit No. 3 until its
next refueling outage, scheduled for 1997, at which time it will be reinspected.
Peach Bottom Unit No. 2 was
4
examined in October 1994 during its last refueling outage and the inspection
revealed a minimal number of flaws. In a letter dated November 7, 1994, the
Company submitted its findings to the NRC and also recommended continued
operation of Unit No. 2 until its next refueling outage, scheduled for September
1996, at which time it will be reinspected. The Company is also participating in
a GE BWR Owners Group to develop long-term corrective actions.
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 corrective 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. The Company has been in contact with the NRC regarding
the Company's long-term measures to address Thermo-Lag fire barrier issues. In
1995, the Company completed its engineering re-analysis for both Peach Bottom
and Limerick. This re-analysis identified proposed modifications to be performed
over the next several years at both plants in order to implement the long-term
measures addressing the concern over Thermo-Lag use.
In 1992, the Company requested authorization from the NRC to rerate the
maximum reactor-core power levels of each Limerick unit by 5% to 1,115 MW. The
NRC approved the Company's request for Unit No. 2 on February 16, 1995 and for
Unit No. 1 on January 24, 1996. Modifications to Unit No. 2 were completed
during the Unit's 1995 refueling outage. Modifications to Unit No. 1 were
completed during the Unit's February 1996 refueling outage.
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 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 at the Point Pleasant Pumping Station, transports it to the
Bradshaw Reservoir (Point Pleasant Project), then to the east and main branches
of the Perkiomen Creek and finally to Limerick. The supplemental cooling water
system also provides water for public use to two Montgomery County water
authorities. The Company has obtained all permits for the construction and
operation of the supplemental cooling water system. Certain of the permits
relating to the operation of the system must be renewed periodically.
The Company has also entered into an agreement with a municipality to
secure a backup source of water for the operation of Limerick should the amount
of water from the supplemental cooling water system not be sufficient. Should
the supplemental cooling water system be completely unavailable, 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 98% in 1995 and 81%
in 1994. Peach Bottom Unit No. 3 achieved a capacity factor of 78% in 1995 and
98% in 1994. 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 1994 and
1995, respectively.
On December 5, 1995, the NRC issued its periodic SALP Report for Peach
Bottom for the period May 1, 1994 to October 15, 1995. Peach Bottom achieved
ratings of "1" in the areas of Operations, Maintenance and Plant Support. The
area of Engineering achieved a rating of "2." Overall, the NRC observed
excellent performance at Peach Bottom during the assessment period. Station
management oversight, effective use of performance enhancement at all levels of
the organization and other measures in identifying and evaluating issues
5
contributed to the strong performance. The NRC noted performance improvements in
all of the assessment areas, particularly in Maintenance and Plant Support.
Although the NRC noted that excellent performance was often displayed in the
Engineering area, errors in modification work, in addition to some other lapses,
indicated inconsistent engineering performance. The Company is taking actions to
further improve Peach Bottom performance.
By letter dated October 18, 1994, the NRC approved the Company's request to
rerate the authorized maximum reactor-core power levels of each Peach Bottom
unit by 5% to 1,093 MW. The amendment of the Unit No. 2 facility operating
license was effective upon the date of the NRC approval letter, and the
associated hardware changes were implemented during the Unit No. 2 refueling
outage in the fall of 1994. The amendment for Unit No. 3 was issued by the NRC
on July 18, 1995 and the associated hardware changes were implemented during the
Unit No. 3 refueling outage in the fall of 1995.
In addition to the matters discussed above, see "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 26% in 1995 and 59% in 1994.
Salem Unit No. 2 achieved a capacity factor of 21% in 1995 and 58% in 1994.
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 1995.
Salem Units No. 1 and No. 2 have been out of service since May 16, 1995 and
June 7, 1995, respectively, due to various operational and technical problems.
The Company has been informed by PSE&G that since the shutdown of Salem, PSE&G
has been engaged in an assessment of each unit to identify and complete the work
necessary to achieve restart. PSE&G has stated that it will keep each unit off
line until it is satisfied that the unit is ready to return to service and to
operate reliably over the long term and the NRC has agreed that the unit is
sufficiently prepared to restart. On June 9, 1995, the NRC issued a Confirmatory
Action Letter documenting these commitments of PSE&G.
On December 11, 1995, PSE&G presented its restart plan for both units to
the NRC at a public meeting. On February 13, 1996, the NRC staff issued a letter
to PSE&G indicating that it had concluded that PSE&G's overall restart plan, if
implemented effectively, should adequately address the numerous Salem issues to
support a plant restart, and describing further actions the NRC will undertake
to confirm that PSE&G's actions have resulted in the necessary performance
improvements to support plant restart.
The Company has been informed by PSE&G that as a part of PSE&G's review, an
examination is being performed on the steam generators, which are large heat
exchangers used to produce steam to drive the turbines. Within the industry,
certain pressurized water reactors (PWRs) other than Salem have experienced
cracking in a sufficient number of the steam generator tubes to require various
modifications to these tubes and replacement of the steam generators in some
cases. Until the current outage, regular periodic inspections of the steam
generators for each Salem unit have resulted in repairs of a small number of
tubes well within NRC limits. As a result of the experience of other utilities
with cracking in steam generator tubes, in April 1995, the NRC issued a generic
letter to all utilities with PWRs. This generic letter requested utilities with
PWRs to conduct steam generator examinations with more sensitive inspection
devices capable of detecting evidence of degradation. Subsequently, PSE&G
conducted steam generator inspections of the Salem units using the latest
technology available, including a new, more sensitive, eddy current testing
device.
With respect to Salem Unit No. 1, the most recent inspection of the steam
generators is not complete, but partial results from eddy current inspections
conducted in February 1996 indicate degradation in a significant number of
tubes. The inspections are continuing and PSE&G has decided to remove several
tubes for laboratory examination to confirm the results of the inspections.
Removal of the tubes is expected to commence in April and preliminary results of
the state of Salem Unit No. 1 tubes from the subsequent laboratory examinations
6
should be known in the third quarter of 1996. However, based on the results of
inspections to date, PSE&G has concluded that the Salem Unit No. 1 outage, which
was expected to be completed in the second quarter of 1996, will be required to
be extended for a substantial additional period to evaluate the state of the
steam generators and to subsequently determine an appropriate course of action.
Degradation of steam generators in PWRs has become of increasing concern for the
nuclear industry. Nationally and internationally, utilities have undertaken
actions to repair or replace steam generators. In the extreme, degradation of
steam generators has contributed to the retirement of several American nuclear
power reactors. After the Salem Unit No. 1 tubes are fully examined, PSE&G will
be able to evaluate its course of action in light of NRC and other industry
requirements.
The examination of the Salem Unit No. 2 generators was completed in January
1996 using the same inspection procedure used in the examination of Salem Unit
No. 1. The results of the Salem Unit No. 2 inspection are being reviewed again
to confirm their results in light of the experience with Salem Unit No. 1.
Although this review has not yet been completed, results to date appear to
confirm that the condition of the Salem Unit No. 2 steam generators are well
within current operating limits at the present time. PSE&G has also removed
tubes from Salem Unit No. 2 steam generators for laboratory analysis to confirm
the results of this testing, the results of which should be known in May.
PSE&G had planned to return Salem Unit No. 1 to service in the second
quarter of 1996 and Salem Unit No. 2 in the third quarter of 1996. As a result
of the extent of the recently discovered degradation in the Salem Unit No. 1
steam generators, PSE&G is focusing its efforts on returning Salem Unit No. 2 to
service in the third quarter of 1996. The additional steam generator inspections
and testing on Salem Unit No. 2 are not expected to adversely affect the timing
of its restart. However, because the timing of the restart is subject to
satisfactory completion of the requirements of the restart plan, as determined
by PSE&G and the NRC, no assurance can be given that the projected return date
will be met. For information concerning additional costs associated with the
shutdown of Salem, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and note 24 of Notes to Consolidated
Financial Statements in the Company's Annual Report to Shareholders for the year
1995 and "Rate Matters."
The Company has been informed by PSE&G that on January 3, 1995, the NRC
issued its periodic SALP Report for Salem for the period June 20, 1993 to
November 5, 1994. Salem received ratings of "3" in the areas of Operations and
Maintenance, a rating of "2" in the area of Engineering, and a rating of "1" in
the area of Plant Support. The NRC noted an overall decline in performance and
evidenced particular concern with plant and operator challenges caused by
repetitive equipment problems and personnel errors. The NRC also noted that
although PSE&G has initiated several comprehensive actions within the past year
to improve plant performance, and that some recent incremental gains have been
made, these efforts have yet to noticeably change overall performance at Salem.
The Company has been informed by PSE&G that PSE&G's own assessments, as
well as those by the NRC and the Institute of Nuclear Power Operations, indicate
that additional efforts are required to further improve operating performance,
and that PSE&G is committed to taking the necessary actions to address Salem's
performance needs. It is anticipated that the NRC will maintain a close watch on
Salem's performance and corrective actions related to the Salem shutdown. No
assurance can be given as to what, if any, further or additional actions may be
taken or required by the NRC to improve Salem's performance.
In addition to the matters discussed above, see "Legal Proceedings" and
"Environmental Regulations -- Water."
