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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K/A

/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
(Exact name of registrant as specified in its charter)

Pennsylvania 23-0970240

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

P.O. Box 8699
2301 Market Street, Philadelphia, PA (215) 841-4000 19101
(Address of principal executive offices) (Registrant's telephone number, including area code) (Zip Code)

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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):

55/8% Series due 2001 63/8% Series due 2005 73/8% Series due 2001 61/2% 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 Pre
ferred 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 Com
pany (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 amend
ment 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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TABLE OF CONTENTS

Page No.
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PART I
ITEM 1. BUSINESS .................................................................... 1
General ..................................................................... 1
Distribution Business Unit .................................................. 2
General ................................................................... 2
Retail Electric Services .................................................. 2
Transmission Services ..................................................... 6
Gas ....................................................................... 6
Generation Business Unit .................................................... 7
General ................................................................... 7
Generation Assets ......................................................... 7
Limerick Generating Station ............................................... 9
Peach Bottom Atomic Power Station ......................................... 10
Salem Generating Station .................................................. 11
Fuel ...................................................................... 11
Power Marketing Group ..................................................... 13
Unregulated Retail Energy Supplier ........................................ 14
AmerGen Energy Company, LLC ............................................... 15
Ventures Business Unit ...................................................... 15
Exelon Infrastructure Services, Inc ....................................... 15
Telecommunications Ventures ............................................... 15
PECO Energy Transition Trust, PECO Energy Capital Corp. and Related Entities 15
Segment Information ......................................................... 16
Competition ................................................................. 16
Year 2000 Readiness Disclosure .............................................. 16
Capital Requirements ........................................................ 17
Construction ................................................................ 18
Employee Matters ............................................................ 18
Environmental Regulations ................................................... 18
Water ..................................................................... 19
Air ....................................................................... 19
Solid and Hazardous Waste ................................................. 21
Costs ..................................................................... 23
ITEM 2. PROPERTIES .................................................................. 24
ITEM 3. LEGAL PROCEEDINGS ........................................................... 25
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ......................... 26
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS ....................................................... 26
ITEM 6. SELECTED FINANCIAL DATA ..................................................... 27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS ................................................. 29
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK .................. 45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ................................. 47
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE .................................................. 79
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT .......................... 79
ITEM 11. EXECUTIVE COMPENSATION ...................................................... 85
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT ................................................................ 90
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS .............................. 91
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K ............................................................... 92
Financial Statements and Financial Statement Schedule ....................... 92
SCHEDULE II-- VALUATION AND QUALIFYING ACCOUNTS ............................. 93
Exhibits .................................................................... 94
Reports on Form 8-K ......................................................... 97
SIGNATURES ........................................................................... 98

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.

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.

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.

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

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(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.

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.

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.

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.

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.

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."

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 strain-

ers, 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.

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.

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.

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.

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.

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 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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
======

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.

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 $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.

For the Years Ended December 31,
--------------------------------------------------------------------------------
1999 1998 1997 1996 1995 1994
---- ---- ---- ---- ---- ----
(In Millions, except per share data)

Statement of 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 Com-
mon Stock ............................... 570 500 (1,514) 499 587 389
Earnings per Average Common Share:
Income Before Extraordinary Item ......... $ 3.10 $ 2.33 $ 1.44 $ 2.24 $ 2.64 $ 1.76
Extraordinary Item ....................... ( 0.19) ( 0.09) ( 8.24) -- -- --
------- ------- -------- -------- -------- --------
Net Income (Loss) ........................ $ 2.91 $ 2.24 $ (6.80) $ 2.24 $ 2.64 $ 1.76
======= ======= ========= ======== ======== ========
Dividends per Common Share ............... $ 1.00 $ 1.00 $ 1.80 $ 1.755 $ 1.65 $ 1.545
======= ======= ========= ======== ======== ========
Common Stock Equity ...................... $ 9.78 $ 13.61 $ 12.25 $ 20.88 $ 20.40 $ 19.41
======= ======= ========= ======== ======== ========
Average Shares of Common Stock
Outstanding ............................. 196.3 223.2 222.5 222.5 221.9 221.6
======= ======= ========= ======== ======== ========

At December 31,
---------------------------------------------------------------------------
1999 1998 1997 1996 1995 1994
---- ---- ---- ---- ---- ----
(In Millions)

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
======= ======= ======= ======= ======= =======

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

General

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.

