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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________________ to ___________________
Commission File Number 1-1401
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PECO ENERGY COMPANY
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(Exact name of registrant as specified in its charter)
Pennsylvania 23-0970240
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P.O. Box 8699
2301 Market Street, Philadelphia, PA (215) 841-4000 19101
(Address of principal executive offices) (Registrant's telephone number, including area code) (Zip Code)
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Securities registered pursuant to Section 12(b) of the Act:
First and Refunding Mortgage Bonds (Listed on the New York Stock Exchange):
5-5/8% Series due 2001 6-3/8% Series due 2005 7-3/8% Series due 2001 6-1/2% Series due 2003
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)
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 Preferred Security, Series D, $25 stated value, issued by PECO Energy
Capital, L.P. and unconditionally guaranteed by the Company (Listed on the New
York Stock Exchange)
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock--without par value:
$7.48 Series $6.12 Series
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the registrant's common stock (only voting
stock) held by non-affiliates of the registrant was $6,895,064,888 at March 24,
2000.
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: 181,449,076 shares outstanding at March
24, 2000.
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DOCUMENTS INCORPORATED BY REFERENCE (In Part)
Proxy Statement of PECO Energy Company in connection with its
2000 Annual Meeting of Shareholders, which is expected to be filed
with the U.S. Securities and Exchange Commission
by April 29, 2000, is incorporated in part in
Part III hereof, as specified herein.
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TABLE OF CONTENTS
PAGE NUMBERS TO BE UPDATED Page No.
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PART I
ITEM 1. BUSINESS..........................................................................................4
General...........................................................................................4
Distribution Business Unit .......................................................................5
General......................................................................................5
Retail Electric Services.....................................................................6
Transmission Services........................................................................9
Gas..........................................................................................9
Generation Business Unit.........................................................................10
General.....................................................................................10
Generation Assets...........................................................................10
Limerick Generating Station.................................................................12
Peach Bottom Atomic Power Station...........................................................14
Salem Generating Station....................................................................14
Fuel........................................................................................15
Power Marketing Group.......................................................................17
Unregulated Retail Energy Supplier..........................................................18
AmerGen Energy Company, LLC.................................................................19
Ventures Business Unit ..........................................................................19
Exelon Infrastructure Services, Inc.........................................................19
Telecommunications Ventures.................................................................19
Peco Energy Transition Trust, Peco Energy Capital Corp. and Related Entities.....................20
Segment Information..............................................................................20
Competition......................................................................................20
Year 2000 Readiness Disclosure...................................................................21
Capital Requirements.............................................................................21
Construction.....................................................................................22
Employee Matters.................................................................................22
Environmental Regulations........................................................................23
Water.......................................................................................23
Air.........................................................................................24
Solid and Hazardous Waste...................................................................25
Costs.......................................................................................28
Executive Officers of the Registrant.............................................................28
ITEM 2. PROPERTIES.......................................................................................31
ITEM 3. LEGAL PROCEEDINGS................................................................................32
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............................................33
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS.................................................................33
ITEM 6. SELECTED FINANCIAL DATA..........................................................................33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.........................................................35
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.......................................53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA......................................................56
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE......................................................91
PAGE NUMBERS TO BE UPDATED Page No.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...............................................92
ITEM 11. EXECUTIVE COMPENSATION...........................................................................92
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT..................................................................................92
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...................................................92
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.................................93
Financial Statements and Financial Statement Schedule............................................93
SCHEDULE II-- VALUATION AND QUALIFYING ACCOUNTS..................................................94
Exhibits.........................................................................................95
Reports on Form 8-K.............................................................................100
SIGNATURES
PART I
ITEM 1. BUSINESS
General
Incorporated in Pennsylvania in 1929, PECO Energy Company (Company) is
engaged principally in the production, purchase, transmission, distribution and
sale of electricity to residential, commercial, industrial and wholesale
customers and the distribution and sale of natural gas to residential,
commercial and industrial customers. Pursuant to the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Competition Act), the
Commonwealth of Pennsylvania has required the unbundling of retail electric
services in Pennsylvania into separate generation, transmission and distribution
services with open retail competition for generation services. Since the
commencement of deregulation in 1999, the Company serves as the local
distribution company providing electric distribution services in its franchised
services territory in southeastern Pennsylvania and bundled electric service to
customers who do not choose an alternate electric generation supplier. The
Company engages in the wholesale marketing of electricity on a national basis.
Through its Exelon Energy division, the Company is a competitive generation
supplier offering competitive energy supply to customers throughout
Pennsylvania. The Company's infrastructure services subsidiary, Exelon
Infrastructure Services, Inc. (EIS), provides utility infrastructure services to
customers in several regions of the United States. The Company owns a 50%
interest in AmerGen Energy Company, LLC (AmerGen), a joint venture with British
Energy, Inc., a wholly owned subsidiary of British Energy plc (British Energy),
that acquires and operates nuclear generating facilities. The Company also
participates in joint ventures which provide telecommunications services in the
Philadelphia metropolitan region.
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.
On September 22, 1999, the Company and Unicom Corporation (Unicom)
entered into an Agreement and Plan of Exchange and Merger providing for a merger
of equals. On January 7, 2000, the Agreement and Plan of Exchange and Merger was
amended and restated (Merger Agreement). The Merger Agreement has been approved
by both companies' Boards of Directors. The transaction will be accounted for as
a purchase with the Company as acquiror.
4
The Merger Agreement provides for (a) the exchange of each share of
outstanding common stock, no par value, of the Company for one share of common
stock of the new company, Exelon Corporation (Exelon) (Share Exchange) and (b)
the merger of Unicom with and into Exelon (Merger and together with the Share
Exchange, Merger Transaction). In the Merger, each share of outstanding common
stock, no par value, of Unicom will be converted into 0.875 shares of common
stock of Exelon plus $3.00 in cash. In the Merger Agreement, the Company and
Unicom agree to repurchase approximately $1.5 billion of common stock prior to
the closing of the Merger, with Unicom to repurchase approximately $1.0 billion
of its common stock, and the Company to repurchase approximately $500 million of
its common stock. As a result of the Share Exchange, the Company will become a
wholly owned subsidiary of Exelon. As a result of the Merger, Unicom will cease
to exist and its subsidiaries, including Commonwealth Edison Company, an
Illinois corporation (ComEd), will become subsidiaries of Exelon. Following the
Merger Transaction, Exelon will be a holding company with two principal utility
subsidiaries, ComEd and the Company.
The Merger Transaction is conditioned, among other things, upon the
approvals of the common shareholders of both companies and the approval of
certain regulatory agencies. See "Distribution Business Unit-Retail Electric
Services." The companies have filed an application with the Securities and
Exchange Commission (SEC) to register Exelon as a holding company under the 1935
Act.
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.
Prior to 1999, substantially all of the Company's retail electric and
gas revenues were derived pursuant to bundled rates regulated by the PUC, and
prior to 1996 all of the Company's wholesale electric revenue was derived
pursuant to rates regulated by the FERC. As a result of the adoption of the
Competition Act and deregulation initiatives by the FERC, electric services have
been unbundled into separate generation, transmission and distribution services
with open competition for both retail and wholesale generation services. Certain
transmission and distribution services remain subject to regulation.
Annual and quarterly operating results can be significantly affected by
weather. Traditionally, sales of electricity are higher in the second and third
quarters due to warmer weather and sales of gas are higher in the first and
fourth quarters due to colder weather.
In 1999, the Company completed the redesign of its internal reporting
structure to separate its distribution, generation and ventures operations into
business units and provide financial and operational data on the same basis to
senior management. The Company has also requested authorization from the PUC
(whether or not the merger with Unicom is consummated) to create a holding
company structure in which the Company would continue as the distribution
company and the generation and ventures businesses would be conducted through
separate unregulated subsidiaries.
Distribution Business Unit
General
The Company's distribution business unit consists of its regulated
operations including electric transmission and distribution services, regulated
retail sales of generation services and retail gas sales and services.
The Company's traditional retail service territory covers 2,107 square
miles in southeastern Pennsylvania. The Company's distribution business unit
provides electric transmission and distribution service and generation service
to customers who do not purchase generation service from an electric generation
supplier (EGS) in an area of 1,972 square miles, with a population of
approximately 3.6 million, including 1.6 million in the City of Philadelphia.
Natural gas service is supplied in a 1,475 square mile area in southeastern
Pennsylvania adjacent to Philadelphia with a population of 1.9 million. Rates
for retail service provided by the Company's distribution business unit are set
by the PUC.
Retail Electric Services
The Competition Act was enacted in December 1996 and provided for the
restructuring of the electric utility industry in Pennsylvania, including 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.
5
The Competition Act required utilities to submit restructuring plans,
including their stranded costs resulting from retail competition for generation
services. Stranded costs include regulatory assets, nuclear decommissioning
costs and long-term power purchase 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. Under the Competition Act, a utility is subject to a generation rate
cap through the earlier of December 31, 2005 or until the utility is no longer
recovering stranded costs. The generation cap provides that total charges to
customers cannot exceed rates in place at December 31, 1996, subject to certain
exceptions. The Competition Act also caps transmission and distribution rates
from December 31, 1996 through June 30, 2002, subject to certain exceptions.
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. 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 alternate
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. 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 EGSs. The Company's
restructuring plan identified $7.5 billion of retail electric generation-related
stranded costs. 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 Settlement authorizes the Company to recover $5.26 billion of
stranded costs, together with a return of 10.75% thereon. 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. Under the Settlement, the CTCs were established assuming annual
growth in sales of 0.8% and are reconciled annually to actual sales.
6
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(3) $551,988(3) $566,134(3) $ (14,146)
2000 33,837,913 0.0192 621,102 564,222 56,879
2001 34,108,616 0.0233(4) 761,097(4) 490,417(4) 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
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(1) Subject to reconciliation of actual sales and collections.
(2) Both the CTCs and the ITCs are subject to adjustment.
(3) The actual CTC/ITC rate for 1999 was $0.0171/kWh resulting in total
CTC/ITC collections of $565 million.
(4) Reflects reduction required by PUC Order on March 16, 2000 as described
below.
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 required the Company to reduce rates during 1999 and
2000 by 8% and 6%, respectively, from rates in existence on December 31, 1996.
Further, the Settlement provided for a one-time additional discount in 2000 if
there was an overcollection of ITC and CTC in 1999. Overcollections for two
customer categories (residential and small commercial and industrial) occurred
in 1999 resulting in reductions in these rate categories of 7% and 8.3%,
respectively, in 2000. The Settlement also extended the rate caps on generation
rates at higher levels than required by the Competition Act, until December 1,
2010 and extended the 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.
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 0.0233 (4) 0.0447 0.0680 (4)
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 (5) 0.0253 (5) 0.0298 (5) 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) Reflects reduction required by PUC Order on March 16, 2000 as described
below.
(5) Effective until June 30, 2005.
Under the Settlement, customer choice of EGSs was phased in between
January 1, 1999 and January 1, 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. As of December 31, 1999,
approximately 17% of the Company's residential load, approximately 39% of its
commercial load and approximately 59% of its industrial load were purchasing
generation service from an alternative EGS. 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, including 20% of residential customers assigned to an EGS as a
PLR default supplier, 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.
7
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 replaces the
customer as the obligor with respect to the customer's bill and the Company
generally has no right to collect such receivable from the customer. 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. 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.
Under the Settlement, the Company acts 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. On April 30, 1999, the
PUC adopted regulations providing for Competitive Default Service. Under the
regulations, 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 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
transmission and distribution rates) and expansion and modification of the
Company's program for low-income customers.
Pursuant to authorization of the PUC granted as part of the Settlement,
PECO Energy Transition Trust (PETT), a special purpose entity and wholly owned
subsidiary of the Company, issued $4 billion of its Transition Bonds on March
25, 1999 to securitize a portion of the Company's stranded cost recovery. As
required by the Competition Act, the proceeds from the securitization were
applied to reduce stranded costs, including related capitalization. For
additional information, see ITEM 7. - Management's Discussion and Analysis of
Financial Condition and Results of Operations.
On March 16, 2000, the PUC issued an order approving a Joint Petition
for Full Settlement of PECO Energy Company's Application for a Qualified Rate
Order (QRO) authorizing the Company to securitize up to an additional $1 billion
of its authorized recoverable stranded costs. In accordance with the terms of
the Joint Petition for Full Settlement, when the QRO becomes final and
non-appealable, the Company, through its distribution business unit, will
provide its retail customers with rate reductions in the total amount of $60
million beginning on January 1, 2001. The rate reduction will be effective for
calendar year 2001 only and will not be contingent upon the issuance of
Transition Bonds pursuant to the QRO.
On March 24, 2000, the Company submitted for approval a joint petition
for settlement reached with various parties to the Company's proceeding before
the PUC involving the proposed merger with Unicom. The Company reached agreement
with advocates for residential, small business and large industrial customers,
and representatives of marketers, environmentalists, municipalities and elected
officials. Under the comprehensive settlement agreement, the Company has agreed
to $200 million in rate reductions for all customers over the period January 1,
2002 through 2005 and extended rate caps on the Company's retail electric
distribution charges through December 31, 2006, electric reliability and
customer service standards, mechanisms to enhance competition and customer
choice, expanded assistance to low-income customers, extensive funding for wind
and solar energy and community education, nuclear safety research funds,
customer protection against nuclear costs outside of Pennsylvania, and
maintenance of charitable and civic contributions and employment for the
Company's headquarters in Philadelphia.
8
Transmission Services
The Company's distribution business unit also provides wholesale
transmission service under rates established by FERC. FERC Order No. 888
required 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 FERC. In response to Order 888, the Company has filed an
individual compliance tariff with FERC.
The Company provides regional transmission service pursuant to a
regional transmission tariff filed by the Company and the other transmission
owners who are members of the PJM Interconnection LLC (PJM). PJM is a power pool
that integrates, through central dispatch, the generation and transmission
operations of its member companies across a 50,000 square mile territory. Under
the PJM tariff, transmission service is provided on a region-wide, open-access
basis using the transmission facilities of the PJM members at rates based on the
costs of transmission service. PJM's Office of Interconnection is the
independent system operator (ISO) for PJM and is responsible for operation of
the PJM control area and administration of the PJM open-access transmission
tariff. The Company and the other transmission owners in PJM have turned control
of their transmission facilities to the ISO.
On December 20, 1999, the FERC issued Order No. 2000, in which it
stated an expectation that all jurisdictional transmission-owning public
utilities participate in regional transmission organizations (RTOs) by specified
deadlines. Transmission owners like the Company who are participants in existing
ISO arrangements must make a compliance filing on or before January 15, 2001 to
address their compliance with the RTO Rule. FERC has also set December 15, 2001
as the deadline for transferring control over transmission facilities to
approved RTOs. The Company's transmission facilities are presently under the
control of the PJM ISO.
Gas
Historically, the Company's gas sales and gas transportation revenues
were derived pursuant to rates regulated by the PUC. The PUC has established
through regulated 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 June 22, 1999, Pennsylvania Governor Tom Ridge signed into law the
Natural Gas Choice and Competition Act (Act) which expands choice of gas
suppliers to residential and small commercial customers and eliminates the 5%
gross receipts tax on gas distribution companies' sales of gas. Large commercial
and industrial customers have been able to choose their suppliers since 1984.
Currently, approximately one-third of the Company's total yearly throughput is
supplied by third parties.
The Act permits gas distribution companies to continue to make
regulated sales of gas to their customers. The Act does not deregulate the
transportation service provided by gas distribution companies, which remains
subject to rate regulation. Gas distribution companies will continue to provide
billing, metering, installation, maintenance and emergency response services.
In compliance with the schedule ordered by the PUC on December 1, 1999,
the Company filed with the PUC a restructuring plan for the implementation of
gas deregulation and customer choice of gas service suppliers in its service
territory effective July 1, 2000. The Company believes there will be no material
impact on the financial condition or operations of the Company because of the
PUC's existing requirement that gas distribution companies cannot collect more
than the actual cost of gas from customers, and the Act's requirement that
suppliers must accept assignment or release, at contract rates, the portion of
the gas distribution company's firm interstate pipeline contracts required to
serve the suppliers' customers.
9
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. For additional
information, 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 1999-2000 heating season
supplies.
The gas industry is continuing to undergo structural changes in
response to FERC policies designed to increase competition.
Generation Business Unit
General
The Company's generation business unit consists of its generation
assets, its power marketing group, its unregulated retail energy supplier and
its investment in AmerGen. The generation business unit, through the power
marketing group, manages the output of the Company's generation assets to serve
native load in the Company's franchised service territory and markets excess
generation in the wholesale market. The power marketing group maintains a net
positive supply of energy and capacity, through the Company's generation assets
and long, intermediate and short-term contracts to protect it from the potential
operational failure of one of its owned or contracted power generating units.
The unregulated retail energy supplier, Exelon Energy, offers competitive energy
supply to customers throughout Pennsylvania. AmerGen is a 50% owned joint
venture with British Energy formed to pursue opportunities to acquire and
operate nuclear generating stations in the United States.
The Company established specific goals to increase its generation
capacity from 9 gigawatts to 25 gigawatts by 2003. The Company is developing a
generation portfolio capable of taking advantage of periods of increased demand.
In order to meet this strategic objective, the Company may require significant
capital resources.
The following discussion of the Company's generation assets does not
include the generation assets of AmerGen. See "AmerGen Energy Company, LLC."
Generation Assets
The net installed electric generating capacity (summer rating) of the
Company and its subsidiaries at December 31, 1999 was as follows:
Type of Capacity Megawatts(MW) % of Total
---------------- ----- ----------
Nuclear .................................. 4,154 44.7%
Mine-mouth, coal-fired ................... 709 7.6
Service-area, coal-fired ................. 725 7.8
Oil-fired ................................ 1,176 12.7
Gas-fired ................................ 261 2.8
Hydro (includes pumped storage) .......... 1,422 15.3
Internal combustion ...................... 849 9.1
----- -----
Total .................................... 9,296(1) 100.0%
===== =====
- - ------------
(1) See "Fuel" for sources of fuels used in electric generation.
10
The all-time maximum hourly demand on the Company's system was 7,959 MW
which occurred on July 6, 1999. The all-time maximum PJM demand of 51,700 MW
occurred on July 6, 1999. PJM's installed capacity (summer rating) is 56,188 MW.
The Company expects to be able to contract for its installed capacity to meet
its obligation to supply its PJM reserve margin share during the period
1999-2002.
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 1,150 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 44.7% of its
installed generating capacity. In 1999, approximately 41% 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 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 $9.5 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 $9.3 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 $9.5 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 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 decommission 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 $32 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.
11
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 reasonable assurance 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. At December 31, 1999, the Company's current estimate of its nuclear
facilities' decommissioning cost is $1.4 billion in 1998 dollars.
Decommissioning costs are recoverable through regulated rates. At December 31,
1999, the Company held $408 million in trust accounts, representing amounts
recovered from customers and net realized and unrealized investment earnings
thereon, to fund future decommissioning costs.
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.
In 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. The
NRC has decided to substitute an alternative program which bases the level of
NRC oversight on the results of NRC inspections and evaluations of specific
plant performance and any identified changes in performance levels.
Limerick Generating Station
Limerick Unit No. 1 achieved a capacity factor of 98% in 1999 and 77%
in 1998. Limerick Unit No. 2 achieved a capacity factor of 86% in 1999 and 95%
in 1998. 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 1999, 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."
12
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 was
completed during the April 1999 refueling outage. Although crack indications
were identified, the results of the inspections and evaluations concluded that
the condition of the Limerick Unit No. 2 core shroud, projected through at least
the next operating cycle, will support the required safety margins, specified in
the ASME Code and reinforced by industry recommendations. 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 have been installed at Peach Bottom Units No. 2 and No. 3 and Limerick
Units No. 1 and No. 2.
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 informed the NRC that
it had taken short-term corrective actions to address the inadequacies of the
Thermo-Lag barriers installed at Limerick and Peach Bottom and was 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. In 1995, the Company completed its engineering
re-analysis for both Limerick and Peach Bottom. This re-analysis identified
modifications at both plants in order to implement the long-term measures
addressing the concern over Thermo-Lag use. 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. On October 12, 1999, the Company confirmed to the
NRC that the corrective actions associated with the Thermo-Lag fire barriers at
Peach Bottom had been completed. 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 confirmatory order was subsequently modified by letter
from the NRC dated May 3, 1999 to require completion of the Limerick Thermo-Lag
upgrades by September 30, 1999. On September 17, 1999, the Company provided
notification to the NRC of completion of the Thermo-Lag fire barrier corrective
actions at Limerick.
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, 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.
13
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.
Peach Bottom Atomic Power Station
Peach Bottom Unit No. 2 achieved a capacity factor of 99% in 1999 and
80% in 1998. Peach Bottom Unit No. 3 achieved a capacity factor of 90% in 1999
and 92% in 1998. 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 1999, 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."
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.
On September 30, 1999, the Company announced it has reached an
agreement to purchase an additional 7.51% ownership interest in Peach Bottom
from Atlantic City Electric Company and Delmarva bringing the Company's
ownership to 50%. The sale is expected to be completed by mid-2000 subject to
federal and state approvals.
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
The Company has been informed by PSE&G that Salem Unit No. 1 achieved
a capacity factor of 83% in 1999 and 66% in 1998. Salem Unit No. 2 achieved a
capacity factor of 82% in 1999 and 80% in 1998. Salem Units No. 1 and No. 2 are
each on an 18-month refeuling cycle. The last refueling outages for Units No. 1
and No. 2 were in the spring of 1999 and fall of 1999, respectively.
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 Operations and Plant Support, Salem achieved a rating of
"1". In the areas of Maintenance and Engineering, Salem achieved a rating of
"2".
In addition to the matters discussed above, see "Peach Bottom Atomic
Power Station,""Environmental Regulations - Water," and ITEM 3. Legal
Proceedings.
14
Fuel
The following table shows the Company's sources of electric output for
1999 and as estimated for 2000:
1999 2000 (Est.)
------ -----------
Nuclear 41.3% 42.1%
Mine-mouth, coal-fired 6.8 6.8
Service-area, coal-fired 3.5 4.2
Oil-fired 1.8 1.7
Hydro (includes pumped storage) 1.2 1.6
Internal combustion 0.1 0.2
Purchased, interchange and nonutility generated 45.3 43.4
---- -----
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 2002 2004 2003
Limerick Unit No. 2 .............. 2002 2002 2004 2004
Peach Bottom Unit No. 2 .......... 2002 2002 2004 2002
Peach Bottom Unit No. 3 .......... 2002 2002 2004 2003
- - ------------
(1) The Company's contracts for uranium concentrates are allocated to Limerick
and Peach Bottom on an as-needed basis. The Company has commitments for at least
80% of concentrates requirements for Limerick and Peach Bottom in 2002, and
about 20% of requirements in 2003 and 2004.
(2) The Company has commitments for at least 90% of the conversion services
requirements for Limerick and Peach Bottom in 2002 and about 20% of requirements
in 2003 and 2004.
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 capability until 2006. Peach Bottom has on-site pools with
capacity to store spent fuel until 2000 for Unit No. 2 and 2001 for Unit No. 3.
The Company has completed construction of a dry spent-fuel storage facility at
Peach Bottom to maintain full core discharge capacity in the spent-fuel pools.
An NRC monitored dry run of storage operations was completed in March 2000 in
anticipation of a summer 2000 spent-fuel storage campaign for Peach Bottom Unit
No. 2. The cost of the facility, including the first nine storage casks, was
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 $6 million per year. The Company has been informed by PSE&G that as a
result of reracking the two spent-fuel pools at Salem, spent-fuel storage
capacity of Salem Units No. 1 and No. 2 is estimated to be 2012 and 2016,
respectively. PSE&G is also currently assessing available options which could
satisfy the potential need for additional storage capacity, including the option
of constructing an on-site dry storage facility that would satisfy the
spent-fuel storage needs of Salem.
15
Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is required
to begin taking possession of all spent nuclear fuel generated by the Company's
nuclear units for long-term storage by no later than 1998. Based on recent
public pronouncements, it is not likely that a permanent disposal site will be
available for the industry before 2015, at the earliest. In reaction to
statements from the DOE that it was not legally obligated to begin to accept
spent fuel in 1998, a group of utilities and state government agencies filed a
lawsuit against the DOE which resulted in a decision by the U.S. Court of
Appeals for the District of Columbia (D.C. Court of Appeals) in July 1996 that
the DOE had an unequivocal obligation to begin to accept spent fuel in 1998. In
accordance with the NWPA, the Company pays the DOE one mil ($.001) per
kilowatthour of net nuclear generation for the cost of nuclear fuel disposal.
This fee may be adjusted prospectively in order to ensure full cost recovery.
Because of inaction by the DOE 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.
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,
has 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.
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 is currently recovering these costs through regulated rates.
16
The Company is currently recovering in rates the costs for nuclear
decommissioning and decontamination and related 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.
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
Sithe Energy, Inc. 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 2000 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 Generating Station
(Eddystone) and Cromby Station (Cromby). At January 1, 2000, 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, 2001.
Purchases pursuant to these contacts represented approximately 2.8% of the
Company's Fuel and Energy Interchange Expense in 1999.
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.
Power Marketing Group
The Company competes in the wholesale electric generation business on a
national basis. The Company enters into bilateral arrangements for the purchase,
sale and delivery of energy and competes in the developing wholesale spot market
for electricity, including the hourly energy market in PJM known as the PJM
Power Exchange (PJM PX). The FERC's stated goal in promulgating Order No. 888
and related orders is to remove impediments to competition in the wholesale bulk
power marketplace and to bring more efficient and lower cost power to
electricity consumers. The Company has received authorization from FERC to sell
energy at market-based rates within and outside the geographical boundaries of
PJM.