7
Fuel
The following table shows the Company's sources of electric output for 1995
and as estimated for 1996:
1995 1996 (Est.) (1)
Nuclear ....................................... 50.0% 54.5%
Mine-mouth, coal-fired ........................ 9.5 9.6
Service-area, coal-fired ...................... 6.2 8.5
Oil-fired ..................................... 1.8 3.2
Gas-fired ..................................... 3.6 4.2
Hydro (includes pumped storage) ............... 1.3 2.6
Internal combustion ........................... 0.3 0.1
Purchased, interchange and nonutility generated 27.3 17.3
---- ----
100.0% 100.0%
===== =====
<FN>
- ---------------
(1) Does not reflect the extended outage beyond June 1996 of Salem Unit No. 1
due to cracking in steam generator tubes.
</FN>
The following table shows the Company's average fuel cost used to generate
electricity:
1991 1992 1993 1994 1995
Nuclear
Cost per million Btu(1) $ 0.64 $ 0.53 $ 0.56 $ 0.53 $ 0.47
Coal
Mine-mouth plants
Cost per ton ........ 37.26 33.75 32.73 33.30 32.68
Cost per million Btu 1.51 1.36 1.32 1.34 1.32
Service-area plants
Cost per ton ........ 50.24 45.25 43.38 38.76 38.82
Cost per million Btu 2.00 1.78 1.66 1.51 1.51
Oil
Residual
Cost per barrel ..... 19.42 15.94 15.87 16.22 14.92
Cost per million Btu 3.11 2.53 2.50 2.54 2.40
Distillate
Cost per barrel ..... 29.90 24.96 27.21 22.77 20.74
Cost per million Btu 5.12 4.26 4.15 3.87 3.66
Gas
Cost per mcf ........ -- 3.05 2.86 2.31 2.13
Cost per million Btu -- 2.96 2.77 2.25 2.00
<FN>
- ------
(1) British thermal unit.
</FN>
Nuclear
The cycle of production and utilization of nuclear fuel includes the mining
and milling of uranium ore; the conversion of uranium concentrates 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 the supply of uranium
concentrates for Limerick and Peach Bottom which extend through 2002. On
February 23, 1995, two companies which supply uranium concentrates to the
Company filed petitions for bankruptcy protection under Chapter 11 of the
Bankruptcy Code. The Company has contracts with the two companies to supply
approximately half of the Company's 1995 and 1996 requirements for uranium
concentrates. In addition, one of the companies is under contract to supply
approximately 25% of the Company's uranium concentrate requirements for the
period 1997 to 2002. The Company has made alternative arrangements
8
with other suppliers to satisfy its short-term requirements for uranium
concentrates. The Company is also finalizing arrangements with another supplier
to satisfy the Company's longer-term needs. The Company does not anticipate any
difficulty in obtaining its requirements for uranium concentrates. 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.
PSE&G has informed the Company that it does not anticipate any difficulty in
obtaining its requirements for uranium concentrates. 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 ... (1) (2) 2003
Limerick Unit No. 2 ... (1) (2) 2004
Peach Bottom Unit No. 2 (1) (2) 1999
Peach Bottom Unit No. 3 (1) (2) 1998
Salem Unit No. 1 ...... 2000 (3) 2004
Salem Unit No. 2 ...... 2000 (3) 2005
<FN>
- ---------------
(1) The Company has commitments for 100% of its conversion services for
Limerick and Peach Bottom through 1997. Approximately 40% of the conversion
services requirements are covered through 2001. The Company does not
anticipate any difficulty in obtaining necessary conversion services for
Limerick and Peach Bottom.
(2) The Company has contractual commitments for enrichment services for
Limerick and Peach Bottom with the United States Enrichment Corporation.
These commitments represent 100% of the enrichment requirements through
1998 and 70% through 1999. The Company does not anticipate any difficulty
in obtaining necessary enrichment services for Limerick and Peach Bottom.
(3) PSE&G has contractual commitments for 100% of enrichment requirements
through 1998; approximately 50% through 2002; and approximately 30% through
2004. The Company has been informed by PSE&G that PSE&G does not anticipate
any difficulty in obtaining necessary enrichment services for Salem.
</FN>
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 Company currently stores all spent nuclear fuel from its
nuclear generating facilities in on-site, spent-fuel storage pools. By letter
dated November 29, 1994, the NRC approved the Company's request to install new
high-density, spent-fuel storage racks at Limerick, which will provide for
storage capacity to 2007. The new configuration will be designed to accommodate
rod consolidation. Spent-fuel racks at Peach Bottom have storage capacity until
2000 for Unit No. 2 and 2001 for Unit No. 3. Options for expansion of storage
capacity at Peach Bottom, including rod consolidation, are being investigated.
The Company has been informed by PSE&G that as a result of reracking the two
spent-fuel pools at Salem, the spent-fuel storage capability of Salem Units No.
1 and No. 2 is estimated to be 2008 and 2012, respectively.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE was to begin
accepting spent fuel for permanent off-site storage no later than 1998. The DOE
has stated that it has 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. In June 1994, a number of
utilities and state agencies, including the PUC, filed a lawsuit against the DOE
seeking a determination of the DOE's legal obligation to accept fuel by 1998.
The DOE has stated that it will not be able to open a permanent, high-level
nuclear waste repository until 2015, at the earliest. The DOE stated that the
delay was a result of federal budget cuts, the DOE 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. Legislation has been introduced in Congress for
the construction of a temporary storage
9
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 the DOE include offsetting a portion of the
financial burden associated with the costs of continued on-site storage of spent
fuel after 1998. 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 mil
($.001) per kWh of net nuclear generation. The 1995 charge collected by the
Company from its customers for spent-fuel disposal was $21 million. The DOE may
revise this charge as necessary for full-cost recovery of nuclear fuel disposal.
As a by-product of their operations, nuclear generating units, including
those in which the Company owns an interest, produce Low Level Radioactive Waste
(LLRW). LLRW is accumulated at each facility and permanently disposed of at a
federally licensed disposal facility. The Company is currently shipping LLRW
generated at Peach Bottom and Limerick to the site located in Barnwell, South
Carolina for disposal. Due to the uncertainty of the continued availability of
LLRW disposal sites, on-site storage facilities were constructed at Peach Bottom
and Limerick, each with five-year storage capacities.
The Company is also pursuing alternative disposal strategies for LLRW
generated at Peach Bottom and Limerick, including an aggressive LLRW reduction
program. Pennsylvania is the host site for LLRW generators located in
Pennsylvania, Delaware, Maryland and West Virginia and is pursuing a permanent
disposal site through a volunteer siting process. The Company has contributed
$12 million towards the total cost of a permanent Pennsylvania disposal site.
The Company has been informed by PSE&G that it has an on-site LLRW storage
facility at Salem, with a five-year storage capacity. PSE&G ships LLRW generated
at Salem to Barnwell, South Carolina and currently uses the Salem facility for
interim storage. PSE&G has also advised the Company that New Jersey also plans
to host a LLRW disposal site. The Company, as a Salem co-owner, has paid
$857,000 as its share of the New Jersey siting costs.
The National Energy Policy Act of 1992 (Energy Act) requires, among other
things, that utilities with nuclear reactors 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 $54 million
for such costs at December 31, 1995. The Company is currently recovering these
costs through the Energy Cost Adjustment (ECA).
The Company is currently recovering in rates the costs for nuclear
decommissioning and decontamination (based on 1990 cost estimates) and
spent-fuel storage. 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. For additional information concerning
decommissioning, see "Electric Operations - General."
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 1996 through 1999; and a total of 6,500,000
tons for the years 2000 through 2004. At December 31, 1995, approximately 20% of
Conemaugh's fuel requirements were secured by a long-term contract and 21% by
several short-term contracts.
10
The Company has entered 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, 1996, the Company had
contracts with two suppliers for 1.5 million tons per year or approximately 80%
of expected annual requirements. Both contracts expire on December 31, 2000.
The coal requirements of each station not covered by existing contracts are
met through additional short-term contracts or spot purchases from 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 sufficient to meet the
estimated residual fuel oil needs of its oil-fired generating units through June
1996, when current orders expire and new yearly orders begin. Purchase orders
for distillate fuel oil are expected to meet the Company's needs through June
1996, when current orders expire and new yearly orders begin.
Natural Gas
The Company obtains natural gas for electric generation through a
combination of short-term orders and spot purchases made on the open market, as
well as through the Company's own City Gate Sales Tariff. The Company obtains
the limited quantities of natural gas used by the auxiliary boilers and
pollution control equipment at Eddystone through the same means. The Company has
the capability to use either oil or natural gas at Cromby Unit No. 2 and
Eddystone Units No. 3 and No. 4.
Gas Operations
During 1995, 9.8% of the Company's operating revenues and 6.5% of its
operating income were from gas operations. Gas sales and operating revenues for
1995 by class of customer are set forth below:
Operating
Sales Revenues
(mmcf) (millions of $)
House heating ......................... 31,848 $ 240
Residential (other than house heating) 1,516 15
Commercial and industrial ............. 19,422 129
Other ................................. 1,184 4
------- -------
Total gas sales ................... 53,970 388
Gas transported for customers ......... 48,531 22
------- -------
Total gas sales and gas transported 102,501 $ 410
======= =======
Annual and quarterly operating results can be significantly affected by
weather. Traditionally, sales of gas are higher in the first and fourth quarters
due to colder weather.
The Company's natural gas supply is provided by purchases from a number of
suppliers for terms of up to five 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
transportation contracts is 98.1 million dekatherms. Peak gas is provided by the
Company's liquefied natural gas facility and propane-air plant (see "ITEM 2.
PROPERTIES").