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 Percentage
Items as a Percentage Dollar Changes
of Operating Revenue 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 (100%) 100%
Programs
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 (30%) 283%
Investments
--% (1%) 1% Other Income and Deductions 188% (217%)
---- --- ---
18% 16% 14% Income Before Income Taxes and 15% 35%
Extraordinary Item
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, 494 employees were eligible for and have taken the retirement incentive
program and 433 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 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.

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 costs 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 $565 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.

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

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.

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 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, 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.

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 fairly, 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.

PECO Energy Company and Subsidiary Companies
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

PECO Energy Company and Subsidiary Companies

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

PECO Energy Company and Subsidiary Companies
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
============ ===========
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

PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Common
Shareholders' Equity and Preferred Stock

Retained
Common Stock Other Earnings
------------------------ Paid-in (Accumulated
All Amounts in Thousands Shares Amount Capital Deficit)
- ------------------------------------------ --------- ------------- ------------- --------------

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
Repurchase of Common Stock ..............
Long-Term Incentive Plan Issuances 670 18,479 -- 11,714
------- ---------- --------- ------------
Preferred Stock Redemptions .............
Balance at December 31, 1999 ............. 225,354 $3,575,514 $ 1,236 $ (102,742)
======= ========== ======== ============

(RESTUBBED TABLE)

Accumulated
Other
Treasury Stock Compre- Compre- Preferred Stock
----------------------------- hensive hensive -----------------
All Amounts in Thousands Shares Amount 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 ............................. 24,489 (695,934)
Repurchase of Common Stock .............. 22,610 (1,009,385)
Long-Term Incentive Plan Issuances (17) 304
Preferred Stock Redemptions ............. (371) (37,091)
------ ------------- ------ ----- --------
Balance at December 31, 1999 ............. 44,082 $ (1,705,015) $ 4,015 1,931 $ 193,081
====== ============= ======= ===== =========

See Notes to Consolidated Financial Statements

PECO Energy Company and Subsidiary Companies

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

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.

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.

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 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

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 8.00% 6.50% 7.00%
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 amortiza-
tion 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
Average
Remaining 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

At December 31,
Expected --------------------------
1999 1998
Final -------------- -------
Payment Termination
Rate Date(a) Date(a) In Thousands
Class --------------- ---------- ------------ --------------------------

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 $3,952,614 $ --
Trust subtotal

PECO Energy Company

First and refunding mortgage bonds
(c) Due

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.

(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.

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 interest ................ 42.49% 42.59% 20.99% 20.72% 21% to 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

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, 494 employees were eligible for and have taken the retirement incentive
program and 433 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, AmerGen 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) 125 (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 $ 0.69 $ 0.50
June 30 .............. 66 148 192.0 222.7 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.

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 PECO Energy board of directors consists of 12 members, divided into
three classes. The three-year terms of each class are staggered so that the
term of one class expires at each annual meeting. The terms of the four Class I
directors will expire at the 2000 annual meeting.

Biographical Information of PECO Energy Directors

CORBIN A. McNEILL, JR.* Director since 1990

Mr. McNeill, age 60, is Chairman, President and Chief Executive Officer of PECO
Energy. He was elected Executive Vice President, Nuclear in 1988, President and
Chief Operating Officer in 1990, Chief Executive Officer in 1995 and Chairman
in 1997. Before joining PECO Energy in 1988, he was Senior Vice President,
Nuclear of Public Service Electric and Gas Company.

SUSAN W. CATHERWOOD Director since 1988

Ms. Catherwood, age 56, is the former Chairman of the Trustee Board, University
of Pennsylvania Medical Center and Health System and Vice Chairman of the Board
of the University of Pennsylvania. She was formerly Chairman of the Board of
Overseers of the University of Pennsylvania Museum. Ms. Catherwood is also a
director of the Glenmede Corporation, the Glenmede Trust Company, the Glenmede
Trust Company of New Jersey and the Pew Charitable Trusts.