The Company's wholesale operations include the physical delivery and
marketing of power obtained through Company-owned generation capacity, and long,
intermediate and short-term contracts. The Company maintains a net positive
supply of energy and capacity, through Company-owned generation assets and power
purchase and lease agreements, to protect it from the potential operational
failure of one of its owned or contracted power generating units. The Company
has also contracted for access to additional generation through bilateral
long-term power purchase agreements. These agreements are firm commitments
related to power generation of specific generation plants and/or are
dispatchable in nature - similar to asset ownership. The Company enters into
power purchase agreements with the objective of obtaining low-cost energy supply
sources to meet its physical delivery obligations to its customers. The Company
has also purchased firm transmission rights to ensure that it has reliable
transmission capacity to physically move its power supplies to meet customer
delivery needs. The intent and business objective for the use of its capital
assets and contracts is to provide the Company with physical power supply to
enable it to deliver energy to meet customer needs. The Company does
not use financial contracts in its wholesale marketing activities and as a
matter of business practice does not "pair off" or net settle its contracts. All
contracts result in the delivery and/or receipt of power.
17
The Company has entered into bilateral long-term contractual
obligations for sales of energy to other load-serving entities including
electric utilities, municipalities, electric cooperatives, and retail loan
aggregators. The Company also enters into contractual obligations to deliver
energy to wholesale market participants who primarily focus on the resale of
energy products for delivery. The Company provides delivery of its energy to
these customers in and out of PJM through access to Company-owned transmission
assets or rights for firm transmission.
The Company has entered into three long-term power purchase agreements
with Independent Power Producers (IPP) under which the Company makes fixed
capacity payments to the IPP in return for exclusive rights to the energy and
capacity of the generating units for a fixed period. The terms of the long-term
power purchase agreements enable the Company to supply the fuel and dispatch
energy from the plants. The plants are currently being constructed and are
scheduled to begin operations in 2000, 2001 and 2002, respectively.
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 was
not 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 FERC order expanded the Company's existing
ability to engage in wholesale marketing of power and certain associated
ancillary services at market-based rates to include transactions 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 transactions within the PJM PX in
particular and on wholesale bilateral transactions generally.
Unregulated Retail Energy Supplier
The Company's Exelon Energy division is an unregulated supplier of
generation and natural gas supply services. Exelon Energy offers competitive
generation services to residential, commercial and industrial customers
throughout Pennsylvania and natural gas supply services to large commercial and
industrial customers in Pennsylvania and New Jersey.
At December 31, 1999, Exelon Energy had 134,000 electric generation
services customers and 1,300 natural gas supply services customers. Exelon
Energy acquires generation services supplied to customers through the Company's
power marketing group. Exelon Energy purchases its natural gas supply in the
open market.
Exelon Energy is licensed by the PUC, the New Jersey Board of Public
Utilities, the Maryland Public Service Commission and the Massachusetts
Department of Telecommunications and Energy to provide energy supply in these
states. As a division of a PUC-regulated distribution company, Exelon Energy
must maintain its operations separate and distinct from the Company's
distribution business. Exelon Energy is subject to a Code of Conduct that
prohibits the sharing of information between the distribution business and
Exelon Energy that would put unrelated generation suppliers at a competitive
disadvantage. Exelon Energy has established its own infrastructure, including
its own call center and billing, pricing and procurement systems.
18
AmerGen Energy Company, LLC
In 1997, the Company and British Energy formed AmerGen to pursue
opportunities to acquire and operate nuclear generating stations in the United
States. The Company and British Energy each own a 50% equity interest in
AmerGen. The Company accounts for its investment in AmerGen under the equity
method of accounting.
In 1999, AmerGen, purchased Clinton Nuclear Power Station (Clinton) and
Three Mile Island Unit No. 1 Nuclear Generating Facility (TMI). Clinton is a BWR
nuclear facility with a capacity of 930 MW. TMI is a pressurized water reactor
nuclear facility with a capacity of 786 MW.
In 1999, AmerGen also entered into agreements to purchase Nine Mile
Point Unit No. 1 Nuclear Generating Facility, a 59% undivided interest in Nine
Mile Point Unit No. 2 Nuclear Generating Facility, Oyster Creek Nuclear
Generating Facility and Vermont Yankee Nuclear Power Station. These purchases
are expected to be completed in 2000 upon receipt of the required federal and
state approvals. In conjunction with each of the completed acquisitions, AmerGen
has received fully funded decommissioning trust funds which have sufficient
assets to fully cover the anticipated costs to decommission each nuclear plant
following its licensed life, including an annual net growth rate of 2% in
accordance with NRC regulations. AmerGen believes that the amount of the trust
funds and investment earnings thereon will be sufficient to meet its
decommissioning obligations.
Ventures Business Unit
The Company's ventures business unit consists of its infrastructure
services business, its telecommunications equity investments and other
investments.
Exelon Infrastructure Services, Inc.
In the second quarter of 1999, the Company formed EIS, an unregulated
subsidiary of the Company, to provide infrastructure services, including
infrastructure construction, operation management and maintenance services to
owners of electric, gas and telecommunications systems, including industrial and
commercial customers, utilities and municipalities.
In October 1999, EIS acquired the stock or assets of six utility
service contracting companies for an aggregate purchase price of approximately
$233 million, including $11 million of EIS stock. The purchase price also
contains estimated contingent payments of $20 million based upon the achievement
of targeted earnings of the acquired companies over a one-year period. The
acquisitions were accounted for using the purchase method of accounting.
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.
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.
19
PECO Energy Transition Trust, PECO Energy Capital Corp. and Related Entities
PETT, a statutory business trust established by the Company under the
laws of the State of Delaware and a wholly owned subsidiary of the Company, was
formed on June 23, 1998 pursuant to a trust agreement between the Company, as
grantor, First Union Trust Company, N.A., as issuer trustee, and two beneficiary
trustees appointed by the Company. PETT was created for the sole purpose of
issuing transition bonds to securitize a portion of the Company's authorized
stranded cost recovery. On March 25, 1999, PETT issued $4 billion of its
Transition Bonds, Series 1999-A. The Transition Bonds are solely obligations of
PETT secured by intangible transition property, representing the right to
collect ITC's sufficient to pay the principal and interest on the Transition
Bonds, sold by the Company to PETT.
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, 1999, the Partnership held
$128.1 million aggregate principal amount of the Subordinated Debentures.
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, 1999, the Trust II had outstanding 2,000,000 Trust II
Receipts. At December 31, 1999, 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 1999 in the aggregate amount of $4 million. Expenses of the Trust II for
1999 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 Preferred Security, Series D (Series D Preferred Securities) of
the Partnership. The Partnership is the sponsor of the Trust III. As of December
31, 1999, the Trust III had outstanding 78,105 Trust III Receipts. At December
31, 1999, 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 1999 in the
aggregate amount of $5.8 million. Expenses of the Trust III for 1999 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.
Segment Information
Segment information is incorporated herein by reference to Note 3 of
Notes to Consolidated Financial Statements included in ITEM 8. - Financial
Statements and Supplementary Data.
Competition
The Company competes in deregulated retail electric generation markets
and the national wholesale electric generation market.
Retail competition for electric generation supply in Pennsylvania
commenced in January 1999. The Company, through Exelon Energy, the Company's new
competitive supplier, actively competes for a share of the generation supply
market throughout Pennsylvania. The Company also participates in the generation
supply market in its traditional service territory through its distribution
business unit. Generation services provided by the distribution business unit
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 the distribution business
unit may choose an alternate generation supplier at any time.
For additional information, see ITEM 7. - Management's Discussion and
Analysis of Financial Condition and Results of Operations.
20
Year 2000 Readiness Disclosure
During 1999 and 1998, the Company successfully addressed, through its
Year 2000 Project (Y2K Project), 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.
The Y2K Project was divided into four main sections - Information
Technology Systems (IT Systems), Embedded Technology (devices to control,
monitor or assist the operation of equipment, machinery or plant), Supply Chain
(third-party suppliers and customers) and Contingency Planning. The IT Systems
section included both the conversion of applications software that was not Y2K
ready and the replacement of software when available from the supplier. The
Supply Chain section included the process of identifying and prioritizing
critical suppliers and communicating with them about their plans and progress in
addressing the Y2K issue.
The current estimated total cost of the Y2K Project is $61 million, the
majority of which is attributable to testing. This represents a $9 million
reduction of the previously estimated cost of the Y2K Project. This estimate
includes the Company's share of Y2K costs for jointly owned facilities. The
total amount expended on the Y2K Project through December 31, 1999 was $56
million. The Company is funding the Y2K Project from operating cash flows.
The Company's systems experienced no Y2K difficulties on December 31,
1999 or since that date. The Company's operations have not, to date, been
adversely affected by any Y2K difficulties that suppliers or customers may have
experienced. The Company's Y2K Project also successfully addressed concerns with
the date February 29, 2000. The Company will continue to monitor its systems for
potential Y2K difficulties through the remainder of 2000.
Capital Requirements
The following table shows the Company's most recent estimate of capital
requirements for 2000:
(Millions of $)
----------------
Construction .......................................... $517
New ventures (1) ...................................... 410
Long-term debt maturities and sinking funds. .......... 127
----
Total capital requirements. ....................... $1,054
====
- - ------------
(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 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, 1999 was 11.60 times. The coverage under the earnings
test of the Mortgage for the twelve months ended December 31, 1998 was 5.47
times. At December 31, 1999, 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, 1999, the Company was entitled to issue
approximately $1.64 billion of mortgage bonds without regard to the earnings and
property additions tests against previously retired mortgage bonds.
21
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, 1999 was 2.45 times. Coverage under this
earnings test of the Articles for the twelve months ended December 31, 1998 was
2.81 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:
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
Ratio of Earnings to Fixed Charges .......... 3.42 3.60 2.71 3.29 3.41
Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends .............. 3.24 3.40 2.50 3.04 3.12
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 1999 does not include the extraordinary charge against
income of $62 million ($37 million net of income taxes ), 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).
For additional information, see ITEM 7. - Management's Discussion and
Analysis of Financial Condition and Results of Operations.
Construction
The following table shows the Company's most recent estimate of capital
expenditures for plant additions and improvements for 2000:
(Millions of $)
----------------
Electric:
Production ............................... $175
Nuclear fuel ............................. 95
Transmission and distribution. ........... 195
----
Total electric ...................... 465
Gas ........................................ 40
Other ...................................... 12
----
Total. ................................... $517
====
The Company's current construction program does not include any new
generating facilities. At December 31, 1999, construction work in progress,
excluding nuclear fuel, aggregated $232 million.
Employee Matters
The Company and its subsidiaries had 11,737 employees, including
approximately 5,000 EIS employees, at December 31, 1999. The number of employees
does not include employees of joint ventures. None of the employees of the
Company or its subsidiaries, other than certain EIS employees, 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, other than certain EIS employees, have rejected union
representation. The Company expects that such petitions will continue to be
filed in the future.
22
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 22 of Notes to Consolidated Financial Statements included
in ITEM 8. - Financial Statements and Supplementary Data.
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 "Generation Business
Unit -- 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 (NJPDES) permit issued
for Salem by the New Jersey Department of Environmental Protection (NJDEP) which
requires, among other things, water intake screen modifications and wetlands
restoration. 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 costs is 42.59% and is included in the Company's capital
requirements. 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 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
commenced in the second quarter of 1999. The DRBC modified the Revised Docket to
provide that it shall remain in effect until six months after the NJDEP acts on
PSE&G's permit, or at a later date established by the DRBC.
PSE&G has informed the Company that it believes that the current
operations of Salem are in compliance with the Federal Water Pollution Control
Act (FWPCA) and will vigorously pursue its applications to continue operations
of Salem with present cooling water intake structures. The EPA, as a result of
litigation by environmental groups, is conducting a rulemaking under the FWPCA
that may result in the establishment of regulatory guidance on material issues
with respect to the FWPCA permitting decisions, such as guidance on
determinations of adverse environmental impacts and best technology available.
The rulemaking may impact NJDEP determinations with respect to PSE&G's permit
renewal applications.
23
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 have several Phase II compliance options for Keystone,
including the purchase of SO(2) 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 appealed the issuance of the EPA regulation to
the Federal Court of Appeals.
On March 3, 2000, the District of Columbia Circuit Court of Appeals
substantively upheld an October 1998 EPA final regulation to reduce summertime
regional NO(x) emissions in 19 eastern states beginning May 1, 2003. The Court's
ruling on the regulation (which is aimed at reducing the interstate transport of
ozone pollution) is expected to be appealed by at least some of the involved
litigants. This appeal may involve a request for rehearing and/or review by the
U.S. Supreme Court. On January 18, 2000, in response to petitions filed by four
northeastern states under Section 126 of the Clean Air Act (CAA), EPA issued an
additional regulation which will require NO(x) reductions from electric
generation and large industrial sources in twelve states beginning May 1, 2003.
In addition to affecting Pennsylvania emission sources, the Section 126
regulation also covers sources in Delaware, Indiana, Kentucky, Maryland,
Michigan, North Carolina, New Jersey, New York, Ohio, Virginia and West
Virginia. It is expected that EPA's Section 126 regulation will also be
litigated in the federal court. As a result of time lost due to past and current
litigation, there is a possibility that the federal program implementation date
may be delayed for some, or all, affected states.
PDEP is in the process of finalizing state regulations to implement the
federal 2003 emission reduction requirements. Pennsylvania is currently
operating under a more restrictive NO(x) program than states located to the
south and west of the Commonwealth. To calculate state NO(x) emission budgets
for the 2003 program, the new federal regulations applied a uniform reduction
requirement to the covered electric generation units in each state. Current PDEP
NO(x) regulations, as well as those to be adopted to implement the federal
requirements, 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.
24
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.
The EPA has filed complaints in several federal district courts against
11 utility companies claiming that modifications to their coal-fired electric
generating stations were implemented without pre-construction permits required
by New Source Regulations (NSR) and without conducting Prevention of Significant
Deterioration (PSD) reviews, all in violation of the CAA. The EPA complaints
were part of a new initiative targeting coal-fired electric generating stations
with emission limits higher than stations coming on line after the effective
date of CAA regulations imposing very low emission rates. The Company's
Eddystone Generating Station meets the initial age and output screening criteria
for EPA scrutiny and enforcement. To date, none of the Company's generation
stations have been targeted by EPA with information requests or site visits.
However, indications are that the EPA's initiative will extend well beyond the
11 utilities targeted to date. Findings of NSR or PSD violations of the CAA pose
risks of significant penalties. The Company believes that its activities over
the last 20 years in maintaining the equipment at its coal-fired units was
lawful and not in violation of the CAA. The Company will vigorously defend its
actions if challenged by the EPA.
Solid and Hazardous Waste
The Comprehensive Environmental Response, Compensation, and Liability
Act of 1980 and the Superfund Amendments and Reauthorization Act of 1986
(collectively CERCLA) authorize the EPA to cause potentially responsible parties
(PRPs) to conduct (or for the EPA to conduct at the PRPs' expense) remedial
action at waste disposal sites that pose a hazard to human health or the
environment. Parties contributing hazardous substances to a site or owning or
operating a site typically are viewed as jointly and severally liable for
conducting or paying for remediation and for reimbursing the government for
related costs incurred. PRPs may agree to allocate liability among themselves,
or a court may perform that allocation according to equitable factors deemed
appropriate. In addition, the Company is subject to the Resource Conservation
and Recovery Act (RCRA) which governs treatment, storage and disposal of solid
and hazardous wastes.
By notice issued in November 1986, the EPA notified over 800 entities,
including the Company, that they may be PRPs under CERCLA with respect to
releases of radioactive and/or toxic substances from the Maxey Flats disposal
site, a low-level radioactive waste disposal site near Moorehead, Kentucky,
where Company wastes were deposited. Approximately 90 PRPs, including the
Company, formed a steering committee and entered into an administrative consent
order with the EPA to conduct a remedial investigation and feasibility study
(RI/FS), which was substantially revised based on the EPA comments. In September
1991, following public review and comment, the EPA issued a Record of Decision
(ROD) 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 $800,000 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 work has commenced.
25
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 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. The EPA has approved the PRP
Group's RD work plan and based upon the RD investigation, EPA has indicated that
it is considering reducing the scope of the required remediation. EPA and the
PRPs are also involved in litigation with the site owner, concerning remediation
liability. The Company is unable to estimate its share of the costs of the
remedial activities.
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 parties successfully challenged the 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 approved the settlement in the
May of 1999. With the expiration of the public comment period in August 1999,
the settlement with the Company was effective.
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 preliminary
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. To date, no formal settlement has been
proposed.
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.
26
The Company had 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. The Company was not
required to contribute to the cleanup of this site. No other defendant has
pursued any cross-claims against the Company.
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 was allocated a total cost of $16,000 for EPA past and
future costs. The settlement was reached in September 1999.
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
(MGP) 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. Ten
other sites are currently under some degree of active study and/or remediation.
At December 31, 1999, the Company had accrued $32 million for investigation and
remediation of these MGP sites that currently can be reasonably estimated. The
Company believes that it could incur additional liabilities with respect to MGP
sites, which cannot be reasonably estimated at this time. The Company has sued a
number of insurance carriers seeking indemnity/coverage for remediation costs
associated with these former MGP sites.
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 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. The PDEP Act 2 program is a land recycling
program allowing remediation of properties more efficiently through
redevelopment. At December 31, 1999, 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.
27
Costs
At December 31, 1999, the Company had accrued $57 million for various
investigation and remediation costs that can be reasonably estimated, including
approximately $32 million for investigation and remediation of former MGP 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 2000 for compliance
with environmental requirements total approximately $7 million. In addition, the
Company may be required to make significant additional expenditures not
presently determinable.
Executive Officers of the Registrant at December 31, 1999
Age at Effective Date of Election
Name Dec. 31, 1999 Position to Present Position
- - ---- --------------- -------- --------------------------
C. A. McNeill, Jr ..... 60 Chairman of the Board, President and Chief
Executive Officer ................................ July 1, 1997
G. R. Rainey .......... 50 President and Chief Nuclear Officer, PECO
Nuclear .......................................... June 1, 1998
G. A. Cucchi .......... 50 Senior Vice President, Corporate and President,
PECO Energy Ventures. ............................ June 22, 1998
J. W. Durham .......... 62 Senior Vice President and General Counsel ......... October 24, 1988
M. J. Egan. ........... 46 Senior Vice President, Finance and Chief
Financial Officer ................................ October 13, 1997
K. G. Lawrence ........ 52 Senior Vice President, Corporate and President,
PECO Energy Distribution ......................... June 22, 1998
I. P. McLean .......... 50 President, Power Team ............................. September 22, 1999
G. N. Rhodes ...... 56 Vice President, Corporate and President
Exelon Energy..................................... April 19, 1999
W. H. Smith, III ...... 51 Senior Vice President, Business Services
Group ............................................ November 7, 1997
D. W. Woods ........... 42 Senior Vice President, Corporate and Public
Affairs .......................................... December 1, 1998
J. J. Hagan .......... 49 Senior Vice President, Nuclear Operations, PECO
Nuclear .......................................... January 26, 1999
E. M. Cavanaugh........ 43 Vice President, Electric Supply and Transmission
PECO Energy Distribution ......................... July 27, 1999
28
Age at Effective Date of Election
Name Dec. 31, 1999 Position to Present Position
- - ---- --------------- -------- --------------------------
J. B. Cotton .......... 54 Vice President, Three Mile Island, PECO
Nuclear .......................................... December 20, 1999
M. T. Coyle ........ 56 Vice President, Clinton Power Station,
PECO Nuclear...................................... December 15, 1999
D. G. DeCampli ........ 42 Vice President, Operations, PECO Energy
Distribution ..................................... July 27, 1999
J. Doering, Jr ........ 55 Vice President, Peach Bottom Atomic Power
Station, PECO Nuclear. ........................... March 2, 1998
G. N. Dudkin .......... 41 Vice President, Customer and Marketing
Services, PECO Energy Distribution ............... July 27, 1999
D. B. Fetters ......... 48 Vice President, Nuclear Acquisitions, PECO
Nuclear .......................................... August 7, 1999
J. H. Gibson .......... 43 Vice President and Controller. .................... May 31, 1998
P. E. Haviland ........ 45 Vice President, Corporate Development ............. March 4, 1998
T. P. Hill, Jr ........ 51 Vice President, Regulatory and External
Affairs, PECO Energy Distribution ................ April 9, 1998
C. A. Jacobs .......... 47 Vice President, Support Services .................. November 9, 1998
J. W. Langenbach....... 53 Vice President, Station Support, PECO Nuclear ..... December 20, 1999
C. P. Lewis ......... 36 Vice President, Finance, PECO Nuclear ............. October 13, 1999
C. A. Matthews ........ 48 Vice President, Information Technology and
Chief Information Officer ........................ July 28, 1997
J. B. Mitchell ........ 51 Vice President, Treasury and Evaluation, and
Treasurer ........................................ December 1, 1994
J. A. Muntz .......... 43 Vice President, Fossil Operations.................. January 26, 1999
J. D. von Suskil ...... 53 Vice President, Limerick Generating Station,
PECO Nuclear ..................................... January 26, 1998
R. G. White ........... 41 Vice President, Corporate Planning. ............... September 28, 1998
K. K. Combs ........... 49 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 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.
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 joining the Company in 1999, Mr. McLean was Group Vice
President of Engelhard Corporation.
Prior to joining the Company in 1999, Mr. Rhodes was Chief Marketing
Officer with Aerial Communications, Inc. and Vice President, Business
Development/Marketing with Sprint Corporation.
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 his election to his current position in 1999, Mr. Hagen was
Senior Vice President, Nuclear Operations, Vice President Station Support, Vice
President, Operations with Entergy Operations, Inc., General Manager, Operations
with Entergy Operations, Inc. and Vice President, Electric Power Generation with
Public Service Electric and Gas Company.
Prior to her election to her current position, Ms. Cavanaugh was
Assistant General Counsel and Director of Risk Management.
29
Prior to his election to his current position in 1999, Mr. Coyle was
Assistant Vice President, Clinton Power Station, Senior Manager, Nuclear
Generation, Deputy Commander for Engineering, U.S. Navy and Fleet Maintenance
Officer, U. S. Navy.
Prior to his election to his current position in 1999, Mr. DeCampli was
Director of Engineering Services, Director of Transmission and Substations and
Director of Reengineering.
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 Development and
Senior Director of Materials Management with Rhone-Polenc Rorer Corporation.
Prior to joining the Company in 1999, Mr. Langenbach was Vice President
and Director of Three Mile Island Power Station, Director Materials and Services
and Outage Director, Oyster Creek Power Station with GPU Nuclear, Inc.
Prior to his election to his current position in 1999, Mr. Lewis was
SBU Vice President of Finance, Director Nuclear Planning and Development and
Director of Corporate Development.
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. Muntz was Vice
President Electric Supply and Transmission, Director of Nuclear Planning and
Development and Director, Site Engineering, Limerick Generating Station.
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, 1995:
Mr. Cotton was Vice President, Special Projects, 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 Vice
President, Operations, Acting General Manager -- Power Delivery, Regional
Director Power Delivery and Manager -- Electric Operations; Mr. Fetters was Vice
President -- Nuclear Development, Vice President -- Nuclear Planning and
Development, Director -- Nuclear Engineering, Director -- Limerick Maintenance
and a Project Manager.
There are no family relationships among directors or executive officers
of the Company.
30
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, 1999:
Net Generating Estimated
Capacity (1) Retirement
Station Location (Kilowatts) Year
------- -------- ----------- ----
Nuclear
Limerick ............................ Limerick Twp., PA ................... 2,284,000 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 .................................................................. 9,296,800
- - ------------
(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 2000.
The following table sets forth the Company's major transmission and
distribution lines in service at December 31, 1999:
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, 1999, 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, 1999:
Pipeline Miles
---------------
Transmission .................... 28
Distribution .................... 5,884
Service piping .................. 4,726
-----
Total ........................ 10,638
======
31
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 25 natural gas city
gate stations at various locations throughout its gas service territory.
At December 31, 1999, the Company had 644 miles of fiber optic cable.
Also, an additional 211 miles of fiber cable network is owned jointly by the
Company and Adelphia Business Solutions.
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 6 of Notes to Consolidated Financial Statements
included in ITEM 8. - Financial Statements and Supplementary Data.
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. For additional information, see ITEM 1. Business - Generation
Business Unit-Nuclear. 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 May 27, 1998, the United States Department of Justice, on behalf of
the Rural Utilities Service (RUS) 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 (Louisiana District Court) arising out of the Company's
termination of the contract to purchase Cajun's interest in the River Bend
nuclear power plant. In the complaint, RUS seeks the full purchase price of the
30% interest in the River Bend nuclear power plant, that is, $50 million, plus
interest and the Trustee seeks alleged consequential damages to Cajun's Chapter
11 estate as a result of the termination. On August 16, 1998, the Company moved
to dismiss the complaint filed by the United States and the Trustee. On July 13,
1999, the Louisiana District Court denied the Company's Motion to Dismiss the
Complaint. The court expressly reserved to the parties the right to file a
motion for summary judgment. The parties to the litigation are presently engaged
in pre-trial discovery. While the Company cannot predict the outcome of this
matter, the Company believes that it validly exercised its right of termination
and did not breach the agreement.
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 alleged that the significant cracking of the steam generator tubes was 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 alleged
violations of both the federal and New Jersey Racketeer Influenced and Corrupt
Organizations Acts (RICO), fraud, negligent misrepresentation and breach of
contract. Westinghouse filed a motion for summary judgment on the grounds that
the claim of the plaintiffs is barred by the statute of limitations. On January
27, 2000, the Company, PSE&G, Atlantic Electric Company, Delmarva and
Westinghouse Electric Corporation entered into an agreement resolving all
litigation concerning this matter.
The Company is involved in tax appeals regarding two of its nuclear
facilities, Limerick (Montgomery County) and Peach Bottom (York County). The
Company is also involved in the tax appeal for Three Mile Island Unit No. 1
Nuclear Generating Facility (Dauphin County) through AmerGen. The Company does
not believe the outcome of these matters will have a material adverse effect on
the Company's results of operations or financial condition.
32
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 February 25, 2000, there were 129,573 owners of record of
the Company's common stock.
The following table sets forth the quarterly high, low and closing
prices and dividends for the Company's common stock on the New York Stock
Exchange for the past two years.