11
Through service agreements with Texas Eastern, Transcontinental, Equitrans,
Inc. and CNG Transmission Corporation, underground storage capacity of 21.5
million dekatherms is under contract to the Company. Natural gas from
underground storage represents approximately 40% of the Company's 1995-96
heating season supplies.
As a result of FERC Order 636 and the subsequent restructuring of the
interstate pipeline industry, the gas distribution merchant function has come
under continued pressure as smaller customers elect to purchase non- utility gas
supplies. This has raised significant issues at the state level regarding the
long-term role of the gas distribution utility as a merchant. Other policy
issues have arisen regarding the obligation to serve by the utility, the erosion
of tax base, the potential for stranded costs associated with long-term
contracts, the implications for social programs now supported by utilities and
overall system reliability.
PECO Gas Supply Company, a wholly owned subsidiary, was formed in 1995 as
an unregulated marketing enterprise. PECO Gas Supply Company is a member of a
natural gas buying cooperative, also formed in 1995, to enhance reliability of
service and access less expensive gas supplies for its eight gas utility
members.
Eastern Pennsylvania Exploration Company, a wholly owned subsidiary, is a
party to several joint ventures formed to develop natural gas resources in the
Gulf Coast area. These joint ventures do not contribute to the Company's natural
gas supply. The Company is engaged in pursuing the sale of these joint ventures.
Segment Information
Segment information is incorporated herein by reference to note 2 of Notes
to Consolidated Financial Statements included in the Company's Annual Report to
Shareholders for the year 1995.
Rate Matters
In 1995, approximately 90% 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 and transmission rates are
regulated by the FERC. For information concerning wholesale electric
competition, see "Competition."
The Company has agreed with the PUC not to seek an increase in electric
base rates before April 1, 1999 except under specified circumstances for items
such as energy cost adjustments, changes in state taxes, changes in federal
taxes, demand side management surcharges, and increases in nuclear plant
decommissioning expenses or funding requirements and spent nuclear fuel disposal
expenses.
The Company's last electric base rate case, intended primarily to recover
costs associated with Limerick Unit No. 2 and associated common facilities, was
filed in 1989. The Company voluntarily excluded 400 MW of capacity from base
rates, and the PUC denied a return on common equity on an additional 399 MW of
capacity. Under its electric tariffs, the Company is allowed to retain for
shareholders any proceeds above the average energy cost for sales of this 399 MW
of capacity and/or associated energy. In addition, beginning April 1994, the
Company became entitled to share in the benefits which result from the operation
of both Limerick Units No. 1 and No. 2 through the retention of 16.5% of the
energy savings, subject to certain limits. During 1995, 1994 and 1993, the
Company recorded as revenue net of fuel costs $79, $68 and $38 million,
respectively, as a result of the sale of the 399 MW of capacity and/or
associated energy and the Company's share of Limerick energy savings.
On February 22, 1996, the PUC approved the Company's petition for a
declaratory accounting order to change the estimated depreciable lives of
certain of the Company's electric plant. The order approves the reduction of the
terminal dates by ten years, for depreciation accrual purposes only, of Limerick
Units No. 1 and
12
No. 2 and associated common facilities, the utilization of new life spans for
various categories of electric production plant and changes in the remaining
life estimates for transmission, distribution, general and common plant. The
order also approves the amortization over a nine-year period of $331 million of
deferred Limerick costs representing $240 million of carrying charges and
depreciation associated with 50% of Limerick common facilities and $91 million
of operating and maintenance expenses, depreciation and accrued carrying charges
on the Company's 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. The changes will increase depreciation
and amortization on assets associated with Limerick by approximately $100
million per year and decrease depreciation and amortization on other Company
assets by approximately $10 million per year, for a net increase in depreciation
and amortization of approximately $90 million per year. The order will not
increase rates charged to customers. The changes will be effective October 1,
1996.
Effective January 1995, in accordance with a PUC Joint Petition, the
Company increased electric base rates by $25 million per year to recover the
increased costs, including the annual amortization of the transition obligation
(over 18 years) deferred in 1994 and 1993, associated with the implementation of
Statement of Financial Accounting Standards (SFAS) No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." See note 7 of Notes
to Consolidated Financial Statements included in the Company's Annual Report to
Shareholders for the year 1995. Subsequent to January 1, 1995, retail electric
non-pension postretirement benefits expense in excess of the amount allowed to
be recovered under the Joint Petition may not be deferred for future rate
recovery. In accordance with the Joint Petition, any of the parties to the Joint
Petition may elect to void the settlement in the event current rate recovery of
non-pension postretirement benefits expense is ultimately disallowed as a result
of the Office of Consumer Advocate's appeal to the Supreme Court of Pennsylvania
of cases involving other Pennsylvania utilities. In such event, the Company
would refund to customers, with interest, any increased base rate amounts
collected.
The Company recovers fuel and gas costs through base rates and various
automatic adjustment clauses. The Company's ECA, applicable to retail electric
service, is adjusted annually. Pursuant to a PUC proceeding applicable to all
Pennsylvania gas utilities, effective March 1, 1996, purchased gas cost rates
are adjusted quarterly in lieu of annual filings. 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 and gas costs. In addition, the PUC may investigate
outages of electric generating units which exceed 120 days or if the annual
capacity factor of a unit is less than 50% to determine whether to deny the
recovery of replacement power costs.
The Company's ECA provides for recovery of 100% of the difference between
the Company's PUC- jurisdictional costs of fuel, energy interchange and
purchased power and the costs billed to customers in base rates. 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, 1995, the Company's system nuclear capacity factor was 72%, which entitled
the Company to a bonus of $2.5 million.
On March 6, 1996, the Company filed its new ECA to become effective April
1, 1996. The ECA filing proposes a change from a credit value of 5.086 mils per
kWh to a credit value of 4.424 mils per kWh, which represents a decrease in
annual revenue of $21.7 million. The ECA filing reflects a settlement agreement
with the Office of Consumer Advocate, the Office of Small Business Advocate and
a group of the Company's industrial customers, which was filed with the ECA,
under which recovery of $33.1 million of replacement power costs associated with
the shutdown of Salem would be denied for the reconciliation period ended
January 31, 1996, offset by an additional $6 million adjustment to the Company's
nuclear performance bonus. The approval of the ECA, including the joint
settlement agreement, is pending before the PUC.
13
On May 31, 1995, the Company filed Purchased Gas Cost (PGC) No. 12 rates
for the period December 1, 1995 through November 30, 1996, which reflected a
$0.80 per thousand cubic feet (mcf) decrease in natural gas sales rates. On
November 13, 1995, the PUC approved the Joint Settlement setting a $0.88 per mcf
decrease, effective December 1, 1995, representing a decrease in annual revenue
of $48.4 million. Effective March 1, 1996, the first quarterly adjustment of the
PGC resulted in an increase of $0.335 per mcf in natural gas sales rates.
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 tax rates not recovered in base rates.
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 PUC order would have permitted surcharge recovery of DSM
program costs and allowed utilities to earn an incentive on kWh saved from DSM.
The PUC order also would have permitted utilities to defer "lost revenues," with
interest, for eventual recovery in the next base rate case. On January 9, 1995,
the Commonwealth Court issued a decision in which it upheld the PUC's order
related to surcharge recovery of DSM program costs, but reversed the PUC's
decision to award DSM incentives through a surcharge. The Commonwealth Court
also remanded all issues related to "lost revenue" recovery for further
consideration by the PUC. The PUC appealed the decision to the Supreme Court of
Pennsylvania which affirmed the Commonwealth Court's decision.
In addition to the matters discussed above, see "Competition" for a
discussion of the PUC's investigation of electric power competition issues.
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 1991-95,
gross property additions (excluding capital leases) amounted to $2.6 billion and
retirements amounted to $272 million, resulting in a net increase of
approximately 17% in the Company's gross utility plant. Investment in new plant
and equipment in 1995 amounted to $480 million. At December 31, 1995,
construction work in progress, excluding nuclear fuel, aggregated $494 million.
The following table shows the Company's most recent estimates of capital
expenditures for plant additions and improvements for 1996 and for 1997-99:
(Millions of $)
1996 1997-99
Electric:
Production .................. $ 158 $ 402
Nuclear fuel ................ 67 139
Transmission and distribution 117 280
Other electric .............. 2 9
------ ------
Total electric .......... 344 830
Gas .............................. 55 158
Other ............................ 139 254
------ ------
Total ....................... $ 538 $1,242
====== ======
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 16 of Notes to Consolidated Financial Statements
included in the Company's Annual Report to Shareholders for the year 1995.
14
Capital Requirements and Financing Activities
The following table shows the Company's most recent estimates of capital
requirements for 1996 and for 1997-99:
(Millions of $)
1996 1997-99
Construction .............................. $ 538 $1,242
Long-term debt maturities and sinking funds 401 867
------ ------
Total capital requirements ....... $ 939 $2,109
====== ======
The Company expects to meet its capital requirements, including long-term
debt maturities, for 1996 with internally generated funds and short-term
borrowings; however, for 1997-99 the Company expects internally generated funds
to more than satisfy its capital requirements including long-term debt
maturities. The estimates of capital requirements do not include any amounts for
unscheduled refundings of higher-dividend preferred stock or higher-interest
debt, which refundings are dependent on future market conditions and internal
cash generation.
The following table shows the Company's financing activities for 1995:
(Millions of $)
Term Loan:
Floating Rate due 1997 ................... $175
Trust Receipts, each representing a Company
Obligated Mandatorily Redeemed
Preferred Securities of a Partnership (1):
8.72% ............................... 81
Pollution Control:
Floating Rate due 1996 ................... 8
----
$264
====
<FN>
- ---------------
(1) Issued through PECO Energy Capital, L.P., of which a wholly owned
subsidiary of the Company is the general partner.
