COMMONWEALTH EDISON CO - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-------------------

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Commission File Name of Registrant; State of Incorporation; Address of IRS Employer
Number Principal Executive Offices; and Telephone Number Identification Number
- ---------------- --------------------------------------------------------- -------------------------

1-16169 EXELON CORPORATION 23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-4321

1-1839 COMMONWEALTH EDISON COMPANY 36-0938600
(an Illinois corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-4321

1-1401 PECO ENERGY COMPANY 23-0970240
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

Name of Each Exchange on
Title of Each Class Which Registered
- ------------------------------------------------------------------------------ -----------------------------

EXELON CORPORATION:
Common Stock, without par value New York, Chicago and
Philadelphia
COMMONWEALTH EDISON COMPANY:
Company-Obligated Mandatorily Redeemable Preferred Securities of New York
Subsidiary Trust Holding Solely Commonwealth Edison Company's
8.48% Subordinated Debt Securities and unconditionally guaranteed by
Commonwealth Edison Company

PECO ENERGY COMPANY:
First and Refunding Mortgage Bonds: 6-3/8% Series due 2005, and 6-1/2% New York
Series due 2003

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SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants
PECO ENERGY COMPANY:

Cumulative Preferred Stock, without par value: $7.48 Series and $6.12 Series

Indicate by check mark whether the registrants (1) have 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 (or for such shorter period that the
registrant was required to file such reports), and (2) have 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 registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

The estimated aggregate market value of the voting and non-voting common
equity held by nonaffiliates of each registrant as of March 1, 2002, was as
follows:

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DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Exelon Corporation's Current Report on Form 8-K dated
February 28, 2002 containing consolidated financial statements and related
information for the year ended December 31, 2001, are incorporated by reference
into Parts I, II and IV of this Annual Report on Form 10-K. Portions of Exelon
Corporation's definitive Proxy Statement filed on March 13, 2002 relating to its
annual meeting of shareholders, are incorporated by reference into Part III of
this Annual Report on Form 10-K.

Portions of Commonwealth Edison Company's definitive Information
Statement to be filed prior to April 30, 2002, relating to its annual meeting of
shareholders, are incorporated by reference into Part III of this Annual Report
on Form 10-K.

Portions of PECO Energy Company's definitive Information Statement to
be filed prior to April 30, 2002, relating to its annual meeting of
shareholders, are incorporated by reference into Part III of this Annual Report
on Form 10-K.

This combined Form 10-K is separately filed by Exelon Corporation,
Commonwealth Edison Company and PECO Energy Company. Information contained
herein relating to any individual registrant is filed by such registrant in its
own behalf. Each registrant makes no representation as to information relating
to the other registrants.

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TABLE OF CONTENTS

PAGE NO.
--------

FORWARD LOOKING STATEMENTS 1

PART I

ITEM 1. BUSINESS 2
General 2
Energy Delivery 3
Generation 11
Enterprises 26
Employees 27
Environmental Regulation 28
Other Subsidiaries of ComEd and PECO with Publicly
Held Securities 32
Executive Officers of the Registrants 34
ITEM 2. PROPERTIES 36
ITEM 3. LEGAL PROCEEDINGS 39
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS 42

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS 43
ITEM 6. SELECTED FINANCIAL DATA 44
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS 47
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK 81
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 84
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE 145

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT 146
ITEM 11. EXECUTIVE COMPENSATION 146
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT 147
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 148

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K 149

SIGNATURES 166

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FORWARD-LOOKING STATEMENTS

Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements that 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 ITEM
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - Outlook and in ITEM 8. Financial Statements and Supplementary Data,
Notes to Consolidated Financial Statements; Exelon - Note 20; ComEd - Note 16;
and PECO Note 18 and other factors discussed in Exelon Corporation (Exelon),
Commonwealth Edison Company (ComEd) and PECO Energy Company's (PECO) 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.
Exelon, ComEd and PECO undertake no obligation to publicly release any revision
to these forward-looking statements to reflect events or circumstances after the
date of this Report.

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PART I

ITEM 1. BUSINESS.

GENERAL

Exelon Corporation (Exelon) was incorporated in Pennsylvania in
February 1999. On October 20, 2000, Exelon became the parent corporation for
each of Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) as a
result of the completion of the transactions contemplated by an Agreement and
Plan of Exchange and Merger, as amended, among PECO, Unicom Corporation (Unicom)
and Exelon (Merger). The Merger was accounted for using the purchase method of
accounting.

During January 2001, Exelon undertook a restructuring to separate its
generation and other competitive businesses from its regulated energy delivery
business at ComEd and PECO. As part of the restructuring, the generation-related
operations and assets and liabilities of ComEd were transferred to Exelon
Generation Company, LLC (Generation). Also, as part of the restructuring, the
non-regulated operations and related assets and liabilities of PECO,
representing PECO's generation and enterprises business segments, were
transferred to Generation and Exelon Enterprises Company, LLC (Enterprises),
respectively. Additionally, certain operations and assets and liabilities of
ComEd and PECO were transferred to Exelon Business Services Company (BSC).

Exelon, through its subsidiaries, operates in three business segments:

o Energy Delivery, consisting of the retail electricity distribution and
transmission businesses of ComEd in northern Illinois and PECO in
southeastern Pennsylvania and the natural gas distribution business of PECO
in the Pennsylvania counties surrounding the City of Philadelphia.

o Generation, consisting of electric generating facilities, energy marketing
operations and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen
Energy Company, LLC (AmerGen).

o Enterprises, consisting of competitive retail energy sales, energy and
infrastructure services, communications and other investments weighted
towards the communications, energy services and retail services industries.

Exelon's principal executive offices are located at 10 South Dearborn
Street, Chicago, Illinois 60603, and its telephone number is 312-394-4321. ComEd
was organized in the State of Illinois in 1913 as a result of the merger of
Cosmopolitan Electric Company into the original corporation named Commonwealth
Edison Company, which was incorporated in 1907. ComEd's principal executive
offices are located at 10 South Dearborn Street, Chicago, Illinois 60603 and its
telephone number is 312-394-4321. PECO was incorporated in Pennsylvania in 1929.
PECO's principal executive offices are located at 2301 Market Street,
Philadelphia, Pennsylvania 19101-8699 and its telephone number is 215-841-4000.

Exelon and various of its subsidiaries are subject to Federal and state
regulation. Exelon is a registered holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). ComEd is a public utility under the
Illinois Public Utilities Act subject to regulation by the Illinois Commerce
Commission (ICC). PECO is a public utility under the Pennsylvania Public Utility
Code subject to regulation by the Pennsylvania

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Public Utility Commission (PUC). PECO, ComEd and Generation are electric
utilities under the Federal Power Act subject to regulation by the Federal
Energy Regulatory Commission (FERC). Specific operations of Exelon are also
subject to the jurisdiction of various other Federal, state, regional and local
agencies, including the United States Nuclear Regulatory Commission (NRC).

As a registered holding company, Exelon and its subsidiaries are
subject to a number of restrictions under PUHCA. These restrictions generally
involve financing, investments and affiliate transactions. Under PUHCA, Exelon
and its subsidiaries cannot issue debt or equity securities or guaranties
without approval of the Securities and Exchange Commission (SEC) or in some
circumstances in the case of ComEd and PECO, the ICC or the PUC, respectively.
Exelon currently has SEC approval to issue up to an aggregate of $4 billion in
common stock, preferred securities, long-term debt and short-term debt, and to
issue up to $4.5 billion in guaranties. PUHCA also limits the businesses in
which Exelon may engage and the investments that Exelon may make. With limited
exceptions, Exelon may only engage in traditional electric and gas utility
businesses and other businesses that are reasonably incidental or economically
necessary or appropriate to the operations of the utility business. The
exceptions include Exelon's ability to invest in exempt telecommunications
companies, in exempt wholesale generating businesses and foreign utility
companies (these investments are capped at $4 billion in the aggregate), in
energy-related companies (as defined in SEC rules, and subject to a cap on these
investments of 15% of Exelon's consolidated capitalization), and in other
businesses, subject to SEC approval. In addition, PUHCA requires that all of a
registered holding company's utility subsidiaries constitute a single system
that can be operated in an efficient, coordinated manner. For additional
information about restrictions on the payment of dividends and other effects of
PUHCA on Exelon and its subsidiaries, see ITEM 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Exelon.

ENERGY DELIVERY

Energy Delivery consists of Exelon's regulated energy delivery
operations conducted by ComEd and PECO.

ComEd is engaged principally in the purchase, transmission,
distribution and sale of electricity to a diverse base of residential,
commercial, industrial and wholesale customers in northern Illinois. ComEd is a
public utility under the Illinois Public Utilities Act. Consequently, ComEd is
subject to regulation by the ICC as to rates and charges, issuance of most of
its securities, service and facilities, classification of accounts, transactions
with affiliated interests, as defined in the Illinois Public Utilities Act, and
other matters. ComEd is also subject to regulation by FERC as to transmission
rates and certain other aspects of its business, including interconnections and
sales of transmission related assets.

ComEd's retail service territory has an area of approximately 11,300
square miles and an estimated population of approximately 8 million as of
December 31, 2001. The service territory includes the City of Chicago, an area
of about 225 square miles with an estimated population of approximately 3
million. ComEd had approximately 3.6 million customers at December 31, 2001.

ComEd's franchises are sufficient to permit it to engage in the
business it now conducts. ComEd's franchise rights are generally nonexclusive
rights documented in agreements and, in some cases, certificates of public
convenience issued by the ICC. With few exceptions, the franchise rights have
stated expiration dates ranging from 2002 to 2050 and subsequent years.

3

PECO is engaged principally in the purchase, transmission, distribution
and sale of electricity to residential, commercial, industrial and wholesale
customers and in the purchase, distribution and sale of natural gas to
residential, commercial and industrial customers. PECO is a public utility under
the Pennsylvania Public Utility Code. As a result, PECO is subject to regulation
by the PUC as to electric distribution rates, retail gas rates, issuances of
securities and certain other aspects of PECO's operations. PECO is also subject
to regulation by FERC as to transmission rates and certain other aspects of its
business, including interconnections and sales of transmission related assets.

PECO's traditional retail service territory covers 2,107 square miles
in southeastern Pennsylvania. PECO provides electric delivery service in an area
of 1,972 square miles, with a population of approximately 3.8 million, including
1.5 million in the City of Philadelphia. Natural gas service is supplied in a
1,625 square mile area in southeastern Pennsylvania adjacent to Philadelphia,
with a population of 2.3 million. PECO delivers electricity to approximately 1.5
million customers and natural gas to approximately 440,000 customers.

PECO has the necessary franchise rights to furnish electric and gas
service in the various municipalities or territories in which it now supplies
such services. PECO's franchise rights, which are generally nonexclusive rights,
consist of charter rights and certificates of public convenience issued by the
PUC and/or "grandfather rights". Such franchise rights are generally unlimited
as to time.

As a result of Exelon's restructuring to separate its regulated and
competitive businesses, effective January 1, 2001, both ComEd and PECO
transferred their assets and liabilities unrelated to energy delivery to other
subsidiaries of Exelon. In the case of ComEd, the assets and liabilities
transferred included nuclear generation and wholesale power marketing operations
and some administrative functions. In the case of PECO, the assets and
liabilities transferred related to nuclear, fossil and hydroelectric generation
and wholesale power marketing; unregulated ventures and activities, including
communications, infrastructure services and unregulated gas and electric sales
activities; and administrative, information technology and other support for
other business activities of Exelon and its subsidiaries.

Energy Delivery's kilowatthour (kWh) sales and load are generally
higher, primarily during the summer periods but also during the winter periods,
when temperature extremes create demand for either summer cooling or winter
heating. ComEd's highest peak load experienced to date occurred on August 9,
2001 and was 21,574 megawatts (MWs), and the highest peak load experienced to
date during a winter season occurred on December 20, 1999 and was 14,484 MWs.
PECO's highest peak load experienced to date occurred on July 6, 1999 and was
7,959 MWs; and the highest peak load experienced to date during a winter season
occurred on January 17, 2000 and was 6,135 MWs.

RETAIL ELECTRIC SERVICES

Electric utility restructuring legislation was adopted in Pennsylvania
in December 1996 and in Illinois in December 1997. Both states, through their
regulatory agencies, established a phased approach to competition, allowing
customers to choose an alternative electric generation supplier; required rate
reductions and imposed caps on rates during a transition period; and allowed the
collection of competitive transition charges (CTCs) from customers to recover
costs that might not otherwise be recovered in a competitive market (stranded
costs). Under the restructuring initiatives adopted at the Federal and state
levels, the role of electric utilities in the supply and delivery of energy is
changing.

4

Provider of last resort (POLR) obligations refer to the obligation of a
utility to provide generation services (i.e., power and energy) to those
customers who do not take service from an alternative generation supplier or who
choose to come back to the utility after taking service from an alternative
supplier. Because the choice lies with the customer, these obligations make it
difficult for the utility to predict and plan for the level of customers and
associated energy demand. If these obligations remain unchanged, the utility
could be required to maintain reserves sufficient to serve 100% of the service
territory load at a tariffed rate on the chance that customers who switched to
new suppliers decide to come back to the utility as a "last resort" option. A
significant over or under estimation of such reserves may cause commodity price
risks for suppliers. ComEd and PECO continue to be obligated to provide a
reliable delivery system under cost-based rates.

The rates for the generation service provided by ComEd and PECO are
subject to rate caps or freezes during all or a portion of the transition
periods. ComEd has entered into a long-term power purchase agreement (PPA) with
Generation to obtain sufficient power at fixed rates. PECO has entered into a
long-term PPA with Generation to obtain sufficient power at the rates PECO is
allowed to charge to serve customers who do not choose an alternate generation
supplier.

ComEd. Under the Illinois legislation, as of December 31, 2000, all
non-residential customers were eligible to choose a new electric supplier or
elect the power purchase option (PPO), which allows the purchase of electric
energy from ComEd at market-based prices. As of December 31, 2001, approximately
18,700 non-residential customers, representing approximately 22% of ComEd's
annual retail kWh sales, had elected to receive their electric energy from an
alternative retail electric supplier (ARES) or had chosen the PPO. Customers who
receive energy from an ARES continue to pay a delivery charge. ComEd's
residential customers become eligible to choose a new electric supplier in May
2002.

In addition to retail competition for generation services, the Illinois
legislation provided for residential base rate reductions, a sharing with
customers of any earnings over a defined threshold and a base rate freeze,
reflecting the residential base rate reductions, through January 1, 2005. A 15%
residential base rate reduction became effective on August 1, 1998 and a further
5% residential base rate reduction became effective in October 2001. A utility
may request a rate increase during the rate freeze period only when necessary to
ensure the utility's financial viability. Under the Illinois legislation, if the
earned return on common equity of a utility during this period exceeds an
established threshold, one-half of the excess earnings must be refunded to
customers. The threshold rate of return on common equity is based on the 30-Year
Treasury Bond rate plus 8.5% in the years 2000 through 2004. Earnings for
purposes of ComEd's threshold include ComEd's net income calculated in
accordance with generally accepted accounting principles and reflect the
amortization of regulatory assets and goodwill. As a result of the Illinois
legislation, at December 31, 2001, ComEd had a regulatory asset with an
unamortized balance of $277 million that it expects to fully recover and
amortize by the end of 2004. Consistent with the provisions of the Illinois
legislation, regulatory assets may be recovered at amounts that provide ComEd an
earned return on common equity within the Illinois legislation earnings
threshold. The earned return on common equity and the threshold return on common
equity for ComEd are each calculated on a two-year average basis. ComEd did not
trigger the earnings sharing provision in 2000 or 2001 and does not currently
expect to trigger the earnings sharing provisions in the years 2002 through
2004.

The Illinois legislation also provided for the collection of a CTC from
customers who choose to purchase electric energy from an ARES or elect the PPO
during a transition period that

5

extends through 2006. The CTC, which was established as of October 1, 1999 and
is applied on a cents per kWh basis, considers the revenue that would have been
collected from a customer under tariffed rates, reduced by the revenue the
utility will receive for providing delivery services to the customer, the market
price for electricity and a defined mitigation factor, which represents the
utility's opportunity to develop new revenue sources and achieve cost savings.
The CTC allows ComEd to recover some of its costs that might otherwise be
unrecoverable under market-based rates.

As part of a settlement agreement between ComEd and the City of Chicago
relating to ComEd's Chicago franchise agreement, ComEd and Chicago agreed to a
revised combination of ongoing work under the franchise agreement and new
initiatives that total approximately $1 billion in defined transmission and
distribution expenditures by ComEd to improve electric service in Chicago, of
which approximately $940 million has been expended through December 31, 2001.
The Illinois legislation also committed ComEd to spend at least $2 billion
during the period 1999 through 2004 on transmission and distribution facilities
outside of Chicago, which has been expended as of December 31, 2001. In
addition, ComEd conducted an extensive evaluation of the reliability of its
transmission and distribution systems in response to several outages in the
summer of 1999. As a result of the evaluation, ComEd has increased its capital
and operating and maintenance expenditures on its transmission and distribution
facilities in order to improve their reliability.

As a result of ComEd's commitments to improve the reliability of its
transmission and distribution system, ComEd expects its capital expenditures
will exceed depreciation on its rate base assets through at least 2002. The base
rate freeze will generally preclude rate recovery of and on such investments
prior to January 1, 2005. Unless ComEd can offset the additional carrying costs
against cost savings, its return on investment will be reduced during the period
of the rate freeze and until rate increases are approved authorizing a return of
and on this new investment.

In addition, the Illinois legislation provides that an electric
utility, such as ComEd, will be liable for actual damages suffered by customers
in the event of a continuous power outage of four hours or more affecting 30,000
or more customers and provides for reimbursement of governmental emergency and
contingency expenses incurred in connection with any such outage. The
legislation bars recovery of consequential damages. The legislation also allows
an affected utility to seek relief from these provisions from the ICC where the
utility can show that the cause of the outage was unpreventable damage due to
weather events or conditions, customer tampering or third party causes.

The Illinois legislation also allows a portion of ComEd's future
revenues to be segregated and used to support the issuance of securities by
ComEd or a special purpose financing subsidiary. The proceeds, net of
transaction costs, from such securities issuances must be used to refinance
outstanding debt or equity or for certain other limited purposes. The total
amount of such securities that may be issued is approximately $6.8 billion. In
December 1998, special purpose financing subsidiaries of ComEd issued $3.4
billion of notes. For additional information, see Other Subsidiaries of ComEd
and PECO with Publicly Held Securities below and ITEM 8. Financial Statements
and Supplementary Data - ComEd, Note 10 of Notes to Consolidated Financial
Statements.

PECO. Under the Pennsylvania Electricity Generation Customer Choice and
Competition Act (Competition Act), all of PECO's retail electric customers have
the right to choose their generation suppliers. At December 31, 2001,
approximately 28% of PECO's residential load, 6% of its small commercial and
industrial load and 5% of its large commercial and industrial load were
purchasing generation service from alternative suppliers.

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In addition to retail competition for generation services, PECO's
settlement of its restructuring case mandated by the Competition Act required
PECO to provide generation services to customers who do not or cannot choose an
alternate supplier through December 31, 2010 and established caps on generation
and distribution rates. The 1998 settlement also authorized PECO to recover $5.3
billion of stranded costs and to securitize up to $4.0 billion of its stranded
cost recovery.

Under the 1998 settlement, PECO's distribution rates were capped
through June 30, 2005 at the level in effect on December 31, 1996. Generation
rates, consisting of the charge for stranded cost recovery and a shopping credit
or capacity and energy charge, were capped through December 31, 2010. For 2002,
the generation rate cap is $0.0698 per kWh, increasing to $0.0751 per kWh in
2006 and $0.0801 per kWh in 2007. The rate caps are subject to limited
exceptions, including significant increases in Federal or state taxes or other
significant changes in law or regulations that would not allow PECO to earn a
fair rate of return.

Pursuant to a settlement related to PECO's request for authorization to
securitize an additional $1 billion of its stranded cost recovery, PECO provided
its customers with additional rate reductions of $60 million in 2001. Under the
settlement agreement entered into by PECO in 2000 relating to the PUC's approval
of the Merger, PECO agreed to $200 million in aggregate rate reductions for all
customers over the period January 1, 2002 through 2005 and extended the rate cap
on distribution rates through December 31, 2006.

PECO has been authorized to recover stranded costs of $5.3 billion over
a twelve-year period ending December 31, 2010 with a return on the unamortized
balance of 10.75%. PECO's recovery of stranded costs is based on the level of
transition charges established in the settlement of PECO's restructuring case
and the projected annual retail sales in PECO's service territory. Recovery of
transition charges for stranded costs and PECO's allowed return on its recovery
of stranded costs are included in operating revenue.

As a mechanism for utilities to recover their allowed stranded costs,
the Competition Act provides for the imposition and collection of non-bypassable
CTCs on customers' bills. 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 electric generation supplier. 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.

In consideration with the settlement agreement, entered into by PECO
with the PUC, PECO developed certain forward-looking financial information
during 1998, which was part of this settlement agreement with the PUC. The
following table shows the estimated average levels of stranded cost recovery and
the amortization of the remaining portion of PECO's authorized stranded cost
recovery ($4.9 billion at December 31, 2001) for the years 2002 through 2010,
based on estimated 0.8% annual sales growth assumed in the 1998 settlement of
PECO's restructuring case.

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PECO Annual Stranded Cost
Amortization And Return

Stranded Cost Revenue Excluding
Recovery Gross Receipts Tax
Year Annual Sales (1) Charge (2)
----------------------------------------------------
Total Return @ 10.75% Amortization
- ----- ----------------- --------------- ---------- ----------------- ---------------
MWh $/kWh ($000) ($000) ($000)

2002 34,381,485 0.0251 825,004 516,869 308,135
2003 34,656,537 0.0247 818,352 482,401 335,951
2004 34,933,789 0.0243 811,540 444,798 366,742
2005 35,213,260 0.0240 807,933 403,555 404,378
2006 35,494,966 0.0266 902,623 353,070 549,553
2007 35,778,925 0.0266 909,844 290,627 619,217
2008 36,065,157 0.0266 917,123 220,312 696,811
2009 36,353,678 0.0266 924,459 141,229 783,231
2010 36,644,507 0.0266 931,855 52,381 879,474
- ----- ----------------- --------------- ---------- ----------------- ---------------

(1) Subject to reconciliation of actual sales and collections.
(2) Subject to periodic adjustments for over- or under- recovery.

Under the Competition Act, licensed entities, including alternate
electric generation suppliers, may act as agents to provide a single bill and
provide associated billing and collection services to retail customers located
in PECO's retail electric service territory. In that event, the alternative
supplier or other third party replaces the customer as the obligor with respect
to the customer's bill and PECO generally has no right to collect such
receivable from the customer. Third-party billing would change PECO's customer
profile (and risk of non-payment by customers) by replacing multiple customers
with the entity providing third-party billing for those customers. PUC-licensed
entities may also finance, install, own, maintain, calibrate and remotely read
advanced meters for service to retail customers in PECO's retail electric
service territory. To date, no third parties are providing billing of PECO's
charges to customers or advanced metering. Only PECO can physically disconnect
or reconnect a customer's distribution service.