1999 1998
Fourth Third Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
High price $38 13/16 $44 3/16 $50 1/2 $46 7/16 $42 3/16 $36 3/4 $30 5/8 $24 11/16
Low price $31 1/2 $35 7/8 $41 7/8 $35 1/4 $36 1/2 $28 1/2 $21 3/16 $18 7/8
Close $34 3/4 $37 1/2 $41 7/8 $46 1/4 $41 3/4 $36 3/4 $29 3/16 $22 1/8
Dividends $0.25 $0.25 $0.25 $0.25 $0.25 $0.25 $0.25 $0.25
The book value of the Company's common stock at December 31, 1999 was
$9.78 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, 1999, such capital ($1.8 billion) amounted to about 9 times the
liquidating value of the outstanding preferred stock ($193.1 million).
The Company may not declare dividends on any shares of its capital
stock in the event that: (1) the Company exercises its right to extend the
interest payment periods on the Subordinated Debentures which were issued to the
Partnership; (2) the Company defaults on its guarantee of the payment of
distributions on the Series C or Series D 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
The selected consolidated financial data presented below has been
derived from the audited financial statements of the Company. This data is
qualified in its entirety by reference to, and should be read in conjunction
with the Company's Consolidated Financial Statements and Management's Discussion
and Analysis of Financial Condition and Results of Operations included elsewhere
herein.
Summary of Earnings and Financial Condition For the Years Ended December 31,
In Millions, except per share data 1999 1998 1997 1996 1995 1994
Income Data
Operating Revenues $5,437 $5,263 $ 4,601 $4,284 $4,186 $4,041
Operating Income 1,409 1,286 1,006 1,249 1,401 1,064
Income before Extraordinary Item 619 532 337 517 610 427
Extraordinary Item (net of income taxes) (37) (20) (1,834) - - -
Net Income (Loss) 582 513 (1,497) 517 610 427
Earnings (Loss) Applicable to Common Stock 570 500 (1,514) 499 587 389
Earnings per Average Common Share Before
Extraordinary Item (dollars) $ 3.10 $ 2.33 $ 1.44 $ 2.24 $ 2.64 $ 1.76
Extraordinary Item (per share) (0.19) (0.09) (8.24) - - -
------ ------ ------- ------ ------ ------
Earnings (Loss) per Average Common Share $ 2.91 $ 2.24 $ (6.80) $ 2.24 $ 2.64 $ 1.76
====== ====== ======= ====== ====== ======
Dividends per Common Share (dollars) $ 1.00 $ 1.00 $ 1.80 $1.755 $ 1.65 $1.545
====== ====== ======= ====== ====== ======
Common Stock Equity (per share) $ 9.78 $13.61 $ 12.25 $20.88 $20.40 $19.41
====== ====== ======= ====== ====== ======
Average Shares of Common Stock Outstanding (millions) 196.3 223.2 222.5 222.5 221.9 221.6
====== ====== ======= ====== ====== ======
33
At December 31,
In Millions 1999 1998 1997 1996 1995 1994
Balance Sheet Data
Current Assets $ 1,213 $ 582 $ 1,003 $ 420 $ 426 $ 427
Property, Plant and Equipment, net 5,045 4,804 4,671 10,942 10,939 11,003
Deferred Debits and Other Assets 6,862 6,662 6,683 3,899 3,944 3,992
------- ------- ------- ------- ------- -------
Total Assets $13,120 $12,048 $12,357 $15,261 $15,309 $15,422
======= ======= ======= ======= ======= =======
Current Liabilities $ 1,304 $ 1,735 $ 1,619 $ 1,103 $ 1,052 $ 850
Long-Term Debt 5,969 2,920 3,853 3,936 4,199 4,786
Deferred Credits and Other Liabilities 3,753 3,756 3,576 4,982 4,933 4,892
COMRPS 128 349 352 302 302 221
Mandatorily Redeemable Preferred Stock 56 93 93 93 93 93
Shareholders' Equity 1,910 3,195 2,864 4,845 4,730 4,580
------- ------- ------- ------- ------- -------
Total Liabilities and Shareholders' Equity $13,120 $12,048 $12,357 $15,261 $15,309 $15,422
======= ======= ======= ======= ======= =======
34
+-ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
General
On September 22, 1999, the Company and Unicom Corporation (Unicom) entered into
an Agreement and Plan of Exchange and Merger providing for a merger of equals.
On January 7, 2000, the Agreement and Plan of Exchange and Merger was amended
and restated (Merger Agreement). The Merger Agreement has been approved by both
companies' Boards of Directors. The transaction will be accounted for as a
purchase with the Company as acquiror.
The Merger Agreement provides for (a) the exchange of each share of outstanding
common stock, no par value, of the Company for one share of common stock of the
new company, Exelon Corporation (Exelon) (Share Exchange) and (b) the merger
of Unicom with and into Exelon (Merger and together with the Share Exchange,
Merger Transaction). In the Merger, each share of the outstanding common
stock, no par value, of Unicom will be converted into 0.875 shares of common
stock of Exelon plus $3.00 in cash. In the Merger Agreement, the Company and
Unicom agree to repurchase approximately $1.5 billion of common stock prior to
the closing of the Merger, with Unicom to repurchase approximately $1.0 billion
of its common stock, and the Company to repurchase approximately $500 million of
its common stock. As a result of the Share Exchange, the Company will become a
wholly owned subsidiary of Exelon. As a result of the Merger, Unicom will cease
to exist and its subsidiaries, including Commonwealth Edison Company, an
Illinois corporation (ComEd), will become subsidiaries of Exelon. Following the
Merger Transaction, Exelon will be a holding company with two principal utility
subsidiaries, ComEd and the Company.
The Merger Transaction is conditioned, among other things, upon the approvals of
the common shareholders of both companies and the approval of certain regulatory
agencies. The companies have filed an application with the Securities and
Exchange Commission (SEC) to register Exelon as a holding company under the
Public Utility Holding Company Act of 1935.
The Company is engaged principally in the production, purchase, transmission,
distribution and sale of electricity to residential, commercial, industrial and
wholesale customers and the distribution and sale of natural gas to residential,
commercial and industrial customers. Pursuant to the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Competition Act), the
Commonwealth of Pennsylvania has required the unbundling of retail electric
services in Pennsylvania into separate generation, transmission and distribution
services with open retail competition for generation services. Since the
commencement of deregulation in 1999, the Company serves as the local
distribution company providing electric distribution services in its franchised
service territory in southeastern Pennsylvania and bundled electric service to
customers who do not choose an alternate electric generation supplier. The
Company engages in the wholesale marketing of electricity on a national basis.
Through its Exelon Energy division, the Company is a competitive generation
supplier offering competitive energy supply to customers throughout
Pennsylvania. The Company's infrastructure services subsidiary, Exelon
Infrastructure Services, Inc. (EIS), provides utility infrastructure services to
customers in several regions of the United States. The Company owns a 50%
interest in AmerGen Energy Company, LLC (AmerGen), a joint venture with British
Energy, Inc., a wholly-owned subsidiary of British Energy plc (British Energy),
to acquire and operate nuclear generating facilities. The
Company also participates in joint ventures which provide telecommunications
services in the Philadelphia metropolitan region.
At December 31, 1997, the Company determined that its electric generation
business no longer met the criteria of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." In connection with the discontinuance of SFAS No. 71, 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. See Note 5 of Notes to Consolidated Financial Statements.
In May 1998, the Pennsylvania Public Utility Commission (PUC) entered an Opinion
and Order (Final Restructuring Order) approving a joint petition and settlement
of the Company's restructuring case. Under the Final Restructuring Order, the
Company received approval to recover stranded costs of $5.3 billion over 12
years beginning January 1, 1999 with a return on the unamortized balance of
10.75%. The Final Restructuring Order provides for the phase-in of customer
choice of electric generation supplier (EGS) for all customers: one-third of the
peak load of each customer class on January 1, 1999; one-third on January 2,
1999; and the remaining one-third on January 1, 2000. The Final Restructuring
Order called for an across-the-board retail electric rate reduction of 8% in
1999. This rate reduction decreased to 6% in 2000. At December 31, 1999,
approximately 17% of the Company's residential load, 39% of its commercial load
and 59% of its industrial load were purchasing generation service from an
alternative EGS. As of that date, Exelon Energy, the Company's alternative EGS,
was providing electric generation service to approximately 134,000 business and
residential customers located throughout Pennsylvania. See Note 4 of Notes to
Consolidated Financial Statements.
On March 25, 1999, PECO Energy Transition Trust (PETT), a wholly owned
subsidiary of the Company, issued $4 billion of PETT Transition Bonds
(Transition Bonds) to securitize a portion of the Company's stranded cost
recovery. In accordance with the terms of the Competition Act, the Company has
utilized the proceeds from the issuance of the Transition Bonds principally to
reduce stranded costs including related capitalization.
The Company expects that competition for both retail and wholesale generation
services will substantially affect its future results of operations. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Outlook."
Results of Operations
The Company's Consolidated Statements of Income for 1998 and 1997 reflect the
reclassification of the results of operations of the Company's non-regulated
retail energy supplier, Exelon Energy, from Other Income and Deductions.
36
In 1999, the Company completed the redesign of its internal reporting structure
to separate its distribution, generation, and ventures operations into business
units and provide financial and operational data on the same basis to senior
management. The Company's distribution business unit consists of its regulated
operations including electric transmission and distribution services, retail
sales of generation services and retail gas sales and services. The Company's
generation business unit consists of its generation assets, its power marketing
group, its unregulated retail energy supplier and its investment in AmerGen. The
Company's ventures business unit consists of its infrastructure services
business, its telecommunications equity investments and other investments.
General corporate expenses include the cost of executive management, corporate
accounting and finance, information technology, risk management, human
resources, and legal functions and employee benefits.
In the fourth quarter of 1999, EIS acquired six infrastructure services
companies. EIS, formed in the second quarter of 1999, provides infrastructure
services including infrastructure construction, operation management and
maintenance services to owners of electric, gas and telecommunications systems,
including industrial and commercial customers, utilities and municipalities.
Significant Operating Items
Revenue and Expense
Items as a Percentage Percentage
of Operating Revenue Dollar Changes
1999- 1998-
1999 1998 1997 1998 1997
89% 92% 90% Electric -% 16%
9% 8% 10% Gas 11% (4%)
2% -% -% Infrastructure Services 100% -%
100% 100% 100% Total Operating Revenues 3% 14%
39% 34% 28% Fuel and Energy Interchange 19% 39%
25% 22% 31% Operating and Maintenance 22% (20%)
-% 2% -% Early Retirement and Separation Programs (100%) 100%
4% 12% 13% Depreciation and Amortization (63%) 11%
5% 5% 7% Taxes Other Than Income (6%) (10%)
73% 75% 79% Total Operating Expenses 1% 10%
27% 25% 21% Operating Income 10% 28%
(8%) (7%) (8%) Interest Charges 15% (6%)
(1%) (1%) -% Equity in Losses of Telecommunications
Investments (30%) 283%
-% (1%) 1% Other Income and Deductions 188% (217%)
18% 16% 14% Income Before Income Taxes and
Extraordinary Item 15% 35%
7% 6% 6% Income Taxes 12% 9%
11% 10% 8% Income Before Extraordinary Item 16% 58%
Year Ended December 31, 1999 Compared To Year Ended December 31, 1998
Operating Revenues
Electric revenues increased $17 million to $4,847 million in 1999. The increase
was primarily attributable to higher revenues from the generation business unit
of $589 million, partially offset by lower revenues from the distribution
business unit of $572 million.
The increase from the generation business unit was attributable to $473 million
from increased volume in Pennsylvania as a result of the sale of competitive
electric generation services by Exelon Energy, increased wholesale revenues of
$133 million from the marketing of excess generation capacity as a result of
retail competition and revenues of $99 million from the sale of generation from
Clinton Nuclear Power Station (Clinton) to Illinois Power (IP), partially offset
by the inclusion of $116 million of PJM Interconnection, L.L.C. (PJM) network
transmission service revenue in 1998. The decrease from the distribution
business unit was primarily attributable to lower volume associated with the
effects of retail competition of $508 million and $278 million related to the 8%
across-the-board rate reduction mandated by the Final Restructuring Order. These
decreases were partially offset by $149 million of PJM network transmission
service revenue and $59 million related to higher volume as a result of weather
conditions as compared to 1998. PJM network transmission service revenues and
charges which commenced April 1, 1998 were recorded in the generation business
unit in 1998 but are being recognized by the distribution business unit in 1999
as a result of the Federal Energy Regulatory Commission (FERC) approval of the
PJM Regional Transmission Owners' rate case settlements. Stranded cost recovery
is included in the Company's retail electric rates beginning January 1, 1999.
Under its Amended Management Agreement with IP, effective April 1, 1999, the
Company was responsible for the payment of all direct operating and maintenance
(O&M) costs and direct capital costs incurred by IP and allocable to the
operation of Clinton. These costs are reflected in the Company's O&M expenses.
IP was responsible for fuel and indirect costs such as pension benefits, payroll
taxes and property taxes. Following the restart of Clinton on June 2, 1999, and
through December 15, 1999, the Company agreed to sell 80% of the output of
Clinton to IP. The remaining output was sold by the Company in the wholesale
market. Under a separate agreement with the Company, British Energy agreed to
share 50% of the costs and revenues associated with the Amended Management
Agreement. Effective December 15, 1999, AmerGen acquired Clinton. Accordingly,
the results of operations of Clinton have been accounted for under the equity
method of accounting in the Company's Consolidated Statements of Income since
the acquisition date.
Gas revenues increased $48 million, or 11%, to $481 million in 1999 primarily as
a result of higher revenues from the distribution business unit of $50 million.
The increase in the distribution business unit was primarily attributable to
increased volume as a result of weather conditions of $27 million and increased
volume from new and existing customers of $20 million as compared to 1998. This
increase was partially offset by lower revenues from the generation business
unit of $2 million, primarily attributable to lower volume from existing
customers of Exelon Energy.
Infrastructure services revenues increased $109 million as a result of growth
from the EIS acquisitions in 1999.
Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased $349 million, or 19%, to $2,145
million in 1999. The increase was attributable to higher fuel and energy
interchange expenses associated with the distribution business unit of $187
million and the generation business unit of $162 million.
The increase from the distribution business unit was attributable to $98 million
of PJM network transmission service charges, $51 million of purchases in the
spot market and $38 million of additional volume as a result of weather
conditions. The increase from the generation business unit was primarily
attributable to $565 million related to increased volume from Exelon Energy
sales and a $36 million reserve related to the Massachusetts Health and
Education Authority (HEFA) contract as a result of higher than anticipated cost
of supply in the New England power pool. These increases were partially offset
by $277 million of fuel savings from wholesale operations as a result of lower
volume and efficient operation of the Company's generating assets, the inclusion
of PJM network transmission service charges of $116 million in 1998, and the
reversal of $27 million in reserves associated with the Grays Ferry Cogeneration
Partnership (Grays Ferry) in connection with the final settlement of litigation
and expected prices of electricity over the remaining life of the power purchase
agreements. In addition, the Company experienced $19 million of fuel savings
associated with the full return to service of Salem Generating Station (Salem)
in April 1998 which decreased the need to purchase power to replace the output
from these units.
As a percentage of revenue, fuel and energy interchange expense was 39% as
compared to 34% in 1998. The increase was primarily attributable to reduced
margins resulting from retail competition for generation services.
Operating and Maintenance Expense
O&M expense, exclusive of the Early Retirement and Separation charge of $124
million incurred in 1998, increased $249 million, or 22%, to $1,384 million in
1999. As a percentage of revenue, O&M expense was 25% as compared to 22% in
1998. The increase in O&M expense was attributable to higher O&M expenses
associated with the generation business unit of $112 million, the ventures
business unit of $109 million and corporate of $28 million.
The increase from the generation business was primarily a result of $70 million
related to Clinton, $24 million related to the growth of Exelon Energy, $13
million of charges related to the abandonment of two information systems
implementations, $10 million associated with the Salem inventory write-off for
excess and obsolete inventory, and $7 million related to the true-up of 1998
reimbursement of joint-owner expenses. These decreases were partially offset by
$10 million of lower O&M expenses as a result of the full return to service of
Salem in April 1998. The increase from the ventures business unit was related to
the infrastructure services business. In addition, the Company incurred
additional corporate costs including $15 million associated with Year 2000 (Y2K)
remediation expenditures, $11 million of compensation expense and $9 million
related to nuclear property insurance, partially offset by $17 million of lower
pension and post-retirement benefit expense primarily as a result of the
performance of the investments in the Company's pension plan. The distribution
business unit's O&M expenses were consistent with the prior year and included
$11 million of additional expenses related to restoration activities as a result
of Hurricane Floyd which were offset by lower electric transmission and
distribution expenses.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $406 million, or 63%, to $237
million in 1999. As a percentage of revenue, depreciation and amortization
expense was 4% as compared to 12% in 1998. The decrease in depreciation and
amortization expense was associated with the December 1997 restructuring charge
through which the Company wrote down a significant portion of its generating
plant and regulatory assets. In connection with this restructuring charge, the
Company reduced generation-related assets by $8.4 billion, established a
regulatory asset, Deferred Generation Costs Recoverable in Current Rates of $424
million, which was fully amortized in 1998, and established an additional
regulatory asset, Competitive Transition Charge (CTC) of $5.3 billion, which
will begin to be amortized in 2000 in accordance with the terms of the Final
Restructuring Order.
Taxes Other Than Income
Taxes other than income decreased $18 million, or 6%, to $262 million in 1999.
As a percentage of revenue, taxes other than income were 5%, which was
consistent with 1998. The decrease in taxes other than income was primarily
attributable to a $34 million credit related to an adjustment of the Company's
Pennsylvania capital stock tax base as a result of the 1997 restructuring
charge, partially offset by an increase of $17 million in real estate taxes as a
result of changes in tax laws for utility property in Pennsylvania.
Interest Charges
Interest charges consist of interest expense, distributions on Company Obligated
Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) and
Allowance for Funds Used During Construction (AFUDC). Interest charges increased
$55 million, or 15%, to $413 million in 1999. As a percentage of revenue,
interest charges were 8% as compared to 7% in 1998. The increase in interest
charges was primarily attributable to interest on the Transition Bonds of $179
million, partially offset by a $98 million reduction in interest charges
resulting from the use of Transition Bond proceeds to repay long-term debt and
COMRPS. In addition, the Company's ongoing program to reduce or refinance higher
cost, long-term debt reduced interest charges by $26 million.
Equity in Losses of Telecommunications Investments
Equity in losses of telecommunications investments decreased $17 million or 30%,
to $38 million in 1999. The lower losses are attributable to customer base
growth for each of the Company's telecommunications joint ventures.
Other Income and Deductions
Other income and deductions, excluding interest charges and equity in losses of
telecommunications investments, increased $40 million, or 188%, to income of $19
million in 1999 as compared to a loss of $21 million in 1998. The increase in
other income and deductions was primarily attributable to $28 million of
interest income earned on the unused portion of the Transition Bond proceeds
prior to application, $14 million of gain on the sale of assets, a $10 million
donation to a City of Philadelphia street lighting project in 1998 and a $7
million write-off of a non-regulated business venture in 1998. These increases
were partially offset by a $15 million write-off of the investment in Grays
Ferry in connection with the settlement of litigation.
Income Taxes
The effective tax rate was 36.6% in 1999 as compared to 37.5% in 1998. The
decrease in the effective tax rate was primarily attributable to an income tax
benefit of approximately $11 million related to the favorable resolution of
certain outstanding issues in connection with the settlement of an Internal
Revenue Service audit and tax benefits associated with the implementation of
state tax planning strategies, partially offset by the non-recognition for state
income tax purposes of certain operating losses.
Extraordinary Items
In 1999, the Company incurred extraordinary charges aggregating $62 million ($37
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment of $811 million of First
Mortgage Bonds with a portion of the Transition Bond proceeds and the
refinancing of $156 million of pollution control notes.
In 1998, the Company incurred extraordinary charges aggregating $33 million ($20
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment of $525 million of First
Mortgage Bonds.
Preferred Stock Dividends
Preferred stock dividends decreased $1 million or 7%, to $12 million in 1999.
The decrease was attributable to the retirement of $37 million of preferred
stock in August 1999 with a portion of the Transaction Bond proceeds.
Earnings
Earnings applicable to common stock increased $71 million, or 14%, to $570
million in 1999. Earnings per average common share increased $0.67 per share or
30%, to $2.91 per share in 1999, reflecting the increase in net income and a
decrease in the weighted average shares of common stock outstanding as a result
of the repurchase of approximately 44.1 million shares with a portion of the
Transition Bond proceeds.
Year Ended December 31, 1998 Compared To Year Ended December 31, 1997
Operating Revenues
Electric revenues increased $680 million, or 16%, to $4,830 million in 1998. The
increase was attributable to higher revenues from the generation business unit
of $682 million, partially offset by lower revenues from the distribution
business unit of $2 million.
The increase from the generation business unit was primarily attributable to
increased wholesale revenues of $663 million as a result of higher volume
attributable to more favorable weather and market conditions and revenues
associated with the pilot program for retail competition of $19 million which
commenced in 1998. The decrease from the distribution business unit was
primarily attributable to a greater portion of its volume being derived from
customers in lower rate classes of $57 million, partially offset by increased
volume as a result of weather conditions of $55 million.
Gas revenues decreased $18 million, or 4%, to $433 million in 1998. The decrease
was attributable to lower revenues from the distribution business unit of $52
million, partially offset by higher revenues from the generation business unit
of $34 million.
The decrease from the distribution unit was primarily attributable to lower
volume as a result of less favorable weather conditions of $47 million and lower
volume from existing customers of $5 million. The increase from the generation
business unit was attributable to gas revenues from gas deregulation pilot
program outside of Pennsylvania of $34 million.
Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased $506 million, or 39%, to $1,796
million in 1998. The increase was attributable to higher fuel and energy
interchange expenses associated with the generation business unit of $532
million, partially offset by lower fuel and energy interchange expenses from the
distribution business unit of $26 million.
The increase from the generation business unit was attributable to increased
volume from wholesale operations of $608 million and additional fuel expense
related to the pilot program for retail competition of $44 million, partially
offset by fuel savings of $120 million associated with the full return to
service of Salem in April 1998 which decreased the need to purchase power to
replace the output from these units. The decrease from the distribution business
unit was primarily attributable to lower gas volume associated with less
favorable weather conditions.
As a percentage of revenue, fuel and energy interchange expenses were 34% as
compared to 28% in 1997. The increase was primarily attributable to increased
energy interchange purchases to support increased wholesale volume.
Operating and Maintenance Expense
Exclusive of certain one-time charges totaling $187 million that occurred in
1997, O&M expense decreased $93 million, or 7%, to $1,135 million in 1998. As a
percentage of revenue, operating and maintenance expenses were 22% as compared
to 31% in 1997. The decrease in O&M expense was attributable to lower O&M
expense associated with the distribution business unit of $41 million, corporate
of $34 million, and the generation business unit of $18 million.
The one-time charges incurred in 1997 consisted of $37 million for environmental
remediation, $33 million as a result of a change in fringe benefit policies
relating to sick and vacation time, $27 million for joint-owner expenses related
to the discontinuance of SFAS No. 71, $24 million in workers' compensation claim
reserves, $21 million for excess and obsolete inventory, $16 million for the
write-off of information systems development charges in accordance with EITF
Issue 97-13, "Accounting for Costs Incurred in Connection with a Consulting
Contract or an Internal Project That Combines Business Process Reengineering and
Information Technology Transformation," $13 million for the write-off of a
customer service information system and $16 million of other reserves including
the write-off of appliance sale accounts receivable and losses on the sales of
real estate.
The decrease from the distribution business unit was primarily the result of
lower uncollectible expenses of $28 million as a result of the implementation of
new collection procedures and lower transmission and distribution expenses of
$27 million as a result of system reliability improvements made in 1997. These
decreases were partially offset by a $12 million reserve for Customer Assistance
Program receivables mandated by the Final Restructuring Order. The decrease from
corporate was primarily attributable to lower pension expense of $31 million as
a result of the performance of the investments in the Company's pension plan,
lower property insurance expense of $14 million, lower post-retirement benefit
expense of $14 million as a result of the reclassification of these expenses to
Deferred Generation Costs Recoverable in Current Rates and lower workers
compensation expense of $11 million. These decreases were partially offset by
Y2K remediation expenditures of $15 million. The decrease from the generation
business unit was primarily attributable to the full return to service of Salem
which resulted in lower restart expenses of $38 million, partially offset by
increased power marketing expenses of $20 million.
Early Retirement and Separation Programs
In April 1998, the Board of Directors authorized the implementation of a
retirement incentive program and an enhanced severance benefit program. The
retirement incentive program allowed employees age 50 and older, who have been
designated as excess or who are in job classifications facing reduction, to
retire from the Company. The enhanced severance benefit program provided
non-retiring excess employees with fewer than ten years of service benefits
equal to two weeks pay per year of service. Non-retiring excess employees with
more than ten years of service received benefits equal to three weeks pay per
year of service.
In 1998, the Company incurred a charge of $125 million ($74 million, net of
income taxes) for its Early Retirement and Separation Program relating to 1,157
employees across the Company who were considered excess or were in job
classifications facing reduction. Of the 1,157 employees, 711 were eligible for
and agreed to take the retirement incentive program. The remaining employees
were eligible for the enhanced severance benefit program. As of December 31,
1999, 497 employees were eligible for and have taken the retirement incentive
program and 502 employees were terminated with the enhanced severance benefit
program. The remaining employees are scheduled for termination through the end
of June 2000.
The charge for Early Retirement and Separation Program consisted of the
following: $121 million for the actuarially determined pension and other
postretirement benefits costs and $4 million for outplacement services costs and
the continuation of benefits for one year. Approximately $0.8 million of the
$125 million charge was related to the Company's non-utility operations and
accordingly was recorded in Other Income and Deductions. The reserve for
separation benefits was approximately $47 million, of which $28 million was paid
through December 31, 1999. The remaining balance of $19 million is expected to
be paid by June 2000. Retirement benefits of approximately $78 million are being
paid to the retirees over their lives. All cash payments related to the early
retirement and severance program are expected to be funded through the assets of
the Company's Service Annuity Plan.
Depreciation and Amortization Expense
Depreciation and amortization expense increased $62 million, or 11%, to $643
million in 1998. As a percentage of revenue, depreciation and amortization
expense was 12% as compared to 13% in 1997. The increase in depreciation and
amortization expense was primarily associated with the amortization of Deferred
Generation Costs Recoverable in Current Rates during 1998. Included in this
amortization were $37 million of charges that were included in operating and
maintenance expense and interest expense in 1997.