</FN>
The long-term debt and the Trust Receipts (recorded in the financial
statements as Company Obligated Mandatorily Redeemed Preferred Securities of a
Partnership) issued during 1995 replaced debt and preferred stock carrying
higher after-tax rates of interest and dividends. During 1995, the Company
utilized cash from operations, proceeds from the sale of its subsidiary
Conowingo Power Company and $100 million from the sale of an undivided interest
in trade receivables to reduce debt by $401 million.
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, 1995 was 4.94
times. Earnings coverages under the Mortgage for the calendar years 1994 and
1993 were 3.48 and 4.20 times, respectively. At December 31, 1995, the most
restrictive issuance test of the Mortgage related to available property
additions. At December 31, 1995, the Company had at least $1.44 billion of
available property additions against which $864 million of mortgage bonds could
have been issued. In addition,
15
at December 31, 1995, the Company was entitled to issue approximately $3.5
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, 1995 was 2.74 times. Earnings coverage under the
Articles for the calendar years 1994 and 1993 was 2.05 and 2.47 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:
1991 1992 1993 1994 1995
Ratio of Earnings to Fixed Charges..................... 2.55 2.43 3.15 2.66 3.49
Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividends......................... 2.14 2.06 2.67 2.32 3.18
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, 1995, the Company had a total of $517 million outstanding
under unsecured term-loan agreements with banks with maturities extending to
1997. Most of the Company's unsecured debt agreements contain cross-default
provisions to the Company's other debt obligations.
The Company has a $300 million commercial paper program supported by a $400
million revolving credit agreement. At December 31, 1995, there was no
commercial paper outstanding. At December 31, 1995, the Company and its
subsidiaries had formal and informal lines of credit with banks aggregating $221
million against which there was no short-term debt outstanding. The Company's
bank lines are comprised of both committed and uncommitted lines of credit. As
of December 31, 1995, the Company had no compensating balance agreements with
any bank.
Employee Matters
The Company and its subsidiaries had 7,217 employees at December 31, 1995.
None of the Company's employees are represented by a union. In 1993, in a
National Labor Relations Board (NLRB) certified election, a majority of
non-management employees voted to continue not to be represented by a union.
On March 7, 1995, a New Jersey local of the International Brotherhood of
Electrical Workers (IBEW) filed two petitions with the NLRB to hold a
certification election to determine whether a group of production and
maintenance employees from Eddystone and Cromby want the IBEW to represent them.
The petitions seek to establish separate bargaining units for 225 employees from
Eddystone and 70 employees from Cromby. The petitions cover craft and technical
employees, including operators, but exclude office clerical, professional,
supervisory and management employees.
On March 22, 1995, the Utility Workers Union of America, AFL-CIO (UWUA)
filed a petition with the NLRB to hold a certification election to determine
whether certain production and maintenance employees from Peach Bottom and
Limerick want the UWUA to represent them. The petition seeks a bargaining unit
of
16
approximately 600 employees composed of all maintenance employees and all
control room and alternate control room operators and auxiliary operators,
instrumental and control technicians, health physics technicians, chemistry
technicians, material handlers and technicians, and rad waste technicians. The
petition excludes security guards, clerical and supervisory employees. On March
23, 1995, the NLRB issued an order consolidating for hearing the three
petitions. From April through September, the NLRB conducted hearings regarding
the appropriateness of the petitioned units and the eligibility issues for those
units. The Company has taken the position that the only appropriate bargaining
unit is the same system-wide unit that was certified by the NLRB for the 1993
election, and that it will oppose any attempt by outside interests to organize
its employees. An NLRB decision is pending.
On October 2, 1995, ten days after the record in proceedings discussed
above were closed, the UWUA filed another petition seeking certification of a
bargaining unit consisting of all production and maintenance employees of the
Consumer Energy Services Group. The Company unsuccessfully sought to consolidate
this petition with the other three petitions. Hearings regarding the latest UWUA
petition are scheduled to begin in April 1996.
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. On
January 11, 1995, researchers at the University of North Carolina released the
results of an EMF study in which the Company had participated. The researchers
stated that this study does not resolve the fundamental question of whether
magnetic fields cause cancer. 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.
Public concerns about the possible health risks of exposure to EMF have,
and are expected in the future to, adversely affect the costs of, and time
required to, site new distribution and transmission facilities and upgrade
existing facilities.
Water
The Company has been informed by PSE&G that PSE&G is implementing the 1994
New Jersey Pollutant Discharge Elimination System permit issued for Salem which
requires, among other things, water intake screen modifications and wetlands
restoration. In addition, PSE&G is seeking permits and approvals from various
agencies needed to fully implement the special conditions of the permit. No
assurances can be given as to receipt of any such additional permits or
approvals. The estimated capital cost of compliance with the final permit is
approximately $100 million, of which the Company's share is 42.59% and is
included in the Company's capital requirements for 1996 and 1997-98. PSE&G must
apply to renew the Salem permit in March 1999 which renewal application must
provide updated demonstrations for review by the New Jersey Department of
Environmental Protection and Energy (NJDEPE).
Air
Air quality regulations promulgated by the PDEP 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
17
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. Flue-gas
desulfurization systems (scrubbers) have been installed at Conemaugh Units No. 1
and No. 2 to reduce SO2 emissions to meet the 1995 Phase I requirements of the
Amendments. The Company's share of the capital costs to construct the scrubbers
and make other related improvements at Conemaugh was approximately $78 million.
Units No. 1 and No. 2 at Keystone are subject to the Phase II SO2 and NOx limits
of the Amendments which must be met by January 1, 2000. The Company and the
other Keystone co-owners are evaluating the Phase II compliance options for
Keystone, including the purchase of SO2 emission allowances and the installation
of scrubbers.
The Company's service-area, coal-fired generating units at Eddystone and
Cromby are equipped with scrubbers and their SO2 emissions meet the SO2 emission
rate limits of both Phase I and Phase II of the Amendments. The Company has
completed the implementation of measures, including the installation of NOx
emissions controls and the imposition of certain operational constraints, to
comply with the Reasonably Available Control Technology limitations of the
Amendments. The Company's capital expenditures to satisfy these compliance
requirements were approximately $19 million. The Company expects that the cost
of compliance with anticipated air-quality regulations may be substantially
higher due to further limitations on permitted NOx emissions. As a result of its
prior investments in scrubbers for Eddystone and Cromby and its investment in
nuclear and hydroelectric 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 affect the Company's business. The
Amendments establish stringent new control measures for geographical regions
which have been determined by the EPA to not meet National Ambient Air Quality
Standards; establish limits on the purchase and operation of motor vehicles and
require increased use of alternative fuels; establish stringent controls on
emissions of toxic air pollutants and provide for 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.
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. In addition, the Company is subject to the Resource Conservation
and Recovery Act (RCRA) which governs treatment, storage and disposal of solid
and hazardous wastes.
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 Company 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
18
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. A settlement has been reached among the PRPs, the
federal and private PRPs, the Commonwealth of Kentucky and the EPA concerning
their respective roles and responsibilities in conducting remedial activities at
the site. Under the settlement, the private PRPs will perform the initial
remedial work at the site and the Commonwealth of Kentucky will assume
responsibility for long-range maintenance and final remediation of the site. The
Company estimates that it will be responsible for $600,000 of the remediation
costs to be incurred by the private PRPs. On June 5, 1995, a consent decree,
which included the terms of the settlement, was filed with the United States
District Court for the Eastern District of Kentucky. The United States
Department of Justice, following a public comment period, filed a motion with
the court for entry of the decree. The PRPs have entered into a contract for the
design and implementation of the remedial plan and preliminary work has
commenced.
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 miscellaneous
electrical equipment at a site located in Philadelphia, Pennsylvania (the Metal
Bank of America site). 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 Company's share of
the cost of the RI/FS was approximately 30%. On October 14, 1994, the PRPs
submitted to the EPA the RI/FS which identified a range of possible remedial
alternatives for the site from taking no action to removal of essentially all
contaminated material with an estimated cost range of $2 million to $90 million.
On July 19, 1995, the EPA issued a proposed plan for remediation of the site
which involves removal of contaminated soil, sediment and groundwater and which
the EPA estimates would cost approximately $17 million to implement. On October
18, 1995, the PRPs submitted comments to the EPA on the proposed plan which
identified several inadequacies with the plan, including substantial
underestimates of the costs associated with remediation. Until the Record of
Decision has been issued by the EPA, the Company cannot estimate its share of
the cost to implement the selected remedy.
By notice issued in September 1985, the EPA notified the Company that it
has been identified as a PRP for the costs associated with the cleanup of a site
(Berks Associates/Douglasville site) where waste oils generated from Company
operations were transported, treated, stored and disposed. 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. On September 29, 1992, the Company and 169
other parties were served with a third-party complaint joining these parties as
additional defendants. Subsequently, an additional 150 parties were joined as
defendants. A group of approximately 100 PRPs with allocated shares of less than
1%, including the Company, have formed a negotiating committee to negotiate a
settlement offer with the EPA. In December 1994, the EPA proposed a de minimis
PRP settlement which would require the Company to pay approximately $800,000 in
exchange for the EPA agreeing not to sue, take administrative action under
CERCLA for recovery of past or future response costs or seek injunctive relief
with respect to the site. The Company has notified the EPA that it wishes to
participate with other eligible PRPs in the de minimus settlement, and is
currently awaiting approval of the settlement.