DANIEL L. COOPER Director since 1997

Admiral Cooper, age 64, is the former Vice President and General Manager,
Nuclear Services Division of Gilbert/Commonwealth, Inc. He retired from the
Navy in 1991 as Assistant Chief of Naval Operations (Undersea Warfare). His
Navy career included service as Commander, Submarine Force, of the U.S.
Atlantic Fleet; Director of Navy Program Planning; and Director, Navy Budget.
He is a former director and Vice Chairman of the Board of USAA insurance
company, an insurance and financial services company; and until December 1999
was Chairman of the Advisory Board of Applied Research Laboratory, Penn State
University.

M. WALTER D'ALESSIO Director since 1983

Mr. D'Alessio, age 66, is Chairman, President and Chief Executive Officer of
Legg Mason Real Estate Services, commercial mortgage banking and pension fund
advisors. He is also a director of the Philadelphia Beltline Railroad,
Independence Blue Cross and the Brandywine Real Estate Investment Trust.

G. FRED DiBONA, JR. Director since 1997

Mr. DiBona, age 49, is President and Chief Executive Officer of Independence
Blue Cross, a health insurance organization. He also serves as Chairman,
President and Chief Executive Officer of Keystone Health Plan East, a
subsidiary of Independence Blue Cross. He is past chairman of the National Blue
Cross and Blue Shield Association. He is also a director of Tasty Baking
Company, Philadelphia Suburban Corporation, Eclipsys Corporation and Magellan
Health Services, Inc.

R. KEITH ELLIOTT Director since 1997

Mr. Elliott, age 58, is the former Chairman and Chief Executive Officer of
Hercules Incorporated, which produces specialty chemicals and related products.
He is also a director of Wilmington Trust Company and Computer Task Group.

RICHARD H. GLANTON* Director since 1991

Mr. Glanton, age 53, is a partner of the law firm of Reed Smith Shaw & McClay
LLP. Mr. Glanton is also a director of CGU Corporation of North America,
Philadelphia Suburban Corporation, Philadelphia Suburban Water Company,
Wackenhut Corrections Corporation and is Chairman of Philadelphia Television
Network, Inc.

Reed Smith Shaw & McClay LLP provided legal services to PECO Energy during
1999. Under the board's conflict of interest policy, the board specifically
reviewed the proposal to engage Mr. Glanton's partners to perform particular
legal services and concluded that the representation was in the best interest
of PECO Energy.

ROSEMARIE B. GRECO* Director since 1998

Ms. Greco, age 53, is the Principle of GRECO ventures and is the former
President of CoreStates Financial Corporation and Chief Executive Officer,
President and director of CoreStates Bank, N.A. She is also a director of
Sunoco, Inc., Pennsylvania Real Estate Investment Trust, Cardone Industries,
Inc., Genuardi's Family Markets, Inc., PWRT ComServe, Inc. and Radian Group,
Inc.

JOHN M. PALMS, Ph.D. Director since 1990

Dr. Palms, age 64, is President of the University of South Carolina and
Professor of Physics. He previously served as President of Georgia State
University and was the Charles Howard Chandler Professor of Physics and Vice
President for Academic Affairs of Emory University. He is also director of
Fortis, Inc., Policy Management Systems Corporation, Chairman of the Board of
Trustees of the Institute for Defense Analyses and a member of the Advisory
Council for the Institute of Nuclear Power Operations.

JOSEPH F. PAQUETTE, JR. Director since 1988

Mr. Paquette, age 65, retired as Chairman of the Board in 1997. During his
career with PECO Energy, he also held the positions of President, Chief
Executive Officer and Chief Operating Officer. He is also a director of AAA
Mid-Atlantic Inc. and Keystone Insurance Companies.