Taxes Other Than Income
Taxes other than income decreased $31 million, or 10%, to $280 million in 1998.
As a percentage of revenue, taxes other than income were 5%, as compared to 7%
in 1997. The decrease in taxes other than income was primarily attributable to
lower real estate taxes of $14 million, lower gross receipts tax of $8 million
and lower capital stock tax of $5 million.
Interest Charges
Interest charges decreased $22 million, or 6%, to $358 million in 1998. As a
percentage of revenue, interest charges were 7% as compared to 8% in 1997. The
decrease in interest charges was primarily attributable to interest savings of
$18 million from the Company's program to reduce and/or refinance higher cost,
long-term debt and the discontinuance of amortization of the loss on reacquired
debt of $16 million related to electric generation operations as of December 31,
1997. These decreases were partially offset by $11 million of lower AFUDC and
capitalized interest resulting from fewer projects in the construction base in
1998 and the replacement of $62 million of preferred stock with COMRPS in the
third quarter of 1997.
Equity in Losses of Telecommunications Investments
Equity in losses of telecommunications investments increased $40 million or
283%, to $54 million in 1998. The increased losses were principally attributable
to the first full year of service for the Company's telecommunications joint
ventures in 1998. Both of the Company's telecommunications joint ventures
commenced operations in 1997.
Other Income and Deductions
Other income and deductions, excluding interest charges and equity in losses of
telecommunications investments, decreased $39 million, or 217% to a loss of $21
million in 1998 as compared to a gain of $18 million in 1997. The decrease in
other income and deductions was primarily attributable to a $70 million
settlement of litigation arising from the shutdown of Salem in 1997, a $10
million donation to a City of Philadelphia street lighting project and a $7
million write-off of a non-regulated business venture. These decreases were
partially offset by a $14 million settlement of a power purchase agreement, $17
million of interest income related to a gross receipts tax refund and a $20
million write-off of a telecommunications investment in 1997.
Income Taxes
The effective tax rate was 37.5% in 1998 as compared to 46.5% in 1997. The
decrease in the effective tax rate was primarily attributable to the full
normalization of deferred taxes associated with deregulated generation plant.
Extraordinary Items
In 1998, the Company incurred extraordinary charges aggregating $33 million ($20
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment of $525 million of First
Mortgage Bonds.
In 1997, the Company recorded an extraordinary charge of $3.1 billion ($1.8
billion, net of taxes) for electric generation-related stranded costs that will
not be recovered from customers.
Preferred Stock Dividends
Preferred stock dividends decreased $4 million or 22%, to $13 million in 1998.
The decrease was attributable to the replacement of $62 million of preferred
stock with COMRPS in the third quarter of 1997.
Earnings
Earnings applicable to common stock increased $2,013 million to $500 million in
1998. Earnings per average common share increased $9.04 per share from a loss of
$6.80 per share in 1997 to income of $2.24 per share in 1998. These increases
reflect the effects of the restructuring charge incurred in 1997 and the
increase in income before extraordinary item.
Liquidity and Capital Resources
The Company's capital resources are primarily provided by internally generated
cash flows from utility operations and, to the extent necessary, external
financing. Capital resources are used primarily to fund the Company's capital
requirements, including investments in new and existing ventures, to repay
maturing debt and to make preferred and common stock dividend payments.
On March 25, 1999, PETT issued $4 billion of its Transition Bonds to securitize
a portion of the Company's authorized stranded cost recovery. PETT used the
$3.95 billion of proceeds from the issuance of Transition Bonds to purchase the
Intangible Transition Property (ITP) from the Company. In accordance with the
Competition Act, the Company utilized the proceeds from the securitization of a
portion of its stranded cost recovery principally to reduce stranded costs
including related capitalization. The Company utilized the net proceeds, and
interest income earned on the net proceeds, to repurchase 44.1 million shares of
common stock for an aggregate purchase price of $1,705 million and $150 million
of accounts receivable; to retire: $811 million of First Mortgage Bonds, a $400
million term loan, $532 million of commercial paper, a $139 million capital
lease obligation and $37 million of preferred stock; to redeem $221 million of
COMRPS; and to pay $25 million of debt issuance costs.
As a result of the issuance of the Transition Bonds and the application of the
proceeds thereof, at December 31, 1999, the Company's capital structure
consisted of 21.6% common equity; 4.0% preferred stock and COMRPS (which
comprised 1.6% of the Company's total capitalization structure); and 74.4%
long-term debt including Transition Bonds issued by PETT (which comprised 64.8%
of the Company's long-term debt).
The weighted average cost of debt and preferred securities that have been
retired was approximately 7.2%. The additional interest expense associated with
the Transition Bonds, which currently have an effective interest rate of
approximately 5.8%, is partially offset by the interest savings associated with
the debt and preferred securities that have been retired. The Company currently
estimates that the impact of this additional expense, combined with the
reduction in common equity, will result in earnings per share benefits of
approximately $0.50 in 2000 as compared to $0.28 in 1999.
The Transition Bonds are solely obligations of PETT, secured by the ITP sold by
the Company to PETT, but are included in the consolidated long-term debt of the
Company. Upon issuance of the Transition Bonds, a portion of the CTC being
collected by the Company to recover stranded costs was designated as Intangible
Transition Charge (ITC). The ITC is an irrevocable non-bypassable, usage-based
charge that is calculated to allow for the recovery of debt service and costs
related to the issuance of the Transition Bonds. The ITC revenue, as well as all
interest expense and amortization expense associated with the Transition Bonds,
is reflected on the Company's Consolidated Statements of Income. The combined
schedule for amortization of the CTC and ITC assets is in accordance with the
amortization schedule set forth in the Final Restructuring Order.
On March 16, 2000, the PUC issued an order approving a Joint Petition for Full
Settlement of PECO Energy Company's Application for Issuance of a Qualified Rate
Order (QRO) authorizing the Company to securitize up to an additional $1 billion
of its authorized recoverable stranded costs. In accordance with the terms of
the Joint Petition for Full Settlement, when the QRO becomes final and
non-appealable, the Company, through its distribution business unit, will
provide its retail customers with rate reductions in the total amount of $60
million beginning on January 1, 2001. This rate reduction will be effective for
calendar year 2001 only and will not be contingent upon the issuance of
additional transition bonds pursuant to the QRO. The Company will use the
proceeds from any additional securitization principally to reduce stranded costs
including related capitalization.
In January 2000, in connection with the Merger Agreement, the Company entered
into a forward purchase agreement to purchase up to $500 million of its common
stock from time to time through open-market, privately negotiated and/or other
types of transactions in conformity with the rules of the SEC. This forward
purchase agreement can be settled from time to time, at the Company's election,
on a physical, net share or net cash basis. The amount at which these agreements
can be settled is dependent principally upon the market price of the Company's
common stock as compared to the forward purchase price per share and the number
of shares to be settled.
Cash flows from operations were $888 million in 1999 as compared to $1,492
million in 1998 and $1,068 million in 1997. The decrease in 1999 was principally
attributable to a reduction in cash generated by operations of $308 million and
changes in working capital of $296 million, principally related to accounts
receivable from unregulated energy sales and the repurchase of accounts
receivable with a portion of the proceeds from the issuance of Transition Bonds.
Cash flows used in investing activities were $885 million in 1999 as compared to
$521 million in 1998 and $604 million in 1997. Expenditures under the Company's
construction program increased by $76 million to $491 million in 1999. The
Company acquired six infrastructure services companies for $222 million and made
investments in and advances to joint ventures of $118 million. Net funds
invested in other activities in 1999 were $54 million, including $29 million for
nuclear plant decommissioning trust fund contributions, $22 million for cost of
removal of retired plant and $15 million for other investments, partially offset
by proceeds from the sale of investments of $12 million.
Cash flows provided by financing activities were $177 million in 1999 as
compared to cash flows used in financing activities of $956 million in 1998 and
$461 million in 1997. Cash flows from financing activities in 1999 were
primarily attributable to the securitization of stranded cost recovery and the
use of related proceeds.
The Company estimates that it will spend approximately $927 million for capital
expenditures and other investments in 2000. Certain facilities under
construction and to be constructed may require permits and licenses which the
Company has no assurance will be granted. The Company has commitments to provide
AmerGen with capital contributions equivalent to 50% of the purchase price of
any acquisitions AmerGen makes in 2000. As of December 31, 1999, the Company
expects to make $97 million of capital contributions, excluding nuclear fuel, if
all of the acquisition agreements that AmerGen entered into in 1999 close in
2000. In addition, the Company and British Energy have each agreed to provide up
to $55 million to AmerGen at any time for operating expenses. See Note 26 of
Notes to Consolidated Financial Statements. The Company has entered into three
long-term power purchase agreements with Independent Power Producers (IPP) under
which the Company makes fixed capacity payments to the IPP in return for
exclusive rights to the energy and capacity of the generating units for a fixed
period. The terms of the long-term power purchase agreements enable the Company
to supply the fuel and dispatch energy from the plants. The plants are currently
being constructed and are scheduled to begin operations in 2000, 2001 and 2002,
respectively. The Company expects to make capacity payments of $18 million in
2000. In 1999, the Company entered into a lease for two buildings that will be
the headquarters for its generation business unit. These buildings are being
constructed in Kennett Square, Pennsylvania and are anticipated to be completed
on or about June 1, 2000 and September 1, 2000, respectively. The lease terms
are for 20 years with renewal options. Estimated lease payments for 2000 are $4
million.
The Company meets its short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings under bank credit facilities. The
Company has a $900 million unsecured revolving credit facility with a group of
banks, which consists 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 its $600 million commercial paper program.
At December 31, 1999, the Company had outstanding $163 million of notes payable,
$142 million of which were commercial paper and $21 million of lines of credit.
In addition, at December 31, 1999, the Company had available formal and informal
lines of bank credit aggregating $100 million and available revolving credit
facilities aggregating $900 million which support its commercial paper program.
At December 31, 1999, the Company had no short-term investments.
Outlook
General
The Company has entered a period of financial uncertainty as a result of the
deregulation of its electric generation operations. The Final Restructuring
Order and retail competition have resulted in reduced revenues from regulated
rates. In addition, the Company is selling an increasing portion of its energy
at market-based rates. The Company believes that the deregulation of its
electric generation operations and other regulatory initiatives designed to
encourage competition have increased the Company's risk profile by changing and
increasing the number of factors upon which the Company's financial results are
dependent. This may result in more volatility in the Company's future results of
operations. The Company believes that it has significant advantages that will
strengthen its position in the increasingly competitive electric generation
environment. These advantages include the ability to produce and contract for
electricity at a low variable cost and the demonstrated ability to market and
deliver power in the competitive wholesale markets.
The Company's future financial condition and results of operations are
substantially dependent upon the effects of the Final Restructuring Order and
retail and wholesale competition for generation services. Additional factors
that affect the Company's financial condition and results of operations include
operation of nuclear generating facilities, gas restructuring in Pennsylvania,
new accounting pronouncements, inflation, weather, compliance with environmental
regulations and the profitability of the Company's investments in EIS and other
new ventures.
Merger
As a result of legislative initiatives aimed at restructuring, the electric
utility industry has undergone rapid change in recent years. Among other things,
competition has increased, particularly with respect to energy supply and retail
energy services. Many states, including the states in which the Company and
Unicom currently operate, have either passed or proposed legislation that
provides for retail electric competition and deregulation of the price of energy
supply. In addition, the wholesale electric energy market has significantly
expanded and geographic boundaries are becoming less important. During 1999, a
substantial amount of electric generation assets were sold in the United States.
The Company expects this trend to continue. Mergers continue at a rapid pace not
only between electric companies, but also between electric and gas companies
that are seeking to capture value through the convergence of the two industries.
At the same time, other companies are focusing on specific portions of the
energy industry by disaggregating their generation, transmission, distribution
and retail operations, spinning off non-core assets and acquiring assets
consistent with their strategic focus. Currently, industry participants are
attempting to prepare themselves for increased competition and position
themselves to take advantage of these trends.
The Company believes that the consolidation and transformation of the electric
and natural gas segments of the energy industry will result in the emergence of
a limited number of substantial competitors. These large entities will have
assets and skills that are necessary to create value in one or more of the
traditional segments of the utility industry. The Company believes that
companies that have the financial strength, strategic foresight and operational
skills to establish scale and an early leadership position in key segments of
the energy industry will be best positioned to compete in the new marketplace.
The Company's Board of Directors has focused significant attention on strategic
planning to adapt to the evolving competitive environment. The strategic
planning activities have concentrated on those factors that would best position
the Company for enhanced shareholder value and continued leadership in the
competitive energy marketplace.
The Company and Unicom are aggressively pursuing all necessary regulatory
approvals and expect to complete the Merger in the second half of 2000. While
the Company believes that the parties will receive the necessary regulatory
approvals, a substantial delay in obtaining satisfactory approvals or the
imposition of unfavorable terms or conditions in the approvals could have a
material adverse effect on the business, financial condition or results of
operations of the Company or Unicom or may cause the abandonment of the Merger.
In addition to other factors, the price of shares of the Company's common stock
may vary significantly as a result of market expectations of the likelihood that
the Merger will be completed and the timing of completion, the prospects of
post-merger operations, including the successful consolidation and integration
of the Company's and Unicom's organizations and the effect of any conditions or
restrictions imposed on or proposed with respect to the combined company by
regulators.
On March 24, 2000, the Company submitted for approval a joint petition for
settlement reached with various parties to the Company's proceeding before the
PUC involving the proposed merger with Unicom. The Company reached agreement
with advocates for residential, small business and large industrial customers,
and representatives of marketers, environmentalists, municipalities and elected
officials. Under the comprehensive settlement agreement the Company has agreed
to $200 million in rate reductions for all customers over the period January 1,
2002 through 2005 and extended rate caps on the Company's retail electric
distribution charges through December 31, 2006, electric reliability and
customer service standards, mechanisms to enhance competition and customer
choice, expanded assistance to low-income customers, extensive funding for wind
and solar energy and community education, nuclear safety research funds,
customer protection against nuclear costs outside of Pennsylvania, and
maintenance of charitable and civic contributions and employment for the
Company's headquarters in Philadelphia.
Competition
The Final Restructuring Order contains a number of provisions that are designed
to encourage competition for generation services. The provisions include
above-market shopping credits for generation service which provide an economic
incentive for customers to choose an alternate EGS, periodic assignments of a
portion of the Company's non-shopping customers to alternate EGSs and the
selection of an alternate supplier as the PLR for a portion of the Company's
customers.
The Final Restructuring Order established market share thresholds to ensure that
a minimum number of residential and commercial customers choose an EGS or a
Company affiliate. If less than 35% and 50% of residential and commercial
customers have chosen an EGS, including 20% of residential customers assigned to
an EGS as a PLR default supplier, by January 1, 2001 and January 1, 2003,
respectively, the number of customers sufficient to meet the necessary threshold
levels shall be randomly selected and assigned to an EGS through a
PUC-determined process.
The Final Restructuring Order requires that on January 1, 2001, 20% of all of
the Company's residential customers, determined by random selection and without
regard to whether such customers are obtaining generation service from an
alternate EGS, shall be assigned to a PLR default supplier other than the
Company through a PUC-approved bidding process.
The Final Restructuring Order caps the Company's retail transmission and
distribution rates at their current levels through June 30, 2005. The Final
Restructuring Order also established rate caps for generation services,
consisting of the charge for stranded cost recovery and a charge for energy and
capacity, through 2010. The rate caps limit the Company's ability to pass cost
increases through to customers, but also allows the Company to retain cost
savings.
The Company's recovery of stranded costs is based on the level of transition
charges established in the Final Restructuring Order and the projected annual
retail sales in the Company's service territory. Recovery of transition charges
for stranded costs and the Company's allowed return on its recovery of stranded
costs are included in operating revenue. In 1999, CTC revenue was $589 million
and is scheduled to increase to $932 million by 2010, the final year of stranded
cost recovery. Amortization of the Company's stranded cost recovery, which is a
regulatory asset, will be included in depreciation and amortization beginning in
2000. As provided by the Final Restructuring Order, there was no amortization of
this regulatory asset in 1999. The amortization expense for 2000 will be
approximately $43 million and will increase to $879 million by 2010.
The Company competes in deregulated retail electric generation markets and the
national wholesale electric generation market. Competition for electric
generation services has created new uncertainties in the utility industry. These
uncertainties include future prices of generation services in both the wholesale
and retail markets; changes in the Company's customer profiles, both at the
retail level where change is expected to be ongoing as a result of customer
choice, and between the retail and wholesale markets; and supply and demand
volatility.
The Company, through Exelon Energy, the Company's new competitive supplier,
actively competes for a share of the generation supply market throughout
Pennsylvania. The Company also participates in the generation supply market in
its traditional service territory through its distribution business unit. The
charge for energy services provided by the distribution business unit is
mandated by the Final Restructuring Order. The charge for energy services
offered by Exelon Energy are at competitive market prices. Customers who
continue to take generation service from the distribution business unit may
choose an alternate EGS at any time. Because the shopping credit established by
the PUC in the Restructuring Order remains above current retail market prices
for generation services, including those offered by Exelon Energy, the Company's
retail revenues will be reduced to the extent customers choose an alternate EGS,
including Exelon Energy. Since prices in the competitive retail and wholesale
markets are currently lower on average than those charged by the distribution
business unit, this will adversely affect the Company's revenues and profit
margins.
The Company is a low variable-cost electricity producer, which puts it in a
favorable position to take advantage of opportunities in the electric retail and
wholesale generation markets. The Company's competitive position and its future
financial condition and results of operations are dependent on the Company's
ability to successfully operate its low variable-cost power plants and market
its power effectively in competitive wholesale markets.
The Company competes in the wholesale market by selling energy and capacity from
the Company's installed capacity not utilized in the retail market and buying
and selling energy from third parties. The Company's wholesale power marketing
activities include short-term and long-term commitments to purchase and sell
energy and energy-related products with the intent and ability to deliver or
take delivery. See Notes 1 and 6 of Notes to Consolidated Financial Statements.
On June 22, 1999, Pennsylvania Governor Tom Ridge signed into law the Natural
Gas Choice and Competition Act (Act) which expands choice of gas suppliers to
residential and small commercial customers and eliminates the 5% gross receipts
tax on gas distribution companies' sales of gas. Large commercial and industrial
customers have been able to choose their suppliers since 1984. Currently,
approximately one-third of the Company's total yearly throughput is supplied by
third parties.
The Act permits gas distribution companies to continue to make regulated sales
of gas to their customers. The Act does not deregulate the transportation
service provided by gas distribution companies, which remains subject to rate
regulation. Gas distribution companies will continue to provide billing,
metering, installation, maintenance and emergency response services.
In compliance with the schedule ordered by the PUC on December 1, 1999, the
Company filed with the PUC a restructuring plan for the implementation of gas
deregulation and customer choice of gas service suppliers in its service
territory effective July 1, 2000. The Company believes there will be no material
impact on the financial condition or operations of the Company because of the
PUC's existing requirement that gas distribution companies cannot collect more
than the actual cost of gas from customers, and the Act's requirement that
suppliers must accept assignment or release, at contract rates, the portion of
the gas distribution company's firm interstate pipeline contracts required to
serve the suppliers' customers.
Expansion of Generation Portfolio
In 1998, the Company established specific goals to increase its generation
capacity from 9 gigawatts to 25 gigawatts by 2003. The Company is developing a
generation portfolio capable of taking advantage of periods of increased demand.
In order to meet this strategic objective the Company may require significant
capital resources.
In 1999, AmerGen purchased Clinton and Three Mile Island Unit No. 1 Nuclear
Generating Facility (TMI) and entered into agreements to purchase Nine Mile
Point Unit 1 Nuclear Generating Facility, a 59% undivided interest in Nine Mile
Point Unit 2 Nuclear Generating Facility, Oyster Creek Nuclear Generating
Facility and Vermont Yankee Nuclear Power Station. These purchases are expected
to be completed in 2000 subject to federal and state approvals. The Company
accounts for its investment in AmerGen under the equity method of accounting.
On September 30, 1999, the Company announced it has reached an agreement to
purchase an additional 7.51% ownership interest in Peach Bottom Atomic Power
Station (Peach Bottom) from Atlantic City Electric Company and Delmarva Power &
Light Company bringing the Company's ownership interest to 50%. The sale is
expected to be completed by mid-2000 subject to
federal and state approvals. The Company consolidates its proportionate interest
in Peach Bottom.
In 1999, the Company also entered into two long-term power purchase agreements
with Independent Power Producers (IPP) under which the Company makes fixed
capacity payments to the IPP in return for exclusive rights to the energy and
capacity of the generating units for a fixed period.
Regulation and Operation of Nuclear Generating Facilities
The Company's financial condition and results of operations are in part
dependent on the continued successful operation of its nuclear generating
facilities. The Company's nuclear generating facilities represent 45% of its
installed generating capacity. Because of the Company's reliance on its nuclear
generating units, any changes in regulations by the NRC requiring additional
investments or resulting in increased operating or decommissioning costs of
nuclear generating units could adversely affect the Company.
During 1999, Company-operated nuclear plants operated at a 93% weighted-average
capacity factor and Company-owned nuclear plants operated at a 92%
weighted-average capacity factor. Company-owned nuclear plants produced 41% of
the electricity generated by the Company. Nuclear generation is currently the
most cost-effective way for the Company to meet customer needs and commitments
for sales to other utilities.
In December 1999, AmerGen acquired Clinton and TMI marking the first
acquisitions by the Company's joint venture. Accordingly, AmerGen's financial
condition and results of operations are also dependent on the continued
successful operation of its nuclear generating facilities. AmerGen's nuclear
generating facilities represent 100% of its installed generating capacity.
Because of AmerGen's reliance on its nuclear generating units, any changes in
regulations by the NRC requiring additional investments or resulting in
increased operating or decommissioning costs of nuclear generating units could
adversely affect AmerGen and, accordingly, the Company's investment in AmerGen.
In conjunction with each of the completed acquisitions, AmerGen has received
fully funded decommissioning trust funds which have sufficient assets to fully
cover the anticipated costs to decommission each nuclear plant following its
licensed life, including an annual net growth rate of 2% in accordance with NRC
regulations. AmerGen believes that the amount of the trust funds and investment
earnings thereon will be sufficient to meet its decommissioning obligations.
Combining the nuclear operations of the Company and Unicom will present
significant challenges. The combined nuclear operations of Exelon will be
significantly larger than either company's nuclear operations and will require
the integration of nuclear operations among the Company and Unicom. Exelon's
nuclear operation will be the largest in the United States in terms of size and
geographic scope. Exelon will have to build on the successful nuclear management
of the Company and Unicom to maintain and improve the safe and efficient
operation of its nuclear generating plants.
Other Factors
Annual and quarterly operating results can be significantly affected by weather.
Since the Company's peak retail demand is in the summer months, temperature
variations in summer months are generally more significant than variations
during winter months.
Inflation affects the Company through increased operating costs and increased
capital costs for utility plant. As a result of the rate caps imposed under the
Final Restructuring Order and price pressures due to competition, the Company
may not be able to pass the costs of inflation through to customers.
The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under federal and state environmental laws, the Company is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by the Company and of property contaminated by
hazardous substances generated by the Company. The Company owns or leases a
number of real estate parcels, including parcels on which its operations or the
operations of others may have resulted in contamination by substances which are
considered hazardous under environmental laws. The Company is currently involved
in a number of proceedings relating to sites where hazardous substances have
been deposited and may be subject to additional proceedings in the future.
The Company has identified 28 sites where former manufactured gas plant (MGP)
activities have or may have resulted in actual site contamination. The Company
is presently engaged in performing various levels of activities at these sites,
including initial evaluation to determine the existence and nature of the
contamination, detailed evaluation to determine the extent of the contamination
and the necessity and possible methods of remediation, and implementation of
remediation. The Pennsylvania Department of Environmental Protection has
approved the Company's clean-up of three sites. Ten other sites are currently
under some degree of active study and/or remediation.
As of December 31, 1999 and 1998, the Company had accrued $57 million and $60
million, respectively, for environmental investigation and remediation costs,
including $32 million and $33 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. The Company expects to
expend $7 million for environmental remediation activities in 2000. The Company
cannot predict whether it will incur other significant liabilities for any
additional investigation and remediation costs at these or additional sites
identified by the Company, environmental agencies or others, or whether such
costs will be recoverable from third parties.
For a discussion of other contingencies, see Note 6 of Notes to Consolidated
Financial Statements.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," (SFAS No.
133) to establish accounting and reporting standards for derivatives. The new
standard requires recognizing all derivatives as either assets or liabilities on
the balance sheet at their fair value and specifies the accounting for changes
in fair value depending upon the intended use of the derivative. In June 1999,
the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133," which
delayed the effective date for SFAS No. 133 until fiscal years beginning after
June 15, 2000. The Company expects to adopt SFAS No. 133 in the first quarter of
2001. The Company is in the process of evaluating the impact of SFAS No. 133 on
its financial statements.
Year 2000 Readiness Disclosure
During 1999 and 1998, the Company successfully addressed, through its Year 2000
Project (Y2K Project), 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.
The Y2K Project was divided into four main sections - Information Technology
Systems (IT Systems), Embedded Technology (devices to control, monitor or assist
the operation of equipment, machinery or plant), Supply Chain (third-party
suppliers and customers) and Contingency Planning. The IT Systems section
included both the conversion of applications software that was not Y2K-ready and
the replacement of software when available from the supplier. The Supply Chain
section included the process of identifying and prioritizing critical suppliers
and communicating with them about their plans and progress in addressing the Y2K
issue.
The current estimated total cost of the Y2K Project is $61 million, the majority
of which is attributable to testing. This represents a $9 million reduction of
the previously estimated cost of the Y2K Project. This estimate includes the
Company's share of Y2K costs for jointly owned facilities. The total amount
expended on the Y2K Project through December 31, 1999 was $56 million. The
Company is funding the Y2K Project from operating cash flows.
The Company's systems experienced no Y2K difficulties on December 31, 1999 or
since that date. The Company's operations have not, to date, been adversely
affected by any Y2K difficulties that suppliers or customers may have
experienced. The Company's Y2K Project also successfully addressed concerns with
the date February 29, 2000. The Company will continue to monitor its systems for
potential Y2K difficulties through the remainder of 2000.