In June 1989, a group of PRPs (Metro PRP Group) entered into an
Administrative Order on Consent (AOC) with the EPA pursuant to which they agreed
to perform certain removal activities at the Metro Container Superfund Site
located in Trainer, Pennsylvania. In January 1990, the Metro PRP Group notified
the Company that the group considered the Company to be a PRP at the site based
on evidence which it believes indicates between 200 and 300 empty Company drums
were transported to the site. The Company was invited to participate in the
allocation process and was further informed that, unless it agreed to sign the
AOC, the Company risked either being named in a cost recovery action brought by
the EPA or in a contribution action to be filed by the Metro PRP Group. In
response, the Company notified the Metro PRP Group that it would be
19
interested in participating in the allocation process. The Metro PRP Group has
proposed a settlement which would involve the Company paying less than $10,000
towards the costs of a removal action estimated to cost approximately $5
million. The Company has requested additional information from the Metro PRP
Group.
In October 1995, the Company, along with over 500 other companies, received
a General Notice from the EPA advising that the Company had been identified as
having sent hazardous substances to the Spectron/Galaxy Superfund Site and
requesting the companies to conduct an RI/FS at the site. The Company had
previously been identified as a de minimus PRP and paid $2,100 to settle an
earlier phase. Additionally, the Company had participated in a PRP agreement and
consent order related to further work at the Spectron site. In conjunction with
the EPA's General Notice, the existing PRP group has proposed a settlement
which, based on the volume of hazardous substances sent to the Spectron site by
the Company, would allow the Company to settle the matter as a de minimus party
for less than $10,000.
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 were deposited at the site by a
third party. The Company was 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. Settlement negotiations are
ongoing. In February 1995, the Company was named as an additional defendant in a
private party class action seeking damages associated with the GEMS site. The
Company settled the private party class action for $52,500.
On October 16, 1989, the EPA and the NJDEPE commenced a civil action in the
United States District Court for the District of New Jersey 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. The direct and
third-party defendants are presently involved in settlement negotiations
involving an allocation process.
In November 1987, the Company received correspondence from the EPA which
indicated that the EPA was investigating the source, extent and nature of the
release or threatened release of hazardous substances from the Blosenski
Landfill located in West Caln Township, Chester County, Pennsylvania (Blosenski
Landfill Superfund Site). The EPA letter requested information on several
Blosenski entities and affiliates (Blosenski entities) and also whether any
wastes generated by the Company had been transported to, stored, treated or
disposed at the Blosenski Landfill Superfund Site. In January 1988, the Company
notified the EPA that, after searching its files and records, it was unable to
locate or identify any information related to the Blosenski entities or
activities conducted at the Blosenski Landfill Superfund Site. Subsequently, on
July 8, 1992, the Company was notified by a group of PRPs who had been ordered
by the EPA to implement one portion of the four-part remedial plan for the site,
that based on information which it believed indicated Company wastes were
disposed of at the site, the group considered the Company to be responsible for
a share of the cleanup and remediation costs. The PRP group advised the Company
that unless it voluntarily joined the existing PRP group, the Company risked
being named as a defendant in a contribution lawsuit which had been filed
against certain other PRPs in federal court. On August 3, 1992, the PRP group
served the Company with a subpoena which required the production of Company
documents and records relating to Company operations and waste disposal
practices and procedures. In September 1992, the Company informed the PRP group
that due to its inability to identify any pertinent records in its own files or
confirm the PRP group's allegations, that it did not, at that time, intend to
join the Blosenski PRP Group or contribute to the remediation costs. In
addition, the Company submitted documentation which responded to some of the
subpoena requests and notified the PRP group of its objection to others. On
September 7, 1995, the federal court approved a consent decree which required
the site owner and approximately 20 PRPs to implement an estimated $13 million
remedy at the site and reimburse the federal government and the Commonwealth of
Pennsylvania $5 million for past costs and oversight costs related to the
cleanup.
20
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 (BROS) site which requested information on various
haulers who transported hazardous and solid waste materials to the BROS site.
Information gathered pursuant to the subpoena indicates that one of the haulers
associated with the BROS site picked up and transported waste generated by the
Company. Additionally, the party participants possess information which they
believe connects the Company to the site. At the invitation of the party
participants, the Company along with several others (voluntary participants) 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 the Company's potential involvement at the BROS site. On May 27,
1993, the Company provided the EPA with the same documents gathered in response
to the subpoena served by the party participants. The voluntary participants are
presently engaged in negotiations with the party participants.
On March 3, 1989, the Company received a Notice of Violation from the PDEP
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 PDEP required the Company to initiate sampling to
determine the scope of the contamination. The Company conducted sampling and
ground water monitoring and submitted the results to the PDEP 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
PDEP a revised remedial clean-up strategy. On March 9, 1993, the PDEP accepted
the Company's revised remedial clean-up strategy. The Company is implementing
the remedial clean-up strategy accepted by the PDEP, which is expected to cost
approximately $2 million over a period of three to five years.
On November 30, 1995, the Company was added as a third party defendant in
an existing suit alleging that the Company is responsible for sending waste to
the Cinnaminson Ground Water Contamination Site located in the Township of
Cinnaminson in Burlington County, New Jersey. The Company joined with other
third party defendants in filing a motion to dismiss the complaint for failure
to state a claim. While the parties await a ruling by the court, they will
participate in a court-ordered mediation process. The Company is currently
unable to estimate the cost of any potential corrective action.
The Company has been named as a defendant in a Superfund matter involving
the Greer Landfill in South Carolina. The Company is currently involved in
settlement discussions with the plaintiff. The Company is currently unable to
estimate the cost of any potential corrective action.
The Company has identified 23 sites where former 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 various levels of activities at these sites, including
initial evaluation to determine the existence and nature of the contamination,
detailed evaluation to determine the extent of the contamination and the
necessity and possible methods of remediation, and implementation of
remediation. Seven of the sites are currently in the detailed evaluation or
remediation stage. At December 31, 1995, the Company had accrued approximately
$13 million for investigation and remediation of these manufactured gas plant
sites. The Company expects that it will incur additional liabilities with
respect to these sites, which cannot be reasonably estimated at this time.
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.
On June 4, 1993, the Company entered into a Corrective Action Consent Order
(CACO) from the EPA under RCRA. The CACO 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.
In October 1994, the Company entered into an agreement with Clean Harbors, the
successor to Chem Clear, pursuant to which the Company will be responsible for
approximately 25%
21
of the costs incurred under the CACO and Clean Harbors will be responsible for
75% of the costs. The Company estimates that its share of the costs to comply
with the CACO will be approximately $2.5 million. At December 31, 1995, the
Company had spent $1.0 million to comply with the CACO. Until completion of the
required investigation, the Company is unable to predict the nature and cost of
any potential corrective action.
Costs
At December 31, 1995, the Company had accrued $27 million for various
investigation and remediation costs that can be reasonably estimated, including
approximately $13 million for investigation and remediation of former
manufactured gas plant sites. The Company cannot currently predict whether it
will incur other significant liabilities for additional investigation and
remediation costs at sites presently identified or additional sites which may be
identified by the Company, environmental agencies or others or whether all such
costs will be recoverable through rates or from third parties.
The Company's budget for capital requirements for 1996 and its most recent
estimate of capital requirements for 1997-98 for compliance with environmental
requirements total $80 million. This estimate includes the Company's share of
the costs to comply with the revised NJDEPE permit for Salem, but does not
include any amounts that may be required 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.
Competition
Over the last few years, legislative and regulatory initiatives and market
forces have laid the foundation for continued development of competition in the
electric utility industry. As a result, the electric utility industry is
reviewing the potential impacts of a major transition from a traditional rate
regulated environment of bundled service based on cost recovery to unbundled
services with some combination of a competitive marketplace for some services,
principally generation, and modified regulation of other market segments.
Increased competition is expected to reduce the margin on certain classes of
energy sales and may result in customer and revenue losses. Increased
competition may also limit high cost utilities' ability to recover capital
investment through rates, resulting in stranded investment and potential
writedown of assets. Potential competition has resulted in increased focus on
cost cutting and consideration of strategic alternatives, including mergers and
restructuring of operations. For additional information concerning competition,
see "Competition" in the "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in the Company's Annual Report to
Shareholders for the year 1995.
The Energy Act was enacted to promote competition among utility and
nonutility generators in the wholesale electric generation market. The Energy
Act allows the FERC to order owners of electric transmission systems to provide
third parties with transmission access for wholesale power transactions. During
1995, the FERC issued proposed rules which, if adopted, would require that all
public utilities have on file with the FERC nondiscriminatory open-access
transmission tariffs for network and point-to-point services, including separate
rates for ancillary services. The FERC's proposed rules would also provide for
recovery of legitimate and verifiable wholesale stranded investment. These
proposals further expressed the FERC's strong expectation that state regulatory
commissions provide for similar full recovery of legitimate and verifiable
stranded investment that could result if state regulatory commissions ordered
retail competition and direct access. The Company filed comments in response to
the FERC's proposal. The comments, while generally supportive, suggested several
adjustments to ensure full stranded investment recovery. An order from the FERC
is expected in the first half of 1996.
The Company also filed a tariff for network and point-to-point services and
a market-based rate tariff that would allow the Company to sell wholesale energy
at market-based rates outside the PJM control area. These tariffs would be
available to wholesale buyers and sellers of electricity, although the Company
would continue to make sales within the PJM control area under its existing
FERC-approved cost-based tariffs. The market-based
22
tariff described above is not expected to affect the applicability of SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation," to the
Company's operations. For additional information concerning SFAS No. 71, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the Company's Annual Report to Shareholders for the year 1995.