RONALD RUBIN Director since 1988

Mr. Rubin, age 68, is Chief Executive Officer of The Pennsylvania Real Estate
Investment Trust, a real estate management and development company. In 1997,
the Rubin Organization, Inc. was acquired by The Pennsylvania Real Estate
Investment Trust. He is a former director of Continental Bank and Midlantic
Bank.

ROBERT SUBIN* Director since 1994

Mr. Subin, age 61, retired as Senior Vice President--Global Sourcing &
Engineering for Campbell Soup Company in 1998. During his career at Campbell
Soup Company, he held the positions of Senior Vice President--Finance,
President of the Bakery and Confectionery Division, President of the
International Specialty Foods Division and President of the Campbell
Europe/America Division.

* Nominee for election at 2000 annual meeting

Committees of the PECO Energy Board of Directors

Audit Committee

The Audit Committee reviews auditing, accounting, financial reporting and
internal control functions. The committee also reviews officers' and directors'
expenses, corporate code of conduct, environmental and legal compliance matters
and Year 2000 issues. This committee recommends the independent auditors and
approves the scope of the annual audit by the independent auditors and internal
auditors. All members of this committee are non-employee directors. The
committee meets outside of the presence of management for portions of its
meetings with both the independent auditors and the internal auditors.

Compensation Committee

The Compensation Committee reviews the executives' compensation and
administers and oversees the employee benefit plans and programs. The committee
makes compensation decisions, which are approved by the full board, for the
positions of Chairman, Chief Executive Officer, President, Senior Vice
President, Vice President and Corporate Secretary. The committee uses the
services of an independent compensation consultant who reports directly to the
committee. All members are non-employee directors.

Corporate Governance Committee

The Corporate Governance Committee considers and recommends nominees for
election as directors. The committee reviews individual committee self-
assessments and makes recommendations on board and committee structure,
membership, functions, compensation and effectiveness. The committee oversees
management succession planning and development programs on behalf of the board.
The committee also establishes the job description and performance criteria of
the chief executive officer and initially evaluates the chief executive
officer's performance for the board. All members are non-employee directors.

Finance Committee

The Finance Committee reviews and makes recommendations to the board about
significant financial matters and business opportunities. The committee serves
as the fiduciary of PECO Energy's qualified pension and savings plans,
establishes the investment policy and reviews the transactions and performance
of the investment managers. All members are non-employee directors.

Nuclear Committee

The Nuclear Committee oversees nuclear operations of PECO Energy for
safety, reliability and quality and effectiveness of management and management
systems. The committee uses an independent consultant to assist it in
performing its functions.

Public Affairs Committee

The Public Affairs Committee advises management on matters of legislative,
regulatory and public policy.

Each director attended at least 92% of the meetings of the board and the
meetings of committees of which he or she was a member.

Committee Membership Roster

Corporate Public
Name Board Audit Compensation Governance Finance Nuclear Affairs
---- ----- ----- ------------ ---------- ------- ------- -------

C. A. McNeill, Jr. .............. X* X*
S. W. Catherwood ................ X X* X
D. L. Cooper .................... X X X X
M. W. D'Alessio ................. X X* X X
G. F. DiBona, Jr. ............... X X X
R. K. Elliott ................... X X X*
R. H. Glanton ................... X X X
R. B. Greco ..................... X X X X X
J. M. Palms ..................... X X X X*
J. F. Paquette, Jr. ............. X X X
R. Rubin ........................ X X X X
R. Subin ........................ X X* X
No. of Meetings in 1999 ......... 10 3 5 4 11 13 2

- ------------
* Chairperson

(b) Identification of Executive Officers.

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
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.

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.

Section 16(a) Beneficial Ownership Reporting Compliance

The federal securities laws require PECO Energy's directors and executive
officers to file with the Securities and Exchange Commission initial reports of
ownership and reports of changes in ownership of any securities of PECO Energy.

To PECO Energy's knowledge, based solely on a review of the copies of
these reports given to PECO Energy and written representations that no other
reports were required during 1999, all of PECO Energy's directors and executive
officers made the required filings except that Rosemarie Greco, a director of
PECO Energy, filed one late report of changes in beneficial ownership on Form 4
relating to a purchase of shares of PECO Energy common stock, and except that
Ian McLean, an officer of PECO Energy, filed an initial statement of beneficial
ownership late.