Forward-Looking Statements
Except for the historical information contained herein, certain of the matters
discussed in this Report are forward-looking statements which are subject to
risks and uncertainties. The factors that could cause actual results to differ
materially include those discussed herein as well as those listed in Note 6 of
Notes to Consolidated Financial Statements and other factors discussed in the
Company's filings with the SEC. Readers are cautioned not to place undue
reliance on these forward-looking statements, which speak only as of the date of
this Report. The Company undertakes no obligation to publicly release any
revision to these forward-looking statements to reflect events or circumstances
after the date of this Report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with commodity price and
supply, interest rates and equity prices.
Commodity Risk
The Company engages in the wholesale and retail marketing of electricity, and,
accordingly, is exposed to risk associated with the price of electricity.
The Company's wholesale operations include the physical delivery and marketing
of power obtained through Company-owned generation capacity and long,
intermediate and short-term contracts. The Company maintains a net positive
supply of energy and capacity, through Company-owned generation assets and power
purchase and lease agreements, to protect it from the potential operational
failure of one of its owned or contracted power generating units. These
operations have resulted in the expansion of the Company's load-servicing
capabilities beyond its primary operating environment, the PJM control area. A
majority of the Company's contractual supplies may be economically moved into
this primary operating environment. The Company has also contracted for access
to additional generation through bilateral long-term power purchase agreements.
These agreements are firm commitments related to power generation of specific
generation plants and/or are dispatchable in nature - similar to asset
ownership. The Company enters into power purchase agreements with the objective
of obtaining low-cost energy supply sources to meet its physical delivery
obligations to its customers, and generally with the ability to import these
supplies to PJM to displace more expensive energy supplied by Company-owned
generation assets. The Company has also purchased firm transmission rights to
ensure that it has reliable transmission capacity to physically move its power
supplies to meet customer delivery needs. The intent and business objective for
the use of its capital assets and contracts is the same - provide the Company
with physical power supply to enable it to deliver energy to meet customer
needs. The Company's principal risk management activities focus on management of
volume risks (supply and transmission) and operational risks (plant or
transmission outages) consistent with its business philosophy, not price risks.
The Company does not use financial contracts in its wholesale marketing
activities and as a matter of business practice does not "pair off" or net
settle its contracts. All contracts result in the delivery and/or receipt of
power.
The Company has entered into bilateral long-term contractual obligations for
sales of energy to other load-serving entities including electric utilities,
municipalities, electric cooperatives, and retail load aggregators. The Company
also enters into contractual obligations to deliver energy to wholesale market
participants who primarily focus on the resale of energy products for delivery.
The Company provides delivery of its energy to these customers in and out of PJM
through access to Company-owned transmission assets or rights for firm
transmission.
The Company completed a thorough review of its activities after the issuance of
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" in the first quarter of 1999 and concluded, based on the
indicators included in EITF 98-10, that its activities were not "trading"
activities. The Company continues to believe that its business philosophy,
performance measurement and other management activities are not consistent with
that of a "trading organization." The Company's short-term and long-term
commitments to purchase and sell energy and energy-related products are carried
at the lower of cost or market. The Company reports the revenue and expense
associated with all of its energy contracts at the time the underlying physical
transaction closes consistent with its business philosophy of generating and
delivering physical power to customers.
The Company's retail operations include the regulated sales of electricity
through its distribution business unit and unregulated sales of electricity
through its generation business unit. Both energy suppliers secure supply
through the Company's wholesale operations. The transmission and distribution
component of the Company's rates for regulated sales of electricity are capped
through December 2006. Additionally, generation rate caps, defined as the sum of
the applicable transition charge and energy and capacity charge, will remain in
effect through 2010. Accordingly, the Company does not have the ability to pass
on increases in the price of electricity through rate increases to its
customers. As of December 31, 1999, a hypothetical 10% increase in the cost of
electricity would result in a $82 million decrease in pretax earnings for 2000.
The Company's rates for unregulated sales of electricity are not subject to rate
caps.
Under the Final Restructuring Order, the Company's customers have been permitted
to shop for their generation supplier since January 1, 1999. The Final
Restructuring Order established market share thresholds to ensure that a minimum
number of residential and commercial customers choose an EGS or a Company
affiliate. If less than35% and 50% of residential and commercial customers have
chosen an EGS, including 20% of residential customers assigned to an EGS as a
PLR default supplier, by January 1, 2002 and January 1, 2003, respectively, the
number of customers sufficient to meet the necessary threshold levels shall be
randomly selected and assigned to an EGS through a PUC-determined process. As of
December 31, 1999, the Company estimates that the impact on pretax earnings for
2000 would be insignificant. $6.8 million decrease in pre-tax earnings during
2000.
Interest Rate Risk
The Company uses a combination of fixed rate and variable rate debt to reduce
interest rate exposure. Interest rate swaps may be used to adjust exposure when
deemed appropriate, based upon market conditions. These strategies attempt to
provide and maintain the lowest cost of capital. As of December 31, 1999, a
hypothetical 10% increase in the interest rates associated with variable rate
debt would result in a $1 million decrease in pretax earnings for 2000.
The Company has entered into interest rate swaps to manage interest rate
exposure associated with the floating rate series of Transition Bonds. At
December 31, 1999, these interest rate swaps had a fair market value of $102
million which was based on the present value difference between the contracted
rate and the market rates at December 31, 1999.
The aggregate fair value of the Transition Bond derivative instruments that
would have resulted from a hypothetical 50 basis point decrease in the spot
yield at December 31, 1999 is estimated to be $63 million. If the derivative
instruments had been terminated at December 31, 1999, this estimated fair value
represents the amount to be paid by the counterparties to the Company.
The aggregate fair value of the Transition Bond derivative instruments that
would have resulted from a hypothetical 50 basis point increase in the spot
yield at December 31, 1999 is estimated to be $137 million. If the derivative
instruments had been terminated at December 31, 1999, this estimated fair value
represents the amount to be paid by the counterparties to the Company.
In February 2000, the Company entered into forward starting interest rate swaps
for a notional amount of $1 billion in anticipation of the issuance of $1
billion of transition bonds in the second quarter of 2000.
Equity Price Risk
The Company maintains trust funds, as required by the Nuclear Regulatory
Commission (NRC), to fund certain costs of decommissioning its nuclear plants.
As of December 31, 1999, these funds were invested primarily in domestic equity
securities and fixed rate, fixed income securities and are reflected at fair
value on the Consolidated Balance Sheet. The mix of securities is designed to
provide returns to be used to fund decommissioning and to compensate for
inflationary increases in decommissioning costs. However, the equity securities
in the trusts are exposed to price fluctuations in equity markets, and the value
of fixed rate, fixed income securities are exposed to changes in interest rates.
The Company actively monitors the investment performance and periodically
reviews asset allocation in accordance with the Company's nuclear
decommissioning trust investment policy. A hypothetical 10% increase in interest
rates and decrease in equity prices would result in a $29 million reduction in
the fair value of the trust assets. The Company's restructuring settlement
agreement provides for the collection of authorized nuclear decommissioning
costs through the CTC. Additionally, the Company is permitted to seek recovery
from customers of any increases in these costs. Therefore, the Company's equity
price risk is expected to remain immaterial.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Accountants
To the Shareholders and Board of Directors
of PECO Energy Company:
In our opinion, the consolidated financial statements listed in the accompanying
index appearing under Item 14(a)1. present farily, in all material respects, the
financial position of PECO Energy Company and Subsidiary Companies at December
31, 1999 and 1998, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1999 in conformity with
accounting principles generally accepted in the United States. In addition, in
our opinion, the financial statement schedule listed in the index appearing
under Item 14(a)2. presents fairly, in all material respects, the information
set forth therein when read in conjunction with the related consolidated
financial statements. These financial statements and financial statement
schedule are the responsibility of the Company's management; our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States,
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Philadelphia, PA
February 29, 2000, except for
certain information included
in Notes 2 and 4, for which
the dates are March 24, 2000
and March 16, 2000, respectively.
Consolidated Statements of Income
For the Years Ended December 31,
----------------------------------------
1999 1998 1997
------ ------ ------
In Thousands, except per share data
Operating Revenues
Electric $4,847,126 $4,829,639 $ 4,149,845
Gas 481,069 432,893 451,232
Infrastructure Services 108,558 - -
---------- ---------- -----------
Total Operating Revenues 5,436,753 5,262,532 4,601,077
Operating Expenses
Fuel and Energy Interchange 2,145,175 1,795,887 1,290,164
Operating and Maintenance 1,383,885 1,134,579 1,414,596
Early Retirement and Separation Programs - 124,200 -
Depreciation and Amortization 236,790 642,842 580,595
Taxes Other Than Income 261,732 279,515 310,091
---------- ---------- -----------
Total Operating Expenses 4,027,582 3,977,023 3,595,446
Operating Income 1,409,171 1,285,509 1,005,631
Other Income and Deductions
Interest Expense (395,670) (330,842) (372,857)
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership,
which holds Solely Subordinated Debentures
of the Company (21,162) (30,694) (28,990)
Allowance for Funds Used During Construction 3,891 3,522 21,771
Settlement of Salem Litigation - - 69,800
Equity in Losses of Telecommunications
Investments (37,857) (54,385) (14,195)
Other, Net 18,611 (21,078) (51,833)
---------- ---------- -----------
Total Other Income and Deductions (432,187) (433,477) (376,304)
---------- ---------- -----------
Income Before Income Taxes and Extraordinary
Item 976,984 852,032 629,327
Income Taxes 357,998 319,654 292,769
---------- ---------- -----------
Income Before Extraordinary Item 618,986 532,378 336,558
Extraordinary Item (net of income taxes of
$25,415, $13,757, and $1,290,961 for 1999,
1998, and 1997, respectively) (36,572) (19,654) (1,833,664)
---------- ---------- -----------
Net Income (Loss) 582,414 512,724 (1,497,106)
Preferred Stock Dividends 12,176 13,109 16,804
---------- ---------- -----------
Earnings (Loss) Applicable to Common Stock $ 570,238 $ 499,615 $(1,513,910)
========== ========== ===========
Average Shares of Common Stock Outstanding 196,285 223,219 222,543
========== ========== ===========
Earnings Per Average Common Share:
Basic:
Income Before Extraordinary Item $ 3.10 $ 2.33 $ 1.44
Extraordinary Item $ (0.19) $ (0.09) $ (8.24)
---------- ---------- -----------
Net Income (Loss) $ 2.91 $ 2.24 $ (6.80)
========== ========== ===========
Diluted:
Income Before Extraordinary Item $ 3.08 $ 2.32 $ 1.44
Extraordinary Item $ (0.19) $ (0.09) $ (8.24)
---------- ---------- -----------
Net Income (Loss) $ 2.89 $ 2.23 $ (6.80)
========== ========== ===========
Dividends per Common Share $ 1.00 $ 1.00 $ 1.80
========== ========== ===========
See Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows
For the Years Ended December 31,
------------------------------------------
1999 1998 1997
------ ------ ------
In Thousands
Cash Flows from Operating Activities
Net Income (Loss) $ 582,414 $ 512,724 $(1,497,106)
Adjustments to reconcile Net Income (Loss) to Net Cash
provided by Operating Activities:
Depreciation and Amortization 358,027 764,641 703,394
Extraordinary Item (net of income taxes) 36,572 19,654 1,833,664
Provision for Uncollectible Accounts 59,418 71,667 88,263
Deferred Income Taxes 7,511 (115,640) (17,228)
Amortization of Investment Tax Credits (14,301) (18,066) (18,201)
Early Retirement and Separation Charge - 125,000 -
Deferred Energy Costs 22,973 5,818 (5,652)
Salem Litigation Settlement - - 69,800
Equity in Losses of Telecommunications Investments 37,857 54,385 14,195
Losses (Gains) on the Disposal of Assets, net 37,832 - -
Other Items Affecting Operations (24,290) (8,627) 63,847
Changes in Working Capital:
Accounts Receivable (159,475) 2,576 (347,787)
Repurchase of Accounts Receivable (150,000) - -
Inventories (43,390) 14,192 28,628
Accounts Payable 63,861 8,971 93,881
Other Current Assets and Liabilities (73,390) 54,263 58,539
--------- ---------- -----------
Net Cash Flows provided by Operating Activities 888,399 1,491,558 1,068,237
--------- ---------- -----------
Cash Flows from Investing Activities
Investment in Plant (491,097) (415,331) (490,200)
Exelon Infrastructure Services Acquisitions (222,492) - -
Investments in and Advances to Joint Ventures (117,615) (58,653) (30,086)
Proceeds from the Sale of Investments 12,226 - -
Increase in Other Investments (66,467) (46,742) (83,261)
--------- ---------- -----------
Net Cash Flows used in Investing Activities (885,445) (520,726) (603,547)
--------- ---------- -----------
Cash Flows from Financing Activities
Issuance of Long-Term Debt, net of issuance costs 4,169,883 13,486 161,813
Common Stock Repurchase (1,705,319) - -
Retirement of Long-Term Debt (1,343,334) (841,755) (283,303)
Change in Short-Term Debt (388,319) 123,500 114,000
Redemption of COMRPS (221,250) (80,794) -
Issuance of COMRPS - 78,105 50,000
Dividends on Preferred and Common Stock (208,059) (236,307) (417,383)
Capital Lease Payments (138,998) (59,923) (39,100)
Termination of Interest Rate Swap Agreements 79,969 - -
Prepayment Premiums (48,307) (27,250) -
Preferred Stock Redemptions (37,091) - (61,895)
Proceeds from Exercise of Stock Options 13,951 50,700 117
Loss on Reacquired Debt 6,454 6,753 22,752
Other Items Affecting Financing (2,420) 17,332 (7,522)
--------- ---------- -----------
Net Cash Flows provided by (used in) Financing Activities 177,160 (956,153) (460,521)
--------- ---------- -----------
Increase in Cash and Cash Equivalents 180,114 14,679 4,169
--------- ---------- -----------
Cash and Cash Equivalents at beginning of period 48,083 33,404 29,235
--------- ---------- -----------
Cash and Cash Equivalents at end of period $ 228,197 $ 48,083 $ 33,404
========= ========== ===========
See Notes to Consolidated Financial Statements
Consolidated Balance Sheets
At December 31,
--------------------------
1999 1998
------ ------
In Thousands
Assets
Current Assets
Cash and Cash Equivalent $ 228,197 $ 48,083
Accounts Receivable, net
Customer 396,453 181,210
Other 295,011 129,546
Inventories
Fossil Fuel 112,739 92,288
Materials and Supplies 93,077 82,068
Deferred Energy Costs - Gas 6,874 29,847
Other 80,264 19,013
----------- -----------
Total Current Assets 1,212,615 582,055
----------- -----------
Property, Plant and Equipment, net 5,045,008 4,804,469
Deferred Debits and Other Assets
Competitive Transition Charge 5,274,624 5,274,624
Recoverable Deferred Income Taxes 638,060 614,445
Deferred Non-Pension Postretirement
Benefits Costs 84,421 90,915
Investments 538,231 497,648
Loss on Reacquired Debt 70,711 77,165
Goodwill, net 120,500 -
Other 135,339 107,042
----------- -----------
Total Deferred Debits and Other Assets 6,861,886 6,661,839
----------- -----------
Total Assets $13,119,509 $12,048,363
=========== ===========
At December 31,
--------------------------
1999 1998
------ ------
In Thousands
Liabilities and Shareholders' Equity
Current Liabilities
Notes Payable, Bank $163,193 $525,000
Long-Term Debt Due Within One Year 127,762 361,523
Capital Lease Obligations
Due Within One Year 13 69,011
Accounts Payable 429,492 316,292
Taxes Accrued 203,011 170,495
Interest Accrued 119,200 61,515
Deferred Income Taxes 14,584 14,168
Other 246,816 217,416
----------- -----------
Total Current Liabilities 1,304,071 1,735,420
----------- -----------
Long-Term Debt 5,968,658 2,919,592
Deferred Credits and Other Liabilities
Capital Lease Obligations 455 85,297
Deferred Income Taxes 2,410,769 2,376,792
Unamortized Investment Tax Credits 285,698 299,999
Pension Obligations 212,198 219,274
Non-Pension Postretirement
Benefits Obligation 442,780 421,083
Other 400,686 354,037
----------- -----------
Total Deferred Credits and
Other Liabilities 3,752,586 3,756,482
----------- -----------
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership,
which holds Solely Subordinated
Debentures of the Company 128,105 349,355
Mandatorily Redeemable Preferred Stock 55,609 92,700
Commitments and Contingencies (Note 6)
Shareholders' Equity
Common Stock 3,575,514 3,557,035
Preferred Stock 137,472 137,472
Other Paid-In Capital 1,236 1,236
Accumulated Deficit (102,742) (500,929)
Treasury Stock, at cost (1,705,015) --
Accumulated Other Comprehensive Income 4,015 --
----------- -----------
Total Shareholders' Equity 1,910,480 3,194,814
----------- -----------
Total Liabilities and
Shareholders' Equity $13,119,509 $12,048,363
=========== ===========
See Notes to Consolidated Financial Statements
Consolidated Statements of Changes in Common
Shareholders' Equity and Preferred Stock
Retained
Common Stock Other Earnings Treasury Stock
----------------------- Paid-in (Accumulated ------------------------
All Amounts in Thousands Shares Amount Capital Deficit) Shares Amount
- - ---------------------------- ---------- ---------- ---------- ------------ ---------- ---------
Balance at January 1, 1997 222,542 $3,506,003 $ 1,326 $ 1,138,652 -- $ --
Net Loss (1,497,106)
Other Comprehensive Income
Comprehensive Income
Cash Dividends Declared:
Preferred Stock
(at specified annual rates) (16,804)
Common Stock ($1.80 per share) (400,579)
Capital Stock Activity:
Expenses of Capital Stock Activity 98
Stock Repurchase Forward Contract (4,889)
Long-Term Incentive Plan Issuances 5 117
Preferred Stock Redemptions (87) -- --
------- ---------- ---------- ----------- ---------- ------------
Balance at December 31, 1997 222,547 3,506,120 1,239 (780,628) -- --
Net Income 512,724
Other Comprehensive Income
Comprehensive Income
Cash Dividends Declared:
Preferred Stock
(at specified annual rates) (13,109)
Common Stock ($1.00 per share) (223,198)
Capital Stock Activity:
Expenses of Capital Stock Activity 2,731
Stock Repurchase Forward Contract (7,677)
Long-Term Incentive Plan Issuances 2,137 50,915 (3) 8,228
------- ---------- ---------- ----------- ---------- ------------
Balance at December 31, 1998 224,684 3,557,035 1,236 (500,929) -- --
Net Income 582,414
Other Comprehensive Income:
Unrealized Gain on Securities,
net of $2,757 tax
Comprehensive Income
Cash Dividends Declared:
Preferred Stock
(at specified annual rates) (12,176)
Common Stock ($1.00 per share) (195,883)
Capital Stock Activity:
Stock Repurchase Forward
Contract Settlement 12,118 24,489 (695,934)
Repurchase of Common Stock 22,610 (1,009,385)
Long-Term Incentive Plan Issuances 670 18,479 -- 11,714 (17) 304
Preferred Stock Redemptions
------- ---------- ---------- ----------- ---------- ------------
Balance at December 31, 1999 225,354 $3,575,514 $ 1,236 $(102,742) 44,082 $ (1,705,015)
======= ========== ========== =========== ========== ============
Accumulated
Other
Compre- Compre- Preferred Stock
hensive hensive ----------------------
All Amounts in Thousands Income Income Shares Amount
- - ---------------------------- --------- ----------- ---------- --------
Balance at January 1, 1997 $ -- 2,921 $292,067
Net Loss $(1,497,106)
Other Comprehensive Income --
Comprehensive Income -----------
(1,497,106)
===========
Cash Dividends Declared:
Preferred Stock
(at specified annual rates)
Common Stock ($1.80 per share)
Capital Stock Activity:
Expenses of Capital Stock Activity
Stock Repurchase Forward Contract
Long-Term Incentive Plan Issuances
Preferred Stock Redemptions (619) (61,895)
--------- -------- ---------
Balance at December 31, 1997 -- 2,302 230,172
Net Income 512,724
Other Comprehensive Income --
-----------
Comprehensive Income 512,742
===========
Cash Dividends Declared:
Preferred Stock
(at specified annual rates)
Common Stock ($1.00 per share)
Capital Stock Activity:
Expenses of Capital Stock Activity
Stock Repurchase Forward Contract
Long-Term Incentive Plan Issuances
--------- -------- ---------
Balance at December 31, 1998 -- 2,302 230,172
Net Income 582,414
Other Comprehensive Income:
Unrealized Gain on Securities,
net of $2,757 tax 4,015 4,015
-----------
Comprehensive Income $ 586,429
===========
Cash Dividends Declared:
Preferred Stock
(at specified annual rates)
Common Stock ($1.00 per share)
Capital Stock Activity:
Stock Repurchase Forward
Contract Settlement
Repurchase of Common Stock
Long-Term Incentive Plan Issuances
Preferred Stock Redemptions (371) (37,091)
--------- -------- ---------
Balance at December 31, 1999 $ 4,015 1,931 $ 193,081
========= ======== =========
See Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
1. Significant Accounting Policies
Description of Business
Incorporated in Pennsylvania in 1929, PECO Energy Company (Company) is engaged
principally in the production, purchase, transmission, distribution and sale of
electricity to residential, commercial, industrial and wholesale customers and
the distribution and sale of natural gas to residential, commercial and
industrial customers. Pursuant to the Pennsylvania Electricity Generation
Customer Choice and Competition Act (Competition Act), the Commonwealth of
Pennsylvania has required the unbundling of retail electric services in
Pennsylvania into separate generation, transmission and distribution services
with open retail competition for generation services. Since the commencement of
deregulation in 1999, the Company serves as the local distribution company
providing electric distribution services in its franchised service territory in
southeastern Pennsylvania and bundled electric service to customers who do not
choose an alternate electric generation supplier. The Company also engages in
the wholesale marketing of electricity on a national basis. Through its Exelon
Energy division, the Company is a competitive generation supplier offering
competitive energy supply to customers throughout Pennsylvania. The Company's
infrastructure services subsidiary, Exelon Infrastructure Services, Inc. (EIS),
provides utility infrastructure services to customers in several regions of the
United States. The Company owns a 50% interest in AmerGen Energy Company, LLC
(AmerGen), a joint venture with British Energy, Inc. a wholly-owned subsidiary
of British Energy plc, to acquire and operate nuclear generating facilities. The
Company also participates in joint ventures which provide telecommunications
services in the Philadelphia metropolitan region.
Basis of Presentation
The consolidated financial statements of the Company include the accounts of its
majority-owned subsidiaries after the elimination of its intercompany
transactions. The Company accounts for investments in its 50% owned joint
ventures under the equity method of accounting. The Company consolidates its
proportionate interest in its jointly owned electric utility plants. The Company
accounts for its less than 20% owned investments under the cost method of
accounting. Accounting policies for regulated operations are in accordance with
those prescribed by the regulatory authorities having jurisdiction, principally
the Pennsylvania Public Utility Commission (PUC) and the Federal Energy
Regulatory Commission (FERC).
Accounting for the Effects of Regulation
The Company accounts for all of its regulated electric and gas operations in
accordance with Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," requiring the
Company to record the financial statement effects of the rate regulation to
which such operations are currently subject. Use of SFAS No. 71 is applicable to
the utility operations of the Company which meet the following criteria: (1)
third-party regulation of rates; (2) cost-based rates; and (3) a reasonable
assumption that all costs will be recoverable from customers through rates. The
Company believes that it is probable that regulatory assets associated with
these operations will be recovered. If a separable portion of the Company's
business no longer meets the provisions of SFAS No. 71, the Company is required
to eliminate the financial statement effects of regulation for that portion.
Effective December 31, 1997, the Company determined that the electric generation
portion of its business no longer met the criteria of SFAS No. 71 and,
accordingly, implemented SFAS No. 101, "Regulated Enterprises - Accounting for
the Discontinuation of FASB Statement No. 71," for that portion of its business.
See Note 5 - Restructuring Charge.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Revenues
Electric and gas revenues are recorded as service is rendered or energy is
delivered to customers. At the end of each month, the Company accrues an
estimate for the unbilled amount of energy delivered or services provided to its
electric and gas customers. The Company recognizes contract revenue and profits
on long-term contracts from its infrastructure services business by the
percentage-of-completion method of accounting based on costs incurred as a
percentage of estimated total costs of individual contracts.
Purchased Gas Adjustment Clause
The Company's gas rates are subject to a fuel adjustment clause designed to
recover or refund the difference between the actual cost of purchased gas and
the amount included in base rates. Differences between the amounts billed to
customers and the actual costs recoverable are deferred and recovered or
refunded in future periods by means of prospective quarterly adjustments to
rates.
Nuclear Fuel
The cost of nuclear fuel is capitalized and charged to fuel expense on the unit
of production method. Estimated costs of nuclear fuel disposal are charged to
fuel expense as the related fuel is consumed.
Nuclear Outage Costs
Incremental nuclear maintenance and refueling outage costs are accrued over the
unit operating cycle. For each unit, an accrual for incremental nuclear
maintenance and refueling outage expense is estimated based upon the latest
planned outage schedule and estimated costs for the outage. Differences between
the accrued and actual expense for the outage are recorded when such differences
are known.
Depreciation, Amortization and Decommissioning
Depreciation is provided over the estimated service lives of property, plant,
and equipment on a straight line basis. Annual depreciation provisions for
financial reporting purposes, expressed as a percentage of average service life
for each asset category are presented in the table below:
Asset Category 1999 1998 1997
------ ------ ------
Electric - Transmission and Distribution 1.83% 1.96% 1.88%
Electric - Generation 5.12% 5.26% 3.90%
Gas 2.36% 2.40% 2.33%
Common 2.13% 4.54% 3.94%
Other Property and Equipment 8.61% 2.80% 1.97%
Amortization of regulatory assets is provided over the recovery period as
specified in the related regulatory agreement. Goodwill related to the EIS
acquisitions in 1999 is being amortized over 20 years.
The Company's current estimate of the costs for decommissioning its ownership
share of its nuclear generating stations is currently included in regulated
rates and is charged to operations over the expected service life of the related
plant. The amounts recovered from customers are deposited in trust accounts and
invested for funding of future costs. The Company accounts for its investments
in decommissioning trust funds by recording a charge to depreciation expense and
a corresponding liability in accumulated depreciation for the current period's
cost of decommissioning. Unrealized gains and losses are reflected as regulatory
liabilities and assets, respectively. The Company believes that the amounts
being recovered from customers through electric rates will be sufficient to
fully fund the unrecorded portion of its decommissioning obligation.
Capitalized Interest
Effective January 1, 1998, the Company ceased accruing Allowance for Funds Used
During Construction (AFUDC) for electric generation-related construction
projects and began using SFAS No. 34, "Capitalizing Interest Costs," to
calculate the costs during construction of debt funds used to finance its
electric generation-related construction projects. The Company recorded
capitalized interest of $6 million and $7 million in 1999 and 1998,
respectively.
AFUDC is the cost, during the period of construction, of debt and equity funds
used to finance construction projects for regulated operations. AFUDC is
recorded as a charge to Construction Work in Progress and as a credit to AFUDC
included in Other Income and Deductions. The rates used for capitalizing AFUDC,
which averaged 6.25% in 1999, 8.63% in 1998 and 8.88% in 1997, are computed
under a method prescribed by regulatory authorities. AFUDC is not included in
regular taxable income and the depreciation of capitalized AFUDC is not tax
deductible.
Income Taxes
Deferred federal and state income taxes are provided on all significant timing
differences between book bases and tax bases of assets and liabilities,
transactions that reflect taxable income in a year different from book income
and tax carryforwards. Investment tax credits previously used for income tax
purposes have been deferred on the Consolidated Balance Sheets and are
recognized in book income over the life of the related property. The Company and
its subsidiaries file a consolidated federal income tax return. Income taxes are
allocated to each of the Company's subsidiaries within the consolidated group
based on the separate return method.
Gains and Losses on Reacquired Debt
Effective January 1, 1998, gains and losses on reacquired debt are being
recognized in the Company's Consolidated Statements of Income as incurred. Gains
and losses on reacquired debt related to regulated operations incurred prior to
January 1, 1998, have been deferred and are being amortized to interest expense
over the period approved for ratemaking purposes based on management's
assessment of the likelihood of recovery.
Comprehensive Income
Comprehensive income includes all changes in equity during a period except those
resulting from investments by and distributions to shareholders. Comprehensive
income is reflected in the Consolidated Statements of Changes in Common
Shareholders' Equity and Preferred Stock.
Cash and Cash Equivalents
The Company considers all temporary cash investments purchased with an original
maturity of three months or less to be cash equivalents.
Marketable Securities
Marketable securities are classified as available-for-sale securities and are
reported at fair value, with the unrealized gains and losses, net of tax,
reported in other comprehensive income. The Company has no held-to-maturity or
trading securities.
Inventories
Inventories are carried at the lower of average cost or market.
Derivative Financial Instruments
Hedge accounting is applied only if the derivative reduces the risk of the
underlying hedged item and is designated at inception as a hedge, with respect
to the hedged item. If a derivative instrument ceased to meet the criteria for
deferral, any gains or losses are recognized in income. The Company does not
hold or issue derivative financial instruments for trading purposes.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. The Company evaluates the
carrying value of property, plant and equipment and other long-term assets based
upon current and anticipated undiscounted cash flows, and recognizes an
impairment when it is probable that such estimated cash flows will be less than
the carrying value of the asset. Measurement of the amount of impairment, if
any, is based upon the difference between carrying value and fair value.
Capitalized Software Costs
Costs incurred during the application development stage of software projects for
software which is developed or obtained for internal use are capitalized. At
December 31, 1999 and 1998, capitalized software costs totaled $105 million and
$84 million, respectively, net of $32 million and $37 million accumulated
amortization, respectively. Such capitalized amounts are amortized ratably over
the expected lives of the projects when they become operational, not to exceed
ten years.
Retail and Wholesale Energy Commitments
The Company's retail and wholesale activities include short-term and long-term
commitments, which are carried at the lower of cost or market, to purchase and
sell energy and energy-related products in the retail and wholesale markets with
the intent and ability to deliver or take delivery. As such, revenue and expense
associated with energy commitments is reported at the time the underlying
physical transaction closes.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," to
establish accounting and reporting standards for derivatives. The new standard
requires recognizing all derivatives as either assets or liabilities on the
balance sheet at their fair value and specifies the accounting for changes in
fair value depending upon the intended use of the derivative. In June 1999, the
FASB issued SFAS No. 137 "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133," which
delayed the effective date for SFAS No. 133 until fiscal years beginning after
June 15, 2000. The Company expects to adopt SFAS No. 133 in the first quarter of
2001. The Company is in the process of evaluating the impact of SFAS No. 133 on
its financial statements.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income or shareholders' equity.
2. Merger with Unicom Corporation
On September 22, 1999, the Company and Unicom Corporation (Unicom) entered into
an Agreement and Plan of Exchange and Merger providing for a merger of equals.
On January 7, 2000, the Agreement and Plan of Exchange and Merger was amended
and restated (Merger Agreement). The Merger Agreement has been approved by both
companies' Boards of Directors. The transaction will be accounted for as a
purchase with the Company as acquiror.
The Merger Agreement provides for (a) the exchange of each share of outstanding
common stock, no par value, of the Company for one share of common stock of the
new company, Exelon Corporation (Exelon) (Share Exchange) and (b) the merger of
Unicom with and into Exelon (Merger and together with the Share Exchange, Merger
Transaction). In the Merger, each share of the outstanding common stock, no par
value, of Unicom will be converted into 0.875 shares of common stock of Exelon
plus $3.00 in cash. In the Merger Agreement, the Company and Unicom agree to
repurchase approximately $1.5 billion of common stock prior to the closing of
the Merger with Unicom to repurchase approximately $1.0 billion of its common
stock, and the Company to repurchase approximately $500 million of its common
stock. As a result of the Share Exchange, the Company will become a wholly owned
subsidiary of Exelon. As a result of the Merger, Unicom will cease to exist and
its subsidiaries, including Commonwealth Edison Company, an Illinois corporation
(ComEd), will become subsidiaries of Exelon. Following the Merger Transaction,
Exelon will be a holding company with two principal utility subsidiaries, ComEd
and the Company.
The Merger Transaction is conditioned, among other things, upon the approvals of
the common shareholders of both companies and the approval of certain regulatory
agencies. The companies have filed an application with the Securities and
Exchange Commission (SEC) to register Exelon as a holding company under the
Public Utility Holding Company Act of 1935.
On March 24, 2000, the Company submitted for approval a joint petition for
settlement reached with various parties to the Company's proceeding before the
PUC involving the proposed merger with Unicom. The Company reached agreement
with advocates for residential, small business and large industrial customers,
and representatives of marketers, environmentalists, municipalities and elected
officials. Under the comprehensive settlement agreement the Company has agreed
to $200 million in rate reductions for all customers over the period January 1,
2002 through 2005 and extended rate caps on the Company's retail electric
distribution charges through December 31, 2006, electric reliability and
customer service standards, mechanisms to enhance competition and customer
choice, expanded assistance to low-income customers, extensive funding for wind
and solar energy and community education, nuclear safety research funds,
customer protection against nuclear costs outside of Pennsylvania, and
maintenance of charitable and civic contributions and employment for the
Company's headquarters in Philadelphia.
3. Segment Information
The Company evaluates the performance of its business segments based on Earnings
Before Interest Expense and Income Taxes (EBIT). The Company's general corporate
expenses and certain non-recurring expenses are excluded from the internal
evaluation of reportable segment performance. General corporate expenses include
the cost of executive management, corporate accounting and finance, information
technology, risk management, human resources and legal functions and employee
benefits.
The Company's distribution business unit consists of its regulated operations
including electric transmission and distribution services, retail sales of
generation services and retail gas sales and services. The Company's generation
business unit consists of its generation assets, its power marketing group, its
unregulated retail energy supplier and its investment in AmerGen. The Company's
ventures business unit consists of its infrastructure services business, its
telecommunications equity investments and other investments.
An analysis and reconciliation of the Company's business segment information to
the respective information in the consolidated financial statements are as
follows (in thousands):
Intersegment
Distribution Generation Ventures Corporate Revenues Consolidated
Revenues:
1999 $ 3,256,718 $2,868,835 $ 110,056 $- $ (798,856) $ 5,436,753
1998 $ 3,778,264 $2,492,886 $- $- $(1,008,618) $ 5,262,532
1997 $ 3,831,453 $1,721,417 $- $- $ (951,793) $ 4,601,077
EBIT:
1999 $ 1,381,686 $ 238,825 $ (41,098) $ (189,488) $- $ 1,389,925
1998 $ 1,372,875 $ 233,339 $(138,605) $ (257,563) $- $ 1,210,046
1997 $ 1,754,385 $ (380,985) $ (81,948) $ (282,049) $- $ 1,009,403
Depreciation and Amortization:
1999 $ 107,686 $ 125,154 $ 3,950 $- $- $ 236,790
1998 $ 532,602 $ 110,224 $ 16 $- $- $ 642,842
1997 $ 100,988 $ 479,301 $ 306 $- $- $ 580,595
Capital Expenditures:
1999 $ 204,404 $ 244,916 $ 1,408 $ 40,369 $- $ 491,097
1998 $ 174,974 $ 205,081 $ 6,271 $ 29,005 $- $ 415,331
1997 $ 219,776 $ 210,579 $ 6,393 $ 53,452 $- $ 490,200
Total Assets:
1999 $10,293,379 $1,779,103 $ 640,375 $ 406,652 $- $13,119,509
1998 $ 9,759,174 $1,686,771 $ 216,870 $ 385,548 $- $12,048,363
1997 $10,008,820 $1,729,920 $ 222,418 $ 395,410 $- $12,356,568
Equity in losses of telecommunications investments of $38 million, $54 million,
and $14 million for 1999, 1998, and 1997, respectively, are included in the
ventures business unit's EBIT.
4. Rate Matters
On May 14, 1998, the PUC issued a final order (Final Restructuring Order)
approving a Joint Petition for Settlement filed by the Company and numerous
parties to the Company's restructuring proceeding mandated by the Competition
Act. The Competition Act provides for the restructuring of the electric utility
industry in Pennsylvania, including the deregulation of generation operations
and the institution of retail competition for generation services beginning in
1999. The Final Restructuring Order provided for the recovery of $5.3 billion of
stranded costs through transition charges to distribution customers over a
12-year period beginning in 1999 with a 10.75% return on the balance. During the
12-year stranded cost recovery period, the Company is amortizing the recoverable
stranded costs in accordance with the rate schedules determined in the Final
Restructuring Order.
The Final Restructuring Order provided for the phase-in of customer choice of
electric generation supplier (EGS) for all customers: one-third of the peak load
of each customer class on January 1, 1999; one-third on January 2, 1999; and the
remaining one-third on January 1, 2000. The Final Restructuring Order also
established market share thresholds to ensure that a minimum number of
residential and commercial customers choose an EGS or a Company affiliate. If
less than 35% and 50% of residential and commercial customers have chosen an
EGS, including 20% of residential customers assigned to an EGS as a PLR default
supplier, by January 1, 2001 and January 1, 2003, respectively, the number of
customers sufficient to meet the necessary threshold levels shall be randomly
selected and assigned to an EGS through a PUC-determined process.
Effective January 1, 1999, electric rates were unbundled into transmission and
distribution components, a Competitive Transition Charge (CTC) for recovery of
stranded costs and an energy and capacity charge. Eligible customers who choose
an alternative EGS are not charged the energy and capacity charge or the
transmission charge and instead purchase their electric energy supply and
transmission at market-based rates from their EGS. The Company is in turn
reimbursed by the EGS, via the PJM Interconnection, L.L.C., for the cost of the
transmission service at a rate approximately equivalent to the unbundled
transmission rate. Also effective January 1, 1999, the Company unbundled its
retail electric rates for metering, meter reading and billing and collection
services to provide credits to those customers who elect to have an alternative
supplier perform these services.
In accordance with the Competition Act and the Final Restructuring Order, the
Company's retail electric rates are capped at the year-end 1996 levels
(system-wide average of 9.96 cents/kilowatt hour [kWh]) through June 2005. The
Final Restructuring Order required the Company to reduce its retail electric
rates by 8% from the 1996 system-wide average rate on January 1, 1999. This rate
reduction decreased to 6% on January 1, 2000 until January 1, 2001, when the
system-wide average rate cap will revert to 9.96 cents/kWh. The transmission and
distribution rate component will remain capped at a system-wide average rate of
2.98 cents/kWh through June 30, 2005. Additionally, generation rate caps,
defined as the sum of the applicable transition charge and energy and capacity
charge, will remain in effect through 2010.
The Final Restructuring Order requires that on January 1, 2001, 20% of all of
the Company's residential customers, determined by random selection and without
regard to whether such customers are obtaining generation service from an
alternate EGS, shall be assigned to a provider of last resort default supplier
other than the Company through a PUC-approved bidding process.
The Final Restructuring Order authorized the issuance of up to $4 billion of
transition bonds (Transition Bonds). In preparation for the issuance of
Transition Bonds, the Company formed the PECO Energy Transition Trust (PETT), an
independent statutory business trust organized under the laws of Delaware and a
wholly owned subsidiary of the Company. On March 25, 1999, PETT issued $4
billion of its Transition Bonds to securitize a portion of the Company's
authorized stranded cost recovery. PETT used the $3.95 billion of proceeds from
the issuance of Transition Bonds to purchase the Intangible Transition Property
(ITP) from the Company. In accordance with the Competition Act, the Company
utilized the proceeds from the securitization of a portion of its stranded cost
recovery principally to reduce stranded costs including related capitalization.
The Company utilized the net proceeds, and interest income earned on the net
proceeds, to repurchase 44.1 million shares of Common Stock for an aggregate
purchase price of $1,705 million and $150 million of accounts receivable; to
retire: $811 million of First Mortgage Bonds, a $400 million term loan, $532
million of commercial paper, a $139 million capital lease obligation and $37
million of preferred stock; to redeem $221 million of COMRPS; and to pay $25
million of debt issuance costs. The Transition Bonds are obligations of PETT,
secured by ITP. ITP represents the irrevocable right of the Company or its
assignee to collect non-bypassable charges from customers to recover stranded
costs.
On March 16, 2000, the PUC issued an order approving a Joint Petition for Full
Settlement of PECO Energy Company's Application for Issuance of a Qualified Rate
Order (QRO) authorizing the Company to securitize up to an additional $1 billion
of its authorized recoverable stranded costs. In accordance with the terms of
the Joint Petition for Full Settlement, when the QRO becomes final and
non-appealable, the Company, through its distribution business unit, will
provide its retail customers with rate reductions in the total amount of $60
million beginning on January 1, 2001. This rate reduction will be effective for
calendar year 2001 only and will not be contingent upon the issuance of
additional transition bonds pursuant to the QRO. The Company will use the
proceeds from any additional securitization principally to reduce stranded costs
and related capitalization.
5. Restructuring Charge
As required by SFAS No. 101, at December 31, 1997, the Company performed an
impairment test of its electric generation assets pursuant to SFAS No. 121, on a
plant-specific basis and determined that $6.1 billion of its $7.1 billion of
electric generation assets would be impaired as of December 31, 1998. The
Company estimated the fair value for each of its electric generating units by
determining its estimated future operating cash inflows and outflows. Cash flows
were determined based on projections of operating revenue, fuel costs, operating
and maintenance costs including administrative and general costs, other taxes,
nuclear decommissioning costs, capital expenditures, required life extension
costs and income taxes. Each plant whose gross future operating cash flows did
not exceed the net book value of the plant was determined to have failed the
first impairment test and was subjected to a second impairment test. In the
second impairment test, generation-related CTC of $3.3 billion, as provided by
the PUC in the Final Restructuring Order, was allocated on a pro rata basis to
the gross future operating cash flows of the plants determined to have failed
the first test. For each plant that failed either impairment test, the Company
wrote down the difference between the sum of the gross future operating cash
flows and the net book value. Since the Company's retail electric rates
continued to be cost-based through January 1, 1999, $333 million representing
depreciation expense on electric generation-related assets in 1998 and $91
million representing amortization of other regulatory assets in 1998 were
reclassified to a regulatory asset and were amortized in 1998.
At December 31, 1997, the Company had total electric generation-related stranded
costs of $8.4 billion, representing $5.8 billion of net stranded electric
generation plant and $2.6 billion of electric generation-related regulatory
assets. The original PUC restructuring order, issued in December 1997, allowed
the Company to recover $5.3 billion of its generation-related stranded costs
from customers. This resulted in a net unrecoverable amount of $3.1 billion.
Accordingly, the Company recorded an extraordinary charge at December 31, 1997
of $3.1 billion ($1.8 billion, net of taxes) of electric generation-related
stranded costs that will not be recovered from customers. The Final
Restructuring Order did not change the amount of allowable stranded costs.
A summary, as of December 31, 1997, of the electric generation-related stranded
costs and the amount of such stranded costs written off by the Company is shown
in the following table:
In Thousands
Electric generation-related asset impairment determined pursuant to SFAS No. 121
Net book value of electric generation-related assets before write-down $7,115,155
December 31, 1998 market value of electric generation-related assets pursuant to SFAS No. 121 (990,376)
Expected 1998 change in net plant recognized for recovery until cost-based rates cease at December 31, 1998 (303,800)
----------
Electric generation-related asset impairment 5,820,979
Electric generation-related regulatory assets
Recoverable Deferred Income Taxes 1,762,946
Deferred Limerick Costs 321,420
Deferred Non-Pension Postretirement Benefits Other Than Pensions 120,899
Deferred Energy Costs - Electric 92,021
Loss on Reacquired Debt 177,183
Above-market component of a purchase power agreement 90,000
Preliminary survey and investigation charges 38,173
Deferred employee compensation absences 20,760
Customer education program 31,547
Other post-retirement employee benefit obligations 6,384
Feasibility studies cost 8,434
Regulatory asset recognized for recovery until cost-based rates cease at December 31, 1998 (91,497)
----------
Total electric generation-related regulatory assets 2,578,270
----------
Total electric generation-related stranded costs 8,399,249
Amounts approved for collection from customers (regulatory asset pursuant to EITF No. 97-4) (5,274,624)
----------
Total Extraordinary Item $3,124,625
==========
In 1994, the Company accelerated the recognition of $180 million of non-pension
postretirement benefit transition obligation as a result of a voluntary
workforce reduction program which resulted in significant reductions in
eligibility for future benefits under the postretirement benefit plans. A
corresponding regulatory asset was recorded because the Company was permitted to
recover the curtailment costs through increased electric base rates. The $121
million of deferred non-pension postretirement benefits other than pensions
included in the calculation of stranded costs represents the remaining balance
of the generation portion of the regulatory asset.
6. Commitments and Contingencies
Capital Commitments
The Company estimates that it will spend approximately $927 million for capital
expenditures and other investments in 2000. The Company has commitments to
provide AmerGen with capital contributions equivalent to 50% of the purchase
price of any acquisitions AmerGen makes in 2000. As of December 31, 1999, the
Company expects to make $97 million of capital contributions, excluding nuclear
fuel, if all of the acquisition agreements that AmerGen entered into in 1999
close in 2000. In addition, the Company and British Energy plc have each agreed
to provide up to $55 million to AmerGen at any time for operating expenses. See
Note 26 - AmerGen Energy Company, L.L.C.
Nuclear Insurance
As of December 31, 1999, the Price-Anderson Act limited the liability of nuclear
reactor owners to $9.5 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 $9.3 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.
The Company carries property damage, decontamination and premature
decommissioning insurance in the amount of its $2.75 billion proportionate share
for each station loss resulting from damage to its nuclear plants. In the event
of an accident, insurance proceeds must first be used for reactor stabilization
and site decontamination. If the decision is made to decommission the facility,
a portion of the insurance proceeds will be allocated to a fund which the
Company is required by the Nuclear Regulatory Commission (NRC) to maintain to
provide for decommissioning the facility. The Company is unable to predict the
timing of the availability of insurance proceeds to the Company for the
Company's bondholders, and the amount of such proceeds which would be available.
Under the terms of the various insurance agreements, the Company could be
assessed up to $32 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. Such losses could have a material
adverse effect on the Company's financial condition and results of operations.
The Company is a member of an industry mutual insurance company which provides
replacement power cost insurance in the event of a major accidental outage at a
nuclear station. The premium for this coverage is subject to assessment for
adverse loss experience. The Company's maximum share of any assessment is $10
million per year.
Nuclear Decommissioning and Spent Fuel Storage
The Company's current estimate of its nuclear facilities' decommissioning cost
is $1.4 billion in 1998 dollars. Decommissioning costs are recoverable through
regulated rates. Under rates in effect through December 31, 1999, the Company
collected and expensed approximately $29 million in 1999 from customers which
was accounted for as a component of depreciation expense and accumulated
depreciation. At December 31, 1999 and 1998, $383 million and $336 million,
respectively, were included in accumulated depreciation. In order to fund future
decommissioning costs, at December 31, 1999 and 1998, the Company held $408
million and $380 million, respectively, in trust accounts which are included as
Investments in the Company's Consolidated Balance Sheets and include both net
unrealized and realized gains. Net unrealized gains of $45 million and $60
million, respectively, were recognized as a Deferred Credits in the Company's
Consolidated Balance Sheets at December 31, 1999 and 1998, respectively. The
Company recognized net realized gains of $14 million, $12 million, and $11
million as Other Income in the Company's Consolidated Statement of Income for
the years ended December 31, 1999, 1998 and 1997, respectively. The Company
believes that the amounts being recovered from customers through regulated rates
will be sufficient to fully fund the unrecorded portion of its decommissioning
obligation.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy
(DOE) is required to begin taking possession of all spent nuclear fuel generated
by the Company's nuclear units for long-term storage by no later than 1998.
Based on recent public pronouncements, it is not likely that a permanent
disposal site will be available for the industry before 2010, at the earliest.
In reaction to statements from the DOE that it was not legally obligated to
begin to accept spent fuel in 1998, a group of utilities and state government
agencies filed a lawsuit against the DOE which resulted in a decision by the
U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) in
July 1996 that the DOE had an unequivocal obligation to begin to accept spent
fuel in 1998. In accordance with the NWPA, the Company pays the DOE one mill
($.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 its 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.
Peach Bottom Atomic Power Station (Peach Bottom) has on-site pools with capacity
to store spent nuclear fuel discharged from the units through 2000 for Unit No.
2 and 2001 for Unit No. 3. Life-of-plant storage capacity will be provided by an
on-site dry cask storage facility, the construction of which was essentially
completed in 1999. The first use of this facility is scheduled for mid-2000.
Limerick Generating Station (Limerick) has on-site facilities with capacity to
store spent nuclear fuel to 2007. Salem Generating Station (Salem) has on-site
facilities with spent-fuel storage capacity through 2012 for Unit No. 1 and 2016
for Unit No. 2.
Energy Commitments
The Company's wholesale operations include the physical delivery and marketing
of power obtained through Company-owned generation capacity, and long,
intermediate and short-term contracts. The Company maintains a net positive
supply of energy and capacity, through Company-owned generation assets and power
purchase and lease agreements, to protect it from the potential operational
failure of one of its owned or contracted power generating units. The Company
has also contracted for access to additional generation through bilateral
long-term power purchase agreements. These agreements are firm commitments
related to power generation of specific generation plants and/or are
dispatchable in nature - similar to asset ownership. The Company enters into
power purchase agreements with the objective of obtaining low-cost energy supply
sources to meet its
physical delivery obligations to its customers. The Company has also purchased
firm transmission rights to ensure that it has reliable transmission capacity to
physically move its power supplies to meet customer delivery needs. The intent
and business objective for the use of its capital assets and contracts is to
provide the Company with physical power supply to enable it to deliver energy to
meet customer needs. The Company does not use financial contracts in its
wholesale marketing activities and as a matter of business practice does not
"pair off" or net settle its contracts. All contracts result in the delivery
and/or receipt of power.
The Company has entered into bilateral long-term contractual obligations for
sales of energy to other load-serving entities including electric utilities,
municipalities, electric cooperatives, and retail load aggregators. The Company
also enters into contractual obligations to deliver energy to wholesale market
participants who primarily focus on the resale of energy products for delivery.
The Company provides delivery of its energy to these customers in and out of PJM
through access to Company-owned transmission assets or rights for firm
transmission.
The Company has entered into three long-term power purchase agreements with
Independent Power Producers (IPP) under which the Company makes fixed capacity
payments to the IPP in return for exclusive rights to the energy and capacity of
the generating units for a fixed period. The terms of the long-term power
purchase agreements enable the Company to supply the fuel and dispatch energy
from the plants. The plants are currently being constructed and are scheduled to
begin operations in 2000, 2001 and 2002, respectively. These agreements provide
for access to capacity of up to 800 megawatts (Mw), 1,700 Mw and 2,500 Mw in
2000, 2001 and 2002, respectively.
At December 31, 1999, the Company had long-term commitments, in megawatt hours
(MwHs) and dollars, relating to the purchase and sale of energy, capacity and
transmission rights from unaffiliated utilities and others as expressed in the
tables below (in thousands):
Power Only
-------------------------------------------------------------------------
Purchases Sales
---------------------------- ------------------------------
MwHs Dollars MwHs Dollars
----- -------- ------ ----------
2000 8,389 $182,188 16,291 $ 499,966
2001 6,684 121,194 9,324 322,496
2002 6,684 128,119 6,309 232,898
2003 6,684 135,060 4,539 108,391
2004 4,928 113,277 3,246 74,501
Thereafter 2,936 82,500 6,396 152,521
-------- ----------
Total $762,338 $1,390,773
======== ==========
Capacity Capacity Transmission
Purchases Sales Rights
in Dollars in Dollars in Dollars
---------- ---------- ------------
2000 $ 44,723 $62,971 $ 99,817
2001 131,991 68,493 60,295
2002 142,153 58,190 30,326
2003 169,479 54,332 27,156
2004 153,676 41,459 19,811
Thereafter 1,355,200 66,714 19,811
---------- -------- --------
Total $1,997,222 $352,159 $257,216
========== ======== ========
In November 1997, the Company signed an agreement with the Massachusetts Health
and Education Facilities Authority (HEFA) to provide power to HEFA's members and
employees in anticipation of deregulation of the electricity industry in
Massachusetts. In the third quarter of 1999, the Company determined that, based
upon anticipated prices of energy in Massachusetts through the remaining life of
the HEFA contract, it had incurred a loss of approximately $36 million.
On April 23, 1999, the Company and Grays Ferry Cogeneration Partnership (Grays
Ferry) entered into a final settlement of litigation, subject to the resolution
of certain issues. The settlement resulted in a restructuring of the power
purchase agreements between the Company and Grays Ferry. The settlement also
required the Company to contribute its partnership interest in Grays Ferry to
the remaining partners. Accordingly, in the first quarter, the Company recorded
a charge to earnings of $14.6 million for the transfer of its partnership
interest. The charge for the partnership interest transfer is recorded in Other
Income and Deductions on the Company's Consolidated Statements of Income. The
settlement also resolved the litigation with Westinghouse Power Generation and
the Chase Manhattan Bank.
During the third quarter of 1999, the Company revised its estimate for losses
associated with the Grays Ferry power purchase agreements and reversed
approximately $26 million of reserves, which consisted of the remaining balance
of the reserve recognized in 1997.
Environmental Issues
The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under federal and state environmental laws, the Company is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by the Company and of property contaminated by
hazardous substances generated by the Company. The Company owns or leases a
number of real estate parcels, including parcels on which its operations or the
operations of others may have resulted in contamination by substances which are
considered hazardous under environmental laws. The Company is currently involved
in a number of proceedings relating to sites where hazardous substances have
been deposited and may be subject to additional proceedings in the future.
The Company has identified 28 sites where former manufactured gas plant (MGP)
activities have or may have resulted in actual site contamination. The Company
is presently engaged in performing various levels of activities at these sites,
including initial evaluation to determine the existence and nature of the
contamination, detailed evaluation to determine the extent of the contamination
and the necessity and possible methods of remediation, and implementation of
remediation. The Pennsylvania Department of Environmental Protection has
approved the Company's clean up of three sites. Ten other sites are currently
under some degree of active study and/or remediation.
As of December 31, 1999 and 1998, the Company had accrued $57 million and $60
million, respectively, for environmental investigation and remediation costs,
including $32 million and $33 million, respectively, for MGP investigation and
remediation, that currently can be reasonably estimated. The Company cannot
reasonably estimate whether it will incur other significant liabilities for
additional investigation and remediation costs at these or additional sites
identified by the Company, environmental agencies or others, or whether such
costs will be recoverable from third parties.
Leases Leased property included in property, plant and equipment was as follows:
At December 31,
-----------------
In Thousands 1999 1998
------- --------
Nuclear fuel $ -- $523,325
Electric plant 2,321 2,321
------ --------
Gross leased property 2,321 525,646
Accumulated amortization (1,853) (371,338)
------ --------
Net leased property $468 $154,308
====== ========
Amortization of leased property totaled $17 million, $60 million, and $39
million for the years ended December 31, 1999, 1998, and 1997, respectively.
Interest expense on capital lease obligations was $3 million, $9 million, and $9
million in 1999, 1998, and 1997, respectively.
Minimum future lease payments as of December 31, 1999 were:
In Thousands
For the Years Capital Operating
Ending December 31, Leases Leases Total
------- --------- -------
2000 $92 $48,421 $48,513
2001 92 40,179 40,271
2002 92 34,531 34,623
2003 92 41,113 41,205
2004 92 29,720 29,812
Remaining years 629 487,663 488,292
------ -------- --------
Total minimum future lease payments $1,089 $681,627 $682,716
------ ======== ========
Imputed interest (17%) (621)
------
Present value of net minimum
future lease payments $468
======
Rental expense under operating leases totaled $54 million, $69 million and $74
million in 1999, 1998 and 1997, respectively.
In 1999, the Company entered into a lease for two buildings that will be the
headquarters for its generation business unit. These buildings are being
constructed in Kennett Square, Pennsylvania and are anticipated to be completed
on or about June 1, 2000 and September 1, 2000, respectively. The lease terms
are for 20 years with renewal options. Estimated lease payments for 2000 are $4
million.
Litigation
Cajun Electric Power Cooperative, Inc. 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 the full purchase price of the 30%
interest in the River Bend nuclear plant, $50 million, plus interest and
consequential damages. While the Company cannot predict the outcome of this
matter, the Company believes that it validly exercised its right of termination
and did not breach the agreement.
Pennsylvania Real Estate Tax Appeals
The Company is involved in tax appeals regarding two of its nuclear facilities,
Limerick (Montgomery County) and Peach Bottom (York County). The Company is also
involved in the tax appeal for Three Mile Island Unit No. 1 Nuclear Generating
Facility (Dauphin County) through
AmerGen. The Company does not believe the outcome of these matters will have a
material adverse effect on the Company's results of operations or financial
condition.
General
The Company is involved in various other litigation matters. The ultimate
outcome of such matters, while uncertain, is not expected to have a material
adverse effect on the Company's financial condition or results of operations.
7. Retirement Benefits
The Company and its subsidiaries have a defined benefit pension plan and
postretirement benefit plans applicable to essentially all employees. The
following provides a reconciliation of benefit obligations, plan assets and
funded status of the plans.
Pension Benefits Other Postretirement Benefits
-------------------------- -----------------------------
In Thousands 1999 1998 1999 1998
Change in Benefit Obligation
Net benefit obligation at beginning of year $ 2,309,586 $ 2,141,040 $ 847,771 $ 779,231
Service cost 28,780 30,167 18,756 18,375
Interest cost 153,740 153,644 57,518 53,924
Plan participants' contributions -- -- 419 397
Plan amendments 25,000 -- -- --
Actuarial (gain)/loss (299,667) 143,274 (76,651) (8,260)
Curtailments -- (73,330) -- 10,403
Settlements -- (46,541) -- --
Special termination benefits -- 114,182 -- 29,712
Gross benefits paid (163,496) (152,850) (49,329) (36,011)
----------- ----------- ----------- -----------
Net benefit obligation at end of year $ 2,053,943 $ 2,309,586 $ 798,484 $ 847,771
=========== =========== =========== ===========
Change in Plan Assets
Fair value of plan assets at beginning of year $ 2,745,347 $ 2,538,039 $ 223,285 $ 178,045
Actual return on plan assets 399,863 343,754 20,076 23,535
Employer contributions 495 16,404 50,047 57,319
Plan participants' contributions -- -- 419 397
Gross benefits paid (163,496) (152,850) (49,329) (36,011)
----------- ----------- ----------- -----------
Fair value of plan assets at end of year $ 2,982,209 $ 2,745,347 $ 244,498 $ 223,285
=========== =========== =========== ===========
Funded status at end of year $ 928,266 $ 435,761 $ (553,986) $ (624,486)
Unrecognized net actuarial (gain)/loss (1,129,187) (659,480) (42,738) 37,617
Unrecognized prior service cost 84,923 65,419 -- --
Unrecognized net transition obligation (asset) (26,071) (30,512) 153,944 165,786
----------- ----------- ----------- -----------
Net amount recognized at end of year $ (142,069) $ (188,812) $ (442,780) $ (421,083)
=========== =========== =========== ===========
Amounts recognized in the consolidated balance sheets consist of:
Prepaid benefit cost $ 70,129 $ 30,462 N/A N/A
Accrued benefit cost (212,198) (219,274) (442,780) (421,083)
----------- ----------- ----------- -----------
Net amount recognized at end of year $ (142,069) $ (188,812) $ (442,780) $ (421,083)
=========== =========== =========== ===========
Pension Benefits Other Postretirement Benefit
---------------------- ---------------------------------------------
1999 1998 1997 1999 1998 1997
Weighted-average assumptions as of December 31,
Discount rate 8.00% 7.00% 7.25% 8.00% 7.00% 7.25%
Expected return on plan assets 9.50% 9.50% 9.50% 8.00% 8.00% 8.00%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00% 5.00% 5.00%
Health care cost trend on covered charges N/A N/A N/A 8.0% 6.5% 7.0%
decreasing decreasing decreasing
to ultimate to ultimate to ultimate
trend of 5.0% trend of 5.0% trend of 5.0%
in 2006 in 2002 in 2002
Pension Benefits Other Postretirement Benefit
----------------------------------- ----------------------------------
1999 1998 1997 1999 1998 1997
Components of net periodic
benefit cost (benefit)
Service cost $28,780 $30,167 $25,368 $18,756 $ 18,375 $14,401
Interest cost 153,740 153,644 150,057 57,518 53,924 54,149
Expected return on assets (222,166) (209,976) (182,866) (16,372) (13,243) (9,984)
Amortization of:
Transition obligation (asset) (4,441) (4,538) (4,538) 11,842 14,882 14,882
Prior service cost 5,496 6,441 6,441 -- -- --
Actuarial (gain)loss (7,657) (7,028) (3,898) -- -- --
Curtailment charge (credit) -- (62,002) -- -- 52,961 --
Settlement charge (credit) -- (13,439) -- -- -- --
-------- --------- ------- ------- -------- -------
Net periodic benefit cost (benefit) $(46,248) $(106,731) $(9,436) $71,744 $126,899 $73,448
======== ========= ======= ======= ======== =======
Special termination benefit charge $ -- $114,182 $ -- $ -- $ 29,712 $ --
======== ========= ======= ======= ======== =======
Sensitivity of retiree welfare results
Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components $11,240
on postretirement benefit obligation $90,130
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components $(9,150)
on postretirement benefit obligation $(74,980)
Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plans.
During 1999, all retirees and beneficiaries who began receiving benefit payments
prior to January 1, 1994 were granted a cost-of-living adjustment resulting in a
$25 million increase in the projected benefit obligation. During 1998, costs
were recognized for special termination benefits in connection with the
retirement incentives and enhanced severance benefits provided under the
Company's Workforce Reduction Program.
The Company provides certain health care and life insurance benefits for retired
employees. Company employees become eligible for these benefits if they retire
from the Company with ten years of service. These benefits and similar benefits
for active employees are provided by several insurance companies whose premiums
are based upon the benefits paid during the year.
The Company sponsors a qualifying savings plan covering all employees.
Contributions made by participating employees are matched based on a specified
percentage of employee contribution up to 5% of the employees' pay base. The
cost of the Company's matching contribution to the savings plan totaled $7
million, $7 million and $3 million in 1999, 1998 and 1997, respectively.
8. Accounts Receivable
Accounts receivable-Customer at December 31, 1999 and 1998 included unbilled
operating revenues of $153 million and $142 million, respectively. The allowance
for uncollectible accounts at December 31, 1999 and 1998 was $112 million and
$122 million, respectively.
Accounts receivable-Other at December 31, 1999 and 1998 included notes
receivable from a telecommunications investment of $153 million and $89 million,
respectively. The interest rate on the notes receivable was 5.66% and 4.28% at
December 31, 1999 and 1998, respectively. Interest income related to the notes
receivable was $6 million and $3 million in 1999 and 1998, respectively.
The Company is party to an agreement with a financial institution under which it
can sell or finance with limited recourse an undivided interest, adjusted daily,
in up to $275 million of designated accounts receivable until November 2000. At
December 31, 1999, the Company had sold a $275 million interest in accounts
receivable, consisting of a $226 million interest in accounts receivable which
the Company accounted for as a sale under SFAS No. 125, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,"
and a $49 million interest in special-agreement accounts receivable which were
accounted for as a long-term note payable. See Note 14 - Long-Term Debt. The
Company retains the servicing responsibility for these receivables. The
agreement requires the Company to maintain the $275 million interest, which, if
not met, requires the Company to deposit cash in order to satisfy such
requirements. At December 31, 1999, the Company met this requirement and was not
required to make a deposit. As of December 31, 1999, the Company was not in
compliance with one of the requirements of the agreement; however, a waiver has
been obtained.
9. Property, Plant and Equipment
A summary of property, plant and equipment by classification as of December 31,
1999 and 1998 is as follows:
In Thousands 1999 1998
---------- ----------
Electric - Transmission & Distribution $3,953,321 $3,833,780
Electric - Generation 1,941,881 1,713,430
Gas 1,175,598 1,131,999
Common 403,760 407,320
Nuclear Fuel 1,551,501 932,156
Construction Work in Progress 231,721 272,590
Leased Property 2,321 525,646
Other Property, Plant and Equipment 152,029 44,520
---------- ----------
Total Property, Plant and Equipment 9,412,132 8,861,441
Less Accumulated Depreciation (including
accumulated amortization of nuclear
fuel of $1,280,850 and $790,249 in
1999 and 1998, respectively) 4,367,124 4,056,972
---------- ----------
Property, Plant and Equipment, net $5,045,008 $4,804,469
========== ==========
Depreciation expense was $188 million, $182 million, and $489 million in 1999,
1998 and 1997, respectively.
10. Common Stock
At December 31, 1999 and 1998, common stock without par value consisted of
500,000,000 shares authorized and 181,271,692 and 224,684,306 shares
outstanding, respectively. At December 31, 1999, there were 5,800,841 shares
reserved for issuance under the Company's Dividend Reinvestment and Stock
Purchase Plan.
Stock Repurchase
During 1997, the Company's Board of Directors authorized the repurchase of up to
25 million shares of its common stock from time to time through open-market,
privately negotiated and/or other types of transactions in conformity with the
rules of the SEC. Pursuant to these authorizations, the Company entered into
forward purchase agreements to be settled from time to time, at the Company's
election, on a physical, net share or net cash basis. The Company utilized the
proceeds from the securitization of a portion of its stranded cost recovery to
physically settle these agreements in the first quarter of 1999, resulting in
the purchase of 21.5 million shares of common stock for $696 million. In
connection with the settlement of these agreements, the Company received $18
million in accumulated dividends on the repurchased shares and paid $6 million
of interest.
In January 2000, in connection with the Merger Agreement, the Company entered
into a forward purchase agreement to purchase $500 million of its common stock
from time to time through open-market, privately negotiated and/or other types
of transactions in conformity with the rules of the SEC. This forward purchase
agreement can be settled from time to time, at the Company's election, on a
physical, net share or net cash basis. The amount at which these agreements can
be settled is dependent principally upon the market price of the Company's
common stock as compared to the forward purchase price per share and the number
of shares to be settled.
Stock Option Plans
The Company maintains a Long-Term Incentive Plan (LTIP) for certain full-time
salaried employees of the Company and a broad-based incentive program for all
other employees. The types of long-term incentive awards which have been granted
under the LTIP are non-qualified options to purchase shares of the Company's
common stock and shares of restricted common stock. The types of long-term
incentive awards which have been granted under the broad-based incentive program
are non-qualified options to purchase shares of the Company's common stock. At
December 31, 1999, there were 9,000,000 options authorized for issuance under
the LTIP and 2,000,000 options authorized under the broad-based incentive
program. The Company uses the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." If the Company elected to account for
its stock option plans based on SFAS No. 123, it would have recognized
compensation expense of $10 million, $6 million and $2 million, respectively for
1999, 1998 and 1997, respectively. In addition, earnings applicable to common
stock would have been $560 million, $494 million and $(1,516) million for 1999,
1998 and 1997, respectively, and earnings per average common share would have
been $2.84, $2.20 and $(6.81) for 1999, 1998 and 1997, respectively.
The exercise price of the stock options is equal to the fair market value of the
underlying stock on the date of issue. Options granted under the LTIP and the
broad-based incentive program become exercisable upon attainment of a target
share value and/or time. All options expire 10 years from the date of grant.
Information with respect to the LTIP and the broad-based incentive program at
December 31, 1999 and changes for the three years then ended, is as follows:
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Price Price Price
Shares (per share) Shares (per share) Shares (per share)
1999 1999 1998 1998 1997 1997
Balance at January 1 4,663,008 $27.71 3,816,794 $26.14 2,961,194 $26.68
Options granted 2,049,789 39.32 3,087,558 28.37 1,139,000 22.49
Options exercised (568,000) 25.17 (2,130,744) 23.86 -- --
Options canceled (78,900) 38.14 (110,600) 26.40 (283,400) 24.96
--------- ---------- ---------
Balance at December 31 6,065,897 31.91 4,663,008 28.65 3,816,794 26.14
========= ========== =========
Exercisable at December 31 3,331,903 25.60 3,462,550 23.91 2,800,794 26.65
========= ========== =========
Weighted average fair value of
options granted during year $8.24 $3.43 $2.97
===== ===== =====
The fair value of each option is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 1999, 1998 and 1997, respectively:
1999 1998 1997
Dividend yield 5.7% 6.8% 6.2%
Expected volatility 30.5% 21.4% 19.5%
Risk-free interest rate 5.9% 5.5% 6.4%
Expected life (years) 9.5 9.5 5
At December 31, 1999, the option groups outstanding, based on ranges of exercise
prices, were as follows:
Options Outstanding Options Exercisable
------------------------------------ -----------------------
Weighted
Remaining
Average Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercise Prices Outstanding (years) Price Exercisable Price
- - --------------- ----------- --------- -------- ----------- --------
$15.75-$20.00 827,150 7.71 $19.61 827,150 $19.61
$20.01-$25.00 890,500 7.75 22.17 890,500 22.17
$25.01-$30.00 1,204,300 4.73 27.43 1,201,800 27.43
$30.01-$35.00 203,400 9.49 33.51 44,000 32.92
$35.01-$50.00 2,940,547 9.23 40.03 368,453 40.53
--------- ---------
Total 6,065,897 3,331,903
========= =========
The Company issued 120,300 and 7,000 shares of restricted common stock during
1999 and 1998, respectively. Vesting for the restricted common stock awards is
over a period not to exceed 10 years from the grant date. Compensation cost of
$5 million and $0.2 million, respectively, associated with these awards is
amortized to expense over the vesting period. The related accumulated
amortization was approximately $2 million at December 31, 1999.
11. Earnings Per Share
Diluted earnings per average common share is calculated by dividing earnings
applicable to common stock by the weighted average shares of common stock
outstanding including stock options outstanding under the Company's stock option
plans considered to be common stock equivalents. The following table shows the
effect of these stock options on the weighted average number of shares
outstanding used in calculating diluted earnings per average common share (in
thousands):
1999 1998 1997
------- ------- -------
Average Common Shares Outstanding 196,285 223,219 222,543
Assumed Conversion of Stock Options 1,331 685 --
------- ------- -------
Potential Average Dilutive Common Shares Outstanding 197,616 223,904 222,543
======= ======= =======
12. Preferred and Preference Stock
At December 31, 1999 and 1998, Series Preference Stock, no par value, consisted
of 100,000,000 shares authorized, of which no shares were outstanding. At
December 31, 1999 and 1998, cumulative Preferred Stock, no par value, consisted
of 15,000,000 shares authorized and the amounts set forth below:
Shares Outstanding Amount in Thousands
Current ------------------ -------------------
Redemption At December 31,
Price (a) 1999 1998 1999 1998
---------- --------- --------- -------- --------
Series (without mandatory redemption)
$4.68 $104.00 150,000 150,000 $15,000 $15,000
$4.40 112.50 274,720 274,720 27,472 27,472
$4.30 102.00 150,000 150,000 15,000 15,000
$3.80 106.00 300,000 300,000 30,000 30,000
$7.48 (b) 500,000 500,000 50,000 50,000
--------- --------- -------- --------
1,374,720 1,374,720 137,472 137,472
Series (with mandatory redemption)
$6.12 (c) 556,200 927,000 55,609 92,700
--------- --------- -------- --------
Total preferred stock 1,930,920 2,301,720 $193,081 $230,172
========= ========= ======== ========
(a) Redeemable, at the option of the Company, at the indicated dollar amounts
per share, plus accrued dividends.
(b) None of the shares of this series are subject to redemption prior to April
1, 2003.
(c) The Company exercised its right to double (to 370,800 shares, from the
original 185,400 share requirement) the first annual sinking fund
requirement for the $6.12 Series on August 2, 1999. Future annual sinking
fund requirements in 2000 to 2002 are $18.5 million.
13. Company Obligated Mandatorily Redeemable Preferred Securities of a
Partnership (COMRPS)
At December 31, 1999 and 1998, PECO Energy Capital, L.P. (Partnership), a
Delaware limited partnership of which a wholly owned subsidiary of the Company
is the sole general partner, had outstanding COMRPS as set forth in the
following table:
Trust Receipts Outstanding Amount in Thousands
Mandatory Distri- -------------------------- -------------------
Redemption bution At December 31,
Series Date Rate 1999 1998 1999 1998
- - ----- ---------- ------- --------- ---------- -------- --------
A (a) 2043 9.00% -- 8,850,000 $ -- $221,250
C (b) 2037 8.00% 2,000,000 2,000,000 50,000 50,000
D (c) 2028 7.38% 78,105 78,105 78,105 78,105
--------- ---------- -------- --------
Total 2,078,105 10,928,105 $128,105 $349,355
========= ========== ======== ========
(a) On July 30, 1999, PECO Energy Capital Trust I redeemed all outstanding
Trust Receipts, each representing a 9.00% Cumulative Monthly Income
Preferred Security, Series A of PECO Energy Capital, L.P.
(b) Ownership of this series is evidenced by Trust Receipts, each representing
an 8.00% COMRPS, Series C with a liquidation value of $25, representing
limited partnership interests. The Trust Receipts were issued by PECO
Energy Capital Trust II, the sole assets of which are 8.00% COMRPS, Series
C. Each holder of Trust Receipts is entitled to withdraw the corresponding
number of 8.00% COMRPS, Series C from the Trust in exchange for the Trust
Receipts so held.
(c) Ownership of this series is evidenced by Trust Receipts, each representing
a 7.38% COMRPS, Series D with a liquidation value of $1,000, representing
limited partnership interests. The Trust Receipts were issued by PECO
Energy Capital Trust III, the sole assets of which are 7.38% COMRPS, Series
D. Each holder of Trust Receipts is entitled to withdraw the corresponding
number of 7.38% COMRPS, Series D from the Trust in exchange for the Trust
Receipts so held.
Each series is supported by the Company's deferrable interest subordinated
debentures, held by the Partnership, which bear interest at rates equal to the
distribution rates on the related series of COMRPS. The interest expense on the
debentures is included in Other Income and Deductions in the Consolidated
Statements of Income and is deductible for tax purposes.
14. Long-Term Debt
PECO Energy Transition Trust - Series 1999-A Transition Bonds
Expected At December 31,
Final Termi- 1999 1998
Payment nation ------- -------
Class Rate Date(a) Date(a) In Thousands
- - ----- ---- -------- ------ --------------------
A-1 5.48% 2001 2003 $201,970 $ --
A-2 5.63% 2003 2005 275,371 --
A-3 6.06%(b) 2004 2006 667,000 --
A-4 5.80% 2005 2007 458,519 --
A-5 6.14%(b) 2007 2009 464,600 --
A-6 6.05% 2007 2009 993,386 --
A-7 6.13% 2008 2009 896,654 --
Unamoritized debt discount (4,886) --
---------- ------
PECO Energy Transition Trust subtotal $3,952,614 $ --
Due
PECO Energy Company
First and refunding mortgage bonds (c)
7 1/2%-9 1/4% 1999 -- 325,000
5 5/8%-7 3/8% 2001 330,000 330,000
7 1/8%-8% 2002 500,000 500,000
6 1/2%-6 5/8% 2003 450,000 450,000
6 3/8%-10 1/4% 2005-2009 107,500 111,562
(d) 2010-2014 154,200 154,200
6 5/8%-8 3/4% 2020-2024 150,710 1,082,130
---------- ----------
Total first and refunding mortgage bonds 1,692,410 2,952,892
Notes payable 17,236 15,930
Pollution control notes (e) 369,125 212,705
Medium-term notes (f) 20,000 50,000
Note Payable - accounts receivable agreement (g) 49,381 66,837
Unamortized debt discount and premium, net (4,897) (17,249)
---------- ----------
PECO Energy Company subtotal 2,143,255 3,281,115
Other 551 --
---------- ----------
Total long-term debt 6,096,420 3,281,115
Due within one year (h) 127,762 361,523
---------- ----------
Long-Term debt $5,968,658 $2,919,592
========== ==========
(a) The Expected Final Payment Date is the date when all principal and interest
of the related class of Transition Bonds is expected to be paid in full in
accordance with the expected amortization schedule for the applicable
class. The Termination Date is the date when all principal and interest of
the related class of Transition Bond must be paid in full. The current
portion of Transition Bonds is based upon the expected maturity date.
(b) Floating rate, as of December 31, 1999, based upon the London Interbank
Offering Rate (LIBOR) plus 0.125% for the A-3 class and LIBOR plus 0.20%
for the A-5 class.
(c) Utility plant is subject to the lien of the Company's mortgage.
(d) Pollution control notes issued under the First and Refunding Mortgage. The
average annual floating rate was 3.23% at December 31, 1999.
(e) Floating rates, which were an average annual interest rate of 4.03% at
December 31, 1999.
(f) Medium-term notes collateralized by mortgage bonds. The average annual
interest rate was 9.095% at December 31, 1999.
(g) Floating rate which was 6.06% at December 31, 1999.
(h) Long-term debt maturities, including mandatory sinking fund requirements,
in the period 2000-2004 are as follows (in millions): 2000 - $127,762; 2001
- $525,656; 2002 - $785,951; 2003 - $927,461; 2004 - $523,156 and
$3,206,434 thereafter.
In 1998, the Company 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
were deferred and are being amortized over the life of the Transition Bonds as a
reduction of interest expense consistent with the Company's hedge accounting
policy. Through December 31, 1999, the Company has amortized approximately $9
million of the deferred gain.
In 1999, the Company incurred extraordinary charges aggregating $62 million ($37
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment of $811 million of First
Mortgage Bonds with a portion of the proceeds from the securitization of
stranded cost recovery and the refinancing of $156 million of pollution control
notes.
In 1998, the Company incurred extraordinary charges aggregating $33 million ($20
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment of $525 million of First
Mortgage Bonds.
15. Notes Payable, Banks
In Thousands 1999 1998 1997
-------- -------- --------
Average borrowings $241,636 $209,261 $248,111
Average interest rates, computed on daily basis 5.62% 5.83% 5.83%
Maximum borrowings outstanding $728,000 $525,000 $464,500
Average interest rates, at December 31 6.80% 6.17% 6.74%
The Company paid off its $400 million one-year term loan on March 26, 1999 with
the proceeds from the securitization of stranded costs.
The Company has a $900 million unsecured revolving credit facility with a group
of banks. The credit facility consists 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 its $600 million commercial paper
program. There was no debt outstanding under this credit facility at December
31, 1999 or 1998. At December 31, 1999 and 1998, the amount of commercial paper
outstanding was $142 million and $125 million, respectively. At December 31,
1999, the Company had $21 million outstanding on lines of credit. In addition,
at December 31, 1999 and 1998, the Company had available formal and informal
lines of credit with banks aggregating $100 million.
16. Income Taxes
Income tax expense (benefit) is comprised of the following components:
For the Years Ended December 31,
In Thousands 1999 1998 1997
Included in operations:
Federal
Current $293,093 $358,051 $ 251,509
Deferred 6,686 (109,211) (11,378)
Investment tax credit, net (14,301) (18,066) (18,201)
State
Current 71,695 95,309 76,689
Deferred 825 (6,429) (5,850)
-------- -------- -----------
$357,998 $319,654 $ 292,769
======== ======== ===========
Included in extraordinary item:
Federal
Current (19,693) (10,583) (123)
Deferred - - (987,234)
State
Current (5,722) (3,174) (29)
Deferred - - (303,575)
-------- -------- -----------
(25,415) (13,757) (1,290,961)
-------- -------- -----------
Total $332,583 $305,897 $ (998,192)
======== ======== ===========
The total income tax provisions, excluding the extraordinary item, differed from
amounts computed by applying the federal statutory tax rate to pre-tax income as
follows:
In Thousands 1999 1998 1997
Income Before Extraordinary Item $618,986 $532,378 $336,558
Total income tax provisions 357,998 319,654 292,769
-------- -------- --------
Income Before Income Taxes and Extraordinary Item $976,984 $852,032 $629,327
======== ======== ========
Income taxes on above at federal statutory rate of 35% $341,944 $298,211 $220,264
Increase (decrease) due to:
Property basis differences (7,926) (10,262 40,828
State income taxes, net of federal income tax benefit 46,704 57,582 46,046
Amortization of investment tax credit (14,301) (18,066) (18,201)
Prior period income taxes (7,153) (12,951) (2,985)
Other, net (1,270) 5,140 6,817
-------- -------- --------
Total income tax provisions $357,998 $319,654 $292,769
======== ======== ========
Effective income tax rate 36.6% 37.5% 46.5%
======== ======== ========
Provisions for deferred income taxes consist of the tax effects of the following
temporary differences:
In Thousands 1999 1998 1997
Depreciation and amortization $ 23,067 $ 140,448 $ 57,530
Deferred generation charges recoverable - (174,787) -
Transition bond hedge (29,010) - -
Deferred energy costs (9,341) (2,491) 2,256
Retirement and separation programs 7,076 (51,146) (12,734)
Incremental nuclear outage costs 3,610 (7,434) (981)
Uncollectible accounts 10,676 4,764 (1,710)
Reacquired debt (1,697) (5,026) (8,607)
Unbilled revenue (2,802) 3,579 (5,110)
Environmental clean-up costs 3,507 (3,574) (15,121)
Obsolete inventory 976 4,206 (7,074)
Limerick plant disallowances and phase-in plan - - (747)
AMT credits - (42,067) -
Other nuclear operating costs (6) 9,926 (9,892)
Other 1,455 7,962 (15,038)
-------- --------- -----------
Subtotal 7,511 (115,640) (17,228)
-------- --------- -----------
Extraordinary item (25,415) (13,757) (1,290,961)
-------- --------- -----------
Total $(17,904) $(129,397) $(1,308,189)
======== ========= ===========
The tax effect of temporary differences giving rise to the Company's net
deferred tax liability as of December 31, 1999 and 1998 is as follows:
Liability or (Asset)
In Thousands 1999 1998
Nature of temporary difference:
Plant basis difference $2,703,627 $2,653,760
Deferred investment tax credit 285,698 299,999
Deferred debt refinancing costs 36,923 37,575
Deferred pension and post-retirement obligations (147,977) (157,166)
Other, net (167,220) (143,209)
---------- ----------
Deferred income taxes (net) on the balance sheet $2,711,051 $2,690,959
========== ==========
The net deferred tax liability shown above as of December 31, 1999 and 1998 was
comprised of $3,140 million and $3,123 million of deferred tax liabilities, and
$429 million and $432 million of deferred tax assets, respectively.
In accordance with SFAS No. 71, the Company recorded a recoverable deferred
income tax asset of $638 million and $614 million at December 31, 1999 and 1998,
respectively. These balances are applicable only to regulated assets, due to the
discontinuance of SFAS No. 71 for the Company's electric generation operations.
These recoverable deferred income taxes include the deferred tax effects
associated principally with liberalized depreciation accounted for in accordance
with the ratemaking policies of the PUC, as well as the revenue impacts thereon,
and assume continued recovery of these costs in future rates.
The Internal Revenue Service (IRS) has completed and settled its examinations of
the Company's federal income tax returns through 1993. The 1994 through 1996
federal income tax returns have been examined and the Company and the IRS are in
the process of settling the audit which is not expected to have a material
adverse impact on financial condition or results of operations of the Company.
17. Taxes Other Than Income - Operating
For the Years Ended December 31,
In Thousands 1999 1998 1997
-------- -------- --------
Gross receipts $155,115 $155,663 $163,552
Capital stock 4,473 43,754 48,085
Real estate 72,083 51,313 69,597
Payroll 27,867 30,068 25,976
Other 2,194 (1,283) 2,881
-------- -------- --------
Total $261,732 $279,515 $310,091
======== ======== ========
18. Jointly Owned Electric Utility Plant
The Company's ownership interests in jointly owned electric utility plant at
December 31, 1999, were as follows:
Production Plants Transmission
------------------------------------------------------ and
Peach Bottom Salem Keystone Conemaugh Other
Plant
Public Service
Electric
PECO Energy and Gas Sithe Sithe Various
Operator Company Company Energy Inc. Energy Inc. Companies
- - -------- ------------- ---------- --------------- ----------- -------------
Participating 21% to
interest 42.49% 42.59% 20.99% 20.72% 43%
Company's share (In Thousands):
Utility plant $387,869 $17,739 $119,920 $192,555 $83,806
Accumulated depreciation 197,827 11,986 83,933 92,047 33,848
Construction work in progress 23,936 2,163 1,967 5,646 2,794
The Company's participating interests are financed with Company funds and, when
placed in service, all operations are accounted for as if such participating
interests were wholly owned facilities.
On September 30, 1999, the Company reached an agreement to purchase an
additional 7.51% ownership interest in Peach Bottom from certain operating
subsidiaries of Atlantic City Electric and Delmarva Power & Light Company for
$17.5 million. The sale is expected to be completed by mid-2000, subject to
federal and state approvals.
19. Supplemental Cash Flow Information
The following disclosures supplement the accompanying Consolidated Statements of
Cash Flows:
In Thousands 1999 1998 1997
-------- -------- --------
Cash paid during the year:
Interest (net of amount capitalized) $349,522 $384,932 $405,838
Income taxes (net of refunds) 304,473 346,539 345,232
Noncash investing and financing:
Capital lease obligations incurred - 38,307 32,909
Issuance of Exelon Infrastructure Services stock 11,000 - -
20. Investments
At December 31,
In Thousands 1999 1998
-------- --------
Trust accounts for decommissioning nuclear plants $408,450 $379,938
Telecommunications ventures 23,349 48,391
Investment in AmerGen 39,624 -
Energy services and other ventures 58,108 69,319
Marketable securities 8,700 -
-------- --------
Total $538,231 $497,648
======== ========
21. Financial Instruments
Fair values of financial instruments, including liabilities, are estimated based
on quoted market prices for the same or similar issues. The carrying amounts and
fair values of the
Company's financial instruments as of December 31, 1999 and 1998 were as
follows:
1999 1998
Carrying Carrying
In Thousands Amount Fair Value Amount Fair Value
---------- ---------- ---------- -----------
Non-derivatives:
Assets
Cash and cash equivalents $ 228,197 $ 228,197 $ 48,083 $ 48,083
Trust accounts for decommis sioning nuclear plants 408,450 408,450 379,938 379,938
Marketable securities 8,700 8,700 - -
Liabilities
Long-term debt (including amounts due within one year) 6,096,420 5,821,697 3,281,115 3,404,250
Derivatives:
Treasury forwards - - - (300)
Interest rate swaps - 35,800 - -
Forward interest rate swaps - 66,100 - (4,400)
Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of cash equivalents and customer accounts
receivable. The Company places its cash equivalents with high-credit quality
financial institutions. Generally, such investments are in excess of the Federal
Deposit Insurance Corporation limit. Concentrations of credit risk with respect
to customer accounts receivable are limited due to the Company's large number of
customers and their dispersion across many industries.
The fair value of derivatives generally reflects the estimated amounts that the
Company would receive or pay to terminate the contracts at the reporting date,
thereby taking into account the current unrealized gains or losses of open
contracts. Dealer quotes are available for all of the Company's derivatives.
The Company has entered into interest rate swaps relating to its two variable
rate series of Transition Bonds in the aggregate notional amount of $1.1 billion
with an average interest rate of 6.65%. The Company has also entered into
forward starting interest rate swaps relating to its two variable rate series of
Transition Bonds in the aggregate notional amount of $1.1 billion with an
average interest rate of 6.01%. The notional amount of derivatives do not
represent amounts that are exchanged by the parties and, thus, are not a
measure of the Company's exposure. The amounts exchanged are calculated on the
basis of the notional or contract amounts, as well as on the other terms of the
derivatives, which relate to interest rates and the volatility of these rates.
The Company would be exposed to credit-related losses in the event of
non-performance by the counterparties that issued the derivative instruments.
The Company does not expect that counterparties to the interest rate swaps will
fail to meet these obligations, given their high credit ratings. The credit
exposure of derivatives contracts is represented by the fair value of contracts
at the reporting date. The Company's interest rate swaps are documented under
master agreements. Among other things, these agreements provide for a maximum
credit exposure for both parties. Payments are required by the appropriate party
when the maximum limit is reached.
22. Early Retirement and Separation Program
In April 1998, the Board of Directors authorized the implementation of a
retirement incentive program and an enhanced severance benefit program. The
retirement incentive program allowed employees age 50 and older, who have been
designated as excess or who are in job classifications facing reduction, to
retire from the Company. The enhanced severance benefit program provided
non-retiring excess employees with fewer than ten years of service benefits
equal to two weeks pay per year of service. Non-retiring excess employees with
more than ten years of service received benefits equal to three weeks pay per
year of service.
Through its Cost Competitiveness Review, the Company identified 1,157 employees
across the Company who were considered excess or were in job classifications
facing reduction. Of the 1,157 employees, 711 were eligible for and agreed to
take the retirement incentive program. The remaining employees are eligible for
the enhanced severance benefit program. As of December 31, 1999, 497 employees
were eligible for and have taken the retirement incentive program and 502
employees were terminated with the enhanced severance benefit program. The
remaining employees are scheduled for termination through the end of June 2000.
At December 31, 1998, the Company incurred a charge of $125 million ($74
million, net of income taxes) for its Early Retirement and Separation Program
relating to 1,157 employees. This charge consisted of the following: $121
million for the actuarially determined pension and other postretirement benefits
costs and $4 million for outplacement services costs and the continuation of
benefits for one year. Approximately $0.8 million of the $125 million charge was
related to the Company's non-utility operations and accordingly was recorded in
Other Income and Deductions. The estimated cost of separation benefits was
approximately $47 million, of which $28 million was paid through December 31,
1999. The remaining balance of $19 million is expected to be paid by June 2000.
Retirement benefits of approximately $78 million are being paid to the retirees
over their lives. All cash payments related to the early retirement and
severance program are expected to be funded through the assets of the Company's
Service Annuity Plan.
23. Other Income and Deductions
Settlement of Salem Litigation
In 1997, the Company received $70 million pursuant to the May 1997 settlement
agreement with Public Service Electric and Gas Company resolving a suit filed by
the Company concerning the shutdown of Salem.
Other, Net consists of the following:
At December 31,
In Thousands 1999 1998 1997
-------- -------- --------
Interest income $ 51,619 $ 26,349 $ -
Gain on sale of assets 13,954 1,511 -
Settlement of power purchase agreement - 14,250 -
Write-off of investments (14,618) (7,128) (20,045)
Nonutility activities (34,806) (49,234) (33,246)
Other 2,462 (6,826) 1,458
-------- -------- --------
Total $ 18,611 $(21,078) $(51,833)
======== ======== ========
24. Regulatory Assets
At December 31, 1999 and 1998, the Company had deferred the following regulatory
assets on the Consolidated Balance Sheets:
In Thousands 1999 1998
---------- ----------
Competitive transition charge (see Note 5) $5,274,624 $5,274,624
Recoverable deferred income taxes (see Note 16) 638,060 614,445
Loss on reacquired debt 70,711 77,165
Compensated absences 4,298 4,289
Deferred energy costs 6,874 29,847
Non-pension postretirement benefits 84,421 90,915
---------- ----------
Total $6,078,988 $6,091,285
========== ==========
At December 31, 1999, the CTC includes the unamortized balance of $3.9 billion
of ITP sold to PETT in connection with the securitization of stranded cost
recovery. ITP represents the irrevocable right of the Company or its assignee to
collect non-bypassable charges from customers to recover stranded costs. See
Note 4 - Rate Matters.
25. Exelon Infrastructure Services Acquisitions
In October 1999, EIS, an unregulated subsidiary of the Company, acquired the
stock or assets of six utility service contracting companies for an aggregate
purchase price of approximately $233 million, including $11 million of EIS
stock. The purchase price also contains estimated contingent payments of $20
million based upon the achievement of targeted earnings of the acquired
companies over a one year period. The acquisitions were accounted for using the
purchase method of accounting. The allocation of purchase price to the fair
value of assets acquired and liabilities assumed is as follows (in thousands):
Current Assets $143,249
Long-Term Assets 85,893
Goodwill 121,110
Current Liabilities (115,408)
Long-Term Liabilities (1,352)
--------
Total $233,492
========
Goodwill associated with these acquisitions is being amortized over 20 years.
At December 31, 1999, Other Current Assets includes $48 million of Costs and
Earnings in Excess of Billings on uncompleted contracts and Other Current
Liabilities includes $9 million of Billings in Excess of Costs and Earnings on
uncompleted contracts.
26. AmerGen Energy Company, L.L.C.
In 1999, AmerGen, the Company's joint venture with British Energy plc, purchased
Clinton Nuclear Power Station (Clinton) and Three Mile Island Unit No. 1 Nuclear
Generating Facility. In 1999, the Company also entered into agreements to
purchase Nine Mile Point Unit 1 Nuclear Generating Facility, a 59% undivided
interest in Nine Mile Point Unit 2 Nuclear Generating Facility, Oyster Creek
Nuclear Generating Facility and Vermont Yankee Nuclear Power Station. These
purchases are expected to be completed in 2000 upon receipt of the required
federal and state approvals. The Company accounts for its investment in AmerGen
under the equity method of accounting. In conjunction with each of these
acquisitions, AmerGen has received a fully funded decommissioning trust fund
which has been computed assuming the anticipated costs to appropriately
decommission each nuclear plant discounted to net present value using the NRC's
mandated rate of 2%. AmerGen believes that the amount of the trust funds and
investment earnings thereon will be sufficient to meet its decommissioning
obligations.
27. Quarterly Data (Unaudited)
The data shown below include all adjustments which the Company considers
necessary for a fair presentation of such amounts:
Income (Loss)
Operating Operating Before Net
Revenues Income Extraordinary Item Income (Loss)
In Millions 1999 1998 1999 1998 1999 1998 1999 1998
Quarter ended
March 31 $1,256 $1,190 $ 376(a) $287 $157 $114 $157 $114
June 30 1,194 1,215 252 366 96(b) 151 69 151
September 30 1,732 1,786 484 549 231 274 231 274
December 31 1,255 1,072 297 84 135 (7)(c) 126 (26)
Earnings (Loss)
Earnings (Loss) Per Average Earnings
Applicable to Average Shares Share Before (Loss) Per
Common Stock Outstanding Extraordinary Item Average Share
In Millions 1999 1998 1999 1998 1999 1998 1999 1998
Quarter ended
March 31 $153 $110 223.4 222.5 $ 0.69 $0.50 $0.68 $0.50
June 30 61 148 192.0 222.7 0.48 0.66 0.34 0.66
September 30 228 270 186.6 223.1 1.22 1.21 1.22 1.21
December 31 123 (28) 183.8 224.5 0.71 (0.04) 0.66 (0.13)
(a) Includes the reclassification of a $7 million charge for the abandonment of
an information system implementation from Other Income and Deduction to
Operating and Maintenance Expense (O&M).
(b) Reflects increased fuel and energy interchange expenses related to Exelon
Energy and O&M expenses related to Clinton.
(c) Reflects a $125 million charge related to the Early Retirement and
Separation Program.
= = = =
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 2000 Annual Meeting of
Shareholders, which is expected to be filed with the U.S. Securities and
Exchange Commission by April 29, 2000, under the heading CHAPTER II -
INFORMATION ABOUT THE PECO ENERGY ANNUAL MEETING AND OTHER PROPOSALS - Proposals
for PECO Energy Annual Meeting - Item 3. Election of PECO Energy 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 2000 Annual Meeting of
Shareholders, which is expected to be filed with the U.S. Securities and
Exchange Commission by April 29, 2000, under the heading CHAPTER II -
INFORMATION ABOUT THE PECO ENERGY ANNUAL MEETING AND OTHER PROPOSALS - Proposals
for PECO Energy Annual Meeting - Item 3. Election of PECO Energy Directors and
is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information with respect to this caption is included in the Proxy
Statement of the Company in connection with its 2000 Annual Meeting of
Shareholders, which is expected to be filed with the U.S. Securities and
Exchange Commission by April 29, 2000, under the heading CHAPTER II -
INFORMATION ABOUT THE PECO ENERGY ANNUAL MEETING AND OTHER PROPOSALS - Proposals
for PECO Energy Annual Meeting - Item 3. Election of PECO Energy 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 2000 Annual Meeting of
Shareholders, which is expected to be filed with the U.S. Securities and
Exchange Commission by April 29, 2000, under the heading CHAPTER II -
INFORMATION ABOUT THE PECO ENERGY ANNUAL MEETING AND OTHER PROPOSALS - Proposals
for PECO Energy Annual Meeting -- Item 3. Election of PECO Energy Directors and
is incorporated herein by reference.
35
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Reference (Page)
Index
(a) 1. Financial Statements
Report of Independent Accountants .................. 56
Consolidated Statements of Income for the years
ended December 31, 1999, 1998 and 1997 ......... 57
Consolidated Statements of Cash Flows for the years
ended December 31, 1999, 1998 and 1997 ......... 58
Consolidated Balance Sheets as of December 31, 1999
and 1998 ....................................... 59
Consolidated Statements of Changes in Common
Shareholders' Equity and Preferred Stock for the
years ended December 31, 1999, 1998 and 1997 ... 61
Notes to Consolidated Financial Statements ......... 63
2. Financial Statement Schedules.
Schedule II--Valuation and Qualifying Accounts for
the years ended December 31, 1999,
1998 and 1997 ...................... 95
3. Exhibits.
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.
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, 1999
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS..... $122,139 $59,418 $ -- $69,543 $112,014
-------- ------- ------ ------- --------
TOTAL .................................. $122,139 $59,418 $ -- $69,543 $112,014
======== ======= ====== ======= ========
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
======== ======= ====== ======= ========
- - ------------
(1) Write-off of individual accounts receivable.
(2) Restated to reflect valuation allowance activity for Customer Assistance
Program and Special Agreement accounts.
36
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 be required to be
listed below have not been so listed because such instruments do not authorize
securities in an amount which exceeds 10% of the total assets of the Company and
its subsidiaries on a consolidated basis and the Company agrees to furnish a
copy of any such instrument to the Commission upon request.
Exhibit No. Description
2-1 Amended and Restated Agreement and Plan of Merger dated as of January
7, 2000, among PECO Energy Company, Exelon Corporation and Unicom
Corporation (Current Report on Form 8-K dated January 13, 2000,
Exhibit 2-1).
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
37
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
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 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).
4-5 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. (1998 Form 10-K, Exhibit 4-6)
4-6 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).
4-7 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. (1998 Form
10-K, Exhibit 4-10)
38
4-8 Revolving Credit Agreement, dated as of September 15, 1999, among the
Company, as borrower, and certain banks named therein.
4-9 364-day Credit Agreement, dated as of September 15, 1999, among the
Company, as borrower, and certain banks named therein.
4-10 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).
10-3 Agreement, dated November 24, 1971, between Atlantic City Electric
Company, Delmarva Power & Light Company, Public Service Electric and
Gas Company and the Company for ownership of Peach Bottom Atomic Power
Station; supplemental agreement dated September 1, 1975; 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
Statement, 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).
39
10-12 Amendment No. 2 to the Amended and Restated Limited Partnership
Agreement of PECO Energy Capital, L.P. (1995 Form 10-K, Exhibit 10-9).
10-13 Amendment No. 3 to the Amended and Restated Limited Partnership
Agreement of PECO Energy Capital, L.P. (1998 Form 10-K, Exhibit 10-14)
10-14 Amended and Restated Trust Agreement of PECO Energy Capital Trust II,
dated as of December 19, 1995.
10-15 Amended and Restated Trust Agreement of PECO Energy Capital Trust III,
dated as of April 6, 1998. (1998 Form 10-K, Exhibit 10-16)
10-16 Amended and Restated Trust Agreement for PECO Energy. Transition Trust
dated as of February 19, 1999 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 (PECO Energy
Transition Trust Current Report on Form 8-K dated March 31, 1999,
Exhibit 4.1.2)
10-17 Intangible Transition Property Sale Agreement dated as of March 25,
1999 between PECO Energy Transition Trust and PECO Energy Company
(PECO Energy Transition Trust Current Report on Form 8-K dated March
31, 1999, Exhibit 10.1).
10-18 Master Servicing Agreement between PECO Energy Transition Trust and
PECO Energy Company (PECO Energy Transition Trust Current Report on
Form 8-K dated March 31, 1999, Exhibit 10.2).
10-19 Form of Intangible Transition Property Sale Agreement between PECO
Energy Transition Trust and PECO Energy Company (Registration
Statement No. 333-31646, Exhibit 10.1)
10-20 Form of Intangible Transition Property Sale Agreement between PECO
Energy Transition Trust and PECO Energy Company (Registration
Statement No. 333-31646, Exhibit 10.2)
10-21 Joint Petition for Full Settlement of PECO Energy Company's
Restructuring Plan and Related Appeals and Application for a Qualified
Rate Order and Application for Transfer of Generation Assets dated
April 29, 1998. (Registration Statement No. 333-31646, Exhibit 10.3)
40
10-22 Form of Second Amended and Restated Trust Agreement for PECO Energy
Transition Trust (Registration Statement No. 333-31646).
12-1 Ratio of Earnings to Fixed Charges.
12-2 Ratio of Earnings to Combined Fixed Charges and Preferred Stock
Dividends.
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.
41
Reports on Form 8-K
During the quarter ended December 31, 1999, the Company filed the following
Current Reports on Form 8-K:
Date of earliest event reported:
September 22, 1999 reporting information under "ITEM 5. OTHER EVENTS"
and "ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND
EXHIBITS" regarding pro forma financial information about the merger of
the Company and Unicom.
Date of earliest event reported:
October 19, 1999 reporting information under "ITEM 5. OTHER EVENTS"
regarding Exelon Infrastructure Services, Inc., a subsidiary of the
Company, announcing the acquisition of five utility service companies.
Date of earliest event reported:
October 19, 1999 reporting information under "ITEM 5. OTHER EVENTS"
regarding AmerGen's accepted bid to acquire Vermont Yankee Nuclear
Power Station from Vermont Yankee Nuclear Power Corporation.
Date of earliest event reported:
December 16, 1999 reporting information under "ITEM 5. OTHER EVENTS"
regarding AmerGen's signing of the closing documents that officially
transfer ownership of Clinton to the Company.
Date of earliest event reported:
December 21, 1999 reporting information under "ITEM 5. OTHER EVENTS"
regarding AmerGen's completion of the sale of the Three Mile Island
Unit 1 Nuclear Generating Facility to the Company.
Subsequent to December 31, 1999, the Company filed the following Current Reports
on Form 8-K:
Date of earliest event reported:
January 7, 2000 reporting information under "ITEM 5. OTHER EVENTS"
regarding the approval by the Board of Directors of the Company and
Unicom Corporation to accelerate the repurchase of $1.5 billion in stock
and adjust shareholder consideration.
Date of earliest event reported:
January 13, 1999 reporting information under "ITEM 5. OTHER EVENTS"
regarding the provision of the Amended Merger Agreement and additional
information, including pro forma financial information, about the
transactions contemplated by the Amended Merger Agreement before the
Company commences repurchases of shares of its common stock.
Date of earliest event reported:
March 21, 2000 reporting information under "ITEM 5. OTHER EVENTS"
regarding the issuance of an order by the Pennsylvania Public Utility
Commission approving a Joint Petition for Full Settlement of PECO Energy
Company's Application for Issuance of a Qualified Rate Order authorizing
the Company to securitize up to an additional $1.0 billion of its
authorized recoverable stranded costs.
Date of earliest event reported:
March 24, 2000 reporting information under "ITEM 5. OTHER EVENTS"
regarding the filing with the PUC of a joint petition for settlement
reached with various parties to the Company's proceeding before the
PUC involving the proposed merger with Unicom.
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 30th day of March 2000.
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 30, 2000
- - --------------------------- Executive Officer and Director (Principal
C. A. McNeill, Jr. Executive Officer)
/s/ M. J. Egan Senior Vice President -- Finance and Chief March 30, 2000
- - --------------------------- 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 30, 2000
- - ------------------------------------
C.A. McNeill, Jr. Attorney-in-Fact