================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
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, 1998
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
---------------------
PECO ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Pennsylvania 23-0970240
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
P.O. Box 8699
2301 Market Street, Philadelphia, PA (215) 841-4000 19101
(Address of principal executive offices) (Registrant's telephone number, including area code) (Zip Code)
---------------------
Securities registered pursuant to Section 12(b) of the Act:
First and Refunding Mortgage Bonds (Listed on the New York Stock Exchange):
5 5/8% Series due 2001 6 1/2% Series due 2003 7 1/8% Series due 2023 7 1/4% Series due 2024
7 3/8% Series due 2001 6 3/8% Series due 2005 7 3/4% Series 2 due 2023
Cumulative Preferred Stock -- without par value (Listed on the New York and Philadelphia Stock Exchanges):
$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 II, each representing an 8.00%
Cumulative Monthly Income Preferred Security, Series C, $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 III, each representing an 7.38%
Cumulative Monthly Income Preferred Security, Series D, $1,000 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
---------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes _X_ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the registrant's common stock (only voting
stock) held by non-affiliates of the registrant was $9,305,227,737 at March
26, 1999.
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: 203,392,956 shares
outstanding at March 26, 1999.
---------------------
DOCUMENTS INCORPORATED BY REFERENCE (In Part)
Annual Report of PECO Energy Company to Shareholders for the year 1998
is incorporated in part in Parts I, II and IV hereof, as specified herein.
Proxy Statement of PECO Energy Company in connection with its 1999 Annual
Meeting of Shareholders is incorporated in part in Part III hereof,
as specified herein.
================================================================================
Page No.
--------
PART I
ITEM 1. BUSINESS ......................................................... 1
The Company ...................................................... 1
Deregulation and Rate Matters .................................... 1
Electric -- Retail .............................................. 2
Electric -- Wholesale ........................................... 5
Gas ............................................................. 6
Competition. .................................................... 6
Electric Operations .............................................. 7
General ......................................................... 7
Limerick Generating Station .....................................10
Peach Bottom Atomic Power Station ...............................12
Salem Generating Station ........................................12
Fuel .............................................................13
Nuclear .........................................................13
Coal. ...........................................................15
Oil .............................................................15
Natural Gas .....................................................15
Gas Operations ...................................................16
Year 2000 Readiness Disclosure ...................................16
Segment Information ..............................................17
Capital Requirements and Financing Activities. ...................17
Construction .....................................................19
Employee Matters .................................................20
Environmental Regulations ........................................20
Water ...........................................................20
Air .............................................................21
Solid and Hazardous Waste .......................................21
Costs ...........................................................24
AmerGen Energy Company, LLC ......................................24
Telecommunications Ventures ......................................24
PECO Energy Capital Corp. and Related Entities ...................25
Executive Officers of the Registrant. ............................26
ITEM 2. PROPERTIES .......................................................28
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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. ......31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ......................31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE ........................................31
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ...............31
ITEM 11. EXECUTIVE COMPENSATION. ..........................................31
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT. ................................................. ...32
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ...................32
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K ................................................. ...33
Financial Statements and Financial Statement Schedule ............33
REPORT OF INDEPENDENT ACCOUNTANTS. ...............................34
SCHEDULE II-- VALUATION AND QUALIFYING ACCOUNTS. .................35
Exhibits .........................................................36
Reports on Form 8-K ..............................................39
SIGNATURES
i
PART I
ITEM 1. BUSINESS
The Company
Incorporated in Pennsylvania in 1929, PECO Energy Company (Company) is
primarily a vertically integrated utility that historically has provided
regulated retail electric and natural gas service to customers in its
franchised service territory in southeastern Pennsylvania. Beginning in 1999,
the Electricity Generation Customer Choice and Competition Act (Competition
Act) requires the unbundling of retail electric services in Pennsylvania into
separate generation, transmission and distribution services with open retail
competition for generation services. With the advent of deregulation, the
Company serves as the local distribution company providing electric
distribution services in southeastern Pennsylvania and bundled electric service
to customers who cannot or do not choose an alternate electric generation
supplier (EGS). Through its Exelon division, the Company is a competitive
generation supplier offering a variety of unregulated energy and utility
infrastructure services, including electric supply, to businesses and
residential customers across Pennsylvania. The Company also engages in the
wholesale marketing of electricity on a national basis. The Company also
participates in joint ventures which provide telecommunication services in the
Philadelphia metropolitan region.
At December 31, 1997, the Company discontinued the use of regulatory
accounting in its financial statements for its electric generation operations.
In connection with the discontinuance of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation,"
the Company performed a market value analysis of its generation assets and
wrote-off $1.8 billion (net of income taxes) of unrecoverable electric plant
costs and regulatory assets. 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 1998.
The Company is a public utility under the Pennsylvania Public Utility Code
and a transmitting utility and electric utility under the Federal Power Act. As
a result, the Company is subject to regulation by the Pennsylvania Public
Utility Commission (PUC) as to electric distribution, certain retail electric
rates, retail 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 (DRBC) 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 Company established specific goals to increase its generation capacity
from 9 gigawatts to 25 gigawatts by 2003. The Company is targeting a balanced
portfolio of nuclear, hydro and clean burning fossil capacity through the
acquisition of plants and long-term supply agreements. In order to meet this
strategic objective the Company may require significant capital resources.
Deregulation and Rate Matters
Historically, all of the Company's retail electric and gas revenues have
been derived pursuant to bundled rates regulated by the PUC and all of the
Company's wholesale electric revenue has been derived pursuant to
1
rates regulated by the FERC. As a result of the adoption of the Competition Act
and deregulation initiatives by the FERC, electric services are being unbundled
into separate generation, transmission and distribution services with open
competition for both retail and wholesale generation services. Certain
transmission and distribution services will remain subject to regulation.
Electric -- Retail
The Competition Act was enacted in December 1996 and provides 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 services. Generation services may be provided by EGSs licensed by
the PUC. Under the Competition Act, EGSs are subject to certain limited
financial and disclosure requirements but are otherwise unregulated by the PUC.
The Competition Act required utilities to submit restructuring plans,
including their stranded costs which will result from retail competition for
generation services. Stranded costs include regulatory assets, nuclear
decommissioning costs and long-term purchase 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.
As a mechanism for utilities to recover their allowed stranded costs, the
Competition Act provides for the imposition and collection of non-bypassable
charges on customers' bills called competitive transition charges (CTCs). CTCs
are assessed to and collected from all retail customers who have been assigned
stranded cost responsibility and access the utilities' transmission and
distribution systems and may be collected over a maximum period of nine years,
except as such period may be extended by the PUC for good cause shown. As the
CTCs are based on access to the utility's transmission and distribution system,
they will be assessed regardless of whether such customer purchases electricity
from the utility or an EGS. The Competition Act provides, however, that the
utility's right to collect CTCs is contingent on the continued operation at
reasonable availability levels of the assets for which the stranded costs were
awarded, except where continued operation is no longer cost efficient because
of the transition to a competitive market.
The Competition Act also authorizes the PUC to issue qualified rate orders
approving the issuance of transition bonds to facilitate the recovery or
financing of qualified transition expenses of an electric utility or its
assignee. Under the Competition Act, proceeds of transition bonds are required
to be used principally to reduce qualified transition expenses, including
stranded costs, and the related capitalization costs of the utility. The
transition bonds are payable from intangible transition charges (ITCs) which
are collected in lieu of CTCs.
In accordance with the provisions of the Competition Act, in April 1997,
the Company filed with the PUC a comprehensive restructuring plan detailing its
proposal to implement full customer choice of electric generation suppliers.
The Company's restructuring plan identified $7.5 billion of retail electric
generation-related stranded costs. In August 1997, the Company and various
intervenors in the Company's restructuring proceeding filed with the PUC a
Joint Petition for Partial Settlement (Joint Petition). In December 1997, the
PUC rejected the Joint Petition and entered an Opinion and Order, revised in
January and February 1998 (PUC Restructuring Order), which deregulated the
Company's electric generation operations. The PUC Restructuring Order
authorized the Company to recover stranded costs of $4.9 billion on a
discounted basis, or $5.3 billion on a book value basis, over 8 1/2 years
beginning in 1999.
In January 1998, the Company and numerous other parties filed petitions
for review of the PUC Restructuring Order in the Commonwealth Court of
Pennsylvania and the Company filed a complaint in the U.S. District Court for
the Eastern District of Pennsylvania seeking injunctive relief. On April 29,
1998, the Company and all but one of the 25 parties who had challenged the
Company's restructuring plan filed a joint petition and settlement (Settlement)
with the PUC. In May 1998, the PUC entered an Opinion and Order (Final
Restructuring Order) approving the Settlement. The intervenor who had not
joined the Settlement appealed the Final Restructuring Order to the
Commonwealth Court. After full briefing and oral argument, the Commonwealth
Court dismissed the appeal thus affirming the Final Restructuring Order. The
intervenor filed a petition for allowance of appeal with the Pennsylvania
Supreme Court which was denied. The intervenor subsequently filed a petition
for writ of certiorari with the United States Supreme Court, which was also
denied. Once this petition
2
for writ of certiorari was denied, the Company and all other parties withdrew
their pending appeals at the Commonwealth Court and the Eastern District of
Pennsylvania. All appeals of the Final Restructuring Order have
either been finally resolved by a court or withdrawn by the parties.
The Settlement authorizes the Company to recover $5.26 billion of stranded
costs, together with a return of 10.75% thereon. For good cause shown, the PUC
authorized the recovery of stranded costs over a 12 year transition period
beginning January 1, 1999 and ending December 31, 2010. Stranded costs and the
allowed return thereon are recovered through CTCs and, at the Company's election
to issue or cause the issuance of transition bonds, ITCs, designed to recover
the $5.26 billion of stranded costs. The CTCs have been established assuming
annual growth in sales of 0.8% and will be reconciled annually to actual sales.
The following table shows the estimated average levels of CTCs and/or ITCs
for the years 1999 through 2010, based on estimated 0.8% annual sales growth
assumed in the Settlement.
TABLE 1
Annual Stranded Cost
Amortization And Return
Revenue Excluding
Annual CTC Gross Receipts Tax
Year Sales and/or ITC(2) Total Return @ 10.75% Amortization
- - ------- ------------ --------------- ----------- ----------------- -------------
MWh(1) $/kWh ($000) ($000) ($000)
1999 33,569,358 $ 0.0172 $551,988 $566,134 $ (14,146)
2000 33,837,913 0.0192 621,102 564,222 56,879
2001 34,108,616 0.0251 818,457 547,777 270,680
2002 34,381,485 0.0251 825,004 516,869 308,135
2003 34,656,537 0.0247 818,352 482,401 335,951
2004 34,933,789 0.0243 811,540 444,798 366,742
2005 35,213,260 0.0240 807,933 403,555 404,378
2006 35,494,966 0.0266 902,623 353,070 549,553
2007 35,778,925 0.0266 909,844 290,627 619,217
2008 36,065,157 0.0266 917,123 220,312 696,811
2009 36,353,678 0.0266 924,459 141,229 783,231
2010 36,644,507 0.0266 931,855 52,381 879,474
- - ------------
(1) Subject to reconciliation of actual sales and collections.
(2) Both the CTCs and the ITCs are subject to adjustment.
The Settlement required the Company to unbundle its retail electric rates
on January 1, 1999 into the following components: (i) distribution and
transmission charges, (ii) CTCs and, if applicable, ITCs and (iii) a capacity
and energy charge for generation, which is the maximum amount the Company, as
the provider of last resort (PLR), can charge customers who do not or cannot
choose to purchase electricity from alternate EGS.
The Settlement requires the Company to reduce rates during 1999 and 2000
by 8% and 6%, respectively, from rates in existence on December 31, 1996. The
Settlement also extends the rate caps on generation rates at higher levels than
required by the Competition Act, until December 1, 2010 and extends rate caps
on transmission and distribution rates until June 30, 2005. The Company's
unbundled rates, rate reductions and rate caps are reflected in the schedule of
system-wide average rates included in the Settlement and shown in Table 2
below.
3
TABLE 2
Schedule of System-Wide Average Rates (dollars per kilowatthour (kWh))(1)
T&D CTC Shopping Generation
Effective Date Transmission(2) Distribution Rate Cap and/or ITC(3) Credit Rate Cap
- - ----------------- ----------------- ----------------- ----------------- --------------- ------------ --------------
(1) (2) (3)=(1) + (2) (4) (5) (6)=(4) + (5)
January 1, 1999 $ 0.0045 $ 0.0253 $ 0.0298 $ 0.0172 $ 0.0446 $ 0.0618
January 1, 2000 0.0045 0.0253 0.0298 0.0192 0.0446 0.0638
January 1, 2001 0.0045 0.0253 0.0298 0.0251 0.0447 0.0698
January 1, 2002 0.0045 0.0253 0.0298 0.0251 0.0447 0.0698
January 1, 2003 0.0045 0.0253 0.0298 0.0247 0.0451 0.0698
January 1, 2004 0.0045 0.0253 0.0298 0.0243 0.0455 0.0698
January 1, 2005 0.0045 (4) 0.0253 (4) 0.0298 (4) 0.0240 0.0458 0.0698
January 1, 2006 N/A N/A N/A 0.0266 0.0485 0.0751
January 1, 2007 N/A N/A N/A 0.0266 0.0535 0.0801
January 1, 2008 N/A N/A N/A 0.0266 0.0535 0.0801
January 1, 2009 N/A N/A N/A 0.0266 0.0535 0.0801
January 1, 2010 N/A N/A N/A 0.0266 0.0535 0.0801
- - ------------
(1) All charges reflect average retail billing for all rate classes (including
gross receipts tax).
(2) The transmission charge listed is for unbundled rates only. The PUC does
not regulate the rates for transmission service.
(3) Both the CTCs and the ITCs are subject to adjustment.
(4) Effective until June 30, 2005.
Under the Settlement, customer choice of EGSs is being phased in between
January 1, 1999 and January 2, 2000 with one-third of each rate class entitled
to choose their EGS by January 1, 1999, an additional one-third by January 2,
1999 and the remaining one-third by January 1, 2000. If on January 1, 2001 and
January 1, 2003 less than 35% and 50%, respectively, of all of the Company's
residential and commercial customers by rate class are obtaining generation
service from alternate EGSs, non-shopping customers will be randomly assigned to
EGSs, including those affiliated with the Company, to meet those thresholds.
Assignment of non-shopping customers will be through a PUC-approved process.
Customers assigned to a PLR, other than the Company will be counted as customers
receiving service from an alternate EGS.
Under the Settlement, the Company may securitize up to $4 billion of its
$5.26 billion of stranded cost recovery through the issuance of transition
bonds. The ITCs associated with the issuance of transition bonds must terminate
no later than December 31, 2010. The rate reductions and rate caps described in
Table 2 included as part of the Settlement anticipate the benefits of the
securitization, and no adjustment in the Company base rates will be made upon
issuance of any transition bonds. After January 1, 1999, CTCs (or the Company's
distribution rates) will be reduced by the amount of ITCs. For additional
information see "Capital Requirements and Financing Activities."
On January 1, 1999, the Company unbundled its retail electric rates for
metering, meter reading, and billing and collection services to provide credits
for those customers that have elected to have alternate suppliers perform these
services. Effective January 1, 1999, PUC-licensed entities, including EGSs, may
act as agents to provide a single bill and provide associated billing and
collection services to retail customers located in the Company's retail electric
service territory. In such event, the EGS or other third party would replace the
customer as the obligor with respect to the customer's bill and the Company will
generally have no right to collect such receivable from the customer. To the
extent that customers choose consolidated billing by an EGS or other third
party, the Company will be relying on a small number of EGSs and other third
parties rather than a large number of customers for the collection of billings,
including ITCs. The PUC-licensed entities, including EGSs, may also finance,
install, own, maintain, calibrate and remotely read advanced meters for service
to retail customers located in the Company's retail electric service territory.
An EGS or other third party that bills on behalf of the Company must comply with
all applicable billing and disclosure requirements absent waiver by the PUC,
including the unbundling of transmission and distribution rates. Only the
Company can physically disconnect or reconnect a customer's distribution
service. Physical termination of the service may only be permitted for failure
to pay transmission and distribution service or PLR service.
4
Under the Restructuring Plan, the Company will act as a PLR for all retail
electric customers in its retail electric service territory who do not choose or
cannot choose to purchase power from an alternative EGS through December 31,
2010, subject to certain terms, conditions and qualifications. In February 1999,
certain utilities, customer advocates and EGSs convened to develop proposed
regulations on Competitive Default Service. On February 26, 1999, the chairman
of the group forwarded a suggested procedure for choosing a Competitive Default
Supplier to the PUC. Under those suggested procedures, entities that desire to
act as a Competitive Default Supplier have until April 1, 2000 to submit both
their qualifications to act as a Competitive Default Supplier and their bid for
providing such service. Competitive Default Service will begin on January 1,
2001 for 20% of the Company's residential customers. The suggested procedures
would require an EGS to provide, among other things, proof that it has received
the requisite licenses from the state and federal governments, proof that it
meets certain creditworthiness standards and assurances that it can acquire
additional bonding as necessary. The supplier of Competitive Default Service
will be required to provide billing, including its payment of ITCs and other
revenues, to the Company on the terms and conditions set forth in the Company
tariff for those entities who currently provide competitive billing services to
customers.
The suggested procedures will not become final until the PUC adopts them.
The PUC may choose to reject or modify the suggested procedures. The PUC has no
time deadline for rendering its decision on this issue. The PUC may allow a
public comment period before reaching a final resolution of these issues.
The Settlement also provides for flexible generation service pricing for
customers served by Competitive Default Service, authorization of the Company to
transfer its generation assets to a separate subsidiary, inclusion of a
sustainable energy and economic development fund (funded at a rate of .01 cents
per kilowatthour on all power sold, to be included in the capped transmision
and distribution rates) and expansion and modification of the Company's program
for low-income customers.
Electric -- Wholesale
During 1996, the FERC issued Order No. 888 which requires all public
utilities that own, control or operate interstate transmission facilities 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 stated goal in promulgating Order No. 888 and related orders
is to remove impediments to competition in the wholesale bulk power market
place and to bring more efficient, lower cost power to electricity consumers.
In response to Order No. 888, on July 3, 1996, the Company filed an
individual compliance tariff with the FERC which became effective July 9, 1996.
In December 1996, the Company and the other members of the PJM Interconnection
LLC (PJM) filed a joint compliance filing with the FERC. The PJM is a power pool
which integrates, through central dispatch, the generation and transmission
operations of its member companies across a 50,000 square-mile territory in the
Mid-Atlantic region. That filing included a PJM regional transmission tariff.
Under the PJM tariff, which became effective on March 1, 1997, transmission
service is provided on a pool-wide, open-access basis using the transmission
facilities of the PJM members at rates based on the costs of the transmission
system at the point of delivery.
On March 31, 1997, the members of the PJM converted that organization from
an unincorporated association into a limited liability company and filed with
the FERC a revised PJM operating agreement to reflect that change.
In November 1997, the FERC issued an order authorizing the establishment of
an independent system operator (ISO) for the PJM on January 1, 1998 and
designated the PJM's Office of the Interconnection as the ISO. The ISO is
responsible for operation of the PJM control area and administration of the PJM
open-access transmission tariff and the hourly energy market in the PJM known as
the PJM Power Exchange (PJM PX). In that same order, the FERC directed the
Company and the other transmission owners in the PJM to turn over control of
their transmission facilities to the ISO and put in place a new PJM regional
transmission tariff and energy market arrangement. Although the Company cannot
predict the long-term economic effect of the restructured pooling arrangements
approved by the FERC, the arrangements could adversely affect the Company's
ability to fully recover its transmission costs.
5
On March 10, 1999, the FERC issued an order granting a pending application
by other PJM utilities for market-based rate authority for sales of energy and
certain ancillary services into the PJM PX. Although the Company has not been a
party to that application, the FERC expressly granted the Company market-based
rate authority for sales of energy and ancillary services into the PJM PX.
Previously, the FERC restricted generators located within PJM, including the
Company, to cost-based bids. The recent order expands the Company's existing
ability to engage in wholesale trading of power and certain associated
ancillary services at market-based rates to include trading with the PJM PX.
The FERC also granted anyone else with market-based rate authority the same
right.
On March 10, 1999, the FERC also entered an order establishing a Market
Monitoring Plan (MMP) for the PJM control area. The MMP will be administered by
a newly created Market Monitoring Unit (MMU) under the PJM and authorizes the
MMU to monitor and report on market activity and alleged exercises of market
power by market participants. The FERC order directs additional modifications to
the proposed MMP that will increase the level of coordination of the MMU with
various governmental authorities. It is unclear what impact either the MMP or
the MMU ultimately will have on power trading within the PJM PX in particular
and on wholesale bilateral transactions generally.
On September 21, 1998, the PUC entered an Order directing holders of
installed capacity resources in PJM (including the Company) to immediately
release or offer capacity for sale in the wholesale markets during 1999 at a
presumptive price of $19.72 per kilowattyear, a price below the current
competitive wholesale market prices at that time. On October 21, 1998, the
Company filed a Petition for Review of the PUC Order in Commonwealth Court
seeking a declaration that the PUC's Order is preempted because it attempts to
regulate matters within the exclusive federal jurisdiction of the FERC. On
October 28, 1998, the Company entered into a settlement with the PUC under
which the Company agreed to make certain of its wholesale capacity available to
new market entrants serving retail load within the Company's service territory
at specified prices during 1999. On October 30, 1998, the PUC approved the
settlement.
Gas
The Company's gas sales and gas transportation revenues are derived
pursuant to rates regulated by the PUC. The PUC has established through
regulatory proceedings the base rates that the Company may charge for gas
service in Pennsylvania. The Company's gas rates are subject to a purchased gas
cost (PGC) adjustment clause and a State Tax Adjustment Surcharge (STAS). The
PGC is designed to recover or refund the difference between the actual cost of
purchased gas and the amount included in base rates. The PGC is adjusted
quarterly. The STAS is designed to recover or refund increases or decreases in
certain state taxes not recovered in base rates.
On November 4, 1998, the PUC issued an order approving the Company's PGC
No. 15 rates for the period December 1, 1998 to November 30, 1999, which
reflects a $0.0068 per thousand cubic feet (mcf) increase in natural gas sales
rates. PGC No. 15 became effective December 1, 1998.
The gas industry is continuing to undergo structural changes in response
to FERC policies designed to increase competition. FERC policies have required
interstate gas pipelines to unbundle their gas sales service from other
regulated tariff services, such as transportation and storage. In anticipation
of these changes, the Company modified its gas purchasing arrangements to
enable the purchase and transportation of gas at lower costs. The Company,
through Exelon Energy, is participating in pilot programs outside the Company's
gas service territory to market natural gas and other services to retail
customers.
Legislation has been introduced in the Pennsylvania legislature to
deregulate the gas industry. The effort to deregulate the gas industry has the
support of the Governor of Pennsylvania. The Company cannot predict whether the
Pennsylvania legislature will enact legislation that deregulates the gas
industry or whether the Governor of Pennsylvania will ultimately sign into law
any such legislation. The Company cannot predict the ultimate effect of gas
industry deregulation on its future financial condition and results of
operations.
Competition
The Company competes in both the retail electric generation market in
Pennsylvania and other states and the wholesale electric generation market
nationally.
6
Retail competition for electric generation supply in Pennsylvania commenced
in January 1999, with two-thirds of the Company's electric utility consumers
having the right to choose their supplier. The Company is actively competing for
a share of the generation supply market in its traditional service territory
through PECO Energy Distribution (PED) and throughout Pennsylvania through
Exelon Energy, the Company's new competitive supplier. Generation services
provided by PED are at the energy and capacity charge mandated by the Final
Restructuring Order. Generation services offered by Exelon Energy are at
competitive market prices. Customers who choose to take generation service from
PED may choose an alternate generation supplier at any time. As of January 12,
1999, approximately 12% of the Company's residential and small commercial
customers and approximately 50% of its large commercial and industrial customers
had selected an alternate EGS. As of that date, Exelon Energy was providing
generation service to approximately 135,000 commercial, industrial and
residential customers throughout Pennsylvania.
The Company actively competes in the developing wholesale markets for
electricity. The Company's wholesale marketing activities include the sale of
energy from the Company's installed capacity, the purchase of energy to meet
the Company's retail requirements, the resale of energy purchased from
unaffiliated utilities and others and the marketing of energy of other
generators. The Company enters into both long-term and short-term commitments
to buy and sell power. Currently, the Company's long-term commitments, together
with the energy the Company expects to market from the Company's installed
capacity, make the Company a net power seller. The Company competes in the
wholesale market for electricity on the bases of price, dependability of
service and execution of transactions.
For additional information regarding competition, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
the Company's Annual Report to Shareholders for the year 1998.
Electric Operations
General
During 1998, 92% of the Company's operating revenues and 94% 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
1998 by class of customer are set forth below:
Operating
Sales Revenues
(millions of kWh) (millions of $)
------------------- ----------------
Residential ............................. 10,623 $1,377
Small commercial and industrial ......... 6,888 784
Large commercial and industrial ......... 15,678 1,067
Other ................................... 803 150
Change in unbilled ...................... 131 1
------ ------
Service territory .................... 34,123 3,379
Interchange sales ....................... 3,483 211
Sales to other utilities ................ 37,258 1,221
------ ------
Total ................................ 74,864 $4,811
====== ======
The Company is engaged in the wholesale marketing of electricity on a
national basis. The Company's wholesale marketing activities include the sale
of energy from the Company's installed capacity, the purchase of energy to meet
the Company's retail requirements, the resale of energy purchased from
unaffiliated utilities and others and the marketing of energy of other
generators. During 1998, the Company purchased 45.1% of its total kilowatthours
sold and estimates that for 1999 it will purchase 46.9% of its total
kilowatthours sold.
At December 31, 1998, the Company had long-term commitments to purchase
from unaffiliated utilities and others energy associated with 632 MW of
capacity in 1999, energy associated with 2,054 MW of capacity during the period
2000 through 2002 and energy associated with 2,431 MW of capacity thereafter.
Under some of
7
these contracts, the Company may purchase, at its option, additional power as
needed. These purchases will be utilized through a combination of retail sales
to customers, sales to other utilities and EGSs and open-market sales. At
December 31, 1998, the Company had entered into long-term agreements with
unaffiliated utilities to sell energy associated with 5,094 MW of capacity, of
which 1,030 MW of these agreements are for 1999, 2,202 MW are for 2000 through
2002 and the remaining 1,862 MW extend through 2009. See Note 5 of Notes to
Consolidated Financial Statements included in the Company's Annual Report to
Shareholders for the year 1998.
The net installed electric generating capacity (summer rating) of the
Company and its subsidiaries at December 31, 1998 was as follows:
Type of Capacity MW % of Total
---------------- ----- ----------
Nuclear .................................. 4,119 44.4%
Mine-mouth, coal-fired ................... 709 7.7
Service-area, coal-fired ................. 725 7.8
Oil-fired ................................ 1,176 12.7
Gas-fired ................................ 267 2.9
Hydro (includes pumped storage) .......... 1,422 15.4
Internal combustion ...................... 844 9.1
----- -----
Total .................................... 9,262(1) 100.0%
===== =====
- - ------------
(1) See "Fuel" for sources of fuels used in electric generation.
The all-time maximum hourly demand on the Company's system was 7,390 MW
which occurred on July 15, 1997. The all-time maximum PJM demand of 49,406 MW
occurred on July 15, 1997. PJM's installed capacity (summer rating) is more
than 56,000 MW. The Company's installed capacity is expected to be sufficient
to meet its obligation to supply its PJM reserve margin share during the period
1998-2001. See "Deregulation and Rate Matters."
The Company's nuclear-generated electricity is supplied by Limerick
Generating Station (Limerick) Units No. 1 and No. 2, Peach Bottom Atomic Power
Station (Peach Bottom) Units No. 2 and No. 3, which are operated by the
Company, and 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 have a capacity of 1,134 MW and 1,115 MW respectively; 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 44.4%
of its installed generating capacity. In 1998, approximately 39.4% of the
Company's electric output was generated from the Company's nuclear generating
facilities. 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 $9.7 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 $9.5 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 $88
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, the U.S. 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 $9.7 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.
Property insurance in the amount of $2.75 billion is maintained for each
nuclear power plant in which the Company has an ownership interest. The Company
is responsible for its proportionate share of such insurance
8
based on its ownership interest. 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 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
$30 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 $10 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. Based on estimates of
decommissioning costs for each of the nuclear facilities in which the Company
has an ownership interest, the PUC 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. Through
1998, the Company's current estimate of its nuclear facilities' decommissioning
cost is $1.5 billion in 1997 dollars which was being collected through electric
rates over the life of each generating unit. Beginning in 1999, decommissioning
costs are recoverable through regulated rates. At December 31, 1998, the
Company held $378 million in trust accounts, representing amounts recovered
from customers and net realized and unrealized investment earnings thereon, to
fund future decommissioning costs.
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 has expanded the scope of the Exposure Draft to include closure or removal
liabilities that are incurred at any time during the operating life of the
related long-lived asset. The FASB is proceeding towards a revised Exposure
Draft, currently expected in the second quarter of 1999. If current electric
utility industry accounting practices for decommissioning are changed, annual
provisions for decommissioning costs could increase and the estimated cost for
decommissioning could be recorded as a liability rather than as accumulated
depreciation, and the increased cost would be recognized as a regulatory asset
to the extent recoverable through regulated rates. For additional information
concerning nuclear decommissioning, see Note 5 of Notes to Consolidated
Financial Statements included in the Company's Annual Report to Shareholders
for the year 1998.
In 1996, the NRC requested that all nuclear plant operators inform the NRC
whether their nuclear units are operated and maintained within the design bases
of the facilities and confirm that any deviations have been or will be
reconciled in a timely manner. The Company responded to the NRC's request on
February 4, 1997 with a detailed description of ongoing activities and new
initiatives to ensure that Limerick and Peach Bottom are operated and
maintained within their design bases. PSE&G provided a similar response to the
NRC on February 11, 1997 concerning Salem. Since the information that was
submitted will be used by the NRC to determine follow-up inspection activity or
potential enforcement actions, the Company cannot predict what impact the NRC's
request will have.
9
On September 16, 1998, the NRC suspended its Systematic Assessment of
License Performance (SALP) program for an interim period until the NRC staff
completes a review of its nuclear power plant performance assessment process.
During the interim period while the SALP program is suspended, the NRC will
utilize the results of its plant performance reviews to provide nuclear power
plant performance information to licensees, state and local officials and the
public. These reviews are intended to identify performance trends since the
previous assessment and make any appropriate changes to the NRC's inspection
plans. At the end of the process, the NRC will decide whether to resume the
SALP program or substitute an alternative program.
Limerick Generating Station
Limerick Unit No. 1 achieved a capacity factor of 77% in 1998 and 85% in
1997. Limerick Unit No. 2 achieved a capacity factor of 95% in 1998 and 85% in
1997. 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 the spring of 1998
and 1997, respectively.
On May 9, 1997, the NRC issued its periodic SALP report for Limerick for
the period April 2, 1995 to March 29, 1997. Limerick achieved ratings of "1,"
the highest of three rating categories, in the areas of Operations, Maintenance
and Plant Support. In the area of Engineering, Limerick achieved a rating of
"2." The NRC stated that the overall performance of Limerick remained
excellent. Strong management involvement and conservative decision making were
exhibited in day-to-day activities. Self-assessment and quality assurance
activities continued to be effective. The performance enhancement process
continued to be an effective program for identifying, evaluating and correcting
issues with appropriate thresholds and priorities. Oversight and independent
review committees contributed to the corrective actions program effectiveness.
While noting strengths in design, analysis and modifications, the NRC stated
that earlier engineering intervention could have prevented equipment problems
that resulted in a number of plant trips and forced shutdowns. The NRC also
noted that management has recognized this performance weakness and has
initiated remedial actions.
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 Limerick Unit No. 2 has been scheduled for the refueling outage
planned for April 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 findings to the NRC and
recommended continued operation of Unit No. 3 for a two-year cycle. Unit No. 3
was re-examined during its refueling outage in the fall of 1995 and the extent
of cracking identified was determined to be within industry-established
guidelines. The Company has concluded, and the NRC has concurred, that there is
a substantial margin for each core shroud weld to allow for continued operation
of Unit No. 3. 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 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, including the
installation of large capacity passive strainers, with a request that actions
be completed by the end of the unit's first refueling outage after January
1997. Strainers were installed at Peach Bottom Unit No. 3 during the October
1997 refueling outage. Strainers were
10
installed at Peach Bottom Unit No. 2 and Limerick Unit No. 1 during their
refueling outages in October 1998 and April 1998, respectively. For Limerick
Unit No. 2, the NRC granted the Company's request to defer the installation of
strainers until its scheduled refueling outage in April 1999. 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 at certain nuclear facilities, including
Limerick and Peach Bottom, may not provide the necessary level of fire
protection and has requested licensees to describe short-term 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 met with the NRC during 1997 regarding the
Company's plans for the resolution of the Thermo-Lag issue. In August 1997, the
NRC informed the Company that it was satisfied with the progress to date on
this issue. On May 19, 1998, the NRC issued a confirmatory order modifying the
license for Peach Bottom Units No. 2 and No. 3 requiring that the Company
complete final implementation of corrective actions on the Thermo-Lag 330 issue
by completion of the October 1999 refueling outage of Peach Bottom Unit No. 3.
In addition, the NRC issued a confirmatory order modifying the license for
Limerick Units No. 1 and No. 2 requiring that the Company complete final
implementation of corrective actions on the Thermo-Lag 330 issue by completion
of the April 1999 refueling outage of Limerick Unit No. 2. The Company
continues to work towards completion of activities to resolve this issue by the
previously committed dates of April 1999 for Limerick and October 1999 for
Peach Bottom.
Water for the operation of Limerick is drawn from the Schuylkill River
adjacent to Limerick and from the Perkiomen Creek, a tributary of the
Schuylkill River. During certain periods of the year, generally the summer
months but possibly for as much as six months or more in some years, the
Company would not be able to operate Limerick without the use of 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. Certain of the permits relating to the
operation of the supplemental cooling water system must be renewed
periodically.
The Company has 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.
11
Peach Bottom Atomic Power Station
Peach Bottom Unit No. 2 achieved a capacity factor of 80% in 1998 and 100%
in 1997. Peach Bottom Unit No. 3 achieved a capacity factor of 92% in 1998 and
79% in 1997. 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
the fall of 1998 and 1997, respectively.
On July 17, 1997, the NRC issued its periodic SALP report for Peach Bottom
for the period October 15, 1995 to June 7, 1997. Peach Bottom achieved a rating
of "1," in the areas of Plant Operations, Maintenance and Plant Support. In the
area of Engineering, Peach Bottom achieved a rating of "2." Overall, the NRC
observed excellent performance at Peach Bottom during the assessment period.
The NRC stated that station management provided excellent oversight and control
of engineering activities throughout the period. The NRC noted that, while
overall engineering performance was good, there were several instances where
operating procedures, surveillances, and tests were not consistent with the
design and licensing bases.
The Company, Delmarva Power & Light Company (Delmarva) and PSE&G have
agreed to an operating performance standard through December 31, 2007 for Peach
Bottom and through December 31, 2011 for Salem. Under the standard, the operator
of each respective station would be required to make payments to the
non-operating owners if the three-year capacity factor, determined annually, of
such station falls below 40 percent, subject to a maximum of $25 million per
year. The initial three-year period began on January 1, 1998 and April 17, 1998
for Peach Bottom and Salem, respectively. The parties have also agreed to forego
litigation in the future, except for limited cases in which the operator would
be responsible for damages of no more than $5 million per year.
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
As previously reported, Salem Units No. 1 and No. 2 were taken out of
service by PSE&G in the second quarter of 1995. Salem Unit No. 2 returned to
service on August 30, 1997. Salem Unit No. 1 returned to service on April 17,
1998. In July 1998, the NRC removed Salem Units No. 1 and No. 2 from the NRC
Watch List. The Company has been informed by PSE&G that the NRC noted that plant
material condition, safety culture and management oversight and effectiveness
had substantially improved. The NRC also observed that, while the maintenance
backlog resulting from discovery efforts during the outage remains high, PSE&G
is effectively managing the prioritization and resolution of those items.
Additionally, the NRC noted that PSE&G's management team has instituted robust
safety oversight and self-assessment at the site and that Salem has demonstrated
sustained successful plant performance.
The Company has been informed by PSE&G that on September 15, 1998, the NRC
issued its latest SALP for Salem for the period March 1, 1997 to August 1, 1998.
In the areas of Maintenance and Engineering, Salem achieved a rating of "2". In
the areas of Operations and Plant Support, Salem achieved a rating of "1". The
NRC noted improved performance overall during the period, as demonstrated by the
nearly event-free return of both units to operation following the extended
outage. The NRC identified strong management oversight, safe and conservative
operations, good engineering support and effective programs for independent
oversight and self-assessment. The NRC also noted that although human
performance has improved significantly due to extensive training interventions,
continued close management attention is warranted in the Operations and
Maintenance areas.
The Company has been informed by PSE&G that predecisional enforcement
conferences were held on December 9, 1997 to discuss two allegations concerning
security program issues which occurred at Salem in 1996. On April 24, 1998, the
NRC issued a severity Level III violation for one of these matters and informed
PSE&G that it would await issuance of the Secretary of Labor's Administrative
Review Board decision before making an enforcement decision in the other
matter. There was no civil penalty issued by the NRC for this violation. PSE&G
did not contest this violation. The Company cannot predict what other actions,
if any, the NRC may take in regard to the second matter.
12
The Company has been informed by PSE&G that, in April 1997, as part of an
NRC inspection of fire barrier systems to protect equipment necessary for the
safe shutdown of the plant in the event of a fire, the NRC noted certain
weaknesses in Salem's fire barrier systems. PSE&G sent a letter to the NRC in
June 1997 addressing these issues concerning the qualifications of fire wrap
barriers used to protect electrical cabling at Salem. The letter outlined a
resolution plan and schedule to address the fire wrap issues. PSE&G has
committed to alternative measures in the form of fire watches until this plan
is implemented. A review of the installed fire barrier materials and safe
shutdown analysis is currently in progress. If certain modifications are
necessary to comply with NRC requirements, it is expected that the costs will
not be material. However, failure to resolve these fire barrier issues could
result in potential NRC violations, fines and/or plant shutdown which could
have a material adverse impact to the Company's financial condition and results
of operations.
In addition to the matters discussed above, see "Environmental Regulations
- - -- Water." See also "Peach Bottom Atomic Power Station"
Fuel
The following table shows the Company's sources of electric output for
1998 and as estimated for 1999:
1998 1999 (Est.)
------ -----------
Nuclear ................................................ 39.4% 39.1%
Mine-mouth, coal-fired ................................. 7.3 6.1
Service-area, coal-fired ............................... 4.5 4.5
Oil-fired .............................................. 1.8 1.9
Hydro (includes pumped storage) ........................ 1.7 1.3
Internal combustion .................................... 0.2 0.2
Purchased, interchange and nonutility generated ........ 45.1 46.9
----- -----
100.0% 100.0%
===== =====
Nuclear
The cycle of production and utilization of nuclear fuel includes the
mining and milling of uranium ore into uranium concentrates; 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 does not anticipate
difficulty in obtaining the necessary uranium concentrates or conversion,
enrichment or fabrication services for Limerick or Peach Bottom. PSE&G has
informed the Company that it presently has sufficient contracts for uranium and
services related to the nuclear fuel cycle to fully meet its current projected
requirements. The following table summarizes the years through which the
Company has contracts for the segments of the nuclear fuel supply cycle:
Concentrates (1) Conversion (2) Enrichment Fabrication
------------------ ---------------- ------------ ------------
Limerick Unit No. 1 .............. 2002 2001 2004 2003
Limerick Unit No. 2 .............. 2002 2001 2004 2004
Peach Bottom Unit No. 2 .......... 2002 2001 2004 2002
Peach Bottom Unit No. 3 .......... 2002 2001 2004 2003
- - ------------
(1) The Company's contracts for uranium concentrates are allocated to Limerick
and Peach Bottom on an as-needed basis.
(2) The Company also has commitments for at least 60% of the conversion
services requirements for Limerick and Peach Bottom through 2002.
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. Limerick
has on-site facilities with capacity to store spent fuel with full core
discharge until 2007. Peach Bottom has on-site facilities with capacity to
store spent fuel until 2000 for Unit No. 2 and 2001 for Unit No. 3. The Company
has begun construction
13
of a dry spent-fuel storage facility at Peach Bottom to maintain full core
discharge capacity in the spent fuel pools. Construction will continue through
early 2000. The facility, including the first nine storage casks, is expected
to cost approximately $33.5 million. The independent spent fuel storage
facility is expected to provide life of plant storage capacity. The Company
expects to purchase storage casks to maintain spent fuel storage capacity at an
estimated cost of $6 million per year. The Company has been informed by PSE&G
that as a result of reracking the two spent fuel pools at Salem, spent fuel
storage capacity of Salem Units No. 1 and No. 2 is estimated to be 2012 and
2016, respectively. PSE&G is also currently assessing available options which
could satisfy the potential need for additional storage capacity, including the
option of constructing an on-site storage facility that would satisfy the
spent-fuel storage needs of Salem.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is required to
begin taking possession of all spent nuclear fuel generated by the Company's
nuclear units for long-term storage by no later than 1998. Based on recent
public pronouncements, it is not likely that a permanent disposal site will be
available for the industry before 2015, at the earliest. In reaction to
statements from the DOE that it was not legally obligated to begin to accept
spent fuel in 1998, a group of utilities and state government agencies filed a
lawsuit against the DOE which resulted in a decision by the U.S. Court of
Appeals for the District of Columbia (D.C. Court of Appeals) in July 1996 that
the DOE had an unequivocal obligation to begin to accept spent fuel in 1998. In
accordance with the NWPA, the Company pays the DOE one mill ($.001) per
kilowatthour of net nuclear generation for the cost of nuclear fuel long-term
storage and disposal. This fee may be adjusted prospectively in order to ensure
full cost recovery. Because of inaction by the DOE following the D.C. Court of
Appeals finding of the DOE's obligation to begin receiving spent fuel in 1998,
a group of forty-two utility companies, including the Company, and forty-six
state agencies, filed suit against the DOE 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 is 1998 obligations. In November 1997, the D.C. Court of Appeals
issued a decision in which it held that the DOE had not abided by its prior
determination that the DOE has an unconditional obligation to begin disposal of
spent nuclear fuel by January 31, 1998. The D.C. Court of Appeals also
precluded the DOE from asserting that it was not required to begin receiving
spent nuclear fuel because it had not yet prepared a permanent repository or an
interim storage facility. The DOE and one of the utility companies filed
Petitions for Reconsideration of the decision which were denied, as were
petitions seeking U.S. Supreme Court review of the decision. In addition, the
DOE is exploring other options to address delays in the waste acceptance
schedule. In January 1999, legislation was introduced in the U.S. House of
Representatives authorizing the construction of a temporary storage facility
which could accept spent nuclear fuel from utilities prior to operation of a
permanent repository.
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 and Clive, Utah for disposal. On-site storage facilities have
been constructed at Peach Bottom and Limerick, with twenty-five year and
five-year storage capacities, respectively.
The Company is also pursuing alternative disposal strategies for LLRW
generated at Peach Bottom and Limerick, including a LLRW reduction program.
Pennsylvania which had agreed to be the host site for a LLRW disposal facility
for generators located in Pennsylvania, Delaware, Maryland and West Virginia
suspended the search for a permanent disposal site. The Company contributed $12
million towards the total cost of a permanent Pennsylvania disposal site prior
to its suspension.
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. In 1991, New Jersey enacted legislation providing
for funding of the estimated $70 million cost to establish a LLRW disposal
facility. New Jersey would recover the costs through fees paid by LLRW
generators. The Company as a Salem co-owner, has paid $857,000 as its share of
the New Jersey siting costs. New Jersey established a volunteer siting process
to establish a LLRW disposal facility by 2000. Public meetings were held across
the State in an effort to provide information to and obtain feedback from the
public; however, no voluntary sites were identified. Consequently, on February
10, 1998, the New Jersey
14
agency responsible for this program recommended to the Governor of New Jersey
that this volunteer plan be abandoned. The Governor of New Jersey has accepted
the agency's plan to reduce the scope of siting activities since the
development of a disposal facility in New Jersey may not be economically
feasible in light of current out-of-state disposal options. As a result, the
refund of the unspent funds paid by waste generators in New Jersey to finance
the siting process needs to be addressed. The Company expects to partially
recover the funds paid in connection with this effort.
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 $47
million for such costs at December 31, 1998. The Company is currently
recovering these costs through regulated rates.
The Company is currently recovering in rates the costs for nuclear
decommissioning and decontamination 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. 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 between 3.0 and 3.5 million tons for 1999 and a total of 6.5 million
tons of coal purchases for the years 2000 through 2004. Approximately 80% of
Conemaugh's 1999 fuel requirements are 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, 1999, 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. Purchases pursuant to
these contacts represented approximately 3% of the Company's Fuel and Energy
Interchange Expense in 1998.
Oil
The Company purchases fuel oil through a combination of short-term
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 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.
15
Gas Operations
During 1998, 8% of the Company's operating revenues and 6% of its
operating income were from gas operations. Gas sales and operating revenues for
1998 by class of customer are set forth below:
Operating
Sales Revenues
(mmcf) (millions of $)
---------- ----------------
House heating .................................. 28,402 $236
Residential (other than house heating) ......... 1,496 16
Commercial and industrial ...................... 16,757 125
Other .......................................... 554 2
Change in unbilled ............................. (440) (3)
------ ----
Total gas sales ............................... 46,769 376
Gas transported for customers .................. 28,204 24
------ ----
Total gas sales and gas transported ........... 74,973 $400
====== ====
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 87.5 million dekatherms. Peak gas is provided by
the Company's liquefied natural gas facility and propane-air plant. See "ITEM
2. PROPERTIES."
The Company has under contract 21.5 million dekatherms of underground
storage through service agreements with Texas Eastern, Transcontinental,
Equitrans, Inc. and CNG Transmission Corporation. Natural gas from underground
storage represents approximately 40% of the Company's 1998-99 heating season
supplies.
The gas industry is continuing to undergo structural changes in response
to FERC policies designed to increase competition. In addition, there is a
renewed initiative in the Pennsylvania legislature to deregulate the gas
industry, which has the support of the Governor of Pennsylvania. See
"Deregulation and Rate Matters."
Year 2000 Readiness Disclosure
Due to the severity of the potential impact of the Year 2000 (Y2K) issue
on the electric utility industry, the Company has adopted a comprehensive
schedule to achieve Y2K readiness. The Company has dedicated extensive
resources to its Y2K Project (Project).
The Project is addressing the issue resulting from computer programs using
two digits rather than four to define the applicable year and other programming
techniques that constrain date calculations or assign special meanings to
certain dates. Any of the Company's computer systems that have date-sensitive
software or microprocessors may recognize a date using "00" as the year 1900
rather than the year 2000. This could result in a system failure or
miscalculations causing disruptions of operations, including a temporary
inability to process transactions, send bills, operate generating stations, or
engage in similar normal business activities.
The Company is utilizing both internal and external resources to
reprogram, or replace and test software and computer systems for the Project.
The Project is scheduled for completion by July 1, 1999, except for a small
number of modifications, conversions or replacements that are impacted by
vendor dates and/or are being incorporated into scheduled plant outages between
July and October 1999.
On July 17, 1998, an order was entered by the PUC instituting a formal
investigation by the Office of Administrative Law on Year 2000 compliance by
jurisdictional fixed utilities and mission-critical service providers such as
the PJM. The order requires, (1) a written response to a list of compliance
program questions by
16
August 6, 1998 and, (2) all jurisdictional fixed utilities be Year 2000
compliant by March 31, 1999 or, if a utility determines that mission-critical
systems cannot be Year 2000 compliant on or before March 31, 1999, the utility
is required to file a detailed contingency plan. The PUC adopted the federal
government's definition for Year 2000 compliance and further defined Year 2000
compliance as a jurisdictional utility having all mission-critical Year 2000
hardware and software updates and/or replacements installed and tested on or
before March 31, 1999. On August 6, 1998, the Company filed its written
response, in which the Company stated that with a few carefully-assessed and
closely-managed exceptions, the Company will have all mission-critical systems
Year 2000 ready by June 1999. Pursuant to the formal investigation on Year 2000
compliance, the Company presented testimony before the PUC on November 20, 1998
On February 19, 1999, the PUC issued a Secretarial Letter notifying the
Company that it had hired a consultant to perform an assessment of the Company
and thirteen other utilities to evaluate the accuracy of their responses to the
compliance program questions and testimony provided before the PUC. The Company
complied with the PUC's directive in the Secretarial Letter to file updated
written responses to compliance questions by March 8, 1999, and to meet with
the consultant during a one-day on-site review session on March 8, 1999.
On May 11, 1998, the NRC issued a generic letter requiring all nuclear
plant operators to provide the NRC with information concerning the operators'
programs, planned or implemented, to address Year 2000 computer and system
issues at its facilities, (1) submission of a written response within 90 days,
indicating whether the operator has pursued and continues to pursue
implementation of Year 2000 programs and addressing the program's scope,
assessment process, plans for corrective actions, quality assurance measures,
contingency plans and regulatory compliance, and (2) submission of a written
response, no later than July 1, 1999, confirming that such facilities are Year
2000 ready, or will be Year 2000 ready, by the year 2000 with regard to
compliance with the terms and conditions of the license(s) and NRC regulations.
On July 30, 1998, the Company filed its 90-day required written response
indicating that the Company has pursued and is continuing to pursue a Year 2000
program which is similar to that outlined in Nuclear Utility Year 2000
Readiness, NEI/NUSMG 97.07.
From November 3 to November 5, 1998, members of the NRC staff conducted an
audit of the Company's Year 2000 Program for the Limerick Generating Station,
Units No. 1 and No. 2. Some of the observations of the audit team included in
their written report issued on December 18, 1998, were that (1) the Company's
readiness program is comprehensive and based on the guidance contained in
NEI/NUSMG 97.07, (2) the program is receiving proper management support and
oversight, and (3) project schedules are being aggressively pursued.
For additional information regarding the Year 2000 Readiness Disclosure
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the Company's Annual Report to Shareholders for the year 1998.
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 1998.
Capital Requirements and Financing Activities
The following table shows the Company's most recent estimate of capital
requirements for 1999:
(Millions of $)
----------------
Construction .......................................... $440
New ventures (1) ...................................... 129
Long-term debt maturities and sinking funds. .......... 362
----
Total capital requirements. ....................... $931
====
- - ------------
(1) A portion of these expenditures will be expensed.
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
17
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. The
coverage under the earnings test of the Mortgage for the twelve months ended
December 31, 1998 was 5.47 times. As a result of the extraordinary charge in
December 1997, the Company did not meet the earnings test under the Mortgage
required for the issuance of additional bonds against property additions for
the twelve months ended December 31, 1997. Earnings coverage under the Mortgage
for the twelve months ended December 31, 1996 was 4.39 times. At December 31,
1998, the Company had at least $2.26 billion of available property additions
against which $1.36 billion of mortgage bonds could have been issued. In
addition at December 31, 1998, the Company was entitled to issue approximately
$4.4 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 twelve months ended December 31, 1998 was 2.81 times. As a
result of the extraordinary charge in December 1997, the Company did not meet
the earnings test of the Articles for the twelve months ended December 31,
1997. Earnings coverage under the Articles for the twelve months ended December
31, 1996 was 2.50 times.
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:
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Ratio of Earnings to Fixed Charges .......... 3.61 2.71 3.29 3.41 2.66
Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends .............. 3.45 2.50 3.04 3.12 2.32
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. For purposes of calculating these ratios, income from
continuing operations for 1998 does not include the extraordinary charge
against income of $33 million ($20 million net of income taxes) and for 1997
does not include the extraordinary charge against income of $3.1 billion ($1.8
billion net of income taxes).
The Company has a $900 million unsecured revolving credit facility with a
group of banks. The credit facility is composed of a $450 million 364-day
credit agreement and a $450 million three-year credit agreement. The Company
uses the credit facility principally to support the Company's commercial paper
program.
At December 31, 1998, the Company had a total of $400 million outstanding
under an unsecured term-loan agreement with banks maturing in 1999. Most of the
Company's unsecured debt agreements contain cross-default provisions to the
Company's other debt obligations.
The Company has a $600 million commercial paper program. At December 31,
1998, there was $125 million of commercial paper outstanding. At December 31,
1998, the Company and its subsidiaries had available formal and informal lines
of credit with banks aggregating $100 million. As of December 31, 1998, the
Company had no compensating balance agreements with any bank.
On March 25, 1999, PECO Energy Transition Trust (PETT), an independent
statutory business trust organized under the laws of Delaware and a wholly owned
subsidiary of the Company, issued $4 billion aggregate principal amount of PECO
Energy Transition Trust Transition Bonds to securitize a portion of the
Company's authorized stranded costs recovery. The Transition Bonds are solely
obligations of PETT, secured by Intangible Transition Property (ITP),
representing the right to collect ITC, sold by the Company to PETT concurrently
with the issuance of the Transition Bonds. The ITC will be allocated from CTC
and variable distribution charges (both of which are usage-based charges). ITCs
will be allocated first from CTCs, then, to the extent ITCs exceed such amounts,
from variable distribution charges. The ITCs collected by PETT, which will be
used to pay debt service on the Transition Bonds and related expenses, will
reduce the Company's collection of CTCs on a dollar-for-dollar basis.
18
The Transition Bonds were sold by PETT in seven separate classes with
average maturities ranging from 1.3 to 8.9 years. Two of the classes bear
interest at floating rates; the remaining five classes bear interest at fixed
rates with coupons ranging from 5.4% to 6.13%. The Company had entered into
treasury forwards and forward starting interest rate swaps to manage interest
rate exposure associated with the anticipated issuance of Transition Bonds. On
March 18, 1999, these instruments were settled with net proceeds to the Company
of approximately $80 million which will be deferred and amortized over the life
of the Transition Bonds, consistent with the Company's hedge accounting policy.
The net proceeds to the Company from the securitization of a portion of
its allowed stranded cost recovery, after payment of fees and expenses and the
capitalization of PETT, was approximately $3.9 billion. In accordance with the
provisions of the Competition Act, the Company is utilizing these proceeds
principally to reduce its stranded costs and related capitalization. The
Company plans to apply the proceeds to reduce capitalization as follows: $1.2
billion to retire fixed-rate debt, $.7 billion to reduce floating-rate debt and
commercial paper, $.3 billion to redeem preferred securities and $1.7 billion
to repurchase common stock. On March 26, 1999, the Company called for
redemption three series of its First Mortgage Bonds, 7.75% Series due 2023,
7.25% Series due 2024 and 7.125% Series due on 2023. On March 26, 1999, the
Company repaid $400 million of borrowings under a term credit facility. The
Company plans to call for redemption in May 1999 First Mortgage Bonds, 7.75%
Series 2 due 2023. The Company also plans to call for redemption in August 1999
the Company's Obligated Mandatorily Redeemable Preferred Securities, 9% Series
due 2043.
On March 26, 1999, the Company physically settled forward purchase
agreements relating to the Company's Common Stock resulting in the purchase by
the Company of 21.5 million shares of Common Stock for an aggregate purchase
price of $696 million. The Company currently anticipates that it will complete
its repurchase of Common Stock equity through open market purchases from time
to time in compliance with the Securities and Exchange Commission rules. The
number of shares to be purchased and the timing and manner of purchases are,
however, dependent upon market and other conditions.
Although the Transition Bonds are solely obligations of PETT, the
Transition Bonds will be included in the consolidated capitalization of the
Company and PETT's revenue from the ITC, as well as all interest expense
associated with the Transition Bonds and amortization expense associated with
the ITP will be reflected on the Company's consolidated financial statements.
The Company currently estimates that the impact of additional interest expense
resulting from the issuance of the Transition Bonds combined with the
anticipated reduction of common equity will result in earnings per share
benefits of approximately $0.15 in 1999 and $0.50 in 2000. These estimated
earnings per share benefits could change and are largely dependent upon the
timing and price of the Company's repurchase of Common Stock.
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 1998.
Construction
The following table shows the Company's most recent estimate of capital
expenditures for plant additions and improvements for 1999:
(Millions of $)
----------------
Electric:
Production ............................... $165
Nuclear fuel ............................. 60
Transmission and distribution. ........... 155
----
Total electric ...................... 380
Gas ........................................ 40
Other ...................................... 20
----
Total. ................................... $440
====
19
The Company's current construction program does not include any new
generating facilities. At December 31, 1998, construction work in progress,
excluding nuclear fuel, aggregated $273 million. Nuclear fuel requirements
exclude the Company's share of the requirements for Peach Bottom and Salem
which are provided by an independent fuel company under a capital lease. See
Note 16 of Notes to Consolidated Financial Statements included in the Company's
Annual Report to Shareholders for the year 1998.
Employee Matters
The Company and its subsidiaries had 6,815 employees at December 31, 1998.
None of the employees of the Company or its subsidiaries are represented by a
union. Over the past several years, a number of unions have filed petitions
with the National Labor Relations Board to hold certification elections with
regard to different segments of employees within the Company. In all cases, the
Company employees have rejected union representation. The Company expects that
such petitions will continue to be filed in the future.
As part of the Cost Competitiveness Review (CCR), in April 1998, the Board
of Directors authorized the implementation of a retirement incentive program
and an enhanced severance benefit program to achieve targeted workforce
reductions. See Note 21 of Notes to Consolidated Financial Statements included
in the Company's Annual Report to Shareholders for the Year 1998.
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 electro-magnetic fields (EMF) causes adverse human health effects.
A large number of scientific studies have examined this question and certain
studies have indicated an association between exposure to EMF and adverse
health effects, including certain types of cancer. However, the scientific
community still has not reached a consensus on the issue. Additional research
intended to provide a better understanding of EMF is continuing. The Company
supports further research in this area and is funding and monitoring such
studies.
Public concerns about the possible health risks of exposure to EMF have
adversely affected, 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. The estimated capital cost of compliance with the final permit,
the preparation of a renewal submittal and the activities required to obtain a
renewed permit is approximately $140 million. The project is approximately 90%
complete. Under the 1994 permit, which remains in effect until such time as a
renewal permit is issued, PSE&G is continuing to restore wetlands and to
conduct the requisite management and monitoring associated with the
implementation of the special conditions of that permit. The existing permit
remains in full force and effect indefinitely upon submission of a timely
renewal filing. The Company's share of such costs is 42.59% and is included in
the Company's capital requirements. PSE&G must apply to the New Jersey
Department of Environmental Protection (NJDEP) to renew the Salem permit in
1999. On March 4, 1999, PSE&G filed a comprehensive application for the
renewal of Salem's NJDEP permit. The Company cannot currently predict the
outcome of the review of this application. An unfavorable determination could
have a material adverse effect on the Company's financial condition and results
of operations.
The DRBC issued a revised Docket for Salem in 1995 (Revised Docket)
approving a modification to the 1970 Salem Docket that approved the
construction and operation of the station's cooling water system. The
20
Revised Docket authorized, among other things, the continued operation of
Salem's cooling water system for an additional five years. The Revised Docket
provides that the authorization expires September 27, 2000 absent review of the
Docket on or before August 31, 1999 and renewal by the DRBC. DRBC review of the
matter is planned to commence in the second quarter of 1999.
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 (SO(2)), nitrogen oxides (NO(x)) 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 emissions of SO(2) and
NO(x) from electric power plants. Flue-gas desulfurization systems (scrubbers)
have been installed at Conemaugh Units No. 1 and No. 2 to reduce SO(2) emissions
to meet the Phase I requirements of the Amendments. Keystone Units No. 1 and No.
2 are subject to the Phase II SO(2) and NO(x) 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.
The Company's service-area, coal-fired generating units at Eddystone and
Cromby are equipped with scrubbers and their SO(2) emissions meet the SO(2)
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 NO(x) 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 NO(x) emissions.
On September 24, 1998, the EPA announced the issuance of a final regulation
which will require 22 states and the District of Columbia to reduce emissions of
NO(x) by more than 1 million tons annually beginning in 2003. The main goal of
the regulation is to limit the transport of ozone pollution into the
northeastern states, including Pennsylvania, by reducing NO(x) emissions in
southern and midwestern states. Pennsylvania utilities, including the Company,
are already subject to strict NO(x) emission limits. A group of southern and
midwestern states and utilities have appealed the issuance of the EPA
regulation to the Federal Court of Appeals.
The PDEP has adopted a NO(x) allowance program which could restrict the
operation of the Company's fossil-fired units, require the purchase of NO(x)
emission allowances from others or require the installation of additional
control equipment.
Many other provisions of the Amendments affect the Company's business. The
Amendments establish stringent 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.
21
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 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 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
agreed 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. In December 1997, the EPA finalized its record of
decision (ROD) for the site. In January 1998, the EPA sent letters to
approximately 20 PRPs, including the Company, giving them 60 days to negotiate
with the EPA to perform the proposed remedy. The Company, along with the nine
other PRPs in the utility PRP group, responded to the EPA's letter by offering
to conduct the Remedial Design (RD) but not the Remedial Action (RA) outlined
in the ROD. The EPA rejected the PRP group's offer and, on June 26, 1998,
issued an Order to the non-de minimis PRP Group members, and others, including
the owner, to implement the RD and RA. The PRP Group is proceeding as required
by the Order. It has selected a contractor which has been approved by the EPA
and, on November 5, 1998, submitted the draft RD work plan. Implementation of
the RD will continue through 1999. The Company's share of the cost of the RD
will be approximately 25%.
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/Douglassville site) where waste oils generated from
Company operations were transported, treated, stored and disposed. In August
1991, the EPA filed suit in the 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 have required the Company to pay
approximately $992,000 in exchange for the EPA agreeing not to sue.
Subsequently, the non-de minimis
22
parties successfully challenged the Record of Decision (ROD) remedy. A ROD
amendment was finalized and, on October 27, 1998, the EPA settled with the de
minimis parties. Under the provisions of the settlement, the Company would be
required to pay approximately $520,000 for liabilities resulting from the
government's past and potential future costs. The Department of Justice must
approve 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 minimis 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 minimis party
for less than $10,000.
On October 16, 1989, the EPA and the NJDEP commenced a civil action in the
United States District Court for the District of New Jersey (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.
The Company has been named as a defendant in a Superfund matter involving
the Greer Landfill in South Carolina. The plaintiff's motion to dismiss the
complaint against the Company was granted, although the third-party defendant's
cross-claims against the Company remain. The Company is currently involved in
settlement discussions with the third-party defendants.
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. In April 1998, the Company was notified of a de minimus
settlement under which the Company is allocated a total cost of $16,000 for EPA
past and future costs. The settlement is still pending.
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 of 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.
The Company has identified 28 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. The PDEP has approved the Company's clean-up of three sites. Eight
other sites are currently under some degree of active study and/or remediation.
At December 31, 1998, the Company had accrued $33 million for investigation and
remediation of these manufactured gas plant sites that currently can be
reasonably estimated.
23
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 the Resource Conservation and Recovery Act (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
required investigation was completed in the summer of 1998 and a comprehensive
RCRA Facility Investigation Report (RFI) is being prepared for submission to the
EPA. The Company performed interim measures at the site. In January 1998, the
Chester Waterfront Redevelopment Project was developed as an alternative to an
expanded RCRA Corrective Action Project. The Company together with the EPA and
the PDEP have agreed that potential remediation of the Chem Clear property and
the investigation and potential remediation of all contiguous properties be
moved from the EPA's RCRA Program to the PDEP Act 2 program. Act 2 is a land
recycling program allowing remediation of properties more efficiently through
redevelopment. At December 31, 1998, the Company had spent approximately $3.6
million to comply with the CACO and $700,000 on the Chester Waterfront Project.
At the completion of the required RCRA investigation, the Company will combine
the projects and will be able to predict the nature and cost of any potential
corrective action.
Costs
At December 31, 1998, the Company had accrued $60 million for various
investigation and remediation costs that can be reasonably estimated, including
approximately $33 million for investigation and remediation of former
manufactured gas plant sites as described above. 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 1999 for compliance with
environmental requirements total approximately $14 million. In addition, the
Company may be required to make significant additional expenditures not
presently determinable.
AmerGen Energy Company, LLC
In 1997, the Company and British Energy, plc of Edinburgh, Scotland formed
AmerGen Energy Company, LLC (AmerGen) to pursue opportunities to acquire and
operate nuclear generating stations in the United States. The Company and
British Energy, Inc., a wholly owned subsidiary of British Energy, plc, each own
a 50% equity interest in AmerGen. In October 1998, AmerGen entered into a
definitive asset purchase agreement with GPU, Inc. and certain of its
subsidiaries (GPU) to acquire GPU's 786 MW Three Mile Island Unit No. 1 Nuclear
Generating Facility for approximately $23 million in cash, $77 million for
nuclear fuel payable over five years and certain contingent payments based upon
future wholesale market prices.
Telecommunications Ventures
In 1995, the Company and Hyperion Telecommunications, Inc., a subsidiary
of Adelphia Cable Company, formed PECO Hyperion Telecommunications. The
partnership is a Competitive Local Exchange Carrier (CLEC) and provides local
phone service in the Philadelphia metropolitan region. PECO Hyperion utilizes a
large-scale fiber optic cable-based network that currently extends over 700
miles and is connected to major long-distance carriers and local businesses.
The Company and Hyperion Telecommunications, Inc. each holds a 50% interest in
the partnership.
24
In 1996, the Company and AT&T Corp. formed AT&T Wireless PCS of
Philadelphia, LLC to provide a new digital wireless Personal Communications
Services (PCS) network in the Philadelphia metropolitan trading area. The
Company has completed the initial build-out of the new digital wireless PCS
network. Commercial launch of PCS in the Philadelphia area occurred in October
1997. The Company holds a 49% equity interest in the venture.
Due to their start-up nature, these joint ventures and investments are
expected to negatively affect earnings in the near future. See Note 19 of Notes
to Consolidated Financial Statements included in the Company's Annual Report to
Shareholders for the year 1998.
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. The 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, 1998, the Partnership held
$349.4 million aggregate principal amount of the Subordinated Debentures.
PECO Energy Capital Trust I (Trust I) 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 I Receipts), each representing an
8.72% Cumulative Monthly Income Preferred Security, Series B (Series B
Preferred Securities) of the Partnership. The Partnership is the sponsor of the
Trust. On May 15, 1998, Trust I fully redeemed all outstanding Trust Receipts.
Distributions were made on the Trust I Receipts during 1998 in the aggregate
amount of $2.4 million. Expenses of the Trust for 1998 were approximately
$50,000, all of which were paid by PECO Energy Capital Corp.
PECO Energy Capital Trust II (Trust II) was created in June 1997 as a
statutory business trust under the laws of the State of Delaware solely for the
purpose of issuing trust receipts (Trust II Receipts) each representing an
8.00% Cumulative Monthly Income Preferred Security, Series C (Series C
Preferred Securities) of the Partnership. The Partnership is the sponsor of the
Trust II. As of December 31, 1998, the Trust II had outstanding 2,000,000 Trust
II Receipts. At December 31, 1998, the assets of the Trust II consisted solely
of 2,000,000 Series C Preferred Securities with an aggregate stated liquidation
preference of $50 million. Distributions were made on the Trust II Receipts
during 1998 in the aggregate amount of $4 million. Expenses of the Trust II for
1998 were approximately $50,000, all of which were paid by PECO Energy Capital
Corp. The Trust II Receipts are issued in book-entry only form.
PECO Energy Capital Trust III (Trust III) was created in April 1998 as a
statutory business trust under the laws of the State of Delaware solely for the
purpose of issuing trust receipts (Trust III Receipts) each representing an
7.38% Cumulative Monthly Income Preferred Security, Series D (Series D
Preferred Securities) of the Partnership. The Partnership is the sponsor of the
Trust III. As of December 31, 1998, the Trust III had outstanding 78,105 Trust
III Receipts. At December 31, 1998, the assets of the Trust III consisted
solely of 78,105 Series D Preferred Securities with an aggregate stated
liquidation preference of $78.1 million. Distributions were made on the Trust
III Receipts during 1998 in the aggregate amount of $4.1 million. Expenses of
the Trust III for 1998 were approximately $50,000, all of which were paid by
PECO Energy Capital Corp. The Trust III Receipts are issued in book-entry only
form.
25
Executive Officers of the Registrant at December 31, 1998
Age at Effective Date of Election
Name Dec. 31, 1998 Position to Present Position
- - ---- --------------- -------- -------------------
C. A. McNeill, Jr ..... 59 Chairman of the Board, President and Chief
Executive Officer ................................ July 1, 1997
N. J. Bessey .......... 45 President, Power Team ............................. April 8, 1998
G. R. Rainey .......... 49 President and Chief Nuclear Officer, PECO
Nuclear .......................................... June 1, 1998
G. A. Cucchi .......... 49 Senior Vice President, Corporate and President,
PECO Energy Ventures. ............................ June 22, 1998
J. W. Durham .......... 61 Senior Vice President and General Counsel ......... October 24, 1988
M. J. Egan. ........... 45 Senior Vice President, Finance and Chief
Financial Officer ................................ October 13, 1997
K. G. Lawrence ........ 51 Senior Vice President, Corporate and President,
PECO Energy Distribution ......................... June 22, 1998
J. M. Madara, Jr ...... 55 Senior Vice President, Power Generation
Group ............................................ March 1, 1994
W. H. Smith, III ...... 50 Senior Vice President, Business Services
Group ............................................ November 7, 1997
D. W. Woods ........... 41 Senior Vice President, Corporate and Public
Affairs .......................................... December 1, 1998
J. B. Cotton .......... 53 Vice President, Special Projects, PECO
Nuclear .......................................... August 14, 1998
J. Doering, Jr ........ 55 Vice President, Peach Bottom Atomic Power
Station, PECO Nuclear. ........................... March 2, 1998
G. N. Dudkin .......... 41 Vice President, Operations, PECO Energy
Distribution ..................................... April 8, 1998
D. B. Fetters ......... 47 Vice President, Nuclear Development, PECO
Nuclear .......................................... June 22, 1998
J. H. Gibson .......... 42 Vice President and Controller. .................... May 31, 1998
P. E. Haviland ........ 44 Vice President, Corporate Development ............. March 4, 1998
T. P. Hill, Jr ........ 50 Vice President, Regulatory and External
Affairs, PECO Energy Distribution ................ April 9, 1998
C. A. Jacobs .......... 46 Vice President, Support Services .................. November 9, 1998
S. L. Keenan .......... 34 Vice President, Customer and Marketing
Services, PECO Energy Distribution ............... April 8, 1998
C. A. Matthews ........ 48 Vice President, Information Technology and
Chief Information Officer ........................ July 28, 1997
J. P. McElwain ........ 48 Vice President, Nuclear Projects, PECO
Nuclear .......................................... April 9, 1997
J. B. Mitchell ........ 51 Vice President, Treasury and Evaluation, and
Treasurer ........................................ December 1, 1994
J. D. von Suskil ...... 52 Vice President, Limerick Generating Station,
PECO Nuclear ..................................... January 26, 1998
R. G. White ........... 40 Vice President, Corporate Planning. ............... September 28, 1998
K. K. Combs ........... 48 Corporate Secretary. .............................. November 1, 1994
Each of the above executive officers holds such office at the discretion
of the Company's Board of Directors until his or her replacement or earlier
resignation, retirement or death.
Prior to his election to his current position, Mr. McNeill was President
and Chief Executive Officer, President and Chief Operating Officer and
Executive Vice President -- Nuclear.
Prior to her election to her current position, Ms. Bessey was Vice
President-Power Transactions. Prior to joining the Company in 1994, Ms. Bessey
was Vice President of U.S. Generating Company, an independent power producer.
26
Prior to his election to his current position, Mr. Rainey was Vice
President -- Peach Bottom Atomic Power Station, Vice President -- Nuclear
Services and Plant Manager -- Eddystone Generating Station;
Prior to his election to his current position, Mr. Cucchi was Vice
President -- Power Delivery, Vice President -- Corporate Planning and
Development, Director of System Planning and Performance, and Manager -- System
Planning.
James W. Durham has held the position of Senior Vice President and General
Counsel for over five years.
Prior to joining the Company, Mr. Egan was Senior Vice President and Chief
Financial Officer of Aristech Chemical Company and Vice President of Planning
and Control of ARCO Chemical Company, Americas.
Prior to his election to his current position, Mr. Lawrence was Senior
Vice President --Local Distribution Company, Senior Vice President -- Finance
and Chief Financial Officer, and Vice President -- Gas Operations.
Prior to his election to his current position, Mr. Madara was Vice
President -- Production.
Prior to his election to his current position, Mr. W. H. Smith, III was
Vice President and Group Executive -- Telecommunications Group, Vice President
- - -- Station Support, Vice President -- Planning and Performance, and Manager --
Corporate Strategy and Performance.
Prior to joining the Company in 1998, Mr. Woods was the Chief of Staff for
the Pennsylvania Senate Majority Leader.
Prior to her election to her current position, Ms. Gibson was Director of
Audit Services and Director of the Tax Division.
Prior to joining the Company in 1998, Mr. Haviland was Senior Vice
President -- Planning and Administration with Bovis Construction Group.
Prior to his election to his current position, Mr. Hill was Vice President
and Controller.
Prior to joining the Company in 1998, Ms. Jacobs was Vice President
of Industrial Operations, Americas and Vice President Professional Deveolpment
and Senior Director of Materials Management with Rhone-Polenc Rorer Corporation.
Prior to her election to her current position, Ms. Keenan was acting
General Manager -- Customer Services, Director -- Field Services, Director --
Reengineering and Performance and Manager -- Regulatory Performance.
Prior to her election to her current position, Ms. Matthews was Director
of Consumer Energy Information Systems and Distributed Information Officer.
Prior to joining the Company in 1996, Ms. Matthews was Vice President of
Strategic Business Development for Europe Online S.A. Luxembourg.
Prior to his election to his current position, Mr. von Suskil was Director
- - -- Engineering, Manager -- Planning and Assistant Manager -- Outages. Prior to
joining the Company in 1995, Mr. von Suskil was a Captain in the United States
Navy.
Prior to joining the Company, Mr. White was Corporate Finance Manager and
Corporate Operations Consultant for ARCO Chemical Company.
Prior to their election to the positions shown above, the following
executive officers held other positions with the Company since January 1, 1994:
Mr. Cotton was Director -- Nuclear Engineering, Director -- Nuclear
Quality Assurance and Superintendent -- Operations; Mr. Doering was Plant
Manager -- Limerick, Director -- Nuclear Strategies Support, and General
Manager Operations; Mr. Dudkin was Acting General Manager -- Power Delivery,
Regional Director Power Delivery and Manager -- Electric Operations; Mr.
Fetters was Vice President -- Nuclear Planning and Development, Director --
Nuclear Engineering, Director -- Limerick Maintenance and a Project Manager;
Mr. McElwain was Director of Outage Management -- Peach Bottom; Mr. Mitchell
was Director of Financial Operations and Assistant Treasurer; and Ms. Combs was
an Assistant General Counsel.
There are no family relationships among directors or executive officers of
the Company.
27
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, 1998:
Net Generating Estimated
Capacity (1) Retirement
Station Location (Kilowatts) Year
------- -------- ----------- ----
Nuclear
Limerick ............................ Limerick Twp., PA ................... 2,249,000 2024, 2029
Peach Bottom ........................ Peach Bottom Twp., PA ............... 928,000(2) 2013, 2014
Salem ............................... Hancock's Bridge, NJ. ............... 942,000(2) 2016, 2020
Hydro
Conowingo ........................... Harford Co., MD. .................... 512,000 2014
Pumped Storage
Muddy Run ........................... Lancaster Co., PA ................... 910,000 2014
Fossil (Steam Turbines) ..............
Cromby .............................. Phoenixville, PA .................... 345,000 (3)
Delaware ............................ Philadelphia, PA .................... 250,000 (3)
Eddystone ........................... Eddystone, PA ....................... 1,341,000 2009, 2010, 2011
Schuylkill .......................... Philadelphia, PA .................... 166,000 (3)
Conemaugh ........................... New Florence, PA .................... 352,000(2) 2005, 2006
Keystone ............................ Shelocta, PA ........................ 357,000(2) 2002, 2003
Fossil (Gas Turbines) ................
Chester ............................. Chester, PA ......................... 39,000 (3)
Croydon ............................. Bristol Twp., PA .................... 380,000 (3)
Delaware ............................ Philadelphia, PA .................... 56,000 (3)
Eddystone ........................... Eddystone, PA ....................... 60,000 (3)
Fairless Hills ...................... Falls Twp., PA ...................... 60,000 (3)
Falls ............................... Falls Twp., PA ...................... 51,000 (3)
Moser ............................... Lower Pottsgrove Twp., PA. .......... 51,000 (3)
Pennsbury ........................... Falls Twp., PA ...................... 6,000 (3)
Richmond ............................ Philadelphia, PA .................... 96,000 (3)
Schuylkill .......................... Philadelphia, PA .................... 30,000 (3)
Southwark ........................... Philadelphia, PA .................... 52,000 (3)
Salem ............................... Hancock's Bridge, NJ. ............... 16,000(2) (3)
Fossil (Internal Combustion) .........
Cromby. ............................. Phoenixville, PA .................... 2,700 (3)
Delaware ............................ Philadelphia, PA .................... 2,700 (3)
Schuylkill .......................... Philadelphia, PA .................... 2,800 (3)
Conemaugh ........................... New Florence, PA .................... 2,300(2) 2006
Keystone ............................ Shelocta, PA ........................ 2,300(2) 2003
-----------
Total .................................................................. 9,261,800
===========
- - ------------
(1) Summer rating.
(2) Company portion.
(3) Retirement dates are under on-going review by the Company. Current plans
call for the continued operation of these units beyond 1999.
28
The following table sets forth the Company's major transmission and
distribution lines in service at December 31, 1998:
Voltage in Kilovolts (Kv) Conductor Miles
------------------------- ----------------
Transmission:
500 Kv......................... 891
220 Kv......................... 1,634
132 Kv......................... 15
66 Kv ......................... 570
33 Kv and below ............... 29
Distribution:
33 Kv and below ............... 48,222
At December 31, 1998, the Company's principal electric distribution system
included 21,009 pole-line miles of overhead lines and 21,002 cable miles of
underground cables.
The following table sets forth the Company's gas pipeline miles at
December 31, 1998:
Pipeline Miles
---------------
Transmission .................... 28
Distribution .................... 5,788
Service piping .................. 4,621
-----
Total ........................ 10,437
======
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 157,000 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 28,800 mcf/day. In addition, the Company owns 24 natural gas city
gate stations at various locations throughout its gas service territory.
At December 31, 1998, the Company had 577 miles of 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 16 of Notes to Consolidated Financial Statements
included in the Company's Annual Report to Shareholders for the year 1998.
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
$30 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.
ITEM 3. LEGAL PROCEEDINGS
On April 9, 1998, Grays Ferry Cogneration Partnership (Grays Ferry), two of
three partners of Grays Ferry and Trigen-Philadelphia Energy Corporation, filed
a complaint in Philadelphia County Court of Common Pleas against the Company
arising out of the Company's termination of two power purchase agreements (PPAs)
that the Company had entered into with Grays Ferry. The complaint alleged among
other things, breach of contract, the fraud and breach of implied covenant of
good faith and fair dealing. The plaintiff seeks specific performance, damages
in excess of $200 million and punitive damages. A preliminary injunction was
entered against the Company on May 5, 1998, enjoining the Company from
terminating the PPAs. On September 4, 1998, the Chase Manhattan Bank, as agent
for a syndicate of banks that are lenders to Grays Ferry, filed a complaint
against the Company alleging tortious interference by the Company in the credit
agreements between Grays Ferry and the banks and breach of the letter agreement
between the Company and the banks. These matters have been
29
consolidated. On March 9, 1999, the Court entered a partial judgment in
favor of Grays Ferry declaring, as a matter of law, that the Company's
termination of the PPAs was in breach of those agreements. Trial in the
remaining issues was scheduled for March 29, 1999. On May 29, 1998, Westinghouse
Power Generation filed a complaint in the Philadelphia Court of Common Pleas
against the Company for tortious interference with two contracts that
Westinghouse has with Grays Ferry. That case is scheduled for trial on April 19,
1999. The Company cannot predict the outcome of these matters.
On May 27, 1998, the United States Department of Justice, on behalf of the
Rural Utilities Service and the Chapter 11 Trustee for the Cajun Electric Power
Cooperative Inc. (Cajun), filed an action claiming breach of contract against
the Company in the United States District Court for the Middle District of
Louisiana arising out of the Company's termination of the contract to purchase
Cajun's interest in the River Bend nuclear power plant. This action seeks $67
million in damages. The Company cannot predict the outcome of this matter.
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. Westinghouse has filed a motion for summary judgment on the grounds
that the claim of the plaintiffs is barred by the statute of limitations. On
November 6, 1998, the New Jersey District Court granted summary judgment in
favor of Westinghouse. The plaintiff co-owners, including the Company, have
filed an appeal of the federal claims with the United States Circuit Court for
the Third Circuit Court of Appeals. The plaintiff co-owners are also pursuing an
action on the state law claims in the New Jersey state courts. The Company
cannot predict the outcome of these proceedings.
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, 1999, there were 142,794 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 1998
and 1997 is incorporated herein by reference to "Operating Statistics" in the
Company's Annual Report to Shareholders for the year 1998.
The book value of the Company's common stock at December 31, 1998 was
$13.61 per share.
Dividends may be declared on common stock out of funds legally available
for dividends whenever full dividends on all series of preferred stock
outstanding at the time have been paid or declared and set apart for payment
for all past quarter-yearly dividend periods. No dividends may be declared on
common stock, however, at any time when the Company has failed to satisfy the
sinking fund obligations with respect to certain series of the Company's
preferred stock. Future dividends on common stock will depend upon earnings,
the Company's financial condition and other factors, including the availability
of cash.
The Company's Articles prohibit payment of any dividend on, or other
distribution to the holders of, common stock if, after giving effect thereto,
the capital of the Company represented by its common stock together with its
Other Paid-In Capital and Retained Earnings is, in the aggregate, less than the
involuntary liquidating value of its then outstanding preferred stock. At
December 31, 1998, such capital ($3.1 billion) amounted to about 13 times the
liquidating value of the outstanding preferred stock ($230.2 million).
30
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 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 1998.
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 1998.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 1998.
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 1998.
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 1999 Annual Meeting of Shareholders to be
held April 27, 1999, under the heading "Election of Directors" and is
incorporated herein by reference.
(b) Identification of Executive Officers.
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 1999 Annual Meeting of
Shareholders to be held April 27, 1999, under the heading "Executive
Compensation Disclosure" and is incorporated herein by reference.
31
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information with respect to this caption is included in the Proxy
Statement of the Company in connection with its 1999 Annual Meeting of
Shareholders to be held April 27, 1999, under the heading "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 1999 Annual Meeting of
Shareholders to be held April 27, 1999, under the heading "Election of
Directors" and is incorporated herein by reference.
32
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Financial Statement Schedule
Reference (Page)
----------------------------------
Form 10-K Annual Report
Index Annual Report to Shareholders
- - ----- --------------- ----------------
Data incorporated by reference from the Annual Report to
Shareholders for the year 1998:
Report of Independent Accountants ..................... -- 23
Consolidated Statements of Income for the years
ended December 31, 1998, 1997 and 1996 ............... -- 24
Consolidated Balance Sheets as of December 31, 1998
and 1997 ............................................. -- 26
Consolidated Statements of Cash Flows for the years
ended December 31, 1998, 1997 and 1996 ............... -- 25
Consolidated Statements of Changes in Common
Shareholders' Equity and Preferred Stock for the
years ended December 31, 1998, 1997 and 1996 ......... -- 28
Notes to Consolidated Financial Statements ............ -- 29
Data submitted herewith:
Report of Independent Accountants ..................... 34 --
Schedule II--Valuation and Qualifying Accounts for
the years ended December 31, 1998,
1997 and 1996 ................................. 35 --
All other schedules are omitted since the required information is not
present or is not present in amounts sufficient to require submission of the
schedule, or because the information required is included in the consolidated
financial statements and notes thereto.
With the exception of the consolidated financial statements and the
independent accountants' report listed in the above index and the information
referred to in Items 1, 2, 5, 6, 7 and 8, all of which is included in the
Company's Annual Report to Shareholders for the year 1998 and incorporated by
reference into this Form 10-K, the Annual Report to Shareholders for the year
1998 is not to be deemed filed as part of this Form 10-K.
33
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors
PECO Energy Company:
Our audits of the consolidated financial statements referred to in our
report dated February 5, 1999 (which report and consolidated financial
statements are incorporated by reference in this Annual Report on Form 10-K)
also included an audit of the financial statement schedule listed in Item 14 of
this Form 10-K. In our opinion, this financial statement schedule presents
fairly, in all material respects, the information set forth therein when read
in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 5, 1999
34
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
Column A Column B Column C Additions Column D Column E
-------- -------- ------------------------- ------------- ----------
Charged to
Balance at Charged to Other Balance at
Beginning of Costs and Accounts Deductions End of
Description Period Expenses Describe Describe(1) Period
----------- ------------ ---------- ----------- ----------- ----------
FOR THE YEAR ENDED DECEMBER 31, 1998
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS..... $133,810 $71,667 $ -- $83,338 $122,139
-------- ------- ---- ------- --------
TOTAL .................................. $133,810 $71,667 $ -- $83,338 $122,139
======== ======= ==== ======= ========
FOR THE YEAR ENDED DECEMBER 31, 1997(2)
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS . $128,459 $88,263 $ -- $82,912 $133,810
-------- ------- ---- ------- --------
TOTAL .................................. $128,459 $88,263 $ -- $82,912 $133,810
======== ======= ==== ======= ========
FOR THE YEAR ENDED DECEMBER 31, 1996(2)
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS..... $118,525 $93,104 $ -- $83,170 $128,459
-------- ------- ---- ------- --------
TOTAL .................................. $118,525 $93,104 $ -- $83,170 $128,459
======== ======= ==== ======= ========
- - ------------
(1) Write-off of individual accounts receivable.
(2) Restated to reflect valuation allowance activity for Customer Assistance
Program and Special Agreement accounts.
35
Exhibits
Certain of the following exhibits have been filed with the Securities and
Exchange Commission (Commission) pursuant to the requirements of the Acts
administered by the Commission. Such exhibits are identified by the references
following the listing of each such exhibit and are incorporated herein by
reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as
amended. Certain other instruments which would otherwise berequired 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 26, 1998. (1997 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:
Dated as of File Reference Exhibit No.
---------------------------------------------------------------------
May 1, 1927 2-2881 B-1(c)
March 1, 1937 2-2881 B-1(g)
December 1, 1941 2-4863 B-1(h)
November 1, 1944 2-5472 B-1(i)
December 1, 1946 2-6821 7-1(j)
September 1, 1957 2-13562 2(b)-17
May 1, 1958 2-14020 2(b)-18
March 1, 1968 2-34051 2(b)-24
March 1, 1981 2-72802 4-46
March 1, 1981 2-72802 4-47
December 1, 1984 1984 Form 10-K 4-2(b)
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
October 15, 1987 Form 8-K dated October 7, 1987 4(c)-66
October 15, 1987 Form 8-K dated October 7, 1987 4(c)-67
April 15, 1988 Form 8-K dated April 11, 1988 4(e)-68
April 15, 1988 Form 8-K dated April 11, 1988 4(e)-69
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
April 1, 1992 March 31, 1992 Form 10-Q 4(e)-79
June 1, 1992 June 30, 1992 Form 10-Q 4(e)-81
July 15, 1992 June 30, 1992 Form 10-Q 4(e)-83
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
36
Dated as of File Reference Exhibit No.
---------------------------------------------------------------------
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
November 1, 1993 Form 8-A dated October 27, 1993 4(e)-94
November 1, 1993 Form 8-A dated October 27, 1993 4(e)-95
May 1, 1995 Form 8-K dated May 24, 1995 4(e)-96
4-3 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).
4-4 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).
4-5 Second Supplemental Indenture, dated as of June 1, 1997, between the
Company and First Union National Bank, as successor trustee, to
Indenture dated as of July 1, 1994. (1997 Form 10-K, Exhibit 4-5).
4-6 Third Supplemental Indenture, dated as of April 1, 1998, between the
Company and First Union National Bank, as successor trustee, to
Indenture dated as of July 1, 1994.
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).
4-9 Payment and Guarantee Agreement, dated as of June 6, 1997, executed
by the Company in favor of the holders of Cumulative Monthly Income
Preferred Securities, Series C of PECO Energy Capital, L.P. (1997
Form 10-K, Exhibit 4-8).
4-10 Payment and Guarantee Agreement, dated as of April 6, 1998, executed
by the Company in favor of the holders of Cumulative Monthly Income
Preferred Securities, Series D of PECO Energy Capital, L.P.
4-11 Revolving Credit Agreement, dated as of October 7, 1997, among the
Company, as borrower, and certain banks named therein. (1997 Form
10-K, Exhibit 4-9).
4-12 364-day Credit Agreement, dated as of October 7, 1997, among the
Company, as borrower, and certain banks named therein. (1997 Form
10-K, Exhibit 4-10).
4-13 Term Loan Agreement, dated as of November 30, 1998, among the Company
as borrower, and certain banks named therein.
4-14 PECO Energy Company Dividend Reinvestment and Stock Purchase Plan, as
amended January 28, 1994 (Post-Effective Amendment No. 1 to
Registration No. 33-42523, Exhibit 28).
10-1 Amended and Restated Operating Agreement of PJM Interconnection,
L.L.C., dated June 2, 1997, (Revised December 31, 1997). (1997 Form
10-K, Exhibit 10-1).
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; supplemental agreement dated January 26, 1977
(1991 Form 10-K, Exhibit 10-3); and supplemental agreement dated May
27, 1997. (1997 Form 10-K, Exhibit 10-2).
37
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 Septem- ber 1, 1975;
supplemental agreement dated January 26, 1977 (1988 Form 10-K,
Exhibit 10-4) and supplemental agreement dated May 27, 1997. (1997
Form 10-K, Exhibit 10-3).
10-4 Deferred Compensation and Supplemental Pension Benefit Plan.* (Form
10-K, Exhibit 10-4).
10-5 Management Group Deferred Compensation and Supplemental Pension
Benefit Plan.* (Form 10-K, Exhibit 10-5).
10-6 Unfunded Deferred Compensation Plan for Directors.* (Form 10-K,
Exhibit 10-6).
10-7 Forms of Agreement between the Company and certain officers (1995
Form 10-K, Exhibit 10-5).
10-8 PECO Energy Company 1989 Long-Term Incentive Plan, amended April 9,
1997 (1997 Proxy Statement, Appendix B).*
10-9 PECO Energy Company Management Incentive Compensation Plan (1997
Proxy State- ment, Appendix A).*
10-10 PECO Energy Company 1998 Stock Option Plan (Registration No.
333-67367, Exhibit 4.2).
10-11 Amended and Restated Limited Partnership Agreement of PECO Energy
Capital, L.P., dated July 25, 1994 (1994 Form 10-K, Exhibit 10-7).
10-12 Amendment No. 1 to the Amended and Restated Limited Partnership
Agreement of PECO Energy Capital, L.P. (1995 Form 10-K, Exhibit
10-8).
10-13 Amendment No. 2 to the Amended and Restated Limited Partnership
Agreement of PECO Energy Capital, L.P. (1995 Form 10-K, Exhibit
10-9).
10-14 Amendment No. 3 to the Amended and Restated Limited Partnership
Agreement of PECO Energy Capital, L.P.
10-15 Amended and Restated Trust Agreement of PECO Energy Capital Trust I,
dated as of December 19, 1995. (1995 Form 10-K, Exhibit 10-10).
10-16 Amended and Restated Trust Agreement of PECO Energy Capital Trust
III, dated as of April 6, 1998.
10-17 Form of Amended and Restated Trust Agreement for PECO Energy
Transition Trust among George Shicora and Diana Moy Kelly, as
Beneficiary Trustees, First Union Trust Company, National
Association, as Issuer Trustee, Delaware Trustee and Independent
Trustee, and PECO Energy Company, as Grantor and Owner (Post-
Effective Amendment No. 1 to Registration Statement No. 333-58055,
Exhibit 4.1.2).
10-18 Form of Intangible Transition Property Sale Agreement between PECO
Energy Transition Trust and PECO Energy Company (Post-Effective
Amendment No. 1 to Registration Statement No. 333-58055, Exhibit
10.1).
10-19 Form of Master Servicing Agreement between PECO Energy Transition
Trust and PECO Energy Company (Post-Effective Amendment No. 1 to
Registration Statement No. 333-58055, Exhibit 10.2).
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 1998.
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.
38
Reports on Form 8-K
During the quarter ended December 31, 1998, the Company filed Current
Reports on Form 8-K, dated:
October 15, 1998 reporting information under "ITEM 5. OTHER EVENTS"
regarding AmerGen Energy Company, LLC, the joint venture between the
Company and British Energy Company, and GPU, Inc. signing a definitive
asset purchase agreement to purchase Unit No. 1 at the Three Mile Island
Nuclear Generating Station.
Subsequent to December 31, 1998, the Company filed Current Reports on Form
8-K, dated:
March 8, 1999 reporting information under "ITEM 5. OTHER EVENTS"
regarding the United States Supreme Court's denial of the petition of
certiorari in an action relating to Pennsylvania's Electricity Generation
Customer Choice and Competition Act.
March 25, 1999 reporting information under "ITEM 5. OTHER EVENTS"
regarding the issuance, by PECO Energy Transition Trust, a wholly owned
subsidiary of the Company, of $4 billion of Transition Bonds.
39
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant, PECO ENERGY COMPANY, has duly caused this
annual report to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Philadelphia, and Commonwealth of Pennsylvania, on
the 31st day of March 1999.
PECO ENERGY COMPANY
By /s/ C.A. McNeill, Jr.
-------------------------------
C.A. McNeill, Jr., Chairman of the Board,
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/ C. A. McNeill, Jr. Chairman of the Board, President, Chief March 31, 1999
- - --------------------- Executive Officer and Director (Principal
C. A. McNeill, Jr. Executive Officer)
/s/ M. J. Egan Senior Vice President -- Finance and Chief March 31, 1999
- - --------------------- Financial Officer (Principal Financial and
M. J. Egan 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 ROSEMARIE B. GRECO
DANIEL L. COOPER JOHN M. PALMS
M. WALTER D'ALESSIO JOSEPH F. PAQUETTE, JR.
G. FRED DIBONA, JR. RONALD RUBIN
R. KEITH ELLIOTT ROBERT SUBIN
RICHARD H. GLANTON
By /s/ C. A. McNeill, Jr. March 31, 1999
- - -------------------------
40