During 1995, the Company proposed a plan to enable the PJM companies to
offer regional open access to their transmission facilities, to create an
independent system operator, to adapt the existing PJM regional wholesale energy
market to increased competition and to preserve those elements of power pooling
which are still beneficial.
While the Energy Act encourages competition on a wholesale level, the
Energy Act prohibits the FERC from ordering wheeling for sales to retail
customers. Currently, a number of states, including Pennsylvania, are assessing
the issue of retail competition with varying outcomes. While assessing their
positions, many issues must be considered which will require significant
deliberation and may result in legal challenges. These issues include the
recovery of any resulting stranded investment, the impact of
inter-jurisdictional sales and whether such change is enacted by regulatory or
legislative action.
In August 1995, after seeking input from Pennsylvania utilities and
interest groups, the PUC staff issued a report recommending against the
implementation of retail electric power competition at this time. The PUC also
issued an order inviting further comments and establishing hearings on
competition issues with the expectation of submitting a report to the
Pennsylvania legislature and the Governor in June 1996. In November 1995, the
Company submitted testimony which proposes five major initiatives to reduce the
costs of electricity while preserving the reliability and universal service that
is essential to Pennsylvania citizens. These initiatives are: 1) improvements in
the PJM interconnection to incorporate an independent system operator, provide
for wholesale energy exchange based on a market bidding mechanism, provide a
regional transmission tariff and expand participation in the wholesale energy
market to others, including firms that are not traditional utilities; 2)
performance-based regulation which would link utility earnings to performance
rather than historic costs; 3) flexible pricing to allow utilities to offer
customers a variety of service options tailored to individual requests, and to
bring certain rates closer to market levels; 4) accelerated depreciation and
other cost mitigation measures that challenge the utilities to reduce possible
stranded investment associated with existing generation assets; and 5)
competitive bidding of new generation to ensure that needs are met as
efficiently as possible. The Company believes that these proposed initiatives
will allow the PUC to improve the efficiency of the electric industry, while
continuing to assure the availability of reliable service for all customers at
reasonable rates, without significant adverse consequences on the financial
condition of the electric utilities.
The Company believes that retail competition should not be adopted if it
represents a mere shifting of costs from one class of customers to another or to
shareholders, and that retail competition does not currently provide a net
benefit. Regulatory changes permitting retail competition may also create
stranded investment if the FERC's position of allowing full recovery of stranded
investment as described in its proposal is not adopted. Investments by the
Company in assets which would not be recoverable from customers, including its
investment in nuclear facilities, may have to be written down, which would have
a material adverse effect on the Company's financial condition and results of
operations. The Company is not able to predict whether retail competition will
be implemented and, if implemented, what impact it would have on the Company's
financial condition or results of operations.
As a result of competitive pressures, the Company has negotiated long-term
contracts with many of its larger- volume industrial customers. Although these
agreements have resulted in lower revenues from this class of customers, they
have permitted the Company to maintain this segment of its customer base.
The gas industry is also undergoing structural changes in response to FERC
policies designed to increase competition in this market. This has included
requirements that interstate gas pipelines unbundle their gas sales service from
other regulated tariff services, such as transportation and storage. In
anticipation of these policies,
23
the Company has modified its gas purchasing arrangements to enable the purchase
of gas and transportation at lower costs, and has become more active in the area
of gas transportation.
During 1995, there were an unprecedented number of mergers in the utility
industry and this trend is expected to continue. In August 1995, the Company
proposed a merger with PP&L Resources, Inc., an electric utility with operations
in northeast Pennsylvania. In November, PP&L Resources declined the Company's
final offer and the Company withdrew its proposal. The Company will continually
evaluate all opportunities to improve its strategic and competitive position
but, because of its strong stand-alone position, is not compelled to pursue such
opportunities at any cost.
Telecommunications
To take advantage of emerging opportunities in the telecommunications
field, in 1995, the Company created a new strategic business unit, the
Telecommunications Group. The business unit has initiated several joint ventures
in newly emerging wireless personal communications services businesses and other
competitive telecommunications opportunities. The telecommunications field
presents the Company with many opportunities to expand its business and generate
additional revenues.
PECO Energy Capital Corp. and Related Entities
PECO Energy Capital Corp., a wholly owned subsidiary, is the sole general
partner of PECO Energy Capital, L.P., a Delaware limited partnership
(Partnership). The Partnership was created solely for the purpose of issuing
preferred securities, representing limited partnership interests, and lending
the proceeds thereof to the Company, and entering into similar financing
arrangements. Such loans to the Company are evidenced by the Company's
subordinated debentures, which are the only assets of the Partnership. The only
revenues of the Partnership are interest on the Company's subordinated
debentures (Subordinated Debentures). All of the operating expenses of the
Partnership are paid by PECO Energy Capital Corp. At December 31, 1995, the
Partnership held $308,612,964 aggregate principal amount of the Subordinated
Debentures.
PECO Energy Capital Trust I (Trust) was created in October 1995 as a
statutory business trust under the laws of the State of Delaware solely for the
purpose of issuing trust receipts (Trust Receipts), each representing an 8.72%
Cumulative Monthly Income Preferred Security, Series B (Series B Preferred
Securities) of the Partnership. The Partnership is the sponsor of the Trust. On
December 19, 1995, the Trust issued 3,124,183 Trust Receipts. At December 31,
1995, the assets of the Trust consisted solely of 3,124,183 Series B Preferred
Securities with an aggregate stated liquidation preference of $78,104,575.
Distributions were made on the Trust Receipts on December 29, 1995 in the
aggregate amount of $1,074,893, or $0.3441 per Trust Receipt. The payment
reflects accrued distributions at the rate of 7.96% per annum from November 1,
1995 through December 18, 1995 and at the rate of 8.72% per annum from December
19, 1995 through December 31, 1995. Expenses of the Trust for 1995 were
approximately $2.1 million, all of which were paid by PECO Energy Capital Corp.
or the Company. The number of holders of record of the Trust Receipts as of
March 20, 1996 was 884.
24
Executive Officers of the Registrant
Age at Effective Date of Election
Name Dec. 31, 1995 Position to Present Position
J. F. Paquette, Jr............. 61 Chairman of the Board............................... April 12, 1995
C. A. McNeill, Jr.............. 56 President and Chief Executive Officer............... April 12, 1995
D. M. Smith.................... 62 President-- PECO Nuclear and Chief
Nuclear Officer................................. February 1, 1996
W. L. Bardeen.................. 57 Senior Vice President and Group Executive--
Consumer Energy Services Group.................. March 1, 1994
J. W. Durham................... 58 Senior Vice President and General Counsel........... October 24, 1988
W. J. Kaschub.................. 53 Senior Vice President-- Human Resources............. June 10, 1991
G. S. King..................... 55 Senior Vice President-- Corporate and
Public Affairs.................................. October 1, 1992
K. G. Lawrence................. 48 Senior Vice President-- Finance and Chief
Financial Officer............................... March 1, 1994
J. M. Madara, Jr............... 52 Senior Vice President and Group
Executive-- Power Generation Group.............. March 1, 1994
R. J. Patrylo.................. 49 Senior Vice President and Group
Executive-- Gas Services Group.................. August 1, 1994
G. R. Rainey................... 46 Senior Vice President-- Nuclear Operations.......... April 1, 1996
A. J. Weigand.................. 57 Senior Vice President and Group
Executive-- Bulk Power Enterprises ............. March 1, 1994
J. M. Bauer.................... 49 Vice President-- Customer Services.................. April 13, 1994
G. A. Cucchi................... 46 Vice President-- Planning and Performance........... March 1, 1994
D. B. Fetters.................. 44 Vice President-- Station Support.................... September 25, 1995
D. R. Helwig................... 44 Vice President-- Power Delivery..................... March 1, 1995
T. P. Hill, Jr................. 47 Vice President and Controller....................... January 1, 1991
K. C. Holland.................. 43 Vice President-- Information Systems
and Chief Information Officer................... March 21, 1994
W. G. MacFarland, IV........... 46 Vice President-- Limerick Generating
Station......................................... March 1, 1995
J. B. Mitchell................. 47 Vice President-- Finance and Treasurer.............. December 1, 1994
W. E. Powell, Jr............... 59 Vice President-- Support Services................... January 30, 1995
T. N. Mitchell................. 40 Vice President-- Peach Bottom Atomic
Power Station................................... April 1, 1996
W. H. Smith, III............... 47 Vice President and Group Executive,
Telecommunications Group........................ September 25, 1995
D. A. Thomas................... 49 Vice President-- Marketing and Sales................ January 30, 1995
N. J. Zausner.................. 42 Vice President-- Power Transactions................. October 11, 1994
K. K. Combs.................... 45 Corporate Secretary................................. November 1, 1994
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 10, 1996).
Prior to his election to his current position with the Company, Mr.
Paquette was Chairman and Chief Executive Officer of the Company.
Prior to his election to his current position with the Company, Mr. McNeill
was President and Chief Operating Officer and Executive Vice President - Nuclear
of the Company.
Prior to his election to his current position with the Company, Mr. Bardeen
was Senior Vice President Finance and Chief Financial Officer. Prior to joining
the Company in 1992, Mr. Bardeen was Vice President Finance and Controller for
Bell Atlantic Corporation.
25
Prior to joining the Company in 1991, Mr. Kaschub was Vice President of
Human Resources with GTE North Incorporated.
Prior to joining the Company in 1992, Mrs. King served as Commissioner of
the United States Social Security Administration.
Prior to his election to his current position with the Company, Mr.
Lawrence was Vice President - Gas 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 joining the Company in 1994, Mr. Patrylo was Senior Vice President
- - Gas Services Business Unit at Niagara Mohawk Power Corporation and President
of RJP Associates, Inc., a business consulting firm.
Prior to his election to his current position with the Company, Mr. D. M.
Smith was Senior Vice President - Nuclear Generation Group, 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.
Prior to joining the Company in March 1994, Mrs. Holland was Director of
Technology Services and Director of Business Services and Operations at
SmithKline Beecham, Inc.
Prior to joining the Company in 1996, Mr. T.N. Mitchell was Team Manager -
Institute of Nuclear Power Operations (INPO), Director - Site Engineering at
Peach Bottom (on loan from INPO), Department Manager Engineering Support at
INPO, Core Team Member - Nuclear Electric, U.K. (on loan from INPO), and
Department Manager - Plant Analysis at INPO.
Prior to joining the Company in 1995, Mr. Powell was Vice President -
Logistics with E.I. DuPont DeNemours & Co.
Prior to joining the Company in 1995, Mr. Thomas was General Manager -
American Parts and Services, Manager - Utility Parts Sales, Manager - Gateway
Region - Utility Sales, and Manager - Product Services at General Electric
Company.
Prior to joining the Company in 1994, Ms. Zausner was Vice President of
U.S. Generating Company, an independent power producer.
Prior to their election to the positions shown above, the following
executive officers held other positions with the Company since January 1, 1991:
Ms. Bauer was Operations Manager - Montgomery County Division and Manager -
Nuclear Operations; Mr. Cucchi was Director of System Planning and Performance;
Mr. Fetters was Director - Nuclear Engineering, Director - Limerick Maintenance
and a project manager; Mr. Helwig was Vice President - Limerick Generating
Station and Vice President - Nuclear Engineering and Services; Mr. Hill was
Controller; Mr. MacFarland was Outage Director - Limerick, Manager - Nuclear
Maintenance, Manager - Peach Bottom Installation Division and Senior Project
Manager - Limerick Nuclear Engineering; Mr. Mitchell was Director of Financial
Operations and Assistant Treasurer; Mr. Rainey was Vice President - Peach Bottom
Atomic Power Station, Vice President - Nuclear Services and Plant Manager -
Eddystone Generating Station; Mr. W. H. Smith was Vice President - Station
Support, Vice President - Planning and Performance, Manager - Corporate Strategy
and Performance, General Manager - Human Resources, Director - Organization
Change Task Force and Manager - Purchasing; and Ms. Combs was an Assistant
General Counsel.
There are no family relationships among directors or executive officers of
the Company.
26
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, 1995:
Net Generating Estimated
Capacity (1) Retirement
Station Location (Kilowatts) Year
Nuclear
Limerick.................................. Limerick Twp., PA.............. 2,170,000(2) 2024(3), 2029(3)
Peach Bottom.............................. Peach Bottom Twp., PA.......... 928,000(4) 2013, 2014
Salem..................................... Hancock's Bridge, NJ........... 942,000(4) 2016, 2020
Hydro
Conowingo................................. Harford Co., MD................ 512,000 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 (5)
Eddystone................................. Eddystone, PA.................. 1,341,000 2009, 2010, 2011
Schuylkill................................ Philadelphia, PA............... 166,000 (5)
Conemaugh................................. New Florence, PA............... 352,000(4) 2005, 2006
Keystone.................................. Shelocta, PA................... 357,000(4) 2002, 2003
Fossil (Gas Turbines)
Chester .................................. Chester, PA.................... 39,000 (5)
Croydon................................... Bristol Twp., PA............... 370,000 (5)
Delaware.................................. Philadelphia, PA............... 60,000 (5)
Eddystone................................. Eddystone, PA.................. 62,000 (5)
Falls..................................... Falls Twp., PA................. 48,000 (5)
Moser..................................... Lower Pottsgrove Twp., PA...... 48,000 (5)
Richmond.................................. Philadelphia, PA............... 96,000 (5)
Schuylkill................................ Philadelphia, PA............... 30,000 (5)
Southwark................................. Philadelphia, PA............... 53,000 (5)
Salem..................................... Hancock's Bridge, NJ........... 16,000(4) (5)
Fossil (Internal Combustion)
Cromby .................. ............... Phoenixville, PA............... 2,700 (5)
Delaware.................................. Philadelphia, PA............... 2,700 (5)
Schuylkill................................ Philadelphia, PA............... 2,800 (5)
Keystone.................................. Shelocta, PA................... 2,300(4) 2003
Conemaugh................................. New Florence, PA............... 2,300(4) 2006
---------
Total.................................................................... 9,077,800
=========
<FN>
- ---------------
(1) Summer rating.
(2) Effective January 24, 1996, Limerick Unit No. 1 was rerated to 1,115,000
kilowatts, making the entire station's capacity 2,230,000 kilowatts. This
rerate increased the Company's net generating capacity to 9,137,800
kilowatts.
(3) For depreciation accrual purposes only, retirement dates have been reduced
by 10 years. See "Rate Matters."
(4) Company portion.
(5) Retirement dates are under on-going review by the Company. Current plans
call for the continued operation of these units beyond 1996.
</FN>
27
The following table sets forth the Company's major transmission and
distribution lines in service at December 31, 1995:
Voltage in Kilovolts (Kv) Conductor Miles
Transmission:
500 Kv .............. 824
220 Kv .............. 1,746
132 Kv .............. 656
66 Kv ............... 646
33 Kv and below ..... 37
Distribution:
33 Kv and below ..... 48,809
At December 31, 1995, the Company's principal electric distribution system
included 11,770 pole-line miles of overhead lines and 20,673 cable miles of
underground cables.
The Company is in the midst of an ongoing program to implement a 33 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 33 Kv subtransmission lines,
which are being converted to 33 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, 1995:
Pipeline Miles
Transmission ..... 28
Distribution ..... 5,458
Service piping.... 4,401
-----
Total ........ 9,887
=====
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 23 natural gas city
gate stations (including one temporary station) 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 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 16 of Notes to Consolidated Financial Statements
included in the Company's Annual Report to Shareholders for the year 1995.
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
$46 million for property losses incurred at any plant insured by the insurance
companies (see "ITEM 1. BUSINESS -- Electric Operations -- General"). 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 and results of operations.
28
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), alleged 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 1990 Early Retirement Plan, thereby depriving the
plaintiffs of substantial pension and salary benefits. In June 1991, the
plaintiffs filed amended complaints adding additional plaintiffs. The lawsuit
named the Company, the Company's Service Annuity Plan (SAP) and two Company
officers as defendants. On May 13, 1994, the Eastern District Court issued a
decision, finding the Company liable to all plaintiffs who made inquiries about
any early retirement plan after March 12, 1990 and retired prior to April 1990.
In an order dated August 23, 1995, the Eastern District Court awarded the
plaintiffs $1.5 million. The Company has filed appeals from the order and has
accrued the amount of the award.
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 between January and June 1987. The lawsuit was filed under ERISA and
concerned the August 1, 1987 amendment to the SAP. The plaintiffs claimed 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. On May 13, 1994, the Eastern District Court issued a decision, finding
the Company liable to all plaintiffs who made inquiries about any pension
improvement after March 1, 1987 and retired prior to June 1987. In an order
dated August 23, 1995, the Eastern District Court awarded the plaintiffs $1.8
million. The Company has filed appeals from the order and has accrued the amount
of the award.
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 was the
findings and conclusions contained in the Credit and Collection section of the
May 1991 PUC Management Audit Report (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 would be in the
best interests of the Company and its shareholders. On March 14, 1994, upon the
recommendation of the special committee, the Board of Directors approved 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 August 15, 1995,
attorneys on behalf of the shareholders filed a derivative action in the Court
of Common Pleas of Philadelphia County (Court of Common Pleas) asserting the
same claims against several present and former officers which are asserted in
the July 26, 1993 shareholder derivative suit discussed below. On February 20,
1996, the Court of Common Pleas ordered that the suit be consolidated with the
July 26, 1993 shareholder derivative suit. 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.
On July 26, 1993, attorneys on behalf of two shareholders filed a
shareholder derivative action in the Court of Common Pleas 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. The derivative suit is based on the findings
and conclusions contained in the Credit and Collections section of the Audit
Report. 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. A trial date has been set for November 4,
1996. 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.
On March 5, 1996, the Company and Delmarva Power & Light Company (Delmarva)
filed an action in the United States District Court for the Eastern District of
Pennsylvania against Public Service Enterprise Group
29
Incorporated and its subsidiary PSE&G (Enterprise Group) concerning the shutdown
of Salem; on the same date, Atlantic Electric Company (Atlantic Electric) filed
a similar suit against Enterprise Group in New Jersey state court. The suit
alleges that Enterprise Group breached the provisions of the Owners Agreement
pursuant to which the four companies own Salem and under which Enterprise Group
operates Salem. The suit also alleges negligence, gross negligence, reckless,
and willful and wanton misconduct. The plaintiffs seek compensation for certain
replacement power costs they incurred as a result of the shutdown of Salem and
for increased operating and maintenance costs and lost profits. The complaint
does not specify any dollar amount of damages.
During the shutdown of Salem, examinations of the steam generator tubes at
Salem Unit No. 1 revealed significant cracking. On February 27, 1996, the
Company, PSE&G, Atlantic Electric and Delmarva, the co-owners of Salem, filed an
action in the United States District Court for the District of New Jersey
against Westinghouse Electric Corporation, the designer and manufacturer of the
Salem steam generators. The suit alleges that the significant cracking of the
steam generator tubes is the result of defects in the design and fabrication of
the steam generators and that Westinghouse knew that the steam generators
supplied to Salem were defective and that Westinghouse deliberately concealed
this from PSE&G. The suit alleges violations of both the federal and New Jersey
Racketeer Influenced and Corrupt Organizations Acts (RICO), fraud, negligent
misrepresentation and breach of contract. For additional information concerning
the cracking of steam generator tubes at Salem, see "ITEM 1. BUSINESS - Electric
Operations - Salem Generating Station."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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, 1996, there were 186,754 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 1995
and 1994 is incorporated herein by reference to "Operating Statistics" in the
Company's Annual Report to Shareholders for the year 1995.
The book value of the Company's common stock at December 31, 1995 was
$20.40 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, 1995, such capital ($4.53 billion) amounted to about 12 times the
liquidating value of the outstanding preferred stock ($292.1 million).
The Company may not declare dividends on any shares of its capital stock in
the event that: (1) the Company exercises its right to extend the interest
payment periods on the Company's subordinated debentures (Subordinated
Debentures) which were issued to the Partnership; (2) the Company defaults on
its guarantee of
30
the payment of distributions on the Cumulative Monthly Income Preferred
Securities of the Partnership; or (3) an event of default occurs under the
Indenture under which the Subordinated Debentures are issued.
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 1995.
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 1995.
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 1995.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
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 1996 Annual Meeting of Shareholders to be
held April 10, 1996, 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 1996 Annual Meeting of
Shareholders to be held April 10, 1996, under the heading "Executive
Compensation Disclosure" and is incorporated herein by reference.
31
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 1996 Annual Meeting of
Shareholders to be held April 10, 1996, 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 1996 Annual Meeting of
Shareholders to be held April 10, 1996, under the heading "Proposal 1. Election
of Directors" and is incorporated herein by reference.
32
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Financial Statement Schedule
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 1995:
Report of Independent Accountants............................................. -- 19
Consolidated Statements of Income for the years ended
December 31, 1995, 1994 and 1993............................................ -- 20
Consolidated Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993............................................ -- 21
Consolidated Balance Sheets as of December 31, 1995 and 1994.................. -- 22
Consolidated Statements of Changes in Common Shareholders'
Equity and Preferred Stock for the years ended
December 31, 1995, 1994 and 1993............................................ -- 24
Notes to Consolidated Financial Statements.................................... -- 25
Data submitted herewith:
Report of Independent Accountants............................................. 34 --
Schedule II-- Valuation and Qualifying Accounts for the years
ended December 31, 1995, 1994 and 1993....................... 35 --
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 1995 and incorporated by
reference into this Form 10-K Annual Report, the Annual Report to Shareholders
for the year 1995 is not to be deemed "filed" as part of this Form 10-K.
33
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 19 of the 1995
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 schedule listed in the index in Item 14 of this Form 10-K.
In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 2, 1996
34
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II -- 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, 1995
ALLOWANCE FOR UNCOLLECTIBLE
ACCOUNTS............................. $16,500 $39,043 $ -- $34,683 $20,860
------- ------- -------- ------- -------
TOTAL.......................... $16,500 $39,043 $ -- $34,683 $20,860
======= ======= ======== ======= =======
FOR THE YEAR ENDED DECEMBER 31, 1994
ALLOWANCE FOR UNCOLLECTIBLE
ACCOUNTS............................. $15,086 $44,186 $ -- $42,772 $16,500
------- ------- -------- ------- -------
TOTAL.......................... $15,086 $44,186 $ -- $42,772 $16,500
======= ======= ======== ======= =======
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
======= ======= ======== ======= =======
<FN>
- ---------------
(1) Write-off of individual accounts receivable.
</FN>
35
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 (1993 Form 10-K, Exhibit 3-1).
3-2 Bylaws of the Company, adopted February 26, 1990 and amended
January 24, 1994 (1993 Form 10-K, Exhibit 3-2).
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:
Dated as of File Reference Exhibit No.
May 1, 1927 2-2881 B-1(c)
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)
September 1, 1957 2-13562 2(b)-17
May 1, 1958 2-14020 2(b)-18
May 1, 1964 2-25628 4(b)-21
October 1, 1967 2-28242 2(b)-23
March 1, 1968 2-34051 2(b)-24
May 1, 1970 2-38849 2(b)-28
December 15, 1970 2-41081 2(b)-29
December 15, 1971 2-44195 2(b)-31
January 15, 1973 2-49842 2(b)-33
March 1, 1981 2-72802 4-46
March 1, 1981 2-72802 4-47
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 1, 1986 1986 Form 10-K 4-2(c)
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
36
Dated as of File Reference Exhibit No.
April 15, 1988 Form 8-K dated April 11, 1988 4(e)-69
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
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
May 1, 1995 Form 8-K dated May 24, 1995 4(e)-96
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).
4-5 Indenture, dated as of July 1, 1994, between the Company and
Meridian Trust Company, as trustee (1994 Form 10-K, Exhibit 4-5).
4-6 Deferrable Interest Subordinated Debenture Certificate, Series A
(1994 Form 10-K, Exhibit 4-6).
4-7 First Supplemental Indenture, dated as of December 1, 1995,
between the Company and Meridian Trust Company, as trustee, to
Indenture dated as of July 1, 1994.
4-8 Deferrable Interest Subordinated Debenture Certificates, Series B,
No. 1 and No. 2.
4-9 Payment and Guarantee Agreement, dated July 27, 1994, executed by
the Company in favor of the holders of Cumulative Monthly Income
Preferred Securities, Series A of PECO Energy Capital, L.P. (1994
Form 10-K, Exhibit 4-7).
4-10 Payment and Guarantee Agreement, dated as of December 19, 1995,
executed by the Company in favor of the holders of Cumulative
Monthly Income Preferred Securities, Series B of PECO Energy
Capital, L.P.
37
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 Forms of Agreement between the Company and certain officers.
10-6 PECO Energy Company Long-Term Incentive Plan (Registration No.
333-451, Exhibit 99).*
10-7 Amended and Restated Limited Partnership Agreement of PECO Energy
Capital, L.P., dated July 25, 1994 (1994 Form 10-K, Exhibit 10-7).
10-8 Amendment No. 1 to the Amended and Restated Limited Partnership
Agreement of PECO Energy Capital, L.P.
10-9 Amendment No. 2 to the Amended and Restated Limited Partnership
Agreement of PECO Energy Capital, L.P.
10-10 Amended and Restated Trust Agreement of PECO Energy Capital Trust
I, dated as of December 19, 1995.
10-11 Agreement between the Company and Delmarva Power & Light Company
for the purchase and sale of capacity and energy, dated May 24,
1994 (1994 Form 10-K, Exhibit 10-9).
12-1 Ratio of Earnings to Fixed Charges.
12-2 Ratio of Earnings to Combined Fixed Charges and Preferred
Stock Dividends.
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 1995.
38
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
24 Powers of Attorney.
27 Financial Data Schedule.
- ---------------
* 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, 1995, the Company filed Current
Reports on Form 8-K, dated:
October 17, 1995 reporting information under "ITEM 5. OTHER EVENTS"
relating to the shutdown of Salem Generating Station operated by Public
Service Electric and Gas Company.
October 23, 1995 reporting information under "ITEM 5. OTHER EVENTS"
relating to the proposed merger with PP&L Resources, Inc.
November 1, 1995 reporting information under "ITEM 5. OTHER EVENTS"
relating to the proposed merger with PP&L Resources, Inc.
December 11, 1995 reporting information under "ITEM 5. OTHER EVENTS"
relating to the shutdown of Salem Generating Station operated by Public
Service Electric and Gas Company.
Subsequent to December 31, 1995, the Company filed a Current Report on Form
8-K, dated:
February 23, 1996 reporting information under "ITEM 5. OTHER EVENTS"
relating to the cracking of steam generator tubes at Unit No. 1 at
Salem Generating Station operated by Public Service Electric and Gas
Company.
39
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 27th day of March 1996.
PECO ENERGY COMPANY
By /s/ C.A. MCNEILL, JR.
----------------------------------------
C.A. McNeill, Jr.,
President and Chief Executive Officer
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 March 27, 1996
J. F. Paquette, Jr.
/s/ C. A. MCNEILL, JR.
- ----------------------------------- President, Chief Executive Officer March 27, 1996
C. A. McNeill, Jr. and Director (Principal Executive
Officer)
/s/ K. G. LAWRENCE
- ----------------------------------- Senior Vice President - Finance March 27, 1996
K. G. Lawrence and Chief Financial Officer
(Principal Financial and
Accounting Officer)
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 JOSEPH C. LADD
M. WALTER D'ALESSIO EDITHE J. LEVIT
RICHARD G. GILMORE KINNAIRD R. MCKEE
RICHARD H. GLANTON JOSEPH J. MCLAUGHLIN
JAMES A. HAGEN JOHN M. PALMS
NELSON G. HARRIS RONALD RUBIN
ROBERT SUBIN
By /s/ C. A. MCNEILL, JR. March 27, 1996
- -----------------------------------
C. A. McNeill, Jr., Attorney-in-Fact