As permitted by the Competition Act and the 1998 settlement of its
restructuring case, PECO securitized $1 billion and $4 billion of its stranded
cost recovery in 2000 and 1999, respectively, by the issuance of transition
bonds (Transition Bonds) through a special purpose financing entity. As required
by the Competition Act, the proceeds from the securitizations were applied to
reduce stranded costs, including related capitalization of PECO. In March 2001,
approximately $805 million of the first series of Transition Bonds were
refinanced. For additional information, see Other Subsidiaries of ComEd and PECO
with Publicly Held Securities below and ITEM 8. Financial Statements and
Supplementary Data - PECO, Note 11 of Notes to Consolidated Financial
Statements.

PECO's settlement of its restructuring case included a number of
provisions designed to encourage competition for generation services. Shopping
credits for generation service may provide an economic incentive for customers
to choose an alternate supplier. Effective January 1, 2001, PECO agreed to
assign 20% of its non-shopping residential customers to competitive default
service provided by one or more alternate suppliers. If on January 1, 2003, 50%
of PECO's residential and commercial customers are not obtaining generation
services from

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alternate generation suppliers, than non-shopping customers will
be assigned to alternate generation suppliers to reach that level.

On November 29, 2000, the PUC approved PECO's bilateral contract with
New Power Company (New Power) to move 22% of PECO's non-shopping residential
customers to New Power for competitive default generation service. Under this
contract, New Power agreed to provide generation services through January 2004,
at specified discounted rates, to nearly 300,000 residential customers of PECO
who were taking their generation service from PECO. On February 22, 2002 New
Power sent PECO a notice of intent to withdraw from the market and return the
New Power customers to PECO in May 2002.

In addition to the New Power contract, PECO has also entered into a
contract with Green Mountain Energy Company (Green Mountain) to assign 50,000 of
PECO's non-shopping residential customers to Green Mountain for competitive
default generation service, on the same terms and conditions as the New Power
contract. On February 21, 2001, the PUC approved the Green Mountain contract.
Beginning in May 2001, Green Mountain enrolled approximately 44,000 customers
and as of December 31, 2001, approximately 13,000 customers, or 25%, have opted
to return to PECO.

TRANSMISSION SERVICES

Energy Delivery provides wholesale and unbundled retail transmission
service under rates established by FERC. FERC has used its regulation of
transmission to encourage competition for wholesale generation services and the
development of regional structures to facilitate regional wholesale markets. In
December 1999, FERC issued Order No. 2000 (Order 2000) requiring jurisdictional
utilities to file a proposal to form a regional transmission organization (RTO)
or, alternatively, to describe efforts to participate in or work toward
participating in an RTO or explain why they were not participating in an RTO.
Order 2000 is generally designed to separate the governance and operation of the
transmission system from generation companies and other market participants.

ComEd. In response to Order 2000, ComEd and several other utilities
filed a business plan in August 2001 with FERC describing the creation of
Alliance Transmission Company, LLC (Alliance Transco or Alliance) as an
independent, for-profit transmission company. In connection with the process
leading to the FERC filing, ComEd issued a non-binding declaration of intent to
divest to Alliance Transco transmission facilities having a gross book value in
excess of $1 billion. In a related action, ComEd entered into a non-binding
memorandum of understanding with National Grid USA (National Grid), the proposed
manager of Alliance Transco, setting forth general principles relating to the
divestiture and Alliance Transco as a basis for further discussion.

On December 20, 2001, FERC issued several orders relating to RTOs
operating in the Midwest. In those orders, FERC, among other things, approved
Midwest Independent Transmission System Operator, Inc. (MISO) as an RTO and
found that Alliance Transco lacked sufficient scope to be a stand-alone RTO.
FERC also directed the Alliance participants to explore with the MISO how the
participants' business plan can be accommodated with the MISO operational
framework and dismissed the business plan filed in August 2001 by the Alliance
participants. In addition, FERC determined that National Grid is not a market
participant within the meaning of Order 2000 and, thus, is eligible to become
the managing member of Alliance Transco if that entity is formed. FERC further
directed the Alliance participants to file a statement of their plans to join an
RTO, including timeframes, within 60 days. As a result of the

9

FERC orders, representatives of ComEd and the other Alliance participants are
exploring various RTO participation options and are meeting with representatives
of MISO to explore how the Alliance Transco may operate under the MISO. The
Alliance participants, including ComEd, filed their discussions with MISO at the
FERC in February 2002, noting progress as to some issues, but also noted
negotiations were ongoing. The Alliance participants also noted that they were
exploring the possibility of filing their business plan within an RTO other than
MISO.

Following further discussions, the Alliance participants and the
National Grid concluded that further negotiations with the MISO required policy
resolutions from FERC. Accordingly, on March 6, 2002, the Alliance participants
and National Grid submitted a petition to FERC for a declaratory order finding
that the proposed policy resolutions contained in the petition provide an
appropriate basis for the participation of the Alliance participants in the
MISO. The filing requests FERC to approve a proposed division of
responsibilities between National Grid and the MISO. It also seeks approval to
use existing systems for startup of operations in order to speed up initial
operations. It requests approval for the Alliance participants to purchase
services from the MISO at incremental costs, and that the MISO refund the $60
million withdrawal fee, plus interest, to ComEd, Illinois Power Company
(Illinois Power), and Ameren Corporation (Ameren), of which ComEd's portion is
$36 million. The $36 million was paid to the MISO by ComEd in May 2001 under a
FERC approved settlement agreement allowing ComEd, Illinois Power, and Ameren to
withdraw from the MISO to join the Alliance Transco.

PECO. PECO provides regional transmission service pursuant to a
regional open-access transmission tariff filed by it and the other transmission
owners who are members of 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 (PJM ISO) and is responsible for
operation of the PJM control area and administration of the PJM open-access
transmission tariff. PECO and the other transmission owners in PJM have turned
over control of their transmission facilities to the PJM ISO. The PJM ISO and
the transmission owners who are members of PJM, including PECO, have filed with
FERC for approval of PJM as an RTO. FERC has conditionally approved the PJM RTO.

GAS

Historically, PECO's gas sales and gas transportation revenues were
derived pursuant to rates regulated by the PUC. Since 1984, large commercial and
industrial customers have been able to choose their gas suppliers. The PUC
established, through regulated proceedings, the base rates that PECO may charge
for gas service in Pennsylvania. PECO's gas rates are subject to quarterly
adjustments designed to recover or refund the difference between the actual cost
of purchased gas and the amount included in base rates and to recover or refund
increases or decreases in certain state taxes not recovered in base rates.

Effective July 1, 2000, the Pennsylvania Natural Gas Choice and
Competition Act expanded the choice of gas suppliers to residential and small
commercial customers and eliminated the 5% gross receipts tax on gas
distribution companies' sales of gas. Approximately one-third of PECO's current
total yearly throughput is supplied by third parties. The Act permits gas
distribution companies to continue to make regulated sales of gas, at cost, to
their customers. The Act does not deregulate the transportation service provided
by gas distribution companies,

10

which remains subject to rate regulation. Gas
distribution companies continue to provide billing, metering, installation,
maintenance and emergency response services.

PECO'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. PECO's aggregate annual
entitlement under these firm transportation contracts is 45 million dekatherms.
Peak gas is provided by PECO's liquefied natural gas facility and propane-air
plant. PECO also has under contract 21.3 million dekatherms of underground
storage through service agreements. Natural gas from underground storage
represents approximately 34% of PECO's 2001-2002 heating season supplies.

CONSTRUCTION BUDGET

The following table shows Exelon's most recent estimate of capital
expenditures for plant additions and improvements for ComEd and PECO for 2002
(in millions):

ComEd PECO
- -------------------------------------------------------------------------------

Transmission and Distribution $712 $200

Gas -- 69

Other 69 10
---- ----
Total $781 $279
==== ====

Approximately two thirds of ComEd's 2002 budgeted capital expenditures and one
half of PECO's 2002 budgeted capital expenditures are for additions to or
upgrades of existing facilities, including reliability improvements. The
remainder of the capital expenditures support customer and load growth.

GENERATION

GENERAL

Generation is one of the largest competitive electric generation
companies in the United States, as measured by owned and controlled MWs.
Generation combines its large, low-cost generation fleet with an experienced
wholesale power marketing operation. It directly owns generation assets in the
Mid-Atlantic and Midwest regions with a net capacity of 19,715 MW, including
14,250 MW of nuclear capacity, and also controls another 16,245 MW of capacity
in the Midwest, Southeast and South Central regions through long-term contracts.

In addition to its owned generation facilities, Generation has acquired
a 49.9% interest in Sithe with put and call options, beginning in December 2002,
to purchase the remaining 50.1% interest. Sithe develops, owns and operates 27
generation facilities in North America. Currently, Sithe has 3,371 MW of
capacity in operation and 5,051 MW under construction or in advanced
development. Generation also owns a 50% interest in AmerGen, a joint venture
with British Energy plc. AmerGen owns three nuclear stations with total
generation capacity of 2,398 MW.

Generation's wholesale marketing unit, Power Team, is a major wholesale
marketer of energy that uses Generation's generation portfolio, transmission
rights and expertise to ensure delivery of generation to Generation's wholesale
customers under long-term and short-term contracts. Power Team is responsible
for supplying the load requirements of ComEd and PECO and markets the remaining
energy in the wholesale and spot markets.

11

GENERATING RESOURCES

The generating resources of Generation, including its ownership share
of AmerGen and Sithe, consist of the following:

Type of Capacity MW
- ---------------- -------

Owned Generation Assets (1),(2)
Nuclear 14,250
Fossil 3,881
Hydro 1,584
------
19,715
Long-term Contracts (3) 16,245
AmerGen and Sithe (2) 2,881
------
Available Resources 38,841
Under Construction or in Advanced Development (2) 2,521
------
Total Generating Resources 41,362
======

(1) See "Fuel" for sources of fuels used in electric generation.
(2) Based on Generation's ownership.
(3) Contracts range from 1 to 29 years.

Generation's owned generation assets are primarily the nuclear
generation stations in the Midwest region that were acquired from ComEd and the
nuclear, fossil and hydroelectric stations in the Mid-Atlantic region that were
acquired from PECO.

Generation has a 49.9% interest in Sithe and a 50% interest in AmerGen.
Sithe, an independent power producer, owns and operates 27 power generation
facilities in North America with approximately 3,371 MW of net generation
capacity and has approximately 5,051 MW of capacity under construction or in
advanced development. AmerGen owns three nuclear plants with a total capacity of
2,398 MW.

The owned generating resources of Generation are located primarily in
the Midwest (approximately 50% of capacity) and the Mid Atlantic and New England
regions (approximately 49% of capacity). AmerGen's generating resources are also
in the Midwest and the Mid Atlantic regions. Sithe's generating resources are
primarily in the New England region.

In December 2001, Generation agreed to purchase two generation plants
located in the Dallas Fort-Worth metropolitan area from TXU Corporation (TXU) to
expand its presence in the Texas region. The $443 million purchase of the two
natural-gas and oil-fired plants, to be financed through available cash and
borrowings from Exelon, will add 2,334 MW capacity. The transaction includes a
purchase power and tolling agreement for TXU Energy to purchase power during the
months of May through September until September 2006. The closing of the
acquisition is subject to certain contingencies including the receipt of the
necessary regulatory approvals and is anticipated to occur in the second quarter
of 2002.

NUCLEAR FACILITIES. Generation has direct ownership interests in eight
nuclear generating stations, consisting of 16 units with 14,250 MW of capacity
(Exelon share). For additional information, see ITEM 2. Properties. All of the
nuclear generating stations are operated by Generation, with the exception of
Salem Generating Station (Salem), which is operated by PSE&G Nuclear, LLC. In
addition, AmerGen operates three nuclear generating stations

12

consisting of three units with 2,398 MW of capacity, of which Generation's
interest is 1,199 MW.

In 2001, approximately 54% of Generation's electric supply was
generated from the nuclear generating facilities. During 2001 and 2000, the
nuclear generating facilities operated by Generation and AmerGen, operated at
weighted average capacity factors of 94.4% and 93.8%, respectively. See the
AmerGen section, which follows within ITEM 1. Business-Generation, for further
discussion of the three nuclear facilities owned by AmerGen. Generation is in
the process of increasing the capacity of its nuclear fleet through power
uprates and plant modifications and refinements. Power uprate projects involve
equipment and instrumentation modifications, which require NRC approval. These
power uprate projects have the potential of adding up to 885 MW of capacity by
the end of 2003. Generation is also pursuing other capacity additions through
plant modifications and refinements of several nuclear units that have the
potential of adding between 60 MW and 90 MW of capacity.

In 2001, Generation completed the purchase of an additional 3.755%
interest in the Peach Bottom Station from Atlantic City Electric Company. Total
cash paid for the additional interest, including nuclear fuel, was $7 million.
As part of this purchase, nuclear decommissioning funds of $29 million were also
transferred to Generation. Generation is now a 50% owner of Peach Bottom.

LICENSES. Exelon has 40-year operating licenses for each of its nuclear
units. Generation applied to the NRC in July 2001 for renewal of the Peach
Bottom 2 and 3 licenses and expects to apply for the extension of the operating
license for Dresden 2 and 3 and Quad Cities in 2003. The operating license
renewal process takes approximately four to five years from the commencement of
the project at a site until completion of the NRC's review. The NRC review
process takes approximately two years from the docketing of an application. Each
requested license extension is expected to be for 20 years beyond the current
license expiration. Depreciation provisions are based on the estimated useful
lives of the units, which assume the extension of these licenses for all of the
nuclear generating stations. The following table summarizes current operating
license expiration dates for Generation's nuclear facilities in service.

In-Service Current License
Station Unit Date Expiration
- ------- ---- ------------ ---------------

Braidwood 1 1988 2026
2 1988 2027
Byron 1 1985 2024
2 1987 2026
Dresden 2 1970 2009
3 1971 2011
LaSalle 1 1984 2022
2 1984 2023
Quad Cities 1 1973 2012
2 1973 2012
Limerick 1 1986 2024
2 1990 2029
Peach Bottom 2 1974 2013
3 1974 2014
Salem 1 1977 2016
2 1981 2020

13

REGULATION OF NUCLEAR POWER GENERATION AND SECURITY. Generation is
subject to the jurisdiction of the NRC with respect to its nuclear generating
stations. The NRC subjects nuclear generating stations to continuing review and
regulation covering, among other things, operations, maintenance, emergency
planning, security, environmental and radiological aspects of those stations.
The NRC may modify, suspend or revoke licenses and impose civil penalties for
failure to comply with the Atomic Energy Act, the regulations under such Act or
the terms of such licenses. 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 Exelon and its results of operations.

The NRC has revamped its inspection, assessment and enforcement
programs for commercial nuclear power plants. The new oversight process uses
objective, timely and safety-significant criteria in assessing performance,
while seeking to effectively and efficiently regulate the industry. It also
takes into account improvements in the performance of the nuclear industry over
the past twenty years. Nuclear plant performance is measured by a combination of
objective performance indicators and by the NRC inspection program. These are
closely focused on those plant activities having the greatest impact on safety
and overall risk. In addition, the NRC conducts periodic reviews of the
effectiveness of each operator's programs to identify and correct problems. The
inspection program is designed to verify the accuracy of performance indicator
information and to assess performance based on safety cornerstones that include:

o initiating events;
o mitigating systems;
o integrity of barriers to release of radioactivity;
o emergency preparedness;
o occupational radiation safety;
o public radiation safety; and
o physical protection.

The NRC evaluates licensee performance by analyzing two distinct
inputs: inspection findings resulting from the NRC inspection program and
performance indicators reported by the licensees on a quarterly basis.

NRC reactor oversight results for the fourth quarter of 2001 indicate
performance at levels satisfactory enough to receive routine NRC oversight.

With respect to nuclear power plant security issues, in response to the
events of September 11, 2001, the NRC issued Safeguards and Threat Advisories to
all nuclear power plant licensees, including Generation, requesting that they
place their facilities on highest alert security status. In response to the NRC
Advisories and on its own initiative, Exelon also implemented enhanced security
measures, such as increased guard forces, the erection of additional physical
barriers, and heightened communication with authorities at all levels of
government. In addition to the Advisories, the NRC began an initiative to
perform a "top to bottom" review of its safeguards and security programs and
requirements in light of the events of September 11.

On February 25, 2002, the NRC issued immediately effective orders
modifying the operating licenses for all nuclear power plants to require all
licensees, including Generation, to implement certain interim security
enhancements. In issuing the orders, the NRC found that these compensatory
measures should be implemented "as prudent, interim measures, to address the
generalized high-level threat environment . . . ." The orders direct all
licensees to provide the NRC a schedule for achieving compliance with the
requirements of the orders or explain site-

14

specific circumstances to justify relief or variation from those requirements.
In addition, if implementation of any requirement would adversely affect safe
operation of a facility, a licensee may either propose an alternate plan for
achieving the objectives of the order or provide the NRC a schedule for
modifying the facility to address the adverse safety condition(s). All
enhancements required by the orders are to be implemented by August 31, 2002.
The orders are to remain in effect pending an NRC decision that changes in the
threat environment justify a relaxation of the requirements or until the NRC
determines that other changes are necessary following a re-evaluation of current
security programs. The security requirements imposed by the NRC's orders are
currently estimated to increase capital expenditures by approximately $1 million
per station for such things as enhanced vehicle barriers, modification to plant
facilities and increased size of guard force.

NUCLEAR WASTE DISPOSAL. There are no facilities for the reprocessing or
permanent disposal of spent nuclear fuel (SNF) currently in operation in the
United States, nor has the NRC licensed any such facilities. Generation
currently stores all SNF generated by nuclear generation facilities in on-site
storage pools and, in the case of Peach Bottom and Dresden, some SNF has been
placed in dry cask storage facilities. SNF storage pools do not have sufficient
storage capacity for the life of the plant and Generation is developing dry cask
storage facilities, as necessary to support operations.

Under the Nuclear Waste Policy Act of 1982 (NWPA), the United States
Department of Energy (DOE) is responsible for the disposal of SNF and other
high-level radioactive waste. ComEd and PECO each signed contracts with the DOE
(each, Standard Contract) to provide for disposal of SNF from their respective
nuclear generation stations. Generation assumed the ComEd and PECO Standard
Contracts as part of the restructuring, covering Byron, Braidwood, LaSalle, Quad
Cities, Zion, Dresden, Limerick and Peach Bottom. In accordance with the NWPA
and the Standard Contract, ComEd and PECO pay the DOE one mill ($.001) per kWh
of nuclear generation, net of station use, for the cost of nuclear fuel
long-term storage and disposal. This fee may be adjusted, in order to ensure
full cost recovery by the DOE.

The Standard Contract required ComEd and PECO to pay the DOE a one-time
fee applicable to nuclear generation through April 6, 1983. PECO has paid this
fee while ComEd exercised its option to pay the one-time fee of $277 million,
with interest, just prior to the first delivery of SNF to the DOE. As of
December 31, 2001, the unfunded liability for the one-time fee with interest was
$843 million. This obligation was assumed by Generation in the corporate
restructuring.

The NWPA and the Standard Contract required the DOE to begin taking
possession of SNF generated by nuclear generating units by no later than January
1998. The DOE, however, failed to meet that deadline and its performance is
expected to be delayed significantly. The DOE's current estimate for opening an
SNF permanent disposal facility is 2010. This extended delay in SNF acceptance
by the DOE has led to Exelon's adoption of dry storage at its Dresden and Peach
Bottom Units and its consideration of dry storage at other units.

In July 1998, ComEd filed a complaint against the DOE in the U.S. Court
of Federal Claims seeking to recover damages caused by the DOE's failure to
honor its contractual obligation to begin disposing of SNF in January 1998.
ComEd subsequently moved for partial summary judgment on liability for breach of
contract claim. In August 2001, the Court granted ComEd's motion for partial
summary judgment for liability on ComEd's breach of contract claim. In November
2001, the DOE filed two partial summary judgment motions relating to certain
damage issues in the case, as well as two motions to dismiss claims other than
ComEd's breach of contract claim. The Court has deferred briefing on those
motions pending completion

15

of discovery on certain damage issues. This litigation was assumed by
Generation in the corporate restructuring.

In July 2000, PECO entered into an agreement with the DOE relating to
Peach Bottom to address the DOE's failure to begin removal of SNF in January
1998, as required by the Standard Contract. Under that agreement, the DOE agreed
to provide PECO with credits against PECO's future contributions to the nuclear
waste fund over the next ten years to compensate for SNF storage costs incurred
as a result of the DOE's breach of the Standard Contract. The agreement also
provides that, upon PECO's request, the DOE will take title to the SNF and the
interim storage facility at Peach Bottom, provided certain conditions are met.
Generation has assumed this contract in restructuring.

In November 2000, eight utilities with nuclear power plants filed a
Joint Petition for Review against the DOE with the U.S. Court of Appeals for the
Eleventh Circuit seeking to invalidate the portion of the agreement providing
for credits to PECO against nuclear waste fund payments on the ground that such
provision is a violation of the NWPA. PECO intervened as a defendant in that
case, which is ongoing. On December 5, 2001, the United States Court of Appeals
for the Eleventh Circuit heard oral argument on the utilities' Joint Petition
for Review. In April 2001, an individual filed suit against the DOE with the
United States District Court for the Middle District of Pennsylvania seeking to
invalidate the agreement on the grounds that the DOE has violated the National
Environmental Policy Act and the Administrative Procedure Act. PECO intervened
as a defendant and moved to dismiss the complaint. The Court has not yet ruled
on the motion to dismiss.

As a by-product of their operations, nuclear generation units produce
low-level radioactive waste (LLRW). LLRW is accumulated at each generation
station and permanently disposed of at Federally licensed disposal facilities.
The Federal Low-Level Radioactive Waste Policy Act of 1980 (Waste Policy Act)
provides that states may enter into agreements to provide regional disposal
facilities for LLRW and restrict use of those facilities to waste generated
within the region. Illinois and Kentucky have entered into an agreement,
although neither state currently has an operational site, and none is currently
expected to be operational until after 2011. Pennsylvania, which had agreed to
be the host site for LLRW disposal facilities for generators located in
Pennsylvania, Delaware, Maryland and West Virginia, has suspended the search for
a permanent disposal site.

Generation has temporary on-site storage capacity at its nuclear
generation stations for limited amounts of LLRW and has been shipping such waste
to LLRW disposal facilities in South Carolina and Utah. The number of LLRW
disposal facilities is decreasing, and Generation anticipates the possibility of
continuing difficulties in disposing of LLRW. Generation is also pursuing
alternative disposal strategies for LLRW, including a LLRW reduction program to
minimize cost impacts.

The National Energy Policy Act of 1992 requires that the owners of
nuclear reactors pay for the decommissioning and decontamination of the DOE
uranium enrichment facilities. The total cost to all domestic utilities covered
by this requirement is estimated to be $150 million per year through 2006, of
which Generation's share is approximately $22 million per year.