ITEM 11. EXECUTIVE COMPENSATION

Board Compensation

Employee directors receive no compensation, other than their normal
salary, for serving on the board or its committees.

PECO Energy's total compensation target for directors who are not officers
of PECO Energy is between the lowest 25th and the 50th percentile of the
general industry average. Directors are paid in cash and deferred stock units
as set forth below, and are reimbursed expenses, if any, for attending
meetings:

o $21,000 Annual board retainer,

o $1,000 Meeting fee,

o $2,000 Annual retainer for chairmanship of audit and nuclear committees,

o $1,000 Annual retainer for chairmanship of compensation, corporate
governance and finance committees, and

o 1,000 Deferred stock units.

Directors are required to own at least 3,000 shares of PECO Energy common
stock or stock units within three years after their election to the board.

Effective January 1997, PECO Energy terminated all future retirement
benefit accruals and stock option grants for non-employee directors. Accrued
benefits under the previous retirement plan have been replaced with a one-time
grant of deferred stock units equal to the January 1997 value of all accrued
benefits. The expected values of the future benefits under the previous
retirement plan have been replaced with annual grants of deferred stock units.
Each deferred stock unit is the right to receive one share of PECO Energy
common stock at retirement. Before retirement, deferred stock units accrue
dividend equivalents for each year the director serves on the board. Upon
retirement, the director can receive the accumulated shares in a lump sum or
spread the distribution over a period of up to ten years.

Directors can elect to receive all or a portion of their compensation in
stock or to defer receiving it until retirement, death or until they no longer
serve as director. Deferred compensation is put in an unfunded account and
credited with interest, equal to the amount that would have been earned had the
compensation been invested in one or more of eight designated mutual funds. The
deferred amounts and accrued interest are unfunded obligations of PECO Energy
and cannot be distributed to the director until he or she reaches 65, retires
or is no longer a director. There are exceptions to this rule for financial
hardship.

In 1999, non-employee directors received $520,000 as a group. At its April
27, 1999 meeting, the corporate governance committee reviewed the overall level
of director compensation and increased the annual allocation of deferred stock
units from 715 to 1,000.

Summary Compensation Table

Compensation of Executive Officers

The amounts listed under "All Other Compensation" are matching
contributions made by PECO Energy under the PECO Energy Employee Savings Plan.

Annual Compensation
----------------------------------------------

Name and Principal Position Year Salary ($) Bonus ($) Other ($)
- -------------------------------- ------ ------------ ----------- -----------

Corbin A. McNeill, Jr. ......... 1999 659,857 1,000,000 0
Chairman of the Board, 1998 585,476 708,100 0
President and Chief 1997 551,112 330,200 0
Executive Officer
Michael J. Egan ................ 1999 326,312 311,400 0
Senior Vice President, 1998 317,439 235,700 0
Finance and Chief 1997 63,003 229,148 0
Financial Officer
Gerald R. Rainey ............... 1999 310,386 289,000 0
President and Chief 1998 269,308 193,700 0
Nuclear Officer, 1997 215,260 99,783 0
PECO Energy Nuclear
James W. Durham ................ 1999 298,831 274,500 0
Senior Vice President, 1998 298,952 225,300 0
and General Counsel 1997 294,639 111,733 0
Kenneth G. Lawrence ............ 1999 291,847 241,200 0
Senior Vice President, 1998 282,164 200,700 0
Corporate and President, 1997 255,126 107,142 0
PECO Energy Distribution

(RESTUBBED TABLE)

Long-Term Compensation
--------------------------------------------------------------
Awards Payouts
-------------------------- ----------------------------------
Restricted
Stock Long-Term All Other
Award(s) Options Incentive Plan Compensation
Name and Principal Position ($) (#)(A) Payouts ($) ($)
- -------------------------------- --------------- --------- ---------------- ----------------

Corbin A. McNeill, Jr. ......... 942,188 0 0 3,200
Chairman of the Board, 0 500,000 0 3,200
President and Chief 0 50,000 0 3,200
Executive Officer
Michael J. Egan ................ 150,750 0 0 0
Senior Vice President, 0 125,000 0 0
Finance and Chief 99,851(B) 298,000 0 200,000(C)
Financial Officer
Gerald R. Rainey ............... 150,750 0 0 2,076
President and Chief 0 90,000 0 2,040
Nuclear Officer, 0 10,000 0 3,200
PECO Energy Nuclear
James W. Durham ................ 120,600 30,000 0 3,200
Senior Vice President, 0 34,000 0 3,200
and General Counsel 0 20,000 0 3,200
Kenneth G. Lawrence ............ 94,219 0 0 3,200
Senior Vice President, 0 115,000 0 3,107
Corporate and President, 0 20,000 0 3,200
PECO Energy Distribution

- ------------
(A) In 1998, Messrs. McNeill, Egan, Rainey and Lawrence received a multi- year
grant of stock options. Therefore, they did not receive any stock options
in 1999.

(B) At December 31, 1999, Mr. Egan held 4,475 shares of restricted stock with
an aggregate value of $155,506. These shares vest on October 13, 2000 and
Mr. Egan will receive dividends on these shares during the vesting period.

Option Grants in 1999

The options listed below become exercisable in full based on a combination of
PECO Energy stock price performance and time. Once the stock has closed at a
price of $41.00, one third of the options will vest 12 months from the date of
grant, one-third will vest 24 months from the date of grant and one-third will
vest 36 months from the date of grant.

Values indicated are an estimate based on the Black-Scholes option pricing
model. Although executives risk forfeiting these options in some circumstances,
these risks are not factored into the calculated values. The actual value of
these options will be determined by the excess of the stock price over the
exercise price on the date the option is exercised. There is no certainty that
the actual value realized will be at or near the value estimated by the
Black-Scholes option pricing model.

Assumptions used for the Black-Scholes model are as of December 31, 1999
and are as follows:

Risk-free interest rate ..................................... 5.41%
Volatility .................................................. .2836
Dividend yield .............................................. 6.26%
Time of exercise ............................................ 9.5 years

Grant Date
Individual Grants Value
---------------------------------- -----------------
% of Total
Number of Options
Securities Granted
Underlying Options to Employees Exercise or Base Grant Date
Name Granted(#) in 1999 Price($/SH) Expiration Date Present Value($)
- -------------------------------- -------------------- -------------- ------------------ ----------------- -----------------

Corbin A. McNeill, Jr. ......... 0 0 N/A N/A 0
Chairman of the Board,
President and Chief
Executive Officer
Michael J. Egan ................ 0 0 N/A N/A 0
Senior Vice President,
Finance and Chief
Financial Officer
Gerald R. Rainey ............... 0 0 N/A N/A 0
President and Chief
Nuclear Officer,
PECO Energy Nuclear
James W. Durham ................ 30,000 .16 37.6875 02/23/09 241,800
Senior Vice President
and General Counsel
Kenneth G. Lawrence ............ 0 0 N/A N/A 0
Senior Vice President,
Corporate and President,
PECO Energy Distribution

Option Exercises and Year-End Value

This table shows the number and value of exercised and unexercised stock
options for the named executive officers during 1999. Value is determined using
the market value of PECO Energy common stock at the year-end price of $34.75
per share, minus the value of PECO Energy common stock at the exercise price.
All options whose exercise price exceeds the market value are valued at zero.

Number of
Securities Value of
Underlying Unexercised
Unexercised in-the-Money
Options at Options at
12/31/98 12/31/98
Shares ---------------- ---------------
Acquired Value (#)Exercisable ($)Exercisable
Name on Exercise(#) Realized($) Unexercisable Unexercisable
- ------------------------------------------ ---------------- ------------- ---------------- ---------------

Corbin A. McNeill, Jr. ................... 25,000 596,875 E 823,500 E 10,725,375
Chairman of the Board, U 0 U 0
President and Chief Executive Officer
Michael J. Egan .......................... 0 0 E 423,000 E 5,379,039
Senior Vice President, U 0 U 0
Finance and Chief Financial Officer
Gerald R. Rainey ......................... 0 0 E 0 E 0
President and Chief Nuclear Officer, U 0 U 0
PECO Energy Nuclear
James W. Durham .......................... 0 0 E 174,000 E 1,580,250
Senior Vice President and General Counsel U 20,000 U 0
Kenneth G. Lawrence ...................... 20,000 497,760 E 108,000 E 1,108,500
Senior Vice President, Corporate and U 0 U 0
President, PECO Energy Distribution

Pension Plan Table

Average Annual
Compensation for
Highest Consecutive Years of Service
Five Years 10 years 15 years 20 Years 25 Years 30 Years 35 Years 40 Years
- --------------------- ---------- ---------- ---------- ----------------- ---------- ---------- ----------

$ 100,000.00 $ 19,343 $ 26,514 $ 33,686 $ 40,857 $ 48,029 $ 55,200 $ 62,372
200,000.00 39,843 54,764 69,686 84,607 99,529 114,450 129,372
300,000.00 60,343 83,014 105,686 128,357 151,029 173,700 196,372
400,000.00 80,843 111,264 141,686 172,107 202,529 232,950 263,372
500,000.00 101,343 139,514 177,686 215,857 254,029 292,200 330,372
600,000.00 121,843 167,764 213,686 259,607 305,529 351,450 397,372
700,000.00 142,343 196,014 249,686 303,357 357,029 410,700 464,372
800,000.00 162,843 224,264 285,686 347,107 408,529 469,950 531,372
900,000.00 183,343 252,514 321,686 390,857 460,029 529,200 598,372
1,000,000.00 203,843 280,764 357,686 434,607 511,529 588,450 665,372

Retirement Plans

The above table shows the estimated annual retirement benefits payable on
a straight-life annuity basis to participating employees, including officers,
in the earnings and year of service classes indicated, under PECO Energy's
non-contributory retirement plans. The amounts shown in the table are not
subject to any deduction for Social Security or other offset amounts. Covered
compensation includes salary and bonus which is disclosed in the Summary
Compensation Table on page 87 for the named executive officers. The calculation
of retirement benefits under the plans is based upon average earnings for the
highest consecutive five-year period. The Internal Revenue Code limits the
annual benefits that can be paid from a tax-qualified retirement plan. As
permitted by the Employee Retirement Income Security Act of 1974, PECO Energy
has supplemental plans which allow the payment out of general funds of PECO
Energy of any benefits calculated under provisions of the applicable retirement
plan which may be above these limits.

Messrs. McNeill, Egan, Rainey, Durham and Lawrence have 32, 2, 30, 21 and
30 credited years of service, respectively, under PECO Energy's pension
program. Mr. Durham has been granted one year of additional service, for
purposes of calculating his benefits under PECO Energy's pension program, for
each year of service up to a maximum of 10 additional years.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Beneficial Ownership

The following table indicates how much PECO Energy common stock was owned
by the directors, named executive officers and beneficial owners of more than
5% owned as of December 31, 1999. In reviewing this table, please note the
following:

o the shares listed as "Beneficially Owned" include shares in the Employee
Savings Plan, the Officers and Directors Deferred Compensation Plan and
the Directors Deferred Stock Unit Plan,

o the shares listed as "May Be Acquired" include shares of PECO Energy
common stock which can be acquired upon the exercise of stock options
granted under the PECO Energy Long-Term Incentive Plan, and

o beneficial ownership of directors and officers as a group represents less
than 1% of the outstanding shares of PECO Energy common stock.

Number of Common Shares
--------------------------------------------
Beneficially May Be
Name Owned Acquired Total
- ------------------------------------------------------ -------------- ------------ ------------

Susan W. Catherwood, Director ........................ 9,165 6,000 15,165
Daniel L. Cooper, Director ........................... 2,992 0 2,992
M. Walter D'Alessio, Director ........................ 9,798 6,000 15,798
G. Fred DiBona, Jr., Director ........................ 2,958 0 2,958
James W. Durham, Officer ............................. 17,095 194,000 211,095
Michael J. Egan, Officer ............................. 20,134 423,000 443,134
R. Keith Elliott, Director ........................... 3,958 0 3,958
Richard H. Glanton, Director ......................... 5,723 0 5,723
Rosemarie B. Greco, Director ......................... 4,523 0 4,523
Kenneth G. Lawrence, Officer ......................... 11,828 108,000 119,828
Corbin A. McNeill, Jr., Director and Officer ......... 90,391 848,500 938,891
John M. Palms, Ph.D., Director ....................... 9,577 6,000 15,577
Joseph F. Paquette, Jr., Director .................... 42,034 90,000 132,034
Gerald R. Rainey, Officer ............................ 25,970 0 25,970
Ronald Rubin, Director ............................... 10,266 6,000 16,266
Robert Subin, Director ............................... 5,439 5,000 10,439
Directors and Officers as a group (42) ............... 411,557 2,679,100 3,090,657

This table does not include 533,293 shares of common stock held under PECO
Energy's Service Annuity Plan. Messrs. Cooper, D'Alessio, Elliott, Paquette and
Rubin are members of the finance committee which monitors the investment policy
and performance of the investments under that plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Change-of-Control Agreements

PECO Energy has entered into change-of-control agreements with most of its
executive officers, including the individuals named in the Summary Compensation
Table. The purpose of the agreements is to assure the objective judgment, and
to keep the loyalties, of key executives when PECO Energy is faced with a
potential change of control by providing for a continuation of salary, bonus,
health and other benefits for a maximum period of three years.

In addition, PECO Energy's long-term incentive plan allows the committee
administering this plan to terminate the restrictions on stock options and
restricted stock grants at any time. PECO Energy has also entered into two
trust agreements to provide for the payment of retirement benefits and deferred
compensation benefits of directors and officers that include provisions
requiring full funding in the event of a change of control.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

Index Reference (Page)
- ----- ----------------

(a) 1. Financial Statements
Report of Independent Accountants ................................... 47
Consolidated Statements of Income for the years ended
December 31, 1999, 1998 and 1997 .................................. 48
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997 .................................. 49
Consolidated Balance Sheets as of December 31, 1999 and
1998 .............................................................. 50
Consolidated Statements of Changes in Common Shareholders'
Equity and Preferred Stock for the years ended December 31,
1999, 1998 and 1997 ............................................... 51
Notes to Consolidated Financial Statements .......................... 52
2. Financial Statement Schedules
Schedule II--Valuation and Qualifying Accounts for the years
ended December 31, 1999, 1998 and 1997 ............................ 93
3. Exhibits ............................................................ 94

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 Column D Column E
-------- -------- -------- -------- --------
Additions
-----------------------
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
======== ======= === ======= ========

FOR THE YEAR ENDED DECEMBER 31, 1998

ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS ......... $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
======== ======= ==== ======= ========

- ------------
(1) Write-off of individual accounts receivable.
(2) Restated to reflect valuation allowance activity for Customer Assistance

Exhibits

Certain of the following exhibits have been filed with the SEC 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
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

Dated as of File Reference Exhibit No.
------------------------------------------------------------------------------

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)

4-8 Revolving Credit Agreement, dated as of September 15, 1999, among the Company, as bor-
rower, 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 Janu-
ary 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); supplemen-
tal 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).

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 Decem-
ber 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 Feb-
ruary 19, 1999 among George Shicora and Diana Moy Kelly, as Beneficiary Trustees, First
Union Trust Company, National Association, as Issuer Trustee, Delaware Trustee and Indepen-
dent 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 Com-
pany (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 Genera-
tion Assets dated April 29, 1998. (Registration Statement No. 333-31646, Exhibit 10.3)

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.

Reports on Form 8-K

During the quarter ended December 31, 1999, the Company filed the following
Current Reports on Form 8-K: