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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, 1996
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 (Listed on the New York Stock Exchange):
<TABLE>
<S> <C> <C> <C>
6 1/8% Series due 1997 (*) 7 3/8% Series due 2001 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
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(*) Also listed on the Philadelphia Stock Exchange
</TABLE>
Cumulative Preferred Stock -- without par value (Listed 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 (Listed on the New York and Philadelphia
Stock Exchanges)
9.00% Cumulative Monthly Income Preferred Securities, Series A, $25 stated
value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by the
Company (Listed 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
(Listed 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. [X]
The aggregate market value of the registrant's common stock (only voting
stock) held by non-affiliates of the registrant was $4,941,367,295 at February
28, 1997.
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: 222,542,087 shares outstanding at
February 28, 1997.
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DOCUMENTS INCORPORATED BY REFERENCE (In Part) Annual Report of
PECO Energy Company to Shareholders for the year 1996
is incorporated in part in Parts I, II and IV hereof, as specified herein.
Proxy Statement of PECO Energy Company in connection with its 1997
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
Deregulation and Rate Matters..................................... 1
Electric - Retail................................................ 2
Electric - Wholesale............................................. 5
Gas.............................................................. 5
Electric Operations............................................... 6
General.......................................................... 6
Limerick Generating Station...................................... 8
Peach Bottom Atomic Power Station................................10
Salem Generating Station.........................................10
Fuel..............................................................12
Nuclear..........................................................12
Coal.............................................................14
Oil..............................................................15
Natural Gas......................................................15
Gas Operations....................................................15
Segment Information...............................................16
Construction......................................................16
Capital Requirements and Financing Activities.....................17
Employee Matters..................................................18
Environmental Regulations.........................................19
Water............................................................19
Air..............................................................19
Solid and Hazardous Waste........................................20
Costs............................................................23
Telecommunications................................................23
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............................................32
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
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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 and buys and sells power in the wholesale generation
market throughout North America. The total retail area served by the Company
covers 2,107 square miles. Retail electric service is supplied in an area of
1,972 square miles with a population of about 3.6 million, including 1.6 million
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 1.9
million.
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 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.
The electric and gas utility industries are both undergoing fundamental
restructurings. In 1996, the FERC issued Order No. 888 providing for competition
in wholesale generation by requiring that all public utilities file
non-discriminatory open-access transmission tariffs. In December 1996,
Pennsylvania Governor Tom Ridge signed into law the Electricity Generation
Customer Choice and Competition Act (Competition Act) which provides for the
restructuring of the electric utility industry in Pennsylvania, including retail
competition for generation beginning in 1999. For additional information, see
"Deregulation and Rate Matters."
Deregulation and Rate Matters
In 1996, approximately 86% of the Company's electric sales revenue and 100%
of its gas sales revenue were derived pursuant to rates regulated by the PUC and
approximately 13% of the Company's electric sales revenue was derived pursuant
to rates regulated by the FERC. The PUC has established through regulatory
proceedings the base rates which the Company may charge for electric and gas
service in Pennsylvania. In addition, the PUC has regulated various fuel and tax
adjustment clauses applicable to customers' bills.
In response to competitive pressures, the Company has continued to
negotiate long-term contracts with many of its large volume industrial
customers. Although these agreements have resulted in reduced margins, they have
permitted the Company to retain these customers. During 1996, energy sales under
long-term contracts were 8% of total electric sales. With the development of the
wholesale generation market, the Company has increased both its wholesale power
purchases and sales.
As a result of the adoption of the Competition Act, and deregulation
initiatives by FERC, as described below, the Company anticipates the unbundling
of electric services into separate generation, transmission and distribution
services with open competition for both wholesale and retail generation
services. The Company believes that the Competition Act and other regulatory
initiatives that provide for competition for generation services will
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significantly affect the Company's future financial condition and results of
operations. Because of the substantial capital costs of its investment in
nuclear generation, the Company is a high-cost producer. However, because of the
fuel and other economies of nuclear generation, the Company is a relatively low
marginal cost producer. At this time the Company cannot predict whether the
changes resulting from deregulation of generation services will materially
affect the market prices of its publicly traded securities. For additional
information, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations" in the Company's Annual Report to Shareholders for
the year 1996.
Electric - Retail
The Competition Act was enacted in December 1996, providing for the
restructuring of the electric utility industry in Pennsylvania. The Competition
Act requires the unbundling of electric services into separate generation,
transmission and distribution services with open retail competition for
generation. Electric distribution and transmission services remain regulated by
the PUC. The Competition Act requires utilities to submit to the PUC
restructuring plans, including their stranded costs which will result from
competition. Stranded costs include regulatory assets, nuclear decommissioning
costs and long-term purchased power commitments, for which full recovery is
allowed, and other costs, including investment in generating plants, spent-fuel
disposal, retirement costs and reorganization costs, for which an opportunity
for recovery is allowed in an amount determined by the PUC as just and
reasonable. These costs, after mitigation by the utility, are to be recovered
through the Competitive Transition Charge (CTC) approved by the PUC and
collected from distribution customers for up to nine years (or for an
alternative period determined by the PUC for good cause shown). During that
period, the utility is subject to a rate cap which provides that total charges
to customers cannot exceed the rates in place as of December 31, 1996, subject
to certain exceptions. To the extent the Company is not ultimately permitted by
the PUC to recover its retail electric stranded costs, this amount could result
in a charge against earnings and a subsequent reduction in revenues.
Full electric generation competition will be phased in for one-third of
each customer class by January 1, 1999, for an additional one-third by January
1, 2000 and for all remaining customers by January 1, 2001.
The Competition Act also authorizes the PUC to approve, by adopting a
qualified rate order (QRO), the issuance by a utility, a finance subsidiary of a
utility or a third party assignee of a utility of Transition Bonds as a
mechanism to mitigate stranded investment and reduce customer rates. Under the
Competition Act, proceeds of Transition Bonds are required to be used
principally to reduce qualified stranded costs and the related capitalization of
the utility. The Transition Bonds are repayable from irrevocable Intangible
Transition Charges (ITC). The maximum maturity of the Transition Bonds is ten
years.
On January 22, 1997, the Company filed an Application with the PUC for a
QRO authorizing the issuance of Transition Bonds to fund $3.6 billion of
stranded costs and related transaction and use of proceeds costs. The Company
requested expedited review of its Application under the Competition Act, which
requires the PUC to complete its review of the Application and issue a final
determination within 120 days.
The Application, which was filed in advance of the Company's required
restructuring filing, seeks recovery of $3.6 billion of the Company's estimated
$7.1 billion (at December 31, 1998) total stranded costs through the issuance of
the Transition Bonds covered by the Application. As a result of an updated
market valuation of the Company's generating plant, the Company has reduced its
total stranded cost claim from $7.1 to $6.7 billion. The Company's current
estimate of total stranded costs includes $3.5 billion of generation assets,
$560 million of unfunded and as yet unrecorded decommissioning expenses and $2.6
billion of regulatory assets. Recovery of the portion of the Company's stranded
costs not recovered by the Application will be requested by the Company in its
restructuring filing, which is presently anticipated to be made on April 1,
1997.
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The Application sets forth the Company's proposal for issuance of the
Transition Bonds through an unrelated special purpose entity in order to achieve
off-balance sheet treatment of the transaction. In proposed transactions
involving other utilities, the Securities and Exchange Commission has indicated
that off-balance sheet treatment would not be permitted. The Company cannot
predict whether off-balance sheet treatment will be permitted for the issuance
of the Transition Bonds. If off-balance sheet treatment is not permitted, the
Company proposes that the Transition Bonds be issued through a limited purpose
finance subsidiary. The finance subsidiary would acquire from the Company the
intangible transition property authorized under the Competition Act which
represents the right to recover through the ITC stranded costs and related
transaction and use of proceed costs. The finance subsidiary would pledge the
intangible transition property and related ITC to secure the Transition Bonds.
Thus, amounts received from the ITC would be dedicated exclusively to the
payment of the Transition Bonds.
The Company proposes using the proceeds it receives resulting from the
issuance of the Transition Bonds, to pay transaction and use of proceeds costs,
currently estimated at $173 million, to settle deferred fuel balances of $240
million and to reduce capitalization by approximately $3.4 billion. The
capitalization reduction would be approximately proportionate to the Company's
current capitalization. Specific securities to be retired and the manner in
which they are to be retired have not been determined and will depend on market
conditions at the time of issuance of the Transition Bonds.
Adoption by the PUC of the requested QRO and issuance of Transition Bonds
to fund $3.6 billion of the Company's stranded costs and related issuance and
use of proceeds costs at current interest rates would result in an estimated
average 3.4% reduction in the Company's retail electric rates. The Company
estimates that the consummation of the transaction as proposed in the
Application and assuming the Company is permitted off- balance sheet treatment
would reduce the Company's annual revenues by approximately $650 million and the
Company's annual operating expenses by $501 million, resulting in an estimated
reduction in annual net income of $149 million. The reduction in revenue results
from the elimination of the revenue requirements of stranded costs, and the
reduction in operating expenses results from decreases in depreciation, interest
expense and associated income taxes. The impact on the Company's earnings per
share will depend on the price at which shares of the Company's Common Stock are
purchased. If Common Stock is purchased at a price above book value ($20.88 at
December 31, 1996), earnings per share will be reduced.
The PUC assigned the requested QRO to an administrative law judge (ALJ) who
has held hearings on the matter. A number of parties have intervened. A
recommended decision by the ALJ is expected by April 15, 1997 and the PUC is
expected to issue a decision with respect to the requested QRO by May 22, 1997.
The Company cannot predict whether the PUC will issue the requested QRO, the
level of stranded cost recovery authorized by any QRO or the amount of
Transition Bonds, if any, ultimately issued pursuant to any QRO.
On March 18, 1997, certain intervenors in the Company's application for a
QRO petitioned the Commonwealth Court of Pennsylvania to enjoin the PUC from
taking any action or rendering any decision pursuant to the Competition Act. The
Company cannot predict the outcome of this matter.
Under the Competition Act, the Company's rates for transmission and
distribution services will be capped at January 1, 1997 levels for 4.5 years and
the generation portion of rates for up to nine years from the effective date of
the Competition Act. In recognition of the capping of rates at current levels,
at December 31, 1996, the PUC approved the Company's request to roll-in and
eliminate the Energy Cost Adjustment (ECA), a billing surcharge mechanism
previously used to recover a portion of the Company's energy costs. In addition,
the PUC recognized the Company's right to defer and, in the future, seek
recovery of (1) an estimated $102 million attributable to its undercollection of
$80 million in energy costs through 1996 and the anticipated $22 million
performance bonus with respect to the 1996 operation of the Company's nuclear
generating facilities, and (2) approximately $198 millon of future energy costs
that would not have otherwise been recoverable. Subject to the rate cap
limitations imposed by the Competition Act, the PUC provided that these deferred
amounts may be recovered either through the stranded cost recovery mechanisms
provided in the Competition Act or an automatic adjustment clause provided in
the Public Utility Code. On February 26, 1997, a coalition of the Company's
large industrial customers petitioned the PUC to reconsider and amend its order
regarding the ECA.
On February 27, 1997, in compliance with the Competition Act, the Company
filed with the PUC a comprehensive pilot program to enable some 90,000
residential, commercial and industrial customers to choose
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their electric generation suppliers beginning as early as October 1997. The
cross section of eligible customers will include 5% from the City of
Philadelphia and 5% from suburban counties across all major rate classes. Also,
residential customers in one randomly selected township or borough in the
suburbs and one randomly selected political subdivision in the City of
Philadelphia will be eligible. In addition, randomly selected commercial and
industrial customers located in state-created enterprise zones will be eligible.
Power would be delivered to the pilot customers as early as October 1997, and no
later than January 1998. The pilot would conclude in December 1998. All pilot
participants would be among the one-third of electric utility customers to be
offered choice by January 1, 1999.
If approved by the PUC, the pilot would begin in April 1997, with the
random selection by a neutral third party of some 90,000 customers from the
Company's service territory. Under the pilot, the 90,000 customers will have the
opportunity to buy their electricity from other power companies, brokers or
marketers through 1998. Cumulatively, about 480 MW of electric load will be open
to competition. The power from other suppliers would continue to be delivered
over the Company's transmission and distribution lines, and the Company would
continue to supply customer services such as meter reading, billing and outage
restoration.
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 1996, 1995 and 1994, the
Company recorded as revenue net of fuel $82, $79 and $68 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 approved the reduction of the
terminal dates by ten years, for depreciation accrual purposes only, of Limerick
Units No. 1 and 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 approved 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 inclusion of Limerick Unit No. 2 in base rates. The
changes, which were effective October 1, 1996, 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 did not increase
rates charged to customers.
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 6 of Notes
to Consolidated Financial Statements included in the Company's Annual Report to
Shareholders for the year 1996. 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
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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 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.
Electric - Wholesale
During 1996, the FERC issued Order No. 888 which required public utilities
to file open-access transmission tariffs for wholesale transmission services in
accordance with non-discriminatory terms and conditions established by the FERC.
The FERC's new rules provide for the recovery of legitimate and verifiable
wholesale stranded costs.
In response to Order No. 888, the Company and the other members of the
Pennsylvania-New Jersey- Maryland Interconnection Association (PJM) submitted to
the FERC separate filings proposing to restructure the PJM. The Company proposed
five major initiatives to reduce the costs of electricity while preserving the
reliability and universal service that is essential to Pennsylvania citizens. In
November 1996, the FERC issued an order rejecting both of the PJM restructuring
filings. The FERC identified two issues that remain to be resolved: independence
of the independent system operator; and open access transmission pricing tariffs
that are nondiscriminatory. The FERC directed the parties to refile their
proposals, preferably as one proposal, resolving these issues by December 31,
1996, with tariffs to be effective March 1, 1997. On December 31, 1996, the PJM
member companies, including the Company, filed a joint compliance open-access
transmission tariff with the FERC. The filing was not a complete consensus but
included competing proposals in certain areas such as transmission rate
structure and transmission constraint/congestion control. The PJM member
companies requested the FERC to choose between the options for implementation
during the interim period. On February 28, 1997, the FERC issued an order
advising the PJM companies of which options to implement and making the PJM pool
compliance filing, as revised by the FERC, effective March 1, 1997, subject to
refund. In doing so, the FERC adopted, at least for an interim period, the
congestion pricing model which had been proposed by the Company. Further, the
FERC advised the PJM companies and other intervenors that it intended to convene
a technical conference to address pricing issues related to PJM pool operations.
The Company received approval for its transmission service tariff covering
network and point-to-point services and a market-based rate energy sales tariff
that allows the Company to sell wholesale energy at market- based rates outside
the PJM control area. During the latter part of 1996, the Company also requested
approval from the FERC of certain modifications to the Company's buy-for-resale
tariff. The requested modifications would remove the existing cost-based cap on
prices charged for power purchased by the Company in anticipation of later
resale in the wholesale market and change certain of its terms. The transactions
covered under the original market-based rate tariff would be rolled into the
amended buy-for-resale tariff. Approval of the new tariff provisions will allow
the Company to purchase and re-sell energy at market-based rates both within the
PJM and outside the PJM.
Gas
The gas industry is continuing to undergo structural changes in response to
the FERC policies designed to increase competition. 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 changes, the Company has modified its gas purchasing
arrangements to enable the purchase of gas and transportation at lower cost.
On March 1, 1997, the Company filed its quarterly update of Purchased Gas
Cost (PGC) No. 13 rates for the period March 1, 1997 through May 31, 1997, which
reflects a $0.42 per thousand cubic feet (mcf) increase in natural gas sales
rates.
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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.
Electric Operations
General
During 1996, 90.0% of the Company's operating revenues and 91.9% of its
operating income were from electric operations. 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. Electric sales and operating revenues for 1996 by
class of customer are set forth below:
Operating
Sales Revenues
(millions of kWh) (millions of $)
Residential ....................... 10,671 $1,370
Small commercial and industrial.... 6,491 749
Large commercial and industrial.... 15,208 1,098
Other ............................. 902 140
Decrease in unbilled .............. (327) (26)
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Service territory ............. 32,945 3,331
Interchange sales ................. 935 26
Sales to other utilities .......... 20,243 498
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Total ......................... 54,123 $3,855
====== ======
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 sales in the wholesale
generation market. In the ordinary course of business, the Company enters into
long-term and short-term commitments to buy and sell power. As of December 31,
1996, the Company had long-term agreements to purchase from unaffiliated
utilities, primarily in 1997, energy associated with 2,200 MW of capacity. These
purchases will be utilized through a combination of open market sales, sales to
jurisdictional customers and long-term sales to other utilities. As of December
31, 1996, the Company had entered into long-term agreements with unaffiliated
utilities to sell energy associated with 1,460 MW of capacity, of which 725 MW
are for 1997 and the remainder run through 2022. See note 4 of Notes to
Consolidated Financial Statements included in the Company's Annual Report to
Shareholders for the year 1996.
The net installed electric generating capacity (summer rating) of the
Company and its subsidiaries at December 31, 1996 was as follows:
Type of Capacity Megawatts (MW) % of Total
Nuclear.................................... 4,090 44.4%
Mine-mouth, coal-fired..................... 709 7.7
Service-area, coal-fired................... 725 7.9
Oil-fired.................................. 1,176 12.8
Gas-fired.................................. 267 2.9
Hydro (includes pumped storage)............ 1,392 15.1
Internal combustion........................ 842 9.2
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Total...................................... 9,201(1)(2) 100.0%
====== ======
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(1) Includes capacity available for sale to other utilities.
(2) See "Fuel" for sources of fuels used in electric generation.
The all-time 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 1997 to be 26%. This is based on the
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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 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 all-time 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 1997-2000 is expected to be sufficient for the
Company to meet its obligation to supply its PJM reserve margin share during
that period. See "Deregulation and Rate Matters-Electric-Retail."
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 1,110 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.
The Company's nuclear generating facilities represent approximately 44% of
its installed generating capacity and 67% of its investment in electric plant.
In 1996, approximately 43% 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 currently limits the liability of nuclear reactor
owners to $8.9 billion for claims that could arise from a single incident. The
limit is subject to change to account for the effects of inflation and changes
in the number of licensed reactors. The Company carries the maximum available
commercial insurance of $200 million and the remaining $8.7 billion is provided
through 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. In addition, Congress could impose revenue raising measures on
the nuclear industry to pay claims if the damages from an incident at a licensed
nuclear facility exceed $8.9 billion. The Price-Anderson Act and the extensive
regulation of nuclear safety by the NRC do not preclude claims under state law
for personal, property or punitive damages related to radiation hazards.
The Company maintains property insurance on nuclear power plants 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, as a result of an accident, 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
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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 $31 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 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 waiting period before
recovery of costs can commence. The premium for this coverage is subject to
assessment for adverse loss experience. The Company's maximum share of any
assessment is $13 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 1990 estimate of its nuclear facilities' decommissioning cost of $643
million is being collected through electric base rates over the life of each
generating unit. Under current rates, the Company collects and expenses
approximately $21 million annually from customers for decommissioning the
Company's ownership portion of its nuclear units. At December 31, 1996, the
Company held $266 million in trust accounts, representing amounts recovered from
customers and net realized and unrealized investment earnings thereon, to fund
future decommissioning costs. The Company's most recent estimate, made in 1995,
of its share of the cost to decommission its nuclear units is $1.4 billion in
1995 dollars. The Company has included the unfunded and as yet unrecorded
portion of its estimated decommissioning costs in its estimate of stranded costs
included in the January 22, 1997 application with the PUC for a QRO, although
such recovery is not assured. See "Deregulation and Rate Matters-
Electric-Retail."
In an exposure draft issued in 1996, the Financial Accounting Standards
Board (FASB) proposed changes in the accounting for closure and removal costs of
production facilities, including the recognition, measurement and classification
of decommissioning costs for nuclear generating stations. The FASB is currently
considering expanding the scope of the Exposure Draft to include closure or
removal liabilities that are incurred at any time in the operating life of the
long-lived asset. The FASB plans to issue either a final Statement or a revised
Exposure Draft in the second quarter of 1997. If current electric utility
industry accounting practices for decommissioning are changed, annual provisions
for decommissioning could increase and the estimated cost for decommissioning
could be recorded as a liability rather than as accumulated depreciation with
recognition of an increase in the cost of the related asset. 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 1996.
Limerick Generating Station
Limerick Unit No. 1 achieved a capacity factor of 84% in 1996 and 88% in
1995. Limerick Unit No. 2 achieved a capacity factor of 91% in 1996 and 85% in
1995. 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 1997,
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
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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. In accordance with
industry experience and guidance, initial examination of Unit No. 2 has been
scheduled for the refueling outage planned for January 1999. 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 re-examined.
Peach Bottom Unit No. 2 was initially examined during its October 1994 refueling
outage and the examination revealed a minimal number of flaws. Unit No. 2 was
re-examined during its last refueling outage in September 1996. Although the
examination revealed additional minor flaw indications, the Company concluded
and the NRC concurred that neither repair nor modification to the core shroud
was necessary. The Company is also participating in a GE BWR Owners Group to
develop long-term corrective actions.
As a result of several BWRs experiencing clogging of some emergency core
cooling system suction strainers, which are part of the water supply system for
emergency cooling of the reactor core, the NRC issued a Bulletin in May 1996 to
operators of BWRs requesting that measures be taken to minimize the potential
for clogging. The NRC proposed three resolution options, with a request that
actions be completed by the end of the unit's first refueling outage after
January 1997. Large capacity passive strainers will be installed at both units
at Peach Bottom and Limerick. Installations at Peach Bottom Units No. 2 and No.
3 and Limerick Unit No. 1 are scheduled for their next refueling outages in
September 1998, September 1997 and April 1998, respectively. During Limerick
Unit No. 2's most recent refueling outage, the NRC granted the Company's request
to defer the installation of strainers until the end of 1998. The Company plans
to request an additional deferral for the installation of strainers at Limerick
Unit No. 2 until its next scheduled refueling outage in April 1999. No assurance
can be given that such additional deferral will be granted. The Company cannot
predict what other actions, if any, the NRC may take in this matter.
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 Limerick and
Peach Bottom. 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. The Company
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will meet with the NRC during the first half of 1997 regarding the Company's
plans for the resolution of the Thermo-Lag issue.
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 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 79% in 1996 and 98%
in 1995. Peach Bottom Unit No. 3 achieved a capacity factor of 99% in 1996 and
78% in 1995. 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 1996 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
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.
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 Units No. 1 and No. 2 have not operated since the second quarter of
1995, when they were removed from service by PSE&G. At that time, PSE&G informed
the NRC that it had determined to keep the Salem units shut down pending review
and resolution of certain equipment and management issues and NRC agreement that
each unit is sufficiently prepared to restart. PSE&G estimates the projected
restart of Unit No. 2 to occur in the second quarter of 1997 and of Unit No. 1
to occur in the fall of 1997. Because the timing of restart for the Salem units
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
restart date will be met. As of December 31, 1996 and 1995, the Company had
incurred and expensed $149 and $50 million, respectively, for replacement power
and maintenance costs related to the shutdown of Salem. The Company continues to
incur replacement power costs of approximately $5 million per month per unit
associated with the outage of the Salem units. The inability to
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successfully return the Salem units to service could have a material adverse
effect on the Company's financial position or results of operations. For
information concerning additional costs associated with the Salem shutdown, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and notes 3 and 4 of Notes to Consolidated Financial Statements to
the Company's Annual Report to Shareholders for the year 1996; for information
concerning litigation relating to Salem, see "ITEM 3. LEGAL PROCEEDINGS."
The Company has been informed by PSE&G that as a part of PSE&G's efforts to
return the Salem units to service, during 1996, an examination was performed on
the steam generators, which are large heat exchangers used to produce steam to
drive the turbines. Inspection of Salem Unit No. 1 indicated degradation in a
significant number of tubes. Inspection and testing of Salem Unit No. 2
confirmed that the condition of the steam generators are well within current
repair limits. The Salem co-owners have purchased and installed in Salem Unit
No. 1 unused steam generators from the unfinished Seabrook Nuclear Generating
Station Unit No. 2 in New Hampshire. PSE&G's estimate of the cost of replacing,
including installing the Salem Unit No. 1 steam generators is approximately $150
to $170 million, of which the Company's share is approximately $64 to $72
million. In addition, the cost of disposal of the four old steam generators
could be as much as $20 million, of which the Company's share is approximately
$9 million.
A recent generic letter from the NRC identified an issue that may further
impact the Salem Unit No. 2 startup schedule. The generic letter requested all
nuclear utilities to review systems for potential waterhammer events
(hydrodynamic stress caused by steam formation in a piping system) and the
impact that these events could have on the system's safety function. PSE&G has
determined that, in order to address the concerns of the generic letter,
modifications are necessary to the containment fan coil units of Salem Units No.
1 and No. 2, which provide containment air cooling. As a result of installation
of these modifications and the time required for NRC acceptance of PSE&G's
proposed resolution of these issues, the restart of Salem Unit No. 2 may be
delayed.
At the January 1997 semi-annual NRC Senior Management Meeting, the Salem
units were placed on the "NRC Watch List" (Watch List) and were designated as
Category 2 facilities. In a letter to PSE&G advising of the action, the NRC
noted that its decision to place the Salem units on the Watch List was not based
on any recent performance problems or decline but was due to the NRC's
determination that the Salem units should have been placed on the Watch List
previously because of Salem's past safety performance. The NRC also indicated in
its letter that it had increased its attention and resources at Salem
commensurate with a Watch List plant. Finally, the NRC concluded that,
notwithstanding the improvements at Salem (which were noted), had it been
previously identified as a Watch List plant, Salem would not have been removed
from the Watch List since Salem had yet to demonstrate a period of safe
performance at power. The NRC has three classifications of facility monitoring.
A Category 3 facility is one which is having or has had significant weaknesses
that warrant maintaining the plant in a shutdown condition until the licensee
can demonstrate to the NRC that adequate programs have both been established and
implemented to ensure substantial improvement. Full NRC approval is required for
restart of plants in this category which the NRC will monitor closely. A
Category 2 facility is a plant that is authorized to operate but that the NRC
will monitor closely. Although being operated in a manner that adequately
protects public health and safety, plants in this category are having or have
had weaknesses that warrant increased NRC attention. A plant will remain in this
category until the licensee either demonstrates a period of improved
performance, or until a further deterioration of performance results in the
plant being placed in Category 3. A Category 1 facility is a plant that has been
removed from the Watch List.
On January 14, 1997, a United States Senator from Delaware wrote to the NRC
to request the full NRC vote on the decision to restart the Salem units, rather
than permit the NRC staff to authorize the restart under applicable NRC rules.
By letter dated February 20, 1997, the NRC advised that it would not require a
full NRC vote on the decision to restart Salem.
The Company has been informed by PSE&G that in August 1996, the NRC
conducted an inspection of the Physical Security Program for Salem and Hope
Creek Generating Station (of which the Company has no ownership interest). On
December 11, 1996, PSE&G received a $100,000 civil penalty for two violations.
Three
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other violations were received with no civil penalty. PSE&G will not dispute
these violations. PSE&G has not yet allocated the civil penalty between Salem
and Hope Creek.
The Company has been informed by PSE&G that on December 11, 1996, PSE&G
received notice of a violation and an $80,000 civil penalty from the NRC for
events at Salem which occurred in 1993 and early 1994, involving alleged
discrimination against two employees for their engagement in protected
activities in accordance with federal regulations. PSE&G will not dispute this
violation.
In addition to the matters discussed above, see "ITEM 3. LEGAL PROCEEDINGS"
and "Environmental Regulations -- Water."
In 1996, the Company and PSE&G announced the commissioning of a study to
identify and evaluate alternatives to their separate nuclear plant operations.
In particular, the study evaluated strategies to reduce nuclear operation and
maintenance costs for both companies and increase efficiencies of operations. In
March 1997, both companies agreed to defer any further evaluation of a combined
nuclear operating company.
Fuel
The following table shows the Company's sources of electric output for 1996
and as estimated for 1997:
1996 1997 (Est.)
Nuclear ....................................... 43.0% 49.4%
Mine-mouth, coal-fired ........................ 8.8 6.2
Service-area, coal-fired ...................... 8.1 6.5
Oil-fired ..................................... 2.0 3.4
Gas-fired ..................................... 0.3 3.7
Hydro (includes pumped storage) ............... 3.0 2.6
Internal combustion ........................... 0.3 0.0
Purchased, interchange and nonutility generated 34.5 28.2
----- -----
100.0% 100.0%
===== =====
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. 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 2001 and 50%
of the requirements through 2003. 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:
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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) 2000
Salem Unit No. 1............................ 2001 (3) 2004
Salem Unit No. 2............................ 2001 (3) 2005
- ---------------
(1) The Company has commitments for 100% of its conversion services for
Limerick and Peach Bottom through 2001 and at least 60% of the conversion
services requirements are covered through 2002. 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
2004. 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.
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 is 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. The Company is considering the
construction of a dry spent-fuel storage facility at Peach Bottom to maintain
full-core discharge capacity in the spent-fuel pools. Construction would take
approximately 27 months. The Company expects that such a facility would cost $10
million to construct and would provide storage capacity at Peach Bottom for the
life of the plant. The Company would have to purchase storage canisters for the
spent fuel at an estimated cost of $2.7 million per year. The Company has been
informed by PSE&G that as a result of reracking the two spent-fuel pools at
Salem, the spent-fuel storage capability of Salem Units No. 1 and No. 2 is
estimated to be 2008 and 2012, respectively.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is required to
begin taking possession of all spent nuclear fuel generated by the Company's
nuclear units for long-term storage by no later than 1998. Based on recent
public pronouncements, it is not likely that a permanent disposal site will be
available for the industry before 2015, at the earliest. In reaction to
statements from the DOE that it was not legally obligated to begin to accept
spent fuel in 1998, a group of utilities and state government agencies filed a
lawsuit against the DOE which resulted in a decision by the United States Court
of Appeals for the District of Columbia (D.C. Court of Appeals) in July 1996
that the DOE has an unequivocal obligation to begin accepting spent fuel in
1998. In accordance with the NWPA, the Company pays the DOE one mill ($.001) per
kilowatthour of net nuclear generation for the cost of nuclear fuel disposal.
This fee may be adjusted prospectively in order to ensure full cost recovery.
Because of inaction by the DOE in response to the D.C. Court of Appeals finding
of the DOE's obligation to begin receiving spent fuel in 1998, a group of
thirty-six utility companies, including the Company, and forty-six state
agencies, filed suit against the DOE on January 31, 1997 seeking authorization
to suspend further payments to the U.S. government under the NWPA and to deposit
such payments into an escrow account until such time as the DOE takes effective
action to meet its 1998 obligations. Legislation introduced in Congress in
January 1997 would authorize construction of a temporary storage facility which
could accept spent nuclear fuel from utilities soon after 1998. In addition, the
DOE is exploring other options to address delays in the waste
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acceptance schedule. The 1996 charge collected by the Company from its customers
for spent-fuel disposal was $22 million.
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 disposal site located in Barnwell,
South Carolina for disposal. On-site storage facilities have been 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 a LLRW reduction program.
Pennsylvania has agreed to be the host site for a LLRW disposal facility for
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.
Salem has on-site LLRW storage facilities with a five-year storage
capacity. The Company has been informed by PSE&G that 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 $50 million
for such costs at December 31, 1996. The Company is currently recovering these
costs through rates.
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 GPU
Generating Corp. 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 1997 through 1999; and a total of 6,500,000
tons for the years 2000 through 2004. At December 31, 1996, approximately 20% of
Conemaugh's fuel requirements were secured by a long-term contract and the
remainder by several short-term contracts or spot purchases.
The Company has entered into 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, 1997, 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.
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Oil
The Company purchases fuel oil through a combination of contracts and spot
market purchases. The contracts are normally not longer than one year in length.
Fuel oil inventories are managed such that in the winter months sufficient
volumes of fuel are available in the event of extreme weather conditions and
during the remaining months inventory levels are managed to take advantage of
favorable market pricing.
Natural Gas
The Company obtains natural gas for electric generation through a
combination of short-term contracts and spot purchases made on the open market,
as well as through the Company's own gas 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 1996, 10.0% of the Company's operating revenues and 8.1% of its
operating income were from gas operations. Gas sales and operating revenues for
1996 by class of customer are set forth below:
Operating
Sales Revenues
(mmcf) (millions of $)
House heating ............................ 35,471 $249
Residential (other than house heating).... 1,681 16
Commercial and industrial ................ 20,999 133
Other .................................... 2,571 11
Decrease in unbilled ..................... (1,306) (4)
------ ----
Total gas sales ...................... 59,416 405
Gas transported for customers ............ 27,891 24
------ ----
Total gas sales and gas transported... 87,307 $429
====== ====
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").
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 1996-97
heating season supplies.
As a result of FERC Order No. 636 and the subsequent restructuring of the
interstate pipeline industry, unbundling at the local distribution level
continues in the form of pilot programs which allow smaller retail gas customers
to purchase non-utility gas supplies and acquire transportation services from
local distribution companies. Significant issues 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 have yet to be formally
addressed. See "Deregulation and Rate Matters."
15
<PAGE>
Horizon Energy Company, formerly PECO Gas Supply Company, a wholly owned
subsidiary, is an unregulated marketing enterprise. Horizon Energy is engaged in
marketing gas to residential and commercial gas customers outside of the
Company's service territory. Horizon Energy is also a member of a natural gas
buying cooperative created to enhance reliability of service and access less
expensive gas supplies for its eight gas utility members.
Eastern Pennsylvania Exploration Company (EPEC), a wholly owned subsidiary,
was a party to several joint ventures formed to develop natural gas resources in
the Gulf Coast area. These joint ventures did not contribute to the Company's
natural gas supply. The Company has sold its interest in these joint ventures
and is in the process of dissolving EPEC.
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 1996.
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 1992-96,
gross property additions (excluding capital leases) amounted to $2.6 billion and
retirements amounted to $249 million, resulting in a net increase of
approximately 17% in the Company's gross utility plant. Investment in new plant
and equipment in 1996 amounted to $534 million. At December 31, 1996,
construction work in progress, excluding nuclear fuel, aggregated $662 million.
The following table shows the Company's most recent estimates of capital
expenditures for plant additions and improvements for 1997 and for 1998-2000:
(Millions of $)
1997 1998-2000
Electric:
Production .................... $151 $210
Nuclear fuel .................. 12 176
Transmission and distribution.. 153 427
Other electric ................ 5 15
---- ------
Total electric ............ 321 828
Gas ................................ 65 210
Other .............................. 174 187
---- ------
Total ......................... $560 $1,225
==== ======
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 15 of Notes to Consolidated Financial Statements
included in the Company's Annual Report to Shareholders for the year 1996.
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<PAGE>
Capital Requirements and Financing Activities
The following table shows the Company's most recent estimates of capital
requirements for 1997 and for 1998-2000:
(Millions of $)
1997 1998-2000
Construction ................................. $560 $1,225
New ventures (1) ............................. 111 173
Long-term debt maturities and sinking funds... 283 642
---- ------
Total capital requirements .......... $954 $2,040
==== ======
- ---------------
(1) A portion of these expenditures will be expensed.
The following table shows the Company's financing activities for 1996:
(Millions of $)
Pollution Control:
Floating Rate due 1997 17.24
Floating Rate due 2034 34.00
------
$51.24
======
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, 1996 was 4.39
times. Earnings coverages under the Mortgage for the calendar years 1995 and
1994 were 4.94 and 3.48 times, respectively. At December 31, 1996, the most
restrictive issuance test of the Mortgage related to available property
additions. At December 31, 1996, the Company had at least $1.62 billion of
available property additions against which $970 million of mortgage bonds could
have been issued. In addition, at December 31, 1996, the Company was entitled to
issue approximately $3.6 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, 1996 was 2.50 times. Earnings coverage under the
Articles for the calendar years 1995 and 1994 was 2.34 and 2.05 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:
<TABLE>
<CAPTION>
1992 1993 1994 1995 1996
<S> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed Charges ............ 2.43 3.15 2.66 3.41 3.29
Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividends ................ 2.06 2.67 2.32 3.12 3.04
</TABLE>
17
<PAGE>
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, 1996, the Company had a total of $262.5 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, 1996, there was $200 million
of commercial paper outstanding. At December 31, 1996, 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, 1996, the Company had no compensating balance agreements with
any bank.
For additional information, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in the Company's Annual Report to
Shareholders for the year 1996.
Employee Matters
On March 7, 1995, a New Jersey local of the International Brotherhood of
Electrical Workers, AFL-CIO, (IBEW) filed two petitions with the National Labor
Relations Board (NLRB) to hold certification elections to determine whether a
group of production and maintenance employees from Eddystone and Cromby want the
IBEW to serve as their collective bargaining representative. The petitions
sought to establish separate bargaining units for 229 employees from Eddystone
and 74 employees from Cromby. The petitions covered craft and technical
employees, including operators, but excluded office clerical, professional,
supervisory and management employees.
On March 22, 1995, the Utility Workers 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, as
well as the maintenance employees headquartered in the Company's Chesterbrook
facility, want the UWUA to serve as their collective bargaining representative.
The UWUA petition sought to establish a bargaining unit of approximately 840
employees composed of all maintenance employees and all control room operators,
auxiliary operators, instrument and control technicians, health physics
technicians, chemistry technicians, material handlers and technicians, and
radioactive waste technicians. The petition excluded security guards, clerical
and supervisory employees.
On October 2, 1995, 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's customer service business
unit.
On February 14, 1997, the NLRB issued its decision ruling that a union
representation election does not require all hourly employees within the Company
to vote as one unit. On the petitions filed by the IBEW, the NLRB ruled that
while Eddystone and Cromby would not be appropriate bargaining units, the
Company's Power Generation Group (PGG), which encompasses employees not only at
Eddystone and Cromby but also eight smaller fossil-fuel plants located in the
City of Philadelphia and its suburbs, the Conowingo Hydroelectric Station and
Muddy Run Pumped Storage Project would be an appropriate bargaining unit. The
NLRB ruled similarly that a separate bargaining unit comprised of the Company's
Nuclear Generating Group (PECO Nuclear) would be appropriate.
On February 24, 1997, the NLRB established March 24, 1997 as the date for
the UWUA/PECO Nuclear election. On March 25, 1997, the NLRB announced that PECO
Nuclear employees voted not to be
18
<PAGE>
represented by a union. Employees cast 659 votes for `no union,' and 228 votes
for the UWUA. The results are not official until the NLRB certifies the
election. All parties involved in the election have seven days to contest the
results.
On March 26, 1997, the NLRB established April 24, 1997 as the date for the
IBEW/PGG election.
In 1993, in an NLRB certified election, a majority of non-management
employees rejected representation by the IBEW and the Independent Group
Association in company-wide elections.
The Company and its subsidiaries had 7,186 employees at December 31, 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. In
October 1996, the National Research Council, which is comprised of several
organizations, including the National Academy of Sciences, the National Academy
of Engineering, and the Institute of Medicine, released a report on EMF which
states that the current body of evidence does not show that exposure to EMF
presents a human health hazard. The National Research Council report recommends
additional research. The Company also supports further research in this area and
is funding and monitoring such studies.
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. The Company cannot predict at this time what effect, if
any, this issue will have on other future operations.
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 final 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 1997 and 1998-2000. In 1999,
PSE&G must apply to the New Jersey Department of Environmental Protection and
Energy (NJDEPE) and other agencies to renew such Salem permits.
Air
Air quality regulations promulgated by the EPA, the PDEP and the City of
Philadelphia in accordance with the federal Clean Air Act and the Clean Air Act
Amendments of 1990 (Amendments) impose restrictions on emission of particulates,
sulfur dioxide (SO2), nitrogen oxides (NOx) and other pollutants and require
permits for operation of emission sources. Such permits have been obtained by
the Company and must be renewed periodically.
The Amendments establish a comprehensive and complex national program to
substantially reduce air pollution. The Amendments include a two-phase program
to reduce acid rain effects by significantly reducing
19
<PAGE>
emissions of SO2 and 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 Phase I requirements of the Amendments.
Keystone Units No. 1 and No. 2 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 expects that the cost of compliance with anticipated
air-quality regulations may be substantial 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, however, the Company believes that compliance with the Amendments will
have less impact on the Company's electric operations than on 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 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 April 18, 1996, a consent decree, which included the terms of
the settlement, was entered by the United States District Court for the Eastern
District of
20
<PAGE>
Kentucky. 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, 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 $991,835 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 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. On July 9, 1996, the Company
executed a consent decree in which the Company agreed to pay the NJDEPE
approximately $240,000 in exchange for a
21
<PAGE>
release from liability at the GEMS site. The parties are currently awaiting
approval of the consent decree by the United States District Court for the
District of New Jersey (New Jersey District Court).
On October 16, 1989, the EPA and the NJDEPE commenced a civil action in the
New Jersey District Court against 26 defendants, not including the Company,
alleging the right to collect past and future response costs for cleanup of the
Helen Kramer landfill located in New Jersey. In October 1991, the direct
defendants joined the Company and over 100 other parties as third-party
defendants. The third-party complaint alleges that the Company generated
materials containing hazardous substances that were transported to and disposed
at the landfill by a third party. The Company, together with a number of other
direct and third- party defendants, has agreed to participate in a proposed de
minimis settlement which would allow the Company to settle its potential
liability at the site for approximately $40,000.
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. 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. On September 25, 1996, the
Company agreed to a settlement with the party participants which provides for
the Company to pay $375,000 to settle its potential liability at the site. Not
covered by the settlement are possible natural resource damage and private party
claims.
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, which was denied; however all claims against third-party
defendants have been stayed. 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.
On November 18, 1996, the Company received a notice from the EPA that the
Company is a PRP at the Malvern TCE Superfund Site, located in Malvern,
Pennsylvania. The Company is currently unable to estimate the amount of
liability, if any, it may have with respect to this site.
On February 3, 1997, the Company was served with a third-party complaint
involving the Pennsauken Sanitary Landfill. The Company is currently unable to
estimate the amount of liability it may have with respect to this site.
In June 1989, a group of PRPs (Metro PRP Group) entered into an
Administrative Order on Consent 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. Since
that time, the Company has reviewed, and continues to review its files and
records and has been unable to locate any information which would indicate any
connection to the site. The Company does not believe that it has any liability
with respect to this site.
In November 1987, the Company received correspondence from the EPA which
indicated that the EPA was investigating the release of hazardous substances
from the Blosenski Landfill located in West Caln Township, Chester County,
Pennsylvania. The Company has been unable to locate any information which would
indicate any connection to this site. The Company does not believe it has any
liability with respect to this site.
22
<PAGE>
The Company has identified 27 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. Eight of the sites are under some degree of active study or
remediation. At December 31, 1996, the Company had accrued approximately $16
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% 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 million. At December 31,
1996, the Company had spent approximately $1.7 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, 1996, the Company had accrued $28 million for various
investigation and remediation costs that can be reasonably estimated, including
approximately $16 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 1997 and its most recent
estimate of capital requirements for 1998-2000 for compliance with environmental
requirements total approximately $26 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.
Telecommunications
In a joint venture with Hyperion, a subsidiary of Adelphia Cable Company,
the deployment of a large-scale fiber optic, cable-based telephone service in
the Philadelphia region is approximately 80% complete. The Company's fiber optic
cable currently extends over 400 miles and is connected to major long-distance
carriers.
The Company is also aggressively completing the initial build-out of a new
digital wireless Personal Communications Services (PCS) network in partnership
with AT&T Wireless Services. Commercial launch of PCS in the Philadelphia area
is scheduled for mid-1997. Due to the start-up nature of these joint ventures,
investments in telecommunications will negatively affect earnings in the near
future and are not expected to produce positive results for several years.
23
<PAGE>
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 (Subordinated Debentures), which are the only assets of
the Partnership. The only revenues of the Partnership are interest on the
Subordinated Debentures. All of the operating expenses of the Partnership are
paid by PECO Energy Capital Corp. As of December 31, 1996, 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. As
of December 31, 1996, the Trust had outstanding 3,124,183 Trust Receipts. At
December 31, 1996, 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 during 1996 in the
aggregate amount of $6,810,719, or $2.18 per Trust Receipt. Expenses of the
Trust for 1996 were approximately $200,000, 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 December 31, 1996 was 874.
24
<PAGE>
Executive Officers of the Registrant
<TABLE>
<CAPTION>
Age at Effective Date of Election
Name Dec. 31, 1996 Position to Present Position
<S> <C> <C> <C>
J. F. Paquette, Jr............. 62 Chairman of the Board............................... April 12, 1995
C. A. McNeill, Jr.............. 57 President and Chief Executive Officer............... April 12, 1995
D. M. Smith.................... 63 President-- PECO Nuclear and Chief
Nuclear Officer................................. February 1, 1996
W. L. Bardeen.................. 58 Senior Vice President and Group Executive--
Consumer Energy Services Group.................. March 1, 1994
J. W. Durham................... 59 Senior Vice President and General Counsel........... October 24, 1988
W. J. Kaschub.................. 54 Senior Vice President-- Human Resources............. June 10, 1991
G. S. King..................... 56 Senior Vice President-- Corporate and
Public Affairs.................................. October 1, 1992
K. G. Lawrence................. 49 Senior Vice President-- Finance and Chief
Financial Officer............................... March 1, 1994
J. M. Madara, Jr............... 53 Senior Vice President and Group
Executive-- Power Generation Group.............. March 1, 1994
R. J. Patrylo.................. 50 Senior Vice President and Group
Executive-- Gas Services Group.................. August 1, 1994
A. J. Weigand.................. 58 Senior Vice President and Group
Executive-- Bulk Power Enterprises ............. March 1, 1994
G. R. Rainey................... 47 Senior Vice President-- PECO Nuclear................ April 1, 1996
J. M. Bauer.................... 50 Vice President-- Customer Services.................. April 13, 1994
G. A. Cucchi................... 47 Vice President-- Corporate Planning
and Development................................. March 1, 1994
J. Doering, Jr................. 53 Vice President-- Operations - Power
Generation Group................................ October 28, 1996
D. B. Fetters.................. 45 Vice President-- Station Support.................... September 25, 1995
T. P. Hill, Jr................. 48 Vice President and Controller....................... January 1, 1991
K. C. Holland.................. 44 Vice President-- Information Systems
and Chief Information Officer................... March 21, 1994
W. G. MacFarland, IV........... 47 Vice President-- Limerick Generating
Station......................................... March 1, 1995
J. B. Mitchell................. 48 Vice President-- Finance and Treasurer.............. December 1, 1994
T. N. Mitchell................. 41 Vice President-- Peach Bottom Atomic
Power Station................................... April 1, 1996
W. E. Powell, Jr............... 60 Vice President-- Support Services................... January 30, 1995
W. H. Smith, III............... 48 Vice President and Group Executive--
Telecommunications Group........................ September 25, 1995
D. A. Thomas................... 50 Vice President-- Marketing and Sales................ January 30, 1995
N. J. Zausner.................. 43 Vice President-- Power Transactions................. October 11, 1994
K. K. Combs.................... 46 Corporate Secretary................................. November 1, 1994
</TABLE>
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 9, 1997).
Prior to his election to his current position, Mr. Paquette was Chairman
and Chief Executive Officer.
Prior to his election to his current position, Mr. McNeill was President
and Chief Operating Officer and Executive Vice President - Nuclear.
Prior to his election to his current position, Mr. D. M. Smith was Senior
Vice President - Nuclear Generation Group, Senior Vice President - Nuclear and
Vice President - Peach Bottom Atomic Power Station.
25
<PAGE>
Prior to his election to his current position, 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.
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, Mr. Lawrence was Vice
President - Gas Operations.
Prior to his election to his current position, Mr. Madara was Vice
President - Production.
Prior to joining the Company in 1994, Mr. Patrylo was Senior Vice President
- - Gas Services Business Unit at Niagara Mohawk Power Corporation.
Prior to his election to his current position, Mr. Weigand was Vice
President - Transmission and Distribution Services.
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, 1992:
Ms. Bauer was Operations Manager - Montgomery County Division and Manager -
Nuclear Operations; Mr. Cucchi was Director of System Planning and Performance,
and Manager - System Planning; Mr. Doering was Plant Manager - Limerick,
Director - Nuclear Strategies Support, and General Manager - Operations; Mr.
Fetters was Director - Nuclear Engineering, Director - Limerick Maintenance and
a project manager; Mr. MacFarland was Outage Management Director - Limerick,
Manager - Nuclear Maintenance, and Manager - Peach Bottom Installation Division;
Mr. J. B. 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, III was Vice President - Station Support, Vice President -
Planning and Performance, and Manager - Corporate Strategy and Performance; and
Ms. Combs was an Assistant General Counsel.
There are no family relationships among directors or executive officers of
the Company.
26
<PAGE>
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, 1996:
<TABLE>
<CAPTION>
Net Generating Estimated
Capacity (1) Retirement
Station Location (Kilowatts) Year
Nuclear
<S> <C> <C> <C>
Limerick.................................. Limerick Twp., PA.............. 2,220,000 2024(2), 2029(2)
Peach Bottom.............................. Peach Bottom Twp., PA.......... 928,000(3) 2013, 2014
Salem..................................... Hancock's Bridge, NJ........... 942,000(3) 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 (4)
Eddystone................................. Eddystone, PA.................. 1,341,000 2009, 2010, 2011
Schuylkill................................ Philadelphia, PA............... 166,000 (4)
Conemaugh................................. New Florence, PA............... 352,000(3) 2005, 2006
Keystone.................................. Shelocta, PA................... 357,000(3) 2002, 2003
Fossil (Gas Turbines)
Chester .................................. Chester, PA.................... 39,000 (4)
Croydon................................... Bristol Twp., PA............... 370,000 (4)
Delaware.................................. Philadelphia, PA............... 60,000 (4)
Eddystone................................. Eddystone, PA.................. 64,000 (4)
Fairless Hills............................ Falls Twp., PA................. 60,000 (4)
Falls..................................... Falls Twp., PA................. 50,000 (4)
Moser..................................... Lower Pottsgrove Twp., PA...... 48,000 (4)
Pennsbury................................. Falls Twp., PA................. 6,000 (4)
Richmond.................................. Philadelphia, PA............... 96,000 (4)
Schuylkill................................ Philadelphia, PA............... 32,000 (4)
Southwark................................. Philadelphia, PA............... 54,000 (4)
Salem..................................... Hancock's Bridge, NJ........... 16,000(3) (4)
Fossil (Internal Combustion)
Cromby.................................... Phoenixville, PA .............. 2,700 (4)
Delaware.................................. Philadelphia, PA............... 2,700 (4)
Schuylkill................................ Philadelphia, PA............... 2,800 (4)
Conemaugh................................. New Florence, PA............... 2,300(3) 2006
Keystone.................................. Shelocta, PA................... 2,300(3) 2003
---------
Total.................................................................... 9,200,800
=========
<FN>
- ---------------
(1) Summer rating.
(2) For depreciation accrual purposes only, retirement dates have been reduced by 10 years.
(3) Company portion.
(4) Retirement dates are under on-going review by the Company. Current plans call for the continued
operation of these units beyond 1997.
</FN>
</TABLE>
27
<PAGE>
The following table sets forth the Company's major transmission and
distribution lines in service at December 31, 1996:
Voltage in Kilovolts (Kv) Conductor Miles
Transmission:
500 Kv.................................................... 825
220 Kv.................................................... 1,503
132 Kv.................................................... 677
66 Kv.................................................... 607
33 Kv and below.......................................... 29
Distribution:
33 Kv and below.......................................... 49,140
At December 31, 1996, the Company's principal electric distribution system
included 13,405 pole-line miles of overhead lines and 20,673 cable miles of
underground cables.
The following table sets forth the Company's gas pipeline miles at December
31, 1996:
Pipeline Miles
Transmission....................................... 28
Distribution....................................... 5,642
Service piping..................................... 4,507
------
Total.............................................. 10,177
======
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.
At December 31, 1996, the Company had 362 miles of underground fiber optic
cable.
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 15 of Notes to Consolidated Financial Statements
included in the Company's Annual Report to Shareholders for the year 1996.
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
$31 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 could have a material adverse effect on
the Company's financial condition and results of operations.
28
<PAGE>
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. On October 1, 1996, the United States Court of Appeals
for the Third Circuit (Third Circuit Court of Appeals) reversed the Eastern
District Court decision and held for the Company. The plaintiffs have since
appealed to the United States Supreme Court (Supreme Court). Pending resolution
of this matter, the Company has accrued the amount awarded by the Eastern
District Court.
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. On October 1, 1996, the Third Circuit Court of Appeals reversed the
Eastern District Court decision and held for the Company. Three plaintiffs who
were members of the class certified by the Eastern District Court have filed a
motion for reconsideration with the Third Circuit Court of Appeals. The Company
has opposed the motion for reconsideration. If their request is denied by the
Third Circuit Court of Appeals, the Company expects that the class members will
appeal to the Supreme Court. Pending resolution of this matter, the Company has
accrued the amount awarded by the Eastern District Court.
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
29
<PAGE>
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. On February 23, 1996, the Company and the defendants
filed a petition to terminate the consolidated action on the basis of the March
14, 1994 Board of Directors' resolution refusing the shareholders' demand. On
May 15, 1996, the Court of Common Pleas denied the petition. On June 20, 1996,
the Company filed a petition with the Supreme Court of Pennsylvania for
extraordinary relief. On October 15, 1996, the Supreme Court of Pennsylvania
granted the Company's petition and oral argument was held on January 27, 1997.
Pending resolution of this issue by the Supreme Court of Pennsylvania, all
matters in the lower courts related to the suits are suspended. 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 Eastern District Court against Public Service Enterprise
Group Incorporated and its subsidiary PSE&G (Enterprise Group) concerning the
shutdown of Salem. The suit alleges that Enterprise Group breached the
provisions of the Owners Agreement pursuant to 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. Discovery in the case is
scheduled to conclude in April 1997. The case is expected to go to trial in
1997.
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 Company and Delmarva, the co-owners of Salem,
filed an action in the New Jersey District Court 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, 1997, there were 176,590 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 1996
and 1995 is incorporated herein by reference to "Operating Statistics" in the
Company's Annual Report to Shareholders for the year 1996.
The book value of the Company's common stock at December 31, 1996 was
$20.88 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
30
<PAGE>
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, 1996, such capital ($4.65 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 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 1996.
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 1996.
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 1996.
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 1997 Annual Meeting of Shareholders to be
held April 9, 1997, under the heading "Proposal 1. Election of Directors" and is
incorporated herein by reference.
(b) Identification of Executive Officers.
31
<PAGE>
The information required for Executive Officers is set forth in "PART I.
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 1997 Annual Meeting of
Shareholders to be held April 9, 1997, under the heading "Executive Compensation
Disclosure" and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information with respect to this caption is included in the Proxy
Statement of the Company in connection with its 1997 Annual Meeting of
Shareholders to be held April 9, 1997, 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 1997 Annual Meeting of
Shareholders to be held April 9, 1997, under the heading "Proposal 1. Election
of Directors" and is incorporated herein by reference.
32
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Financial Statement Schedule
<TABLE>
<CAPTION>
Reference (Page)
Form 10-K Annual Report
Index Annual Report to Shareholders
<S> <C> <C>
Data incorporated by reference from the Annual Report
to Shareholders for the year 1996:
Report of Independent Accountants .......................... -- 20
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994 ......................... -- 21
Consolidated Balance Sheets as of December 31, 1996 and 1995 -- 22
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994 ......................... -- 24
Consolidated Statements of Changes in Common Shareholders'
Equity and Preferred Stock for the years ended
December 31, 1996, 1995 and 1994 ......................... -- 25
Notes to Consolidated Financial Statements ................. -- 26
Data submitted herewith:
Report of Independent Accountants .......................... 34 --
Schedule II-- Valuation and Qualifying Accounts for the years
ended December 31, 1996, 1995 and 1994 .... 35 --
</TABLE>
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 1996 and incorporated by
reference into this Form 10-K Annual Report, the Annual Report to Shareholders
for the year 1996 is not to be deemed "filed" as part of this Form 10-K.
33
<PAGE>
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 20 of the 1996
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 3, 1997
34
<PAGE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
<TABLE>
<CAPTION>
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, 1996
<S> <C> <C> <C> <C> <C>
ALLOWANCE FOR UNCOLLECTIBLE
ACCOUNTS ............................ $20,860 $50,976 $ -- $47,796 $24,040
------- ------- ----- ------- -------
TOTAL .................... $20,860 $50,976 $ -- $47,796 $24,040
======= ======= ===== ======= =======
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
======= ======= ===== ======= =======
</TABLE>
- ---------------
(1) Write-off of individual accounts receivable.
35
<PAGE>
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 Union National
Bank, successor), (Registration No. 2-2881, Exhibit B-1).
4-2 Supplemental Indentures to the Company's First and Refunding
Mortgage:
<TABLE>
<CAPTION>
Dated as of File Reference Exhibit No.
<S> <C> <C>
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
<PAGE>
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
</TABLE>
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
First Union National Bank, as successor trustee (1994 Form
10-K, Exhibit 4-5).
4-6 First Supplemental Indenture, dated as of December 1, 1995,
between the Company and First Union National Bank, as
successor trustee, to Indenture dated as of July 1, 1994 (1995
Form 10-K, Exhibit 4-7).
4-7 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).
4-8 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 (1995 Form 10-K, Exhibit 4-10).
37
<PAGE>
10-1 Pennsylvania-New Jersey-Maryland Interconnection Agreement
dated September 26, 1956 (Registration No. 2-13340, Exhibit
13-40) and agreements supplemental thereto:
<TABLE>
<CAPTION>
Dated as of File Reference Exhibit No.
<S> <C> <C>
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)
</TABLE>
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
(1995 Form 10-K, Exhibit 10-5).
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. (1995 Form
10-K, Exhibit 10-8).
10-9 Amendment No. 2 to the Amended and Restated Limited
Partnership Agreement of PECO Energy Capital, L.P. (1995 Form
10-K, Exhibit 10-9).
10-10 Amended and Restated Trust Agreement of PECO Energy Capital
Trust I, dated as of December 19, 1995. (1995 Form 10-K,
Exhibit 10-10).
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 1996.
38
<PAGE>
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, 1996, the Company filed Current
Reports on Form 8-K, dated:
December 3, 1996 reporting information under "ITEM 5. OTHER EVENTS"
relating to Pennsylvania Governor Ridge signing the Pennsylvania
Electricity Generation Customer Choice and Competition Act into law.
December 20, 1996 reporting information under "ITEM 5. OTHER EVENTS"
relating to the elimination of the Energy Cost Adjustment.
Subsequent to December 31, 1996, the Company filed Current Reports on Form
8-K, dated:
January 23, 1997 reporting information under "ITEM 5. OTHER EVENTS"
relating to the Company's filing with the Pennsylvania Public Utility
Commission for the issuance of a Qualified Rate Order authorizing
recovery of stranded and other costs through the issuance of Transition
Bonds.
January 24, 1997 reporting information under "ITEM 5. OTHER EVENTS"
relating to Salem Generating Station operated by Public Service
Electric and Gas Company.
January 30, 1997 reporting information under "ITEM 5. OTHER EVENTS"
relating to Salem Generating Station operated by Public Service
Electric and Gas Company.
February 21, 1997 reporting information under "ITEM 5. OTHER EVENTS"
relating to the National Labor Relations Board's decision regarding
certification elections.
February 27, 1997 reporting information under "ITEM 5. OTHER EVENTS"
relating to the Company filing its electric competition pilot program,
the National Labor Relations Board's order setting the date for a
certification election and the Company's offer to purchase an interest
in a nuclear operating facility.
March 25, 1997 reporting information under "ITEM 5. OTHER EVENTS"
relating to the results of the National Labor Relations Board's
certification election.
39
<PAGE>
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 31st day of March 1997.
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 March 31, 1997
- ------------------------- Director
J. F. Paquette, Jr.
/s/ C. A. MCNEILL, JR. President, Chief Executive March 31, 1997
- ------------------------- Officer and Director
C. A. McNeill, Jr. (Principal Executive Officer)
/s/ K. G. LAWRENCE Senior Vice President - March 31, 1997
- ------------------------- Finance and Chief Financial
K. G. Lawrence 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
G. FRED DIBONA KINNAIRD R. MCKEE
R. KEITH ELLIOTT JOSEPH J. MCLAUGHLIN
RICHARD G. GILMORE JOHN M. PALMS
RICHARD H. GLANTON RONALD RUBIN
JAMES A. HAGEN ROBERT SUBIN
NELSON G. HARRIS
By /s/ C. A. MCNEILL, JR. March 31, 1997
- ---------------------------
C. A. McNeill, Jr., Attorney-in-Fact
Exhibit 12-1
PECO ENERGY COMPANY AND SUBSIDIARY COMPAINES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
SEC METHOD
($000)
12 Months
Ended
12/31/96
NET INCOME $517,205
ADD BACK:
- -INCOME TAXES:
OPERATING INCOME $343,105
NON-OPERATING INCOME ($3,004)
NET TAXES $340,101
- -FIXED CHARGES:
INTEREST APPLICABLE TO DEBT $366,360
ANNUAL RENTALS ESTIMATE $8,789
TOTAL FIXED CHARGES $375,149
ADJUSTED EARNINGS INCLUDING AFUDC $1,232,455
RATIO OF EARNINGS TO FIXED CHARGES 3.29
Exhibit 12-2
PECO ENERGY COMPANY AND SUBSIDIARY COMPAINES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
SEC METHOD
($000)
12 Months
Ended
12/31/96
NET INCOME $517,205
ADD BACK:
- -INCOME TAXES:
OPERATING INCOME $343,105
NON-OPERATING INCOME ($3,004)
NET TAXES $340,101
- -FIXED CHARGES:
TOTAL INTEREST $366,360
ANNUAL RENTALS ESTIMATE $8,789
TOTAL FIXED CHARGES $375,149
EARNINGS REQUIRED FOR PREFERRED DIVIDENDS:
DIVIDENDS ON PREFERRED STOCK $18,036
ADJUSTMENT TO PREFERRED DIVIDENDS* $11,860
$29,896
FIXED CHARGES AND PREFERRED DIVIDENDS $405,045
EARNINGS BEFORE INCOME TAXES AND FIXED CHARGES $1,232,455
RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
EARNINGS REQUIRED FOR PREFERRED DIVIDENDS 3.04
13
Management's Discussion and Analysis of Financial Condition and Results of
Operations
General
In December 1996, Pennsylvania Governor Tom Ridge signed into law the
Electricity Generation Customer Choice and Competition Act (Competition Act)
which provides for the restructuring of the electric utility industry in
Pennsylvania, including retail competition for generation beginning in 1999. The
Company estimates that its stranded costs resulting from retail electric
generation competition mandated by the Competition Act at December 31, 1998 will
be $7.1 billion.
The Company intends to seek recovery of these stranded costs and to securitize
that recovery in accordance with the provisions of the Competition Act. The
proceeds of the securitization will be used to reduce stranded costs and related
capitalization.
The Company believes that the Competition Act and other regulatory initiatives
that provide for competition for generation services will significantly affect
the Company's future financial condition and results of operations. At this time
the Company cannot predict whether those changes will materially affect the
market prices of its publicly traded securities. See "Outlook-Competition Act."
Discussion of Operating Results
Earnings and Dividends
Earnings per common share were $2.24 in 1996 as compared with $2.64 and $1.76 in
1995 and 1994, respectively. The $0.40 per share decrease in 1996 earnings was
primarily due to higher Salem Generating Station (Salem) outage-related
replacement power and maintenance costs which reduced earnings by $0.27 per
share. Earnings also decreased by $0.18 per share in 1996 due to lower electric
revenues resulting from less favorable weather conditions compared to last year,
by $0.12 per share due to the gain recognized in 1995 on the sale of Conowingo
Power Company (COPCO), by $0.11 per share due to higher customer expenses, and
by $0.06 per share due to the accelerated depreciation of assets associated with
Limerick Generating Station (Limerick). These decreases were partially offset by
$0.18 per share due to the Company's continuing cost control initiatives, by
$0.09 per share due to savings resulting from the Company's ongoing debt and
preferred stock refunding and refinancing program, and by $0.08 per share due to
higher revenues resulting from increased sales to other utilities.
The $0.88 per share increase in 1995 earnings was primarily due to a one-time
charge of $0.66 in 1994 associated with the Company's voluntary retirement and
separation incentive programs. Earnings also increased $0.22 per share in 1995
due to increased electric sales, by $0.19 per share due to the Company's ongoing
emphasis on cost control, by $0.12 per share due to the gain on the sale of
COPCO, and by $0.04 per share due to reduced financing costs. These increases
were partially offset by $0.14 per share due to additional costs incurred as a
result of the shutdown of Salem, by $0.14 per share due to increased taxes and
by $0.07 per share due to revenues recorded in 1994 from the receipt of nuclear
fuel from Shoreham Generating Station (Shoreham).
<PAGE>
14
Significant Operating Items
<TABLE>
<CAPTION>
Revenue and Expense Items as a
percentage of Total Operating
Revenues Percentage Dollar Changes
1994 1995 1996 1996-1995 1995-1994
<S> <C> <C> <C> <C>
90% 90% 90% Electric 2% 4%
10% 10% 10% Gas 4% (1%)
--- --- --- ---- -----
100% 100% 100% Total Operating Revenues 2% 4%
=== === === ==== ====
17% 18% 23% Fuel and Energy Interchange 27% 8%
38% 30% 30% Other Operation and Maintenance 2% (18%)
11% 11% 11% Depreciation 7% 3%
6% 9% 8% Income Taxes (14%) 70%
7% 8% 7% Other Taxes (5%) 1%
--- --- --- ---- -----
79% 76% 79% Total Operating Expenses 6% (1%)
=== === === ==== ====
21% 24% 21% Operating Income (10%) 21%
=== === === ==== ====
-- -- -- Allowance for Other Funds Used During Construction (29%) 41%
=== === === ==== ====
-- 1% -- Total Other Income and Deductions (70%) 111%
=== === === ==== ====
11% 11% 10% Total Interest Charges (8%) 3%
=== === === ==== ====
(1%) (1%) (1%) Allowance for Borrowed Funds Used During Construction (23%) 5%
--- --- --- ---- -----
10% 10% 9% Net Interest Charges (8%) 3%
=== === === ==== ====
11% 15% 12% Net Income (15%) 43%
=== === === ==== ====
Preferred Stock Dividends (22%) (38%)
==== ====
Earnings Applicable to Common Stock (15%) 51%
==== ====
Earnings per Average Common Share (15%) 50%
==== ====
</TABLE>
Operating Revenues
Total operating revenues increased in 1996 by $98 million to $4,284 million.
This represented an $80 million increase in electric revenues and an $18 million
increase in gas revenues over 1995. The increase in electric revenues was
primarily due to increased sales to other utilities and was partially offset by
decreased retail sales due to less favorable weather conditions. The increase in
gas revenues was primarily due to increased sales to retail customers from more
favorable weather conditions in the first half of 1996 and higher levels of firm
sales resulting from customers switching from transportation service to firm
service. These increases were partially offset by decreased sales and
transportation revenues resulting from unusually mild weather in December 1996.
Total operating revenues increased in 1995 by $146 million to $4,186
million. This represented a $151 million increase in electric revenues and a $5
million decrease in gas revenues over 1994. The increase in electric revenues
was primarily due to increased sales to other utilities and higher retail sales
due to favorable weather conditions. The increase in electric revenues from
residential sales was also attributable to higher fuel-clause revenues resulting
from yearly changes in the Company's Energy Cost Adjustment (ECA). The decrease
in gas revenues was primarily due to lower interruptible sales and sales of gas
to the Company's electric generating units because of reduced spot market rates.
This decrease was partially offset by higher fuel-clause revenues and increased
transportation revenues related to higher levels of gas transported for
customers purchasing gas on the spot market.
Increases/(decreases) in electric sales and operating revenues by class of
customer for 1996 compared to 1995 and 1995 compared to 1994 are set forth
below:
<TABLE>
<CAPTION>
1996 - 1995 1995 - 1994
Electric Electric Electric Electric
Sales Revenues Sales Revenues
(Millions of kWh) (Millions of $) (Millions of kWh) (Millions of $)
<S> <C> <C> <C> <C>
Residential (86) $ (14) 18 $ 20
House Heating 121 5 (241) (12)
Small Commercial
and Industrial 291 19 50 20
Large Commercial
and Industrial (555) (37) (205) (13)
Other 42 3 69 1
Unbilled (862) (69) 740 54
Service Territory (1,049) (93) 431 70
Interchange Sales 439 9 (272) (6)
Sales to Other Utilities 6,202 164 4,002 87
Total 5,592 $ 80 4,161 $ 151
</TABLE>
<PAGE>
15
Fuel and Energy Interchange Expense
Fuel and energy interchange expenses increased in 1996 by $210 million to
$973 million. The increase was primarily due to interchange purchases needed for
increased sales to other utilities, increased replacement power costs resulting
from the shutdown of Salem and a net credit to expense in 1995 from certain
energy sales to other utilities. Fuel and energy interchange expense as a
percentage of operating revenues increased from 18% to 23% principally due to
increased replacement power costs resulting from the shutdown of Salem.
Fuel and energy interchange expenses increased in 1995 by $59 million to
$763 million. The increase was primarily due to increased customer demand,
higher levels of sales to other utilities and replacement power costs resulting
from the shutdown of Salem. These increases were partially offset by net credits
to expense from the retention by the Company of a share of the energy savings
resulting from the operation of Limerick and from certain energy sales to other
utilities. The increases were further offset by lower purchased gas costs
resulting from reduced output. Fuel and energy interchange expense as a
percentage of operating revenues increased from 17% to 18% principally due to
increased interchange purchases.
Other Operating and Maintenance Expenses
Other operating and maintenance expenses increased in 1996 by $23 million
to $1,274 million due to higher customer expenses, higher contractor costs and
higher nuclear generating station charges resulting from the shutdown of Salem.
These increases were partially offset by lower operating costs at the
Company-operated nuclear generating stations and lower administrative and
general expenses resulting from the Company's ongoing cost-control efforts.
Other operating and maintenance expenses decreased in 1995 by $268 million
to $1,251 million. The decrease was primarily due to the charge in 1994
associated with the early retirement and separation programs, lower customer
expenses and lower nuclear generating station charges resulting from shorter
refueling and maintenance outages at Company-owned nuclear generating units.
These decreases were partially offset by increased process reengineering costs
and maintenance expenses at Salem. Other operating and maintenance expenses
decreased as a percentage of operating revenues from 38% to 30% primarily due to
the charge in 1994 associated with the early retirement and separation programs.
Depreciation Expense
Effective October 1, 1996, the Company increased depreciation and
amortization on assets associated with Limerick by $100 million per year and
decreased depreciation and amortization on other Company assets by $10 million
per year.
Depreciation expense increased in 1996 by $32 million to $489 million. The
increase was primarily due to the accelerated depreciation of assets associated
with Limerick which began in October 1996, and accounted for $23 million, or
one-quarter of the expected net annual increase of $90 million. Depreciation
expense also increased due to additions to plant in service.
Depreciation expense increased in 1995 by $15 million to $457 million. The
increase was primarily due to additions to plant in service.
Income Taxes
Income taxes decreased in 1996 by $54 million to $343 million. The decrease
was primarily due to lower operating income.
Income taxes increased in 1995 by $163 million to $397 million. The
increase was primarily due to increases in operating income.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFUDC) decreased in 1996 by
$7 million to $20 million. The decrease was primarily due to an adjustment in
1995. Also contributing to the decrease was a decrease in the 1996 AFUDC rate.
AFUDC increased in 1995 by $5 million to $27 million. The increase was
primarily due to an increase in the AFUDC rate, and an adjustment in 1995.
Other Income and Deductions
Other income and deductions decreased in 1996 by $23 million to $1 million.
The decrease was primarily due to the gain recognized in 1995 on the sale of
COPCO.
Other income and deductions increased in 1995 by $16 million to $24
million. The increase was primarily due to the gain on the sale of COPCO,
partially offset by revenues recorded in 1994 from the receipt of nuclear fuel
from Shoreham.
Total Interest Charges
Total interest charges decreased in 1996 by $36 million to $409 million.
The decrease was primarily due to the Company's ongoing program to reduce and
refinance higher-cost, long-term debt. This decrease was partially offset by the
replacement of preferred stock with Monthly Income Preferred Securities
(recorded in the financial statements as Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership), Series B, in the fourth
quarter of 1995.
Total interest charges increased in 1995 by $12 million to $445 million.
The increase was primarily due to the July 1994 issuance of Monthly Income
Preferred Securities, Series A.
Preferred Stock Dividends
Preferred stock dividends decreased in 1996 by $5 million to $18 million.
The decrease was primarily due to the replacement of preferred stock with
Monthly Income Preferred Securities, Series B in the fourth quarter of 1995.
Preferred stock dividends decreased in 1995 by $14 million to $23 million.
The decrease was primarily due to the replacement of preferred stock with
Monthly Income Preferred Securities, Series A in the third quarter of 1994.
<PAGE>
16
Discussion of Liquidity and Capital Resources
The Company's capital resources are primarily provided by internally generated
cash flows from utility operations and, to the extent necessary, external
financing. Such capital resources are generally used to fund the Company's
capital requirements, to repay maturing debt and to make preferred and common
stock dividend payments.
In 1996 and each of the preceding five years, internally generated cash
exceeded the Company's capital requirements and dividend payments, thereby
improving the Company's financial condition. Contributing to the Company's
improved financial condition were a reduction in interest expense and dividend
requirements associated with the Company's ongoing program to reduce debt and
refinance higher-cost, long-term debt and preferred stock and increased revenues
from sales to other utilities.
The Company expects that its future liquidity and capital resources will be
reduced as a result of the Competition Act. The Company is pursuing a strategy
to reduce its stranded costs and the associated capitalization roughly in
proportion to the current capitalization, which would reduce the Company's
liquidity and capital resource requirements. The Company cannot predict the
level of stranded cost recovery which will be permitted under the Competition
Act, the impact of any such recovery on the Company's capitalization or whether
internally generated cash will continue to meet or exceed the Company's capital
requirements and dividend payments.
As of December 31, 1996, the Company's capital structure consisted of 49.1%
common equity; 6.3% preferred stock and Company obligated mandatorily redeemable
preferred securities (which comprised 3.2% of the Company's total capitalization
structure); and 44.6% long-term debt.
The Company expects its level of capital investment in generation utility
plant to decrease in future years to mitigate costs in anticipation of
competition. Total construction program expenditures, primarily for utility
plant were $534 million in 1996 and are estimated to be $560 million in 1997 and
$1,225 million for the period 1998 to 2000. The Company's construction program
is subject to periodic review and revision to reflect changes in economic
conditions and other appropriate factors. Certain facilities under construction
and to be constructed may require permits and licenses which the Company has no
assurance will be granted.
The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
The Company has undertaken a number of new ventures, principally through
its Telecommunications Group, some of which require significant cash
commitments. For the period 1997 through 2000, the Company plans to invest
approximately $200-$300 million in such ventures.
Cash flows from operations were $1,172 million in 1996, substantially
consistent with the 1995 and 1994 levels. Cash flows consisted of earnings,
non-cash charges of depreciation and deferred income taxes.
Cash flows used in investing activities were $663 million as compared to
$465 million in 1995 and $589 million in 1994. While the Company's construction
program has been relatively stable, the Company has made significant investments
in diversified activities and other obligations. Net funds used in these
activities were $114 million, consisting of $58 million for telecommunications
ventures, $44 million for nuclear plant decommissioning trust funds and $12
million for other deposits and ventures. In 1995 and 1994, funds used in similar
activities were $82 million and $18 million, respectively. 1995 cash flows
benefited from the sale of COPCO.
Cash flows used in financing activities were $501 million in 1996 as
compared to $802 million in 1995 and $706 million in 1994. The decrease in 1996
is primarily due to less available cash permitting fewer retirements of higher
cost debt. In 1995 higher available cash resulting from the sale of COPCO
permitted a higher level of debt retirement than in 1994. In 1996 the debt
retirement program has resulted in a reduction of $12 million in annualized
interest.
The Company meets its short-term liquidity requirements primarily through
the issuance of commercial paper, borrowings under a revolving credit agreement
and lines of credit. The Company had $288 million of short-term debt including
$200 million of commercial paper outstanding at December 31, 1996.
At December 31, 1996, the Company's embedded cost of debt was 6.9% with
12.8% of the Company's long-term debt having floating rates. The coverage ratios
under the Company's mortgage indenture and Articles of Incorporation as of
December 31, 1996, were 4.39 and 2.50 times, respectively, compared with minimum
issuance requirements of 2.00 and 1.50 times, respectively. The Company believes
that its internal sources of funds will be sufficient to cover its fixed charges
for 1997.
Outlook
The Company's future financial condition and its future operating results
are substantially dependent upon the effects of the Competition Act and other
competitive initiatives. Additional factors that affect the Company's financial
condition and future operating results include operation of nuclear generating
facilities, sales to other utilities, accounting issues, inflation, weather and
compliance with environmental regulations.
Competition Act
The Competition Act was enacted in December 1996, providing for the
restructuring of the electric utility industry in Pennsylvania. The Competition
Act requires the unbundling of electric services into separate generation,
transmission and distribution services with open retail competition for
generation. Electric distribution and transmission services will remain
regulated by the Pennsylvania Public Utility Commission (PUC). The Competition
Act requires utilities to submit to the PUC restructuring plans, including their
stranded costs which will result from competition. Stranded costs include
regulatory assets, nuclear decommissioning costs and long-term purchased power
commitments, for which full recovery is allowed, and other costs, including
investment in generating plants, spent-fuel disposal, retirement costs and
reorganization costs, for which an opportunity for recovery is allowed in an
amount determined by the PUC as just and reasonable. These costs, after
mitigation by the utility, are to be recovered through the competitive
transition charge (CTC) approved by the PUC and collected from distribution
customers for up to nine years (or for an alternative period determined by the
PUC for good cause shown). During that period, the utility is subject to a rate
cap which provides that total charges to customers cannot exceed the rates in
place as of December 31, 1996, subject to certain exceptions.
<PAGE>
17
Full electric generation competition will be phased in, in three steps,
beginning January 1, 1999. Direct retail access is to be phased in for one-third
of each customer class by January 1, 1999, for an additional one-third by
January 1, 2000 and for all remaining customers by January 1, 2001.
The Competition Act also authorizes the PUC to approve by adopting a
Qualified Rate Order (QRO) the issuance by a utility, a finance subsidiary of a
utility or a third party assignee of a utility of Transition Bonds as a
mechanism to mitigate stranded investment and reduce customer rates. Under the
Competition Act, proceeds of Transition Bonds are required to be used
principally to reduce qualified stranded costs and the related capitalization of
the utility. The Transition Bonds are repayable from the irrevocable Intangible
Transition Charges (ITC) which are collected in lieu of CTC. The maximum
maturity of the Transition Bonds is ten years.
On January 22, 1997, the Company filed an Application with the PUC for a
QRO authorizing the issuance of $3.9 billion of Transition Bonds to fund $3.6
billion of stranded costs and $277 million of transaction and use of proceeds
costs. The Company has requested expedited review of its Application under the
Competition Act, which requires the PUC to complete its review of the
Application and issue a final determination within 120 days.
The Application, which has been filed in advance of the Company's required
restructuring filing, seeks recovery of $3.6 billion of the Company's estimated
$7.1 billion (at December 31, 1998) total stranded costs through the issuance of
the Transition Bonds covered by the Application. The Company's estimate of total
stranded costs includes $3.9 billion of generation assets, $560 million of
unfunded and as yet unrecorded decommissioning expenses and $2.6 billion of
regulatory assets. Recovery of the portion of the Company's stranded costs not
covered by the Application will be requested by the Company in its restructuring
filing, which is presently anticipated to be made on April 1, 1997. To the
extent the Company is not ultimately permitted by the PUC to recover its retail
electric stranded costs, this amount could result in a charge against earnings.
The Application sets forth the Company's proposal for the issuance of
Transition Bonds. The proposal provides for (i) the sale by the Company to an
unrelated special purpose entity (SPE) of the intangible transition property
authorized under the Competition Act, which represents the right to recover
through the ITC the $3.9 billion of stranded costs and related transaction and
use of proceeds costs, and (ii) the issuance by the SPE of the Transition Bonds.
The Company believes that such a transaction would result in the exclusion of
the ITC from the Company's revenues and off-balance sheet treatment of the
Transition Bonds; however, such accounting treatment will be subject to
Securities and Exchange Commission review.
The Company proposes using the proceeds it receives from the SPE, resulting
from the issuance of the Transition Bonds, to pay estimated transaction and use
of proceeds costs of $277 million, to settle deferred fuel balances of $240
million and to reduce capitalization by approximately $3.4 billion. The
capitalization reduction is expected to be proportionate to the Company's
current capitalization. Specific securities to be retired and the manner in
which they are to be retired have not been determined and will depend on market
conditions at the time of issuance of Transition Bonds.
Adoption by the PUC of the requested QRO and issuance of $3.9 billion of
Transition Bonds at current interest rates would result in an estimated 2.9%
reduction in the Company's retail electric rates. The Company estimates that the
consummation of the transaction as proposed in the Application would reduce the
Company's annual revenues by approximately $650 million and the Company's annual
operating expenses by $501 million, resulting in an estimated reduction in
annual net income of $149 million. The reduction in revenue results from the
elimination of the revenue requirements of stranded costs, and the reduction in
operating expenses results from decreases in depreciation, interest expense and
associated income taxes. The impact on the Company's earnings per share will
depend on the price at which shares of the Company's Common Stock are purchased.
If Common Stock is purchased at a price above book value ($20.88 at December 31,
1996), earnings per share will be reduced.
Under the Competition Act, the Company expects that its rates for
transmission and distribution services will be capped at their current levels
for 4.5 years and the generation portion of rates for up to nine years. In
recognition of the capping of rates at current levels, at December 31, 1996, the
PUC approved the Company's request to roll-in and eliminate the ECA. The Company
cannot predict whether the PUC will issue the requested QRO, the level of
stranded cost recovery authorized by any QRO or the amount of Transition Bonds,
if any, ultimately issued pursuant to any QRO. The Company believes that once
the issues surrounding the recovery of its stranded costs are resolved, it will
be able to compete effectively in the generation market primarily because of its
marketing efforts and its low generation costs.
Other Competitive Initiatives
During 1996, the Federal Energy Regulatory Commission (FERC) issued Order
No. 888 which requires public utilities to file open-access transmission tariffs
for wholesale transmission services in accordance with non-discriminatory terms
and conditions established by the FERC. The FERC's new rules provide for the
recovery of legitimate and verifiable wholesale stranded costs. The Company does
not have any stranded costs related to this portion of its business.
In response to Order No. 888, the Company and the other members of the
Pennsylvania-New Jersey-Maryland Interconnection Association (PJM) submitted to
the FERC separate filings proposing to restructure PJM. The Company proposed
five major initiatives to reduce the costs of electricity while preserving the
reliability and universal service that is essential to Pennsylvania citizens. In
November 1996, the FERC issued an order rejecting both of the PJM restructuring
filings. The FERC identified two issues that remain to be resolved: independence
of the independent system operator; and open access transmission pricing tariffs
that are nondiscriminatory. The FERC directed the parties to refile their
proposals, preferably as one proposal, resolving these issues by December 31,
1996, with tariffs to be effective March 1, 1997. On December 31, 1996, the PJM
member companies, including the Company, filed a joint compliance filing with
the FERC. The filing was not a complete consensus but included competing
proposals in certain areas such as transmission rate structure and transmission
constraint/congestion control. The PJM member companies requested the FERC to
choose between the options for implementation during the interim period. The
FERC is expected to rule on this filing in the first quarter of 1997.
<PAGE>
18
The Company received approval for its transmission service tariff covering
network and point-to-point services and a market-based rate energy sales tariff
that allows the Company to sell wholesale energy at market-based rates outside
the PJM control area. During the latter part of 1996, the Company also requested
approval from the FERC to remove the existing cost-based cap on prices charged
for power purchased by the Company in anticipation of later resale in the
wholesale market and certain changes regarding the terms of the buy-for-resale
agreements. The transactions covered under the original market-based rate tariff
were rolled into the more recent request. Approval of the new tariff provisions
will allow the Company to purchase and re-sell energy at market-based rates both
within PJM and outside PJM.
The gas industry is continuing to undergo structural changes in response to
FERC policies designed to increase competition. 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 changes, the Company has modified its gas purchasing arrangements to
enable the purchase of gas and transportation at lower cost. During 1996 the
Company, through a wholly owned subsidiary, successfully participated in a pilot
program outside the Company's gas service territory to market natural gas and
other services.
As a result of competitive pressures, the Company has continued to
negotiate long-term contracts with many of its larger-volume industrial
customers. Although these agreements have resulted in reduced margins, they have
permitted the Company to retain these customers. During 1996, energy sales under
long-term contracts were 8% of total electric sales.
Regulation and Operation of Nuclear Generating Facilities
The Company's financial condition and results of operations are in part
dependent on the continued successful operation of its nuclear generating
facilities. The Company's nuclear generating facilities represent approximately
45% of its installed generating capacity. Because of the Company's substantial
investment in, and reliance on, its nuclear generating units, any changes in
regulations by the Nuclear Regulatory Commission (NRC) requiring additional
investments or resulting in increased operating costs of nuclear generating
units could adversely affect the Company.
Public Service Electric and Gas Company (PSE&G), the operator of Salem
Units No. 1 and No. 2, which are 42.59% owned by the Company, removed the units
from service in the second quarter of 1995. PSE&G informed the NRC at that time
that it had determined to keep the Salem units shut down pending review and
resolution of certain equipment and management issues and NRC agreement that
each unit is sufficiently prepared to restart. PSE&G reported that Unit No. 2 is
expected to return to service in the second quarter of 1997 and Unit No. 1 is
expected to return to service in the summer of 1997. It is the Company's belief
that the earliest that Unit No. 1 will return to service is late in the third
quarter of 1997. The Company expects to incur and expense at least $95 million
in 1997 for increased costs related to the shutdown. As of December 31, 1996 and
1995, the Company had incurred and expensed $149 million and $50 million,
respectively, for replacement power and maintenance costs related to the
shutdown of Salem. See note 4 of Notes to Consolidated Financial Statements.
During 1996, Company-operated nuclear plants operated at an 89% weighted-average
capacity factor and Company-owned nuclear plants operated at a 68%
weighted-average capacity factor. The Company-owned nuclear plants produced 43%
of the Company's output, including purchased power, despite the shutdown of both
Salem units during 1996. Nuclear generation is the most cost-effective way for
the Company to meet customer needs and commitments for sales to other utilities.
Sales to Other Utilities
In the ordinary course of business, the Company enters into commitments to
buy and sell power. As of December 31, 1996, the Company entered into long-term
agreements to purchase from unaffiliated utilities, primarily in 1997, energy
associated with 2,200 megawatts (MW) of capacity. These purchases will be
utilized through a combination of sales to jurisdictional customers, long-term
sales to other utilities and open market sales. The Company's future results of
operations are dependent in part on its ability to successfully market the rest
of this generation. See note 4 of Notes to Consolidated Financial Statements.
In the wholesale market, the Company has increased its sales to other
utilities, but increased competition has reduced the Company's margin on these
sales. As of December 31, 1996, the Company has entered into long-term
agreements with unaffiliated utilities to sell energy associated with 1,460 MW
of capacity, of which 725 MW of these agreements are for 1997 and the remainder
run through 2022.
Accounting Issues
The Company accounts for all of its regulated operations in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effect of Certain Types of Regulation" which requires the Company to record the
financial statement effects of the rate regulation to which the Company is
currently subject. Use of SFAS No. 71 is applicable to the utility operation of
the Company which meet the following criteria: 1) third-party regulation of
rates; 2) cost-based rates; and 3) a reasonable assumption that all costs will
be recoverable from customers through rates.
By January 1, 1999, the date when market competition is introduced for
retail generation under the Competition Act, the Company expects it will no
longer meet the criteria of SFAS No. 71 for this separable portion of its
operations. When the Company determines that the criteria required by SFAS No.
71 are no longer satisfied, the Company will adopt the provisions of SFAS No.
101, "Regulated Enterprises Accounting for the Discontinuance of Application of
FASB Statement No. 71." SFAS No. 101 requires the elimination of all effects of
any actions of regulators that have been recognized as assets and liabilities
pursuant to SFAS No. 71 and a determination of impairment of plant assets under
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of."
In its January 22, 1997 Application, the Company estimated total stranded
costs of $7.1 billion, including $2.6 billion of regulatory assets, and $3.9
billion of plant assets.
Given the stranded cost recovery provisions of the Competition Act, the
Company believes that it will be given the opportunity for full recovery of its
regulatory assets. In addition, as of December 31, 1996 there is no impairment
of plant costs under SFAS No. 121.
For 1996, the Company believes that its wholesale operations continue to
meet the criteria for the continued application
<PAGE>
19
of SFAS No. 71. Due to the market-based pricing of generation provisions of the
PJM restructuring proposal, it is anticipated that, upon acceptance of the
proposal by the FERC, the Company's wholesale energy sales operations would no
longer be subject to the provisions of SFAS No. 71. The Company does not believe
that the discontinuance of SFAS No. 71 for its wholesale energy sales operations
would result in a charge against income. Based on projections of the Company's
retail load growth, the Company believes all of the owned generation capacity
will be necessary to meet its retail load.
In 1996, the Financial Accounting Standards Board (FASB) issued SFAS No.
125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," which is currently effective for transfers and
servicing of financial assets and extinguishment of liabilities occurring after
December 31, 1996. Adoption of SFAS No. 125 is not expected to have a material
effect on the Company's financial condition or results of operation.
During 1996, the FASB issued the Exposure Draft "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets." The FASB has
recently taken under consideration the expansion of the scope of the project to
include closure or removal liabilities that are incurred at any time in the
operating life of the related long-lived asset. The Exposure Draft originally
included only liabilities incurred in the acquisition, construction, development
or early operation of a long-lived asset. The FASB plans to issue either a final
Statement or a revised Exposure Draft in the second quarter of 1997. Until such
time that the final Statement is issued or a revised Exposure Draft is issued,
the Company is unable to determine what, if any, effect the final Statement
might have on its financial condition or results of operations. See note 4 of
Notes to Consolidated Financial Statements.
Other Factors
Annual and quarterly operating results can be significantly affected by
weather. Since the Company's peak demand is in the summer months, temperature
variations in summer months are generally more significant than during winter
months.
Inflation affects the Company through increased operating costs and
increased capital costs for utility plant. As a result of the rate cap imposed
by the Competition Act and the elimination of the ECA, the Company may have
limited opportunity to pass the costs of inflation through to customers.
The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under federal and state environmental laws, the Company is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by the Company and of property contaminated by
hazardous substances generated by the Company. The Company owns or leases a
number of real estate parcels, including parcels on which its operations or the
operations of others may have resulted in contamination by substances which are
considered hazardous under environmental laws. The Company is currently involved
in a number of proceedings relating to sites where hazardous substances have
been deposited and may be subject to additional proceedings in the future.
The Company has identified 27 sites where former manufactured gas plant
(MGP) activities have or may have resulted in 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. Eight of the sites are currently under some degree of active study
or remediation.
As of December 31, 1996 and 1995, the Company had accrued $28 and $27
million, respectively, for environmental investigation and remediation costs,
including $16 and $13 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. The Company expects to
expend $7 million for such activities in 1997. The Company cannot currently
predict whether it will incur other significant liabilities for any additional
investigation and remediation costs at these or additional sites identified by
the Company, environmental agencies or others, or whether all such costs will be
recoverable from third parties.
Forward-Looking Statements
Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements which are
subject to risks and uncertainties. The factors that could cause actual results
to differ materially include those discussed herein as well as those listed in
notes 3 and 4 of Notes to Consolidated Financial Statements and other factors
discussed in the Company's filings with the Securities and Exchange Commission.
Readers are cautioned not to place undue reliance on these forward-looking
statements, which speak only as of the date of this Report. The Company
undertakes no obligation to publicly release any revision to these
forward-looking statements to reflect events or circumstances after the date of
this Report.
For a discussion of other contingencies, see notes 3 and 4 of Notes to
Consolidated Financial Statements.
<PAGE>
20
Report of Independent Accountants
To the Shareholders and Board of Directors
PECO Energy Company:
We have audited the accompanying consolidated balance sheets of PECO Energy
Company and Subsidiary Companies as of December 31, 1996 and 1995, and the
related consolidated statements of income, cash flows, and changes in common
shareholders' equity and preferred stock for each of the three years in the
period ended December 31, 1996. These financial statements are the
responsibility of the Companies' management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of PECO Energy
Company and Subsidiary Companies as of December 31, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.
/s/ Coopers & Lybrand LLP
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1997
<PAGE>
21
Consolidated Statements of Income
<TABLE>
<CAPTION>
For the Years Ended December 31, 1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Operating Revenues
Electric $ 3,854,836 $ 3,775,326 $ 3,624,797
Gas 428,814 410,830 415,835
----------- ----------- -----------
Total Operating Revenues 4,283,650 4,186,156 4,040,632
----------- ----------- -----------
Operating Expenses
Fuel and Energy Interchange 972,380 762,762 703,590
Other Operating 949,495 943,476 937,849
Early Retirement and Separation Programs -- -- 254,106
Maintenance 324,727 307,797 327,714
Depreciation 489,001 457,254 442,101
Income Taxes 343,105 396,897 234,033
Other Taxes 299,546 314,071 311,689
----------- ----------- -----------
Total Operating Expenses 3,378,254 3,182,257 3,211,082
----------- ----------- -----------
Operating Income 905,396 1,003,899 829,550
----------- ----------- -----------
Other Income and Deductions
Allowance for Other Funds Used During Construction 10,222 14,371 10,180
Gain on Sale of Subsidiary -- 58,745 --
Income Taxes 3,004 (34,820) (15,291)
Other, net (1,976) (444) 23,121
----------- ----------- -----------
Total Other Income and Deductions 11,250 37,852 18,010
----------- ----------- -----------
Income Before Interest Charges 916,646 1,041,751 847,560
Interest Charges
Long-Term Debt 328,557 386,205 387,279
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership, which
holds Solely Subordinated Debentures of the
Company 26,723 20,987 8,570
Short-Term Debt 53,886 37,506 36,987
----------- ----------- -----------
Total Interest Charges 409,166 444,698 432,836
Allowance for Borrowed Funds Used During
Construction (9,725) (12,679) (11,989)
----------- ----------- -----------
Net Interest Charges 399,441 432,019 420,847
----------- ----------- -----------
Net Income 517,205 609,732 426,713
Preferred Stock Dividends 18,036 23,217 37,298
----------- ----------- -----------
Earnings Applicable to Common Stock $ 499,169 $ 586,515 $ 389,415
=========== =========== ===========
Average Shares of Common Stock
Outstanding (Thousands) 222,490 221,859 221,554
=========== =========== ===========
Earnings per Average Common Share (Dollars) $ 2.24 $ 2.64 $ 1.76
=========== =========== ===========
Dividends per Common Share (Dollars) $ 1.755 $ 1.65 $ 1.545
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
22
Consolidated Balance Sheets
<TABLE>
<CAPTION>
At December 31, 1996 1995
Thousands of Dollars
<S> <C> <C>
Assets
Utility Plant, at Original Cost
Electric $ 13,622,380 $ 13,441,880
Gas 1,005,507 954,180
Common 317,065 299,899
------------ ------------
14,944,952 14,695,959
Less Accumulated Provision for Depreciation 5,046,950 4,623,707
------------ ------------
9,898,002 10,072,252
Nuclear Fuel, net 199,579 191,084
Construction Work in Progress 661,871 494,194
Leased Property, net 182,088 180,425
------------ ------------
Net Utility Plant 10,941,540 10,937,955
------------ ------------
Current Assets
Cash and Temporary Cash Investments 29,235 20,602
Accounts Receivable, net
Customers 19,159 75,220
Other 74,377 71,997
Inventories, at average cost
Fossil Fuel 84,633 78,260
Materials and Supplies 119,743 123,387
Deferred Energy Costs-Gas 30,013 (3,722)
Other 63,234 60,868
------------ ------------
Total Current Assets 420,394 426,612
------------ ------------
Deferred Debits and Other Assets
Recoverable Deferred Income Taxes 2,325,721 2,425,311
Deferred Limerick Costs 361,762 390,433
Deferred Non-Pension Postretirement Benefits Costs 233,492 248,085
Deferred Energy Costs-Electric 92,021 59,605
Investments 432,574 318,448
Loss on Reacquired Debt 283,853 308,577
Other 169,262 193,479
------------ ------------
Total Deferred Debits and Other Assets 3,898,685 3,943,938
------------ ------------
Total Assets $ 15,260,619 $ 15,308,505
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
23
Consolidated Balance Sheets (Continued)
<TABLE>
<CAPTION>
At December 31, 1996 1995
Thousands of Dollars
<S> <C> <C>
Capitalization and Liabilities
Capitalization
Common Shareholders' Equity
Common Stock $ 3,517,614 $ 3,506,313
Other Paid-In Capital 1,326 1,326
Retained Earnings 1,127,041 1,023,708
----------- -----------
4,645,981 4,531,347
Preferred and Preference Stock
Without Mandatory Redemption 199,367 199,367
With Mandatory Redemption 92,700 92,700
Company Obligated Mandatorily Redeemable Preferred
Securities of a Partnership, which holds Solely
Subordinated Debentures of the Company 302,182 302,282
Long-Term Debt 3,935,514 4,198,283
----------- -----------
Total Capitalization 9,175,744 9,323,979
----------- -----------
Current Liabilities
Notes Payable, Bank 287,500 --
Long-Term Debt Due Within One Year 283,303 401,003
Capital Lease Obligations Due Within One Year 49,347 60,320
Accounts Payable 212,966 299,731
Taxes Accrued 71,482 107,621
Interest Accrued 82,006 88,047
Dividends Payable 22,407 20,722
Other 94,353 74,847
----------- -----------
Total Current Liabilities 1,103,364 1,052,291
----------- -----------
Deferred Credits and Other Liabilities
Capital Lease Obligations 132,741 120,105
Deferred Income Taxes 3,745,242 3,685,534
Unamortized Investment Tax Credits 336,132 351,569
Pension Obligation 224,454 216,283
Non-Pension Postretirement Benefits Obligation 315,058 326,251
Other 227,884 232,493
----------- -----------
Total Deferred Credits and Other Liabilities 4,981,511 4,932,235
----------- -----------
Commitments and Contingencies (Notes 3 and 4)
Total Capitalization and Liabilities $15,260,619 $15,308,505
=========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
24
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
For the Years Ended December 31, 1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net Income $ 517,205 $ 609,732 $ 426,713
Adjustments to reconcile Net Income to Net Cash
provided by Operating Activities:
Depreciation and Amortization 566,412 531,299 517,681
Deferred Income Taxes 166,771 183,514 (23,306)
Gain on Sale of Subsidiary -- (58,745) --
Early Retirement and Separation Programs -- -- 254,106
Deferred Energy Costs (66,151) (71,104) (33,205)
Amortization of Leased Property 31,400 42,900 61,900
Changes in Working Capital:
Accounts Receivable 53,681 (8,198) 23,508
Inventories (2,729) (10,872) 18,210
Accounts Payable (86,765) (4,686) 5,342
Other Current Assets and Liabilities (25,040) 9,641 52,940
Other Items affecting Operations 17,461 16,855 (9,175)
----------- ----------- -----------
Net Cash Flows from Operating Activities 1,172,245 1,240,336 1,294,714
----------- ----------- -----------
Cash Flows from Investing Activities
Investment in Plant (548,854) (532,614) (570,903)
Proceeds from Sale of Subsidiary -- 150,000 --
Increase in Other Investments (114,126) (82,041) (17,951)
----------- ----------- -----------
Net Cash Flows from Investing Activities (662,980) (464,655) (588,854)
----------- ----------- -----------
Cash Flows from Financing Activities
Change in Short-Term Debt 287,500 (11,499) (107,851)
Issuance of Common Stock 11,301 15,585 2,308
Retirement of Preferred Stock -- (78,105) (238,800)
Issuance of Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership -- 81,032 221,250
Issuance of Long-Term Debt 43,700 182,540 245,100
Retirement of Long-Term Debt (427,463) (575,713) (397,763)
Loss on Reacquired Debt 24,724 12,302 22,125
Dividends on Preferred and Common Stock (411,569) (390,340) (377,883)
Change in Dividends Payable 1,685 5,626 (3,249)
Expenses of Issuing Long-Term Debt and Capital Stock 890 (577) (9,150)
Capital Lease Payments (31,400) (42,900) (61,900)
----------- ----------- -----------
Net Cash Flows from Financing Activities (500,632) (802,049) (705,813)
----------- ----------- -----------
Increase/(Decrease) in Cash and Cash Equivalents 8,633 (26,368) 47
Cash and Cash Equivalents at beginning of period 20,602 46,970 46,923
----------- ----------- -----------
Cash and Cash Equivalents at end of period $ 29,235 $ 20,602 $ 46,970
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
25
Consolidated Statements of Changes in Common Shareholders' Equity
and Preferred Stock
<TABLE>
<CAPTION>
Other
Common Stock Paid-In Retained Preferred Stock
All Amounts in Thousands Shares Amount Capital Earnings Shares Amount
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1994 221,517 $ 3,488,477 $ 1,214 $ 773,727 6,090 $ 608,972
Net Income 426,713
Cash Dividends Declared
Preferred Stock
(at specified annual rates) (35,706)
Common Stock ($1.545 per share) (342,177)
Expenses of Capital Stock Activity (11,662)
Capital Stock Activity
Long-Term Incentive Plan Issuances 92 2,251 (388)
Preferred Stock Issuances 57
Preferred Stock Redemptions (2,388) (238,800)
------- ----------- ----------- ----------- ----- -----------
Balance at December 31, 1994 221,609 3,490,728 1,271 810,507 3,702 370,172
Net Income 609,732
Cash Dividends Declared
Preferred Stock
(at specified annual rates) (24,253)
Common Stock ($1.65 per share) (366,087)
Expenses of Capital Stock Activity (4,035)
Capital Stock Activity
Long-Term Incentive Plan Issuances 563 15,585 (2,156)
Preferred Stock Issuances 55
Preferred Stock Redemptions (781) (78,105)
------- ----------- ----------- ----------- ----- -----------
Balance at December 31, 1995 222,172 3,506,313 1,326 1,023,708 2,921 292,067
Net Income 517,205
Cash Dividends Declared
Preferred Stock
(at specified annual rates) (21,042)
Common Stock ($1.755 per share) (390,527)
Expenses of Capital Stock Activity (275)
Capital Stock Activity
Long-Term Incentive Plan Issuances 370 11,301 (2,028)
------- ----------- ----------- ----------- ----- -----------
Balance at December 31, 1996 222,542 $ 3,517,614 $ 1,326 $ 1,127,041 2,921 $ 292,067
======= =========== =========== =========== ===== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
26
Notes to Consolidated Financial Statements
1. Significant Accounting Policies
General
The consolidated financial statements of PECO Energy Company (Company) include
the accounts of its utility subsidiary companies, all of which are wholly owned.
Accounting policies are in accordance with those prescribed by the regulatory
authorities having jurisdiction, principally the Pennsylvania Public Utility
Commission (PUC) and the Federal Energy Regulatory Commission (FERC). The
Company has unconsolidated non-utility subsidiaries which are not material. The
unconsolidated subsidiaries are accounted for under the equity method.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Estimates are used in the Company's accounting for unbilled revenue, the
allowance for uncollectible accounts, fuel adjustment clauses, depreciation and
amortization, taxes, reserves for contingencies, employee benefits, certain fair
value and recoverability determinations, and nuclear outage costs, among others.
Accounting for the Effects of Regulation
The Company follows the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," requiring the Company to record the financial statement effects of
the rate regulation to which the Company is currently subject. If a separable
portion of the Company's business no longer meets the provisions of SFAS No. 71,
the Company would be required to eliminate the financial statement effects of
regulation for that portion (see note 3).
Revenues
Electric and gas revenues are recorded as service is rendered or energy is
delivered to customers. At the end of each month, the Company accrues an
estimate for the unbilled amount of energy delivered or services provided to
customers (see note 7).
Fuel and Energy Cost Adjustment Clauses
The Company's classes of service historically have been subject to fuel
adjustment clauses designed to recover or refund the differences between the
actual cost of fuel, energy interchange, purchased power and gas, and the
amounts of such costs included in base rates. Differences between the amounts
billed to customers and the actual costs recoverable were deferred and recovered
or refunded in future periods by means of prospective adjustments to rates.
Generally, such rates were adjusted every twelve months.
In response to a Company proposal requesting the elimination of the Energy
Cost Adjustment (ECA), the PUC approved the roll-in of energy costs into the
base rates charged to the Company's electric customers. Effective December 31,
1996, the Company's classes of electric service are no longer subject to the
ECA.
The Company's PUC-established Purchased Gas Cost Adjustment (PGC) which
allows for the recovery of the difference between actual purchased gas costs and
the amounts of such costs included in the base rates charged to the Company's
natural gas customers will continue to be in effect subsequent to January 1,
1997.
Nuclear Fuel
The cost of nuclear fuel is capitalized and charged to fuel expense on the unit
of production method. Estimated costs of nuclear fuel disposal are charged to
fuel expense as the related fuel is consumed. The Company's share of nuclear
fuel at Peach Bottom Atomic Power Station (Peach Bottom) and Salem Generating
Station (Salem) is accounted for as a capital lease. Nuclear fuel at Limerick
Generating Station (Limerick) is owned.
Depreciation and Decommissioning
The annual provision for depreciation is provided over the estimated service
lives of plant on the straight-line method. Annual depreciation provisions for
financial reporting purposes, expressed as a percentage of average depreciable
utility plant in service, were approximately 2.90% in 1996, 2.80% in 1995 and
2.77% in 1994. See note 3 for information concerning the change in 1996 to
depreciation and amortization.
The Company's share of the 1990 estimated costs for decommissioning nuclear
generating stations currently included in electric base rates is being charged
to operations over the expected service life of the related plant. The amounts
recovered from customers are deposited in trust accounts and invested for
funding of future costs. These amounts, and realized investment earnings
thereon, are credited to accumulated depreciation (see note 4).
Income Taxes
The Company uses an asset and liability approach for financial accounting and
reporting of income taxes. The effects of the Alternative Minimum Tax (AMT) are
normalized. Investment tax credits are deferred and amortized to income over the
estimated useful life of the related utility plant (see note 13).
Allowance for Funds Used During Construction (AFUDC)
AFUDC is the cost, during the period of construction, of debt and equity funds
used to finance construction projects. AFUDC is recorded as a charge to
Construction Work in Progress, and the credits are to Interest Charges for the
cost of borrowed funds and to Other Income and Deductions for the remainder as
the allowance for other funds. The rates used for capitalizing AFUDC, which
averaged 9.38% in 1996, 9.88% in 1995 and 7.74% in 1994, are computed under a
method prescribed by regulatory authorities. AFUDC is not included in regular
<PAGE>
27
taxable income and the depreciation of capitalized AFUDC is not tax deductible.
Nuclear Outage Costs
Incremental nuclear maintenance and refueling outage costs are accrued over the
unit operating cycle. For each unit, an accrual for incremental nuclear
maintenance and refueling outage expense is estimated based upon the latest
planned outage schedule and estimated costs for the outage. Differences between
the accrued and actual expense for the outage are recorded when such differences
are known.
Capitalized Software Costs
Software projects which exceed $5 million are capitalized. At December 31, 1996
and 1995, capitalized software costs totaled $78 million and $65 million (net of
$29 million and $19 million accumulated amortization), respectively. Such
capitalized amounts are amortized ratably over the expected lives of the
projects when they become operational, not to exceed ten years.
Gains and Losses on Reacquired Debt
Gains and losses on reacquired debt are deferred and amortized to interest
expense over the period approved for rate-making purposes.
Impairment of Long-Lived Assets
Effective January 1, 1996, under SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," long-lived
assets are subject to periodic analysis for impairment. No loss from impairment
has been recorded in 1996.
Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income or common shareholders'
equity.
2. Nature of Operations and Segment Information
The Company 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 to an area of 1,972
square miles with a population of 3.6 million, including 1.6 million in the City
of Philadelphia. Approximately 94% of the retail electric service area and 64%
of retail kilowatthour sales are in the suburbs around Philadelphia, and 6% of
the retail service area and 36% of such sales are in the City of Philadelphia.
Natural gas service is supplied to a 1,475-square-mile area of southeastern
Pennsylvania adjacent to Philadelphia with a population of 1.9 million.
<TABLE>
<CAPTION>
For the Years Ended December 31, 1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Electric Operations
Operating revenues:
Residential $ 1,370,158 $ 1,379,046 $ 1,371,237
Small commercial and industrial 748,561 730,220 710,028
Large commercial and industrial 1,098,307 1,135,550 1,149,193
Other 140,133 136,988 136,002
(Decrease)/increase in unbilled (25,950) 42,580 (11,130)
----------- ----------- -----------
Service territory 3,331,209 3,424,384 3,355,330
Interchange sales 25,991 17,488 23,017
Sales to other utilities 497,636 333,454 246,450
----------- ----------- -----------
Total operating revenues 3,854,836 3,775,326 3,624,797
----------- ----------- -----------
Operating expenses, excluding depreciation 2,560,669 2,405,876 2,429,452
Depreciation 462,315 430,993 415,854
----------- ----------- -----------
Operating income $ 831,852 $ 938,457 $ 779,491
=========== =========== ===========
Utility plant additions $ 447,105 $ 435,400 $ 457,728
=========== =========== ===========
</TABLE>
<PAGE>
28
<TABLE>
<CAPTION>
For the Years Ended December 31, 1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Gas Operations
Operating revenues:
Residential $ 15,716 $ 15,482 $ 16,048
House heating 249,507 235,456 237,397
Commercial and industrial 132,822 125,631 128,077
Other 11,462 5,382 20,168
(Decrease)/increase in unbilled (4,250) 6,540 (3,140)
------------ ------------ ------------
Subtotal 405,257 388,491 398,550
------------ ------------ ------------
Other revenues (including transported for customers) 23,557 22,339 17,285
------------ ------------ ------------
Total operating revenues 428,814 410,830 415,835
------------ ------------ ------------
Operating expenses, excluding depreciation 328,585 319,127 339,529
Depreciation 26,686 26,261 26,247
------------ ------------ ------------
Operating income $ 73,543 $ 65,442 $ 50,059
============ ============ ============
Utility plant additions $ 68,394 $ 63,192 $ 67,090
============ ============ ============
Identifiable Assets* at December 31,
Electric $ 10,287,444 $ 10,408,105 $ 10,410,461
Gas 858,471 785,881 768,279
Nonallocable assets 4,114,704 4,114,519 4,243,410
------------ ------------ ------------
Total assets $ 15,260,619 $ 15,308,505 $ 15,422,150
============ ============ ============
<FN>
* Includes utility plant less accumulated depreciation, inventories and
allocated common utility property.
</FN>
</TABLE>
3. Rate Matters
Competition Act
The recently enacted electricity generation customer choice and competition Act
(Competition Act) provides for the restructuring of the electric industry in
Pennsylvania, including retail competition for generation beginning in 1999. At
that date, the Company expects it will no longer meet the criteria of SFAS No.
71 for the retail generation portion of its operations. The Competition Act
requires the unbundling of electric services into separate generation,
transmission and distribution services with open retail competition for
generation. Electric distribution and transmission services will remain
regulated by the PUC. The Competition Act requires utilities to submit to the
PUC restructuring plans, including their stranded costs which will result from
competition. Stranded costs include regulatory assets (see note 22), nuclear
decommissioning costs and long-term purchased power commitments, for which full
recovery is allowed, and other costs including investment in generating plants,
spent fuel disposal, retirement costs and reorganization costs, for which an
opportunity for recovery is allowed in an amount determined by the PUC as just
and reasonable. These costs, after mitigation by the utility, are to be
recovered and collected from distribution customers for up to nine years (or for
an alternative period determined by the PUC for good cause shown). During that
period, the utility is subject to a rate cap providing that total charges to
customers cannot exceed rates in place as of December 31, 1996, subject to
certain exceptions.
The Company estimates that its stranded costs resulting from retail
generation competition at December 31, 1998 will be $7.1 billion. This estimate
includes $3.9 billion of generating assets, $560 million of unfunded and as yet
unrecorded decommissioning expenses and $2.6 billion of regulatory assets. On
January 22, 1997, the Company filed an Application with the PUC seeking to
recover $3.6 billion of its stranded costs and to securitize that recovery
through the issuance by a third party assignee of $3.9 billion of Transition
Bonds. The Company intends to seek recovery of the remaining $3.5 billion of its
stranded costs in the Company's restructuring filing mandated by the Competition
Act. To the extent the Company is not ultimately permitted by the PUC to recover
its retail electric stranded costs, this amount could result in a charge against
earnings. However, as of December 31, 1996, there is no impairment of its
generation assets under SFAS No. 121, and given the stranded cost recovery
provisions of the Competition Act, the Company believes that it will be given
the opportunity for full recovery of its regulatory assets.
Under the Competition Act, the Company is required to use the proceeds it
receives from any securitization of the recovery of stranded assets principally
to reduce qualified stranded costs and related capitalization. In the
Application, the Company proposes using the proceeds it receives resulting from
the issuance of the Transition Bonds to pay estimated transaction and use of
proceeds costs of $277 million, to settle deferred fuel balances of $240 million
and to reduce capitalization by approximately $3.4 billion. The capitalization
reduction is expected to be proportionate to the Company's current
capitalization.
Limerick
Under its electric tariffs, the Company is recovering $285 million of deferred
Limerick costs representing carrying charges and depreciation associated with
50% of Limerick common facilities. These costs are included in base rates and
are being recovered over a nine year period beginning October 1, 1996. The
Company is also recovering $137 million of Limerick Unit No. 1 costs over a
ten-year period without a return on investment. At December 31, 1996, the
unrecovered portion of these balances
<PAGE>
29
were $228 and $46 million, respectively.
Under its electric tariffs and ECA, the Company was allowed to retain for
shareholders any proceeds above the average energy cost for sales of 399
megawatts (MW) of near-term excess 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 1996, 1995 and 1994, the Company recorded as revenue net of fuel costs
$82, $79 and $68 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.
Pursuant to a PUC Declaratory Order issued in 1990, the Company deferred
certain operating and maintenance expenses, depreciation and accrued carrying
charges on its capital investment in Limerick Unit No. 2 and 50% of Limerick
common facilities. At December 31, 1996 and 1995, such costs included in
Deferred Limerick Costs totaled $88 and $91 million, respectively. These costs
are included in base rates and are being recovered over a nine year period
beginning October 1, 1996.
Declaratory Accounting Order
Pursuant to a PUC Declaratory Order, effective October 1, 1996, the Company
increased depreciation and amortization on assets associated with Limerick by
$100 million per year and decreased depreciation and amortization on other
Company assets by $10 million per year, for a net increase in depreciation and
amortization of $90 million per year.
Recovery of Non-Pension Postretirement Benefits Costs
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 SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions,"
(see note 6). 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. During
1996 and 1995, the Company deposited $46.5 and $59.6 million, respectively, in
trust accounts to fund its retail electric non-pension postretirement benefits
costs. These costs include amounts charged to operating expense or capitalized
on and after January 1, 1995.
In accordance with a December 1994 PUC approved accounting order, the
Company is recognizing $2.8 million in non-pension postretirement benefits costs
annually associated with gas utility operations. During 1996 and 1995, the
Company deposited $2.9 and $3.8 million, respectively, in trust accounts to fund
its gas non-pension postretirement benefits costs.
Energy Cost Adjustment
Through December 31, 1996, the Company was subject to a PUC-established electric
ECA which, in addition to reconciling fuel costs and revenues, incorporated a
nuclear performance standard which allowed for financial bonuses or penalties
depending on whether the Company's system nuclear capacity factor exceeded or
fell below a specified range. For the years ended December 31, 1996, 1995 and
1994, the Company recorded bonuses of $22, $13 and $14 million, respectively.
4. Commitments and Contingencies
Capital Commitments
Total construction program expenditures primarily for utility plant are
estimated to be $560 million for 1997 and $1,225 million for the period 1998 to
2000. Construction expenditure estimates are reviewed and revised periodically
to reflect changes in economic conditions and other appropriate factors. Certain
facilities under construction and to be constructed may require permits and
licenses which the Company has no assurance will be granted. Additionally, for
the period 1997 through 2000, the Company plans to invest approximately
$200-$300 million in other new ventures which includes telecommunications
activities.
The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Nuclear Insurance
The Price-Anderson Act currently limits the liability of nuclear reactor owners
to $8.9 billion for claims that could arise from a single incident. The limit is
subject to change to account for the effects of inflation and changes in the
number of licensed reactors. The Company carries the maximum available
commercial insurance of $200 million and the remaining $8.7 billion is provided
through 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. In addition, Congress could impose revenue raising measures on
the nuclear industry to pay claims.
The Company carries property damage, decontamination and premature
decommissioning insurance in the amount of its $2.75 billion proportionate share
for each station loss resulting from damage to its nuclear plants. In the event
of an accident, insurance proceeds must first be used for reactor stabilization
and site decontamination. 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 Nuclear Regulatory Commission (NRC) to maintain to
provide for decommissioning the facility. The Company is unable to predict 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 $31 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 and 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 premium for this coverage is subject to
assessment for adverse loss experience. The Company's maximum share of any
assessment is $13 million per year.
Nuclear Decommissioning and Spent Fuel Storage
The Company's 1990 estimate of its nuclear facilities' decommissioning cost of
$643 million is being collected through electric base rates over the life of
each generating unit. Under
<PAGE>
30
current rates, the Company collects and expenses approximately $20 million
annually from customers. The expense is accounted for as a component of
depreciation expense and accumulated depreciation. At December 31, 1996 and
1995, $256 and $216 million, respectively, was included in accumulated
depreciation. In order to fund future decommissioning costs, at December 31,
1996 and 1995, the Company held $266 and $223 million, respectively, in trust
accounts which are included as an Investment in the Company's Consolidated
Balance Sheet and include both net unrealized and realized gains. Net unrealized
gains of $26 and $19 million were recognized as a Deferred Credit in the
Company's Consolidated Balance Sheet at December 31, 1996 and 1995,
respectively. The Company recognized net realized gains of $10, $9 and $7
million as Other Income in the Company's Consolidated Statement of Income for
the years ended December 31, 1996, 1995 and 1994 respectively. The most recent
estimate of the Company's share of the cost to decommission its nuclear units is
$1.4 billion in 1995 dollars. The Company has included the unfunded and as yet
unrecorded portion of the decommissioning trust fund estimate in its January 22,
1997 application with the PUC.
In an exposure draft issued in 1996, the Financial Accounting Standards
Board (FASB) proposed changes in the accounting for closure and removal costs of
production facilities, including the recognition, measurement and classification
of decommissioning costs for nuclear generating stations. The FASB is currently
considering expanding the scope of the Exposure Draft to include closure or
removal liabilities that are incurred at any time in the operating life of the
long-lived asset. The FASB plans to issue either a final Statement or a revised
Exposure Draft in the second quarter of 1997. If current electric utility
industry accounting practices for decommissioning are changed, annual provisions
for decommissioning could increase and the estimated cost for decommissioning
could be recorded as a liability rather than as accumulated depreciation with
recognition of an increase in the cost of the related asset.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of
Energy (DOE) is required to begin taking possession of all spent nuclear fuel
generated by the Company's nuclear units for long-term storage by no later than
1998. Based on recent public pronouncements, it is not likely that a permanent
disposal site will be available for the industry before 2015, at the earliest.
In reaction to statements from the DOE that it was not legally obligated to
begin to accept spent fuel in 1998, a group of utilities and state government
agencies filed a lawsuit against the DOE which resulted in a decision by the
United States Court of Appeals for the District of Columbia (D.C. Court of
Appeals) in July 1996 that the DOE had an unequivocal obligation to begin to
accept spent fuel in 1998. In accordance with the NWPA, the Company pays the DOE
one mill ($.001) per kilowatthour of net nuclear generation for the cost of
nuclear fuel disposal. This fee may be adjusted prospectively in order to ensure
full cost recovery. Because of inaction by the DOE in response to the D.C. Court
of Appeals finding of the DOE's obligation to begin receiving spent fuel in
1998, a group of thirty-six utility companies, including the Company, and
forty-six state agencies, filed suit against the DOE on January 31, 1997 seeking
authorization to suspend further payments to the U.S. government under the NWPA
and to deposit such payments into an escrow account until such time as the DOE
takes effective action to meet its 1998 obligations. Legislation introduced in
Congress in January 1997 would authorize construction of a temporary storage
facility which could accept spent nuclear fuel from utilities soon after 1998.
In addition, the DOE is exploring other options to address delays in the waste
acceptance schedule.
Peach bottom and limerick have on-site facilities with the capacity to
store spent nuclear fuel discharged from the units through the early 2000s.
Life-of-plant storage capacity could be provided by the construction of on-site
dry cask storage facilities. Salem has on-site facilities with spent fuel
storage capacity through 2008 for Unit No. 1 and 2012 for Unit No. 2. Public
Service Electric and Gas Company (PSE&G) is the operator of Salem, which is
42.59% owned by the Company.
The Company is currently recovering in rates costs for nuclear
decommissioning and decontamination and spent fuel storage. The Company believes
that the ultimate costs of decommissioning and decontamination and spent fuel
disposal will continue to be recoverable, although such recovery is not assured.
Energy Purchases
In the ordinary course of business, the Company enters into commitments to buy
and sell power. As of December 31,1996, the Company had long-term aggreements to
purchase from unaffiliated utilities, primarily in 1997, energy associated with
2,200 MW of capacity. During 1996, purchases under long-term agreements resulted
in expenditures of $44 million. At December 31, 1996, these purchases result in
commitments of approximately $259 million for 1997, $48 million for 1998, $51
million for 1999, $52 million for 2000 and $50 million for 2001. These purchases
will be utilized through a combination of sales to jurisdictional customers
primarily to compensate for the Salem shutdown, long-term sales to other
utilities and open market sales.
Environmental Issues
The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under federal and state environmental laws, the Company is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by the Company and of property contaminated by
hazardous substances generated by the Company. The Company owns or leases a
number of real estate parcels, including parcels on which its operations or the
operations of others may have resulted in contamination by substances which are
considered hazardous under environmental laws. The Company is currently involved
in a number of proceedings relating to sites where hazardous substances have
been deposited and may be subject to additional proceedings in the future.
The Company has identified 27 sites where former manufactured gas plant
(MGP) activities have or may 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. Eight of the sites are under some degree of active study or
remediation.
As of December 31, 1996 and 1995, the Company had accrued $28 and $27
million, respectively, for environmental investigation and remediation costs,
including $16 and $13 million, respectively, for MGP investigation and
remediation, that currently can be reasonably estimated. The Company cannot
predict whether it will incur other significant liabilities for addi-
<PAGE>
31
tional investigation and remediation costs at these or additional sites
identified by the Company, environmental agencies or others, or whether all such
costs will be recoverable from third parties.
Shutdown of Salem Generating Station
PSE&G removed Salem Units No. 1 and No. 2 from service in the second quarter of
1995 and informed the NRC at that time that it had determined to keep the Salem
units shut down pending review and resolution of certain equipment and
management issues and NRC agreement that each unit is sufficiently prepared to
restart. PSE&G estimates the projected restart of Unit No. 2 to occur in the
second quarter of 1997 and of Unit No. 1 to occur in the summer of 1997. It is
the Company's belief that the earliest that Unit No. 1 will return to service is
late in the third quarter of 1997. For the years ended December 31, 1996 and
1995, the Company had incurred and expensed approximately $149 million and $50
million of replacement power and maintenance costs, respectively.
Litigation
The Company is involved in various litigation matters, the ultimate outcome of
such matters, while uncertain, is not expected to have a material adverse effect
on the Company's financial condition or results of operations.
5. Retirement Benefits
The Company and its subsidiaries have a non-contributory trusteed retirement
plan applicable to all regular employees. The benefits are based primarily upon
employees' years of service and average earnings prior to retirement. The
Company's funding policy is to contribute, at a minimum, amounts sufficient to
meet the Employee Retirement Income Security Act requirements. Approximately
80%, 74% and 85% of pension costs were charged to operations in 1996, 1995 and
1994, respectively, and the remainder, associated with construction labor, to
the cost of new utility plant.
Pension costs for 1996, 1995 and 1994 included the following components:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Thousands of Dollars
Service cost benefits earned during the period $ 27,627 $ 19,710 $ 33,403
Interest cost on projected benefit obligation 145,570 147,261 136,690
Actual return on plan assets (320,247) (456,057) 12,946
Amortization of transition asset (4,538) (4,538) (4,538)
Amortization and deferral 154,402 300,214 (161,955)
--------- --------- ---------
Net pension cost $ 2,814 $ 6,590 $ 16,546
========= ========= =========
</TABLE>
The changes in net periodic pension costs in 1996, 1995 and 1994 were as
follows:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Thousands of Dollars
Change in number, characteristics and salary
levels of participants and net actuarial gain $(12,893) $ 1,486 $ (6,004)
Change in plan provisions -- (8,305) (1,777)
Change in actuarial assumptions 9,117 (3,136) (959)
-------- -------- --------
Net change $ (3,776) $ (9,955) $ (8,740)
======== ======== ========
</TABLE>
Plan assets consist principally of common stock, U.S. government obligations and
other fixed income instruments. In determining pension costs, the assumed
long-term rate of return on assets was 9.5% for 1996, 1995 and 1994.
The weighted-average discount rate used in determining the actuarial
present value of the projected benefit obligation was 7.75% at December 31,
1996, 7.25% at December 31, 1995 and 8.25% at December 31, 1994. The average
rate of increase in future compensation levels ranged from 4% to 6% at December
31, 1996 and 1995, and from 4.25% to 6.25% at December 31, 1994.
Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plan.
<PAGE>
32
The funded status of the plan at December 31, 1996 and 1995 is summarized as
follows:
<TABLE>
<CAPTION>
1996 1995
Thousands of Dollars
<S> <C> <C>
Actuarial present value of accumulated plan benefit obligations:
Vested benefit obligation $(1,657,098) $(1,746,685)
Accumulated benefit obligation (1,742,116) (1,838,661)
Projected benefit obligation for services rendered to date $(1,982,915) $(2,097,300)
Plan assets at fair value 2,302,935 2,088,950
----------- -----------
Funded status 320,020 (8,350)
Unrecognized transition asset (40,251) (44,789)
Unrecognized prior service costs 92,682 68,223
Unrecognized net gain (588,013) (265,472)
----------- -----------
Pension liability recognized on the balance sheet $ (215,562) $ (250,388)
=========== ===========
</TABLE>
6. Non-Pension Postretirement Benefits
The Company provides certain health care and life insurance benefits for retired
employees. Company employees become eligible for these benefits if they retire
from the Company with ten years of service. These benefits and similar benefits
for active employees are provided by an insurance company whose premiums are
based upon the benefits paid during the year.
The transition obligation, which represents the previously unrecognized
accumulated non-pension postretirement benefit obligation, is being amortized on
a straight-line basis over an allowed 20-year period. As a result of voluntary
retirement and separation programs in 1994, the Company accelerated recognition
of $177 million of its non-pension postretirement benefits obligation (see note
21).
The transition obligation was determined by application of the terms of
medical, dental and life insurance plans, including the effects of established
maximums on covered costs, together with relevant actuarial assumptions and
health care cost trend rates, which are projected to range from 8% in 1997 to 5%
in 2002. The effect of a 1% annual increase in these assumed cost trend rates
would increase the accumulated postretirement benefit obligation by $68 million
and the annual service and interest costs by $8 million.
Total costs for all plans amounted to $71 million in 1996 and 1995 and $81
million in 1994.
The net periodic benefits costs for 1996 and 1995 included the following
components:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Thousands of Dollars
Service cost benefits earned during the period $ 11,855 $ 8,681 $ 17,056
Interest cost on projected benefit obligation 48,524 48,641 41,196
Amortization of transition asset 14,882 14,882 22,659
Actual return on plan assets (13,257) (2,075) --
Deferred asset gain 9,320 1,359 --
-------- -------- --------
Net postretirement benefits costs $ 71,324 $ 71,488 $ 80,911
======== ======== ========
</TABLE>
Plan assets consist principally of common stock, U.S. government obligations and
other fixed income instruments. In determining non-pension postretirement
benefits costs, the assumed long-term rate of return on assets was 8% for 1996,
1995 and 1994.
The weighted-average discount rate used in determining the actuarial
present value of the projected benefit obligation was 7.50% as of January 1,
1996, 8.50% as of January 1, 1995 and 7.25% at January 1, 1994. The average rate
of increase in future compensation levels ranged from 4% to 6% at December 31,
1996 and 1995, and from 4.25% to 6.25% at December 31, 1994.
Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plan.
<PAGE>
33
The funded status of the plan at December 31, 1996 and 1995 is summarized as
follows:
<TABLE>
<CAPTION>
1996 1995
<S> <C> <C>
Thousands of Dollars
Accumulated postretirement benefit obligation:
Retirees $ 609,206 $ 628,804
Fully eligible active plan participants 4,509 4,199
Other active plan participants 48,986 41,863
--------- ---------
Total 662,701 674,866
Plan assets at fair value (126,661) (66,735)
--------- ---------
Accumulated postretirement benefit obligation in excess of plan assets 536,040 608,131
Unrecognized transition obligation (238,108) (252,990)
Unrecognized net gain (17,126) (28,890)
--------- ---------
Accrued postretirement benefits cost recognized on the balance sheet $ 315,058 $ 326,251
========= =========
</TABLE>
Measurement of the accumulated postretirement benefits obligation was based on a
7.75% and 7.5% assumed discount rate as of December 31, 1996 and 1995,
respectively.
For the regulatory treatment of non-pension postretirement benefits costs, see
note 3.
7. Accounts Receivable
Accounts receivable at December 31, 1996 and 1995 included unbilled operating
revenues of $117 and $148 million, respectively. Accounts receivable at December
31, 1996 and 1995 were net of an allowance for uncollectible accounts of $24 and
$21 million, respectively.
The Company is party to an agreement with a financial institution under
which it sold with limited recourse an undivided interest, adjusted daily, in up
to $425 million of designated accounts receivable until November 14, 2000. At
December 31, 1996 and 1995, the Company had sold a $425 million interest in
accounts receivable. The Company retains the servicing responsibility for these
receivables.
By terms of this agreement, under certain circumstances, a portion of
deferred Limerick costs may be included in the pool of eligible receivables. At
December 31, 1996, $23 million of deferred Limerick costs were included in the
pool of eligible receivables.
8. Common Stock
At December 31, 1996 and 1995, common stock without par value consisted of
500,000,000 shares authorized and 222,542,087 and 222,172,216 shares
outstanding, respectively. At December 31, 1996, there were 5,800,841 shares
reserved for issuance under the dividend reinvestment and stock purchase plan.
Long-Term Incentive Plan (LTIP)
The Company maintains an LTIP for certain full-time salaried employees of the
Company. The types of long-term incentive awards which may be granted under the
LTIP are non-qualified options to purchase shares of the Company's common stock,
dividend equivalents and shares of restricted common stock. The Company has
adopted the disclosure-only provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation," but applies Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees" and related interpretations
in accounting for the LTIP. If the Company had elected to account for the LTIP
based on SFAS No. 123, earnings applicable to common stock and earnings per
average common share would have been changed to the pro forma amounts as
indicated below:
<TABLE>
<CAPTION>
1996 1995
Thousands of Dollars
<S> <C> <C> <C>
Earnings applicable to common stock As reported $499,169 $586,515
Pro forma $497,887 $585,063
Earnings per average common share (Dollars) As reported $ 2.24 $ 2.64
Pro forma $ 2.24 $ 2.64
</TABLE>
<PAGE>
34
Options granted under the LTIP become exercisable on the anniversary of the date
of grant and all options expire 10 years from the date of the grant. Information
with respect to the LTIP at December 31, 1996 and changes for the three years
then ended, is as follows:
<TABLE>
<CAPTION>
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Price Price Price
Shares (per share) Shares (per share) Shares (per share)
1996 1996 1995 1995 1994 1994
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1 2,591,765 $ 26.16 2,651,397 $ 26.73 1,961,882 $ 25.12
Options granted 786,500 28.12 850,700 26.46 909,000 30.13
Options exercised (369,871) 25.07 (561,232) 23.91 (90,885) 22.91
Options cancelled (47,200) 29.36 (349,100) 35.57 (128,600) 28.87
--------- --------- ---------
Balance at December 31 2,961,194 26.68 2,591,765 26.16 2,651,397 26.73
========= ========= =========
Exercisable at December 31 2,192,694 26.17 1,813,565 25.91 1,865,397 25.21
Weighted average fair value of
options granted during year $ 2.78 $ 2.91 $ --
</TABLE>
The fair value of each option is estimated on the date of the grant using the
Black-Scholes option-pricing model.
The following weighted average assumptions were used for grants in 1996:
dividend yield of 6.2%, expected volatility of 16.6%, risk-free interest rate of
5.5%, and an expected life of five years. The following weighted average
assumptions were used for grants in 1995: dividend yield of 6.2%, expected
volatility of 15.3%, risk-free interest rate of 6.9%, and an expected life of
five years.
At December 31, 1996, the option groups outstanding based on ranges of
exercise prices is as follows:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
Weighted-
Average Weighted- Weighted-
Remaining Average Average
Number Contractual Life Exercise Number Exercise
Range of Exercise Prices Outstanding (Years) Price Exercisable Price
<C> <C> <C> <C> <C> <C>
$15.75 - $20.00 117,594 3.86 $ 18.43 117,594 $ 18.43
$20.01 - $25.00 155,500 4.75 22.70 125,500 22.37
$25.01 - $30.00 2,675,900 7.63 27.23 1,941,400 26.86
$30.01 - $50.00 12,200 7.55 37.18 8,200 30.93
--------- ---------
Total 2,961,194 2,192,694
--------- ---------
</TABLE>
9. Preferred and Preference Stock
At December 31, 1996 and 1995, Series Preference Stock consisted of 100,000,000
shares authorized, of which no shares were outstanding. At December 31, 1996 and
1995, cumulative Preferred Stock, no par value, consisted of 15,000,000 shares
authorized.
<TABLE>
<CAPTION>
Current Shares Amount
Redemption Outstanding Thousands of Dollars
Price(a) 1996 1995 1996 1995
<S> <C> <C> <C> <C> <C>
Series (without mandatory redemption)
$4.68 104.00 150,000 150,000 $ 15,000 $ 15,000
$4.40 112.50 274,720 274,720 27,472 27,472
$4.30 102.00 150,000 150,000 15,000 15,000
$3.80 106.00 300,000 300,000 30,000 30,000
$7.96(b) (c) 618,954 618,954 61,895 61,895
$7.48 (d) 500,000 500,000 50,000 50,000
--------- --------- ---------- -----------
1,993,674 1,993,674 199,367 199,367
Series (with mandatory redemption)
$6.12 (e) 927,000 927,000 92,700 92,700
--------- --------- ---------- -----------
Total preferred stock 2,920,674 2,920,674 $ 292,067 $ 292,067
========= ========= ========== ===========
<FN>
(a) Redeemable, at the option of the Company, at the indicated dollar amounts
per share, plus accrued dividends.
(b) Ownership of this series of preferred stock is evidenced by depositary
receipts, each representing one-fourth of a share of preferred stock.
(c) None of the shares of this series are subject to redemption prior to
October 1, 1997.
(d) None of the shares of this series are subject to redemption prior to April
1, 2003.
(e) There are no annual sinking fund requirements in the period 1997-1998.
Annual sinking fund requirements in 1999 are $18,540,000. None of the
shares of this series are subject to redemption prior to August 1, 1999.
</FN>
</TABLE>
<PAGE>
35
10. Company Obligated Mandatorily Redeemable Preferred Securities of a
Partnership (COMRPS)
At December 31, 1996 and 1995, PECO Energy Capital, L.P. (Partnership), a
Delaware limited partnership of which a wholly owned subsidiary of the Company
is the sole general partner, had outstanding two series of cumulative COMRPS,
each with a liquidation value of $25 per security. Each series is supported by
the Company's deferrable interest subordinated debentures, held by the
Partnership, which bear interest at rates equal to the distribution rates on the
securities. The interest paid by the Company on the debentures is included in
Interest Charges in the Consolidated Statements of Income and is deductible for
income tax purposes.
<TABLE>
<CAPTION>
Amount
Shares Outstanding Thousands of Dollars
At December 31, Due Distribution Rate 1996 1995 1996 1995
Series
<S> <C> <C> <C> <C> <C> <C>
A 2043 9.00% 8,850,000 8,850,000 $ 221,250 $ 221,250
B (a) 2025 8.72% 3,124,183 3,124,183 80,932 81,032
---------- ---------- ----------- -----------
Total 11,974,183 11,974,183 $ 302,182 $ 302,282
========== ========== =========== ===========
<FN>
(a) Ownership of this series is evidenced by Trust Receipts, each representing
a 8.72% COMRPS, Series B, representing limited partnership interests. The
Trust Receipts were issued by PECO Energy Capital Trust I, the sole assets
of which are 8.72% COMRPS, Series B. Each holder of Trust Receipts is
entitled to withdraw the corresponding number of 8.72% COMRPS, Series B
from the Trust in exchange for the Trust Receipts so held.
</FN>
</TABLE>
11. Long-Term Debt
<TABLE>
<CAPTION>
At December 31, Series Due 1996 1995
Thousands of Dollars
<S> <C> <C> <C> <C>
First and refunding mortgage bonds (a) 6 1/8 % 1997 $ 75,000 $ 75,000
5 3/8 % 1998 225,000 225,000
7 1/2%-9 1/4 % 1999 325,000 325,000
5 5/8%-7 3/8 % 2001 330,000 330,000
6 3/8%-8 % 2002-2006 1,025,000 1,025,000
10 1/4 % 2007-2011 44,688 48,750
(b) 2012-2016 154,200 188,200
6 7/10%-7 3/5 % 2017-2021 277,590 277,590
6 5/8%-8 3/4 % 2022-2024 1,329,540 1,329,540
----------- -----------
Total first and refunding mortgage bonds 3,786,018 3,824,080
Notes payable - banks -- 167,000
Term loan agreements (c) 1997 175,000 350,000
Pollution control notes (d) 1997-2034 212,705 169,005
Medium-term notes (e) 1997-2005 74,400 121,800
Unamortized debt discount and premium, net (29,306) (32,599)
----------- -----------
Total long-term debt 4,218,817 4,599,286
Due within one year (f) 283,303 401,003
----------- -----------
Long-term debt included in capitalization (g) $ 3,935,514 $ 4,198,283
=========== ===========
<FN>
(a) Utility plant is subject to the lien of the Company's mortgage.
(b) Floating rates, which were an average annual interest rate of 3.532% at
December 31, 1996.
(c) The average annual rate in 1996 was 5.94%. The Company also has a $400
million revolving credit and term loan agreement with a group of banks
which terminates in 2001. There is an annual commitment fee of 0.125% on
the unused amount. There was no debt outstanding under this agreement at
December 31, 1996.
(d) Floating rates, which were an average annual interest rate of 3.620% at
December 31, 1996.
(e) Medium-term notes collateralized by mortgage bonds. The average annual
interest rate was 8.465% at December 31, 1996.
(f) Long-term debt maturities, including mandatory sinking fund requirements,
in the period 1997-2001 are as follows: 1997 - $283,303,000; 1998 -
$241,463,000; 1999 - $359,063,000; 2000 - $4,063,000; 2001 - $334,063,000.
(g) The annualized interest on long-term debt at December 31, 1996, was $292
million, of which $274 million was associated with mortgage bonds and $18
million was associated with other long-term debt.
</FN>
</TABLE>
<PAGE>
36
12. Short-Term Debt
<TABLE>
<CAPTION>
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Average borrowings $ 198,090 $ 17,560 $ 130,539
Average interest rates, computed on daily basis 5.64% 6.25% 4.03%
Maximum borrowings outstanding $ 369,500 $182,000 $ 418,600
Average interest rates, at December 31 6.90% -- 6.73%
</TABLE>
The Company has a $300 million commercial paper program which is supported by
the $400 million revolving credit agreement (see note 11); at December 31, 1996,
$200 million was outstanding. In 1996, $87.5 million of a term loan agreement
with a group of banks was refinanced with a single bank as short-term debt under
a 364-day term loan facility; at December 31, 1996, $87.5 million was
outstanding. At December 31, 1996, the Company had formal and informal lines of
credit with banks aggregating $275 million. No short-term debt was outstanding
against these lines at that date.
13. Income Taxes
Income tax expense is comprised of the following components:
<TABLE>
<CAPTION>
For the Years Ended December 31, 1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Included in operating income:
Federal
Current $ 126,702 $ 170,042 $ 164,472
Deferred 156,129 159,970 (2,691)
Investment tax credit, net (15,979) (21,679) 28,006
State
Current 63,447 72,177 77,754
Deferred 12,806 16,387 (33,508)
--------- --------- ---------
343,105 396,897 234,033
========= ========= =========
Included in other income and deductions:
Federal
Current (231) 20,754 1,989
Deferred (1,565) 7,556 9,722
State
Current (608) 6,909 409
Deferred (600) (399) 3,171
--------- --------- ---------
(3,004) 34,820 15,291
--------- --------- ---------
Total $ 340,101 $ 431,717 $ 249,324
========= ========= =========
</TABLE>
The total income tax provisions differed from amounts computed by applying the
federal statutory tax rate to income as shown below:
<TABLE>
<CAPTION>
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Net Income $ 517,205 $ 609,732 $ 426,713
Total income tax provisions 340,101 431,717 249,324
----------- ----------- -----------
Income before income taxes $ 857,306 $ 1,041,449 $ 676,037
=========== =========== ===========
Income taxes on above at federal statutory rate at 35% $ 300,057 $ 364,507 $ 236,613
Increase (decrease) due to:
Depreciation timing differences not normalized 7,924 14,127 12,767
Limerick plant disallowances and phase-in plan (651) (736) (530)
AFUDC (6,981) (9,467) (7,759)
State income taxes, net of federal income tax benefit 48,779 61,799 31,086
Amortization of investment tax credit (15,979) (13,604) (14,570)
Prior period income taxes (1,707) 1,791 (14,524)
Other, net 8,659 13,300 6,241
----------- ----------- -----------
Total income tax provisions $ 340,101 $ 431,717 $ 249,324
=========== =========== ===========
Effective Income Tax rate 39.7% 41.5% 36.9%
</TABLE>
<PAGE>
37
Provisions for deferred income taxes consist of the tax effects of the following
temporary differences:
<TABLE>
<CAPTION>
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Depreciation and amortization $ 42,385 $ 32,287 $ 85,772
Deferred energy costs 27,374 30,073 13,777
Retirement and separation programs 19,746 15,733 (82,008)
Incremental nuclear maintenance and refueling outage costs 2,440 8,079 (2,751)
Uncollectible accounts (2,805) (1,991) (23,096)
Reacquired debt (9,578) (3,266) (12,954)
Unrecovered revenue 3,910 (5) (2,239)
Environmental clean-up costs (714) 2,433 (3,949)
Obsolete inventory 5,829 6,362 (6,192)
Limerick plant disallowances and phase-in plan (747) 2,507 12,894
AMT credits 83,010 91,399 --
Other (4,080) (97) (2,560)
--------- --------- ---------
Total $ 166,770 $ 183,514 $ (23,306)
========= ========= =========
</TABLE>
The tax effect of temporary differences which gives rise to the Company's net
deferred tax liability as of December 31, 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
Liability or (Asset)
1996 1995
Millions of Dollars
<S> <C> <C>
Nature of temporary difference
Plant basis difference $ 3,796 $ 3,797
Deferred investment tax credit 336 351
Deferred debt refinancing costs 120 130
Other, net (168) (249)
------- -------
Deferred income taxes (net) on the balance sheet $ 4,084 $ 4,029
======= =======
</TABLE>
The net deferred tax liability shown above as of December 31, 1996 and 1995 is
comprised of $4,347 and $4,401 million of deferred tax liabilities, and $263 and
$372 million of deferred tax assets, respectively.
In accordance with SFAS No. 71, the Company has recorded a recoverable
deferred income tax asset of $2,322 million and $2,420 million at December 31,
1996 and 1995, respectively (see note 22). These recoverable deferred income
taxes include the deferred tax effects associated principally with liberalized
depreciation accounted for in accordance with the ratemaking policies of the
PUC, as well as the revenue impacts thereon, and assume recovery of these costs
in future rates.
The Internal Revenue Service (IRS) has completed and settled its
examinations of the Company's federal income tax returns through 1986. The 1987
through 1990 federal income tax returns have been examined and the IRS
subsequently issued an assessment that the Company has appealed. The Company
does not expect the ultimate resolution of the assessment and its appeal to have
a material effect upon the Company's financial condition or results of
operations. The years 1991 through 1993 are currently being examined by the IRS.
Investment tax credits and other general business credits were fully
utilized for tax purposes at December 31, 1994 and reduced federal income taxes
currently payable by $43 million in 1994. The AMT credit was fully utilized for
tax purposes at December 31, 1996, and reduced federal income taxes currently
payable by $71 million in 1996.
14. Taxes, Other Than Income - Operating
<TABLE>
<CAPTION>
For the Years Ended December 31, 1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
Gross receipts $160,246 $165,172 $160,704
Capital stock 41,972 42,444 39,957
Real estate 69,185 71,600 77,571
Payroll 27,585 30,109 31,556
Other 558 4,746 1,901
-------- -------- --------
Total $299,546 $314,071 $311,689
======== ======== ========
</TABLE>
<PAGE>
38
15. Leases
Leased property included in utility plant at December 31, was as follows:
<TABLE>
<CAPTION>
1996 1995
Thousands of Dollars
<S> <C> <C>
Nuclear fuel $ 527,116 $ 494,051
Electric plant 2,069 2,076
--------- ---------
Gross leased property 529,185 496,127
Accumulated amortization (347,097) (315,702)
--------- ---------
Net leased property $ 182,088 $ 180,425
========= =========
</TABLE>
The nuclear fuel obligation is amortized as the fuel is consumed. Amortization
of leased property totaled $31, $43 and $62 million for the years ended December
31, 1996, 1995 and 1994, respectively. Other operating expenses included
interest on capital lease obligations of $9, $10 and $7 million in 1996, 1995
and 1994, respectively.
Minimum future lease payments as of December 31, 1996 were:
<TABLE>
<CAPTION>
For the Year Ending December 31, Capital Leases Operating Leases Total
Thousands of Dollars
<C> <C> <C> <C>
1997 $ 49,804 $ 47,919 $ 97,723
1998 54,595 44,541 99,136
1999 45,751 42,339 88,090
2000 22,267 41,534 63,801
2001 20,305 40,632 60,937
Remaining years 18,598 554,412 573,010
---------- ----------- -----------
Total minimum future lease payments $ 211,320 $ 771,377 $ 982,697
=========== ===========
Imputed interest (rates ranging from 6.5% to 17.0%) (29,232)
----------
Present value of net minimum future lease payments $ 182,088
==========
</TABLE>
Rental expense under operating leases totaled $74, $115 and $101 million in
1996, 1995 and 1994, respectively.
16. Jointly Owned Electric Utility Plant
The Company's ownership interests in jointly owned electric utility plant at
December 31, 1996 were as follows:
<TABLE>
<CAPTION>
Transmission
Production Plants and Other Plant
Peach Bottom Salem Keystone Conemaugh
Public Service GPU GPU
PECO Energy Electric and Generating Generating Various
Operator Company Gas Company Corp. Corp. Companies
<S> <C> <C> <C> <C> <C>
Participating interest 42.49% 42.59% 20.99% 20.72% 21% to 43%
Company's share (Thousands of Dollars)
Utility plant $ 754,271 $1,234,771 $ 108,144 $ 165,713 $ 87,623
Accumulated depreciation 326,778 432,959 59,231 67,216 30,475
Construction work in progress 49,441 164,122 8,956 22,529 1,164
</TABLE>
The Company's participating interests are financed with Company funds and, when
placed in service, all operations are accounted for as if such participating
interests were wholly owned facilities.
<PAGE>
39
17. Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all highly
liquid debt instruments purchased with a maturity of three months or less to be
cash equivalents. The following disclosures supplement the accompanying
Statements of Cash Flows:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Thousands of Dollars
Cash paid during the year:
Interest (net of amount capitalized) $415,063 $449,664 $437,096
Income taxes (net of refunds) 251,554 257,677 205,316
Noncash investing and financing:
Capital lease obligations incurred 33,063 48,760 41,763
</TABLE>
18. Investments
<TABLE>
<CAPTION>
At December 31, 1996 1995
Thousands of Dollars
<S> <C> <C>
Trust accounts for decommissioning nuclear plants $266,270 $222,655
Telecommunications ventures 79,833 21,500
Energy services and other ventures 44,023 40,779
Nonutility property 26,349 26,816
Other deposits 11,255 132
Emission allowances 2,480 6,347
Gas exploration and development joint ventures 2,364 219
-------- --------
Total $432,574 $318,448
======== ========
</TABLE>
19. Financial Instruments
Fair values of financial instruments, including liabilities, are estimated based
on quoted market prices for the same or similar issues. The carrying amounts and
fair values of the Company's financial instruments as of December 31, 1996 and
1995 were as follows:
<TABLE>
<CAPTION>
Thousands of Dollars 1996 1995
Carrying Amount Fair Value Carrying Amount Fair Value
<S> <C> <C> <C> <C>
Cash and temporary cash investments $ 29,235 $ 29,235 $ 20,602 $ 20,602
Long-term debt (including amounts due within one year) 4,218,817 4,239,357 4,599,286 4,773,700
Trust accounts for decommissioning nuclear plants 266,270 266,270 222,655 222,655
</TABLE>
Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of temporary cash investments and customer
accounts receivable. The Company places its temporary cash investments with
high-credit, quality financial institutions. At times, such investments may be
in excess of the Federal Deposit Insurance Corporation limit. Concentrations of
credit risk with respect to customer accounts receivable are limited due to the
Company's large number of customers and their dispersion across many industries.
20. Other Income
Nuclear Fuel Agreement with Long Island Power Authority (LIPA)
In 1994, the Company recognized $26 million as Other Income in accordance with a
1993 agreement with LIPA and other parties to accept slightly irradiated nuclear
fuel from Shoreham Nuclear Power Station.
Sale of Subsidiary
On June 19, 1995, the Company completed the sale of Conowingo Power Company
(COPCO) to Delmarva Power & Light Company (Delmarva) for $150 million. The
transaction also included a ten-year contract for the Company to sell power to
Delmarva. The Company's gain of $59 million ($27 million net of taxes) on the
sale was recorded in the second quarter of 1995.
<PAGE>
40
21. Voluntary Retirement and Separation Programs
The Company incurred a one-time, pre-tax charge of $254 million ($145 million
net of taxes) in the third quarter of 1994 as a result of voluntary retirement
and separation programs approved by the Company's Board of Directors in April
1994. Pursuant to these programs 1,474 employees elected to retire and 1,008
employees elected to voluntarily separate from the Company. The retirements and
separations took place in stages through December 31, 1995. As a result of the
programs, in 1994 the Company accelerated recognition of $177 million of its
non-pension postretirement benefits obligation. The Company recorded a
corresponding regulatory asset and is recovering this amount in rates as a
component of non-pension postretirement benefits expense. The recognition of the
$177 million of non-pension postretirement benefits obligation and corresponding
regulatory asset did not impact earnings.
22. Regulatory Assets and Liabilities
At December 31, 1996 and 1995, the Company had deferred the following regulatory
assets on the Consolidated Balance Sheet:
<TABLE>
<CAPTION>
1996 1995
Millions of Dollars
<S> <C> <C>
Recoverable deferred income taxes (see note 13) $2,322 $2,420
Deferred Limerick costs (see note 3) 362 390
Loss on reacquired debt 284 309
Compensated absences 38 33
Deferred energy costs (see note 3) 122 56
Non-pension postretirement benefits (see note 3) 233 248
------ ------
Total $3,361 $3,456
====== ======
</TABLE>
23. Quarterly Data (Unaudited)
The data shown below include all adjustments which the Company considers
necessary for a fair presentation of such amounts:
<TABLE>
<CAPTION>
Operating Revenues Operating Income Net Income
Millions of Dollars 1996 1995 1996 1995 1996 1995
<S> <C> <C> <C> <C> <C> <C>
Quarter ended
March 31 $1,171 $1,059 $ 253 $ 257 $ 150 $ 152
June 30 989 959 196 233 99 154
September 30 1,110 1,125 249 292 150 184
December 31 1,014 1,044 208 222 118 120
</TABLE>
<TABLE>
<CAPTION>
Earnings Applicable Average Shares Earnings
to Common Stock Outstanding Per Average Share
Millions of Dollars 1996 1995 1996 1995 1996 1995
Quarter ended
<S> <C> <C> <C> <C> <C> <C>
March 31 $146 $146 222.4 221.7 $ 0.65 $ 0.66
June 30 94 148 222.5 221.8 0.43 0.67
September 30 145 178 222.5 221.9 0.65 0.80
December 31 114 115 222.5 221.9 0.51 0.52
</TABLE>
The decrease in 1996 third quarter results was primarily due to the lower
electric revenues from less favorable weather conditions, higher customer
expenses and higher costs related to the Salem outage.
1995 second quarter results include a pre-tax gain of $59 million ($27
million net of taxes), or $0.12 per share, as a result of the sale of COPCO (see
note 20).
Exhibit 21
PECO ENERGY COMPANY
Subsidiaries
PECO Energy Power Company
Pennsylvania Corporation
Subsidiaries:
Susquehanna Power Company
The Proprietors of the Susquehanna Canal (Inactive)
Susquehanna Electric Company
Maryland Corporation
PECO Wireless, Inc.
Pennsylvania Corporation
The Proprietors of the Susquehanna Canal- (inactive)
Maryland Corporation
Horizon Energy Company (formerly known as PECO Gas Supply Company)
Pennsylvania Corporation
PECO Energy Capital Corp.
Delaware Corporation
Eastern Pennsylvania Development Co.
Subsidiaries: Adwin Equipment Company
Adwin Realty Company
Adwin (Schuylkill) Cogeneration, Inc.
Buttonwood Associates, Inc.
Energy Performance Services, Inc.
Route 213 Enterprises, Inc.
Exelon Corporation
Pennsylvania Corporation
Energy Trading Company
Delaware Corporation
Eastern Pennsylvania Exploration Company
Pennsylvania Corporation
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
PECO Energy on Form S-3 (File Nos. 33-31436, 33-59152, 33-49887, 33-43523, and
33-54935), Form S-4 (File Nos. 33-53785, 33-53785-01, 33-60859, and
33-60859-01), and Form S-8 (File No. 33-30317) of our report dated February 3,
1997, on our audits of the consolidated financial statements of PECO Energy
Company and Subsidiary Companies as of December 31, 1996 and 1995 and for each
of the three years in the period ended December 31, 1996, which report is
incorporated by reference in this Annual Report on Form 10-K.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
March 25, 1997
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Susan W. Catherwood of Bryn Mawr, PA, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ S. W. CATHERWOOD
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, M. Walter D'Alessio of Philadelphia, PA,
do hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of
them, attorney for me and in my name and on my behalf to sign the annual
Securities and Exchange Commission report on Form 10-K for 1996 of PECO Energy
Company, to be filed with the Securities and Exchange Commission, and generally
to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/S/ M. WALTER D'ALESSIO
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Richard G. Gilmore of Bradenton, FL, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ RICHARD G. GILMORE
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Richard H. Glanton of Philadelphia, PA,
do hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of
them, attorney for me and in my name and on my behalf to sign the annual
Securities and Exchange Commission report on Form 10-K for 1996 of PECO Energy
Company, to be filed with the Securities and Exchange Commission, and generally
to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/S/ RICHARD H. GLANTON
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, James A. Hagen of Wilmington, North
Carolina, do hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or
either of them, attorney for me and in my name and on my behalf to sign the
annual Securities and Exchange Commission report on Form 10-K for 1996 of PECO
Energy, to be filed with the Securities and Exchange Commission, and generally
to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/S/ JAMES A. HAGEN
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Nelson G. Harris of Lafayette Hill, PA,
do hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of
them, attorney for me and in my name and on my behalf to sign the annual
Securities and Exchange Commission report on Form 10-K for 1996 of PECO Energy
Company, to be filed with the Securities and Exchange Commission, and generally
to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/S/ NELSON G. HARRIS
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Joseph C. Ladd of Amelia Island, FL, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ JOSEPH C. LADD
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Edithe J. Levit of Philadelphia, PA, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ EDITHE J. LEVIT
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Kinnaird R. McKee of Oxford, MD, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ KINNAIRD R. MCKEE
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Joseph J. McLaughlin of Rosemont, PA, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ JOSEPH J. MCLAUGHLIN
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Corbin A. McNeill, Jr. of Kennett Square,
PA, do hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of
them, attorney for me and in my name and on my behalf to sign the annual
Securities and Exchange Commission report on Form 10-K for 1996 of PECO Energy
Company, to be filed with the Securities and Exchange Commission, and generally
to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/S/ CORBIN A. MCNEILL, JR.
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Dr. John M. Palms of Columbia, SC, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ DR. JOHN M. PALMS
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Joseph F. Paquette, Jr. of Gladwyne, PA,
do hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of
them, attorney for me and in my name and on my behalf to sign the annual
Securities and Exchange Commission report on Form 10-K for 1996 of PECO Energy
Company, to be filed with the Securities and Exchange Commission, and generally
to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/S/ JOSEPH F. PAQUETTE, JR.
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Ronald Rubin of Narberth, PA, do hereby
appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and
Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to be
filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ RONALD RUBIN
--------------------------------
March 25, 1997
DATE:_________________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, Robert Subin of Blue Bell, PA, do hereby
appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and
Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to be
filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ ROBERT SUBIN
--------------------------------
March 25, 1997
DATE:_______________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, R. Keith Elliott of Mendenhall, PA, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ R. KEITH ELLIOTT
--------------------------------
March 25, 1997
DATE:_______________
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that I, G. Fred DiBona, Jr. of Bryn Mawr, PA, do
hereby appoint J. F. PAQUETTE, JR. and C. A. MC NEILL, JR., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities
and Exchange Commission report on Form 10-K for 1996 of PECO Energy Company, to
be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/S/ G. FRED DIBONA
--------------------------------
March 25, 1997
DATE:_______________
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