INSURANCE. The Price-Anderson Act limits the liability of nuclear
reactor owners to $9.5 billion for claims arising from a single incident. The
current limit is subject to change to account for the effects of inflation and
changes in the number of licensed reactors. Exelon carries the maximum available
commercial insurance of $200 million and the remaining $9.3 billion is

16

provided through mandatory participation in a financial protection pool. Under
the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $89
million per reactor per incident, payable at a rate of 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 Price-Anderson Act is
scheduled to expire in August 2002. Although replacement legislation has been
proposed from time to time, Exelon is unable to predict whether replacement
legislation will be enacted. The Price-Anderson Act and the extensive NRC
regulation by the NRC do not preclude claims under state law for personal,
property or punitive damages related to radiation hazards.

Liability of owners of nuclear power plants currently licensed by the
NRC to operate would continue to be limited by the Price-Anderson Act provisions
regardless of whether Congress renews the Price-Anderson Act. The renewal of
Price-Anderson, however, would be important for any new plants to be licensed in
the future. Although several bills proposing the renewal of the Price-Anderson
Act are currently pending in the United States Congress, Generation is unable to
predict at this time whether renewal will occur before August 1, 2002.

Generation maintains property insurance for each nuclear power plant in
which Generation has an ownership interest. Generation is responsible for its
proportionate share of premiums for such insurance based on its ownership
interest. Generation's insurance policies provide coverage for decontamination
liability expense, premature decommissioning and loss or damage to 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. Under Generation'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
incident, the decision is made to decommission the facility, a portion of the
insurance proceeds will be allocated to a decommissioning fund that Generation
is required to maintain by the NRC. (See "Regulation of Nuclear Facility
Decommissioning and Security.") 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. Generation is
unable to predict what effect these requirements may have on the timing of the
availability of insurance proceeds to creditors and the amount of these
proceeds. Under the terms of the various insurance agreements, Generation could
be assessed up to $121 million for losses incurred at any plant insured by the
insurance companies. Nuclear Electric Institute Limited (NEIL), a mutual
insurance company to which Generation belongs, provides property and business
interruption insurance for Generation's nuclear operations. One feature of
Generation's property insurance through NEIL provides coverage for damages
caused by acts of terrorism at any of its nuclear generating stations. This
terrorism endorsement to the NEIL policy specifies that its coverage applies to
acts of terrorism similar to the September 11, 2001 events. In the event that
one or more acts of terrorism cause accidental property damage within a 12-month
period from the first accidental property damage under one or more policies for
all insureds, the maximum recovery for all losses by all insureds will be an
aggregate of $3.2 billion plus such additional amounts as the insurer may
recover for all such losses from reinsurance, indemnity or any other source
applicable to such losses. If total property losses exceed available funds under
the policy, proportionate recovery is provided to cover a portion of an
insured's property losses. The percentage recovery would be equal to the ratio
of the insured's property losses and the total of all property losses.

Generation's insurance through NEIL also provides replacement power
cost insurance in the event of a major accidental outage at a nuclear station.
The policy provides for a waiting

17

period before recovery of costs can commence. The premium for this coverage is
subject to assessment for adverse loss experience, with a maximum assessment of
$46 million per year. Recovery under this insurance for terrorist acts is
subject to the $3.2 billion aggregate limit and secondary to the property
insurance described above.

In addition, Generation participates in the American Nuclear Insurers
Master Worker Program, which provides coverage for worker tort claims filed for
bodily injury caused by a nuclear energy accident. This program was modified,
effective January 1, 1998, to provide coverage to all workers whose
nuclear-related employment began on or after the commencement date of reactor
operations. Generation will not be liable for a retroactive assessment under
this new policy. However, in the event losses incurred under the small number of
policies in the old program exceed accumulated reserves, a maximum retroactive
assessment of up to $50 million could apply.

Generation does not carry any business interruption insurance other
than the NEIL coverage for nuclear operations. Generation 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 Generation's financial condition
and results of operations.

DECOMMISSIONING. 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 Generation has an ownership interest, the ICC
permits ComEd and the PUC permits PECO to collect from its customers and deposit
in segregated accounts amounts which, together with earnings thereon, will be
used to decommission such nuclear facilities. As of December 31, 2001,
Generation's estimate of its nuclear facilities' decommissioning cost is $7.2
billion in current year dollars. The liability for decommissioning each
generation station is recognized ratably over that generating station's service
life. At December 31, 2001, the decommissioning liability recorded in
accumulated depreciation and deferred credits and other liabilities was $2.7
billion and $1.3 billion, respectively. Decommissioning expenditures are
expected to occur primarily after the plants are retired and are currently
estimated to begin in 2029 for plants currently in operation. Decommissioning
costs are currently recoverable by ComEd and PECO through regulated rates and
are remitted to Generation for deposit in the decommissioning trust funds. In
2001, ComEd and PECO collected from customers and remitted to Generation
approximately $102 million in decommissioning costs. Generation believes that
the amounts being remitted to it by ComEd and PECO and the earnings on nuclear
decommissioning trust funds will be sufficient to fully fund Generation's
decommissioning obligations.

In connection with the transfer of ComEd's nuclear generating stations
to Generation, ComEd asked the ICC to approve the continued recovery of
decommissioning costs after the transfer. On December 20, 2000, the ICC issued
an order finding that the ICC has the legal authority to permit ComEd to
continue to recover decommissioning costs from customers for the six-year term
of the PPAs between ComEd and Generation. Under the ICC order, ComEd is
permitted to recover $73 million per year from customers for decommissioning for
the years 2001 through 2004. In 2005 and 2006, ComEd can recover up to $73
million annually, depending upon the portion of the output of the former ComEd
nuclear stations that ComEd purchases from Generation. Under the ICC order,
subsequent to 2006, there will be no further recoveries of decommissioning costs
from customers. The ICC order also provides that any surplus funds after the
nuclear stations are decommissioned must be refunded to customers. The ICC order
is currently pending on appeal in the Illinois Appellate Court.

18

Zion, a two-unit nuclear generation station, and Dresden Unit 1
formerly owned by ComEd, have permanently ceased power generation. ComEd
transferred Zion and Dresden Unit 1 as well as their related decommissioning
liabilities and trust funds to Generation as part of Exelon's corporate
restructuring. Zion's and Dresden Unit 1's spent nuclear fuel is currently being
stored in on-site storage pools until a permanent repository under the NWPA is
completed. Generation has recorded a liability of $1.3 billion, which represents
the estimated cost of decommissioning Zion and Dresden Unit 1 in current year
dollars. Decommissioning expenditures are expected to occur primarily after 2013
and 2030 for Zion and Dresden Unit 1, respectively.

FOSSIL AND HYDROELECTRIC FACILITIES.

Fossil units include:

o base-load units -- the coal-fired units at Eddystone and Cromby and our
interests in the Keystone and Conemaugh Stations;

o intermediate units -- the Eddystone and Cromby units that have dual fuel
(oil/gas) capability; and

o peaking units -- oil- or gas-fired steam turbines, combustion turbines and
internal combustion units at various locations.

Hydroelectric facilities include:

o base-load units-- at the Conowingo run-of-river hydroelectric facility on
the Susquehanna River in Harford County, Maryland; and

o intermediate units-- at the Muddy Run pumped-storage hydroelectric
facility in Lancaster County, Pennsylvania.

Generation operates all of its fossil and hydroelectric facilities
other than La Porte, Keystone and Conemaugh. In 2001, approximately 3% of
electric output was generated from our owned fossil and hydroelectric generation
facilities. The majority of this output was dispatched to support Generation's
power marketing activities.

Generation is in the process of extensively renovating the Conowingo
and Muddy Run control systems to improve plant efficiency. Generation is
planning to overhaul 4 units at Conowingo, which is expected to increase
capacity by 10 MW per unit.

The controls at all combustion turbine facilities have been
re-configured to provide remote start capability for all units, enabling
immediate response time to capture fluctuations in electric market prices.

LICENSES. Fossil generation plants are generally not licensed and,
therefore, the decision on when to retire plants is fundamentally an economic
one. Hydroelectric plants are licensed by FERC. The Muddy Run and Conowingo
facilities have licenses that expire in September 2014. Generation is
considering applying to FERC for license extensions of 40 years for both plants,
but the duration of any license extension will depend on then-current policies
at FERC. The process of applying for an extension to an existing hydroelectric
license generally takes at least eight years.

19

LONG-TERM CONTRACTS. In addition to owned generation assets, Generation
sells electricity purchased under the long-term contracts described below:

Seller Location Expiration Capacity (MW)
- ----------------------------- --------------------- ------------- --------------

Midwest Generation, LLC Various in Illinois 2004 9,105
Kincaid Generation, LLC Kincaid, Illinois 2012 1,158
Tenaska Georgia Partners, LP Franklin, Georgia 2029 900
Tenaska Frontier, Ltd Shiro, Texas 2020 830
Others Various 2002 to 2022 4,252
--------------
Total 16,245
==============

MIDWEST GENERATION, LLC CONTRACT. Generation is a party to contracts
with Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison
Mission Energy. Under the contracts, Generation initially had the right to
purchase through 2004 the capacity and energy associated with approximately
9,460 MW of fossil-fired generation stations located in Northern Illinois,
formerly owned by ComEd. The generation units include base-load, intermediate
and peaking units. Under the contracts, Generation pays a fixed capacity charge
that varies by season and a fixed energy charge. The capacity charge is reduced
to the extent the plants are unable to generate and deliver energy when
requested. Under the contracts, Generation has annual rights to reduce the
capacity and related energy purchase obligations, and some of these rights were
recently exercised. Effective January 1, 2002, Generation has released all of
the 355 MW of oil-fixed peaking capacity that is covered by the contracts, and
will decide whether to exercise yearly options in 2003 and 2004 depending on the
projected need for capacity and energy to fulfill obligations under the
agreement with ComEd or otherwise, taking into account forward market conditions
and other alternatives. Finally, Generation is in arbitration with Midwest
Generation under the contract relating to the unavailability of certain units in
January 2001.

FEDERAL POWER ACT

The Federal Power Act gives FERC exclusive rate-making jurisdiction
over wholesale sales of electricity and the transmission of electricity in
interstate commerce. Pursuant to the Federal Power Act, all public utilities
subject to FERC's jurisdiction are required to file rate schedules with FERC
with respect to wholesale sales or transmission of electricity. Tariffs
established under FERC regulation give Generation access to transmission lines
that enables it to participate in competitive wholesale markets.

Because Generation sells power in the wholesale markets, Generation is
deemed to be a public utility for purposes of the Federal Power Act and is
required to obtain FERC's acceptance of the rate schedules for wholesale sales
of electricity. Generation has received authorization from FERC to sell energy
at market-based rates. As is customary with market-based rate schedules, FERC
reserved the right to suspend market-based rate authority on a retroactive basis
if it is subsequently determined that Generation or any of its affiliates
exercised or have the ability to exercise market power. FERC is also authorized
to order refunds if it finds that market-based rates are unreasonable.

In April 1996, FERC issued Order 888 (Order 888). The intent of Order
888 was to open the transmission grid subject to FERC's jurisdiction to all
eligible customers, including sellers of power and retail customers, in states
where retail access is approved. Order 888 requires that owners of transmission
facilities provide access to their transmission facilities under filed tariffs
at cost-based rates. In connection with Order 888, FERC issued Order 889 (Order
889). Under Order 889, PECO and ComEd were required to file Standards of
Conduct, which governed the

20

communication of non-public information between
transmission personnel and employees of any affiliated wholesale merchant
function. FERC recently issued a Notice of Proposed Rulemaking for the Standards
of Conduct for Transmission Providers. Among other things, FERC is considering
whether it would be appropriate for it to adopt measures that would limit the
amount of capacity an affiliate can hold in a transmission provider.
Generation's business would be impacted if any of these measures were
instituted.

In December 1999, FERC issued Order 2000, which encourages the
voluntary restructuring of transmission operations through the use of
independent system operators (ISOs) and RTOs. A result of establishing these
entities is to eliminate or reduce transmission charges imposed by successive
transmission systems when wholesale generators cross several transmission
systems to deliver capacity. During 2000, FERC announced its intention to foster
RTO development. Each transmission-owning public utility was required to file a
plan to form an RTO, with December 2001 as the target date for operation. In
July 2001, FERC conditionally granted RTO status to PJM and, in separate orders,
directed that the various proposed RTOs combine into four regional RTOs.
However, inconsistencies in the pace of RTO development and significant state
public utility commission concerns caused FERC to indefinitely extend its
operational target date of December 2001.

The latter half of 2001 and early 2002 have brought further change to
the electric industry. In early November 2001, FERC announced its intent to
complete RTO development using two parallel tracks: (1) address geographic scope
and governance of RTOs; and (2) address transmission pricing and market design.
Contemporaneously, FERC initiated several immediate steps to move the RTO
development process forward. One of these actions was initiation of an effort to
standardize generator interconnection (a related effort concerning cost
allocation is to be addressed in 2002). Also, FERC issued a Notice of Proposed
Ruling on Revised Public Utility Filing Requirements, pursuant to which it is
considering mandatory electronic filing of transactional data and additional
public filing requirements.

Several other actions by FERC are important. First, FERC announced in
late November 2001 a new market power test, the Supply Margin Assessment (SMA)
screen. Under the SMA, if within a particular geographic market an energy
company's generation capacity exceeds the market's surplus capacity above peak
demand then the test is failed. Where this occurs, FERC will impose on the
company and its affiliates a requirement to offer uncommitted capacity under a
cost-based rate structure. The only exemption will be for companies operating
under the authority of an ISO or RTO with a FERC-approved market monitoring and
mitigation plan. Under this approach, it would be unlikely that a vertically
integrated energy company serving franchised retail load would be able to pass
the test and maintain market-based rates, unless and until the company was a
member of an approved ISO or RTO.

Second, FERC continues to exhibit a commitment to increased market
monitoring with an intent to ensure that high price volatility, such as was seen
in California, does not occur again. As part of this commitment, FERC announced
early in 2002 the formation of the Office of Market Oversight and Investigation,
which will report directly to the FERC Chairman. This new office will assess,
among other things, market performance. It is unclear how Generation's business
may be impacted by these initiatives.

Finally, in December 2001, FERC approved the Midwest ISO (MISO) as an
RTO, which principally resides within the MAPP reliability region. The FERC's
action also rejected the stand alone, for-profit RTO structure proposed by the
Alliance Companies. FERC, however, indicated that a for-profit transmission
company could be formed and successfully integrated into the

21

MISO. Currently, while a significant portion of Exelon's generation is located
within the PJM RTO area, other significant generation is located within the MAIN
reliability region, where an approved ISO or RTO does not exist. It is possible
that under its evolving market power tests, FERC might determine that Generation
has market power in this area. If FERC were to suspend Generation's market-based
rate authority, it would most likely be necessary to file, and obtain FERC
acceptance of, cost-based rate schedules or schedules tied to a public index. In
addition, the loss of market-based rate authority would subject Generation to
the accounting, record-keeping and reporting requirements that are imposed on
public utilities with cost-based rate schedules.

FUEL

The following table shows sources of electric supply for 2001 and
estimated for 2002:

Source of Electric Supply
----------------------------
2001 2002 (Est.)
------- -------------

Nuclear units 54% 52%
Purchases 37% 39%
Fossil and hydro units 3% 3%
Units operated by others (a) 6% 6%
------- -------------
100% 100%
------- -------------

(a) Reflects Generation's share of the output of Salem, Keystone and Conemaugh
stations, and 100% of the output for LaPorte station, all which are operated by
other companies. See ITEM 2. Properties - for further information on
Generation's station ownership.

The fuel costs for nuclear generation are substantially less than
fossil-fuel generation. Consequently, nuclear generation is the most
cost-effective way for Generation to meet its commitment to supply the
requirements of ComEd, PECO and Enterprise's competitive retail energy sales
business, Exelon Energy Inc. (Exelon Energy), and for sales to other utilities.

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 and the fabrication of fuel assemblies. Generation has uranium
concentrate inventory and supply contracts sufficient to meet all of its uranium
concentrate requirements through 2003. Generation's contracted conversion
services are sufficient to meet all of its uranium conversion requirements
through 2004. All of Generation's enrichment requirements have been contracted
through 2004. Contracts for fuel fabrication have been obtained through 2005.
Generation does not anticipate difficulty in obtaining the necessary uranium
concentrates or conversion, enrichment or fabrication services for its nuclear
units.

Generation obtains approximately 25% of its uranium enrichment services
from European suppliers. There is an ongoing trade action by USEC, Inc. (USEC)
alleging dumping in the United States against European enrichment services
suppliers. In January 2002, the U.S. International Trade Commission determined
that USEC was "materially injured or threatened with material injury" by
low-enriched uranium exported by European suppliers. The U.S. Department of
Commerce (DOC) has assessed countervailing and anti-dumping duties against the
European suppliers. Both USEC and the European suppliers have appealed these
decisions. Exelon is uncertain at this time as to the outcome of the pending
appeals, however as a result of these actions Exelon may incur higher costs for
uranium enrichment services necessary for the production of nuclear fuel.

22

FUEL MANAGEMENT. Coal is obtained for coal-fired plants primarily
through annual contracts with the remainder supplied through either short-term
contracts or spot-market purchases.

Natural gas is procured through annual, monthly and spot-market
purchases. Some fossil generation stations can use either oil or gas as fuel.
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. In 2001, the use of financial instruments to mitigate
price risk associated with multi-commodity price exposures was started.
Generation also hedges forward price risk with both over-the-counter and
exchange-traded instruments.

POWER TEAM

Power Team competes nationally in wholesale power marketing on the
basis of price and service offerings, using Generation's generation assets,
transmission access, reservations and its knowledge of the interconnected bulk
power systems and developing markets to assure customers of energy delivery.
Through Power Team, Generation enters into bilateral arrangements for the
purchase, sale and delivery of capacity, energy and ancillary services. Sales
agreements are with load-serving entities, including electric utilities,
municipalities, electric cooperatives, retail load aggregators and other
wholesale market participants. Through Power Team, Generation also competes in
the wholesale spot markets for electricity.

Generation has agreements with ComEd and PECO to supply their
respective load requirements for customers through 2006 and 2010, respectively.
See Item 8. Financial Statements and Supplementary Data - ComEd, Note 2, and
PECO Note 2. Generation has also contracted with Exelon Energy to meet its
supply commitments pursuant to its competitive retail generation sales
agreements. Under the agreements with ComEd and PECO, Generation will supply all
of ComEd and PECO's needs to supply customers who do not select an alternative
electric generation supplier through the end of the respective transition
periods. Therefore, the supply requirements under the agreements will vary
depending on how much of the load has selected an alternative supplier.

Power Team also manages the price and supply risks for energy and fuel
associated with generation assets and the risks of power marketing activities.
Through Power Team, Generation began to use financial and commodity contracts
for trading purposes in the second quarter of 2001. The trading activities
represent a very limited portion of Generation's overall power marketing
activities. For example, the limit on new purchases of electricity for any
forward month represents less than 5% of the owned and contracted supply of
electricity. The trading portfolio is planned to grow modestly in 2002, subject
to stringent risk management limits and policies including volume, stop-loss and
value-at-risk limits to manage exposure to market risk. Additionally, Generation
has a financial risk management policy and a corporate risk group to monitor the
financial risks of its power marketing activities. Financial trading, together
with the effects of Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivatives and
Hedging Activities" (SFAS No. 133), may cause volatility in Generation's future
results of operations.

Generation's wholesale operations include the physical delivery and
marketing of power obtained through its generation capacity, and long,
intermediate and short-term contracts. Generation seeks to maintain a net
positive supply of energy and capacity, through ownership of generation assets
and power purchase and lease agreements, to protect it from the potential

23

operational failure of one of its owned or contracted power generating units.
Generation has also contracted for access to additional generation through
bilateral long-term PPAs. These agreements are commitments related to power
generation of specific generation plants and/or are dispatchable in nature
similar to asset ownership. Generation enters into PPAs with the objective of
obtaining low-cost energy supply sources to meet its physical delivery
obligations to customers. Excess power is sold in the wholesale market.
Generation has also purchased transmission service 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 Generation with physical power supply
to enable it to deliver energy to meet customer needs.

Generation has entered into bilateral long-term contractual obligations
for sales of energy to load-serving entities including electric utilities,
municipalities, electric cooperatives, and retail load aggregators. Generation
also enters into contractual obligations to deliver energy to wholesale market
participants who primarily focus on the resale of energy products for delivery.
Generation provides delivery of its energy to these customers through access to
transmission assets or rights for transmission service.

In addition, Generation has entered into long-term PPAs with
independent power producers under which Generation makes fixed capacity payments
in return for exclusive rights to the energy and capacity of the generating
units for a fixed period. The terms of the long-term PPAs enable Generation to
dispatch energy from the plants.

At December 31, 2001, Generation had long-term commitments, relating to
the purchase and sale of energy, capacity and transmission rights from
unaffiliated utilities and others, including the Midwest Generation and AmerGen
contracts, as expressed in the following tables:

Capacity Power Only Power Only Transmission
(in millions) Purchases Purchases Sales Rights Purchases
--------- ---------- ---------- -----------------

2002 $1,005 $ 551 $1,803 $ 139
2003 1,214 345 666 31
2004 1,222 346 219 15
2005 406 264 139 15
2006 406 250 58 5
Thereafter 3,657 2,321 22 --
------ ------ ------ ------
Total $7,910 $4,077 $2,907 $ 205
====== ====== ====== ======

In addition, in connection with the acquisition of the TXU generating
stations, expected to close in the second quarter of 2002, Exelon has agreed to
supply TXU with 100% of the station output during the months of May through
September from 2002 through 2006. During the periods covered by the power
purchase agreement, TXU will make fixed capacity payments and will provide fuel
to Exelon in return for exclusive rights to the energy and capacity of the
generation plants.

24

CAPITAL EXPENDITURES

Generation's estimated capital expenditures for 2002 are as follows:

(in millions)
- ------------------------------------------------------------------------------------------------------------

Production Plant $ 403
Nuclear Fuel 432
Investments 254
---------
Total $ 1,089
=========

Approximately 75% of Generation's estimated capital expenditures for
2002 are for additions to or upgrades of existing facilities (including nuclear
outages), nuclear fuel and increases in capacity at existing plants. The
remainder is for asset acquisitions other than the TXU generating station
acquisition.

SITHE

Generation owns 49.9% of the outstanding common stock of Sithe and has
an option, beginning on December 18, 2002, to purchase the remaining common
stock outstanding (Remaining Interest) in Sithe. The purchase option expires on
December 18, 2005. In addition, the Sithe stockholders who own in the aggregate
the Remaining Interest have the right to require Generation to purchase the
Remaining Interest (Put Rights) during the same period in which Generation can
exercise its purchase option. At the end of this exercise period, if Generation
has not exercised its purchase option and the other Sithe stockholders have not
exercised their Put Rights, Generation will have an additional one-time option
to purchase shares from the other stockholders in Sithe to bring Generation's
ownership in Sithe from the current 49.9% to 50.1% of Sithe's total outstanding
common stock.

Sithe presently owns and operates 27 power generation facilities in
North America, with approximately 3,371 MW of net merchant generating capacity.
It has 4 facilities under construction with an estimated capacity of 2,651 MW
and approximately 2,400 MW of generation capacity in various stages of advanced
development.

On December 31, 2001, Sithe had long-term debt of $2.3 billion,
including $2.1 billion of non-recourse project debt, not including any
non-recourse project debt associated with Sithe's equity investments. In
December 2001, Sithe entered into a new 18-month corporate credit facility for
$500 million expiring in June 2003. As of December 31, 2001 Sithe had drawn
approximately $176 million under this facility and extended approximately $161
million in letters of credit. Through internally generated cashflows and the
corporate credit facility, Sithe has sufficient liquidity to cover all 2002
operating and capital commitments.

AMERGEN

AmerGen Energy Company, LLC was formed in 1997 by PECO and British
Energy plc, (British Energy), to acquire and operate nuclear generation
facilities in North America. Currently, AmerGen owns three single-unit nuclear
generation facilities, which are described in the table below. AmerGen's nuclear
facilities are subject to the provisions and maximum assessment and recovery
limits of the Price -Anderson Act and NEIL similar to Generation's, as discussed
above within ITEM 1. Business - Generation, however the American Nuclear
Insurers Master Worker Program is not applicable to AmerGen as AmerGen purchased
its nuclear reactors after 1998.

25

The capacity factors for the AmerGen plants for 2000 and 2001 were 87%
and 88.5%, respectively. AmerGen operates these nuclear facilities; however,
Generation provides AmerGen with many services, including management services,
in connection with the operation and support of these facilities under a
Services Agreement dated March 1, 1999. In addition, Generation's chief nuclear
officer holds the same position at AmerGen. As part of the restructuring PECO
transferred its 50% interest in AmerGen to Generation in January 2001.

License Net
Expiration Generation
Station Year Acquired Location Date (1) Capacity (MW)
- ---------------------- ------------- -------------------- ----------- -------------

Clinton Nuclear Power
Station 1999 Clinton, IL 2026 933
Unit 1 of Three Mile
Island Nuclear Station 1999 Londonderry Twp., PA 2014 835
Oyster Creek Nuclear
Generation Facility 2000 Forked River, NJ 2009 630
-----
Total 2,398
=====

(1) AmerGen is reviewing the potential for license renewals for the Oyster Creek
Nuclear Generating Facility (Oyster Creek) and Unit 1 of Three Mile Island
(TMI-1).

As part of each acquisition of its nuclear facilities, AmerGen entered
into a power sales agreement with the seller. The agreement with Illinois Power
for Clinton Nuclear Power Station (Clinton) is for 75% of the output for a term
expiring at the end of 2004. The agreement with GPU, Inc. for TMI-1 and Oyster
Creek are for all of the output. Generation purchases the residual energy from
Clinton through December 31, 2002. The agreement for the output of Oyster Creek
expires on March 31, 2003. The original agreement for the output of TMI-1
expired in 2001. Exelon has agreed to purchase from AmerGen all the energy from
TMI after December 31, 2001 through December 31, 2014. AmerGen maintains a
decommissioning trust fund for each of its plants in accordance with NRC
regulations and believes that amounts in these trust funds, together with
investment earnings thereon, and additional contributions for Clinton from
Illinois Power will be sufficient to meet its decommissioning obligations.

Under its LLC Agreement, AmerGen is managed by or at the direction of a
management committee, which consists of six voting representatives, three of
whom are appointed by British Energy and three by Generation. In addition,
Generation appoints the chairman of the management committee. Action by the
management committee generally requires the affirmative vote of a majority of
members.

Generation may transfer its interest in AmerGen, as may British Energy,
subject to a right of first refusal of the other party and to the right of the
other party to require a third party buying the interest to also purchase the
other party's interest.

In February 2002, Generation entered into an agreement to loan AmerGen
up to $75 million at an interest rate of 1-month London Interbank Offering Rate
plus 2.25%. As of March 31, 2002, $46 million has been loaned to AmerGen. The
loan is due November 1, 2002.

Exelon has committed to provide AmerGen with capital contributions
equivalent to 50% of the purchase price of any acquisitions AmerGen makes in
2002.

ENTERPRISES

Enterprises consists primarily of the infrastructure services business
of InfraSource, Inc. (InfraSource), the energy services business of Exelon
Services, Inc., the competitive retail energy sales business of Exelon Energy,
the district cooling business of Exelon Thermal Technologies,

26

Inc.,
communications joint ventures and other investments weighted towards the
communications, energy services and retail services industries.

The results of InfraSource's infrastructure services business and
Exelon Services' energy services business are dependent on demand for outsourced
construction and maintenance services. That demand has been driven in the past
by the restructuring of the electric utility industry and growth of the
communications, cable and internet industries. Slowdown in that restructuring
and the current condition of the communications, cable and internet industries
means that results will be driven by efforts to manage costs and achieve
synergies.

InfraSource, formerly Exelon Infrastructure Services, Inc., provides
infrastructure services, including infrastructure construction, operation
management and maintenance services to owners of electric, gas, cable and
communications systems, including industrial and commercial customers, utilities
and municipalities, throughout the United States. Since it was established in
1997, InfraSource has acquired thirteen infrastructure service companies. In
2001, InfraSource had revenues of approximately $900 million and employed
approximately 8,200 at the end of 2001.

Exelon Services is engaged in the design, installation and servicing of
heating, ventilation and air conditioning facilities for commercial and
industrial customers. Exelon Services also provides energy-related services,
including performance contracting and energy management systems.

Exelon Energy provides retail electric and gas services as an
unregulated retail energy supplier in Illinois, Massachusetts, Michigan, New
Jersey, Ohio, Pennsylvania and other areas in the Midwest and Northeast United
States. Its retail energy sales business is dependent upon continued
deregulation of retail electric and gas markets and its ability to obtain
supplies of electricity and gas at competitive prices in the wholesale market.
The low margin nature of the business makes it important to achieve
concentrations of customers with higher volumes so as to manage costs.

Exelon Thermal Technologies provides district cooling and related
services to offices and other buildings in the central business district of
Chicago and in other cities in North America. District cooling involves the
production of chilled water at one or more central locations and its circulation
to customers' buildings, primarily for air conditioning.

Exelon Communications is the unit of Enterprises through which Exelon
manages its communications investments. Exelon Communications' principal
investment is PECOAdelphia Communications. PECOAdelphia is a competitive local
exchange carrier, providing local and long-distance, point-to-point voice and
data communications, internet access and enhanced data services for businesses
and institutions in eastern Pennsylvania. PECOAdelphia 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. PECOAdelphia is
a 50% owned joint venture with Adelphia Business Solutions.

On March 1, 2002, Exelon Communications announced an agreement to sell
its 49% interest in AT&T Wireless PCS of Philadelphia, LLC for $285 million in
cash. Proceeds from the transaction will be used for Exelon's general corporate
purposes.

Exelon Capital Partners was created in 1999 as a vehicle for direct
venture capital investing in the areas of unregulated energy sales, energy
services, utility infrastructure services,

27

e-commerce and communications. At
December 31, 2001, Exelon Capital Partners had made direct investments in eight
companies, with funding commitments totaling approximately $100 million. The
investment mix was weighted toward the communications industry, but also
included companies in energy services and retail services, including e-commerce.

EMPLOYEES

As of December 31, 2001, Exelon and its subsidiaries had approximately
29,200 employees, in the following companies:

ComEd 7,700
PECO 2,700
Generation 7,200
Enterprises 10,600
BSC 1,000
------
Total 29,200
======

Approximately 7,000 employees, including 4,900 employees of ComEd,
2,000 employees of Generation and 70 employees of BSC are covered by a
collective bargaining agreement with Local 15 of the International Brotherhood
of Electrical Workers (IBEW). Exelon and the IBEW Local 15 reached agreement on
a new Collective Bargaining Agreement (CBA) in April 2001. The new agreement had
an expiration date of March 31, 2004. An agreement to extend the date of the
contracts was ratified by the union on December 31, 2001. The new agreements run
through September 30, 2005, for Generation, and September 30, 2006 for ComEd and
BSC. The new agreements extend the existing CBA, create separate agreements for
the major business units and provide for a voluntary severance plan.

In addition, approximately 4,900 Enterprises employees are represented
by unions, including approximately 2,600 employees who are represented by
various local unions of the International Brotherhood of Electrical Workers. The
remaining union employees are members of a number of different local unions,
including laborers, welders, operators, plumbers and machinists.

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 PECO. In all cases, PECO
employees have rejected union representation. Exelon expects that such
petitions, related to segments of employees at PECO, Generation and Enterprises,
will continue to be filed in the future.

ENVIRONMENTAL REGULATION

GENERAL

Specific operations of Exelon, primarily those of Generation, are
subject to regulation regarding environmental matters by the United States and
by various states and local jurisdictions where Exelon operates its facilities.
The Illinois Pollution Control Board (IPCB) has jurisdiction over environmental
control in the State of Illinois, together with the Illinois Environmental
Protection Agency, which enforces regulations of the IPCB and issues permits in
connection with environmental control. The Pennsylvania Department of
Environmental Protection (PDEP) has jurisdiction over environmental control in
the Commonwealth of Pennsylvania. State regulation

28

includes the authority to
regulate air, water and noise emissions and solid waste disposals. The United
States Environmental Protection Agency (EPA) administers certain Federal
statutes relating to such matters as do various interstate and local agencies.

WATER

Under the Federal Clean Water Act, National Pollutant Discharge
Elimination System (NPDES) permits for discharges into waterways are required to
be obtained from the EPA or from the state environmental agency to which the
permit program has been delegated. Those permits must be renewed periodically.
Generation either has NPDES permits for all of its generating stations or has
pending applications for such permits. Generation is also subject to the
jurisdiction of certain other state and interstate agencies, including the
Delaware River Basin Commission and the Susquehanna River Basin Commission.

SOLID AND HAZARDOUS WASTE

The Comprehensive Environmental Response, Compensation, and Liability
Act of 1980, as amended (CERCLA), provides for immediate response and removal
actions coordinated by the EPA in the event of threatened releases of hazardous
substances into the environment and authorizes the U.S. Government either to
clean up sites at which hazardous substances have created actual or potential
environmental hazards or to order persons responsible for the situation to do
so. Under CERCLA, generators and transporters of hazardous substances, as well
as past and present owners and operators of hazardous waste sites, are strictly,
jointly and severally liable for the cleanup costs of waste at sites, most of
which are listed by the EPA on the National Priorities List (NPL). These
potentially responsible parties (PRPs) can be ordered to perform a cleanup, can
be sued for costs associated with a EPA-directed cleanup, may voluntarily settle
with the U.S. Government concerning their liability for cleanup costs, or may
voluntarily begin a site investigation and site remediation under state
oversight prior to listing on the NPL. Various states, including Illinois and
Pennsylvania, have enacted statutes that contain provisions substantially
similar to CERCLA. In addition, the Resource Conservation and Recovery Act
(RCRA) governs treatment, storage and disposal of solid and hazardous wastes and
cleanup of sites where such activities were conducted.

ComEd, PECO and Generation and their subsidiaries are or are likely to
become parties to proceedings initiated by the EPA, state agencies and/or other
responsible parties under CERCLA and RCRA with respect to a number of sites,
including manufactured gas plant (MGP) sites, or may undertake to investigate
and remediate sites for which they may be subject to enforcement actions by an
agency or third party.

By notice issued in November 1986, the EPA notified over 800 entities,
including ComEd and PECO, that they may be PRPs under CERCLA with respect to
releases of radioactive and/or toxic substances from the Maxey Flats disposal
site, a LLRW disposal site near Moorehead, Kentucky, where ComEd and PECO wastes
were deposited. A settlement was reached among the Federal and private PRPs,
including ComEd and PECO, 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 agreed to perform the initial
remedial work at the site and the Commonwealth of Kentucky agreed to assume
responsibility for long-range maintenance and final remediation of the site. 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

29

implementation of the remedial plan and work has commenced. As a result of
restructuring, ComEd's and PECO's liability and obligations arising from the
Maxey Flats site have been transferred to Generation. Exelon estimates that its
share of remediation costs will not be material.

By notice issued in December 1987, the EPA notified several entities,
including PECO, 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 PECO, 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 remedial
investigation and feasibility study as described in the work plan issued with
the Consent Order. PECO's share of the cost of study was approximately 30%. 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 estimated would cost approximately $17 million to implement. On June 26,
1998, the EPA issued an Order to the non-de minimis PRP group members, and
others, including the owner, to implement the remedial design (RD) and remedial
action (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, the EPA has modified the work
plan. On March 5, 2001, the PRP group submitted a revised RD to the EPA, in
which it estimates the cost to implement the RA to range from $14 million to $27
million. The EPA and the PRPs are also involved in litigation with the site
owner concerning remediation liability. PECO is unable to estimate its share of
the costs of the remedial activities.

MGP SITES

MGPs manufactured gas in Illinois and Pennsylvania from approximately
1850 to 1950. ComEd generally did not operate MGPs as a corporate entity but
did, however, acquire MGP sites as part of the absorption of smaller utilities.
Approximately half of these sites were transferred to Nicor Gas as part of a
general conveyance in 1954. ComEd also acquired former MGP sites as vacant real
estate on which ComEd facilities have been constructed. To date, ComEd has
identified 44 former MGP sites for which it may be liable for remediation.
Similarly, PECO has identified 28 sites where former MGP activities may have
resulted in site contamination. With respect to these sites, ComEd and PECO are
presently engaged in performing various levels of activities, 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. Overseeing
state regulatory agencies have approved the remediation of five MGP sites, while
39 other sites are currently under some degree of active study or remediation.
At December 31, 2001, Exelon had accrued $127 million for investigation and
remediation of these MGP sites that currently can be reasonably estimated.
Exelon believes that it could incur additional liabilities with respect to MGP
sites, which cannot be reasonably estimated at this time. Exelon has sued a
number of insurance carriers seeking indemnity/coverage for remediation costs
associated with these former MGP sites.

30

AIR

Air quality regulations promulgated by the EPA, the PDEP and the City
of Philadelphia in accordance with the Federal Clean Air Act and the Clean Air
Act Amendments of 1990 (Amendments) impose restrictions on emission of
particulates, sulfur dioxide (SO2), nitrogen oxides (NOx) and other pollutants
and require permits for operation of emission sources. Such permits have been
obtained by Exelon's subsidiaries 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 SO2
and NOx from electric power plants. Flue-gas desulfurization systems (scrubbers)
have been installed at all of Generation's coal-fired units other than the
Keystone Station. Keystone is subject to, and in compliance with, the Phase II
SO2 and NOx limits of the Amendments, which became effective January 1, 2000.
Generation and the other Keystone co-owners are purchasing SO2 emission
allowances to comply with the Phase II limits.

Generation has completed implementation of measures, including the
installation of NOx emissions controls and the imposition of certain operational
constraints, to comply with the Reasonably Available Control Technology
limitations of the Amendments. Generation expects that the cost of compliance
with anticipated air-quality regulations may be substantial due to further
limitations on permitted NOx emissions.

The EPA has issued two regulations to limit NOx emissions from power
plants in the eastern United States to address the "ozone transport" issue. The
first regulation was issued on September 24, 1998. The original NOx regulation
covered power plants in the 22 eastern states and had an effective date of May
1, 2003. As a result of litigation at the D.C. Circuit Court of Appeals, the
original NOx regulation was revised to cover 19 eastern states (rather than the
original 22) and the effective date was delayed by approximately one year to May
31, 2004. In most other respects, the original NOx regulation was substantively
upheld by the Court. Both Illinois and Pennsylvania power plants are covered by
the original NOx regulation. The second EPA regulation, referred to as the
"Section 126 Petition Regulation," was issued on May 25, 1999. This regulation
was issued by the EPA in response to downwind state (Connecticut, Maine,
Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, Vermont)
complaints under Section 126 of the Clean Air Act that upwind state NOx
emissions were negatively impacting downwind states' ability to attain the
Federal ozone standard. The Section 126 Petition Regulation requires
substantively the same NOx reduction requirement for the power generation sector
as the original NOx regulation. However, the Section 126 Petition Regulation
covers a more limited number of states (Delaware, Indiana, Kentucky, Maryland,
Michigan, North Carolina, New Jersey, New York, Ohio, Virginia and West
Virginia). It does not cover power plants in Illinois. The compliance date of
the Section 126 Petition Regulation, originally set for May 1, 2003, was tolled
by the D.C. Circuit Court of Appeals pending resolution of several issues.
Despite this delay, the northeast states covered by the Section 126 Petition
Regulation are still expected to comply with the original May 1, 2003 compliance
date. On September 23, 2000, Pennsylvania issued final state NOx reduction
regulations for power plants that satisfy both the original NOx regulation and
the Section 126 Petition Regulation. The Pennsylvania regulation is effective
May 1, 2003. Exelon is currently evaluating options to comply with the new
Pennsylvania regulations. These options include limiting the operation of the
Generation's fossil-fired units, require the purchase of NOx emission allowances
from the allowance market, the installation of additional control equipment, or
a combination of these alternatives.

31

Many other provisions of the Amendments affect activities of Exelon's
business, primarily Generation. 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.

Several other legislative and regulatory proposals regarding the
control of emissions of air pollutants from a variety of sources, including
utility units, are under active consideration. Exelon is unable at this time to
ascertain which proposals may take effect, what requirements they may contain,
or how they may affect Exelon's business. At this time, Exelon can provide no
assurance that these proposals if adopted will not have a significant effect on
Exelon's operations and costs.

COSTS

At December 31, 2001, Exelon accrued $156 million for various
environmental investigation and remediation costs that can be reasonably
estimated, including approximately $127 million for investigation and
remediation of former MGP sites as described above. Exelon 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 Exelon, environmental agencies or others or
whether all such costs will be recoverable through rates or from third parties.

Exelon's budget for capital requirements for 2002 for compliance with
environmental requirements total approximately $35 million. In addition, Exelon
may be required to make significant additional expenditures not presently
determinable.

OTHER SUBSIDIARIES OF COMED AND PECO WITH PUBLICLY HELD SECURITIES

ComEd Transitional Funding Trust (ComEd Funding Trust), a Delaware
business trust, was formed on October 28, 1998, pursuant to a trust agreement
among First Union Trust Company, National Association, as Delaware trustee, and
two individual trustees appointed by ComEd. ComEd Funding Trust was created for
the sole purpose of issuing transitional funding notes to securitize intangible
transition property granted to ComEd Funding LLC, a ComEd affiliate, by an ICC
order issued July 21, 1998. On December 16, 1998, ComEd Funding Trust issued
$3.4 billion of transitional funding notes, the proceeds of which were used to
purchase the intangible transition property held by ComEd Funding LLC. ComEd
Funding LLC transferred the proceeds to ComEd where they were used, among other
things, to repurchase outstanding debt and equity securities of ComEd. The
transitional funding notes are solely obligations of ComEd Funding Trust and are
secured by the intangible transition property, which represents the right to
receive instrument funding charges collected from ComEd's customers. The
instrument funding charges represent a nonbypassable, usage-based, per kWh
charge on designated consumers of electricity.

ComEd Financing I, a Delaware business trust, was formed by ComEd on
July 21, 1995. ComEd Financing I was created solely for the purpose of issuing
$200 million of trust preferred securities. The trust preferred

32

securities issued on September 26, 1995, carry an annual distribution rate of
8.48% and are mandatorily redeemable on September 30, 2035. The sole assets of
ComEd Financing I are $206.2 million principal amount of 8.48% subordinated
deferrable interest notes due September 30, 2035, issued by ComEd.

Similarly, ComEd Financing II, a Delaware business trust, was formed by
ComEd on November 20, 1996. ComEd Financing II was created solely for the
purpose of issuing $150 million of trust capital securities. The trust capital
securities were issued on January 24, 1997, carry an annual distribution rate of
8.50% and are mandatorily redeemable on January 15, 2027. The sole assets of
ComEd Financing II are $154.6 million principal amount of 8.50% subordinated
deferrable interest debentures due January 15, 2027, issued by ComEd.

PECO Energy Transition Trust (PETT), a Delaware business trust wholly
owned by PECO, was formed on June 23, 1998 pursuant to a trust agreement between
PECO, as grantor, First Union Trust Company, National Association, as issuer
trustee, and two beneficiary trustees appointed by PECO. PETT was created for
the sole purpose of issuing transition bonds to securitize a portion of PECO's
authorized stranded cost recovery. On March 25, 1999, PETT issued $4 billion of
its Series 1999-A Transition Bonds. On May 2, 2000, PETT issued $1 billion of
its Series 2000-A Transition Bonds and on March 1, 2001, PETT issued $805
million of its Series 2001-A Transition Bonds to refinance a portion of the
Series 1999-A Transition Bonds. The Transition Bonds are solely obligations of
PETT secured by intangible transition property, representing the right to
collect transition charges sufficient to pay the principal and interest on the
Transition Bonds, sold by PECO to PETT.

PECO Energy Capital Corp., a wholly owned subsidiary of PECO, 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 PECO and entering into similar financing
arrangements. The loans to PECO are evidenced by PECO'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, 2001, the Partnership held $128 million aggregate
principal amount of the Subordinated Debentures.

PECO Energy Capital Trust II (Trust II) was created in June 1997 as a
Delaware business trust 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 Trust II. As of December 31, 2001, Trust II had
outstanding 2,000,000 Trust II Receipts. At December 31, 2001, the assets of
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 2001 in the aggregate amount of $4 million.
Expenses of Trust II for 2001 were approximately $10,000, 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 Delaware business trust 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 Trust III. As of December 31, 2001, Trust III had outstanding
78,105 Trust III Receipts. At December 31, 2001, the assets of Trust III
consisted solely of 78,105 Series D Preferred Securities with an aggregate
stated liquidation preference of

33

$78 million. Distributions were made on Trust III Receipts during 2001 in the
aggregate amount of $5.8 million. Expenses of Trust III for 2001 were
approximately $10,000, all of which were paid by PECO Energy Capital Corp. The
Trust III Receipts are issued in book-entry only form.

EXECUTIVE OFFICERS OF THE REGISTRANTS AT DECEMBER 31, 2001

EXELON

Name Age Position
- -------------------------------------- --- ----------------------------------------------------------

McNeill, Jr., Corbin A. 62 Co-Chief Executive Officer and Chairman
(retiring as of April 23, 2002)
Rowe, John W. 56 Co-Chief Executive Officer and President
Kingsley Jr., Oliver D. 59 Executive Vice President
Strobel, Pamela B. 49 Executive Vice President
Clark, Frank M. 56 Senior Vice President
Gillis, Ruth Ann M. 47 Senior Vice President and Chief Financial Officer
Gilmore Jr., George H. 52 Senior Vice President
Lawrence, Kenneth G. 54 President and Chief Operating Officer, Energy Delivery
McLean, Ian P. 52 Senior Vice President
Mehrberg, Randall E. 46 Senior Vice President and General Counsel
Moler, Elizabeth A. 52 Senior Vice President, Government Affairs and Policy
Padron, Honorio J. 49 Senior Vice President
Snodgrass, S. Gary 50 Senior Vice President and Chief Human Resources Officer
Gibson, Jean 45 Vice President and Corporate Controller

34

ComEd

Name Age Position
- -------------------------------------- --- ----------------------------------------------------------------------------------

McNeill, Jr., Corbin A. 62 Co-Chief Executive Officer and Chairman, Exelon and Director, ComEd (retiring as
of April 23, 2002)
Rowe, John W. 56 Co-Chief Executive Officer and President, Exelon and Director, ComEd
Strobel, Pamela B. 49 Executive Vice President, Exelon and Chair, ComEd
Gillis, Ruth Ann M. 47 Senior Vice President, Finance and Chief Financial Officer, Exelon and Director,
ComEd
Lawrence, Kenneth G. 54 President and Chief Operating Officer, Energy Delivery and Director, ComEd
Clark, Frank M. 56 President, ComEd
Helwig, David R. 51 Executive Vice President, Operations, ComEd
Berdelle, Robert E. 45 Vice President, Finance and Chief Financial Officer, ComEd

PECO

Name Age Position
- -------------------------------------- --- ----------------------------------------------------------------------------------

McNeill, Jr., Corbin A. 62 Co-Chief Executive Officer and Chairman, Exelon and Director, PECO (retiring as
of April 23, 2002)
Rowe, John W. 56 Co-Chief Executive Officer and President, Exelon and Director, PECO
Strobel, Pamela B. 49 Executive Vice President, Exelon and Chair, PECO
Gillis, Ruth Ann M. 47 Senior Vice President and Chief Financial Officer, Exelon and Director, PECO
Lawrence, Kenneth G. 54 President, PECO
Frankowski, Frank F. 51 Vice President, Finance and Chief Financial Officer, PECO

Each of the above was elected as an executive officer effective October
20, 2000, the closing date of the merger, except for Randall E. Mehrberg, who
was elected effective December 1, 2000, Robert E. Berdelle, who was elected
effective October 11, 2001, Frank F. Frankowski, who was elected effective
October 22, 2001 and George H. Gilmore, Jr., who was elected effective December
3, 2001.

Each of the above executive officers holds such office at the
discretion of the respective 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 Co-Chief
Executive Officer of ComEd and President, Co-Chief Executive Officer and
Chairman of PECO; Chief Executive Officer of PECO; Chief Operating Officer and
Executive Vice President, Nuclear division of PECO.

Prior to his election to his current position, Mr. Rowe was President,
Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer of
PECO; Chairman, President and Chief Executive Officer of ComEd and Unicom; and
President and Chief Executive Officer of New England Electric System.

Prior to his election to his current position, Mr. Kingsley was
Executive Vice President of ComEd and Unicom, President and Chief Nuclear
Officer, Nuclear Generation Group of ComEd, and Chief Nuclear Officer of the
Tennessee Valley Authority.

Prior to her election to her current position, Ms. Strobel was Vice
Chairman of ComEd; Vice Chairman of PECO; Executive Vice President and General
Counsel of ComEd and Unicom; Senior Vice President and General Counsel of ComEd
and Unicom; and Vice President and General Counsel of ComEd.

Prior to his election to his current position, Mr. Clark was Senior
Vice President, Distribution Customer and Marketing Services and External
Affairs of ComEd; Senior Vice President of ComEd and Unicom; Vice President of
ComEd; Governmental Affairs Vice President; and Governmental Affairs Manager.

Prior to her election to her current position, Ms. Gillis was Senior
Vice President and Chief Financial Officer of ComEd and Unicom; Vice President
and Treasurer of ComEd and Unicom; Vice President, Chief Financial Officer and
Treasurer of the University of Chicago Hospitals and Health System; and Senior
Vice President and Chief Financial Officer of American National Bank and Trust
Company.

Prior to his election to his current position, Mr. Gilmore was Group
President for National Service Industries, Inc.; President and Chief Operating
Officer of Calmat Company; and President of Moore Document Solutions and Moore
Business Systems.

Prior to his election to his current position, Mr. Lawrence was Senior
Vice President, Distribution of PECO; Senior Vice President of PECO, President,
Distribution division, of PECO; Senior Vice President, Distribution division of
PECO; Senior Vice President, Finance and Chief Financial Officer of PECO; and
Vice President, Gas Operations division of PECO.

Prior to his election to his current position, Mr. McLean was President
of the Power Team division of PECO; and Group Vice President of Engelhard
Corporation.

35

Prior to his election to his current position, Mr. Mehrberg was an equity
partner with the law firm of Jenner & Block; and General Counsel and Lakefront
Director of the Chicago Park District.

Prior to her election to her current position, Ms. Moler was Senior Vice
President of ComEd and Unicom; Director of Unicom and ComEd; Partner at the law
firm of Vinson & Elkins, LLP; Deputy Secretary of the U.S. Department of
Energy; and Chair of the Federal Energy Regulatory Commission.

Prior to his election to his current position, Mr. Padron was Executive
Vice President Process Engineering and Chief Information Officer of CompUSA,
Inc.; Senior Vice President and Chief Information Officer of Pepsico Restaurant
Service Group; and Senior Vice President Business Engineering and Technology
and Chief Information Officer of Flagstar Corporation.

Prior to his election to his current position, Mr. Snodgrass was Senior
Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and
Vice President of USG Corporation.

Prior to her election to her current position, Ms. Gibson was Vice
President and Controller of PECO; and Director of Audit Services and Director
of the Tax Division of PECO.

Prior to his election to his current position, Mr. Helwig was Senior Vice
President, Operations of ComEd; Senior Vice President of ComEd; Vice President
of ComEd; General Manager of General Electric Company's Nuclear Services
Company; and Vice President at PECO.

Prior to his election to his current position, Mr. Berdelle was Vice
President and Comptroller of Unicom and ComEd; and Manager of Financial
Reporting of Unicom and ComEd.

Prior to his election to his current position of Vice President, Finance
and Chief Financial Officer of PECO Energy Company, Mr. Frankowski was
Controller of PECO Energy Company; Manager, Accounting and Control of PECO
Energy; and Director - Taxes of PECO Energy Company.

36

ITEM 2. PROPERTIES.

ENERGY DELIVERY

The electric substations and a portion of the transmission rights of
way of ComEd and PECO are owned in fee. A significant portion of the electric
transmission and distribution facilities is located over or under highways,
streets, other public places or property owned by others, for which permits,
grants, easements or licenses, deemed satisfactory by ComEd and PECO,
respectively, but without examination of underlying land titles, have been
obtained.

TRANSMISSION AND DISTRIBUTION

Exelon's higher voltage electric transmission and distribution lines
owned and in service are as follows:

Voltage (Volts) Circuit Miles
---------------- --------------

ComEd

765,000 90
345,000 2,590
138,000 2,110
PECO

500,000 891
220,000 1,634
132,000 15

ComEd's electric distribution system includes 40,633 pole-line miles of
overhead lines and 38,798 cable miles of underground lines. PECO's electric
distribution system includes 21,009 pole-line miles of overhead lines and 21,002
cable miles of underground lines.

GAS

The following table sets forth PECO's gas pipeline miles at December
31, 2001:

Pipeline Miles
---------------

Transmission 31
Distribution 6,199
Service piping 5,171
------
Total 11,401
======

PECO has a liquefied natural gas facility located in West Conshohocken,
Pennsylvania that has a storage capacity of 1,200,000 million cubic feet (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 25,000 mcf/day. In addition, PECO owns 28 natural gas city
gate stations at various locations throughout its gas service territory.

37

MORTGAGES

The principal plants and properties of ComEd are subject to the lien of
ComEd's Mortgage dated July 1, 1923, as amended and supplemented, under which
ComEd's first mortgage bonds are issued.

The principal plants and properties of PECO are subject to the lien of
PECO's Mortgage dated May 1, 1923, as amended and supplemented, under which
PECO's first mortgage bonds are issued.

38

GENERATION

The following table sets forth Generation's owned net electric generating
capacity by station at December 31, 2001:

No. of % Primary Dispatch Net Generation
Station Location Units Owned (1) Fuel Type Type Capacity(MW) (2)
- --------- -------- ------ ------- --------- -------- --------------

Nuclear (3)
Braidwood Braidwood, IL 2 Uranium Base-load 2,372
Byron Byron, IL 2 Uranium Base-load 2,391
Dresden Morris, IL 2 Uranium Base-load 1,659
LaSalle County Seneca, IL 2 Uranium Base-load 2,298
Limerick Limerick Twp., PA 2 Uranium Base-load 2,312
Peach Bottom Peach Bottom Twp., PA 2 50.00 Uranium Base-load 1,112 (4)
Quad Cities Cordova, IL 2 75.00 Uranium Base-load 1,172 (4)
Salem Hancock's Bridge, NJ 2 42.59 Uranium Base-load 934 (4)
-------
14,250

Fossil (Steam Turbines)
Cromby (1) Phoenixville, PA 1 Coal Base-load 144
Cromby (2) Phoenixville, PA 1 Oil/Gas Intermediate 201
Delaware Philadelphia, PA 2 Oil Peaking 250
Eddystone (1), (2) Eddystone, PA 2 Coal Base-load 581
Eddystone (3), (4) Eddystone, PA 2 Oil/Gas Intermediate 760
Schuylkill Philadelphia, PA 1 Oil Peaking 166
Conemaugh New Florence, PA 2 20.72 Coal Base-load 352 (4)
Keystone Shelocta, PA 2 20.99 Coal Base-load 357 (4)
Fairless Hills Falls Twp., PA 2 Landfill Gas Peaking 60
-------
2,871

Fossil (Combustion Turbines)
Chester Chester, PA 3 Oil Peaking 39
Croydon Bristol Twp., PA 8 Oil Peaking 380
Delaware Philadelphia, PA 4 Oil Peaking 56
Eddystone Eddystone, PA 4 Oil Peaking 60
Falls Falls Twp., PA 3 Oil Peaking 51
Moser Lower Pottsgrove Twp., PA 3 Oil Peaking 51
Pennsbury Falls Twp., PA 2 Landfill Gas Peaking 6
Richmond Philadelphia, PA 2 Oil Peaking 96
Schuylkill Philadelphia, PA 2 Oil Peaking 30
Southwark Philadelphia, PA 4 Oil Peaking 52
Salem Hancock's Bridge, NJ 1 42.59 Oil Peaking 16 (4)
LaPorte LaPorte, Tx 4 Gas Peaking 160
-------
997

Fossil (Internal Combustion/Diesel)
Cromby Phoenixville, PA 1 Oil Peaking 3
Delaware Philadelphia, PA 1 Oil Peaking 3
Schuylkill Philadelphia, PA 1 Oil Peaking 3
Conemaugh New Florence, PA 4 20.72 Oil Peaking 2 (4)
Keystone Shelocta, PA 4 20.99 Oil Peaking 2 (4)
-------
13

Hydroelectric
Conowingo Harford Co., MD 11 Hydro Base-load 512
Muddy Run Lancaster Co., PA 8 Hydro Intermediate 1,072
--- -------
1,584
-------
101 19,715
=== =======

(1) 100%, unless otherwise indicated.

(2) For nuclear stations, except Salem, capacity reflects the annual mean
rating. All other stations, including Salem, reflect a summer rating.

(3) All nuclear stations are boiling water reactors except Braidwood, Byron
and Salem, which are pressurized water reactors.

(4) Generation's portion.

39

The net generating capability available for operation at any time may
be less due to regulatory restrictions, fuel restrictions, efficiency of cooling
facilities and generating units being temporarily out of service for inspection,
maintenance, refueling, repairs or modifications required by regulatory
authorities.

Exelon and its subsidiaries maintain property insurance against loss or
damage to its principal plants and properties by fire or other perils, subject
to certain exceptions. For information regarding nuclear insurance, see ITEM 1.
Business - Generation. Exelon and its subsidiaries are 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 Exelon's consolidated financial
condition and results of operations.

ITEM 3. LEGAL PROCEEDINGS.

EXELON

During 1989 and 1991, actions were brought in Federal and state courts
in Colorado against ComEd and its subsidiary, Cotter Corporation (Cotter),
seeking unspecified damages and injunctive relief based on allegations that
Cotter permitted radioactive and other hazardous material to be released from
its mill into areas owned or occupied by the plaintiffs, resulting in property
damage and potential adverse health effects. In 1994, a Federal jury returned
nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989
cases, which verdicts were upheld on appeal. The remaining claims in the 1989
actions were settled or dismissed. In 1998, a jury verdict was rendered against
Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling
approximately $6 million in compensatory and punitive damages, interest and
medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the
jury verdict, and remanded the case for new trial. These plaintiffs' cases were
consolidated with the remaining 26 plaintiffs' cases, which had not been tried.
The consolidated trial was completed on June 28, 2001. The jury returned a
verdict against Cotter and awarded $16 million in various damages. On November
20, 2001, the District Court entered an amended final judgment which included an
award of both pre-judgment and post-judgment interests, costs, and medical
monitoring expenses which total $43 million. This matter is being appealed by
Cotter in the Tenth Circuit Court of Appeals. Cotter will vigorously contest the
award.

In November 2000, another trial involving a separate sub-group of 13
plaintiffs, seeking $19 million in damages plus interest was completed in
federal district court in Denver. The jury awarded nominal damages of $42,500 to
11 of 13 plaintiffs, but awarded no damages for any personal injury or health
claims, other than requiring Cotter to perform periodic medical monitoring at
minimal cost. The plaintiffs appealed the verdict to the Tenth Circuit Court of
Appeals.

On February 18, 2000, ComEd sold Cotter to an unaffiliated third party.
As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred
by Cotter as a result of these actions, as well as any liability arising in
connection with the West Lake Landfill discussed in the next paragraph. In
connection with the corporate restructuring, the responsibility to indemnify
Cotter for any liability related to these matters was transferred to Generation.
Generation's management believes adequate reserves have been established in
connection with these proceedings.

40

The United States Environmental Protection Agency (EPA) has advised
Cotter that it is potentially liable in connection with radiological
contamination at a site known as the West Lake Landfill in Missouri. Cotter is
alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700
tons of leached barium sulfate at the site. Cotter, along with three other
companies identified by the EPA as potentially responsible parties (PRPs), is
reviewing a draft feasibility study that recommends capping the site. The PRPs
are also engaged in discussions with the State of Missouri and the EPA. The
estimated costs of remediation for the site are $10 to $15 million. Once a final
feasibility study is complete and a remedy selected, it is expected that the
PRPs will agree on an allocation of responsibility for the costs. Until an
agreement is reached, Generation cannot predict its share of the costs.

PECO initiated tax appeals regarding two of its nuclear facilities,
Limerick Generating Station (Montgomery County) and Peach Bottom Atomic Power
Station (York County), and one of its fossil facilities, Eddystone (Delaware
County). The potential benefit or obligation resulting from these appeals was
transferred to Generation in connection with the corporate restructuring.
Generation is also involved in a tax appeal for TMI (Dauphin County) through
AmerGen. Generation does not believe the outcome of these matters will have a
material adverse effect on its results of operations or financial condition.

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 PECO in the United States District Court for the Middle District of
Louisiana arising out of PECO's termination of the contract to purchase Cajun's
interest in the River Bend nuclear power plant. Effective with the corporate
restructuring, Generation has agreed to assume any liability and obligation
arising from this litigation. During 2001, the parties reached a settlement of
the dispute, and Generation made a payment of $14 million to Cajun.

Generation is an unsecured creditor in Enron Corp.'s (Enron) bankruptcy
proceeding. Generation's claim for power and other products sold to Enron in
November and early December 2001 is $8.5 million. Enron may assert that
Generation should not have closed out and terminated all of its forward
contracts with Enron. If Enron is successful in this argument, Generation's
exposure could be greater than $8.5 million. Generation may also be subject to
exposure due to the credit policies of ISO-operated spot markets that allocate
defaults of market participants to non-defaulting participants. Generation has
established reserves for these matters.

(See the ComEd litigation section for additional Enron litigation matters.)

COMED

In March 1999, ComEd reached a settlement agreement with the City of
Chicago (Chicago) to end the arbitration proceeding between ComEd and Chicago
regarding the January 1, 1992 franchise agreement. As part of the settlement
agreement, ComEd and Chicago agreed to a revised combination of ongoing work
under the franchise agreement and new initiatives that total approximately $1
billion in defined transmission and distribution expenditures by ComEd to
improve electric services in Chicago, of which approximately $940 million has
been expended through December 31, 2001. The settlement agreement provides that
ComEd would be subject to liquidated damages if the projects are not completed
by various dates, unless it was prevented from doing so by events beyond its
reasonable control. In addition, ComEd and Chicago established an Energy
Reliability and Capacity Account, into which ComEd deposited $25 million during
each of the years 1999 through 2001 and has conditionally agreed to deposit $25
million at the end of 2002, to help ensure an adequate and reliable electric
supply for Chicago.

41

Three of ComEd's wholesale municipal customers filed a complaint and
request for refund with the FERC alleging that ComEd failed to properly adjust
its rates, as provided for under the terms of the electric service contracts
with the municipal customers and to track certain refunds made to ComEd's retail
customers in the years 1992 through 1994. In the third quarter of 1998, FERC
granted the complaint and directed that refunds be made, with interest. ComEd
filed a request for rehearing. On April 30, 2001, FERC issued an order granting
rehearing in which it determined that its 1998 order had been erroneous and that
no refunds were due from ComEd to the municipal customers. On June 29, 2001,
FERC denied the customers' requests for rehearing of the order granting
rehearing. In August 2001, each of the three wholesale municipal customers
appealed the April 30, 2001 FERC order to the Federal circuit court, which
consolidated the appeals for the purposes of briefing and decision. In November
2001, the court suspended briefing pending court-initiated settlement
discussions.

On April 18, 2001, the Godley Park District filed suit in Will County
Circuit Court against ComEd and Exelon alleging that oil spills at Braidwood
Station have contaminated the Park District's water supply. The complaint sought
actual damages, punitive damages of $100 million and statutory penalties. The
court dismissed all counts seeking punitive damages and statutory penalties, and
the plaintiff has filed an amended complaint before the court. ComEd is
contesting the liability and damages sought by the plaintiff.

In 1996, several developers of non-utility generating facilities filed
litigation against various Illinois officials claiming that the enforcement
against those facilities of an amendment to Illinois law removing the
entitlement of those facilities to state-subsidized payments for electricity
sold to ComEd after March 15, 1996 violated their rights under the Federal and
state constitutions. The developers also filed suit against ComEd for a
declaratory judgement that their rights under their contracts with ComEd were
not affected by the amendment. On August 4, 1999, the Illinois Appellate Court
held that the developers' claims against the state were premature, and the
Illinois Supreme Court denied leave to appeal that ruling. Developers of both
facilities have since filed amended complaints repeating their allegations that
ComEd breached the contracts in question and requesting damages for such breach,
in the amount of the difference between the state-subsidized rate and the amount
ComEd was willing to pay for the electricity. ComEd is contesting this matter.

In August 1999, three class action lawsuits were filed against ComEd,
and subsequently consolidated, in the Circuit Court of Cook County, Illinois
seeking damages for personal injuries, property damage and economic losses
related to a series of service interruptions that occurred in the summer of
1999. The combined effect of these interruptions resulted in over 168,000
customers losing service for more than four hours. Conditional class
certification was approved by the court for the sole purpose of exploring
settlement talks. ComEd filed a motion to dismiss the complaints. On April 24,
2001, the court dismissed four of the five counts of the consolidated complaint
without prejudice and the sole remaining count was dismissed in part. On June 1,
2001, the plaintiffs filed a second amended consolidated complaint and ComEd has
filed an answer. A portion of any settlement or verdict may be covered by
insurance; discussions with the carrier are ongoing. ComEd's management believes
adequate reserves have been established in connection with these cases.

As a result of Enron's bankruptcy proceeding, ComEd has potential
monetary exposure for customers served by Enron Energy Services (EES) as a
billing agent. On January 7, 2002, EES was authorized by the bankruptcy court
to, and subsequently did, reject its contract with 129 of ComEd's customer
accounts. As of March 15, 2002, EES was the billing agent for 97 of

42

ComEd's customer accounts. EES has advised Exelon that it will retain its
billing agency with these remaining accounts. ComEd is working to ensure that
customers know what amounts are owed to ComEd on 269 accounts on which EES has
been removed as billing agent, and has obtained updated billing addresses for
these accounts. With regard to the 97 remaining accounts, as of March 15, 2002,
ComEd's total amount outstanding is immaterial. Because that amount is owed to
ComEd by individual customers, it is not part of the bankrupt Enron's estate.
The ICC has rescinded EES's authority to act as an alternative retail energy
supplier in Illinois. However, EES never served as a supplier, as opposed to a
billing agent, to any of ComEd's retail accounts.

PECO

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

43

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

EXELON

The information required by this Item with respect to market
information relating to Exelon's common stock is incorporated herein by
reference to "Market for Registrant's Common Equity and Related Stockholder
Matters" in Exhibit 99-1 to Exelon's Current Report on Form 8-K dated February
28, 2002.

ComEd

As of March 1, 2002, there were outstanding 127,016,373 shares of
common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held
by Exelon. At March 1, 2002, in addition to Exelon, there were approximately 280
holders of ComEd common stock. There is no established market for shares of the
common stock of ComEd.

ComEd may not declare dividends on any shares of its capital stock in
the event that: (1) it exercises its right to extend the interest payment
periods on the subordinated debt securities which were issued to ComEd Financing
I and ComEd Financing II (the Financing Trusts); (2) it defaults on its
guarantee of the payment of distributions on the preferred trust securities of
the Financing Trusts; or (3) an event of default occurs under the Indenture
under which the subordinated debt securities are issued. See Item 1. Business -
Other Subsidiaries of ComEd and PECO with Publicly Held Securities.

PECO

As of March 1, 2002, there were outstanding 170,478,507 shares of
common stock, without par value, of PECO, all of which were held by Exelon.

PECO's Articles of Incorporation prohibit payment of any dividend on,
or other distribution to the holders of, common stock if, after giving effect
thereto, the capital of PECO represented by its common stock together with its
retained earnings is, in the aggregate, less than the involuntary liquidating
value of its then outstanding preferred stock. At December 31, 2001, such
capital ($2.2 billion) amounted to about 14 times the liquidating value of the
outstanding preferred stock ($156 million).

PECO may not declare dividends on any shares of its capital stock in
the event that: (1) PECO exercises its right to extend the interest payment
periods on the Subordinated Debentures which were issued to the Partnership; (2)
PECO 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.
See Item 1. Business - Other Subsidiaries of ComEd and PECO with Publicly Held
Securities.

DIVIDENDS

Under PUHCA and the Federal Power Act, Exelon, ComEd, PECO and
Generation can only pay dividends from retained or current earnings. Similar
restrictions also apply to ComEd

44

under the Illinois Public Utilities Act. An SEC order issued under PUHCA
granted permission to Exelon and ComEd to pay up to $500 million in dividends
out of additional paid-in capital, provided that Exelon agreed not to pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total capitalization. At December 31, 2001, Exelon had
retained earnings of $1.2 billion, which includes ComEd retained earnings of
$257 million, PECO retained earnings of $270 million and Generation retained
earnings of $471 million.

The following table sets forth Exelon's quarterly cash dividends paid
during 2001 and 2000:

2001 2000
---------------------------------------- ----------------------------------------
1st 2nd 3rd 4th 1st 2nd 3rd 4th
(per share) Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- ----------- ------- ------- ------- ------- -------- -------- ------- -------

Exelon $ 0.55 (1) $ 0.42 $ 0.42 $ 0.43 $ 0.25 $ 0.25 $ 0.25 $ 0.16
------- ------- ------- -------- -------- ------- ------- -------

(1) Exelon did not pay any cash dividends in 2000. The first quarter dividend in
2001 was a pro rata dividend. Unicom and PECO each paid their shareholders pro
rata, per diem dividends from their last regular dividend dates through October
19, 2000. The first quarter of 2001 covered the 119-day period from the date of
the Merger, through the February 15, 2001 record date.

The following table sets forth ComEd and PECO's quarterly common dividend
payments:

2001 2000
---------------------------------------- ----------------------------------------
1st 2nd 3rd 4th 1st 2nd 3rd 4th
(in millions) Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- ------------- -------- ------- ------- ------- ------- ------- ------- -------

ComEd $ 63 $ 85 $ 105 $ 230 $ 87 $ 75 $ 74 $ 90
PECO $ 45 $ 55 $ 69 $ 173 $ 45 $ 43 $ 43 $ 26
-------- ------- ------- ------- ------- ------- ------- -------

On January 29, 2002, the Board of Directors of Exelon declared a
quarterly dividend of $0.44 per share of Exelon's common stock. This increase of
$0.07 per share annually will result in an annual dividend rate of $1.76 per
share. The new dividend rate reflects Exelon's vertically integrated business
portfolio and its focus on total return to shareholders. The new dividend rate
represents about a 50% payout of the expected 2002 earnings per share from
Exelon's regulated electricity delivery businesses. Exelon intends to grow the
dividend to about a 60% payout of earnings from regulated operations based on
cash flow and earnings growth prospects for Energy Delivery. The payment of
future dividends is subject to approval and declaration by the Board of
Directors each quarter.

ITEM 6. SELECTED FINANCIAL DATA.

EXELON

The information required by this Item is incorporated herein by
reference to "Selected Financial Data" in Exhibit 99-1 to Exelon's Current
Report on Form 8-K dated February 28, 2002.

45

COMED

The selected consolidated financial data presented below has been
derived from the audited financial statements of ComEd. This data is qualified
in its entirety by reference to, and should be read in conjunction with ComEd's
Consolidated Financial Statements and Management's Discussion and Analysis of
Financial Condition and Results of Operations included herein.

The information for the year ended 2000 is presented for the periods
before and after the Merger. For additional information, see ITEM 8. Financial
Statements and Supplementary Data - ComEd, Notes 1 and 3 of the Notes to
Consolidated Financial Statements.

Jan. 1 - Oct. 20 - Jan. 1 -
Dec. 31 Dec. 31 Oct. 19 For the Years Ended December 31,
--------------------------------
(in millions) 2001 2000 2000 1999 1998 1997
- ------------- ------ ------ ------ ------- ------- -------

STATEMENT OF INCOME DATA:

Operating Revenues $ 6,206 $ 1,310 $ 5,702 $ 6,793 $ 7,150 $ 7,076
Operating Income 1,594 338 1,048 1,549 1,387 1,214
Income (Loss) before
Extraordinary Items
And Cumulative Effect
of a Change in
Accounting Principle 607 133 603 651 594 (160)
Extraordinary Item
(net of income taxes) -- -- (4) (28) -- (810)
Cumulative Effect of a
Change in
Accounting Principle
(net of income taxes) -- -- -- -- -- 196
Net Income (Loss)
on Common Stock 607 133 596 599 537 (834)

at December 31,
------------------------------------------------
(in millions) 2001 2000 1999 1998 1997
- ------------- ------- ------ ------- ------- -------
BALANCE SHEET DATA:

Current Assets $ 1,114 $ 2,172 $ 4,045 $ 4,974 $ 1,745
Property, Plant and Equipment, net 7,351 7,657 11,993 13,300 16,622
Deferred Debits and Other Assets 7,251 10,369 6,538 6,583 3,397
------- ------- ------- ------- -------
Total Assets $15,716 $20,198 $22,576 $24,857 $21,764
======= ======= ======= ======= =======
Current Liabilities $ 1,886 $ 1,723 $ 3,427 $ 3,309 $ 2,223
Long-Term Debt 5,850 6,882 6,962 7,677 5,563
Deferred Credits and Other Liabilities 2,568 5,082 6,456 7,770 8,050
Mandatorily Redeemable Preference Stock -- -- 69 171 205
Company-Obligated Mandatorily Redeemable
Preferred Securities of Subsidiary Trusts
Holding the Company's Subordinated Debt
Securities 329 328 350 350 350
Shareholders' Equity 5,083 6,183 5,312 5,580 5,373
------- ------- ------- ------- -------
Total Liabilities and Shareholders' Equity $15,716 $20,198 $22,576 $24,857 $21,764
======= ======= ======= ======= =======

46

PECO

The selected consolidated financial data presented below has been
derived from the audited financial statements of PECO. This data is qualified in
its entirety by reference to, and should be read in conjunction with PECO's
Consolidated Financial Statements and Management's Discussion and Analysis of
Financial Condition and Results of Operations included herein.

For the Years Ended December 31,
----------------------------------------------------
(in millions) 2001 2000 1999 1998 1997
- ------------- -------- ------- ------- ------- --------

STATEMENT OF INCOME DATA:
Operating Revenues $ 3,965 $ 5,950 $ 5,478 $ 5,325 $ 4,601
Operating Income 999 1,222 1,373 1,268 1,006
Income before Extraordinary Items
and Cumulative Effect of a Change in
Accounting Principle 425 487 619 533 337
Extraordinary Items (net of income taxes) -- (4) (37) (20) (1,834)
Cumulative Effect of a Change in
Accounting Principle (net of income taxes) -- 24 -- -- --
Net Income (Loss) on Common Stock 415 497 570 500 (1,514)

at December 31,
--------------------------------------------------
(in millions) 2001 2000 1999 1998 1997
- ------------- -------- ------- ------- ------- --------

BALANCE SHEET DATA:
Current Assets $ 820 $ 1,779 $ 1,221 $ 582 $ 1,003
Property, Plant and Equipment, net 4,047 5,158 5,004 4,804 4,671
Deferred Debits and Other Assets 5,878 7,839 6,862 6,662 6,683
------- ------- ------- ------- --------
Total Assets $10,745 $14,776 $13,087 $12,048 $12,357
======= ======= ======= ======= =======
Current Liabilities $ 1,342 $ 2,974 $ 1,286 $ 1,735 $ 1,619
Long-Term Debt 5,438 6,002 5,969 2,920 3,853
Deferred Credits and Other Liabilities 3,358 3,860 3,738 3,756 3,576
Company-Obligated Mandatorily
Redeemable Preferred Securities 128 128 128 349 352
Mandatorily Redeemable Preferred Stock 19 37 56 93 93
Shareholders' Equity 460 1,775 1,910 3,195 2,864
------- ------- ------- ------- -------
Total Liabilities and Shareholders' Equity $10,745 $14,776 $13,087 $12,048 $12,357
======= ======= ======= ======= ========

47

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

EXELON

The information required by this Item is incorporated herein by
reference to "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Exhibit 99-2 to Exelon's Current Report on Form 8-K
dated February 28, 2002.

COMED

GENERAL

On October 20, 2000, ComEd became a 99.9% owned subsidiary of Exelon as
a result of the transactions relating to the Merger. As a result of the Merger,
ComEd's consolidated financial information for the period after the Merger has a
different cost basis than that of previous periods. Material variances caused by
the different cost basis have been disclosed where applicable.

Through December 31, 2000, ComEd operated as a vertically integrated
electric utility. During January 2001, Exelon undertook a restructuring to
separate its generation and other competitive businesses from its regulated
energy delivery business. As part of the restructuring, the non-regulated
operations and related assets and liabilities of ComEd were transferred to
separate subsidiaries of Exelon. As a result, beginning January 2001, the
operations of ComEd consist of its retail electricity distribution and
transmission business in northern Illinois. The restructuring has had a
significant impact on all components of ComEd's results of operations. The
estimated impact of the restructuring set forth herein reflects the effects of
removing the operations related to ComEd's nuclear generating stations and
obtaining energy and capacity from Generation under the terms of the PPA for the
year ended December 31, 2000.

48

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

SUMMARY FINANCIAL INFORMATION - COMED

Components of Variance
------------------------------------
Restructuring Normal
(in millions) 2001 2000 Impact Operations Total
- -------------------------------------- ------- ------- -------------- ---------- -------

Operating Revenues $ 6,206 $ 7,012 $ (707) $ (99) $ (806)
Fuel and Purchased Power 2,670 1,977 677 16 693
Operating and Maintenance 981 2,076 (1,072) (23) (1,095)
Merger-Related Costs -- 67 -- (67) (67)
Depreciation and Amortization 665 998 (282) (51) (333)
Taxes Other Than Income 296 508 (131) (81) (212)
------- ------- ------- ------- -------
Total Operating Expenses 4,612 5,626 (808) (206) (1,014)
------- ------- ------- ------- -------
Operating Income 1,594 1,386 101 107 208
------- ------- ------- ------- -------
Interest Expense (565) (596) 43 (12) 31
Distributions on Company-Obligated
Mandatorily Redeemable
Preferred Securities of Subsidiary
Trusts Holding Solely the Company's
Subordinated Debt Securities (30) (30) -- -- --
Other, Net 114 308 -- (194) (194)
------- ------- ------- ------- -------
Income Before Income Taxes and
Extraordinary Items 1,113 1,068 144 (99) 45
Income Taxes 506 332 72 102 174
------- ------- ------- ------- -------
Net Income Before Extraordinary Items 607 736 72 (201) (129)
Extraordinary Items (net of income taxes) -- (4) -- 4 4
Net Income 607 732 72 (197) (125)
Preferred and Preference Stock Dividends -- (3) -- 3 3
------- ------- ------- ------- -------
Net Income on Common Stock $ 607 $ 729 $ 72 $ (194) $ (122)
======= ======= ======= ======= =======

NET INCOME

Net income from normal operations decreased $197 million, or 25% in
2001. Net income was impacted by $107 million in increased operating income
offset by a higher effective tax rate and a $194 million decrease in other
income and deductions primarily attributable to a gain on the forward share
purchase arrangement recognized during 2000 and a reduction in intercompany
interest income in 2001 as compared to 2000.

49

OPERATING REVENUES

Bundled service reflects deliveries to customers taking electric
service under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and distribution of the energy. Unbundled service
reflects customers electing to receive electric generation service from the PPO
or an ARES. Revenue from customers choosing the PPO includes an energy charge at
market rates, transmission and distribution charges and a CTC charge. Revenue
from customers choosing an ARES includes a distribution charge and a CTC charge.
Transmission charges received from ARES are included in wholesale and
miscellaneous revenue. ComEd's electric sales statistics are as follows:

Retail Deliveries - (in megawatthours (MWh)) 2001 2000 Variance
---------- ---------- ----------

BUNDLED DELIVERIES

Residential 25,281,880 23,997,261 1,284,619
Small Commercial & Industrial 23,435,141 24,832,551 (1,397,410)
Large Commercial & Industrial 10,305,130 15,348,098 (5,042,968)
Public Authorities & Electric Railroads 7,879,260 7,664,309 214,951
---------- ---------- ----------
66,901,411 71,842,219 (4,940,808)
========== ========== ==========
UNBUNDLED DELIVERIES
Small Commercial & Industrial - PPO 3,279,491 1,433,337 1,846,154
- ARES 2,865,423 2,772,316 93,107
Large Commercial & Industrial - PPO 5,749,995 2,812,524 2,937,471
- ARES 5,457,847 5,806,535 (348,688)
Public Authorities & Electric Railroads - PPO 986,756 1,087,524 (100,768)
- ARES 364,998 297,048 67,950
---------- ---------- ----------
18,704,510 14,209,284 4,495,226
---------- ---------- ----------
TOTAL RETAIL DELIVERIES 85,605,921 86,051,503 (445,582)
========== ========== ==========

Electric Revenue (in millions) 2001 2000 Variance
---------- ---------- ----------
BUNDLED REVENUE

Residential $ 2,308 $ 2,235 $ 73
Small Commercial & Industrial 1,821 1,949 (128)
Large Commercial & Industrial 523 811 (288)
Public Authorities & Electric Railroads 430 424 6
---------- ---------- ----------
5,082 5,419 (337)
---------- ---------- ----------
UNBUNDLED REVENUE

Small Commercial & Industrial- PPO 220 92 128
- ARES 48 62 (14)
Large Commercial & Industrial - PPO 343 158 185
- ARES 74 115 (41)
Public Authorities & Electric Railroads - PPO 59 56 3
- ARES 5 7 (2)
---------- ---------- ----------
749 490 259
---------- ---------- ----------
TOTAL ELECTRIC RETAIL REVENUES $ 5,831 $ 5,909 $ (78)
Wholesale and Miscellaneous Revenue 375 396 (a) (21)
---------- ---------- ----------
TOTAL ELECTRIC REVENUE $ 6,206 $ 6,305 $ (99)
========== ========== ==========

(a) Includes the operations of ComEd as if the restructuring had occurred
on January 1, 2000.

50

The changes in electric retail revenues for 2001, as compared to 2000, are
attributable to the following:

- ------------------------------- ---------- ------------ ------------
Electric Revenues (in millions) 2001 2000 Variance
- ------------------------------- ---------- ------------ ------------

BUNDLED REVENUE

Residential $ 1,028 $ 1,113 $ (85)
Small Commercial & Industrial 682 422 260
Large Commercial & Industrial 929 532 397
Public Authorities & Electric Railroads 72 47 25
------------ ------------ ------------
2,711 2,114 597
------------ ------------ ------------
UNBUNDLED REVENUE

Residential 235 135 100
Small Commercial & Industrial 81 154 (73)
Large Commercial & Industrial 64 180 (116)
Public Authorities & Electric Railroads 1 11 (10)
------------ ------------ ------------
381 480 (99)
------------ ------------ ------------
TOTAL ELECTRIC RETAIL REVENUES 3,092 2,594 498
Wholesale and Miscellaneous Revenue 219 247 (28)
------------ ------------ ------------
TOTAL ELECTRIC REVENUE $ 3,311 $ 2,841 $ 470
============ ============ ============

66

The changes in electric retail revenues for 2001, as compared to 2000,
are as follows:

(in millions) Variance
- ------------- --------

Customer Choice $ 276
Rate Changes 241
Weather (5)
Other Effects (14)
-----
Retail Revenue $ 498
=====

Customer Choice. All PECO customers have choice to purchase energy from
other suppliers. This choice generally does not impact kWh deliveries, but
reduces revenue collected from customers because they are not obtaining
generation supply from PECO. Customers who are served by an alternate supplier
continue to pay competitive transition charges.

As of December 31, 2001, the customer load served by alternate
suppliers was 1,003 MWh or 13.0% as compared to the same prior year period of
2,631 MW or 34.9%. For the year ended December 31, 2001, the percent of MWh
sold by PECO increased by 17.2% to 79.8% of total retail deliveries as compared
to 62.6% in 2000. This reduction in the customer load and the percentage of MWh
served by alternate suppliers, primarily resulted from small and large
commercial and industrial customers selecting or returning to PECO as their
electric generation supplier.

As of December 31, 2001, the number of customers served by alternate
suppliers was 371,500 or 24.4% as compared to December 31, 2000 of 269,395 or
18.0%. The increase from the prior year is primarily a result of the Competitive
Default Service (CDS) agreements for residential customers with the New Power
Company and Green Mountain Energy Company. As of December 31, 2001, there were
227,349 residential customers assigned to these generation providers as part of
the agreement. As of December 31, 2001, the customer load served by a alternate
suppliers was 1,003 MWh or 13.0% as compared to the same prior year period of
2,631 MWh or 34.9%.

Rate Changes. The increase in revenues attributable to rate changes
reflects the expiration of a 6% reduction in PECO's electric rates in effect for
2000, partially offset by a $60 million rate reduction in effect for 2001.

Weather. The demand for electricity and gas services is impacted by
weather conditions. Very warm weather in summer months and very cold weather in
other months is referred to as "favorable weather conditions", because these
weather conditions result in increased demand for electricity. Conversely, mild
weather reduces demand. The weather impact was unfavorable compared to the prior
year as a result of warmer winter weather partially offset by warmer summer
weather. Cooling degree days increased 34% in 2001 compared to 2000 while
heating degree days decreased 12% in 2001 compared to 2000.

Other Effects. Other items affecting revenue during 2001 include:

o Volume. Exclusive of weather impacts, lower delivery volume affected PECO's
revenue by $21 million compared to 2000. Total kWh sales to retail
customers decreased 1% compared to 2000, primarily as a result of less
favorable economic conditions in 2001 offset by customer growth. Large
commercial and industrial sales decreased 2% and residential sales
decreased 1%. These were partially offset by an increase in small
commercial and industrial sales of 2%.

o Other. The payment of $29 million to Generation related to nuclear
decommissioning cost recovery under an agreement effective September 2001
partially offset by an $11 million settlement of competitive transition
charges by a large customer.

67

PECO's gas sales statistics are as follows:

2001 2000 Variance
------ ------ --------

Deliveries in million cubic feet (mmcf) 81,528 91,686 (10,158)
Revenue (in millions) $ 654 $ 532 $ 122
------- ------- --------

The changes in gas revenue for 2001, as compared to 2000, are as
follows:

(in millions) Variance
- ------------ --------

Price $ 174
Weather (38)
Volume (14)
-----
Gas Revenue $ 122
=====

o Price. The favorable variance in price is attributable to an adjustment of
the purchased gas cost recovery by the PUC effective in December 2000. The
average price per million cubic feet for all customers for 2001 was 38%
higher than in 2000. PECO's gas rates are subject to periodic adjustments
by the PUC designed to recover or refund the difference between actual cost
of purchased gas and the amount included in base rates and to recover or
refund increases or decreases in certain state taxes not recovered in base
rates.

o Weather. The unfavorable weather impact is attributable to warmer
temperatures in the non-summer months of 2001 than in 2000 in the PECO
service territory. Heating degree days decreased 12% in 2001 compared to
2000.

o Volume. Exclusive of weather impacts, lower delivery volume affected
revenue by $14 million compared to 2000. Total mmcf sales to retail
customers decreased 11% compared to 2000, primarily as a result of slower
economic conditions in 2001 offset by increased customer growth.

FUEL AND PURCHASED POWER EXPENSE

Fuel and purchased power expense for 2001 increased $468 million, or
35%, as compared to the same 2000 period, excluding the effects of the
restructuring. The increase in fuel and purchased power expense was primarily
attributable to $293 million from customers in Pennsylvania selecting or
returning to PECO as their electric generation supplier, $174 million from
increased prices related to gas and higher PJM ancillary charges of $31 million.
These increases were partially offset by $24 million as a result of unfavorable
weather conditions and $14 million attributable to lower delivery volume related
to gas.

OPERATING AND MAINTENANCE EXPENSE

O&M expense for 2001 increased $95 million, or 19%, as compared to the
same 2000 period, excluding the effects of the restructuring. The increase in
O&M expense was primarily attributable to $20 million related to an increased
allocation of corporate expense, $18 million related to additional employee
severance costs in 2001, $17 million as a result of higher administrative and
general costs for functions previously performed at Corporate, $14 million
related to the deployment of the automated meters during 2001, $12 million of
incremental costs related to two storms in 2001, $9 million related to
additional uncollectible accounts expense and $5 million associated with the
write-off of excess and obsolete inventory.

MERGER-RELATED COSTS

Merger-related costs charged to income in 2000 were $248 million
consisting of $132 million of direct incremental costs and $116 million for
employee costs. Direct incremental costs represent expenses associated with
completing the Merger, including professional fees, regulatory

68

approval and settlement costs, and settlement of compensation arrangements.
Employee costs represent estimated severance payments and pension and
postretirement benefits provided under Exelon's MSP for 642 eligible PECO
employees who are expected to be involuntarily terminated before December 2002
upon completion of integration activities for the merged companies.
Merger-related costs attributable to the operations transferred to Generation,
Enterprises and BSC in the corporate restructuring were $181 million. The
remaining $67 million is attributable to PECO's energy delivery segment. See
Item 8. Financial Statements and Supplementary Data - PECO - Note 2 to
Consolidated Financial Statements.

DEPRECIATION AND AMORTIZATION EXPENSE

Depreciation and amortization expense for 2001 increased $233 million,
or 127%, as compared to the same 2000 period, excluding the effects of the
restructuring. The increase was primarily attributable to $214 million of
additional amortization of PECO's CTC and an increase of $19 million related to
depreciation expense associated with additional plant in service. The additional
amortization of the CTC is in accordance with PECO's original settlement under
the Pennsylvania Competition Act.

TAXES OTHER THAN INCOME

Taxes other than income for 2001 decreased $5 million, or 3%, as
compared to the same 2000 period, excluding the effects of the restructuring.
The decrease was primarily attributable to the elimination of the gross receipts
tax on gas sales effective July 1, 2000.

INTEREST CHARGES

Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership
(COMRPS). Interest charges increased $6 million, or 1% in 2001. The increase was
primarily attributable to additional interest on the Transition Bonds issued to
securitize PECO's stranded cost recovery of $16 million and interest expense
related to a loan from an affiliate in 2001 of $8 million, partially offset by
the reduction of PECO's long-term debt with the proceeds from Transition Bonds,
which reduced interest charges by $18 million.

EQUITY IN EARNINGS (LOSSES) OF UNCONSOLIDATED AFFILIATES

As part of the corporate restructuring, PECO's unconsolidated
affiliates were transferred to Generation and Enterprises.

OTHER INCOME AND DEDUCTIONS

Other income and deductions excluding interest charges and equity in
earnings (losses) of unconsolidated affiliates increased $24 million, or 109% in
2001 as compared to 2000, excluding the effects of the restructuring. The
increase in other income and deductions was primarily attributable to
intercompany interest income of $10 million in the third quarter of 2001, a gain
on the settlement of an interest rate swap of $6 million and the favorable
settlement of a customer contract of $3 million.

INCOME TAXES

The effective tax rate was 31.7% in 2001 as compared to 35.7% in 2000.
The decrease in the effective tax rate was primarily attributable to tax
benefits associated with the implementation of State tax planning Strategies, a
favorable adjustment to prior period income taxes in connection with the
completion of the 2000 tax return and the reduced impact of investment tax
credit amortization.

69

EXTRAORDINARY ITEMS

In 2000, PECO incurred extraordinary charges aggregating $6 million ($4
million, net of tax) related to prepayment premiums and the write-off of
unamortized deferred financing costs associated with the early retirement of
debt with a portion of the proceeds from the securitization of PECO's stranded
cost recovery in May 2000.

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

In 2000, PECO recorded a benefit of $40 million ($24 million, net of
tax) representing the cumulative effect of a change in accounting method for
nuclear outage costs in conjunction with the synchronization of accounting
policies in connection with the Merger.

PREFERRED STOCK DIVIDENDS

Preferred stock dividends for 2001 were consistent as compared to 2000.

70

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

SUMMARY FINANCIAL INFORMATION - PECO

(in millions) 2000 1999 Variance
- ------------- ------- ------- --------

Operating Revenues $5,950 $5,478 $ 472

Fuel and Purchased Power 2,127 2,152 (25)
Operating and Maintenance 1,791 1,454 337
Merger-Related Costs 248 -- 248
Depreciation and Amortization 325 237 88
Taxes Other Than Income 237 262 (25)
------ ------ -----
Total Operating Expenses 4,728 4,105 623
------ ------ -----
Operating Income 1,222 1,373 (151)
------ ------ -----
Interest Expense (457) (396) (61)
Distributions on Company-Obligated
Mandatorily Redeemable
Preferred Securities of a Partnership,
which holds Solely Subordinated
Debentures of the Company (8) (21) 13
Equity in Earnings (Losses) of
Unconsolidated Affiliates, Net (41) (38) (3)
Other, Net 41 59 (18)
------ ------ -----
Income Before Income Taxes, Extraordinary Item
and Cumulative Effect of a Change of
Accounting Principle 757 977 (220)
Income Taxes 270 358 (88)
------ ------ -----
Net Income Before Extraordinary Item and
Cumulative Effect of Changes of
Accounting Principles 487 619 (132)
Extraordinary Item (net of income taxes) (4) (37) 33
Cumulative Effect of Changes
of Accounting Principles 24 -- 24
------ ------ -----
Net Income 507 582 (75)
Preferred Stock Dividends (10) (12) 2
------ ------ -----
Net Income on Common Stock $ 497 $ 570 $ (73)
====== ====== =====

NET INCOME

Net income decreased $75 million, or 13% in 2000, as compared to 1999
reflecting merger related expenses and amortization of CTCs in 2000.

71

OPERATING REVENUES

(in millions, except percentage data) 2000 1999 $ Variance % Variance
- ------------------------------------- ------ ------ ---------- ---------

Energy Delivery $3,373 $3,265 $ 108 3.3%
Generation 1,931 2,097 (166) (7.9)%
Enterprises 646 116 530 456.9%
------ ------ -----
$5,950 $5,478 $ 472 8.6%
====== ====== ====== ---------

Energy Delivery. The increase in operating revenue from energy delivery
was attributable to higher electric revenue of $32 million and additional gas
revenue of $76 million. The increase in electric revenue reflects $102 million
from customers in Pennsylvania selecting PECO as their electric generation
supplier and rate adjustments in Pennsylvania, partially offset by a decrease of
$69 million as a result of lower summer volume. Regulated gas revenue reflected
increases of $44 million related to higher prices, $29 million attributable to
increased volume from new and existing customers and $24 million from increased
winter volume. These increases were partially offset by $21 million of lower
gross receipts tax collections as a result of the repeal of the gross receipts
tax on gas sales in connection with gas restructuring in Pennsylvania.

Generation. The decrease in operating revenue from generation was a
result of lower electric revenue of $180 million partially offset by higher gas
revenue of $14 million. The decrease in electric revenue was principally
attributable to lower sales of competitive retail electric generation services
of $132 million, of which $196 million represented decreased volume that was
partially offset by $64 million from higher prices. In addition, the termination
of the management agreement for Clinton resulted in lower revenues of $99
million. As a result of the acquisition by AmerGen of Clinton in December 1999,
the management agreement was terminated and, accordingly, the operations have
been included in Equity in Earnings (Losses) of Unconsolidated Affiliates on
PECO's Consolidated Statements of Income in 2000. These decreases were partially
offset by an increase of $50 million from higher wholesale revenue attributable
to $199 million associated with higher prices partially offset by $149 million
related to lower volume. Unregulated gas revenue increased primarily as a result
of $11 million from wholesale sales of excess natural gas.

Enterprises. The increase in operating revenue from enterprises was
attributable to $530 million from the acquisition of thirteen infrastructure
services companies during 2000 and 1999.

FUEL AND PURCHASED POWER EXPENSE

(in millions, except percentage data) 2000 1999 $ Variance % Variance
- ------------------------------------- ------ ------ ---------- ---------

Energy Delivery $ 462 $ 370 $ 92 24.9%
Generation 1,665 1,782 (117) (6.6)%
------ ------ -----
$ 2,127 $ 2,152 $ (25) (1.2)%
====== ====== ===== ---------

Energy Delivery. The increase in fuel and purchased power expense from
energy delivery was primarily attributable to $73 million from additional volume
and increased prices related to gas, $13 million as a result of favorable
weather conditions and $4 million in additional PJM ancillary charges.

72

Generation. The decrease in fuel and purchased power expense from
generation was primarily attributable to $262 million principally related to
reduced sales of competitive retail electric generation services partially
offset by an increase of $120 million in the cost to supply energy delivery
customers and an increase of $5 million from wholesale operations principally
related to $97 million as a result of increased prices partially offset by $92
million as a result of decreased volume.

OPERATING AND MAINTENANCE EXPENSE

(in millions, except percentage data) 2000 1999 $ Variance % Variance
- ------------------------------------- ------- ------- ---------- ----------

Energy Delivery $ 491 $ 434 $ 57 13.1%
Generation 616 721 (105) (14.6)%
Enterprises 650 136 514 377.9%
Corporate 34 163 (129) (79.1)%
------ ------ ------
$1,791 $1,454 $ 337 23.2%
====== ====== ====== -------

Energy Delivery. The increase in O&M expense from energy delivery was
primarily attributable to the direct charging to the business segments of O&M
expenses that were previously reported at PECO Corporate.

Generation. The decrease in O&M expense from generation was primarily
attributable to O&M expenses related to the management agreement for Clinton of
$70 million in 1999 which has since been terminated, $15 million related to the
abandonment of two information system implementations in 1999, $17 million
related to lower administrative and general expenses related to the unregulated
retail sales of electricity and $15 million related to lower joint-owner
expenses.

Enterprises. The O&M expense from enterprises increased $505 million
from the infrastructure services business as a result of acquisitions.

Corporate. PECO Corporate's decrease in O&M expense was primarily
attributable to expenses of $56 million related to lower Year 2000 remediation
expenditures, lower pension and postretirement benefits expense of $31 million
and the direct charging to business segments of O&M expenses that were
previously recorded at Corporate.

MERGER-RELATED COSTS

Merger-related costs charged to income in 2000 were $248 million
consisting of $132 million of direct incremental costs and $116 million for
employee costs. Direct incremental costs represent expenses associated with
completing the Merger, including professional fees, regulatory approval and
settlement costs, and settlement of compensation arrangements. Employee costs
represent estimated severance payments and pension and postretirement benefits
provided under Exelon's MSP for 642 eligible PECO employees who are expected to
be involuntarily terminated before December 2002 upon completion of integration
activities for the merged companies.

DEPRECIATION AND AMORTIZATION EXPENSE

Depreciation and amortization expense increased $88 million, or 37%, to
$325 million in 2000. The increase was primarily attributable to $57 million of
amortization of PECO's CTC which commenced in 2000 and $29 million related to
depreciation and amortization expense associated with the infrastructure
services business acquisitions.

73

TAXES OTHER THAN INCOME

Taxes other than income decreased $25 million, or 10%, to $237 million
in 2000. The decrease was primarily attributable to lower real estate taxes of
$18 million relating to a change in tax laws for utility property in
Pennsylvania and $11 million as a result of the elimination of the gross
receipts tax on natural gas sales net of an increase in gross receipts tax on
electric sales. This decrease was partially offset by a non-recurring $22
million capital stock tax credit related to a 1999 adjustment associated with
the impact of PECO's 1997 restructuring charge.

INTEREST CHARGES

Interest charges consist of interest expense and distributions on
COMRPS. Interest charges increased $48 million, or 12%, to $465 million in 2000.
The increase was primarily attributable to interest on the Transition Bonds
issued to securitize PECO's stranded cost recovery of $104 million, partially
offset by the reduction of PECO's long-term debt with the proceeds from
Transition Bonds, which reduced interest charges by $77 million.

EQUITY IN EARNINGS (LOSSES) OF UNCONSOLIDATED AFFILIATES

Equity in earnings (losses) of unconsolidated affiliates decreased $3
million, or 8%, to losses of $41 million in 2000 as compared to losses of $38
million in 1999. The decrease was primarily attributable to $8 million of
additional losses from communications joint ventures, partially offset by $4
million of earnings from AmerGen as a result of the acquisitions of Clinton and
TMI in December 1999 and Oyster Creek in September 2000.

OTHER INCOME AND DEDUCTIONS

Other income and deductions excluding interest charges and equity in
earnings (losses) of unconsolidated affiliates decreased $18 million, or 31%, to
$41 million in 2000 as compared to $59 million in 1999. The decrease in other
income and deductions was primarily attributable to the writedown of a
communications investment of $33 million, a $10 million gain on the disposal of
assets in 1999 and a decrease in interest income of $2 million. These decreases
were partially offset by a $15 million write-off in 1999 of the investment in a
cogeneration facility in connection with the settlement of litigation and gains
on sales of investments of $13 million.

INCOME TAXES

The effective tax rate was 35.7% in 2000 as compared to 36.6% in 1999.

EXTRAORDINARY ITEMS

In 2000, PECO incurred extraordinary charges aggregating $6 million ($4
million, net of tax) related to prepayment premiums and the write-off of
unamortized deferred financing costs associated with the early retirement of
debt with a portion of the proceeds from the securitization of PECO's stranded
cost recovery in May 2000.

In 1999, PECO 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 and refinancing of debt.

74

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

In 2000, PECO recorded a benefit of $40 million ($24 million, net of
tax) representing the cumulative effect of a change in accounting method for
nuclear outage costs in conjunction with the synchronization of accounting
policies in connection with the Merger.

PREFERRED STOCK DIVIDENDS

Preferred stock dividends decreased $2 million, or 17%, to $10 million
as compared 1999. The decrease was attributable to the redemption of $37 million
of Mandatorily Redeemable Preferred Stock in August 1999 with a portion of the
proceeds from the issuance of Transition Bonds. In addition, PECO redeemed $19
million of Mandatorily Redeemable Preferred Stock in August 2000.

LIQUIDITY AND CAPITAL RESOURCES

PECO's capital resources are primarily provided by internally generated
cash flows from operations and, to the extent necessary, external financing
including the issuance of commercial paper. PECO's access to external financing
at reasonable terms is dependent on its credit ratings and the general business
condition of PECO and the industry. PECO's business is capital intensive.
Capital resources are used primarily to fund PECO's capital requirements,
including construction, repayments of maturing debt and preferred securities and
payment of common stock dividends to Exelon.

CASH FLOWS FROM OPERATING ACTIVITIES

Cash flows provided by operations for 2001 were $828 million. PECO's
cash flow from operating activities primarily results from sales of electricity
and gas to a stable and diverse base of retail customers at fixed prices. PECO's
future cash flows will depend upon the ability to achieve cost savings in
operations, and the impact of the economy, weather and customer choice on its
revenues. Although the amounts may vary from period to period as a result of the
uncertainties inherent in its business, PECO expects that it will continue to
provide a reliable and steady source of internal cash flow from operations for
the foreseeable future.

CASH FLOWS FROM INVESTING ACTIVITIES

Cash flows used in investing activities for 2001 were $235 million,
primarily for capital expenditures of $264 million. PECO's projected capital
expenditures for 2002 are $279 million.

Approximately one half of the budgeted 2002 expenditures are for
capital additions to support customer and load growth and the remainder for
additions to or upgrades of existing facilities. PECO anticipates that it will
obtain financing, when necessary, through borrowings, the issuance of preferred
securities, or capital contributions from Exelon. PECO's proposed capital
expenditures and other investments are subject to periodic review and revision
to reflect changes in economic conditions and other factors.

CASH FLOWS FROM FINANCING ACTIVITIES

Cash flows used in financing activities were $579 million in 2001
primarily attributable to debt service and payments of dividends to Exelon. Debt
financing activities during 2001 included the refinancing of $805 million in
PECO transition bonds. In 2001, PECO paid Exelon $342 million in common stock
dividends and currently expects that the 2002 dividend will be comparable to
2001.

75

CREDIT ISSUES

PECO meets its short-term liquidity requirements primarily through the
issuance of commercial paper, borrowings under bank credit facilities and
borrowings from the Exelon intercompany money pool. PECO, along with Exelon,
ComEd and Generation, are parties to a $1.5 billion unsecured revolving credit
facility with a group of banks. This credit facility is used principally by PECO
to support its commercial paper program. PECO has a $300 million sublimit under
this credit facility.

At December 31, 2001, PECO had outstanding $101 million of notes
payable consisting principally of commercial paper. For 2001, the average
interest rate on notes payable was approximately 2.25%. Certain of the credit
agreements to which PECO is a party requires PECO to maintain a debt to total
capitalization ratio of 65% or less, excluding securitization debt and excluding
the receivable from parent recorded in PECO's shareholders' equity. At December
31, 2001, the debt to total capitalization ratios on that basis for PECO was
38%.

PECO's access to the capital markets, including the commercial paper
market, and its financing costs in those markets are dependent on its securities
ratings. None of PECO's borrowings are subject to default or prepayment as a
result of a downgrading of securities ratings although such a downgrading could
increase interest charges under PECO's bank credit facility. PECO from time to
time enters into interest rate swap and other derivatives that require the
maintenance of investment grade ratings. Failure to maintain investment grade
ratings would allow the counterparty to terminate the derivative and settle the
transaction on a net present value basis.

Under PUHCA and the Federal Power Act, PECO can pay dividends only from
retained or current earnings. At December 31, 2001, PECO had retained earnings
of $270 million.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

PECO's contractual obligations as of December 31, 2001 representing
cash obligations that are considered to be firm commitments are as follows:

Payment due within Due after
----------------------------- ---------
(in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years
- ------------- ------ ------ --------- --------- -------

Long-Term Debt $5,992 $ 548 $1,008 $1,003 $3,433
Short-Term Debt 101 101 -- -- --
COMRPS and Preferred
Stock with Mandatory
Redemption Requirements 147 19 -- -- 128
Operating Leases 13 2 4 4 3
------ ------ ------ ------ ------
Total Contractual Obligations $6,253 $ 670 $1,012 $1,007 $3,564
====== ====== ====== ====== ======

See ITEM 8. Financial Statements and Supplementary Data - PECO, Notes
to Consolidated Financial Statements for additional information about:
o long-term debt see Note 11
o short-term debt see Note 10
o operating leases see Note 18
o COMRPS and Preferred Stock with Mandatory Redemption Requirements see
Notes 15 and 14, respectively.

76

PECO's commercial commitments as of December 31, 2001 representing
commitments triggered by future events, including obligations to make payment on
behalf of other parties as well as financing arrangements to secure obligations
of PECO, are as follows:

Expiration within After
---------------------------- -------
(in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years
- ------------- ----- ------ --------- --------- -------

Available Lines of Credit (a) $300 $300 $-- $-- $--
Letters of Credit (non-debt) (b) 11 11 -- -- --
Letters of Credit (Long-Term Debt) (c) 17 -- 17 -- --
Insured Long-Term Debt (d) 154 -- 154 -- --
Guarantees (e) 100 -- -- -- 100
---- ---- ---- --- ----
Total Commercial Commitments $582 $311 $171 $-- $100
==== ==== ==== === ====

(a) Lines of Credit - PECO, along with Exelon, ComEd and Generation, maintain a
$1.5 billion 364-day credit facility to support commercial paper issuances.
PECO has a $300 million sublimit under the credit facility. At December 31,
2001, there are no borrowings against the credit facility.

(b) Letters of Credit (non-debt) - PECO and certain of its subsidiaries
maintain non-debt letters of credit to provide credit support for certain
transactions as requested by third parties.

(c) Letters of Credit (Long-Term Debt) - Direct-pay letters of credit issued in
connection with variable-rate debt in order to provide liquidity in the
event that it is not possible to remarket all of the debt as required
following specific events, including changes in the basis of determining
the interest rate on the debt.

(d) Insured Long-Term Debt - Borrowings that have been credit-enhanced through
the purchase of insurance coverage equal to the amount of principal
outstanding plus interest.

(e) Guarantees - Provide support for lines of credit, performance contracts,
surety bonds and leases as required by third parties.

OFF BALANCE SHEET OBLIGATIONS

PECO 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 $225 million of designated accounts receivable until November
2005. At December 31, 2001, PECO had sold a $225 million interest in accounts
receivable, consisting of a $170 million interest in accounts receivable which
PECO accounted for as a sale under SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities - a Replacement
of FASB Statement No. 125," and a $55 million interest in special-agreement
accounts receivable which was accounted for as a long-term note payable. See
ITEM 8. Financial Statements and Supplementary Data - PECO, Note 14 of Notes to
Consolidated Financial Statements. PECO retains the servicing responsibility for
these receivables. The agreement requires PECO to maintain the $225 million
interest, which, if not met, requires PECO to deposit cash in order to satisfy
such requirements. At December 31, 2001 and 2000, PECO met this requirement and
was not required to make any cash deposits.

OTHER FACTORS

PECO participates in defined benefit pension plans and postretirement
welfare sponsored by Exelon. Essentially all PECO employees are eligible to
participate in these plans. In 2001, PECO's former plans were consolidated into
the Exelon plans. Essentially all PECO employees, hired on or after January 1,
2001 are eligible to participate in newly established Exelon cash balance
pension plans. Employees who were active participants in the former PECO pension
plans on December 31, 2000 and remain employed by PECO on January 1, 2002, will
have the opportunity to continue to participate in the pension plan or to
transfer to the cash balance plan. Participants in the cash balance plan, unlike
participants in the other defined benefit plans, may request a lump-sum cash
payment upon employee termination which may result in increased cash
requirements from pension plan assets. PECO may be required to increase future
funding to the pension plan as a result of these increased cash requirements.

77

Due to the performance of the United States debt and equity markets in
2001, the value of assets held in trusts to satisfy the obligations of pension
and postretirement benefit plans has decreased. Also, as a result of the Merger
and corporate restructuring, there was a larger than average number of employees
taking advantage of retirement benefits in 2001. These factors may also result
in additional future funding requirements of the pension and postretirement
benefit plans.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
The following areas represent those that management believes are particularly
important to the financial statements and that require the use of estimates and
assumptions to describe matters that are inherently uncertain:

REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent incurred costs that have been deferred
because they are probable of future recovery in customer rates. Regulatory
liabilities represent previous collections from customers to fund costs which
have not yet been incurred.

PECO is currently subject to a rate freeze that limits the opportunity
to recover increased costs and the costs of new investment in facilities through
rates during the rate freeze period. Current rates include the recovery of
PECO's existing regulatory assets. PECO continually assesses whether the
regulatory assets are probable of future recovery by considering factors such as
applicable regulatory environment changes, recent rate orders to other regulated
entities in the same jurisdiction, and the status of any pending or potential
deregulation legislation. If future recovery of costs ceases to be probable the
assets would be required to be recognized in current period earnings.

UNBILLED ENERGY REVENUES

Revenues related to the sale of energy are generally recorded when
service is rendered or energy is delivered to customers. However, the
determination of the energy sales to individual customers is based on the
reading of their meters which are read on a systematic basis throughout the
month. At the end of each month, amounts of energy delivered to customers since
the date of the last meter reading are estimated and the corresponding unbilled
revenue is estimated. This unbilled revenue is estimated each month based on
daily generation volumes, estimated customer usage by class, line losses and
applicable customer rates based on regression analyses reflecting significant
historical trends and experience. Customer accounts receivable as of December
31, 2001 include unbilled energy revenues of $100 million on a base of annual
revenues of $4.0 billion.

78

ACCOUNTING FOR DERIVATIVE INSTRUMENTS

PECO utilizes derivatives to manage its exposure to fluctuation in
interest rates related to outstanding variable rate debt instruments and planned
future debt issuances as well as exposure to changes in the fair value of
outstanding debt that is planned for early retirement. Derivative financial
instruments are accounted for under SFAS No. 133. Hedge accounting has been used
for all interest rate derivatives to date based on the probability of the
transaction and the expected highly effective nature of the hedging relationship
between the interest rate swap contract and the interest payment or changes in
fair value of the hedged debt. Dealer quotes are available for all of PECO's
interest rate swap agreement derivatives. Accounting for derivatives continues
to evolve through guidance issued by the DIG of the FASB. To the extent that
changes by the DIG modify current guidance, including the normal purchases and
normal sales determination, the accounting treatment for derivatives may change.

ENVIRONMENTAL COSTS

As of December 31, 2001 PECO had accrued liabilities of $37 million for
environmental investigation and remediation costs. The liabilities are based
upon estimates with respect to the number of sites for which PECO will be
responsible, the scope and cost of work to be performed at each site, the
portion of costs that will be shared with other parties and the timing of the
remediation work. Where timing and amounts of expenditures can be reliably
estimated, amounts are discounted. Where timing and amounts cannot be reliably
estimated, a range is estimated and the low end of the range is recognized on an
undiscounted basis. Estimates can be affected by factors including future
changes in technology, changes in regulations or requirements of local
governmental authorities and actual costs of disposal.

OUTLOOK

GENERAL

PECO believes that it will provide a significant and steady source of
earnings. PECO's primary goals are to deliver reliable service, to improve
customer service and to sustain productive regulatory relationships. Achieving
these goals is expected to maximize the value of PECO's assets.

Under restructuring regulations adopted at the Federal and state
levels, the role of electric utilities in the supply and delivery of energy is
changing. PECO continues to be obligated to provide reliable delivery systems
under cost-based rates. It remains obligated, as a provider of last resort, to
supply generation service during the transition period to a competitive supply
marketplace to customers who do not or cannot choose an alternate supplier.
Retail competition for generation services has resulted in reduced revenues from
regulated rates and the sale of increasing amounts of energy at market-based
rates.

PECO's revenues will be affected by rate reductions and rate freezes
currently in effect. The rate freezes limit PECO's ability to recover increased
expenses and the costs of investments in new transmission and distribution
facilities through rates. As a result, PECO's future results of operations will
be dependent on its ability:

o to deliver electricity and gas to its customers cost-effectively,

o to realize cost savings and synergies from the Merger to offset increased
costs on new investments and inflation while its delivery rates are capped
and,

o to manage its provider of last resort responsibilities.

79

PECO's results will be affected by annual increases in amortization of
its stranded cost recovery through 2010. PECO has been authorized to recover
stranded costs of $5.3 billion ($4.9 billion of unamortized costs at December
31, 2001) over a twelve-year period ending December 31, 2010 with a return on
the unamortized balance of 10.75%. In 2001, revenue attributable to stranded
cost recovery was $797 million and is scheduled to increase to $932 million by
2010, the final year of stranded cost recovery. Amortization of PECO's stranded
cost recovery, which is a regulatory asset, is included in depreciation and
amortization. The amortization expense for 2001 was $271 million and will
increase to $879 million by 2010.

All of PECO's retail customers have the right to choose their
electricity suppliers. At December 31, 2001, approximately 28% of PECO's
residential load, 6% of its small commercial and industrial load and 5% of its
large commercial and industrial load were purchasing generation service from an
alternate supplier.

PECO has entered into a long-term agreement with Generation to procure
its power needs and achieve some certainty during the next several years with
respect to these obligations. Because PECO's agreement with Generation allows it
to obtain sufficient power at the rates it is allowed to charge to serve
customers who do not choose alternate generation suppliers revenues and expenses
may vary with customer choice, but income will not be significantly impacted.

Transmission. PECO provides wholesale transmission service under rates
established by FERC. FERC has used its regulation of transmission to encourage
competition for wholesale generation services and the development of regional
structures to facilitate regional wholesale markets. In December 1999, FERC
issued Order 2000 requiring jurisdictional utilities to file a proposal to form
an RTO or, alternatively, to describe efforts to participate in or work toward
participating in an RTO or explain why they were not participating in an RTO.
Order 2000 is generally designed to separate the governance and operation of the
transmission system from generation companies and other market participants.

PECO provides regional transmission service pursuant to a regional
open-access transmission tariff filed by it and the other transmission owners
who are members of 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 ISO for PJM (PJM ISO) and is
responsible for operation of the PJM control area and administration of the PJM
open-access transmission tariff. PECO and the other transmission owners in PJM
have turned over control of their transmission facilities to the PJM ISO. The
PJM ISO and the transmission owners who are members of PJM, including PECO, have
filed with FERC for approval of PJM as an RTO. FERC has conditionally approved
the PJM RTO.

OTHER FACTORS

Inflation affects PECO through increased operating costs and increased
capital costs for electric plant. As a result of the rate caps imposed under the
legislation in Pennsylvania and price pressures due to competition, PECO may not
be able to pass the costs of inflation through to customers.

PECO participates in defined benefit pension plans and postretirement
welfare sponsored by Exelon. Essentially all PECO employees are eligible to
participate in these plans. In 2001, PECO's former plans were consolidated into
the Exelon plans. PECO's costs of providing pension and postretirement benefits
to its retirees is dependent upon a number of factors, such as

80

the discount rate, rates of return on plan assets, and the assumed rate of
increase in health care costs. Although PECO's pension and postretirement
expense is determined using three-year averaging and is not as vulnerable to a
single year's change in rates, these costs are expected to increase in 2002 and
beyond as the result of the above noted plan changes along with the affects of
the decline in market value of plan assets, changes in appropriate assumed rates
of return on plan assets and discount rates, and increases in health care costs.
For a discussion of PECO's pension and postretirement benefit plans, see Item 8.
Financial Statements and Supplementary Data - PECO - Note 13 of the Notes to
Consolidated Financial Statements.

Environmental. PECO'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, PECO is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by PECO and of property contaminated by hazardous
substances generated by PECO. PECO 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 that are considered hazardous
under environmental laws. PECO has identified 28 sites where former MGP
activities have or may have resulted in actual site contamination. PECO 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.

As of December 31, 2001 and 2000, PECO had accrued $37 million and $54
million, respectively, for environmental investigation and remediation costs,
including $27 million and $30 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. In conjunction with the
corporate restructuring in January 2001, a portion of the environmental
investigation and remediation costs were transferred to Generation. PECO expects
to expend $2 million for environmental remediation activities in 2002. PECO
cannot predict whether it will incur other significant liabilities for any
additional investigation and remediation costs at these or additional sites
identified by PECO, environmental agencies or others, or whether such costs will
be recoverable from third parties.

Security Issues and Other Impacts of Terrorist Actions. The events of
September 11, 2001 have affected PECO's operating procedures and costs and are
expected to affect the cost and availability of the insurance coverages that
PECO carries. PECO has initiated security measures to safeguard its employees
and critical operations and is actively participating in industry initiatives to
identify methods to maintain the reliability of its delivery systems. It is
expected that governmental authorities will be working to ensure that emergency
plans are in place and that critical infrastructure vulnerabilities are
addressed. The electric utility industry is proposing security guidelines rather
than government mandated standards to protect critical infrastructures. It is
not known if Federal standards will be issued to the electric or gas industries.
PECO is evaluating enhanced security measures at certain critical locations,
enhanced response and recovery plans and assessing longer term design changes
and redundancy measures. These measures will involve additional expense to
develop and implement.

PECO carries property damage and liability insurance for its properties
and operations. As a result of significant changes in the insurance marketplace,
due in part to the September 11, 2001 terrorist acts, the available coverage and
limits may be less than the amount of insurance obtained in the past, and the
recovery for losses due to terrorists acts may be limited.

PECO is self-insured to the extent that any losses may exceed the
amount of insurance maintained. Damage to PECO's properties could disrupt the
transmission or distribution

81

electricity and significantly and adversely affect results of operations. PECO
cannot predict the effects on operations of the availability of property damage
and liability coverage or any disruptions to its delivery facilities.

NEW ACCOUNTING PRONOUNCEMENTS

In 2001, the FASB issued SFAS No. 141, SFAS No. 142, SFAS No. 143 and
SFAS No. 144.

SFAS No. 141 requires that all business combinations be accounted for
under the purchase method of accounting and establishes criteria for the
separate recognition of intangible assets acquired in business combinations.
SFAS No. 141 is effective for business combinations initiated after June 30,
2001.

SFAS No. 142 establishes new accounting and reporting standards for
goodwill and intangible assets. SFAS No. 142 is effective as of January 1, 2002.
Under SFAS No. 142, effective January 1, 2002, goodwill recorded is no longer
subject to amortization. After January 1, 2002, goodwill will be subject to an
assessment for impairment using a two-step fair value based test, the first step
of which must be performed at least annually, or more frequently if events or
circumstances indicate that goodwill might be impaired. The first step compares
the fair value of a reporting unit to its carrying amount, including goodwill.
If the carrying amount of the reporting unit exceeds its fair value, the second
step is performed. The second step compares the carrying amount of the goodwill
to the fair value of the goodwill. If the fair value of goodwill is less than
the carrying amount, an impairment loss would be reported as a reduction to
goodwill and a charge to operating expense, except at the transition date, when
the loss would be reflected as a cumulative effect of a change in accounting
principle. As of December 31, 2001, PECO does not have any Goodwill reflected on
its Consolidated Balance Sheets and does not expect the effect of adopting SFAS
No. 142 to materially affect the results of operations. As a result of the
corporate restructuring in January 2001, all of PECO's goodwill was transferred
to Enterprises.

SFAS No. 143 provides accounting requirements for retirement
obligations associated with tangible long-lived assets. PECO expects to adopt
SFAS No. 143 on January 1, 2003. Retirement obligations associated with
long-lived assets included within the scope of SFAS No. 143 are those for which
there is a legal obligation to settle under existing or enacted law, statute,
written or oral contract or by legal construction under the doctrine of
promissory estoppel. PECO is currently in the process of evaluating the impact
of SFAS No. 143 on its financial statements.

SFAS No. 144 establishes accounting and reporting standards for both
the impairment and disposal of long-lived assets. This statement is effective
for fiscal years beginning after December 15, 2001 and provisions of this
statement are generally applied prospectively. PECO is in the process of
evaluating the impact of SFAS No. 144 on its financial statements, and does not
expect the impact to be material.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

EXELON

The information required by this Item is incorporated herein by
reference to the information appearing under the subheading "Quantitative and
Qualitative Disclosures About

82

Market Risk" under "Management's Discussion and Analysis of Financial Condition
and Results of Operations" in Exhibit 99-2 to Exelon's Current Report on Form
8-K dated February 28, 2002.

COMED

ComEd is exposed to market risks associated with credit, interest
rates and commodity price. The inherent risk in market sensitive instruments and
positions is the potential loss arising from adverse changes in commodity
prices, counterparty credit, and interest rates. Exelon's corporate Risk
Management Committee (RMC) sets forth risk management philosophy and objectives
for Exelon and its subsidiaries through a corporate policy, and establishes
procedures for risk assessment, control and valuation, counterparty credit
approval, and the monitoring and reporting of derivative activity and risk
exposures. The RMC is chaired by Exelon's chief risk officer and includes the
chief financial officer, general counsel, treasurer, vice president of corporate
planning and officers from each of the business units. The RMC reports to the
board of directors on the scope of ComEd's derivative activities.

CREDIT RISK

ComEd is obligated to provide service to all electric customers within
its franchised territories, and, as a result, has a broad customer base. For the
year ended December 31, 2001, ComEd's ten largest customers represented
approximately 3% of its retail electric revenues. ComEd manages credit risk
using credit and collection policies which are regulated by the ICC.

INTEREST RATE RISK

ComEd 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. ComEd also utilizes
forward-starting interest rate swaps and treasury rate locks to lock in interest
rate levels in anticipation of future financing. These strategies are employed
to maintain the lowest cost of capital. As of December 31, 2001, a hypothetical
10% increase in the interest rates associated with variable rate debt would
result in a $1 million decrease in pre-tax earnings for 2002.

ComEd has entered into an interest rate swap to manage interest rate
exposure associated with a $235 million fixed-rate obligation. In December 2001,
ComEd entered into forward-starting interest rate swaps, with an aggregate
notional amount of $250 million in anticipation of the issuance of debt in the
first quarter of 2002. At December 31, 2001, these interest rate swaps had an
aggregate fair market value exposure of $1 million based on the present value
difference between the contract and market rates at December 31, 2001.

The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point decrease in the spot yield at
December 31, 2001 is estimated to be $7 million. If these derivative instruments
had been terminated at December 31, 2001, this estimated fair value represents
the amount that would be paid by ComEd to the counterparties.

The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point increase in the spot yield at
December 31, 2001 is estimated to be $4 million. If these derivative instruments
had been terminated at December 31, 2001, this estimated fair value represents
the amount to be paid by the counterparties to ComEd.

83

In March 2002, ComEd settled the $250 million of forward-starting
interest rate swaps and paid $6 million to the counterparty. ComEd also entered
into forward-starting interest rate swaps with an aggregate notional amount of
$175 million in anticipation of the issuance of debt in the second half of 2002.

COMMODITY PRICE RISK

As part of the corporate restructuring, ComEd entered into a PPA with
Generation to meet its retail customer obligations at fixed prices. ComEd's
principal exposure to commodity price risk is in relation to revenues collected
from customers who elect the power purchase option at market-based prices, and
CTC revenues which are calculated to provide the customer with a credit for the
market price for electricity. ComEd has performed a sensitivity analysis to
determine the net impact of a 10% decrease in the average around-the-clock
market price of electricity. Because the decrease in revenues from customers
electing the power purchase option is significantly offset by increased CTC
revenues, ComEd does not believe that its exposure to such a market price
decrease would be material.

PECO

PECO is exposed to market risks associated with credit and interest
rates. The inherent risk in market sensitive instruments and positions is the
potential loss arising from adverse changes in counterparty credit and interest
rates. Exelon's corporate RMC sets forth risk management philosophy and
objectives through a corporate policy, and establishes procedures for risk
assessment, control and valuation, counterparty credit approval, and the
monitoring and reporting of derivative activity and risk exposures. As a result
of the PPA with Generation, PECO does not believe it is subject to material
commodity price risk.

CREDIT RISK

PECO is obligated to provide service to all electric customers within
its franchised territory. As a result, PECO has a broad customer base. For the
year ended December 31, 2001, PECO's ten largest customers represented
approximately 10% of its retail electric revenues. Credit risk for PECO is
managed by its credit and collection policies, which is consistent with state
regulatory requirements.

Under the Competition Act, licensed entities, including alternate
electric generating suppliers, may act as agents to provide a single bill and
provide associated billing and collection services to retail customers located
in PECO's retail electric service territory. Currently, there are no third
parties providing billing of PECO's charges to customers or advanced metering.
However, if this occurs, PECO would be subject to credit risk related to the
ability of the third parties to collect such receivables from the customers.

84

INTEREST RATE RISK

PECO 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. PECO also utilizes
forward-starting interest rate swaps and treasury rate locks to lock in interest
rate levels in anticipation of future financing. These strategies are employed
to maintain the lowest cost of capital. As of December 31, 2001, a hypothetical
10% increase in the interest rates associated with variable rate debt would not
have a material impact on pre-tax earnings for 2002.

PECO has entered into interest rate swaps to manage interest rate
exposure associated with the floating rate series of transition bonds issued to
securitize PECO's stranded cost recovery. At December 31, 2001, these interest
rate swaps had an aggregate fair market value exposure of $19 million based on
the present value difference between the contract and market rates at December
31, 2001.

The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point decrease in the spot yield at
December 31, 2001 is estimated to be $23 million. If these derivative
instruments had been terminated at December 31, 2001, this estimated fair value
represents the amount that would be paid by PECO to the counterparties.

The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point increase in the spot yield at
December 31, 2001 is estimated to be $15 million. If these derivative
instruments had been terminated at December 31, 2001, this estimated fair value
represents the amount to be paid by PECO to the counterparties.

In 1999, PECO entered into interest rate swaps relating to the Class
A-3 and Class A-5 Series 1999-A Transition Bonds in the aggregate notional
amount of $1.1 billion with an average interest rate of 6.65%. PECO also entered
into forward-starting interest rate swaps relating to these two classes of
floating rate transition bonds in the aggregate notional amount of $1.1 billion
with an average interest rate of 6.01%. In connection with the refinancing of a
portion of the two floating rate series of transition bonds in the first quarter
of 2001, PECO settled $318 million of a forward-starting interest rate swap,
resulting in a $6 million gain which is reflected in other income and
deductions. Also, in connection with the refinancing, PECO settled a portion of
the interest rate swaps and the remaining portion of the forward-starting
interest rate swaps resulting in gains of $25 million, which were deferred and
are being amortized over the expected remaining lives of the related debt.

In February 2000, PECO 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. In May 2000, PECO
settled these forward-starting interest rate swaps and paid the counterparties
$13 million which was deferred and is being amortized over the life of the
Transition Bonds as an increase in interest expense.

85

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EXELON

The information required by this Item is incorporated herein by reference
to the Consolidated Statements of Income for the years 2001, 2000 and 1999;
Consolidated Statements of Cash Flows for the years 2001, 2000 and 1999;
Consolidated Balance Sheets as of December 31, 2001 and 2000; Consolidated
Statements of Changes in Shareholders' Equity for the years 2001, 2000 and 1999
and Consolidated Statements of Comprehensive Income for the years 2001, 2000 and
1999; and Notes to Consolidated Financial Statements appearing in Exhibit 99-4
to Exelon's Current Report on Form 8-K dated February 28, 2002.

86

ComEd

REPORT OF INDEPENDENT ACCOUNTANTS

To the Shareholders and Board of Directors of
Commonwealth Edison Company:

In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)(2)(i) present fairly, in all material respects, the
financial position of Commonwealth Edison Company and Subsidiary Companies
(ComEd) at December 31, 2001 and 2000, and the results of their operations and
their cash flows for the year ended December 31, 2001 and for the periods from
October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19,
2000, in conformity with accounting principles generally accepted in the United
States of America. In addition, in our opinion, the financial statement schedule
listed in the index appearing under Item 14(a)(2)(ii) for the years ended
December 31, 2001 and 2000, 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 the financial
statement schedule are the responsibility of ComEd'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 of America, 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 our opinion.

As discussed in Note 3 to the consolidated financial statements, effective
October 20, 2000, Exelon Corporation acquired Unicom Corporation, the parent
company of ComEd at that date, in a business combination accounted for as a
purchase. As a result of the acquisition, the consolidated financial information
for the period after the acquisition is presented on a different cost basis than
that for the periods before the acquisition and therefore, is not comparable. As
discussed in Note 2, as part of a corporate restructuring undertaken on January
1, 2001 by Exelon Corporation, the parent company of ComEd, all of ComEd's
generation-related and certain other operations, assets and liabilities of ComEd
were transferred to affiliated companies of ComEd.

As discussed in Note 1 to the consolidated financial statements, ComEd changed
its method of accounting for derivative instruments and hedging activities
effective January 1, 2001.

PricewaterhouseCoopers LLP

Chicago, Illinois
January 29, 2002, except for Note 19 for which the date is March 21, 2002.

87

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of Commonwealth Edison Company:

We have audited the consolidated statements of income, cash flows,
comprehensive income and changes in shareholders' equity of Commonwealth Edison
Company (an Illinois corporation) and Subsidiary Companies for the year ended
December 31, 1999. These financial statements and the schedule referred to below
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and schedule based on our
audit.

We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the results of operations and cash flows of
Commonwealth Edison Company and Subsidiary Companies for the year ended December
31, 1999, in conformity with accounting principles generally accepted in the
United States.

Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item
14(a)(2)(ii) for the year ended December 31, 1999, is presented for the purposes
of complying with the Securities and Exchange Commission's rules and is not part
of the basic financial statements. This schedule has been subjected to the
auditing procedures applied in the audit of the basic financial statements and,
in our opinion, fairly states in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.

Arthur Andersen LLP

Chicago, Illinois
January 31, 2000

88

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME

For the For the period For the
Year Ended Oct. 20 - Jan. 1- Year Ended
Dec. 31, Dec. 31, Oct. 19, Dec. 31,
(in millions) 2001 2000 2000 1999
- ------------- ---- ---- ---- ----

OPERATING REVENUES

Operating Revenues $ 6,125 $ 1,297 | $ 5,625 $ 6,793
Operating Revenues from Affiliates 81 13 | 77 --
------- ------- | ------- -------
Total Operating Revenues 6,206 1,310 | 5,702 6,793
------- ------- | ------- -------
OPERATING EXPENSES |
|
Fuel and Purchased Power 14 322 | 1,655 1,549
Purchased Power from Affiliate 2,656 -- | -- --
Operating and Maintenance 833 423 | 1,653 2,352
Operating and Maintenance from Affiliates 148 -- | -- --
Merger-Related Costs -- 14 | 53 --
Depreciation and Amortization 665 130 | 868 836
Taxes Other Than Income 296 83 | 425 507
------- ------- | ------- -------
Total Operating Expenses 4,612 972 | 4,654 5,244
------- ------- | ------- -------
OPERATING INCOME 1,594 338 | 1,048 1,549
------- ------- | ------- -------
Other Income and Deductions |
|
Interest Expense (555) (127)| (469) (602)
Interest Expense from Affiliates (10) -- | -- --
Distributions on Company-Obligated |
Mandatorily Redeemable Preferred Securities of |
Subsidiary Trusts Holding Solely the Company's |
Subordinated Debt Securities (30) (6)| (24) (30)
Interest Income from Affiliates 79 29 | 150 8
Other, Net 35 2 | 127 52
------- ------- | ------- -------
Total Other Income and Deductions (481) (102)| (216) (572)
------- ------- | ------- -------
INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEMS 1,113 236 | 832 977
INCOME TAXES 506 103 | 229 326
------- ------- | ------- -------
INCOME BEFORE EXTRAORDINARY ITEMS 607 133 | 603 651
EXTRAORDINARY ITEMS (NET OF INCOME TAXES OF $2 AND $18 |
FOR THE PERIODS ENDING OCT. 19, 2000 AND DEC. 31, 1999, |
RESPECTIVELY) -- -- | (4) (28)
------- ------- | ------- -------
NET INCOME 607 133 | 599 623
PREFERRED AND PREFERENCE STOCK DIVIDENDS -- -- | 3 24
------- ------- | ------- -------
NET INCOME ON COMMON STOCK $ 607 $ 133 | $ 596 $ 599
======= ======= | ======= =======

See Notes to Consolidated Financial Statements

89

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the For the period For the
Year Ended Oct. 20 - Jan. 1- Year Ended
Dec. 31, Dec. 31 Oct. 19 Dec. 31,
(in millions) 2001 2000 2000 1999
- ------------- ---- ---- | ---- ----
|
CASH FLOWS FROM OPERATING ACTIVITIES |
|
Net Income $ 607 $ 133 | $ 599 $ 623
Adjustments to reconcile Net Income to Net |
Cash Flows provided by Operating Activities: |
Depreciation and Amortization 665 174 | 1,012 902
Extraordinary Items (net of income taxes) -- -- | 4 28
(Gain)/loss on Forward Share Arrangements -- -- | (113) 44
Reversal of Provision for Revenue Refunds (15) -- | -- --
Provision for Uncollectible Accounts 42 16 | 30 87
Deferred Income Taxes 14 72 | 861 (1,456)
Merger-Related Costs -- 14 | 53 --
Early Retirement and Separation Program -- -- | 28 (62)
Midwest Independent System Operator Exit Fees (36) -- | -- --
Contribution to Environmental Trust -- -- | -- (250)
Recovery of Coal Reserve Regulatory Assets -- -- | -- 198
Other Operating Activities (2) (69) | (163) 1
Changes in Working Capital: |
Accounts Receivable 76 (37) | 96 (175)
Inventories 16 97 | 17 (6)
Accounts Payable, Accrued Expenses |
& Current Liabilities 149 65 | (1,334) 1,331
Change in Receivables and Payables to Affiliates, net (166) -- | (10) (6)
Other Current Assets 2 59 | (6) (16)
------- ------- | ------- -------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 1,352 524 | 1,074 1,243
------- ------- | ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES |
|
Investment in Plant (839) (196) | (1,210) (1,337)
Plant Removals, net (30) (11) | (14) (75)
Sales of Generating Plants -- -- | -- 4,886
Proceeds from Nuclear Decommissioning Trust Funds -- 288 | 1,251 1,593
Investment in Nuclear Decommissioning Trust Funds -- (377) | (1,290) (1,683)
Change in Receivables from Affiliates 417 (441) | 288 (2,209)
Other Investments -- (63) | 139 (37)
Other Investing Activities 11 -- | 9 8
------- ------- | ------- -------
NET CASH FLOWS (USED IN) PROVIDED BY INVESTING ACTIVITIES (441) (800) | (827) 1,146
------- ------- | ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES |
|
Issuance of Long-Term Debt, net of issuance costs -- -- | 450 --
Common Stock Repurchases -- -- | (153) (115)
Retirement of Long-Term Debt (542) (84) | (755) (1,558)
Change in Short-Term Debt -- -- | (5) (272)
Redemption of Preferred Securities of Subsidiaries -- -- | (71) (534)
Change in Restricted Cash 19 50 | 175 2,778
Dividends on Capital Stock (483) (95) | (260) (392)
Common Stock Forward Repurchases -- -- | (67) (813)
Nuclear Fuel Lease Principal Payments -- -- | (270) (255)
Other Financing Activities (23) -- | -- --
------- ------- | ------- -------
NET CASH FLOW USED IN FINANCING ACTIVITIES (1,029) (129) | (956) (1,161)
------- ------- | ------- -------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (118) (405) | (709) 1,228
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 141 546 | 1,255 27
------- ------- | ------- -------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 23 $ 141 | $ 546 $ 1,255
======= ======= | ======= =======

See Notes to Consolidated Financial Statements

90

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS