Edgar Filing: PECO ENERGY CO

Filed Pursuant to Rule 424(b)(3)
Registration Statement No. 333-97401

$250,000,000

PECO Energy Company
[LOGO]
Peco/R/
An Exelon Company

Offer to Exchange
$250,000,000 5.95% First and Refunding Mortgage Bonds Due 2011 (Exchange Bonds)
Which have been registered under the Securities Act

For Any and All Outstanding
$250,000,000 5.95% First and Refunding Mortgage Bonds Due 2011
Which have not been so registered

TERMS OF THE EXCHANGE OFFER

. The exchange offer expires at 5:00 p.m., Eastern Time, on September 26,
2002, unless extended by us in our sole discretion, subject to applicable
law.

. The terms of the exchange bonds are identical to the original bonds,
except that the exchange bonds are registered under the Securities Act
and the transfer restrictions and registration rights applicable to the
original bonds do not apply to the exchange bonds.

. All original bonds that are validly tendered and not validly withdrawn
will be exchanged.

. Tenders of original bonds may be withdrawn at any time prior to
expiration of the exchange offer.

. We do not intend to apply for listing of the exchange bonds on any
securities exchange or to arrange for them to be quoted on any quotation
system.

. The exchange offer is subject to customary conditions, including the
condition that the exchange offer not violate applicable law or any
applicable interpretation of the staff of the Securities and Exchange
Commission.

. We will not receive any proceeds from the exchange offer.

. You will not incur any material United States Federal income tax
consequences from your participation in the exchange offer.

Each broker-dealer that receives exchange bonds for its own account pursuant
to the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of those exchange bonds. The letter of transmittal
states that by so acknowledging and by delivering a prospectus, a broker-dealer
will not be deemed to admit that it is an "underwriter" within the meaning of
the Securities Act. This prospectus, as it may be amended or supplemented from
time to time, may be used by a broker-dealer in connection with resales of
exchange bonds received in exchange for original bonds where the original bonds
were acquired by the broker-dealer as a result of market-making activities or
other trading activities.

Until the Expiration Date (as defined herein), all broker-dealers that
effect transactions in these securities may be required to deliver a
prospectus. This is in addition to the broker-dealers' obligation to deliver a
prospectus when acting as underwriters and with respect to their unsold
allotment of subscriptions. We have agreed that, starting on the Expiration
Date and ending on the close of business one year after the Expiration Date, we
will make this prospectus available to any broker-dealer for use in connection
with any such resale. See "Plan of Distribution."

Please see "Risk Factors" beginning on page 8 for a discussion of factors
you should consider in connection with the exchange offer.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of the exchange bonds or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.

The date of this prospectus is August 27, 2002.

TABLE OF CONTENTS

Page
----

WHERE TO FIND MORE INFORMATION......................................... i
PROSPECTUS SUMMARY..................................................... 1
RISK FACTORS........................................................... 8
FORWARD-LOOKING STATEMENTS............................................. 11
USE OF PROCEEDS........................................................ 11
CAPITALIZATION......................................................... 12
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA........................ 13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS........................................................ 14
BUSINESS............................................................... 42
MANAGEMENT............................................................. 51
COMPENSATION........................................................... 52
CERTAIN TRANSACTIONS................................................... 61
THE EXCHANGE OFFER..................................................... 63
DESCRIPTION OF THE EXCHANGE BONDS...................................... 71
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS................ 77
PLAN OF DISTRIBUTION................................................... 81
LEGAL OPINIONS......................................................... 81
EXPERTS................................................................ 82
INDEX TO FINANCIAL STATEMENTS.......................................... F-1
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA............................ F-2

When we refer to "original bonds," we are referring to the $250,000,000
5.95% First and Refunding Mortgage bonds due 2011, which were not registered
under the Securities Act. When we refer to "exchange bonds," we are referring
to the $250,000,000 5.95% First and Refunding Mortgage Bonds due 2011, which
have been registered under the Securities Act and are to be exchanged for the
original bonds.

When we refer to the term "bonds" or "bonds," we are referring to both the
original bonds and the exchange bonds to be issued in the exchange offer. When
we refer to "holders" of the bonds, we are referring to those persons who are
the registered holders of bonds on the books of the registrar appointed under
the indenture. Unless the context otherwise indicates, all references to "we,"
"us" or "our" in this prospectus mean PECO Energy Company, a Pennsylvania
corporation, and its consolidated subsidiaries.

No dealer, salesperson or other person is authorized to give any information
or to represent anything not contained in this prospectus. You must not rely on
any unauthorized information or representations. This prospectus is an offer
only of the exchange bonds to be issued in exchange for the original bonds, but
only under circumstances and in jurisdictions where it is lawful to do so. The
information contained in this prospectus is current only as of its date.

WHERE TO FIND MORE INFORMATION

In connection with the exchange offer, we have filed with the Securities and
Exchange Commission (the "SEC") a registration statement under the Securities
Act of 1933, as amended (the "Securities Act"), which offers to exchange the
original bonds for exchange bonds. As permitted by SEC rules, this prospectus
omits information included in the registration statement. For a more complete
understanding of this exchange offer, you should refer to the registration
statement, including its exhibits.

The public may read and copy any reports or other information that we file
with the SEC at the SEC's public reference room, Room 1024 at Judiciary Plaza,
450 Fifth Street, N.W., Washington, D.C. 20549, or at the SEC's regional
offices located at 233 Broadway, New York, New York 10279, and Suite 900, 175
W. Jackson Boulevard, Chicago, Illinois 60604. The public may obtain
information on the operation of the public reference room by calling the SEC at
1-800-SEC-0330. These documents are also available to the public from
commercial document retrieval services and at the web site maintained by the
SEC at http://www.sec.gov. You may also obtain a copy of the exchange offer
registration statement at no cost by writing us at the following address:

PECO Energy Company
Attn: Investor Relations
10 South Dearborn Street, 36th Floor
P.O. Box 805379
Chicago, IL 60680-5379

To obtain timely delivery, securities holders must request the information
no later than five business days before the date securities holders intend to
make their exchange decision.

PROSPECTUS SUMMARY

The following information is qualified in its entirety by the more detailed
information and financial statements appearing elsewhere in this prospectus. An
investment in the exchange bonds involves certain risks relating to our
business, prospects, financial condition and results of operations and certain
other risks relating to the terms of the exchange bonds. These risks are
described in "Risk Factors" beginning on page 8.

Summary of the Exchange Offer

The Exchange Offer.......... We are offering to exchange an aggregate of
$250,000,000 principal amount of exchange bonds
of one series, due 2011 for the $250,000,000
5.95% First and Refunding Mortgage Bonds due
2011. The original bonds may be exchanged only in
minimum denominations of $1,000 and multiples
thereof.

The Original Bonds.......... The original bonds were issued and sold on
October 30, 2001 in a transaction not requiring
registration under the Securities Act. At the
time we issued the original bonds, we entered
into a registration rights agreement which
obligates us to make this exchange offer.

Required Representations.... In order to participate in the exchange offer,
you will be required to make representations in a
letter of transmittal, including that:

. you are not affiliated with us;

. you are not a broker-dealer who bought your
original bonds directly from us;

. you will acquire the exchange bonds in the
ordinary course of business; and

. you have not agreed with anyone to distribute
the exchange bonds.

If you are a broker-dealer that purchased
original bonds for your own account as part of
market-making or trading activities, you must
represent to us that you have agreed with us or
our affiliates not to distribute the exchange
bonds. If you make this representation, you need
not make the last representation provided for
above. Each broker-dealer that receives exchange
bonds for its own account in exchange for
original bonds, where the original bonds were
acquired by the broker-dealer as a result of
market-making activities or other trading
activities, must acknowledge that it will deliver
a prospectus in connection with any resale of
exchange bonds. See "Plan of Distribution."

Resale of the Exchange Bonds We are making the exchange offer in reliance on
the position of the staff of the Division of
Corporation Finance of the SEC outlined in
certain interpretive letters issued to other
companies in other transactions. We believe that
the exchange bonds acquired in this exchange
offer may be freely traded without compliance
with the provisions of the Securities Act that
call for registration and delivery of a
prospectus, except as described in the following
paragraph.

The exchange bonds will be freely tradable only
if the holders meet the conditions described
under "Required Representations" above. If you
are a broker-dealer that purchased original bonds
for your own account as part of market-making or
trading activities, you must deliver a prospectus
when you sell the exchange bonds. We have agreed
in the registration rights agreement relating to
the original bonds to allow you to use this
prospectus for this purpose during the one-year
period following the Expiration Date, subject to
our right under some circumstances to restrict
your use of this prospectus. See "The Exchange
Offer--Resales of Exchange Bonds."

Broker-dealers that acquired original bonds
directly from us may not rely on the staff of the
Division of Corporation Finance's interpretations
and must comply with the registration and
prospectus delivery requirements of the
Securities Act, including being named as a
selling security holder, in order to resell the
original bonds or the exchange bonds.

Accrued Interest on the
Exchange Bonds............ The exchange bonds will bear interest at an
annual rate of 5.95%. Any interest that has
accrued on the original bonds before their tender
in this exchange offer will be payable on the
exchange bonds on the first interest payment date
after the conclusion of this exchange offer.

Procedures for Exchanging
Bonds..................... The procedures for exchanging original bonds
involve notifying the exchange agent before the
Expiration Date of your intention to do so. These
procedures are described in this prospectus under
the heading "The Exchange Offer--Procedures for
Tendering Original Bonds."

Expiration Date............. 5:00 p.m., Eastern Time, on September 26, 2002,
unless the exchange offer is extended
("Expiration Date").

Exchange Date............... We will notify the exchange agent of the date of
acceptance of the original bonds for exchange.

Withdrawal Rights........... If you tender your original bonds for exchange in
this exchange offer and later wish to withdraw
them, you may do so at any time before 5:00 p.m.,
Eastern Time, on the Expiration Date.

Acceptance of Original Bonds
and Delivery of Exchange
Bonds..................... We will accept any original bonds that are
properly tendered for exchange before 5:00 p.m.,
Eastern Time, on the Expiration Date. The
exchange bonds will be delivered promptly after
the Expiration Date.

Tax Consequences............ You will not incur any material United States
Federal income tax consequences from your
participation in this exchange offer. The
exchange of bonds will not constitute a taxable
exchange for U.S. Federal income tax purposes.
For a discussion of other U.S. Federal income tax
consequences resulting from the exchange and the
acquisition, ownership and disposition of the
exchange bonds, see "Certain United States
Federal Income Tax Considerations."

Use of Proceeds............. We will not receive any cash proceeds from this
exchange offer.

Exchange Agent.............. Wachovia Bank, National Association is serving as
the exchange agent. Its address and telephone
number are provided in this prospectus under the
heading "The Exchange Offer--Exchange Agent."

Effect on Holders of
Original Bonds............ Any original bonds that remain outstanding after
this exchange offer will continue to be subject
to restrictions on their transfer. The original
bonds may not be offered or sold in the U.S. for
the account of or benefit of U.S. persons within
the meaning of the Securities Act, except
pursuant to an exemption from or in a transaction
not subject to, the registration requirements of
the Securities Act. After this exchange offer,
holders of original bonds will not (with limited
exceptions) have any further rights under the
registration rights agreement. Any market for
original bonds that are not exchanged could be
adversely affected by the consummation of this
exchange offer.

Summary of the Exchange Bonds

This exchange offer applies to $250,000,000 aggregate principal amount of
the original bonds. The terms of the exchange bonds will be the same as the
original bonds, except that the exchange bonds will not contain language
restricting their transfer, and holders of the exchange bonds generally will
not be entitled to further registration rights under the registration rights
agreement. The exchange bonds will be issued under the same mortgage indenture
as the original bonds and under a supplemental mortgage indenture substantially
similar to the supplemental mortgage indenture under which the original bonds
were issued.

The following summary of the mortgage does not purport to be complete and is
subject to, and is qualified in its entirety by reference to, all provisions of
the mortgage. Certain terms used in this section are defined in the mortgage.
Copies of the First and Refunding Mortgage and the ninety-seven supplemental
mortgage indentures are on file with the SEC. A copy of the supplemental
mortgage indenture relating to the bonds may be obtained by contacting us as
described under "Where You Can Find More Information."

Issuer...................... PECO Energy Company

Securities Offered.......... $250,000,000 5.95% First and Refunding Mortgage
Bonds due 2011 ("exchange bonds"), which have
been registered under the Securities Act. The
original bonds were and the exchange bonds will
be issued under our First and Refunding Mortgage
dated May 1, 1923, as amended and supplemented by
ninety-seven supplemental mortgage indentures and
as proposed to be further amended and
supplemented by a supplemental mortgage indenture
relating to the exchange bonds (herein sometimes
referred to collectively as the "mortgage").
Wachovia Bank, National Association is the
trustee under the mortgage ("trustee") as
successor to First Union National Bank.

Interest Payment Dates...... May 1 and November 1 of each year, beginning May
1, 2002, until the principal is paid or made
available for payment. Interest on the exchange
bonds will accrue from the most recent date to
which interest has been paid on the original
bonds. Interest will be computed on the basis of
a 360-day year comprised of twelve 30-day months.

Maturity.................... November 1, 2011

Optional Redemption......... We may, at our option, redeem the exchange bonds
in whole or in part at any time at a price equal
to the greater of:

100% of the principal amount of the exchange
bonds being redeemed plus accrued interest to the
redemption date; or

as determined by the Quotation Agent, the sum of
the present values of the remaining scheduled
payments of principal and interest on the
exchange bonds to be redeemed (not including any
portion of payments of interest accrued as of the
redemption date) discounted to the redemption
date on a semi-annual basis at the Adjusted
Treasury Rate plus 30 basis points, plus accrued
interest to the redemption date. See "Description
of Exchange Bonds--Redemption at Our Option."

The redemption price will be calculated assuming
a 360-day year consisting of twelve 30-day months.

We will mail notice of any redemption at least 30
days but not more than 45 days before the
redemption date to each registered holder of the
exchange bonds to be redeemed.

Unless we default in payment of the redemption
price, on and after the redemption date, interest
will cease to accrue on the exchange bonds or
portions of the exchange bonds called for
redemption.

See "Description of the Exchange Bonds" for
certain definitions used in this summary.

Security.................... The exchange bonds will be secured equally with
all other bonds outstanding or hereafter issued
under the mortgage (sometimes referred to herein
as the "mortgage bonds") by the lien of the
mortgage. The lien of the mortgage, subject to
(1) minor exceptions and certain excepted
encumbrances that are defined in the mortgage and
(2) the trustee's prior lien for compensation and
expenses, constitutes a first lien on
substantially all of our properties. The mortgage
does not constitute a lien on any property owned
by our subsidiaries. Our properties consist
principally of electric transmission and
distribution lines and substations, gas
distribution facilities and general office and
service buildings.

We may not issue securities which will rank ahead
of the mortgage bonds as to security. We may
acquire property subject to prior liens. If such
property is made the basis for the issuance of
additional bonds after we acquire it, all
additional bonds issued under the prior lien must
be pledged with the trustee as additional
security under the mortgage.

Form........................ The exchange bonds will be book-entry only and
registered in the name of a nominee of DTC.

Summary Information About PECO Energy Company

The following summary contains basic information about PECO Energy Company.
It may not contain all of the information that may be important to you in
making a decision to exchange your original bonds for the exchange bonds. You
should read this entire prospectus, and the documents to which we refer, before
making your decision.

PECO ENERGY COMPANY

We are a subsidiary of Exelon Corporation ("Exelon") and are 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. We deliver electricity to approximately 1.5 million
customers and natural gas to approximately 440,000 customers.

Our traditional retail service territory covers 2,107 square miles in
southeastern Pennsylvania. We provide electric delivery service in an area of
1,972 square miles, with a population of approximately 3.6 million, including
1.6 million in the City of Philadelphia. Natural gas service is supplied in a
1,475 square mile area in southeastern Pennsylvania adjacent to Philadelphia,
with a population of 1.9 million.

Pursuant to the Pennsylvania Electricity Generation Customer Choice and
Competition Act (the "Competition Act"), the Commonwealth of Pennsylvania
required the unbundling of retail electric services in Pennsylvania into
separate generation, transmission and distribution services with open retail
competition for generation services. Since the commencement of deregulation in
1999, we have served as the local distribution company providing electric
distribution services to all customers in our service territory and bundled
electric service to provider-of-last-resort customers, which are customers who
do not or cannot choose an alternate electric generation supplier.

As a result of deregulation, Exelon undertook a corporate restructuring to
separate its unregulated generation and other competitive businesses from its
regulated energy delivery businesses. As part of the corporate restructuring,
effective January 1, 2001, our unregulated operations were transferred to
separate subsidiaries of Exelon. The transferred assets and liabilities related
to nuclear, fossil and hydroelectric generation and wholesale services and
unregulated gas and electric sales activities, and administrative, information
technology and other support for all other business activities of Exelon and
its subsidiaries. In connection with the restructuring, we entered into a power
purchase agreement with Exelon Generation Company, LLC ("Exelon Generation"), a
wholly owned subsidiary of Exelon, to supply us with all of our electric load
requirements for customers through 2010.

As a public utility under the Pennsylvania Public Utility Code, we are
subject to regulation by the Pennsylvania Public Utility Commission ("PUC"),
including regulation as to electric distribution rates, retail gas rates,
issuances of securities and certain other aspects of our operations. As a
subsidiary of Exelon, a registered holding company under the Public Utility
Holding Company Act of 1935 ("PUHCA"), we are subject to a number of
restrictions under PUHCA. As an electric utility under the Federal Power Act,
we are also subject to regulation by the Federal Energy Regulatory Commission
("FERC") as to transmission rates and certain other aspects of our business,
including interconnections and sales of transmission related assets.

Our principal executive offices are located at 2301 Market Street,
Philadelphia, PA 19101-8699 and our telephone number is (215) 841-4000.

CORPORATE STRUCTURE

We were incorporated in Pennsylvania in 1929. We are an indirect wholly
owned subsidiary of Exelon, a public utility holding company. Exelon is the
result of the merger in October 2000 between us and Unicom Corporation
("Unicom"), the former parent company of Commonwealth Edison Company ("ComEd").
As part of a corporate restructuring of Exelon effective January 1, 2001, our
power generation assets and wholesale power marketing business, as well as
ComEd's power generation assets and wholesale power marketing business, were
transferred to Exelon Generation.

Exelon Corporation
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Exelon Energy Delivery Exelon Ventures
Company, LLC Company, LLC

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Commonwealth PECO Energy Exelon Exelon
Edison Company Company Generation Enterprises
Company, LLC Company, LLC

Electric and Gas Generation and Enterprises infrastructure
Distribution Power Marketing services, communications
retail energy sales,
energy services

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Regulated Unregulated

RISK FACTORS

In addition to the information contained elsewhere in this prospectus, you
should carefully consider the risks described below. Each of the following
factors could have a material adverse effect on our business and could result
in a loss or a decrease in the value of your investment.

The rates we charge for electric distribution and retail gas are regulated by
the Pennsylvania Public Utility Commission; failure to obtain adequate and
timely rate relief could negatively affect our business.

We are a public utility under the Pennsylvania Public Utility Code and, as a
result, the PUC regulates our electric distribution rates and retail gas rates
and also matters such as the issuance of securities and certain other aspects
of our operations. Substantially all of our retail revenues are subject to
regulation by the PUC. The rates are set by the PUC and are effective until a
new rate case is brought. Limited categories of costs, principally the cost of
gas, are recovered through adjustment charges that are periodically set to
reflect actual costs. If our costs to serve customers exceed the amount
included in our adjustment charges, there will be a negative effect on our cash
flow.

We are subject to the risks inherent in the utility business and our cash flow
and earnings could be adversely affected by increased customer demand for
energy, a failure to deliver on the part of our suppliers or, after our
long-term contracts expire, high prices and volatile markets for purchased
electricity.

The utility business involves many operating risks. If our operating
expenses exceed the levels recovered from retail customers for an extended
period of time our cash flow and earnings would be negatively affected. In
addition, after our power purchase agreement with our affiliate Exelon
Generation expires in 2010, our results could be affected by increases in
purchased power costs. In addition, our provider-of-last-resort obligation may
continue past the expiration of this contract, which, depending upon the
volatility of the market for electricity at the time, could affect our
operating expenses and therefore results. Factors that could cause purchased
power costs to increase include, but are not limited to:

. increases in demand due to, for example, weather, customer growth or
customer obligations;

. below normal energy available on the market;

. increases in purchases in wholesale markets at prices above the amount
recovered in retail rates;

. extended outages of any thermal or other generating facilities or the
transmission lines that deliver energy to load centers; and

. failure to perform on the part of any party from which we purchase
capacity or energy.

Our financial performance depends on our operation of our facilities.

Failures of equipment or facilities in our distribution system may cause
interruption of the electric services we provide, which could adversely affect
our business. Failures of equipment or facilities could result in lost
revenues, additional costs and possible claims against us for damages incurred
by customers as a result of the outage. Our efforts to repair or replace
equipment may not be successful or we may be unsuccessful in making necessary
improvements to our transmission and distribution system, causing other
outages, having an adverse affect on our business.

If our operating expenses exceed the levels recovered from retail customers
for an extended period of time our cash flow and earnings would be negatively
affected

Our business may be adversely affected by regulatory changes in the electric
power and natural gas industries.

Transmission and distribution of electricity remain regulated industries,
while in many states, including the Commonwealth of Pennsylvania, electricity
generation has been deregulated. The regulation of the electric power and
natural gas industries, however, continues to undergo substantial changes at
both the federal and state level.

These changes have significantly affected the whole industry and the manner in
which its participants conduct their businesses. Future changes in laws and
regulations, including changes resulting from market volatility and increased
security concerns, may have an effect on our business in ways that we cannot
predict.

Our revenues will be affected by rate reductions and rate caps currently in
effect and any that may be imposed in the future. The rate caps limit our
ability to recover increased expenses and the costs of investments in new
transmission and distribution facilities through rates. As a result, our future
results of operations will depend on our ability:

. to deliver electricity and gas to our customers cost-effectively,
particularly in light of the current caps on rates;

. to realize cost savings; and

. to manage our provider of last resort responsibilities.

Our financial performance depends on our ability to predict our load
requirements.

Under electric restructuring legislation in Pennsylvania, we are required to
provide generation and distribution services as the "provider-of-last-resort"
to customers who cannot or do not choose alternate suppliers or who choose to
return to our utility after taking service elsewhere. This obligation may
continue past the expiration of our power purchase agreement with Exelon
Generation in 2010. Because the choice of electricity generation supplier lies
with the customer, it is difficult for us to predict and plan for the level of
customers and associated energy demand. If these obligations remain unchanged,
we 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 come back to us as a "last resort" option. A
significant over- or under-estimation of such reserves may cause us to take a
commodity price risk. We continue to be obligated to provide a reliable
delivery system under cost-based rates.

Recession, acts of war or terrorism could negatively impact our business.

The consequences of a prolonged recession and adverse market conditions may
include the continued uncertainty of energy prices--which could increase our
provider-of-last-resort obligations--and uncertainty in the capital and
commodity markets. We cannot predict the impact of any continued economic
downturn, uncertain capital and commodity markets or fluctuating energy prices
on our business. The impact, however, could have a material adverse effect on
our financial condition, results of operations and net cash flows.

Like other operators of major industrial facilities, our transmission and
distribution facilities may be targets of terrorist activities that could
result in disruption of our ability to distribute some portion of our
electricity and gas. Any such disruption could result in a significant decrease
in revenues and/or significant additional costs to repair, which could have a
material adverse impact on our financial condition, results of operation and
net cash flows.

We are subject to control by Exelon.

We are ultimately controlled by Exelon and, therefore, Exelon controls
decisions regarding our business and has control over our management and
affairs. In circumstances involving a conflict of interest between Exelon, on
the one hand, and our creditors, on the other, Exelon could exercise its power
to control us in a manner that would benefit Exelon to the detriment of our
creditors, including the holders of the exchange bonds.

Conflicts of interest may arise between us and our affiliate.

We rely on purchases from our affiliate Exelon Generation under long-term
contracts in order to supply electricity to our customers. Conflicts of
interest may arise if we need to enforce the terms of agreements between us and
Exelon Generation. Decisions concerning the interpretation or operation of
these agreements could be made from perspectives other than the interests
solely of our company or its creditors, including the holders of the exchange
bonds.

We are subject to regulation by FERC.

We also provide 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. FERC continues to propose regulations
regarding evolving wholesale markets. Further regulation by FERC in this area
could affect our business in ways we cannot predict.

There is no public market for the exchange bonds.

Following the completion of this exchange offer, the exchange bonds will be
freely tradable by most holders. See "The Exchange Offer." We do not intend to
list the exchange bonds on any United States or foreign securities exchange. We
can give no assurances concerning the liquidity of any market that may develop
for the exchange bonds, the ability of any investor to sell the exchange bonds,
or the price at which investors would be able to sell their exchange bonds. If
a market for the exchange bonds does not develop, investors may be unable to
resell the exchange bonds for an extended period of time, if at all.
Consequently, investors may not be able to liquidate their investment readily,
and lenders may not readily accept the exchange bonds as collateral for loans.

If you fail to exchange the original bonds, they will remain subject to
transfer restrictions.

Any original bonds that remain outstanding after this exchange offer will
continue to be subject to restrictions on their transfer. After this exchange
offer, holders of original bonds will not (with limited exceptions) have any
further rights under the exchange and registration rights agreement. Any market
for original bonds that are not exchanged could be adversely affected by the
conclusion of this exchange offer.

Late deliveries of the original bonds and other required documents could
prevent a holder from exchanging its bonds.

Holders are responsible for complying with all exchange offer procedures.
Issuance of exchange bonds in exchange for original bonds will only occur upon
completion of the procedures described in this prospectus under the heading
"The Exchange Offer--Procedures for Tendering Original bonds." Therefore,
holders of original bonds who wish to exchange them for exchange bonds should
allow sufficient time for completion of the exchange procedure. We are not
obligated to notify you of any failure to follow the proper procedure.

If you are a broker-dealer, your ability to transfer the bonds may be
restricted.

A broker-dealer that purchased original bonds for its own account as part of
market-making or trading activities must deliver a prospectus when it sells the
exchange bonds. Our obligation to make this prospectus available to
broker-dealers is limited. Consequently, we cannot guarantee that a proper
prospectus will be available to broker-dealers wishing to resell their exchange
bonds.

FORWARD-LOOKING STATEMENTS

This prospectus includes "forward-looking statements" within the meaning of
the Private Securities Litigation Reform Act of 1995. All statements, other
than statements of historical facts, included in this prospectus that address
activities, events or developments that we expect or anticipate will or may
occur in the future, including such matters as our projections, future capital
expenditures, business strategy, competitive strengths, goals, expansion,
market and industry developments and the growth of our businesses and
operations, are forward-looking statements. These statements are based on
assumptions and analyses made by us in light of our experience and our
perception of historical trends, current conditions and expected future
developments, as well as other factors we believe are appropriate under the
circumstances. These statements involve a number of risks and uncertainties,
many of which are beyond our control. The following are among the most
important factors that could cause actual results to differ materially from the
forward-looking statements:

. the significant considerations and risks discussed in this prospectus;

. general and local economic, market or business conditions;

. fluctuations in demand for electricity, capacity and ancillary services
in the markets in which we operate;

. uncertain obligations due to customers' right to choose generation
suppliers;

. changes in laws or regulations that are applicable to us;

. environmental constraints on construction and operation; and

. access to capital.

Consequently, all of the forward-looking statements made in this prospectus
are qualified by these cautionary statements and we cannot assure you that the
results or developments anticipated by us will be realized or, even if
realized, will have the expected consequences to or effects on us or our
business prospects, financial condition or results of operations. You should
not place undue reliance on these forward-looking statements in making your
investment decision. We expressly disclaim any obligation or undertaking to
release publicly any updates or revisions to these forward-looking statements
to reflect events or circumstances that occur or arise or are anticipated to
occur or arise after the date hereof. In making an investment decision
regarding the exchange bonds, we are not making, and you should not infer, any
representation about the likely existence of any particular future set of facts
or circumstances.

USE OF PROCEEDS

The exchange offer is being made in accordance with requirements of the
registration rights agreement. We will not receive any cash proceeds from the
issuance of the exchange bonds in the exchange offer. In exchange for issuing
the exchange bonds as described in this prospectus, we will receive an equal
principal amount of original bonds, which will be canceled.

The net proceeds from the sale of the original bonds, together with
available cash balances, were used to repay $250 million aggregate principal
amount of our First and Refunding Mortgage Bonds, 5 5/8% Series due November 1,
2001.

CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2002. This
table should be read in conjunction with our consolidated financial statements
and related notes for the quarter ended June 30, 2002, included in this
prospectus.

As of June 30, 2002
-------------------
($ in millions)

Short-term debt (a).............. $1,085
------
Capitalization:
Long-term debt (b):
Transition bonds (c)...... $4,132
First mortgage bonds...... 509
Other long-term debt...... 228
Preferred securities.......... 284
Shareholders' equity.......... 385
------
Total capitalization...... $5,538
======

--------
(a) Includes current maturities of long-term debt of $910 million, of which
$280 million are transition bonds.
(b) Includes unamortized debt discounts and premiums. Excludes current
maturities.
(c) Transition bonds represent bonds issued by our subsidiary to securitize a
portion of our stranded cost recovery.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected historical consolidated
financial data. The historical consolidated income statement data for the years
ended December 31, 2001, December 31, 2000 and December 31, 1999 have been
derived from our audited financial statements included elsewhere in this
prospectus. The historical consolidated balance sheet data as of December 31,
2001 and 2000 have been derived from our audited financial statements included
elsewhere in this prospectus. As part of Exelon's restructuring, effective
January 1, 2001, our unregulated generation and other competitive businesses
and related assets and liabilities were transferred to separate subsidiaries of
Exelon. The restructuring has had a significant impact on our assets,
liabilities and equity and our results of operations. Our results of operations
and assets and liabilities prior to January 2001 do not reflect the
restructuring. The information set forth below should be read in conjunction
with Management's Discussion and Analysis of Financial Condition and Results of
Operations ("MD&A") and the Consolidated Financial Statements and accompanying
Notes to Consolidated Financial Statements included elsewhere in this
prospectus.

Six
Months
Ended
Years Ended December 31, June 30,
------------------------------------------- 2002
1997 1998 1999 2000 2001 (Unaudited)
------- ------- ------- ------- ------- -----------
($ in millions)

Income Statement Data
Operating revenues................... $ 4,601 $ 5,325 $ 5,478 $ 5,950 $ 3,965 $ 2,015
Operating income..................... 1,006 1,268 1,373 1,222 999 461
Net income on common stock........... (1,514) 500 570 497 415 177
Cash Flow Data
Cash interest paid (a)............... $ 406 $ 385 $ 350 $ 431 $ 416 $ 193
Capital expenditures................. 490 415 491 549 264 123
Cash flows from operating activities. 1,068 1,499 895 756 828 468
Cash flows from investing activities. (604) (521) (886) (894) (235) (122)
Cash flows from financing activities. (460) (963) (3) 133 (579) (306)

As of December 31, As of
------------------------------------------- June 30,
1997 1998 1999 2000 2001 2002
------- ------- ------- ------- ------- -----------
($ in millions)
Balance Sheet Data
Property, plant and equipment, net... $ 4,671 $ 4,804 $ 5,004 $ 5,158 $ 4,047 $ 4,098
Total assets......................... 12,357 12,048 13,087 14,776 10,745 10,717
Long-term debt(b).................... 3,853 2,920 5,969 6,002 5,438 4,869
Preferred securities................. 582 580 321 302 284 284
Common shareholders' equity.......... 2,727 3,057 1,773 1,638 323 385

Ratio of Earnings to Fixed Charges
Twelve
Months
Years Ended December 31, Ended
------------------------------------------- June 30,
1997 1998 1999 2000 2001 2002
---- ------- ------- ------- ------- -----------
2.56 3.38 3.37 2.70 2.46 2.49

--------
(a) Includes cash interest paid of none, none, $107 million, $268 million, $315
million and $145 million in connection with transition bonds for the years
ended December 31, 1997, 1998, 1999, 2000 and 2001 and the six months ended
June 30, 2002, respectively.
(b) Excludes current maturities of $247 million, $362 million, $128 million,
$553 million, $548 million and $910 million as of December 31, 1997,
December 31, 1998, December 31, 1999, December 31, 2000, December 31, 2001
and June 30, 2002, respectively.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

On October 20, 2000, we became a wholly owned subsidiary of Exelon as a
result of the transactions relating to the merger.

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, our non-regulated operations and
related assets and liabilities, representing the generation and enterprises
business segments, were transferred to separate subsidiaries of Exelon. As a
result, beginning January 2001, our operations have consisted of retail
electricity distribution and transmission business in southeastern Pennsylvania
and our natural gas distribution business located in the Pennsylvania counties
surrounding the City of Philadelphia. The estimated impact of the restructuring
reflects the effects of removing the generation and enterprises operations and
obtaining energy and capacity from Exelon Generation under the terms of the
Power Purchase Agreement for the year ended December 31, 2000.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001

Three Months
Ended June 30,
-------------
2002 2001 Variance % Change
---- ----- -------- --------
(in millions)

OPERATING REVENUES............................................ $995 $ 906 $ 89 9.8%
OPERATING EXPENSES
Purchased Power............................................ 405 315 90 28.6%
Fuel....................................................... 53 79 (26) (32.9)%
Operating and Maintenance.................................. 131 126 5 4.0%
Depreciation and Amortization.............................. 109 99 10 10.1%
Taxes Other Than Income.................................... 63 41 22 53.7%
---- ----- ----
Total Operating Expense................................ 761 660 101 15.3%
---- ----- ----
OPERATING INCOME.............................................. 234 246 (12) (4.9)%
---- ----- ----
OTHER INCOME AND DEDUCTIONS
Interest Expense........................................... (92) (119) 27 (21.4)%
Distributions on Company-Obligated Mandatorily Redeemable
Preferred Securities of a Partnership which holds Solely
Subordinated Debentures of the Company................... (2) (2) -- --
Other, net................................................. 2 4 (2) (50.0)%
---- ----- ----
Total Other Income and Deductions...................... (92) (117) 25 (21.4)%
---- ----- ----
INCOME BEFORE INCOME TAXES.................................... 142 129 13 10.1%
INCOME TAXES.................................................. 49 44 5 11.4%
---- ----- ----
NET INCOME.................................................... 93 85 8 9.4%
Preferred Stock Dividends..................................... (2) (3) 1 (33.3)%
---- ----- ----
NET INCOME ON COMMON STOCK.................................... $ 91 $ 82 $ 9 11.0%
==== ===== ====

Net income on common stock increased $9 million, or 11% for the quarter
ended June 30, 2002 as compared to the same 2001 period. The increase was a
result of higher additional volume, favorable rate adjustments and lower
interest expense on debt partially offset by increased depreciation and
amortization expense.

Our electric sales statistics are as follows:

For the three
months ended
June 30,
-------------
Deliveries--(in GWh) 2002 2001 % Change
-------------------- ----- ----- --------

Bundled Deliveries (1)
Residential............................ 2,115 1,673 26.4%
Small Commercial & Industrial.......... 1,881 1,312 43.4%
Large Commercial & Industrial.......... 3,927 3,172 23.8%
Public Authorities & Electric Railroads 200 181 10.5%
----- -----
8,123 6,338 28.2%
----- -----
Unbundled Deliveries (2)
Residential............................ 557 848 (34.3)%
Small Commercial & Industrial.......... 2 524 (99.6)%
Large Commercial & Industrial.......... 13 732 (98.2)%
Public Authorities & Electric Railroads -- 2 (100.0)%
----- -----
572 2,106 (72.8)%
----- -----
Total Retail Deliveries................ 8,695 8,444 3.0%
===== =====

--------
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy, the delivery cost
of the transmission and distribution of the energy and a Competitive
Transition Charge ("CTC") charge.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier.

For the three
months ended
June 30,
-------------
Electric Revenue (in millions) 2002 2001 Variance % Change
------------------------------ ---- ---- -------- --------

Bundled Revenue (1)
Residential............................ $278 $222 $ 56 25.2%
Small Commercial & Industrial.......... 224 157 67 42.7%
Large Commercial & Industrial.......... 288 224 64 28.6%
Public Authorities & Electric Railroads 19 17 2 11.8%
---- ---- ----
809 620 189 30.5%
---- ---- ----
Unbundled Revenue (2)
Residential............................ 42 67 (25) (37.3)%
Small Commercial & Industrial.......... -- 28 (28) (100.0)%
Large Commercial & Industrial.......... 1 19 (18) (94.7)%
Public Authorities & Electric Railroads -- -- -- --
---- ---- ----
43 114 (71) (62.3)%
---- ---- ----
Total Electric Retail Revenues......... 852 734 118 16.1%
Wholesale and Miscellaneous Revenue (3) 59 60 (1) (1.7)%
---- ---- ----
Total Electric Revenue................. $911 $794 $117 14.7%
==== ==== ====

--------
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.
(2) Revenue from customers receiving generation from an alternate supplier
includes a distribution charge and a CTC charge.
(3) Wholesale and miscellaneous revenues include sales, transmission revenue,
sales to municipalities and other wholesale energy sales.

The changes in electric retail revenues for the quarter ended June 30, 2002,
as compared to the same 2001 period, are as follows:

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

Customer Choice........ $ 85
Rate Changes........... 13
Weather................ 1
Other Effects.......... 19
----
Electric Retail Revenue $118
====

Customer Choice. All our customers have a 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 us.

As of June 30, 2002, the customer load served by alternate suppliers was 991
MW or 12.8% as compared to 1,102 MW or 14.5% as of June 30, 2001. For the
quarter ended June 30, 2002, the percent of our total retail deliveries for
which we were the electric supplier was 93.4% in 2002, an 18.3% increase as
compared to 75.1% in 2001. As of June 30, 2002, the number of customers served
by alternate suppliers was 308,866 or 20.2% as compared to June 30, 2001 of
400,972 or 26.4%. The increases in the customer load and the percentage of MWh
served by us, and the decrease in the number of customers served by alternative
suppliers primarily resulted from customers selecting or returning to us as
their electric generation supplier.

In February 2002, we were notified by New Power Company ("New Power") of its
intent to withdraw from providing Competitive Default Service ("CDS") to
approximately 180,000 residential customers. As a result of that withdrawal,
those CDS customers were returned to us in the second quarter of 2002. Pursuant
to a tariff filing approved by the PUC, we will serve those returned customers
at the discount energy rates on generation provided for under the original New
Power CDS Agreement for the remaining term of that contract. Subsequently, in
the second quarter of 2002, New Power also advised us it planned to withdraw
from serving all of its customers in Pennsylvania, including approximately
15,000 of our non-CDS customers, and to return those customers to us in
September 2002.

Rate Changes. The increase in revenues attributable to rate changes
primarily reflects a $13 million increase due to an increase in the gross
receipts tax rate effective January 1, 2002.

As permitted by the Pennsylvania Electric Competition Act, the Pennsylvania
Department of Revenue has calculated a 2002 Revenue Neutral Reconciliation
("RNR") adjustment to the gross receipts tax rate in order to neutralize the
impact of electric restructuring on its tax revenues. The RNR adjustment
increases the gross receipts tax rate, which will increase our annual revenues
and tax obligations by approximately $50 million in 2002. In January 2002, the
PUC approved the adjustment to the gross receipts tax rate, which was
implemented effective January 1, 2002. The RNR adjustment is under appeal.

The weather impact was favorable compared to the prior year as a result of
warmer summer weather.

Other Effects. Other items affecting revenue during the quarter ended June
30, 2002 include:

. Volume. Exclusive of weather impacts, higher delivery volume affected
our revenue by $24 million compared to the same 2001 period.

. Other. The payment of $7 million to Exelon Generation related to nuclear
decommissioning cost recovery under an agreement effective September
2001, which reduced our revenue compared to the prior year.

Our gas sales statistics for the quarter ended June 30, 2002 as compared to
the same 2001 period are as follows:

For the three months
ended June 30,
--------------------
2002 2001 Variance
------- ------- --------

Deliveries in million cubic feet (mmcf) 14,286 13,781 505
Revenue (in millions).................. $ 84 $ 112 $(28)

The changes in gas revenue for the quarter ended June 30, 2002, as compared
to the same 2001 period, are as follows:

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

Rate Changes $(28)
Weather..... --
Volume...... (1)
Other....... 1
----
Gas Revenue. $(28)
====

Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC effective in December
2001. The average rate per million cubic feet for all customers for the quarter
ended June 30, 2002 was 28% lower than the same 2001 period. Our 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.

Weather. The weather impact was neutral during the quarter ended June 30,
2002 compared to the same 2001 period.

Volume. Exclusive of weather impact, delivery volume was consistent for the
quarter ended June 30, 2002 compared to the same 2001 period.

Purchased Power and Fuel Expense

Purchased power and fuel expense for the quarter ended June 30, 2002
increased $64 million as compared to the same 2001 period. The increase in fuel
and purchased power expense was primarily attributable to $73 million from
customers in Pennsylvania selecting or returning to us as their electric
generation supplier, $9 million primarily attributable to higher delivery
volume and higher PJM ancillary charges of $8 million. These increases were
partially offset by $28 million from lower gas prices.

Operating and Maintenance Expense

O&M expense for the quarter ended June 30, 2002 increased $5 million, or 4%,
as compared to the same 2001 period. The increase in O&M expense was primarily
attributable to $5 million related to the deployment of automated meter reading
technology and $3 million related to an increased allocation of corporate
expense.

Depreciation and Amortization Expense

Depreciation and amortization expense for the quarter ended June 30, 2002
increased $10 million, or 10%, as compared to the same 2001 period. The
increase was primarily attributable to $9 million of additional amortization of
our CTC and an increase of $1 million related to depreciation expense
associated with additional plant in service. The additional amortization of the
CTC is in accordance with our original settlement under the Competition Act.

Taxes Other Than Income

Taxes other than income for the quarter ended June 30, 2002 increased $22
million, or 54%, as compared to the same 2001 period. The increase was
primarily attributable to additional gross receipts tax related to additional
revenues and an increase in the gross receipts tax rate on electric revenue
effective January 1, 2002.

Interest Charges

Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership
("COMRPS"). Interest charges decreased $27 million, or 21% in the quarter ended
June 30, 2002 as compared to the same 2001 period. The decrease was primarily
attributable to lower interest expense on long-term debt of $22 million as a
result of principal payments and lower interest rates and interest expense
related to a loan from an affiliate in 2001 of $2 million.

Other Income and Deductions

Other income and deductions excluding interest charges remained consistent
in the quarter ended June 30, 2002 as compared to the same 2001 period.

Income Taxes

The effective tax rate was substantially unchanged at 34.5% for the quarter
ended June 30, 2002 as compared to 34.1% for the same 2001 period.

Preferred Stock Dividends

Preferred stock dividends for the quarter ended June 30, 2002 were
consistent as compared to the same 2001 period.

Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001

Six Months
Ended June 30,
--------------
2002 2001 Variance % Change
------ ------ -------- --------
(in millions)

OPERATING REVENUES............................................ $2,015 $1,957 $ 58 3.0%
OPERATING EXPENSES
Purchased Power............................................ 756 598 158 26.4%
Fuel....................................................... 188 284 (96) (33.8)%
Operating and Maintenance.................................. 267 258 9 3.5%
Depreciation and Amortization.............................. 221 200 21 10.5%
Taxes Other Than Income.................................... 122 84 38 45.2%
------ ------ ----
Total Operating Expense................................ 1,554 1,424 130 9.1%
------ ------ ----
OPERATING INCOME.............................................. 461 533 (72) (13.5)%
------ ------ ----
OTHER INCOME AND DEDUCTIONS
Interest Expense........................................... (187) (227) 40 (17.6)%
Distributions on Company-Obligated Mandatorily Redeemable
Preferred Securities of a Partnership which holds Solely
Subordinated Debentures of the Company................... (5) (5) -- --
Other, net................................................. 2 18 (16) (88.9)%
------ ------ ----
Total Other Income and Deductions...................... (190) (214) 24 (11.2)%
------ ------ ----
INCOME BEFORE INCOME TAXES.................................... 271 319 (48) (15.0)%
INCOME TAXES.................................................. 90 112 (22) (19.6)%
------ ------ ----
NET INCOME.................................................... 181 207 (26) (12.6)%
Preferred Stock Dividends..................................... (4) (5) 1 (20.0)%
------ ------ ----
NET INCOME ON COMMON STOCK.................................... $ 177 $ 202 $(25) (12.4)%
====== ====== ====

Net income on common stock decreased $25 million, or 12% for the six months
ended June 30, 2002 as compared to the same 2001 period. The decrease was a
result of lower margins due to the unplanned return of certain residential,
commercial and industrial customers, milder weather, increased depreciation and
amortization expense, partially offset by favorable rate adjustments.

Our electric sales statistics are as follows:

For the six months
ended June 30,
------------------
Deliveries - (in GWh) 2002 2001 % Change
--------------------- ------ ------ --------

Bundled Deliveries (1)
Residential............................ 4,171 4,132 0.9%
Small Commercial & Industrial.......... 3,638 2,313 57.3%
Large Commercial & Industrial.......... 7,278 5,703 27.6%
Public Authorities & Electric Railroads 393 374 5.1%
------ ------
15,480 12,522 23.6%
------ ------
Unbundled Deliveries (2)
Residential............................ 1,348 1,375 (2.0)%
Small Commercial & Industrial.......... 99 1,416 (93.0)%
Large Commercial & Industrial.......... 116 1,921 (94.0)%
Public Authorities & Electric Railroads -- 7 (100.0)%
------ ------
1,563 4,719 (66.9)%
------ ------
Total Retail Deliveries................ 17,043 17,241 (1.1)%
====== ======

--------
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier.

For the six months
ended June 30,
------------------
Electric Revenue (in millions) 2002 2001 Variance % Change
------------------------------ ------ ------ -------- --------

Bundled Revenue (1)
Residential............................ $ 522 $ 503 $ 19 3.8%
Small Commercial & Industrial.......... 413 264 149 56.4%
Large Commercial & Industrial.......... 532 407 125 30.7%
Public Authorities & Electric Railroads 37 34 3 8.8%
------ ------ -----
1,504 1,208 296 24.5%
------ ------ -----
Unbundled Revenue (2)
Residential............................ 96 103 (7) (6.8%)
Small Commercial & Industrial.......... 5 68 (63) (92.6%)
Large Commercial & Industrial.......... 3 54 (51) (94.4%)
Public Authorities & Electric Railroads -- 1 (1) (100.0%)
------ ------ -----
104 226 (122) (54.0%)
------ ------ -----
Total Electric Retail Revenues......... 1,608 1,434 174 12.1%
Wholesale and Miscellaneous Revenue (3) 114 116 (2) (1.7%)
------ ------ -----
Total Electric Revenue................. $1,722 $1,550 $ 172 11.1%
====== ====== =====

--------
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.
(2) Revenue from customers receiving generation from an alternate supplier
includes a distribution charge and a CTC charge.
(3) Wholesale and miscellaneous revenues include sales, transmission revenue,
sales to municipalities and other wholesale energy sales.

The changes in electric retail revenues for the six months ended June 30,
2002, as compared to the same 2001 period, are as follows:

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

Customer Choice........ $165
Rate Changes........... 39
Weather................ (18)
Other Effects.......... (12)
----
Electric Retail Revenue $174
====

Customer Choice. As of June 30, 2002, the customer load served by alternate
suppliers was 991 MW or 12.8% as compared to 1,102 MW or 14.5% as of June 30,
2001. For the six months ended June 30, 2002, the percent of our total retail
deliveries for which we were the electric supplier was 90.9% in 2002, an 18.2%
increase as compared to 72.7% in 2001. As of June 30, 2002, the number of
customers served by alternate suppliers was 308,866 or 26.4% as compared to
June 30, 2001 of 400,972 or 26.4%. This increase in the customer load and the
percentage of MWh served by us, and the decrease in the number of customers
served by alternative suppliers primarily resulted from customers selecting or
returning to us as their electric generation supplier.

Rate Changes. The increase in revenues attributable to rate changes
primarily reflects the expiration of a 6% reduction in our electric rates
during the first quarter of 2001 and a $26 million increase as a result of the
increase in the gross receipts tax rate effective January 1, 2002. These
increases are partially offset by the timing of a $60 million rate reduction in
effect for 2001 and 2002.

Weather. The weather impact was unfavorable compared to the prior year
primarily as a result of warmer winter weather. Heating degree-days decreased
15% for the six months ended June 30, 2002 compared to the same 2001 period.

Other Effects. Other items affecting revenue during the six months ended
June 30, 2002 include:

Volume. Exclusive of weather impacts, higher delivery volume increased our
revenue by $7 million compared to the same 2001 period.

Other. The payment of $14 million to Exelon Generation related to nuclear
decommissioning cost recovery under an agreement effective September 2001 which
reduced our revenue compared to the prior year and an $11 million settlement of
CTCs by a large customer in the first quarter of 2001.

Our gas sales statistics for the six months ended June 30, 2002 as compared
to the same 2001 period are as follows:

2002 2001 Variance
------- ------- --------

Deliveries in million cubic feet (mmcf) 45,643 48,011 (2,368)
Revenue (in millions).................. $ 293 $ 407 $ (114)

The changes in gas revenue for the six months ended June 30, 2002, as
compared to the same 2001 period, are as follows:

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

Rate Changes $ (63)
Weather..... (30)
Volume...... (22)
Other....... 1
-----
Gas Revenue. $(114)
=====

Weather. The unfavorable weather impact is attributable to warmer winter
weather during the six months ended June 30, 2002 as compared to the same 2001
period. Heating degree-days decreased 15% in the six months ended June 30, 2002
compared to the same 2001 period.

Volume. Exclusive of weather impacts, lower delivery volume affected
revenue by $22 million in the six months ended June 30, 2002 compared to the
same 2001 period. Total deliveries to retail customers decreased 5% in the six
months ended June 30, 2002 compared to the same 2001 period, primarily as a
result of slower economic conditions in 2002 offset by increased customer
growth.

Purchased Power and Fuel Expense

Purchased power and fuel expense for the six months ended June 30, 2002
increased $62 million as compared to the same 2001 period. The increase in fuel
and purchased power expense was primarily attributable to $150 million from
customers in Pennsylvania selecting or returning to us as their electric
generation supplier and higher PJM ancillary charges of $17 million. These
increases were partially offset by $63 million from lower gas prices, $30
million as a result of unfavorable weather conditions and $22 million primarily
attributable to lower delivery volume primarily related to gas.

Operating and Maintenance Expense

O&M expense for the six months ended June 30, 2002 increased $9 million, or
4%, as compared to the same 2001 period. The increase in O&M expense was
primarily attributable to $12 million related to the deployment of automated
meter reading technology and $9 million related to an increased allocation of
corporate expense. These increases were partially offset by $6 million of
incremental storm costs in 2001 and $4 million associated with a write-off of
excess and obsolete inventory in 2001.

Depreciation and Amortization Expense

Depreciation and amortization expense for the six months ended June 30, 2002
increased $21 million, or 11%, as compared to the same 2001 period. The
increase was primarily attributable to $17 million of additional amortization
of our CTC and an increase of $4 million related to depreciation expense
associated with additional plant in service. The additional amortization of the
CTC is in accordance with our original settlement under the Competition Act.

Taxes Other Than Income

Taxes other than income for the six months ended June 30, 2002 increased $38
million, or 45%, as compared to the same 2001 period. The increase was
primarily attributable to additional gross receipts tax related to additional
revenues and an increase in the gross receipts tax rate on electric revenue
effective January 1, 2002.

Interest Charges

Interest charges decreased $40 million, or 18% in the six months ended June
30, 2002 as compared to the same 2001 period. The decrease was primarily
attributable to lower interest expense on long-term debt of $32 million as a
result of principal payments, lower interest rates and an $8 million reduction
in interest expense due to lower interest rates on a loan from ComEd in 2001.

Other Income and Deductions

Other income and deductions excluding interest charges decreased $16
million, or 89% in the six months ended June 30, 2002 as compared to the same
2001 period. The decrease in other income and deductions was primarily
attributable to lower interest income of $6 million in 2002. The decrease was
also attributable to a gain on the settlement of an interest rate swap of $6
million and the favorable settlement of a customer contract of $3 million, both
of which occurred in 2001.

Income Taxes

The effective tax rate was 33.2% for the six months ended June 30, 2002 as
compared to 35.1% for the same 2001 period. The decrease in the effective tax
rate was primarily attributable to a reduction in state income taxes.

Preferred Stock Dividends

Preferred stock dividends for the quarter ended June 30, 2002 were
consistent as compared to the same 2001 period.

LIQUIDITY AND CAPITAL RESOURCES

Our business is capital intensive and requires considerable capital
resources. Our 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. Our access to external financing at
reasonable terms is dependent on our credit ratings and general business
condition and the utility industry. Capital resources are used primarily to
fund 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 the six months ended June 30, 2002
were $468 million compared to $427 million for the six months ended June 30,
2001. The increase in cash flows was primarily attributable to lower payments
related to accounts payable of $46 million, higher collection of deferred
energy costs as a result of a change in gas rates of $42 million and lower
prepaid taxes of $29 million. These increases were partially offset by changes
in intercompany receivables and payables of $41 million and deferred income
taxes of $32 million. Our 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. Our 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 our business, we expect
that we 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 the six months ended June 30,
2002 were $122 million compared to $87 million for the six months ended June
30, 2001. The increase in cash flows used in investing activities was primarily
attributable to an increase in other investing activities. Our investing
activities during the six months ended June 30, 2002 were funded primarily by
operating activities.

Our projected capital expenditures for 2002 are $284 million. Approximately
one half of the budgeted 2002 expenditures are for capital additions to support
customer and load growth and the remainder for additions and upgrades to
existing facilities. We anticipate that we will obtain financing, when
necessary, through borrowings, the issuance of preferred securities, or capital
contributions from Exelon. Our 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 for the six months ended June 30,
2002 were $306 million compared to $332 million for the six months ended June
30, 2001. Cash flows used in financing activities are primarily attributable to
debt service and payment of dividends to Exelon. The change in cash flows used
in financing activities is primarily attributable to an increase in commercial
paper borrowings of $196 million partially offset by additional dividends paid
to Exelon of $69 million, the contribution from Exelon in 2001 of $53 million,
additional debt service of $34 million, and proceeds from the settlement of
interest rate swap agreements in 2001 of $31 million.

Credit Issues

At June 30, 2002, we had outstanding $175 million of notes payable
consisting principally of commercial paper. Certain of the credit agreements to
which we are a party require us to maintain a debt to total capitalization
ratio of 65% or less, excluding securitization debt and excluding the
receivable from parent recorded in our shareholders' equity. At June 30, 2002,
our debt to total capitalization ratio on that basis was 38%.

Our access to the capital markets, including the commercial paper market,
and our financing costs in those markets are dependent on our securities
ratings. None of our 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 our bank credit facility. From time to
time, we enter into interest rate swaps 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.

At June 30, 2002, our capital structure, excluding the deduction from
shareholders' equity of the $1.8 billion receivable from Exelon, consisted of
26% common equity, 2% notes payable, 3% preferred stock and COMRPS (which
comprised 2% of our total capitalization structure), and 69% long-term debt
including transition bonds issued by PECO Energy Transition Trust. Long-term
debt included $4.4 billion of transition bonds representing 52% of
capitalization.

Under PUHCA and the Federal Power Act, we can pay dividends only from
retained or current earnings. At June 30, 2002, we had retained earnings of
$277 million.

Contractual Obligations and Commercial Commitments

Contractual obligations represent cash obligations that are considered to be
firm commitments and commercial commitments represent commitments triggered by
future events. Our contractual obligations and commercial commitments as of
June 30, 2002 were materially unchanged, other than in the normal course of
business, from the amounts as set forth in the December 31, 2001 Form 10-K,
except for an $85 million increase in the amount of surety bonds required by
our insurance policies. Approximately one-fourth of the surety bonds expire in
the remainder of 2002 and the other three-fourths expire in the two-year period
ending December 2004.

RESULTS OF OPERATIONS

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

Summary Financial Information

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

OPERATING REVENUES.................................... $3,965 $5,950 $(2,577) $ 592 $(1,985)
OPERATING EXPENSES
Fuel and Purchased Power........................... 1,802 2,127 (793) 468 (325)
Operating and Maintenance.......................... 587 1,791 (1,299) 95 (1,204)
Merger-Related Costs............................... -- 248 (181) (67) (248)
Depreciation and Amortization...................... 416 325 (142) 233 91
Taxes Other Than Income............................ 161 237 (71) (5) (76)
------ ------ ------- ----- -------
Total Operating Expenses....................... 2,966 4,728 (2,486) 724 (1,762)
------ ------ ------- ----- -------
OPERATING INCOME...................................... 999 1,222 (91) (132) (223)
------ ------ ------- ----- -------
OTHER INCOME AND DEDUCTIONS
Interest Expense................................... (413) (457) 48 (4) 44
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which holds Solely Subordinated, Debentures of
the Company...................................... (10) (8) -- (2) (2)
Equity in Earnings (Losses) of Unconsolidated
Affiliates, Net.................................. -- (41) 41 -- 41
Other, Net......................................... 46 41 (19) 24 5
------ ------ ------- ----- -------
INCOME BEFORE INCOME TAXES,
EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF A CHANGE OF ACCOUNTING
PRINCIPLE........................................... 622 757 (21) (114) (135)
INCOME TAXES.......................................... 197 270 26 (99) (73)
------ ------ ------- ----- -------
NET INCOME BEFORE EXTRAORDINARY ITEM
AND CUMULATIVE EFFECT OF A CHANGE OF
ACCOUNTING PRINCIPLE................................ 425 487 (47) (15) (62)
Extraordinary Item (net of income taxes)........... -- (4) -- 4 4
Cumulative Effect of a Change of Accounting
Principle........................................ -- 24 (24) -- (24)
------ ------ ------- ----- -------
NET INCOME............................................ 425 507 (71) (11) (82)
Preferred Stock Dividends............................. (10) (10) -- -- --
------ ------ ------- ----- -------
NET INCOME ON COMMON STOCK............................ $ 415 $ 497 $ (71) $ (11) $ (82)
====== ====== ======= ===== =======

Net Income

Net income from normal operations decreased $11 million, or 3% in 2001 as
compared to 2000. Our results from normal operations improved as a result of
lower margins due to the unplanned return of certain commercial and industrial
customers, milder weather, increased depreciation and amortization expense and
higher interest expense partially offset by favorable rate adjustments.

Operating Revenues

Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy, the delivery cost of
the transmission and distribution of the energy and a transition charge
(including CTC and intangible transition charge ("ITC")). Unbundled service
reflects customers electing to receive electric generation service from an
alternative energy supplier. Revenue from customers receiving generation from
an alternate supplier includes a transmission and distribution charge and a
CTC/ITC charge. Our electric sales statistics are as follows:

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

Bundled Deliveries
Residential............................ 8,072,915 9,324,800 (1,251,885)
Small Commercial & Industrial.......... 5,997,571 3,918,529 2,079,042
Large Commercial & Industrial.......... 12,960,295 8,291,607 4,668,688
Public Authorities & Electric Railroads 765,554 478,809 286,745
----------- ----------- -----------
27,796,335 22,013,745 5,782,590
----------- ----------- -----------
Unbundled Deliveries
Residential............................ 3,104,811 1,985,614 1,119,197
Small Commercial & Industrial.......... 1,606,067 3,549,667 (1,943,600)
Large Commercial & Industrial.......... 2,351,520 7,404,363 (5,052,843)
Public Authorities & Electric Railroads 7,285 300,978 (293,693)
----------- ----------- -----------
7,069,683 13,240,622 (6,170,939)
----------- ----------- -----------
Total Retail Deliveries................ 34,866,018 35,254,367 (388,349)
=========== =========== ===========
Electric Revenue (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
=========== =========== ===========

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

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

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

Customer Choice. All our 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 us. 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 MW 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 us
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 us 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.

Rate Changes. The increase in revenues attributable to rate changes
reflects the expiration of a 6% reduction in our 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:

. Volume. Exclusive of weather impacts, lower delivery volume affected our
revenue by $21 million compared to the same 2000 period. 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%.

. Other. The payment of $29 million to Exelon 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.

Our 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:

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

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

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. Our 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.

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

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 period in 2000, 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 us or
returning to us 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 our corporate division, $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 approval and settlement
costs, and settlement of compensation arrangements. Employee costs represent
estimated severance payments and pension and postretirement benefits provided
under Exelon's Merger Separation Plan ("MSP") for 642 of our eligible 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 affiliates in the corporate
restructuring were $181 million. The remaining $67 million is attributable to
our energy delivery segment. See Note 2--Corporate Restructuring to
Consolidated Financial Statements.

Depreciation and Amortization Expense

Depreciation and amortization expense for 2001 increased $233 million, or
127%, compared to the same period in 2000, excluding the effects of the
restructuring. The increase was primarily attributable to $214 million of
additional amortization of our 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 our 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 our 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 our 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, our unconsolidated affiliates were
transferred to Exelon Generation and Exelon 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

Our effective tax rate was 31.7% in 2001 as compared to 35.7% in 2000. The
decrease in our 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.

Extraordinary Items

In 2000, we 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 our stranded
cost recovery in May 2000.

Cumulative Effect of a Change in Accounting Principle

In 2000, we 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.

Year Ended December 31, 2000 Compared To Year Ended December 31, 1999

Summary Financial Information

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

OPERATING REVENUES.............................................................. $5,950 $5,478 $ 472
OPERATING EXPENSES
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)
------ ------ -----
OTHER INCOME AND DEDUCTIONS
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.

Operating Revenues

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

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 us 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 Power Station ("Clinton")
resulted in lower revenues of $99 million. As a result of the acquisition by
AmerGen Energy Company, LLC ("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 our
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

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

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.

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

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

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 to our corporate division.

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. Our corporate 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

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 our CTC which commenced in 2000 and $29 million related to
depreciation and amortization expense associated with the infrastructure
services business acquisitions.

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 nonrecurring $22 million capital stock
tax credit related to a 1999 adjustment associated with the impact of our 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 our stranded cost recovery of $104 million, partially offset by
the reduction of our 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
Unit No. 1 at Three Mile Island Nuclear Station ("TMI") in December 1999 and
Oyster Creek Nuclear Generation Facility ("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 1999, we 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.

Cumulative Effect of a Change in Accounting Principle

Preferred Stock Dividends

Preferred stock dividends decreased $2 million, or 17%, to $10 million as
compared to 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, we redeemed
$19 million of Mandatorily Redeemable Preferred Stock in August 2000.

Liquidity and Capital Resources

Our 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. Our access to external financing at
reasonable terms is dependent on our credit ratings and our general business
condition and the utility industry. Our business is capital intensive. Capital
resources are used primarily to fund our 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. Our 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. Our 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 our revenues.
Although the amounts may vary from period to period as a result of the
uncertainties inherent in our business, we expect that we 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. Our 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. We anticipate that we will obtain
financing, when necessary, through borrowings, the issuance of preferred
securities, or capital contributions from Exelon. Our 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
transition bonds. In 2001, we paid Exelon $342 million in common stock
dividends and currently expect that the 2002 dividend will be comparable to
2001.

Credit Issues

We meet our short-term liquidity requirements primarily through the issuance
of commercial paper, borrowings under bank credit facilities and borrowings
from the Exelon intercompany money pool. We, along with Exelon, ComEd and
Generation, are parties to a $1.5 billion unsecured revolving credit facility
with a group of banks. We use this credit facility principally to support our
commercial paper program. We have a $300 million sublimit under this credit
facility.

At December 31, 2001, we 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 we are a party requires us to maintain a debt to total capitalization
ratio of 65% or less, excluding securitization debt and excluding the
receivable from parent recorded in our shareholders' equity. At December 31,
2001, the debt to total capitalization ratios on that basis was 38%.

Our access to the capital markets, including the commercial paper market,
and our financing costs in those markets are dependent on our securities
ratings. None of our 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 our bank credit facility. From time to
time, we enter 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, we can pay dividends only from
retained or current earnings. At December 31, 2001, we had retained earnings of
$270 million.

Contractual Obligations and Commercial Commitments

Our 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
Total 1 Year 2-3 Years 4-5 Years 5 Years
------ ------ --------- --------- ---------
(in millions)

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 Notes to Consolidated Financial Statements for additional information
about:

. long-term debt (see Note 11);

. short-term debt (see Note 10);

. operating leases (see Note 18); and

. COMRPS and Preferred Stock with Mandatory Redemption Requirements (see
Notes 15 and 14, respectively).

Our 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 our obligations, are
as follows:

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

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--We, along with Exelon, ComEd and Exelon Generation,
maintain a $1.5 billion 364-day credit facility to support commercial paper
issuances. We have 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)--We and certain of our 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

We are party to an agreement with a financial institution under which we 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, we had sold a $225 million interest in accounts receivable,
consisting of a $170 million interest in accounts receivable which we 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. We retain the
servicing responsibility for these receivables. The agreement requires us to
maintain the $225 million interest, which, if not met, requires us to deposit
cash in order to satisfy such requirements. At December 31, 2001 and 2000, we
met this requirement and were not required to make any cash deposits.

Other Factors

the Exelon plans. Essentially all of our 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 our former pension
plans on December 31, 2000 and remain employed by us 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. We may be required to increase future
funding to the pension plan as a result of these increased cash requirements.

Due to the performance of the U.S. 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.

We are currently subject to a rate cap that limits the opportunity to
recover increased costs and the costs of new investment in facilities through
rates during the rate cap period. Current rates include the recovery of our
existing regulatory assets. We continually assess 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.

Accounting for Derivative Instruments

We use derivatives to manage our 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 our 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 we 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 we 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

Our 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 our transmission and distribution
assets and provide a significant and steady source of earnings.

Under restructuring regulations adopted at the federal and state levels, the
role of electric utilities in the supply and delivery of energy is changing. We
continue to be obligated to provide reliable delivery systems under cost-based
rates. We remain 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.

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

. to deliver electricity and gas to our customers cost-effectively;

. to realize cost savings and synergies from the merger to offset increased
costs on new investments and inflation while our delivery rates are
capped; and

. to manage our provider-of-last-resort responsibilities.

Our results will be affected by annual increases in the amortization of our
stranded cost recovery through 2010. We have been authorized by the PUC 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 our
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 our customers have the choice of purchasing energy from other
electricity suppliers. At June 30, 2002, approximately 23% of our residential
load, 7% of our small commercial and industrial load and 6% of our large
commercial and industrial load were purchasing generation service from
alternative suppliers.

We have entered into a long-term agreement with our affiliate Exelon
Generation to procure our power needs and achieve some certainty during the
next several years with respect to these obligations. Because our agreement
with Exelon Generation allows us to obtain sufficient power at the rates we are
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. We provide 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
a regional transmission operation ("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.

We provide regional transmission service pursuant to a regional open-access
transmission tariff we and the other transmission owners who are members of
Pennsylvania-New Jersey-Maryland Interconnection, LLP ("PJM") file. 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. We 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 us, have filed with FERC for approval
of PJM as an RTO. FERC has conditionally approved the PJM RTO.

Other Factors

Inflation affects us 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, we may not
be able to pass the costs of inflation through to customers.

We participate in defined benefit pension plans and postretirement welfare
sponsored by Exelon. Essentially all of our employees are eligible to
participate in these plans. In 2001, our former plans were consolidated into
the Exelon plans. Our costs of providing pension and postretirement benefits to
our retirees is dependent upon a number of factors, such as the discount rate,
rates of return on plan assets, and the assumed rate of increase in health care
costs. Although our 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 our pension and postretirement benefit plans, see Note 13--Retirement
Benefits of the Notes to Consolidated Financial Statements.

Environmental. Our 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, we are
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by us and of property contaminated by hazardous
substances we have generated. We own or lease a number of real estate parcels,
including parcels on which our operations or the operations of others may have
resulted in contamination by substances that are considered hazardous under
environmental laws. We have identified 28 sites where former MGP activities
have or may have resulted in actual site contamination. We are 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, we 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 Exelon Generation. We
expect to expend $2 million for environmental remediation activities in 2002.
We cannot predict whether we will incur other significant liabilities for any
additional investigation and remediation costs at these or additional sites we
identify, 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 our operating procedures and costs and are
expected to affect the cost and availability of the insurance coverages that we
carry. We have initiated security measures to safeguard our employees and
critical operations and are actively participating in industry initiatives to
identify methods to maintain the reliability of our 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. We are 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.

We carry property damage and liability insurance for our 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.

We are self-insured to the extent that any losses may exceed the amount of
insurance maintained. Damage to our properties could disrupt the transmission
or distribution electricity and significantly and adversely affect results of
operations. We cannot predict the effects on operations of the availability of
property damage and liability coverage or any disruptions to our delivery
facilities.

New Accounting Pronouncements

In 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("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, we did not have any
goodwill reflected on our Consolidated Balance Sheets and we do 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 our goodwill
was transferred to Exelon Enterprises.

SFAS No. 143 provides accounting requirements for retirement obligations
associated with tangible long-lived assets. We expect 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. We
are currently in the process of evaluating the impact of SFAS No. 143 on our
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. We are in the process of evaluating the
impact of SFAS No. 144 on our financial statements, and do not expect the
impact to be material.

Quantitative And Qualitative Disclosures About Market Risk

Commodity Price Risk

We are 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 risk management committee 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 power purchase agreement with Exelon Generation,
we do not believe we are subject to material commodity price risk.

Credit Risk

We are obligated to provide service to all electric customers within our
franchised territory. As a result, we have a broad customer base. For the year
ended December 31, 2001, our ten largest customers represented approximately
10% of our retail electric revenues. Our credit risk is managed by our 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 our
retail electric service territory. Currently, there are no third parties
billing our charges to customers or providing advanced metering. However, if
others enter this business, we would be subject to credit risk related to the
ability of the third parties to collect such receivables from the customers.

Interest Rate Risk

We use 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. We also use 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.

We have entered into interest rate swaps to manage interest rate exposure
associated with the floating rate series of transition bonds issued by our
subsidiary, PECO Energy Transition Trust ("PETT") to securitize our stranded
cost recovery. At June 30, 2002, these interest rate swaps had a fair market
value exposure of $21 million based on the present value difference between the
contract and market rates at June 30, 2002.

The aggregate fair value exposure of the transition bond derivative
instruments that would have resulted from a hypothetical 50 basis point
decrease in the spot yield at June 30, 2002 is estimated to be $23 million. If
the derivative instruments had been terminated at June 30, 2002, this estimated
fair value represents the amount we would have paid to the counterparties.

The aggregate fair value exposure of the transition bond derivative
instruments that would have resulted from a hypothetical 50 basis point
increase in the spot yield at June 30, 2002 is estimated to be $18 million. If
the derivative instruments had been terminated at June 30, 2002, this estimated
fair value represents the amount we would have paid to the counterparties.

In 1999, we entered into interest rate swaps relating to the Class A-3 and
Class A-5 Series 1999-A transition bonds issued by PETT in the aggregate
notional amount of $1.1 billion with an average interest rate of 6.65%. We 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, we 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, we 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, we 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 by PETT in the second quarter of 2000. In May 2000, we 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.

BUSINESS

Overview

Incorporated in Pennsylvania in October 1929, we are a wholly owned
subsidiary of Exelon. We are 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. We have the franchise
rights necessary to furnish electric and gas service in the various
municipalities or territories in which we now supply these services. Our
franchise rights, which are generally nonexclusive, consist of charter rights
and certificates of public convenience issued by the PUC and/or "grandfather
rights" and are generally time unlimited.

Our gas and electricity retail service territory covers 2,107 square miles
in southeastern Pennsylvania.

. We provide electric delivery service in an area of 1,972 square miles,
with a population of approximately 3.6 million, including 1.6 million in
the City of Philadelphia.

. We supply natural gas service in a 1,475 square mile area in southeastern
Pennsylvania counties adjacent to Philadelphia, with a population of 1.9
million.

. We deliver electricity to approximately 1.6 million customers and natural
gas to approximately 440,000 customers.

Our kilowatthour ("kWh") sales and load are generally higher, primarily
during the summer periods and also during the winter periods, when temperature
extremes create demand for either summer cooling or winter heating. Our highest
peak load experienced to date occurred on August 14, 2002 and was 8164 MWs; and
the highest peak load experienced to date during a winter season occurred on
January 17, 2000 and was 6,135 MWs.

As a result of Exelon's restructuring to separate its regulated and
competitive businesses, effective January 1, 2001, we transferred assets and
liabilities unrelated to energy delivery to other subsidiaries of Exelon. We
transferred the assets and liabilities related to nuclear, fossil and
hydroelectric generation and wholesale power marketing; unregulated ventures,
including communications, infrastructure services and unregulated gas and
electric sales; and administrative, information technology and other support
services.

Retail Electric Services

Electricity distribution and transmission is a regulated business. The
Pennsylvania Public Utility Commission regulates electric distribution rates,
retail gas rates, issuances of securities, and certain other aspects of our
business. FERC regulates wholesale electric transmission and sets rates for our
wholesale transmission service. Substantially all of our retail revenues are
subject to regulation by the PUC. Generally, if our costs to serve customers
exceed our regulated rates, we can petition the PUC and FERC for rate
increases, but there is no assurance the request for a rate increase will be
approved. In addition, in connection with the implementation of competition for
generation services in Pennsylvania, our overall rates and rates for
distribution services in Pennsylvania were subject to rate caps.

Electric utility restructuring legislation was adopted in Pennsylvania in
December 1996 and electricity generation was deregulated. Through the PUC,
Pennsylvania established a phased approach to competition, allowing an
increasing number of 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").

Our distribution rates are 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, are
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 us to earn a fair rate of return.

Under the settlement agreement that we entered into relating to the PUC's
approval of the merger between us and Unicom to form Exelon, we agreed to $200
million in aggregate rate reductions for all customers over the period 2002
through 2005 and extended the rate cap on distribution rates through December
31, 2006.

We have 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%. Our recovery of stranded costs is based on the level of
transition charges established in the settlement of our restructuring case and
the projected annual retail sales in our service territory. Recovery of
transition charges for stranded costs and our allowed return on its recovery of
stranded costs are included in operating revenue.

Under the Competition Act, all of our retail electric customers have the
right to choose their generation suppliers. At June 30, 2002, approximately 23%
of our residential load, 7% of our small commercial and industrial load and 6%
of our large commercial and industrial load were purchasing generation service
from alternative suppliers.

In order to have a reliable electricity delivery system during the
transition to a competitive market for electricity generation, the PUC required
utilities in Pennsylvania to provide generation services (power and energy) to
those customers who do not or cannot choose an alternate generation provider
or, who choose to come back to us after taking service from an alternate
supplier (called the "provider-of-last-resort obligation"). Because the choice
is with the customer, it is hard for us to predict and plan for any level of
customers and associated energy demand. We have entered into a power purchase
agreement with our affiliate Exelon Generation to provide as much generation as
we need at a fixed price through 2010. After that contract expires, if we still
have provider-of-last-resort obligations, we could be faced with having to
provide power and energy to an ever-increasing customer base, returning to us
in order to receive the benefit of regulated rates. Without changes to the
provider-of-last-resort obligations, we could be required to maintain
sufficient reserves to service 100% of our traditional service territory load
at the tariffed rate on the chance that all customers decide to come back.
Significant over or under estimations of the market or the necessary reserves
could have serious consequences for our business.

As part of a 1998 settlement agreement that we entered into with the PUC, we
developed certain forward-looking financial information. The following table
shows the estimated average levels of stranded cost recovery and the
amortization of the remaining portion of our authorized stranded cost recovery
($4.8 billion at June 30, 2002) for the years 2002 through 2010, based on
estimated 0.8% annual sales growth assumed in the 1998 settlement. The
following table shows the estimated average levels of competitive transition
charges and/or intangible transition charges for the years 2002 through 2010,
based on estimated 0.8% annual sales growth assumed in the restructuring
settlement. The projected amounts included within the Annual Stranded Cost
Amortization and Return disclosure in this section were not prepared with a
view toward compliance with published guidelines of the SEC, the guidelines
established by the American Institute of Certified Public Accountants for
preparation and presentation of financial projections or generally accepted
accounting principles. Additionally, PricewaterhouseCoopers LLP, as described
in the "Experts" section, has neither examined nor compiled these projected
amounts.

Annual Stranded Cost
Amortization And Return

Revenue Excluding Gross Receipts Tax
Stranded ------------------------------------
Cost Return
Recovery @
Year Annual Sales (1) Charge (2) Total 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.

The Competition Act provides for the imposition and collection of
non-bypassable CTCs on customers' bills as a mechanism for utilities to recover
their allowed stranded costs. CTCs are assessed to and collected from all
retail customers who have been assigned stranded cost responsibility and who
access the utilities' transmission and distribution systems. As a result, 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 the
1998 settlement of its restructuring case, we agreed to negotiate with certain
of our large customers for the payment of their stranded investment obligations
in a single lump sum. On January 11, 2002, a complaint was brought by a
municipal authority requesting that the PUC require us to adopt specific
procedures for such negotiations, including setting a specific discount rate.
The complaint alleges that we are using an inappropriate discount rate in our
evaluations, thus making the lump-sum payment of CTC financially unattractive
to customers. A procedural schedule for this matter has been set, and it will
be litigated through the fourth quarter of 2002.

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 our
retail electric service territory. In that event, the alternative supplier or
other third party replaces the customer as the obligor of the customer's bill
and we generally have no right to collect these receivables from the customer.
We can only physically disconnect or reconnect a customer's distribution
service. Third-party billing would change our 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 our retail electric service
territory. To date, no third parties are providing billing of our charges to
customers or advanced metering.

As permitted by the Competition Act and the settlements, we securitized $4
billion and $1 billion of our stranded cost recovery in 1999 and 2000,
respectively, by the issuance of transition bonds through a special purpose
financing entity. As required by the Competition Act, the proceeds from the
securitizations were applied to reduce our stranded costs, including related
capitalization. In March 2001, approximately $805 million of the first series
of transition bonds were refinanced.

The 1998 settlement also included a number of provisions designed to
encourage competition for generation services. Shopping credits for generation
service were intended to provide an economic incentive for customers to choose
an alternate supplier. Effective January 1, 2001, we also agreed to assign 20%
of our non-shopping residential customers to competitive default service
provided by one or more alternate suppliers. If, on January 1, 2003, 50% of our
residential and commercial customers are not obtaining generation services from
alternate generation suppliers, then non-shopping customers will be assigned to
alternate generation suppliers to reach that level.

On November 29, 2000, the PUC approved a bilateral contract between us and
New Power Company to move 22% of our non-shopping residential customers to New
Power for competitive default service ("CDS"). Under this contract, New Power
agreed to provide generation services through January 2004, at specified
discounted rates, to nearly 300,000 of our residential customers who were
taking our generation service. On February 22, 2002, however, New Power sent us
a notice of intent to withdraw from providing CDS to approximately 180,000
residential customers in May 2002. As a result of that withdrawal,
approximately 180,000 CDS customers were returned to us in the second quarter
of 2002. Pursuant to a tariff filing approved by the PUC, we will serve those
returned customers at the discount energy rates on generation provided for
under the original New Power CDS Agreement for the remaining term of that
contract. Subsequently, in the second quarter of 2002, New Power also advised
us that it planned to withdraw from serving all of its customers in
Pennsylvania, including approximately 15,000 of our non-CDS customers, and to
return those customers to us in September 2002.

In addition to the New Power contract, we also entered into a contract with
Green Mountain Energy Company ("Green Mountain") to assign 50,000 of our
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
June 30, 2002, approximately 16,000 customers, or 32%, have opted to return to
us.

Transmission Services

We provide wholesale and unbundled retail transmission service under rates
established by FERC and we provide regional transmission service pursuant to a
regional open-access transmission tariff filed with FERC by us 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
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. We and the other transmission owners in PJM have turned
over control of our respective transmission facilities to the PJM ISO. The PJM
ISO and the transmission owners who are members of PJM, including us, have
filed with FERC for approval of PJM as an RTO. FERC has conditionally approved
the PJM RTO.

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

In April 1996, FERC issued Order 888. The intent of Order 888 is 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. Under Order 889,
we, along with all owners of transmission facilities, were required to file
Standards of

Conduct, which governed the 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.

In December 1999, FERC issued Order 2000, which encourages the voluntary
restructuring of transmission operations through the use of 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 or energy. 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) addressing geographic
scope and governance of RTOs; and (2) addressing transmission pricing and
market design. Contemporaneously, FERC initiated several immediate steps to
move the RTO development process forward. One of these actions was the
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 (the "SMA")
screen. Under the SMA, if an energy company's generation capacity within a
particular geographic market exceeds the market's surplus capacity above peak
demand, then the energy company fails the test. 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 would 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 in early
2002, FERC announced 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 our
business may be impacted by these initiatives.

Gas

Historically, our gas sales and gas transportation revenues were derived
pursuant to rates regulated by the PUC. The PUC established, through regulated
proceedings, the base rates that we may charge for gas service in Pennsylvania.
Our 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.

Since 1984, large commercial and industrial customers have been able to
choose their gas suppliers. 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 our 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, which remains subject to rate
regulation. Gas distribution companies continue to provide billing, metering,
installation, maintenance and emergency response services.

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

Construction Budget

The following table shows PECO's most recent estimate of capital
expenditures for our plant additions and improvements in for 2002:

Transmission and Distribution $203 million
Gas.......................... 70 million
Other........................ 11 million
------------
Total........................ $284 million

Approximately one-half of our 2002 budgeted capital expenditures are for
additions to or upgrades of our existing facilities, including reliability
improvements. The remainder of the capital expenditures support for new
construction upgrades, customer and load growth.

Properties

Our electric substations and a portion of the transmission rights of way 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, which we have deemed satisfactory, but without examination of
underlying land titles, have been obtained.

Transmission and Distribution. Our higher voltage electric transmission and
distribution lines owned and in service are as follows:

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

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

Our 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 our gas pipeline miles at December 31,
2001:

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

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

We have 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, we own 28 natural gas city
gate stations at various locations throughout our gas service territory.

Mortgage

Our principal properties are subject to the lien of our Mortgage dated May
1, 1923, as amended and supplemented, under which we have outstanding
approximately $1,139 million of first mortgage bonds as of June 30, 2002.

Our Subsidiaries with Publicly Held Securities

PECO Energy Transition Trust ("PETT"), a Delaware business trust wholly
owned by us, was formed on June 23, 1998 pursuant to a trust agreement between
us, as grantor, First Union Trust Company, National Association (now Wachovia
Bank, National Association), as issuer trustee, and two beneficiary trustees
that we appointed. PETT was created for the sole purpose of issuing transition
bonds to securitize a portion of our 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
us to PETT.

PECO Energy Capital Corp., our wholly owned subsidiary, is the sole general
partner of PECO Energy Capital, L.P., a Delaware limited partnership (the
"Partnership"). The Partnership was created solely for the purpose of issuing
preferred securities, representing limited partnership interests and lending to
us the proceeds thereof and entering into similar financing arrangements. Our
loans are evidenced by our subordinated debentures (the "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 $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.

Environmental Matters

General

Our operations are subject to environmental regulation by the U.S. and by
the Commonwealth of Pennsylvania and its local jurisdictions. The U.S.
Environmental Protection Agency ("EPA") administers certain federal statutes
relating to such matters. The Pennsylvania Department of Environmental
Protection ("PDEP") has jurisdiction over environmental control in the
Commonwealth of Pennsylvania. State regulation includes the authority to
regulate air, water and noise emissions and solid waste disposals.

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. Pennsylvania has
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.

We have become and 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 December 1987, the EPA notified several entities,
including us, that we 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 us, 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. Our 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. We are unable to estimate its share of
the costs of the remedial activities.

MGP Sites

MGPs manufactured gas in Pennsylvania from approximately 1850 to 1950. We
have identified twenty-eight sites where former MGP activities may have
resulted in site contamination. We are presently engaged in

performing various levels of activities at these sites, including initial
evaluation to determine the existence and nature of the contamination, detailed
evaluation to determine the extent of the contamination and the necessity and
possible methods of remediation, and implementation of remediation. Overseeing
state regulatory agencies have approved the remediation of five MGP sites,
while eleven other sites are currently under some degree of active study or
remediation. As of June 30, 2002, we had accrued $34 million for various
environmental investigation and remediation costs that can be reasonably
estimated, including $25 million for investigation and remediation of these MGP
sites. We believe that we could incur additional liabilities with respect to
MGP sites, which cannot be reasonably estimated at this time. We have sued a
number of insurance carriers seeking indemnity/coverage for remediation costs
associated with these former MGP sites.

Our budget for capital requirements for 2002 for compliance with
environmental requirements total approximately $2 million. In addition, we may
be required to make significant additional expenditures not presently
determinable.

Employees

As of June 30, 2002, we had approximately 2,700 employees. Over the past
several years, a number of unions have filed petitions with the National Labor
Relations Board to hold certification elections for different segments of our
employees. In all cases, our employees have rejected union representation. On
August 15, 2002, the International Brotherhood of Electrical Workers filed a
petition to conduct a unionization vote of our employees.

Litigation

We are involved in a number of judicial and regulatory proceedings
concerning matters arising out of the conduct of our business. We believe,
based on currently available information, that the ultimate outcome of any
proceedings known to us at this time will not have a material adverse effect on
our financial condition or results of operations.

MANAGEMENT

Currently some of our officers are also officers of Exelon or one of its
subsidiaries other than PECO.

Our executive officers and their ages as of December 31, 2001 are as follows:

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

McNeill, Jr. Corbin A 62 Co-Chief Executive Officer and Chairman, Exelon and Director, PECO*
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 and Director, PECO
Gillis, Ruth Ann M... 47 Senior Vice President and Chief Financial Officer, Exelon and Director, PECO
Lawrence, Kenneth G.. 54 President and Chief Operating Officer, Energy Delivery, Exelon and President,
PECO
Frankowski, Frank F.. 51 Vice President, Finance and Chief Financial Officer, PECO

--------
* Retired as of April 23, 2002

Each of the above was elected as an executive officer effective October 20,
2000, the closing date of the merger, except for Frank F. Frankowski, who was
elected effective October 22, 2001.

Each of the above executive officers holds such office at the discretion of
our board of directors until his or her replacement or earlier resignation,
retirement or death.

Corbin A. McNeill, Jr. 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. Mr.
McNeill retired as of April 23, 2002.

John W. Rowe. Mr. Rowe is Co-Chief Executive Officer and President of
Exelon and a Director of PECO and ComEd. Prior to his election to his current
position, Mr. Rowe was Chairman, President and Chief Executive Officer of ComEd
and Unicom Corporation; and President and Chief Executive Officer of New
England Electric System. Mr. Rowe is also a director of UnumProvident
Corporation. Upon Mr. McNeill's retirement, Mr. Rowe becomes Chief Executive
Officer, President of Exelon and a Director of PECO.

Pamela B. Strobel. 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.

Ruth Ann M. Gillis. 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.

Kenneth G. Lawrence. 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.

Frank F. Frankowski. 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.

COMPENSATION

We originally established the Management Incentive Compensation Plan
("MICP") in 1988 and amended it in 1997. In connection with the merger, Exelon
assumed sponsorship of the MICP.

The MICP provides for annual awards of cash, stock, or other currency
("Awards") to key employees (employees so designated by a Committee of Exelon's
Board of Directors, including employees who are officers or directors) based on
achievement of certain pre-established goals. The maximum annual Awards payable
to any participant is two million dollars.

The MICP is administered and interpreted by a Committee ("Committee")
consisting of two or more outside, non-employee directors of Exelon. The
Committee has the full power to select the employees who will receive Awards
under the MICP; determine the amounts and forms of Awards; determines the terms
and conditions of Awards in a manner consistent with the MICP; construe and
interpret the MICP and any agreement or instrument entered into under the MICP;
make factual determinations; and, establish, amend, or waive rules and
regulations for the MICP's administration.

In order to qualify as performance-based compensation, the Committee must
establish performance goals and the formula for applying such goals in
determining Awards (within 90 days after the commencement of the applicable
performance period or before 25% of the performance period has elapsed, if
shorter than 12 months). During the performance period, the Committee may
modify performance goals or the formula for applying such goals; provided,
however, that the Committee cannot increase the Award otherwise payable to
employees subject to section 162(m) of the Internal Revenue Code under the
goals and formula initially adopted. The Committee may, however, reduce or
eliminate the Award otherwise payable.

The performance goals are based on business criteria chosen by the Committee
from among the following alternatives, each of which may be based on absolute
standards or peer industry group comparatives and may be applied at various
organizational levels (e.g., corporate, business unit, division): a) total
shareholder return; b) stock price increase; c) dividend payout as percentage
of net income; d) return on equity; e) return on capital; f) cash flow,
including operating cash flows, free cash flow, discounted cash flow return on
investment, and cash flow in excess of cost of capital; g) economic value added
(income in excess of capital costs); h) cost per kilowatt hour; i) market
share; j) customer/employee satisfaction as measured by survey instruments; k)
earnings per share; l) revenue; m) workforce diversity; n) safety; o) personal
performance; p) productivity measures; q) diversification of business
opportunities; r) price to earnings ratio; s) expense ratio; t) total
expenditures; and u) completion of key projects.

We also originally established the Exelon Long-Term Incentive Plan
("Incentive Plan") in 1989 as the PECO Energy Company 1989 Long-Term Incentive
Plan. In connection with the exchange of our shares for shares of Exelon
Corporation and the merger, Exelon assumed sponsorship of the Incentive Plan
and the Incentive Plan was amended to change its name and otherwise reflect the
share exchange and the merger.

Employees of Exelon and its subsidiary companies (including us) are eligible
to be selected to participate in the Incentive Plan. Approximately 650 persons
are eligible to participate in the Incentive Plan.

The Incentive Plan authorizes the following types of grants singly, in
combination or in tandem:

Stock Options. Grants consist of options to purchase shares of Exelon
Common Stock, which may be "incentive stock options" or non-qualified stock
options. Incentive stock options must meet the requirements of Section 422 of
the Internal Revenue Code and carry some potential tax advantages for the
recipient. Non-qualified stock options are not subject to those requirements
and do not carry such advantages. Each stock option grant specifies the number
of shares subject to the option, the manner and time of the option's exercise
and the exercise price per share of stock subject to the option. The exercise
price of stock option may not be less than the

fair market value of a share of Exelon Common Stock on the date the option is
granted. The exercise price of an option may be paid by a participant in cash,
shares of Exelon Common Stock owned by the participant if approved by Exelon's
Compensation Committee, a combination thereof or such other consideration as
the Compensation Committee may deem appropriate.

Stock Appreciation Rights. A stock appreciation right ("SAR") is a right to
receive a payment (either in cash, shares of Exelon Common Stock, or a
combination thereof) equal to the appreciation in market value of a stated
number of shares of Exelon Common Stock. The appreciation is measured by the
difference between a base amount stated in the SAR and the market value of a
share of Exelon Common Stock on the date of exercise of the SAR. A SAR may be
granted in tandem with a stock option ("Tandem SARS") or independent of a stock
option ("Non-tandem SARs"). A Tandem SAR may be granted either at the time of
the grant of the related stock option or, in the case of a non-qualified stock
option, at any time thereafter during the term of such option. Upon the
exercise of a stock option as to some or all of the shares covered by the
award, the related Tandem SAR is cancelled automatically to the extent that the
number of shares subject to the Tandem SAR exceeds the number of remaining
shares subject to the related stock option.

Restricted Stock. Grants are made of restricted shares of Exelon Common
Stock. Such grants will be subject to such terms, conditions, restrictions
and/or limitations, if any, as Exelon's Compensation Committee deems
appropriate, which may include vesting periods, restrictions on transferability
and requirements of continued employment.

Performance Shares and Performance Units. Performance shares are shares of
Exelon Common Stock and performance units which are valued by reference to
criteria chosen by Exelon's Compensation Committee. Such grants are contingent
on the attainment over a specified period of time of certain performance
objectives. The length of the performance period, the performance objectives to
be achieved and the measure of whether and to what degree such objectives have
been achieved are determined by Exelon's Compensation Committee. Amounts earned
under performance shares and performance units may be paid in cash, shares of
Exelon Common Stock or both.

Phantom Stock. Phantom stock is a grant expressed in terms of, but not
actually represented by, a number of shares of Exelon Common Stock. Exelon's
Compensation Committee establishes the initial value of the phantom stock at
the time of grant, which may be greater than, equal to or less than the fair
market value of a share of Exelon Common Stock. Exelon's Compensation Committee
also determines the time at which the phantom stock will be paid and whether
such payment will be in the form of cash, shares of Exelon Common Stock or a
combination of both. Any cash payment will be the fair market value of shares
of Exelon Common Stock on the payment date equal in number to the number of
shares of phantom stock being paid in cash.

Dividend Equivalents. Each dividend equivalent represents the right to
receive an amount in cash, or in shares of Exelon Common Stock having a fair
market value, equal to the amount of each dividend paid on one share of Exelon
Common Stock during a period of time established by Exelon's Compensation
Committee. Dividend equivalents may be paid currently or accrued as contingent
cash obligations payable at a time or times specified by Exelon's Compensation
Committee. Dividend equivalents may be granted separately or in connection with
grants of stock options or phantom stock under the Incentive Plan.

The Incentive Plan currently limits the maximum aggregate number of shares
of Exelon Common Stock that may be granted to any given individual in any
calendar year to 500,000 (proposed to be amended to 1,000,000). The proposed
amendment also adds to the Incentive Plan a provision that limits the number of
shares available to be granted under the Incentive Plan at full value as
restricted stock, performance shares or phantom stock to 3,000,000.

Grants are evidenced by written agreements containing the terms, conditions,
restrictions and/or limitations covering the grant.

Available Shares and Outstanding Awards. On October 20, 2000, the effective
date of the exchange of our shares for shares of Exelon Common Stock and the
merger, 10,800,000 shares of Exelon Common Stock were available for grants
under the Incentive Plan. Since then, grants covering 9,883,672 shares have
been made under the Incentive Plan and grants covering 232,651 shares have
expired or been forfeited, leaving approximately 1,148,979 shares of Exelon
Common Stock available for future grants under the Incentive Plan as of March
1, 2002. Approval of the proposed amendment of the Incentive Plan will increase
the number of shares available for future grants under the Incentive Plan to
approximately 14,148,000. As of July 1, 2002, the market price of Exelon Common
Stock was $51.44 per share.

The Exelon Corporation Employee Stock Purchase Plan ("Purchase Plan") was
adopted by the Board of Directors of Exelon Corporation on May 11, 2001 and
became effective on June 1, 2001, subject to approval by the shareholders of
Exelon Corporation in April 2002 at the annual meeting. If shareholders do not
approve the Purchase Plan, it will cease to be effective on May 10, 2002.

Under the Purchase Plan, eligible employees of Exelon and designated
subsidiaries including us may authorize their employers to withhold up to 10%
of their regular base pay and to use those amounts to purchase shares of Exelon
Common Stock. The Purchase Plan establishes four purchase periods beginning on
January 1, April 1, July 1 and October 1 of each year. A participant's payroll
deductions are accumulated and used to purchase shares of Exelon Common Stock
as soon as practicable after the end of each purchase period. The purchase
price per share for any purchase period is equal to 90% of the lesser of the
closing price on the New York Stock Exchange of a share of Exelon Common Stock
on the first day of the purchase period or the last day of the purchase period
on which the Exchange is open. Dividends on shares purchased under the Purchase
Plan will be paid in cash unless the participant elects to have the dividends
reinvested to purchase additional shares of Exelon Common Stock. Shares
purchased with reinvested dividends will be purchased at fair market value with
no discount. In addition to the 10% limit on payroll deductions, a participant
in the Purchase Plan may not purchase more than 125 shares in any purchase
period (500 shares per year) or more than $25,000 in fair market value of stock
in any calendar year. An individual's purchases under the Purchase Plan also
will be limited if they would cause the employee to own 5% or more of the total
combined voting power or value of all classes of stock of Exelon Corporation or
any of its subsidiaries.

Under the terms of the Purchase Plan, the maximum number of shares of Exelon
Common Stock that may be purchased under the Purchase Plan is 3,000,000,
subject to adjustment for stock dividends, stock splits or combinations of
shares of Exelon Common Stock. Through the purchase period that ended December
31, 2001, 137,648 shares of Exelon Common Stock had been purchased under the
Purchase Plan. John Rowe, President and Chief Executive Officer of our parent,
has purchased 394 shares under the Purchase Plan. As of June 30, 2002,
approximately 27,801 employees were eligible to participate in the Purchase
Plan and 3,552 were participating in the Purchase Plan.

In 2001, Exelon adopted a cash balance pension plan. All management and
electing union employees who joined Exelon or one of its participating
subsidiaries, including us, during 2001 become participants in the plan.
Management employees who were active participants in Exelon's previous
qualified defined plans at December 31, 2000 and are employed by Exelon in
January 1, 2002 will be given a choice to convert 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 requirements for pension plan assets. Exelon may
be required to increase future funding to the pension plan as a result of these
increased cash requirements.

SUMMARY COMPENSATION TABLE

Compensation of Executive Officers

The following table shows the compensation for the last three years, ending
December 31, 2001, of Exelon's Co-CEO's and our executive officers who also
served as our directors and officers.

Annual Compensation Long Term Compensation
----------------------------------------- --------------------------------------------------
Bonus Awards Payouts
--------------------------- ------------------ --------------------
Restricted All Other
Stock- Stock Stock- Compen-
Salary Cash Based Other Awards Options Cash Based sation
Name and Principal Position Year ($) ($) ($)(1) ($)(2) ($) (#)(3) ($) ($)(1) ($)
--------------------------- ---- --------- --------- ------- ------- ---------- ------- --------- --------- ---------

Corbin A. McNeill, Jr............ 2001 1,050,000 1,500,300 0 84,987 1,354,104 233,000 0 0 26,573
Co-CEO & Chairman, 2000 855,830 1,081,472 0 0 2,803,513 392,500 0 0 3,200
Exelon Corp.; 1999 659,857 1,000,000 0 0 942,188 0 0 0 3,200
Chairman & President, Exelon
Generation
John W. Rowe..................... 2001 1,050,000 1,500,300 0 71,369 1,354,104 233,000 0 0 52,729
CEO & President, 2000 989,423 1,180,269 0 134,473 0 385,450 1,071,878* 1,071,878* 60,293
Exelon Corp.; 1999 957,692 529,125 529,125* 55,112 0 116,850 * * 42,478
Chairman, Exelon Energy 475,246 203,677*
Delivery & Exelon Enterprises
Pamela B. Strobel................ 2001 450,000 500,500 0 0 378,187 0 0 0 23,605
EVP, Exelon Corp.; 2000 377,423 269,824 0 0 0 122,250 331,618 331,618* 19,181
Vice Chair & CEO 1999 375,131 208,961 69,654* 0 0 28,500 84,410 84,410* 16,483
Exelon Energy
Delivery; Chair,
ComEd and PECO
Energy
Kenneth G. Lawrence.............. 2001 370,577 378,700 0 0 243,979 0 0 0 14,029
Sr. VP, Exelon Corp.; 2000 318,923 225,666 0 0 777,112 81,600 0 0 4,093
President & COO, 1999 291,847 241,200 0 0 94,219 0 0 0 3,200
Exelon Energy
Delivery; President,
PECO Energy
Ruth Ann M. Gillis............... 2001 330,000 221,800 0 0 243,979* 0 0 0 16,620
Sr. VP & Chief 2000 305,770 216,330 24,037 0 0 86,750 0 431,405* 13,300
Financial Officer, 1999 300,163 135,923 45,307 0 0 23,750 0 94,773 13,060
Exelon Corp.
Frank F. Frankowski.............. 2001 148,120 76,823 0 0 6,457* 0 0 0 7,400
VP & Chief Financial 2000 134,040 43,120 0 0 0 7,000 0 0 4,410
Officer, PECO 1999 123,960 52,400 0 0 0 4,166 0 0 8,544

--------
(1) All of the amounts shown under "Bonus--Stock-Based" and "Long Term
Compensation Payouts--Stock-Based" were either paid in shares of Exelon
common stock or were deferred and since the merger, are deemed to be
invested in shares of Exelon common stock, and thus fully "at risk" until
the end of the deferral period. Deferred amounts are noted with an asterisk.
(2) Excludes perquisites and other benefits, unless the aggregate amount of
such compensation is at least $50,000. For 2001, includes $42,805 paid to
Mr. McNeill for financial and legal services and $22,879 paid to Mr. Rowe
for the payment of other taxes.
(3) Grants of options to Mr. Rowe, Ms. Strobel, and Ms. Gillis prior to the
merger have been adjusted to reflect the substitution of options to acquire
shares of Exelon common stock in accordance with the merger agreement.

Option Grants in 2001

The "grant date present values" indicated in the option grant table below
are an estimate based on the Black-Scholes option pricing model. Although
executives risk forfeiting these options in some circumstances, these risks are
not factored into the calculated values. The actual value of these options will
be determined by the excess of the stock price over the exercise price on the
date that the options are exercised. There is no certainty that the actual
value realized will be at or near the value estimated by the Black-Scholes
option pricing model. The assumptions used for the Black-Scholes model are as
of December 31, 2001 and are as follows: Risk-free interest rate: 4.85%;
Volatility: 37.17%; Dividend Yield: 3.24%; Time of Exercise: 5 years.

Grant Date
Individual Grants Value
----------------------------------------- ----------
Number of % of Total
Securities Options Exercise
Underlying Granted or Grant Date
Options to Base Present
Granted(#) Employees Price Expiration Value
Name (1) in 2000 ($/Sh.) Date ($)
---- ---------- ---------- -------- ---------- ----------

Corbin A. McNeill, Jr. 233,300 37.08% $67.88 01/01/2011 $4,710,327
John W. Rowe.......... 233,300 37.08% $67.88 01/01/2011 $4,710,327
Pamela B. Strobel..... 0
Kenneth G. Lawrence... 0
Ruth Ann M. Gillis.... 0
Frank F. Frankowski... 0

--------
(1) Regular stock options that would have normally been granted to eligible
participants in January 2001 were granted at the time of the merger in
October 2000 with the exception of the Co-CEOs. Due to Plan limitations as
to the maximum number of options that can be granted in a calendar year,
the 10/20/2000 launch grant to the Co-CEOs was split between that date and
January 2, 2001. The remaining stock options granted during 2001 were
deemed "off-cycle" grants and were usually awarded as part of an employment
offer.

Option Exercises and Year-End Value

This table shows the number and value of exercised and unexercised stock
options for the named executive officers during 2001. Value is determined using
the market value of Exelon common stock at the year-end price of $47.88 per
share, minus the value of Exelon common stock at the exercise price. All
options whose exercise price exceeds the market value are valued at zero.

Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options Options
Shares at 12/31/2001 at 12/31/2001
Acquired ------------- -------------
of (#) ($)
Exercise Value Exercisable Exercisable
Name (#) Realized ($) Unexercisable Unexercisable
---- -------- ------------ ------------- -------------

Corbin A. McNeill, Jr. 32,500 $1,478,750 545,833 E $11,586,765 E
494,967 U $ 886,265 U
John W. Rowe.......... 100,000 $2,980,000 348,000 E $ 2,936,529 E
525,100 U $ 1,058,110 U
Pamela B. Strobel..... 28,025 $1,136,224 76,750 E $ 487,315 E
91,000 U $ 293,680 U
Kenneth G. Lawrence... 8,000 $ 305,000 87,200 E $ 1,490,879 E
54,400 U $ 131,037 U
Ruth Ann M. Gillis.... 0 $ 0 68,500 E $ 596,790 E
65,750 U $ 221,350 U
Frank F. Frankowski... 0 $ 0 4,834 E 41,171 E
6,332 U 38,022 U

Retirement Plans

The following table shows the estimated annual retirement benefits payable
on a straight-life annuity basis to participating employees, including
officers, in the earnings and year of service classes indicated, under Exelon's
non-contributory retirement plans. Effective January 1, 2001, Exelon
Corporation assumed sponsorship of the PECO Energy Company Service Annuity
Plan. Effective December 31, 2001, this plan, along with the Commonwealth
Edison Company Service Annuity System, was merged to form the Exelon Retirement
Program, which incorporates the separate benefit formula of each merged plan
for employees in business units formerly covered by that merged plan. Effective
January 1, 2001, Exelon also established two cash balance pension plans which
cover management employees and bargaining unit employees hired on or after such
date. The amounts shown in the table are not subject to any deduction for
Social Security or other offset amounts.

Covered compensation includes salary and bonus which is disclosed in the
Summary Compensation Table on page 51 for the named executive officers. The
calculation of retirement benefits under the plan is based upon average
earnings for the highest consecutive five-year period under the PECO Energy
Company Service Annuity Benefit Formula and for the highest four-year period
(three-year for certain represented employees) under the ComEd Service Annuity
Benefit Formula.

The Internal Revenue Code limits the annual benefits that can be paid from a
tax-qualified retirement plan to $170,000 as of January 1, 2001. As permitted
by the Employee Retirement Income Security Act of 1974, Exelon sponsored
supplemental plans, which allow the payment out of its general assets, any
benefits calculated under provisions of the applicable retirement plan which
may be above these limits.

PECO Energy Service Annuity Formula Table

Annual Normal Retirement Benefits After Specified Years of Service
--------------------------------------------------------------
Highest 5-Year 10 Years 15 Years 20 Years 25 Years 30 Years 35 Years 40 Years
Average Earnings ($) ($) ($) ($) ($) ($) ($)
---------------- -------- -------- -------- -------- -------- -------- --------

$ 100,000.00. 19,272 26,407 33,543 40,679 47,815 54,950 62,086
200,000.00. 39,772 54,657 69,543 84,429 99,315 114,200 129,086
300,000.00. 60,272 82,907 105,543 128,179 150,815 173,450 196,086
400,000.00. 80,772 111,157 141,543 171,929 202,315 232,700 263,086
500,000.00. 101,272 139,407 177,543 215,679 253,815 291,950 330,086
600,000.00. 121,772 167,657 213,543 259,429 305,315 351,200 397,086
700,000.00. 142,272 195,907 249,543 303,179 356,815 410,450 464,086
800,000.00. 162,772 224,157 285,543 346,929 408,315 469,700 531,086
900,000.00. 183,272 252,407 321,543 390,679 459,815 528,950 598,086
1,000,000.00. 203,772 280,657 357,543 434,429 511,315 588,200 665,086

Upon his retirement, Mr. McNeill had 34 credited years of service under our
pension program. Mr. Lawrence and Mr. Frankowski have 32 and 6 credited years
of service, respectively, under our pension program.

Employment Agreements

Employment Agreement with John W. Rowe

Exelon entered into an amended employment agreement with Mr. Rowe, which
amended and restated his employment agreement with Unicom Corporation and ComEd
in effect at the time of the merger forming Exelon (the "prior agreement") and
under which Mr. Rowe will serve as:

. co-chief executive officer and president of Exelon, chairman of the
executive committee of the Exelon board of directors and a member of the
Exelon board of directors during the first half of the transition period
provided for in Exelon's Bylaws, which is defined as the period from the
effective time of the merger forming Exelon (October 20, 2000) until
December 31, 2003;

. co-chief executive officer of Exelon, chairman of the Exelon board of
directors and a member of the Exelon board of directors during the second
half of the transition period; and

. chief executive officer of Exelon, chairman of the Exelon board of
directors and a member of the Exelon board of directors after the
transition period.

Mr. Rowe will succeed to the position of sole chief executive officer of
Exelon or chairman of the Exelon board of directors if:

. prior to the end of the transition period, Mr. McNeill should cease to be
a co-chief executive officer of Exelon or the chairman of the Exelon
board of directors; and

. Mr. Rowe is still a co-chief executive officer of Exelon at that time.

Mr. Rowe will receive an annual base salary determined by Exelon's
compensation committee. Mr. Rowe will be eligible to participate in annual
incentive award programs, long-term incentive plans and stock option plans on
the same basis as other senior executives of Exelon. The agreement provided
that a grant of options would be considered at the time the merger was
completed. Mr. Rowe is entitled to participate in all savings, deferred
compensation, retirement and other employee benefit plans generally available
to other senior executives of Exelon. During the transition period, Mr. Rowe's
base salary and participation in the plans and awards described in this
paragraph will be in an amount or on a basis that is not less than that of Mr.
McNeill's or on which Mr. McNeill participates.

Under his amended employment agreement and the prior agreement, Mr. Rowe is
entitled to receive a special supplemental executive retirement plan, or SERP,
benefit if he terminates due to normal retirement, early retirement,
termination without cause, termination for good reason, death or disability or
if he voluntarily terminates his employment for any other reason.

The term "good reason" includes the failure to appoint Mr. Rowe to the
management and Exelon board of director positions described above. The special
SERP benefit will equal the SERP benefit that Mr. Rowe would have received if:

. he had attained age 60 (or his actual age, if greater);

. he had earned 20 years of service on March 16, 1998 and one additional
year of service on each anniversary after that date and prior to
termination; and

. his annual incentive awards for each of 1998 and 1999 had been $300,000
greater than the annual incentive awards he actually received for those
years.

Except as provided in the next paragraph, if Exelon terminates Mr. Rowe's
employment for reasons other than cause, death or disability or if he should
terminate employment for good reason on or after December 31, 2004 and not
within 24 months following a change in control of Exelon, he would be entitled
to the following benefits:

. a prorated annual incentive award for the year in which termination
occurs;

. severance payments equal to his base salary for two years after
termination, and for each year during such period an amount equal to the
average of the annual incentive awards paid to him with respect to the
three years preceding the year of termination or, if greater, his annual
incentive award for the year before termination;

. for the two-year period, continuation of his life, disability, accident,
health and other welfare benefits, plus the retirement benefits described
above and post-retirement health care coverage;

. all of his exercisable options would remain exercisable until the
applicable option expiration date;

. unvested options would continue to become exercisable during the two-year
continuation period and thereafter remain exercisable until the
applicable option expiration date; and

. all compensation earned through the date of termination and coverage and
benefits under all benefit plans to which he is entitled.

Mr. Rowe will receive the termination benefits described in "Change in
Control and Severance Arrangements" below, rather than the benefits described
in the previous paragraph, if Exelon terminates Mr. Rowe without cause or he
terminates with good reason and

. the termination occurs within 24 months after a change in control of
Exelon,

. the termination occurs at any other time prior to the earlier of normal
retirement or December 31, 2004, or

. the termination occurs at any other time on and before normal retirement
because of the failure to appoint or elect Mr. Rowe to the management or
Exelon board of director positions described above.

Employment Arrangement with Corbin A. McNeill, Jr.

Although Exelon did not enter into an employment agreement with Mr. McNeill,
the merger agreement provided that at any time during the transition period
when Messrs. McNeill and Rowe are co-chief executive officers, each of them
will receive the same salary, bonus and other compensation (including option
grants and other incentive awards and all other forms of compensation) and
enjoy the same other benefits and the same

employment security arrangements as the other. Mr. McNeill retired April 23,
2002. Under an agreement approved by the board of directors of Exelon, Mr.
McNeill receives the termination benefits described in "Change in Control
Severance Arrangements" below.

Change in Control Severance Arrangements

Exelon has entered into change in control agreements with certain senior
executives including the senior executives listed under "Management" on page 61
which generally protect executives' positions and compensation levels through
October 20, 2002 with respect to the Exelon merger in the case of certain
officers, and for two years after certain future changes in control if such
changes in control occur before June 1, 2003. The June 1, 2003 date is subject
to annual extension if there is no change in control before June 1 of each
year. In some cases, these agreements replaced change in control agreements
with PECO and Unicom which became effective upon the completion of the merger
and which cover employment through October 20, 2002. A material adverse change
in compensation or position is included in the definition of "good reason" for
purposes of these agreements. If an executive resigns for good reason or if the
executive's employment is terminated by Exelon other than for cause, severance
pay and benefits become payable.

The severance payments and benefits provided under the change in control
agreements include:

. Severance payments equal to either two and one-half or three multiplied
by the sum of: the employee's annual base salary, plus an amount equal to
the average of the annual incentive awards paid to the employee for the
two years preceding the year of termination or, if greater, the target
award under the annual incentive award program in which the employee
participates for the year in which termination occurs.

. A prorated annual incentive award for the year in which termination
occurs.

. Continuation of life, disability, accident, health and other welfare
benefit coverage for three years; thereafter, if applicable, retiree
coverage is available.

. Outplacement services.

. All of a terminated employee's exercisable options remain exercisable
until the applicable option expiration date, and all unvested options
become fully exercisable and remain so until the applicable option
expiration date.

. Any deferred stock units, restricted stock, or restricted share units
become fully vested and any other long-term incentive plan award which is
unvested would vest.

. For purposes of determining benefits under the supplemental retirement
plan or arrangement, in which the employee participates, the employee
will be credited with three additional years of credited service, age and
compensation.

. For purposes of determining eligibility for retiree welfare benefits, the
employee will be deemed to have three additional years of service and age.

. All compensation earned through the date of termination as well as all
coverage and benefits under all benefit plans to which the employee is
entitled.

Pursuant to the terms of offers of employment or employment agreements,
certain employees are also entitled to additional service credits for purposes
of retiree health care eligibility and for determining benefits under the
supplemental retirement plan or arrangement in which they participate.

In connection with the severance benefits described above, each executive is
subject to a non-compete agreement for 24 months from the applicable
termination date. Although a participating employee does not have a duty to
mitigate the amounts due from Exelon continued welfare benefit coverage would
be offset during the applicable continuation period by comparable coverage
provided under welfare plans of another employer.

Employees who are senior vice-presidents or above will receive an additional
payment to cover excise taxes imposed under Section 4999 of the Internal
Revenue Code on "excess parachute payments" or under similar state or local law
if the after-tax amount of payments and benefits subject to these taxes exceeds
110% of the "safe harbor" amount that would not subject the employee to these
excise taxes. If the after-tax amount, however, is less than 110% of the safe
harbor amount, payments and benefits subject to these taxes would be reduced or
eliminated to equal the safe harbor amount. Benefits payable to other employees
subject to the excise taxes imposed under Section 4999 of the Internal Revenue
Code will be reduced to the employees' safe harbor amount.

CERTAIN TRANSACTIONS

We are an indirect subsidiary of Exelon. The following describes our
material relationships and agreements with Exelon and other affiliates.

Restructuring and Asset Transfers. During January 2001, Exelon undertook a
restructuring to separate its generation and other competitive businesses from
its regulated energy delivery business. As part of this restructuring, we and
ComEd transferred our assets and liabilities unrelated to energy delivery to
other subsidiaries of Exelon, including Exelon Generation. In our case, the
assets and liabilities transferred to Exelon Generation related to nuclear,
fossil, hydroelectric and other generation facilities and wholesale power
marketing operations, rights under certain power purchase agreements and
nuclear decommissioning trust funds. The liabilities that Exelon Generation
assumed include: decommissioning costs for nuclear facilities; obligations to
comply with all liabilities connected with or arising out of permits, licenses,
exemptions, allowances, approvals and other items obtained or required in
connection with the generation assets; obligations and liabilities arising
under contracts assigned by us, including power purchase agreements and
pollution control revenue bonds after January 1, 2001; all employment related
obligations and liabilities to our employees who became Exelon Generation's
employees in connection with the restructuring and associated litigation
matters.

Power Purchase Agreement with Exelon Generation. The power purchase
agreement between us and Exelon Generation, dated January 1, 2001, requires
Exelon Generation to deliver energy to us to meet our hourly load obligations
for provider-of-last-resort ("PLR") customers and provide us with rights to
capacity sufficient to meet our daily unforced capacity obligation as
determined by PJM through the year 2010. To ensure long-term generation
reliability within the PJM control area, PJM rules require that we have rights
to capacity in amounts based on our load plus a reserve margin. The bundled
price for both the energy and capacity that Exelon Generation provides to us is
a function of the amount we are able to charge our PLR customers. We arrange
for transmission service and all other transmission service products with PJM
and pay PJM for these services.

Interconnection Agreement. Following the corporate restructuring and the
disaggregation of Exelon's distribution and generation businesses,
interconnection agreements between us and Exelon Generation's generation
facilities was filed with FERC to establish the requirements, terms and
conditions for the continuing interconnection of those generation facilities
with the transmission and distribution systems that we own and/or operate. The
agreements govern interconnection only and it is our responsibility or the
responsibility of the purchaser of capacity or energy output to make
arrangements for transmission service through PJM.

Generation Reliability Services. Pursuant to the terms of certain Call
Contracts for Generator Reliability Services between us and Exelon Generation
dated as of January 10, 2001, Exelon Generation has agreed that, when called
upon by us to do so in accordance with the terms of the Call Contracts, Exelon
Generation will generate energy at the Delaware Generation Station and Moser
Generating Station and deliver that energy to our distribution system in order
to preserve the reliable operations of the distribution system. In exchange for
receiving such services, we are obligated to pay Exelon Generation's net
out-of-pocket costs associated with providing the services. The agreements are
for terms of ten years, unless terminated earlier by either party upon 90 days
prior written notice.

Transmission Services. PJM sells transmission services on our behalf to our
affiliates at price terms set under FERC open-access transmission tariffs. For
2001, transmission sales on our behalf to affiliates totaled $6.6 million.

Affiliated Services Agreements. There are several contracts among Exelon
and its affiliates, including us, under which services are provided and
received. Exelon Business Services Company, a wholly owned subsidiary of
Exelon, provides business services, such as legal, accounting, purchasing and
information technology, to Exelon and its affiliates, including us, at cost. We
currently provide services to or receive services from Exelon affiliates at
market prices, or if there is no prevailing price, then at fully allocated
cost. We also provide and receive from Exelon Generation services, at cost,
pertaining to the interface between the generation function conducted by Exelon
Generation and the transmission and distribution functions provided by us.
These services are limited to those necessary for the efficient operation of
the facilities located at the generation station sites where generation
facilities are connected to the transmission and distribution facilities
(primarily switchyard facilities). Exelon Generation also provides us supply
planning services, at cost, and assists us in obtaining energy supply resources
to the extent energy supply is not provided by Exelon Generation.

Pollution Control Notes. In 2001, we transferred to Exelon Generation $121
million of debt, through refundings of tax-exempt pollution control notes. On
July 24, 2002, we transferred an additional $29.5 million of tax-exempt debt
through a refunding.

Consolidated Tax Return and Tax Sharing Agreement. We join with Exelon and
its subsidiaries in filing a consolidated federal income tax return. The
consolidated tax liability is allocated among participants in accordance with a
Tax Sharing Agreement entered into with the other members of the Exelon
Consolidated Group. This agreement provides an equitable method for determining
the share of the affiliated group's consolidated federal tax burdens and
benefits to be attributed to each member.

THE EXCHANGE OFFER

Purpose of the Exchange Offer

In connection with the sale of the original bonds, we entered into a
registration rights agreement with the initial purchasers. Under the
registration rights agreement, we agreed to use our best efforts to complete
the exchange offer and to file and cause to become effective with the SEC a
registration statement for the exchange of the original bonds for exchange
bonds.

The terms of the exchange bonds are the same as the terms of the original
bonds, except that the exchange bonds have been registered under the Securities
Act and will not be subject to some restrictions on transfer that apply to the
original bonds. In that regard, the original bonds provide, among other things,
that if the exchange offer has not been consummated within the period specified
in the original bonds, the interest rate on the original bonds will increase by
0.50% per annum, until the exchange offer is consummated.

Upon completion of the exchange offer, holders of original bonds will not be
entitled to any further registration rights under the registration rights
agreement, except under limited circumstances. See "Risk Factors--If you fail
to exchange the original bonds, they will remain subject to transfer
restrictions" and "Description of the Exchange Bonds." The exchange offer is
not being made to holders of original bonds in any jurisdiction in which the
exchange offer or the acceptance of the bonds would not comply with securities
or blue sky laws.

The original bonds were issued and are held in the book-entry system of The
Depository Trust Company ("DTC"). Unless the context requires otherwise, the
term "holder" with respect to the exchange offer means any person whose
original bonds are held of record by DTC and who desires to deliver such
original bonds by book-entry transfer at DTC. As soon as practicable after the
Expiration Date, we will exchange the original bonds for a like aggregate
principal amount of the exchange bonds of each series.

Completion of the exchange offer is subject to the conditions that the
exchange offer not violate any applicable law or interpretation of the staff of
the Division of Corporate Finance of the SEC and that no injunction, order or
decree has been issued that would prohibit, prevent or materially impair our
ability to proceed with the exchange offer. The exchange offer is also subject
to various procedural requirements discussed below with which holders must
comply. We reserve the right, in our absolute discretion, to waive compliance
with these requirements subject to applicable law.

Terms of the Exchange Offer

We are offering, upon the terms and subject to the conditions described in
this prospectus and in the accompanying letter of transmittal, to exchange up
to $250,000,000 aggregate principal amount of exchange bonds for a like
aggregate principal amount of original bonds of the same series properly
tendered on or before the Expiration Date and not properly withdrawn in
accordance with the procedures described below. We will issue, promptly after
the Expiration Date, up to an aggregate principal amount of up to $250,000,000
of exchange bonds in exchange for a like principal amount of outstanding
original bonds tendered and accepted in connection with the exchange offer. We
will pay all charges and expenses, other than certain applicable taxes
described below, in connection with the exchange offer. See "--Fees and
Expenses."

Holders may tender their original bonds in whole or in part in minimum
denominations of $1,000 and multiples thereof. The exchange offer is not
conditioned upon any minimum principal amount of original bonds being tendered.
As of the date of this prospectus, $250,000,000 aggregate principal amount of
the original bonds is outstanding. Holders of original bonds do not have any
appraisal or dissenters' rights in connection with the exchange offer. Original
bonds that are not tendered or are tendered but not accepted in connection with
the exchange offer will remain outstanding and be entitled to the benefits of
the indenture, but will not be entitled to any further registration rights
under the registration rights agreement, except under limited circumstances. See

"Risk Factors--If you fail to exchange the original bonds, they will remain
subject to transfer restrictions" and "Description of the Exchange Bonds." If
any tendered original bonds are not accepted for exchange because of an invalid
tender, the occurrence of other events described in this prospectus or
otherwise, appropriate book-entry transfer will be made, without expense, to
the tendering holder of the original bonds promptly after the Expiration Date.
Holders who tender original bonds in connection with the exchange offer will
not be required to pay brokerage commissions or fees or, subject to the
instructions in the bondholders' instruction form, transfer taxes with respect
to the exchange of original bonds in connection with the exchange offer.

We do not make any recommendation to holders of original bonds as to whether
to exchange all or any portion of their original bonds in this exchange offer.
In addition, no one has been authorized to make any recommendation as to
whether holders should exchange bonds in this exchange offer. Holders of
original bonds must make their own decisions whether to exchange original bonds
in this exchange offer and, if so, the aggregate amount of original bonds to
exchange based on the holders' own financial positions and requirements.

Expiration Date; Extensions; Amendments

The term "Expiration Date" means 5:00 p.m., Eastern Time, on September 26,
2002. However, if the exchange offer is extended by us, the term "Expiration
Date" will mean the latest date and time to which we extend the exchange offer.

We expressly reserve the right in our sole and absolute discretion, subject
to applicable law, at any time and from time to time:

. to delay the acceptance of the original bonds for exchange;

. to extend the Expiration Date and retain all original bonds tendered in
the exchange offer, subject, however, to the right of holders of original
bonds to withdraw their tendered original bonds as described under
"--Withdrawal Rights"; and

. to waive any condition or otherwise amend the terms of the exchange offer
in any respect.

If the exchange offer is amended in a manner determined by us to constitute
a material change, we will promptly

. disclose the amendment in a prospectus supplement that will be
distributed to the holders of the original bonds,

. file a post-effective amendment to the registration statement filed with
the SEC with regard to the exchange bonds and the exchange offer, and

. extend the exchange offer to the extent required by Rule 14e-1 under the
Exchange Act.

We will promptly notify the exchange agent by making an oral or written
public announcement of any delay in acceptance, extension, termination or
amendment. This announcement in the case of an extension will be made no later
than 9:00 a.m., Eastern Time, on the next business day after the previously
scheduled expiration date. Without limiting the manner in which we may choose
to make any public announcement and, subject to applicable law, we will have no
obligation to publish, advertise or otherwise communicate any such public
announcement other than by issuing a release to an appropriate news agency.

Acceptance for Exchange and Issuance of Exchange bonds

Upon the terms and subject to the conditions of the exchange offer, we will
exchange and issue to the exchange agent, promptly after the Expiration Date,
exchange bonds for original bonds validly tendered and not

withdrawn. In all cases, delivery of exchange bonds in exchange for original
bonds tendered and accepted for exchange pursuant to the exchange offer will be
made only after timely receipt by the exchange agent of:

. a book-entry confirmation of a book-entry transfer of original bonds into
the exchange agent's account at DTC, including an agent's message (as
defined below) if the tendering holder has not delivered a letter of
transmittal;

. the letter of transmittal (or facsimile thereof), properly completed or
an agent's message instead of the letter of transmittal; and

. any other documents required by the letter of transmittal.

The term "book-entry confirmation" means a timely confirmation of a
book-entry transfer of original bonds into the exchange agent's account at DTC.
The term "agent's message" means a message, transmitted by DTC to and received
by the exchange agent and forming a part of a book-entry confirmation, that
states that DTC has received an express acknowledgment from the tendering DTC
participant. This acknowledgment states that the participant has received and
agrees to be bound by the letter of transmittal and that we may enforce the
letter of transmittal against the participant.

If the procedures for book-entry transfer cannot be completed on a timely
basis or time will not permit all required documents to reach the Exchange
Agent prior to 5:00 PM Eastern Standard Time on the Expiration Date, a Notice
of Guaranteed Delivery may be submitted to the Exchange Agent in the manner and
at the address for the Exchange Agent below (See "--Exchange Agent"). The
notice of guaranteed delivery must be signed by a member of a registered
national securities exchange, or a member of the National Association of
Securities Dealers or a commercial bank or trust company having an office or
correspondent in the U.S., or an "eligible guarantor institution" within the
meaning of Rule 17Ad-15 of the Securities Exchange Act of 1934, as amended. In
addition, in order to use the guaranteed delivery procedure to render original
bonds pursuant to the Exchange Offer, a completed and signed and dated Letter
of Transmittal (or facsimile thereof) must also be received by the Exchange
Agent prior to 5:00 PM Eastern Standard Time on the Expiration Date.

Subject to the terms and conditions of the exchange offer, we will be deemed
to have accepted for exchange, and therefore exchanged, original bonds validly
tendered and not withdrawn as, if and when we give oral or written notice to
the exchange agent of our acceptance of such original bonds for exchange
pursuant to the exchange offer. The exchange agent will act as agent for us for
the purpose of receiving tenders of original bonds, letters of transmittal and
related documents, and as agent for tendering holders for the purpose of
receiving holders' instruction forms, letters of transmittal and related
documents and transmitting exchange bonds to validly exchanging holders. The
exchange will be made promptly after the Expiration Date.

If, for any reason whatsoever, acceptance for exchange or the exchange of
any tendered original bonds is delayed, whether before or after our acceptance
for exchange of original bonds, or we extend the exchange offer or are unable
to accept for exchange or exchange tendered original bonds, then, without
prejudice to the rights we have in the exchange offer, the exchange agent may,
nevertheless, on our behalf and subject to Rule 14e-1(c) under the Exchange
Act, retain tendered original bonds. These original bonds may not be withdrawn
except to the extent tendering holders are entitled to withdrawal rights as
described under "--Withdrawal Rights."

Under the letter of transmittal or agent's message, a holder of original
bonds will warrant and agree that it has full power and authority to tender,
exchange, sell, assign and transfer original bonds, that we will acquire good,
marketable and unencumbered title to the tendered original bonds, free and
clear of all liens, restrictions, charges and encumbrances, and the original
bonds tendered for exchange are not subject to any adverse claims or proxies.
The holder also will warrant and agree that it will, upon request, execute and
deliver any additional documents deemed by us or the exchange agent to be
necessary or desirable to complete the exchange, sale, assignment, and transfer
of the original bonds exchanged in the exchange offer.

Procedures for Tendering Original Bonds

Valid Tender. The tender of original bonds must follow the procedures for
book-entry transfer described below and a book-entry confirmation, including an
agent's message if the tendering holder has not delivered a letter of
transmittal, must be received by the exchange agent, in each case on or before
the Expiration Date.

If less than all of the original bonds are to be exchanged, a holder should
fill in the amount of original bonds being exchanged in the appropriate box on
the holder's instruction forms. The entire amount of original bonds will be
deemed to have been tendered for exchange unless otherwise indicated.

The method of delivery of the holder's instruction form and all other
required documents is at the option and sole risk of the tendering holder.
Delivery will be deemed made only when actually received by the exchange agent.
If delivery is by mail, we recommend properly insured registered mail, return
receipt requested, or an overnight delivery service. In all cases, you should
allow sufficient time to ensure timely delivery.

The exchange agent will establish an account with respect to the original
bonds at DTC for purposes of the exchange offer within two business days after
the date of this prospectus. Any financial institution that is a participant in
DTC's book-entry transfer facility system may make a book-entry delivery of the
original bonds by causing DTC to transfer the original bonds into the exchange
agent's account at DTC in accordance with DTC's procedures for transfers.
However, although delivery of original bonds may be effected through book-entry
transfer into the exchange agent's account at DTC, the holder's instruction
form (or facsimile thereof), properly completed and duly executed, or an
agent's message instead of the letter of transmittal, and any other required
documents, must in any case be delivered to and received by the exchange agent
at its address listed under "--Exchange Agent" on or before the Expiration Date.

Delivery of documents to DTC in accordance with DTC's procedures does not
constitute delivery to the exchange agent.

Determination of Validity. All questions as to the form of documents,
validity, eligibility, including time of receipt, and acceptance for exchange
of any tendered original bonds will be determined by us, in our sole
discretion. Our interpretation of the terms and conditions of the exchange
offer, including the bondholders' instruction form letter of transmittal and
the accompanying instructions, will be final and binding.

We reserve the absolute right, in our sole and absolute discretion, to
reject any and all tenders determined by us not to be in proper form or the
acceptance of which, or exchange for, may, in the opinion of our counsel, be
unlawful. We also reserve the absolute right, subject to applicable law, to
waive any condition or irregularity in any tender by a particular holder
whether or not similar conditions or irregularities are waived in the case of
other holders. No tender will be deemed to have been validly made until all
irregularities with respect to such tender have been cured or waived. Neither
we, any of our affiliates or assigns, the exchange agent nor any other person
will be under any duty to give any notification of any irregularities in
tenders or incur any liability for failure to give any notification.

If any bondholder instruction form, endorsement, bond power, power of
attorney, or any other required document is signed by a trustee, executor,
administrator, guardian, attorney-in-fact, officer of a corporation or other
person acting in a fiduciary or representative capacity, that person should so
indicate when signing, and unless waived by us, evidence satisfactory to us, in
our sole discretion, of that person's authority must be submitted.

Resales of Exchange Bonds

We are making the exchange offer in reliance on the position of the staff of
the Division of Corporation Finance of the SEC as defined in certain
interpretive letters addressed to third parties in other transactions. However,
we did not seek our own interpretive letter and we cannot assure that the staff
of the Division of

Corporation Finance of the SEC would make a similar determination with respect
to the exchange offer as it has in other interpretive letters to third parties.
Based on these interpretations by the staff of the Division of Corporation
Finance of the SEC, and subject to the two immediately following sentences, we
believe that exchange bonds issued pursuant to this exchange offer in exchange
for original bonds may be offered for resale, resold and otherwise transferred
by a holder thereof (other than a holder who is a broker-dealer) without
further compliance with the registration and prospectus delivery requirements
of the Securities Act, provided that such exchange bonds are acquired in the
ordinary course of the holder's business and that the holder is not
participating, and has no arrangement or understanding with any person to
participate, in a distribution (within the meaning of the Securities Act) of
the exchange bonds.

However, any holder of original bonds who is an "affiliate" of ours or who
intends to participate in the exchange offer for the purpose of distributing
exchange bonds, or any broker-dealer who purchased original bonds from us to
resell pursuant to Rule 144A or any other available exemption under the
Securities Act:

. will not be able to rely on the interpretations of the staff of the
Division of Corporation Finance of the SEC defined in the above-mentioned
interpretive letters;

. will not be permitted or entitled to tender such original bonds in the
exchange offer; and

. must comply with the registration and prospectus delivery requirements of
the Securities Act in connection with any sale or other transfer of such
original bonds unless such sale is made pursuant to an exemption from
such requirements.

In addition, as described below, if any broker-dealer holds original bonds
acquired for its own account as a result of market-making or other trading
activities and exchanges those original bonds for exchange bonds, then that
broker-dealer must deliver a prospectus meeting the requirements of the
Securities Act in connection with any resales of those exchange bonds. Each
holder of original bonds who wishes to exchange original bonds for exchange
bonds in the exchange offer will be required to represent that:

. it is not an "affiliate" of ours;

. any exchange bonds to be received by it are being acquired in the
ordinary course of its business;

. it has no arrangement or understanding with any person to participate in
a distribution (within the meaning of the Securities Act) of such
exchange bonds; and

. if the tendering holder is not a broker-dealer, that holder is not
engaged in, and does not intend to engage in, a distribution (within the
meaning of the Securities Act) of its exchange bonds.

In addition, we may require the holder, as a condition to that holder's
eligibility to participate in the exchange offer, to furnish to us (or an agent
of ours) in writing, information as to the number of "beneficial owners"
(within the meaning of Rule 13d-3 under the Exchange Act) on behalf of whom
that holder holds the original bonds to be exchanged in the exchange offer.

Each broker-dealer that receives exchange bonds for its own account in the
exchange offer must acknowledge that it acquired the original bonds for its own
account as the result of market-making activities or other trading activities
and must agree that it will deliver a prospectus meeting the requirements of
the Securities Act in connection with any resale of those exchange bonds. The
letter of transmittal states that by making that acknowledgement and delivering
a prospectus, a broker-dealer will not be deemed to admit that it is an
"underwriter" within the meaning of the Securities Act. Based on the position
taken by the staff of the Division of Corporation Finance of the SEC in the
interpretive letters referred to above, we believe that participating
broker-dealers who acquired original bonds for their own accounts as a result
of market-making activities or other trading activities may fulfill their
prospectus delivery requirements with respect to the exchange bonds received
upon exchange of original bonds (other than original bonds that represent an
unsold allotment from the initial sale of the original bonds) with a prospectus
meeting the requirements of the Securities Act, which may be

the prospectus prepared for this exchange offer so long as it contains a
description of the plan of distribution regarding the resale of the exchange
bonds.

Accordingly, this prospectus, as it may be amended or supplemented from time
to time, may be used by a participating broker-dealer in connection with
resales of exchange bonds received in exchange for original bonds where the
original bonds were acquired by the participating broker-dealer for its own
account as a result of market-making or other trading activities. See "Plan of
Distribution." Subject to certain provisions contained in the registration
rights agreement, we have agreed that this prospectus, as it may be amended or
supplemented from time to time, may be used by a participating broker-dealer in
connection with resales of exchange bonds for a period not exceeding one year
after the expiration date. However, a participating broker-dealer who intends
to use this prospectus in connection with the resale of exchange bonds received
in exchange for original bonds pursuant to the exchange offer must notify us on
or before the Expiration Date that it is a participating broker-dealer. This
notice may be given in the space provided for that purpose in the letter of
transmittal or may be delivered to the exchange agent at one of the addresses
set forth herein under "--Exchange Agent."

Any participating broker-dealer who is an "affiliate" of ours may not rely
on these interpretive letters and must comply with the registration and
prospectus delivery requirements of the Securities Act in connection with any
resale transaction. In that regard, each participating broker-dealer who
surrenders original bonds in the exchange offer will be deemed to have agreed,
by execution of the letter of transmittal or an agent's message, that upon
receipt of notice from us of the occurrence of any event or the discovery of:

. any fact that makes any statement contained or incorporated by reference
in this prospectus untrue in any material respect, or

. any fact that causes this prospectus to omit to state a material fact
necessary in order to make the statements contained or incorporated by
reference in this prospectus, in light of the circumstances under which
they were made, not misleading, or

. the occurrence of other events specified in the registration rights
agreement,

that participating broker-dealer will suspend the sale of exchange bonds under
this prospectus until we have amended or supplemented this prospectus to
correct the misstatement or omission and have furnished copies of the amended
or supplemented prospectus to the participating broker-dealer, or we have given
notice that the sale of the exchange bonds may be resumed, as the case may be.

Withdrawal Rights

Except as otherwise provided in this prospectus, tenders of original bonds
may be withdrawn at any time on or before the Expiration Date. In order for a
withdrawal to be effective, a written, telegraphic, telex or facsimile
transmission of the notice of withdrawal must be timely received by the
exchange agent at its address listed under "--Exchange Agent" on or before the
Expiration Date. Any notice of withdrawal must specify the name of the person
who tendered the original bonds to be withdrawn and the aggregate principal
amount of original bonds to be withdrawn.

The notice of withdrawal must specify the name and number of the account at
DTC to be credited with the withdrawal of original bonds, in which case a
notice of withdrawal will be effective if delivered to the exchange agent by
written, telegraphic, telex or facsimile transmission. Withdrawals of tenders
of original bonds may not be rescinded. Original bonds properly withdrawn will
not be deemed validly tendered for purposes of the exchange offer, but may be
retendered at any subsequent time on or before the Expiration Date by following
any of the procedures described above under "--Procedures for Tendering
Original Bonds." All questions as to the validity, form and eligibility,
including time of receipt, of withdrawal notices will be determined by us, in
our sole discretion, and our determination will be final and binding on all
parties. None of we, the exchange agent or any other person is under any duty
to give any notification of any irregularities in any notice of withdrawal nor
will those parties incur any liability for failure to give that notice. Any
original bonds that have been tendered but which are withdrawn will be credited
to the holder promptly after withdrawal.

Interest on Exchange Bonds

Interest on the exchange bonds will accrue at the rate of 5.95% per annum
and will be payable semi-annually in arrears on May 1 and November 1 of each
year, commencing May 1, 2002. We will make each interest payment to the persons
in whose names the exchange bonds are registered at the close of business on
record dates fixed by us which must be not more than 14 days prior to the
applicable interest payment date. The exchange bonds will bear interest from
and including the last interest payment date on the original bonds, or if one
has not yet occurred, the date of issuance of the original bonds. Accordingly,
holders of original bonds that are accepted for exchange will not receive
accrued but unpaid interest on original bonds at the time of tender. Rather,
that interest will be payable on the exchange bonds delivered in exchange for
the original bonds on the first interest payment date after the Expiration
Date. Default interest will be paid in the same manner to holders as of a
special record date established in accordance with the mortgage.

Accounting Treatment

The exchange bonds will be recorded at the same carrying value as the
original bonds for which they are exchanged, which is the aggregate principal
amount of the original bonds, as reflected in our accounting records on the
date of exchange. Accordingly, no gain or loss for accounting purposes will be
recognized in connection with the exchange offer. The cost of the exchange
offer will be amortized over the term of the exchange bonds.

Exchange Agent

Wachovia Bank, National Association has been appointed exchange agent for
the exchange offer. Delivery of the bondholders' instruction forms, letters of
transmittal and any other required documents, questions, requests for
assistance, and requests for additional copies of this prospectus or of the
bondholders' instruction form or letters of transmittal should be directed to
the exchange agent as follows:

By Registered or Certified Mail:

Wachovia Bank, National Association
PECO Energy Company
Corporate Actions Department
1525 West W.T. Harris Boulevard, 3C3
Charlotte, North Carolina 28262
Attention: Tiffany Williams

By Hand or Overnight Delivery Service:

Wachovia Bank, National Association
PECO Energy Company
Corporate Actions Department
1525 West W.T. Harris Boulevard, 3C3
Charlotte, North Carolina 28262
Attention: Tiffany Williams

By Facsimile Transmission (for Eligible Institutions only):

Wachovia Bank, National Association
Attention: Tiffany Williams
(704) 590-7628

Confirm by Telephone:

Wachovia Bank, National Association
Attention: Tiffany Williams
(704) 590-7409

Delivery to other than the above addresses or facsimile number will not
constitute a valid delivery.

Fees and Expenses

We have agreed to pay the exchange agent reasonable and customary fees for
its services and will reimburse it for its reasonable out-of-pocket expenses.
We will also pay brokerage houses and other custodians, nominees and
fiduciaries the reasonable out-of-pocket expenses incurred by them in
forwarding copies of this prospectus and related documents to the beneficial
owners of original bonds, and in handling or tendering for their customers.
Holders who tender their original bonds for exchange will not be obligated to
pay any transfer taxes in connection with the transfer. If, however, exchange
bonds are to be delivered to, or are to be issued in the name of, any person
other than the registered holder of the original bonds tendered, or if a
transfer tax is imposed for any reason other than the exchange of original
bonds in connection with the exchange offer, then the amount of any such
transfer taxes, whether imposed on the registered holder or any other persons,
will be payable by the tendering holder. If satisfactory evidence of payment of
such taxes or exemption therefrom is not submitted with the exchanging holder's
letter of instruction or the letter of transmittal, the amount of such transfer
taxes will be billed directly to such tendering holder. We will not make any
payment to brokers, dealers or other nominees soliciting acceptances of the
exchange offer.

DESCRIPTION OF THE EXCHANGE BONDS

General

We issued the original bonds and will issue the exchange bonds under our
First and Refunding Mortgage dated May 1, 1923, as amended and supplemented by
ninety-six supplemental mortgage indentures and as proposed to be further
amended and supplemented by a supplemental mortgage indenture relating to the
Bonds (herein sometimes referred to collectively as the "mortgage"). Wachovia
Bank, National Association (formerly First Union National Bank) is trustee
under the mortgage (the "trustee").

The following summary of the mortgage does not purport to be complete and is
subject to, and is qualified in its entirety by reference to, all provisions of
the mortgage. Certain terms used in this section are defined in the mortgage.
Copies of the First and Refunding Mortgage and the ninety-six supplemental
mortgage indentures are on file with the SEC. A copy of the supplemental
mortgage indenture relating to the Bonds may be obtained by accessing the
Internet address provided or contacting us as described under "Where You Can
Find More Information."

Principal, Maturity and Interest

The exchange bonds will be limited in aggregate principal amount to
$250,000,000. The exchange bonds will be issued in book-entry form only in
denominations of $1,000 and integral multiples thereof.

The exchange bonds will mature on June 15, 2011. Interest will be payable on
the exchange bonds semiannually on May 1 and November 1, commencing on May 1,
2002 until the principal is paid or made available for payment. Interest on the
exchange bonds will accrue from the most recent date to which interest has been
paid or, if no interest has been paid, from the date of issuance. Interest will
be computed on the basis of a 360-day year comprised of twelve 30-day months.

For so long as the exchange bonds are issued in book-entry form, payments of
principal and interest will be made in immediately available funds by wire
transfer to The Depository Trust Company ("DTC") or its nominee. If the
exchange bonds are issued in certificated form to a holder other than DTC,
payments of principal and interest will be made by check mailed to such holder
at such holder's registered address. Payment of principal of the exchange bonds
in certificated form will be made against surrender of those exchange bonds at
the office or agency of our company in the City of Philadelphia, Pennsylvania
and an office or agency in the Borough of Manhattan, City of New York. Payment
of interest on the exchange bonds will be made to the person in whose name the
exchange bonds are registered at the close of business on record dates fixed by
the Company which must be not more than 14 days prior to the relevant interest
payment date. Default interest will be paid in the same manner to holders as of
a special record date established in accordance with the mortgage.

All amounts paid by us for the payment of principal, premium (if any) or
interest on any exchange bonds that remain unclaimed at the end of two years
after such payment has become due and payable will be repaid to us and the
holders of such exchange bonds will thereafter look only to us for payment
thereof.

Redemption at Our Option

We may, at our option, redeem the exchange bonds in whole or in part at any
time at a redemption price equal to the greater of:

. 100% of the principal amount of the exchange bonds to be redeemed, plus
accrued interest to the redemption date; or

. as determined by the Quotation Agent, the sum of the present values of
the remaining scheduled payments of principal and interest on the
exchange bonds to be redeemed (not including any portion of payments of
interest accrued as of the redemption date) discounted to the redemption
date on a semi-annual basis at the Adjusted Treasury Rate plus 30 basis
points, plus accrued interest to the redemption date.

The redemption price will be calculated assuming a 360-day year consisting
of twelve 30-day months.

We will mail notice of any redemption at least 30 days but not more than 45
days before the redemption date to each registered holder of the exchange bonds
to be redeemed.

Unless we default in payment of the redemption price, on and after the
redemption date, interest will cease to accrue on the exchange bonds or
portions of the exchange bonds called for redemption.

"Adjusted Treasury Rate" means, with respect to any redemption date, the
rate per year equal to the semi-annual equivalent yield to maturity of the
Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue
(expressed as a percentage of its principal amount) equal to the Comparable
Treasury Price for the redemption date.

"Business Day" means any day that is not a day on which banking institutions
in New York City are authorized or required by law or regulation to close.

"Comparable Treasury Issue" means the U.S. Treasury security selected by the
Quotation Agent as having a maturity comparable to the remaining term of the
Bonds that would be used, at the time of selection and in accordance with
customary financial practice, in pricing new issues of corporate debt
securities of comparable maturity to the remaining term of the Bonds.

"Comparable Treasury Price" means, with respect to any redemption date:

. the average of the Reference Treasury Dealer Quotations for that
redemption date, after excluding the highest and lowest of the Reference
Treasury Dealer Quotations; or

. if the trustee obtains fewer than three Reference Treasury Dealer
Quotations, the average of all Reference Treasury Dealer Quotations so
received.

"Quotation Agent" means the Reference Treasury Dealer appointed by us.

"Reference Treasury Dealer" means (1) each of Merrill Lynch, Pierce, Fenner
& Smith Incorporated and First Union Securities, Inc. and their respective
successors, unless any of them ceases to be a primary U.S. Government
securities dealer in New York City (a "Primary Treasury Dealer"), in which case
we shall substitute another Primary Treasury Dealer; and (2) any other Primary
Treasury Dealer selected by us.

"Reference Treasury Dealer Quotations" means, with respect to each Reference
Treasury Dealer and any redemption date, the average, as determined by the
trustee, of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) quoted in
writing to the trustee by that Reference Treasury Dealer at 5:00 p.m., New York
City time, on the third Business Day preceding that redemption date.

Security

The exchange bonds will be secured equally with all other bonds outstanding
or hereafter issued under the mortgage (sometimes referred to herein as the
"mortgage bonds") by the lien of the mortgage. The lien of the mortgage,
subject to (1) minor exceptions and certain excepted encumbrances that are
defined in the mortgage and (2) the trustee's prior lien for compensation and
expenses, constitutes a first lien on substantially all of our properties. The
mortgage does not constitute a lien on any property owned by our subsidiaries.
Our properties consist principally of electric transmission and distribution
lines and substations, gas distribution facilities and general office and
service buildings.

We may not issue securities which will rank ahead of the mortgage bonds as
to security. We may acquire property subject to prior liens. If such property
is made the basis for the issuance of additional bonds after we acquires it,
all additional bonds issued under the prior lien must be pledged with the
trustee as additional security under the mortgage.

Authentication and Delivery of Additional Bonds

The mortgage permits the issuance from time to time of additional mortgage
bonds, without limit as to aggregate amount. Additional mortgage bonds may be
in principal amount equal to:

(1) the principal amount of underlying bonds secured by a prior lien upon
property acquired by us after March 1, 1937 and deposited with the trustee
under the mortgage;

(2) the principal amount of any such underlying bonds redeemed or retired,
or for the payment, redemption or retirement of which funds have been deposited
in trust;

(3) the principal amount of bonds previously authenticated under the
mortgage on or after March 1, 1937, which have been delivered to the trustee;

(4) the principal amount of bonds previously issued under the mortgage on
or after March 1, 1937, which are being refunded or redeemed, if funds for the
refunding or redemption have been deposited with the trustee;

(5) an amount not exceeding 60% of the actual cost or the fair value,
whichever is less, of the net amount of permanent additions to the property
subject to the lien of the mortgage, made or acquired after November 30, 1941,
and of additional plants or property acquired by us after November 30, 1941,
and to be used in connection with its electric or gas business as part of one
connected system and located in Pennsylvania or within 150 miles of
Philadelphia; and

(6) the amount of cash deposited with the trustee, which cash shall not at
any time exceed $3,000,000 or 10% of the aggregate principal amount of bonds
then outstanding under the mortgage, whichever is greater, and which cash may
subsequently be withdrawn to the extent of 60% of capital expenditures, as
described in clause (5) above.

No additional bonds may be issued under the mortgage as outlined in clauses
(5) and (6) and, in certain cases, clause (3) above, unless the net earnings
test of the mortgage is satisfied. The net earnings test of the mortgage, which
relates only to the issuance of additional mortgage bonds, requires for 12
consecutive calendar months, within the 15 calendar months immediately
preceding the application for such bonds, that our net earnings, after
deductions for amounts set aside for renewal and replacement or depreciations
reserves and before provision for income taxes, must have been equal to at
least twice the annual interest charges on all bonds outstanding under the
mortgage (including those then applied for) and any other bonds secured by a
lien on our property.

The exchange bonds will be issued against mortgage bonds being redeemed as
described under clause (4) above.

Release and Substitution of Property

While no event of default exists, we may obtain the release of the lien of
the mortgage on mortgaged property which is sold or exchanged if (1) we deposit
or pledge cash or purchase money obligations with the trustee, or (2) in
certain instances, if we substitute other property of equivalent value. The
mortgage also contains certain requirements relating to our withdrawal or
application of proceeds of released property and other funds held by the
trustee.

Corporate Existence

We may consolidate or merge with or into or convey, transfer or lease all,
or substantially all, of the mortgage property to any corporation lawfully
entitled to acquire or lease and operate the property, provided that: such
consolidation, merger, conveyance, transfer or lease in no respect impairs the
lien of the mortgage or any rights or powers of the trustee or the holders of
the outstanding mortgage bonds; and such successor corporation executes and
causes to be recorded an indenture which assumes all of the terms, covenants
and conditions of the mortgage and any indenture supplement thereto.

The mortgage does not contain any covenant or other provision that
specifically is intended to afford holders of our mortgage bonds special
protection in the event of a highly leveraged transaction. The issuance of
long-term debt securities requires the approval of the PUC.

Defaults

Events of default are defined in the mortgage as (1) default for 60 days in
the payment of interest on mortgage bonds or sinking funds deposits under the
mortgage, (2) default in the payment of principal of bonds under the mortgage
at maturity or upon redemption, (3) default in the performance of any other
covenant in the mortgage continuing for a period of 60 days after written
notice from the trustee, and (4) certain events of bankruptcy or insolvency.

Upon the authentication and delivery of additional mortgage bonds or the
release of cash or property, we are required to file documents and reports with
the trustee with respect to the absence of default.

Rights of Bondholders upon Default

Upon the occurrence of an event of default, the holders of a majority in
principal amount of all the outstanding mortgage bonds may require the trustee
to accelerate the maturity of the mortgage bonds and to enforce the lien of the
mortgage. Prior to any sale under the mortgage, and upon the remedying of all
defaults, any such acceleration of the maturity of the mortgage bonds may be
annulled by the holders of at least a majority in principal amount of all the
outstanding mortgage bonds. The mortgage permits the trustee to require
indemnity before proceeding to enforce the lien of the mortgage.

Amendments

We and the trustee may amend the mortgage without the consent of the holders
of the mortgage bonds: (1) to subject additional property to the lien to the
mortgage; (2) to define the covenants and provisions permitted under or not
inconsistent with the mortgage; (3) to add to the limitations of the authorized
amounts, date of maturity, method, conditions and purposes of issue of any
bonds issued under the mortgage; (4) to evidence the succession of another
corporation to us and the assumption by a successor corporation of our
covenants and obligations under the mortgage; (5) to make such provision in
regard to matters or questions arising under the mortgage as may be necessary
or desirable and not inconsistent with the mortgage.

We and the trustee may amend the mortgage or modify the rights of the
holders of the mortgage bonds with the written consent of at least 66 2/3% of
the principal amount of the mortgage bonds then outstanding; provided, that no
such amendment shall, without the written consent of the holder of each
outstanding mortgage bond affected thereby: (1) change the date of maturity of
the principal of, or any installment hereof on, any mortgage bond, or reduce
the principal amount of any mortgage bond or the interest thereon or any
premium payable on the redemption thereof, or change any place of payment
where, or currency in which, any mortgage bond or interest thereon is payable,
or impair the right to institute suit for the enforcement of any such payment
on or after the date of maturity thereof; or (2) reduce the percentage in
principal amount of the outstanding mortgage bonds, the consent of whose
holders is required for any amendment, waiver of compliance with the provisions
of the mortgage or certain defaults and their consequences; or (3) modify any
of the amendment provisions or Section 22 of Article VIII (relating to waiver
of default), except to increase any such percentage or to provide that certain
other provisions of the mortgage cannot be modified or waived without the
consent of the holder of each mortgage bond affected thereby.

Trustee

Wachovia Bank, National Association (formerly First Union National Bank),
the trustee under the mortgage, is the registrar and disbursing agent for our
mortgage bonds. Wachovia Bank, National Association is also our depository,
from time to time makes loans to us and is trustee for a series of senior
unsecured notes of Exelon Generation.

Concerning the Trustee

We and our affiliates use or will use some of the banking services of the
trustee in the normal course of business.

Governing Law

The mortgage is and the exchange bonds will be governed by the laws of the
Commonwealth of Pennsylvania.

Book-Entry, Delivery and Form

The certificates representing the exchange bonds will be in fully
registered, global form without interest coupons.

Ownership of beneficial interests in a global bond will be limited to
persons who have accounts with DTC ("participants") or persons who hold
interests through participants. Ownership of beneficial interests in a global
bond will be shown on, and the transfer of that ownership will be effected only
through, records maintained by DTC or its nominee (with respect to interests of
participants) and the records of participants (with respect to interests of
persons other than participants).

So long as DTC or its nominee is the registered owner or holder of the
global bonds, DTC or such nominee, as the case may be, will be considered the
sole record owner or holder of the exchange bonds represented by such global
bonds for all purposes under the indenture. No beneficial owner of an interest
in the global bonds will be able to transfer that interest except in accordance
with DTC's applicable procedures, in addition to those provided for under the
indenture and, if applicable, Euroclear or Clearstream.

Payments of the principal of and interest on the global bonds will be made
to DTC or its nominee, as the case may be, as the registered owner thereof.
None of us, the trustee, or any paying agent will have any responsibility or
liability for any aspect of the records relating to or payments made on account
of beneficial ownership interests in the global bonds or for maintaining,
supervising or reviewing any records relating to such beneficial ownership
interests.

We expect that DTC or its nominee, upon receipt of any payment of principal
or interest in respect of the global bonds, will credit participants, accounts
with payments in amounts proportionate to their respective beneficial ownership
interests in the principal amount of such global bonds, as shown on the records
of DTC or its nominee. We also expect that payments by participants to owners
of beneficial interests in such global bonds held through such participants
will be governed by standing instructions and customary practices, as is now
the case with securities held for the accounts of customers registered in the
names of nominees for such customers.

Such payments will be the responsibility of such participants.

DTC has advised us as follows: DTC is a limited purpose trust company
organized under the laws of the State of New York, a "banking organization"
within the meaning of the New York Banking Law, a member of the Federal Reserve
System, a "clearing corporation" within the meaning of the New York Uniform
Commercial Code and a "Clearing Agency" registered pursuant to the provisions
of Section 17A of the Exchange Act. DTC was created to hold securities for its
participants and facilitate the clearance and settlement of securities
transactions between participants through electronic book-entry changes in
accounts of its participants, thereby eliminating the need for physical
movement of the exchange bonds. Participants include securities brokers and
dealers, banks, trust companies and clearing corporations and certain other
organizations. Indirect access to the DTC system is available to others such as
banks, brokers, dealers and trust companies that clear through or maintain a
custodial relationship with a participant, either directly or indirectly
("indirect participants").

Neither the trustee nor we will have any responsibility for the performance
by DTC or its participants or indirect participants of their respective
obligations under the rules and procedures governing their operations.

If DTC is at any time unwilling or unable to continue as a depositary for
the global bonds and a successor depositary is not appointed within 90 days, we
will issue definitive, certificated original bonds in exchange for the global
bonds.

Euroclear has advised us as follows: Euroclear was created in 1968 to hold
securities for its participants and to clear and settle transactions between
its participants through simultaneous electronic book-entry delivery against
payment, thereby eliminating the need for physical movement of certificates and
any risk from lack of simultaneous transfers of securities and cash. Euroclear
provides various other services, including securities lending and borrowing,
and interfaces with domestic markets in several countries. Euroclear is
operated by Euroclear Bank S.A./N.V. (the "Euroclear Operator"), under contract
with Euroclear Clearance Systems, S.C., a

Belgian cooperative corporation (the "Cooperative"). All operations are
conducted by the Euroclear Operator, and all Euroclear securities clearance
accounts and Euroclear cash accounts are accounts with the Euroclear Operator,
not the Cooperative. The Cooperative establishes policy for Euroclear on behalf
of Euroclear participants. Euroclear participants include banks (including
central banks), securities brokers and dealers and other professional financial
intermediaries. Indirect access to Euroclear is also available to others that
clear through or maintain a custodial relationship with a Euroclear
participant, either directly or indirectly.

The Euroclear Operator was granted a banking license by the Belgian Banking
and Finance Commission in 2000, authorizing it to carry out banking activities
on a global basis. It took over operation of Euroclear from the Brussels,
Belgium office of Morgan Guaranty Trust Company of New York on December 31,
2000.

Securities clearance accounts and cash accounts with the Euroclear Operator
are governed by the Terms and Conditions Governing Use of Euroclear and the
related Operating Procedures of the Euroclear System, and applicable Belgian
law (collectively, the "Terms and Conditions"). The Terms and Conditions govern
transfers of securities and cash within Euroclear, withdrawals of securities
and cash from Euroclear, and receipts of payments with respect to securities in
Euroclear. All securities in Euroclear are held on a fungible basis without
attribution of specific certificates to specific securities clearance accounts.
The Euroclear Operator acts under the Terms and Conditions only on behalf of
Euroclear participants and has no record of or relationship with persons
holding through Euroclear participants.

Distributions with respect to exchange bonds held beneficially through
Euroclear will be credited to the cash accounts of Euroclear participants in
accordance with the Terms and Conditions, to the extent received by Euroclear.

Clearstream has advised us as follows: Clearstream is incorporated under the
laws of The Grand Duchy of Luxembourg as a professional depositary. Clearstream
holds securities for its participants and facilitates the clearance and
settlement of securities transactions between its participants through
electronic book-entry changes in accounts of its participants, thereby
eliminating the need for physical movement of certificates. Clearstream
provides to its participants, among other things, services for safekeeping,
administration, clearance and settlement of internationally traded securities
and securities lending and borrowing. Clearstream interfaces with domestic
markets in several countries. As a professional depositary, Clearstream is
subject to regulation by the Luxembourg Monetary Institute. Clearstream
participants are financial institutions around the world, including securities
brokers and dealers, banks, trust companies, clearing corporations and certain
other organizations. Indirect access to Clearstream is also available to others
that clear through or maintain a custodial relationship with a Clearstream
participant either directly or indirectly.

Distributions with respect to exchange bonds held beneficially through
Clearstream will be credited to cash accounts of Clearstream participants in
accordance with its rules and procedures, to the extent received by Clearstream.

CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a summary of certain U.S. Federal income tax
consequences relevant to the acquisition, ownership and disposition of the
exchange bonds by the beneficial owners thereof ("Holders"). This discussion is
limited to the tax consequences to the initial Holders of original bonds who
purchased the original bonds at the issue price within the meaning of Section
1273 of the Internal Revenue Code of 1986, as amended (the "Code"), and does
not address the tax consequences to subsequent purchasers of the original bonds
or the exchange bonds. This summary does not purport to be a complete analysis
of all of the potential U.S. Federal income tax consequences relating to the
purchase of the original bonds or the exchange of original bonds for exchange
bonds or the ownership and disposition of the original bonds, nor does this
summary describe any federal estate or gift tax consequences.

There can be no assurance that the Internal Revenue Service ("IRS") will
take a similar view of the tax consequences described herein. Furthermore, this
discussion does not address all aspects of taxation that might be relevant to
particular purchasers in light of their individual circumstances. For instance,
this discussion does not address the alternative minimum tax provisions of the
Code or special rules applicable to certain categories of purchasers (including
dealers in securities or foreign currencies, insurance companies, regulated
investment companies, financial institutions, tax-exempt entities, Holders
whose functional currency is not the U.S. dollar and, except to the extent
discussed below, Foreign Holders (as defined below)), or to purchasers who hold
the bonds as part of a hedge, straddle, conversion, constructive ownership or
constructive sale transaction or other risk reduction transaction. This
discussion is based on the provisions of the Code, the Treasury Regulations
promulgated thereunder, and administrative and judicial interpretations
thereof, all as in effect as of the date hereof and all of which are subject to
change (possibly on a retroactive basis). This discussion below assumes that
the original bonds (and the exchange bonds) have been (and will be) held as
capital assets within the meaning of Code Section 1221.

You are urged to consult your tax advisor as to the specific tax
consequences of an exchange of the original bonds for exchange bonds in light
of such investor's particular tax situation, including the application and
effect of the Code, as well as state, local and foreign income tax, estate and
gift tax and other tax laws.

Tax Consequences to United States Holders

The following summary is a general description of certain U.S. Federal
income tax consequences applicable to a "United States Holder." For the purpose
of this discussion, the term "United States Holder" means a Holder of an
original bond or an exchange bond that is for U.S. Federal income tax purposes:
(1) a citizen or resident of the U.S.; (2) a corporation, partnership or other
entity created or organized in or under the laws of the U.S. or of any
political subdivision thereof; (3) an estate, the income of which is subject to
U.S. Federal income taxation regardless of its source; or (4) a trust, the
administration of which is subject to the primary supervision of a court within
the U.S. and which has one or more U.S. persons with authority to control all
substantial decisions, or a trust that was in existence on August 20, 1996 and
has elected to continue to be treated as a U.S. trust.

If a partnership (or an entity taxable as a partnership) holds the exchange
bonds, the U.S. Federal income tax treatment of a partner generally will depend
upon the status of the partner and the activities of the partnership. If you
are a partner in a partnership (or an entity taxable as a partnership) holding
exchange bonds, you should consult your tax advisor.

Exchange Offer

The exchange of an original bond for an exchange bond pursuant to the
registered exchange offer generally will not be taxable to the exchanging
Holder for U.S. Federal income tax purposes. As a result, an exchanging Holder:

. will not recognize any gain or loss on the exchange;

. will have a holding period for the exchange bond that includes the
holding period for the original bond exchanged therefor;

. will have an initial adjusted tax basis in the exchange bond equal to its
adjusted tax basis in the original bond exchanged therefor; and

. will experience tax consequences upon a subsequent sale, exchange,
redemption or retirement of an exchange bond similar to the tax
consequences upon a sale, exchange, redemption or retirement of an
original bond.

This exchange offer is not expected to result in any U.S. Federal income tax
consequences to a nonexchanging Holder.

Payments of Interest

Interest paid on the exchange bonds will generally be taxable to a United
States Holder as ordinary interest income at the time the interest accrues or
is received in accordance with such Holder's method of accounting for U.S.
Federal income tax purposes.

Sale, Redemption, Retirement or Other Disposition of an Exchange Bond

In general, upon the sale, redemption, retirement or other taxable
disposition of an exchange bond, a United States Holder will recognize capital
gain or loss equal to the difference between the amount realized on such sale,
redemption, retirement or other disposition (not including any amount
attributable to accrued but unpaid interest that the United States Holder has
not already included in gross income) and such Holder's adjusted tax basis in
the bond. Any amount attributable to accrued but unpaid interest that the
United States Holder has not already included in gross income will be treated
as a payment of interest. See "Payments of Interest" above. A United States
Holder's adjusted tax basis in a bond generally will equal the cost of the
original bond, reduced by any principal payments received by such Holder and
increased by any accrued but unpaid interest the Holder has included in income.

A noncorporate United States Holder generally will be subject to a maximum
tax rate of 20% on net capital gains realized by the Holder on the disposition
of capital assets (including the bonds) held for more than one year. Capital
losses realized by a Holder from the disposition of capital assets (including
the bonds) during any taxable year are, with minor exceptions, deductible only
to the extent of capital gains realized in that taxable year or subsequent
taxable years.

Tax Consequences to Foreign Holders

The following summary is a general description of certain U.S. Federal
income tax consequences to a "Foreign Holder" (which, for the purpose of this
discussion, means a Holder that is not a United States Holder). Special rules
not discussed in this summary may apply to certain Foreign Holders, including a
"controlled foreign corporation," a "passive foreign investment company," an
"expatriate," or a "foreign personal holding company." The following summary is
subject to the discussion below concerning backup withholding.

Exchange Offer

A Foreign Holder will not recognize gain or loss from the exchange of an
original bond for an exchange bond regardless of whether such Holder is
otherwise subject to U.S. Federal income tax with respect to income derived
from an original bond or an exchange bond under the rules described below.

Payments of Interest

Assuming that a Foreign Holder's income from an exchange bond is not
"effectively connected" with the conduct by such Holder of a trade or business
in the U.S., payments of interest on an exchange bond to a Foreign Holder will
not be subject to U.S. Federal income tax or withholding tax, provided that:

. such Holder does not own, actually or constructively, 10% or more of the
total combined voting power of all classes of our stock entitled to vote;

. such Holder is not, for U.S. Federal income tax purposes, a controlled
foreign corporation related, directly or indirectly, to us through stock
ownership;

. such Holder is not a bank receiving interest described in Code Section
881(c)(3)(A); and

. the certification requirements imposed under Code Section 871(h) or
881(c) (summarized below) are met.

Payments of interest on an exchange bond that do not satisfy all of the
foregoing requirements are generally subject to U.S. Federal income tax
withholding at a flat rate of 30% (or a lower applicable treaty rate, provided
certain certification requirements are met).

Except to the extent otherwise provided under an applicable tax treaty, a
Foreign Holder generally will be subject to U.S. Federal income tax in the same
manner as a United States Holder with respect to interest on an exchange bond
if such interest is effectively connected with the conduct of a U.S. trade or
business by such Holder. Effectively connected interest income will not be
subject to withholding tax if the Foreign Holder delivers an IRS Form W-8ECI to
the paying agent. Effectively connected interest income received by a corporate
Foreign Holder may also, under certain circumstances, be subject to an
additional "branch profits tax" at a 30% rate (or lower treaty rate).

Sale, Exchange, Redemption or Retirement of an Exchange Bond

In general, a Foreign Holder will not be subject to U.S. Federal income tax
or withholding tax on the receipt of payments of principal on an exchange bond
or on any gain recognized on the sale, redemption, retirement or other taxable
disposition of an exchange bond, unless:

. such Foreign Holder is a nonresident alien individual who is present in
the U.S. for 183 or more days during the taxable year of disposition and
certain other conditions are met;

. the Foreign Holder is required to pay tax pursuant to the provisions of
U.S. tax law applicable to certain U.S. expatriates;

. the gain is effectively connected with the conduct of a U.S. trade or
business by the Foreign Holder;

. the certification requirements imposed under Code Section 871(h) or
881(c) (summarized below) are not satisfied.

Certification Requirements

In order to obtain the exemption from U.S. Federal income tax withholding
described above, either (1) a Foreign Holder of an exchange bond must provide a
certificate containing its name and address, and certify, under penalties of
perjury, to our paying agent that such Holder is a Foreign Holder, or (2) a
securities clearing organization, bank or other financial institution that
holds customer securities in the ordinary course of its trade or business (a
"Financial Institution") that holds an exchange bond on behalf of the Foreign
Holder must (a) certify, under penalties of perjury, to our paying agent that
the required certificate has been received from the Foreign Holder by it or by
an intermediary Financial Institution and (b) furnish a copy of the
certificates to our paying agent. A certificate described in this paragraph is
effective only with respect to payments of interest made to the Foreign Holder
after issuance of the certificate in the calendar year of its issuance and the
two immediately succeeding calendar years. The foregoing certification may be
provided by the Foreign Holder on IRS Form W-8BEN, W-8IMY or W-8EXP, as
applicable.

Backup Withholding and Information Reporting

Backup withholding tax (presently imposed at the rate of 30%) and certain
information reporting requirements apply to certain payments of principal and
interest or the proceeds of sale made to certain Holders of exchange bonds.

In the case of a noncorporate United States Holder, information reporting
requirements will apply to payments of principal or interest made by our paying
agent on an exchange bond. The payor will be required to impose backup
withholding tax if:

. a Holder fails to furnish its Taxpayer Identification Number ("TIN")
(which, for an individual, is the individual's Social Security number) to
the payor in the manner required;

. a Holder furnishes an incorrect TIN and the payor is so notified by the
IRS;

. the payor is notified by the IRS that such Holder has failed to properly
report payments of interest or dividends; or

. under certain circumstances, a Holder fails to certify, under penalties
of perjury, that it has furnished a correct TIN and is not subject to
backup withholding for failure to report interest or dividend payments.

Backup withholding and information reporting do not apply with respect to
payments made to certain exempt recipients, including a corporation.

In the case of a Foreign Holder, backup withholding will not apply to
payments of principal or interest made by our paying agent on an exchange bond
(absent actual knowledge that the Holder is actually a United States Holder) if
the Foreign Holder has provided the required certification under penalties of
perjury that it is not a United States Holder or has otherwise established an
exemption from backup withholding. If the Foreign Holder provides the required
certification, such Holder may nevertheless be subject to withholding of U.S.
Federal income tax as described above under "--Tax Consequences to Foreign
Holders."

Credit for Withheld Taxes

Federal withholding tax is not an additional tax. Rather, any amount
withheld from a payment to a Holder is generally allowed as a credit against
such Holder's U.S. Federal income tax liability and may entitle the Holder to a
refund provided that certain required information is provided to the IRS.

PLAN OF DISTRIBUTION

We are making the exchange offer in reliance on the position of the staff of
the Division of Corporation Finance of the SEC as defined in certain
interpretive letters issued to third parties in other transactions.

Each broker-dealer that receives exchange bonds for its own account pursuant
to the exchange offer must acknowledge that it will deliver a prospectus
meeting the requirements of the Securities Act in connection with any resale of
such exchange bonds. This prospectus, as it may be amended or supplemented from
time to time, may be used by a broker-dealer in connection with resales of
exchange bonds received in exchange for original bonds where such original
bonds were acquired as a result of market-making activities or other trading
activities. We have agreed that, starting on the Expiration Date and ending on
the close of business one year after the Expiration Date, we will make this
prospectus, as amended or supplemented, available to any broker-dealer that
reasonably requests such document for use in connection with any such resale.
Broker-dealers who acquired original bonds directly from us may not rely on the
staff's interpretations and must comply with the registration and prospectus
delivery requirements of the Securities Act, including being named as a selling
security holder, in order to resell the original bonds or the exchange bonds.

We will not receive any proceeds from any sale of exchange bonds by
broker-dealers. Exchange bonds received by broker-dealers for their own account
pursuant to the exchange offer may be sold from time to time in one or more
transactions in the over-the-counter market, in negotiated transactions,
through the writing of options on the exchange bonds or a combination of such
methods of resale, at market prices prevailing at the time of resale, at prices
related to such prevailing market prices or negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers
or dealers who may receive compensation in the form of commissions or
concessions from any such broker-dealer and/or the purchasers of any such
exchange bonds. Any broker-dealer that resells exchange bonds that were
received by it for its own account pursuant to the exchange offer and any
broker or dealer that participates in a distribution of such exchange bonds may
be deemed to be an "underwriter" within the meaning of the Securities Act and
any profit on any such resale of exchange bonds and any commissions or
concessions received by any such persons may be deemed to be underwriting
compensation under the Securities Act.

The letter of transmittal states that by acknowledging that it will deliver
and by delivering a prospectus, a broker-dealer will not be deemed to admit
that it is an "underwriter" within the meaning of the Securities Act.

For a period of one year after the exchange offer has been completed, we
will promptly send additional copies of this prospectus and any amendment or
supplement to this prospectus to any broker-dealer that requests such document
in the letter of transmittal.

We have agreed to pay all expenses incident to the exchange offer (including
the expenses of one counsel for the holders of the original bonds), other than
commissions or concessions of any brokers or dealers, and will indemnify the
holders of the exchange bonds (including any broker-dealers) against certain
liabilities, including liabilities under the Securities Act.

By acceptance of this exchange offer, each broker-dealer that receives
exchange bonds for its own account pursuant to the exchange offer agrees that,
upon receipt of notice from us of the happening of any event which makes any
statement in the prospectus untrue in any material respect or requires the
making of any changes in the prospectus in order to make the statements therein
not misleading (which notice we agree to deliver promptly to such
broker-dealer), such broker-dealer will suspend use of the prospectus until we
have amended or supplemented the prospectus to correct such misstatement or
omission and have furnished copies of the amended or supplemental prospectus to
such broker-dealer.

LEGAL OPINIONS

The validity of the exchange bonds, including the binding nature of debt
securities to be issued by us, will be passed upon for us by Ballard Spahr
Andrews & Ingersoll, LLP.

EXPERTS

The financial statements of PECO Energy Company as of December 31, 2001 and
2000 and for each of the three years in the period ended December 31, 2001
included in this prospectus have been so included in reliance on the report of
PricewaterhouseCoopers LLP independent accountants, given on the authority of
said firm as experts in auditing and accounting.

The projected amounts included within the Annual Stranded Cost Amortization
and Returns disclosure in the "Business--Retail Electric Services" section were
not prepared with a view toward compliance with published guidelines of the
SEC, the guidelines established by the American Institute of Certified Public
Accountants for preparation and presentation of financial projections, or
generally accepted accounting principles. These projected amounts included in
this prospectus have been prepared by, and are the responsibility of, our
management. PricewaterhouseCoopers LLP, our accountants, has neither examined
nor compiled these projections and accordingly, PricewaterhouseCoopers LLP does
not express an opinion or any other form of assurance with respect thereto. The
PricewaterhouseCoopers LLP report included in this prospectus relates to our
historical financial information. It does not extend to the projections and
should not be read to do so.

INDEX TO FINANCIAL STATEMENTS

Table of Contents

Page(s)
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I. Consolidated Financial Statements (unaudited) for the quarter ending June 30, 2002:
Consolidated Statements of Income and Comprehensive Income....................... F-2
Consolidated Balance Sheets...................................................... F-3
Consolidated Statements of Cash Flows............................................ F-4
Notes to Consolidated Financial Statements....................................... F-5
II. Consolidated Financial Statements for the year ended December 31, 2001:
Report of Independent Accountants................................................ F-9
Statements of Income............................................................. F-10
Statements of Cash Flows......................................................... F-11
Balance Sheets................................................................... F-12
Statements of Changes in Shareholders' Equity.................................... F-13
Statements of Other Comprehensive Income......................................... F-14
Notes to Consolidated Financial Statements....................................... F-15
Schedule II--Valuation and Qualifying Accounts................................... F-37

F-1

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Six Months
Ended June 30, Ended June 30,
------------- --------------
2002 2001 2002 2001
---- ----- ------ ------
(in millions)

OPERATING REVENUES
Operating Revenues....................................... $992 $ 903 $2,008 $1,952
Operating Revenues from Affiliates....................... 3 3 7 5
---- ----- ------ ------
Total Operating Revenues............................ 995 906 2,015 1,957
---- ----- ------ ------
OPERATING EXPENSES
Purchased Power.......................................... 59 51 107 90
Purchased Power from Affiliate........................... 346 264 649 508
Fuel..................................................... 53 79 188 284
Operating and Maintenance................................ 123 122 251 251
Operating and Maintenance from Affiliates................ 8 4 16 7
Depreciation and Amortization............................ 109 99 221 200
Taxes Other Than Income.................................. 63 41 122 84
---- ----- ------ ------
Total Operating Expense............................. 761 660 1,554 1,424
---- ----- ------ ------
OPERATING INCOME............................................ 234 246 461 533
---- ----- ------ ------
OTHER INCOME AND DEDUCTIONS
Interest Expense......................................... (92) (117) (187) (219)
Interest Expense from Affiliate.......................... -- (2) -- (8)
Company-Obligated Mandatorily Redeemable Preferred.......
Securities of a Partnership, which holds Solely..........
Subordinated Debentures of the Company................... (2) (2) (5) (5)
Interest Income from Affiliates.......................... -- 1 -- 1
Other, net............................................... 2 3 2 17
---- ----- ------ ------
Total Other Income and Deductions................... (92) (117) (190) (214)
---- ----- ------ ------
INCOME BEFORE INCOME TAXES.................................. 142 129 271 319
INCOME TAXES................................................ 49 44 90 112
---- ----- ------ ------
NET INCOME.................................................. 93 85 181 207
Preferred Stock Dividends................................ (2) (3) (4) (5)
---- ----- ------ ------
NET INCOME ON COMMON STOCK.................................. $ 91 $ 82 $ 177 $ 202
==== ===== ====== ======
OTHER COMPREHENSIVE INCOME
Net Income............................................... $ 93 $ 85 $ 181 $ 207
Other Comprehensive Income (Loss) (net of income taxes):
SFAS 133 Transition Adjustment....................... -- -- -- 40
Cash Flow Hedge Fair Value Adjustment................ (6) 8 (4) (10)
---- ----- ------ ------
Total Other Comprehensive Income.................... (6) 8 (4) 30
---- ----- ------ ------
TOTAL COMPREHENSIVE INCOME.................................. $ 87 $ 93 $ 177 $ 237
==== ===== ====== ======

See Notes to Consolidated Financial Statements

F-2

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30, December 31,
2002 2001
-------- ------------
(in millions)

ASSETS
CURRENT ASSETS
Cash and Cash Equivalents...................................... $ 72 $ 32
Restricted Cash................................................ 322 323
Accounts Receivable, net
Customer.................................................... 261 286
Other....................................................... 30 33
Receivables from Affiliates.................................... 6 8
Inventories, at average cost
Fossil Fuel................................................. 59 72
Materials and Supplies...................................... 6 7
Prepaid Taxes.................................................. 98 1
Other.......................................................... 13 58
------- -------
Total Current Assets........................................ 867 820
------- -------
PROPERTY, PLANT AND EQUIPMENT, NET................................ 4,098 4,047

DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets.............................................. 5,623 5,756
Investments.................................................... 22 24
Pension Asset.................................................. 29 13
Other.......................................................... 78 85
------- -------
Total Deferred Debits and Other Assets...................... 5,752 5,878
------- -------
TOTAL ASSETS...................................................... $10,717 $10,745
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable.................................................. $ 175 $ 101
Payables to Affiliates......................................... 190 194
Long-Term Debt Due within One Year............................. 910 548
Accounts Payable............................................... 52 54
Accrued Expenses............................................... 436 397
Deferred Income Taxes.......................................... 27 27
Other.......................................................... 33 21
------- -------
Total Current Liabilities................................... 1,823 1,342
------- -------
LONG-TERM DEBT.................................................... 4,869 5,438
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes.......................................... 2,927 2,938
Unamortized Investment Tax Credits............................. 26 27
Non-Pension Postretirement Benefits Obligation................. 263 239
Payables to Affiliates......................................... 20 44
Other.......................................................... 120 110
------- -------
Total Deferred Credits and Other Liabilities................ 3,356 3,358
------- -------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF A
PARTNERSHIP, WHICH HOLDS SOLEY SUBORDINATED DEBENTURES OF THE
COMPANY.......................................................... 128 128
MANDATORILY REDEEMABLE PREFERRED STOCK............................ 19 19

COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock................................................... 1,911 1,912
Receivable from Parent......................................... (1,818) (1,878)
Preferred Stock................................................ 137 137
Retained Earnings.............................................. 277 270
Accumulated Other Comprehensive Income......................... 15 19
------- -------
Total Shareholders' Equity.................................. 522 460
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY........................ $10,717 $10,745
======= =======

See Notes to Consolidated Financial Statements

F-3

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months
Ended June 30,
-------------
2002 2001
----- ------
(in millions)

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income............................................................................. $ 181 $ 207
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating
Activities:
Depreciation and Amortization...................................................... 221 200
Provision for Uncollectible Accounts............................................... 32 29
Deferred Income Taxes.............................................................. (19) 13
Deferred Energy Costs.............................................................. 49 7
Other Operating Activities......................................................... (81) (40)
Changes in Working Capital:
Accounts Receivable................................................................ (4) (19)
Changes in Receivables and Payables to Affiliates, net............................. 34 75
Inventories........................................................................ 14 6
Accounts Payable, Accrued Expenses and Other Current Liabilities................... 44 22
Other Current Assets............................................................... (3) (73)
----- ------
Net Cash Flows provided by Operating Activities........................................... 468 427
----- ------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures................................................................... (123) (122)
Other Investing Activities............................................................. 1 35
----- ------
Net Cash Flows used in Investing Activities............................................... (122) (87)
----- ------
CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of Long-Term Debt........................................................... (207) (978)
Issuance of Long-Term Debt............................................................. -- 805
Contribution from Parent............................................................... -- 53
Change in Short-Term Debt.............................................................. 74 (122)
Dividends on Preferred and Common Stock................................................ (174) (105)
Change in Restricted Cash.............................................................. 1 (16)
Settlement of Interest Rate Swap Agreements............................................ -- 31
----- ------
Net Cash Flows used in Financing Activities............................................... (306) (332)
----- ------
INCREASE IN CASH AND CASH EQUIVALENTS..................................................... 40 8
Cash Transferred in Restructuring......................................................... -- (31)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.......................................... 32 49
----- ------
CASH AND CASH EQUIVALENTS AT END OF PERIOD................................................ $ 72 $ 26
===== ======
SUPPLEMENTAL CASH FLOW INFORMATION
Noncash Investing and Financing Activities:
Net Assets Transferred as a result of Restructuring, net of Receivable from Affiliates. $ -- $1,624
Contribution of Receivable from Parent................................................. $ -- $1,983

See Notes to Consolidated Financial Statements

F-4

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

1. BASIS OF PRESENTATION

The accompanying consolidated financial statements as of June 30, 2002 and
for the three and six months then ended are unaudited, but include all
adjustments that PECO Energy Company (PECO) considers necessary for a fair
presentation of its financial statements. All adjustments are of a normal,
recurring nature, except as otherwise disclosed. The December 31, 2001
consolidated balance sheet data was derived from audited financial statements
but do not include all disclosures required by generally accepted accounting
principles. Certain prior-year amounts have been reclassified for comparative
purposes. These reclassifications had no effect on net income or shareholders'
equity. These notes should be read in conjunction with the Notes to
Consolidated Financial Statements of PECO included in or incorporated by
reference in Item 8 of its Annual Report on Form 10-K for the year ended
December 31, 2001.

2. ADOPTION OF NEW ACCOUNTING PRINCIPLES

SFAS No. 142

PECO adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 establishes
new accounting and reporting standards for goodwill and intangible assets. PECO
does not have significant intangible assets recorded on its consolidated
balance sheets. Under SFAS No. 142, goodwill is no longer subject to
amortization, however, goodwill is 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 is reported as a reduction to goodwill and
a charge to operating expense, except at the transition date, when the loss is
reflected as a cumulative effect of a change in accounting principle.

SFAS No. 144

In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets" (SFAS No. 144). PECO adopted SFAS No. 144 on
January 1, 2002. SFAS No. 144 establishes accounting and reporting standards
for both the impairment and disposal of long-lived assets. SFAS No. 144 is
effective for fiscal years beginning after December 15, 2001 and its provisions
are generally applied prospectively. The adoption of this statement had no
effect on PECO's reported financial positions, results of operations or cash
flows.

SFAS No. 133

SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS No. 133) applies to all derivative instruments and requires that such
instruments be recorded on the balance sheet either as an asset or a liability
measured at their fair value through earnings, with special accounting
permitted for certain qualifying hedges. On January 1, 2001, PECO adopted SFAS
No. 133. PECO deferred a non-cash gain of $40 million, net of income taxes, in
accumulated other comprehensive income.

3. REGULATORY ISSUES

As permitted by the Pennsylvania Electric Competition Act, the Pennsylvania
Department of Revenue has calculated a 2002 Revenue Neutral Reconciliation
(RNR) adjustment to the gross receipts tax rate in order to

F-5

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

neutralize the impact of electric restructuring on its tax revenues. In January
2002, the Pennsylvania Public Utility Commission (PUC) approved the RNR
adjustment to the gross receipts tax rate collected from customers. Effective
January 1, 2002, PECO implemented the change in the gross receipts tax rate.
The RNR adjustment is under appeal. The RNR adjustment increases the gross
receipts tax rate, which will increase PECO's annual revenues and tax
obligations by approximately $50 million in 2002.

4. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES

PECO recorded net gains/(losses) in other comprehensive income relating to
mark-to-market (MTM) adjustments of contracts designated as cash flow hedges of
$(7) million and $15 million for the three months ended June 30, 2002 and 2001,
respectively and $(1) million and 8 million for the six months ended June 30,
2002 and 2001, respectively.

During the three months ended June 30, 2002 and 2001 and the six months
ended June 30, 2002 and 2001, PECO reclassified other income in the
Consolidated Statements of Income and Comprehensive Income, as a result of the
discontinuance of cash flow hedges related to certain forecasted financing
transactions that were no longer probable of occurring as follows:

2002 2001
---- ----

Three months ended June 30, $-- $--
Six months ended June 30,.. -- 6

As of June 30, 2002, deferred net gains on derivative instruments
accumulated in other comprehensive income are expected to be reclassified to
earnings during the next twelve months are $15 million.

Amounts in accumulated other comprehensive income related to interest rate
cash flow hedges are reclassified into earnings when the forecasted interest
payment occurs.

5. COMMITMENTS AND CONTINGENCIES

For information regarding capital commitments, see the Commitments and
Contingencies Note in the Consolidated Financial Statements of PECO for the
year ended December 31, 2001.

Environmental Liabilities

PECO has identified 28 sites where former manufactured gas plant (MGP)
activities have or may have resulted in actual site contamination. As of June
30, 2002, PECO had accrued $34 million (undiscounted) for environmental
investigation and remediation costs that currently can be reasonably estimated,
including $25 million for MGP investigation and remediation.

PECO cannot predict the extent to which it will incur other significant
liabilities for additional investigation and remediation costs at these or
additional sites identified by environmental agencies or others, or whether
such costs may be recoverable from third parties.

Litigation

General

PECO is involved in various other litigation matters. The ultimate outcome
of such matters, as well as the matters discussed above, while uncertain, are
not expected to have a material adverse effect on its respective financial
condition or results of operations.

F-6

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

6. MERGER-RELATED COSTS

In association with the Merger, Exelon Corporation (Exelon) recorded certain
reserves for restructuring costs. The reserves associated with PECO were
charged to expense, while the reserves associated with Unicom Corporation were
recorded as part of the application of purchase accounting and did not affect
results of operations.

Merger-related costs charged to expense in 2000 were $276 million,
consisting of $124 million for PECO employee costs and $152 million of direct
incremental costs. Direct incremental costs represent expenses directly
associated with completing the Merger, including professional fees, regulatory
approval and settlement costs, and settlement of compensation arrangements.
Employee costs represent estimated severance costs and pension and
postretirement benefits provided under Exelon's merger separation plans for
eligible employees who are expected to be involuntarily terminated before
December 2002 due to integration activities of the merged companies.

7. SALE OF ACCOUNTS RECEIVABLE

PECO is party to an agreement, which expires in November 2005, 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. As of June 30, 2002, PECO had sold a $225 million interest
in accounts receivable, consisting of a $170 million interest in accounts
receivable that PECO accounted for as a sale under SFAS No. 140, "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities, a Replacement of FASB Statement No. 125" and a $55 million
interest in special-agreement accounts receivable which were accounted for as a
long-term note payable. PECO retains the servicing responsibility for these
receivables. The agreement requires PECO to maintain the $225 million interest,
which, if not met, requires cash, which would otherwise be released to PECO
under this program, to be held in escrow until the requirement is met. At June
30, 2002, PECO met this requirement.

8. RELATED-PARTY TRANSACTIONS

Effective January 1, 2001, Exelon contributed to PECO a $2.0 billion
non-interest bearing receivable from Exelon related to the 2001 corporate
restructuring. This receivable is reflected as a reduction of Shareholders'
Equity in PECO's Consolidated Balance Sheets and is expected to be settled over
the years 2002 through 2010. As of June 30, 2002 and December 31, 2001, the
balance of this receivable from Exelon was $1.8 billion and $1.9 billion,
respectively.

PECO paid common stock dividends to Exelon of $85 million and $56 million
for the three months ended June 30, 2002 and 2001, respectively, and $170
million and $101 million for the six months ended June 30, 2002 and 2001,
respectively.

Effective January 1, 2001, PECO entered into a PPA with Exelon Generation
(Generation). Intercompany power purchases pursuant to the PPA were $346
million and $264 million for the three months ended June 30, 2002 and 2001,
respectively, and $649 million and $508 million for the six months ended June
30, 2002 and 2001. As of June 30, 2002 and December 31, 2001, PECO's payable
related to the PPA was $137 million and $90 million, respectively.

PECO receives a variety of corporate support services from Business Services
Company (BSC), including legal, human resources, financial and information
technology services. Such services, provided at cost including applicable
overhead, were $7 million and $15 million for the three months ended June 30,
2002 and 2001,

F-7

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

respectively, and $13 million and $17 million for the six months ended June 30,
2002 and 2001, respectively. At June 30, 2002 and December 31, 2001, PECO had a
$33 million and $41 million payable, respectively, to BSC.

PECO receives services from Exelon Enterprises (Enterprises) for
construction and the deployment of automated meter reading technology.
Construction services totaling $10 million and $14 million were capitalized in
the six months ended June 30, 2002 and 2001, respectively. Automated meter
reading technology services totaling $8 million and $4 million for the three
months ended June 30, 2002 and 2001, respectively, and totaling $16 million and
$7 million for the six months ended June 30, 2002 and 2001, respectively, were
included in Operating and Maintenance from Affiliates in the Consolidated
Statements of Income and Comprehensive Income. At June 30, 2002 and December
31, 2001, PECO had $6 million and $8 million payable, respectively, to
Enterprises.

At December 31, 2000, PECO had a $400 million payable to Commonwealth Edison
Company, which was repaid in the second quarter of 2001. The average annual
interest rate on this payable for the period outstanding was 6.5%. Interest
expense related to this payable for the three and six months ended June 30,
2001 was $2 million and $8 million, respectively.

PECO provides energy to Generation for Generation's own use. Intercompany
sales for the three and six months ended June 30, 2002 and 2001 were $2 million
and $3 million, respectively.

9. NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the FASB issued SFAS No. 143, "Asset Retirement Obligations"
(SFAS No. 143). In April 2002, the FASB issued SFAS No. 145, "Rescission of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" (SFAS No. 145). In July 2002, the FASB issued SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS
No. 146).

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 in the process of evaluating the impact of SFAS No. 143 on its
financial statements, and cannot determine the ultimate impact of adoption at
this time.

SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses from
Extinguishment of Debt" (SFAS No. 4) and thus allows for only those gains or
losses on the extinguishment of debt that meet the criteria of extraordinary
items to be treated as such in the financial statements. SFAS No. 145 also
amends Statement of Financial Accounting Standards No. 13, "Accounting for
Leases" (SFAS No. 13) to require sale-leaseback accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. The provisions of this statement relating to the rescission of
SFAS No. 4 are effective for fiscal years beginning after May 15, 2002, the
provisions of this statement relating to the amendment of SFAS No. 13 are
effective for transactions occurring after May 15, 2002, and all other
provisions of this Statement are effective for financial statements issued on
or after May 15, 2002. PECO is in the process of evaluating the impact of SFAS
No. 145 on their financial statements, and do not expect the impact to be
material.

SFAS No. 146 requires that the liability for costs associated with exit or
disposal activities be recognized when incurred, rather than at the date of a
commitment to an exit or disposal plan. SFAS No. 146 is to be applied
prospectively to exit or disposal activities initiated after December 31, 2002.

F-8

Report of Independent Accountants

To the Shareholders and Board of Directors
of PECO Energy Company:

In our opinion, the consolidated financial statements listed in the index on
Page F-1 under Item II present fairly, in all material respects, the financial
position of PECO Energy Company and Subsidiary Companies (PECO) at December 31,
2001 and 2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001 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 on Page F-1 under Item II presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and financial
statement schedule are the responsibility of PECO'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 2, as part of a corporate restructuring undertaken on
January 1, 2001 by Exelon Corporation, the parent company of PECO, certain of
PECO's operations, assets and liabilities, including those related to power
generation and enterprises, were transferred to affiliated companies of PECO.

As discussed in Note 5 to the consolidated financial statements, PECO
changed its method of accounting for nuclear outage costs in 2000. As discussed
in Note 1 to the consolidated financial statements, PECO changed its method of
accounting for derivative instruments and hedging activities effective January
1, 2001.

/s/ PRICEWATERHOUSECOOPERS LLP
----------------------------------
PricewaterhouseCoopers LLP

Philadelphia, PA
January 29, 2002

F-9

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

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

Operating Revenues
Operating Revenues....................................................... $3,953 $5,950 $5,478
------ ------ ------
Operating Revenues from Affiliates....................................... 12 -- --
------ ------ ------
Total Operating Revenues............................................. 3,965 5,950 5,478
Operating Expenses
Fuel and Purchased Power................................................. 640 2,127 2,152
Purchased Power from Affiliates.......................................... 1,162 -- --
Operating and Maintenance................................................ 527 1,791 1,454
Operating and Maintenance from Affiliates................................ 60 -- --
Merger-Related Costs..................................................... -- 248 --
Depreciation and Amortization............................................ 416 325 237
Taxes Other Than Income.................................................. 161 237 262
------ ------ ------
Total Operating Expenses............................................. 2,966 4,728 4,105
------ ------ ------
Operating Income............................................................ 999 1,222 1,373
------ ------ ------
Other Income and Deductions
Interest Expense......................................................... (405) (457) (396)
Interest Expense from Affiliates......................................... (8) -- --
Company-Obligated Mandatorily Redeemable Preferred Securities of a
Partnership, which holds Solely Subordinated Debentures of the Company. (10) (8) (21)
Equity in Earnings (Losses) of Unconsolidated Affiliates................. -- (41) (38)
Interest Income from Affiliates.......................................... 10 -- --
Other, Net............................................................... 36 41 59
------ ------ ------
Total Other Income and Deductions.................................... (377) (465) (396)
------ ------ ------
Income Before Income Taxes, Extraordinary Items and
Cumulative Effect of a Change in Accounting Principle..................... 622 757 977
Income Taxes................................................................ 197 270 358
------ ------ ------
Income Before Extraordinary Items and Cumulative Effect of a Change in
Accounting Principle...................................................... 425 487 619
Extraordinary Items (net of income taxes of $2, and $25 for 2000, and 1999,
respectively)............................................................. -- (4) (37)
Cumulative Effect of a Change in Accounting Principle (net of income taxes
of $16)................................................................... -- 24 --
------ ------ ------
Net Income.................................................................. 425 507 582
Preferred Stock Dividends................................................... 10 10 12
------ ------ ------
Net Income on Common Stock.................................................. $ 415 $ 497 $ 570
====== ====== ======

See Notes to Consolidated Financial Statements

F-10

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

Cash Flows from Operating Activities
Net Income...................................................................... $ 425 $ 507 $ 582
Adjustments to reconcile Net Income to Net
Cash Flows provided by Operating Activities:
Depreciation and Amortization................................................ 416 437 358
Extraordinary Items (net of income taxes).................................... -- 4 37
Cumulative Effect of a Change in Accounting Principle (net of income taxes).. -- (24) --
Provision for Uncollectible Accounts......................................... 69 68 59
Deferred Income Taxes........................................................ (66) 103 (7)
Merger-Related Costs......................................................... -- 248 --
Deferred Energy Costs........................................................ 29 (79) 23
Equity in (Earnings) Losses of Unconsolidated Affiliates..................... -- 41 38
Other Operating Activities................................................... 79 (76) (20)
Changes in Working Capital:
Accounts Receivable.......................................................... (54) (264) (159)
Repurchase of Accounts Receivable............................................ -- (50) (150)
Inventories.................................................................. (15) (45) (43)
Accounts Payable, Accrued Expenses & Other Current Liabilities............... (133) (85) 189
Change in Receivables and Payables to Affiliates, net........................ 73 -- --
Other Current Assets......................................................... 5 (29) (12)
------- ------ -------
Net Cash Flows provided by Operating Activities................................. 828 756 895
------- ------ -------
Cash Flows from Investing Activities
Investment in Plant.......................................................... (264) (549) (491)
InfraSource, Inc. Acquisitions............................................... -- (245) (222)
Investments in and Advances to Joint Ventures................................ -- -- (118)
Proceeds from Nuclear Decommissioning Trust Funds............................ -- 74 69
Investment in Nuclear Decommissioning Trust Funds............................ -- (100) (95)
Other Investing Activities................................................... 29 (74) (29)
------- ------ -------
Net Cash Flows used in Investing Activities..................................... (235) (894) (886)
------- ------ -------
Cash Flows from Financing Activities
Issuance of Long-Term Debt, net of issuance costs............................ 1,055 1,021 4,170
Common Stock Repurchases..................................................... -- (496) (1,705)
Retirement of Long-Term Debt................................................. (1,416) (557) (1,343)
Change in Receivable and Payable to Affiliates............................... 25 400 --
Change in Notes Payable...................................................... (60) -- (388)
Redemption of COMRPS......................................................... -- -- (221)
Redemptions of Mandatorily Redeemable Preferred Stock........................ (18) (19) (37)
Change in Restricted Cash.................................................... (69) (80) (174)
Dividends on Preferred and Common Stock...................................... (352) (167) (208)
Proceeds from Employee Stock Plans........................................... -- 47 19
Capital Lease Payments....................................................... -- -- (139)
Contribution from Parent..................................................... 225 -- --
Proceeds on the Settlement of Interest Rate Swap Agreements.................. 31 -- --
Other Financing Activities................................................... -- (16) 23
------- ------ -------
Net Cash Flows provided by (used in) Financing Activities....................... (579) 133 (3)
------- ------ -------
Increase in Cash and Cash Equivalents........................................... 14 (5) 6
Cash Transferred in Restructuring............................................... (31) -- --
Cash and Cash Equivalents at beginning of period................................ 49 54 48
------- ------ -------
Cash and Cash Equivalents at end of period...................................... $ 32 $ 49 $ 54
======= ====== =======

See Notes to Consolidated Financial Statements

F-11

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

At December 31,
----------------
2001 2000
------- -------
(in millions)

Assets
Current Assets
Cash and Cash Equivalents.................................................. $ 32 $ 49
Restricted Cash............................................................ 323 254
Accounts Receivable, net
Customer................................................................ 286 774
Other................................................................... 33 250
Inventories, at average cost
Fossil Fuel............................................................. 72 135
Materials and Supplies.................................................. 7 122
Receivable from Affiliates................................................. 8 --
Other...................................................................... 59 195
------- -------
Total Current Assets................................................. 820 1,779
------- -------
Property, Plant and Equipment, net............................................. 4,047 5,158
Deferred Debits and Other Assets
Regulatory Assets.......................................................... 5,756 6,026
Nuclear Decommissioning Trust Funds........................................ -- 440
Investments................................................................ 24 847
Goodwill, net.............................................................. -- 326
Pension Asset.............................................................. 13 --
Other...................................................................... 85 200
------- -------
Total Deferred Debits and Other Assets............................... 5,878 7,839
------- -------
Total Assets................................................................... $10,745 $14,776
======= =======
Liabilities and Shareholders' Equity
Current Liabilities
Notes Payable.............................................................. $ 101 $ 163
Payables to Affiliates..................................................... 194 1,096
Long-Term Debt Due Within One Year......................................... 548 553
Accounts Payable........................................................... 54 403
Accrued Expenses........................................................... 397 637
Deferred Income Taxes...................................................... 27 27
Other...................................................................... 21 95
------- -------
Total Current Liabilities............................................ 1,342 2,974
------- -------
Long-Term Debt 5,438 6,002
Deferred Credits and Other Liabilities
Deferred Income Taxes...................................................... 2,938 2,532
Unamortized Investment Tax Credits......................................... 27 271
Pension Obligations........................................................ -- 129
Non-Pension Postretirement Benefits Obligation............................. 239 501
Payables to Affiliates..................................................... 44 --
Other...................................................................... 110 427
------- -------
Total Deferred Credits and Other Liabilities......................... 3,358 3,860
------- -------
Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership,
which holds Solely Subordinated Debentures of the Company..................... 128 128
Mandatorily Redeemable Preferred Stock......................................... 19 37
Commitments and Contingencies
Shareholders' Equity
Common Stock............................................................... 1,912 1,442
Receivable from Parent..................................................... (1,878) --
Preferred Stock............................................................ 137 137
Retained Earnings.......................................................... 270 197
Accumulated Other Comprehensive Income (Loss).............................. 19 (1)
------- -------
Total Shareholders' Equity........................................... 460 1,775
------- -------
Total Liabilities and Shareholders' Equity..................................... $10,745 $14,776
======= =======

See Notes to Consolidated Financial Statements

F-12

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

Accumulated
Receivable Other Total
Common Preferred from Deferred Retained Comprehensive Treasury Shareholders'
Stock Stock Parent Compensation Earnings Income Stock Equity
------- --------- ---------- ------------ -------- ------------- -------- -------------
(in millions)

Balance, December 31,
1998....................... $ 3,558 $137 $ -- $-- $(501) $-- $ -- $ 3,194
Net Income.................. -- -- -- -- 582 -- -- 582
Long-Term Incentive Plan.... 19 -- -- (5) 15 -- -- 29
Deferred Compensation....... -- -- -- 2 -- -- -- 2
Common Stock Dividends...... -- -- -- -- (196) -- -- (196)
Preferred Stock Dividends... -- -- -- -- (12) -- -- (12)
Common Stock
Repurchases................ -- -- -- -- 12 -- (1,705) (1,693)
Other Comprehensive Income
net of income taxes of $3.. -- -- -- -- -- 4 -- 4
------- ---- ------- --- ----- --- ------- -------
Balance, December 31,
1999....................... 3,577 137 -- (3) (100) 4 (1,705) 1,910
Net Income.................. -- -- -- -- 507 -- -- 507
Long-Term Incentive Plan.... 47 -- -- (9) 7 -- 7 52
Deferred Compensation....... -- -- -- 5 -- -- -- 5
Common Stock Dividends...... -- -- -- -- (157) -- -- (157)
Preferred Stock Dividends... -- -- -- -- (10) -- -- (10)
Unicom Merger
Consideration.............. -- -- -- -- (45) -- -- (45)
Common Stock
Repurchases................ -- -- -- -- (5) -- (496) (501)
Stock Option Exercises...... -- -- -- -- -- -- 19 19
Cancellation of Treasury
Shares..................... (2,175) -- -- -- -- -- 2,175 --
Other Comprehensive
Income net of income
taxes of $(3).............. -- -- -- -- -- (5) -- (5)
Reorganization Pursuant to
Share Exchange............. (7) -- -- 7 -- -- -- --
------- ---- ------- --- ----- --- ------- -------
Balance, December 31,
2000....................... 1,442 137 -- -- 197 (1) -- 1,775
Net Income.................. -- -- -- -- 425 -- -- 425
Common Stock Dividends...... -- -- -- -- (342) -- -- (342)
Preferred Stock Dividends... -- -- -- -- (10) -- -- (10)
Receivable from Parent...... 1,983 -- (1,983) -- -- -- -- --
Repayment of Receivable from
Parent..................... -- -- 105 -- -- -- -- 105
Stock Option Exercises...... (26) -- -- -- -- -- -- (26)
Capital Contribution from
Parent..................... 121 -- -- -- -- -- -- 121
Net Assets Transferred in
Restructuring.............. (1,608) -- -- -- -- -- -- (1,608)
Other Comprehensive
Income net of income
taxes of $16............... -- -- -- -- -- 20 -- 20
------- ---- ------- --- ----- --- ------- -------
Balance, December 31,
2001....................... $ 1,912 $137 $(1,878) $-- $ 270 $19 $ -- $ 460
======= ==== ======= === ===== === ======= =======

See Notes to Consolidated Financial Statements

F-13

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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

Net Income...................................................................... $425 $507 $582
Other Comprehensive Income
SFAS 133 Transition Adjustment, net of income taxes of $29................... $ 40 $ -- $ --
Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(13).......... (20) -- --
Unrealized Gain (Loss) on Marketable Securities, net of income taxes of $(2)
and $2 for 2000 and 1999, respectively..................................... -- (5) 4
---- ---- ----
Total Other Comprehensive Income................................................ 20 (5) 4
---- ---- ----
Total Comprehensive Income...................................................... $445 $502 $586
==== ==== ====

See Notes to Consolidated Financial Statements

F-14

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data unless otherwise noted)

1. Significant Accounting Policies

Description of Business Incorporated in Pennsylvania in 1929, PECO Energy
Company (PECO) is engaged principally in the production, purchase,
transmission, distribution and sale of electricity to residential, commercial,
industrial and wholesale customers and the distribution and sale of natural gas
to residential, commercial and industrial customers. Pursuant to the
Pennsylvania Electricity Generation Customer Choice and Competition Act
(Competition Act), the Commonwealth of Pennsylvania has required the unbundling
of retail electric services in Pennsylvania into separate generation,
transmission and distribution services with open retail competition for
generation services. Since the commencement of deregulation in 1999, PECO
serves as the local distribution company providing electric distribution
services in its franchised service territory in southeastern Pennsylvania and
bundled electric service to customers who do not choose an alternate electric
generation supplier.

PECO is a wholly owned subsidiary of Exelon Corporation (Exelon) (see Note
3--Merger). During January 2001, Exelon undertook a corporate restructuring to
separate PECO's 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 PECO, representing the
generation and enterprises business segments were transferred to separate
subsidiaries of Exelon. As a result, beginning January 2001, the operations of
PECO consist of its retail electricity distribution and transmission business
in southeastern Pennsylvania and its natural gas distribution business located
in the Pennsylvania counties surrounding the City of Philadelphia.

As a result of the corporate restructuring, certain risks and commitments
and the financial condition and results of operations of PECO have changed
significantly. Additionally as a result of the restructuring, PECO is no longer
subject to the risks associated with nuclear insurance, decommissioning, spent
fuel disposal and energy commitments, other than its purchase power agreement
with Exelon Generation Company, LLC (Generation). See Note 19--Segment
Information for additional financial information.

Prior to the corporate restructuring effective January 2001, PECO also
engaged in the wholesale marketing of electricity on a national basis. Through
its Exelon Energy division, PECO was a competitive generation supplier offering
competitive energy supply to customers throughout Pennsylvania. PECO's
infrastructure services subsidiary, InfraSource, Inc. (InfraSource), formerly
Exelon Infrastructure Services, Inc., provided utility infrastructure services
to customers in several regions of the United States. PECO owned a 50% interest
in AmerGen Energy Company, LLC (AmerGen), a joint venture with British Energy,
Inc., a wholly-owned subsidiary of British Energy plc (British Energy), to
acquire and operate nuclear generating facilities. PECO also participated in
joint ventures which provide communications services in the Philadelphia
metropolitan region. As a result of the corporate restructuring effective
January 1, 2001, these operations were separated from the regulated energy
delivery business. See Note 2--Corporate Restructuring.

Basis of Presentation The consolidated financial statements of PECO include
the accounts of its majority-owned subsidiaries after the elimination of
intercompany transactions. In 2000 and 1999, PECO generally accounted for its
20% to 50% owned investments and joint ventures, in which it exerts significant
influence, under the equity method of accounting. In 2000 and 1999, PECO
consolidated its proportionate interest in its jointly owned electric utility
plants. PECO accounts for its less than 20% owned investments under the cost
method of accounting. Accounting policies for regulated operations are in
accordance with those prescribed by the regulatory authorities having
jurisdiction, principally the Pennsylvania Public Utility Commission (PUC), the
Federal Energy Regulatory Commission (FERC) and the Securities and Exchange
Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA).

F-15

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Accounting for the Effects of Regulation PECO accounts for all of its
regulated electric and gas operations in accordance with the Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"
(SFAS No. 71) requiring PECO to record in its financial statements the effects
of the rate regulation. Use of SFAS No. 71 is applicable to the utility
operations of PECO that meet the following criteria: (1) third-party regulation
of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs
will be recoverable from customers through rates. PECO believes that it is
probable that currently recorded regulatory assets will be recovered. If a
separable portion of PECO's business no longer meets the provisions of SFAS No.
71, PECO is required to eliminate the financial statement effects of regulation
for that portion.

Use of Estimates The preparation of financial statements in conformity with
generally accepted accounting principles (GAAP) requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates have been made in the accounting for unbilled revenue,
derivatives, environmental costs, retirement benefit costs and prior to the
corporate restructuring, nuclear decommissioning liabilities.

Revenues Operating revenues are generally recorded as service is rendered
or energy is delivered to customers. At the end of each month, PECO accrues an
estimate for the unbilled amount of energy delivered or services provided to
its electric and gas customers. In 2000 and 1999, PECO recognized contract
revenues and profits on certain long-term fixed-price contracts from its
services businesses under the percentage-of-completion method of accounting
based on costs incurred as a percentage of estimated total costs of individual
contracts.

Purchased Gas Adjustment Clause PECO's natural gas rates are subject to a
fuel adjustment clause designed to recover or refund the difference between the
actual cost of purchased gas and the amount included in base rates. Differences
between the amounts billed to customers and the actual costs recoverable are
deferred and recovered or refunded in future periods by means of prospective
quarterly adjustments to rates.

Nuclear Fuel In 2000 and 1999, the cost of nuclear fuel was capitalized and
charged to fuel expense using the unit of production method. Estimated costs of
nuclear fuel storage and disposal at operating plants were charged to fuel
expense as the related fuel was consumed.

Depreciation, Amortization and Decommissioning Depreciation is provided
over the estimated service lives of property, plant and equipment on a straight
line basis. Annual depreciation provisions for financial reporting purposes,
expressed as a percentage of average service life for each asset category are
presented below:

Asset Category 2001 2000 1999
-------------- ---- ---- ----

Electric--Transmission and Distribution 2.13% 1.82% 1.83%
Electric--Generation................... -- 5.15% 5.12%
Gas.................................... 2.34% 2.39% 2.36%
Common--Gas and Electric............... 6.26% 3.60% 4.45%
Other Property and Equipment........... 0.60% 7.82% 8.61%

Amortization of regulatory assets is provided over the recovery period as
specified in the related regulatory agreement. In 2000 and 1999, goodwill
associated with acquisitions was amortized over periods from 10 to 20 years.
Accumulated amortization of goodwill was $35 million and $1 million at December
31, 2000 and 1999, respectively. Due to the corporate restructuring, which was
effective January 2001, the Goodwill on PECO's Consolidated Balance Sheets was
transferred to Exelon Enterprises Company, LLC (Enterprises).

F-16

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Capitalized Interest Allowance for Funds Used During Construction (AFUDC)
is the cost, during the period of construction, of debt and equity funds used
to finance construction projects for regulated operations. AFUDC of $2 million,
$2 million and $4 million in 2001, 2000 and 1999, respectively, was recorded as
a charge to construction work in progress and as a non-cash credit to AFUDC
which is included in other income and deductions. The rates used for
capitalizing AFUDC are computed under a method prescribed by regulatory
authorities.

PECO uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the costs
during construction of debt funds used to finance its non-regulated
construction projects. PECO did not record any capitalized interest in 2001,
but did record capitalized interest of $2 million and $6 million in 2000 and
1999, respectively.

Income Taxes Deferred Federal and state income taxes are provided on all
significant temporary differences between book bases and tax bases of assets
and liabilities, transactions that reflect taxable income in a year different
from book income and tax carryforwards. Investment tax credits previously
utilized for income tax purposes have been deferred on the Consolidated Balance
Sheets and are recognized in book income over the life of the related property.
PECO and its subsidiaries file a consolidated Federal income tax return with
Exelon. Current and deferred income taxes of the consolidated group are
allocated to PECO based on the separate return method.

Gains and Losses on Reacquired Debt Recoverable gains and losses on
reacquired debt related to regulated operations are deferred and amortized to
interest expense over the period consistent with rate recovery for ratemaking
purposes. In 2000 and 1999, prior to the corporate restructuring, gains and
losses on reacquired debt were recognized in PECO's Consolidated Statements of
Income as incurred.

Comprehensive Income Comprehensive income includes all changes in equity
during a period except those resulting from investments by and distributions to
shareholders. Comprehensive Income is reflected in the Consolidated Statements
of Comprehensive Income.

Cash and Cash Equivalents PECO considers all temporary cash investments
purchased with an original maturity of three months or less to be cash
equivalents.

Restricted Cash Restricted cash reflects unused cash proceeds from the
issuance of the transition bonds and escrowed cash to be applied to the
principal and interest payment on the transition bonds.

Marketable Securities Marketable securities are classified as
available-for-sale securities and are reported at fair value, with the
unrealized gains and losses, net of tax, reported in other comprehensive
income. Prior to the corporate restructuring in which PECO's nuclear generating
stations were transferred to Generation (See Note 2--Corporate Restructuring),
unrealized gains and losses on marketable securities held in the nuclear
decommissioning trust funds were reported in accumulated depreciation. At
December 31, 2001 and 2000, PECO had no held-to-maturity or trading securities.

Property, Plant and Equipment Property, plant and equipment is recorded at
cost. PECO evaluates the carrying value of property, plant and equipment and
other long-term assets based upon current and anticipated undiscounted cash
flows, and recognizes an impairment when it is probable that such estimated
cash flows will be less than the carrying value of the asset. Measurement of
the amount of impairment, if any, is based upon the difference between carrying
value and fair value. The cost of maintenance, repairs and minor replacements
of property are charged to maintenance expense as incurred.

Upon retirement, the cost of regulated property plus removal costs less
salvage value, are charged to accumulated depreciation by the regulated
subsidiaries in accordance with regulatory practices. For unregulated property,
the cost and accumulated depreciation of property, plant and equipment retired
or otherwise disposed of are removed from the related accounts and included in
the determination of the gain or loss on disposition.

F-17

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Capitalized Software Costs Costs incurred during the application
development stage of software projects for software which is developed or
obtained for internal use are capitalized. At December 31, 2001 and 2000,
capitalized software costs totaled $107 million and $131 million, respectively,
net of $31 million and $49 million accumulated amortization, respectively. Such
capitalized amounts are amortized ratably over the expected lives of the
projects when they become operational, not to exceed ten years.

Derivative Financial Instruments PECO accounts for derivative financial
instruments under SFAS No. 133 "Accounting for Derivatives and Hedging
Activities" (SFAS No. 133). Under the provisions of SFAS No. 133, all
derivatives are recognized on the balance sheet at their fair value unless they
qualify for a normal purchases and normal sales exception. Changes in the fair
value of the derivative financial instruments are recognized in earnings unless
specific hedge accounting criteria are met. A derivative financial instrument
can be designated as a hedge of the fair value of a recognized asset or
liability or of an unrecognized firm commitment (fair value hedge), or a hedge
of a forecasted transaction or the variability of cash flows to be received or
paid related to a recognized asset or liability (cash flow hedge). Changes in
the fair value of a derivative that is highly effective as, and is designated
and qualifies as, a fair value hedge, along with the gain or loss on the hedged
asset or liability that is attributable to the hedged risk, are recorded in
earnings. Changes in the fair value of a derivative that is highly effective
as, and is designated as and qualifies as a cash flow hedge are recorded in
other comprehensive income, until earnings are affected by the variability of
cash flows being hedged.

In connection with Exelon's Risk Management Policy (RMP), PECO enters into
derivatives to manage its exposure to fluctuation in interest rates related to
its variable rate debt instruments, changes in interest rates related to
planned future debt issuances prior to their actual issuance and changes in the
fair value of outstanding debt which is planned for early retirement.

For 2000 and 1999, prior to the corporate restructuring, PECO utilized
derivatives to manage the utilization of its available generating capability
and provisions of wholesale energy to its affiliates. PECO also utilized energy
option contracts and energy financial swap arrangements to limit the market
price risk associated with forward energy commodity contracts. Prior to the
adoption of SFAS No. 133, PECO applied hedge accounting only if the derivative
reduced the risk of the underlying hedged item and was designated at the
inception of the hedge, with respect to the hedged item. PECO recognized any
gains or losses on these derivatives when the underlying physical transaction
affected earnings.

New Accounting Pronouncements In 2001, the FASB issued SFAS No. 141,
"Business Combinations" (SFAS No. 141), SFAS No. 142 "Goodwill and Other
Intangible Assets" (SFAS No. 142), SFAS No. 143, "Asset Retirement Obligations"
(SFAS No. 143), and SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (SFAS No. 144).

F-18

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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. As a result of the
corporate restructuring in January 2001, the goodwill was transferred to
Enterprises.

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.

Reclassifications Certain prior year amounts have been reclassified for
comparative purposes. The reclassifications did not affect net income.

2. Corporate Restructuring

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 PECO, representing PECO's generation and
enterprises business segments, were transferred to Generation and Enterprises,
respectively. Additionally, certain operations and assets and liabilities of
PECO were transferred to Exelon Business Services Company (BSC). As a result,
effective January 1, 2001, the operations of PECO consist of its retail
electricity distribution and transmission business in southeastern
Pennsylvania, and its natural gas distribution business in the Pennsylvania
counties surrounding the City of Philadelphia.

The corporate restructuring had the following effect on PECO's Consolidated
Balance Sheet:

Decrease in Assets:
Current Assets..................... $(1,085)
Property, Plant and Equipment, net. (1,212)
Investments........................ (1,262)
Other Noncurrent Assets............ (431)

(Increase) Decrease in Liabilities:
Current Liabilities................ 1,540
Long-Term Debt..................... 205
Deferred Income Taxes.............. (441)
Other Noncurrent Liabilities....... 1,003
-------
Net Assets Transferred............. $(1,683)
=======

Consideration, based on the net book value of the net assets transferred,
was as follows:

Return of Capital $1,608
Note Receivable.. 75
------
$1,683
======

In connection with the transfer, PECO entered into a power purchase
agreement (PPA) with Generation. Under the terms of the PPA, PECO obtains the
majority of its electric supply from Generation through 2010.

F-19

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Also, under the terms of the transfer, PECO assigned its rights and obligations
under various PPAs and fuel supply agreements to Generation. Generation
supplies power to PECO from the transferred generation assets, assigned PPAs
and other market sources.

As a result of the corporate restructuring, certain risks and commitments
that have been disclosed in Note 18--Commitments and Contingencies and the
future financial condition and results of operations will change significantly.
On a prospective basis, PECO will not be subject to the risks associated with
nuclear insurance, decommissioning, spent fuel disposal and energy commitments,
other than its purchase power agreement with Generation. See Note 19--Segment
Information for Additional Financial Information.

3. Merger

On October 20, 2000, Exelon became the parent corporation of PECO and
Commonwealth Edison Company (ComEd) as a result of the completion of the
transactions contemplated by an Agreement and Plan of Exchange and Merger, as
amended (Merger Agreement), among PECO, Unicom Corporation (Unicom) and Exelon.
As a result of the share exchange, Exelon became the owner of all of the common
stock of PECO. Following the share exchange, pursuant to the Merger Agreement,
Unicom merged with and into Exelon (Merger). In the Merger, each share of the
outstanding common stock of Unicom was converted into 0.875 shares of common
stock of Exelon plus $3.00 in cash. As a result of the Merger, Unicom ceased to
exist and its subsidiaries, including ComEd, became subsidiaries of Exelon.

Merger-Related Costs

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

4. Acquisitions

Sithe Energies, Inc. Acquisition On December 18, 2000, PECO acquired 49.9%
of the outstanding common stock of Sithe Energies, Inc. (Sithe) for $696
million in cash and $8 million of acquisition costs. The transaction includes
an option to purchase the remaining common stock outstanding exercisable
between December 2002 and December 2005, at a price to be determined based on
prevailing market conditions.

Sithe is an independent power generator in North America utilizing primarily
fossil and hydro generation. The purchase involves approximately 10,000
megawatts ("MW") of generation consisting of 3,800 MW of existing merchant
generation, 2,500 MW under construction, and another 3,700 MW of generation in
various stages of development, as well as Sithe's domestic marketing and
development businesses. The generation assets are located primarily in
Massachusetts and New York, but also include plants in Pennsylvania,
California, Colorado and Idaho, as well as Canada and Mexico.

In conjunction with the corporate restructuring in January 2001, PECO
transferred its investment in Sithe and the purchase option to Generation.

F-20

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

InfraSource, Inc. Acquisitions In 2000, InfraSource, Inc. (InfraSource), an
unregulated majority owned subsidiary of PECO, formerly Exelon Infrastructure
Services, Inc., acquired the stock or assets of seven utility service
contracting companies for an aggregate purchase price of approximately $245
million, net of cash acquired of $9 million, including InfraSource common stock
valued at $14 million. The acquisitions were accounted for using the purchase
method of accounting. The initial estimate of the excess of the purchase price
over the fair value of net assets acquired (goodwill) was approximately $216
million.

The allocation of purchase price to the fair value of assets acquired and
liabilities assumed in these acquisitions is as follows:

Current Assets (net of cash acquired) $ 63
Property, Plant and Equipment........ 17
Goodwill............................. 216
Current Liabilities.................. (51)
----
Total................................ $245
====

At December 31, 2000 current assets included $70 million of costs and
earnings in excess of billings on uncompleted contracts and current liabilities
includes $23 million of billings and earnings in excess of costs on uncompleted
contracts, related to InfraSource.

In conjunction with the corporate restructuring in January 2001, PECO
transferred InfraSource to Enterprises.

AmerGen Energy Company, LLC In August 2000, AmerGen completed the purchase
of Oyster Creek Nuclear Generating Facility (Oyster Creek) from GPU, Inc. (GPU)
for $10 million. Under the terms of the purchase agreement, GPU agreed to fund
outage costs not to exceed $89 million, including the cost of fuel, for a
refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU
in nine equal annual installments through 2009. In addition, AmerGen assumed
full responsibility for the ultimate decommissioning of Oyster Creek. At the
closing of the sale, GPU provided funding for the decommissioning trust of $440
million. In conjunction with this acquisition, AmerGen has received a fully
funded decommissioning trust fund which has been computed assuming the
anticipated costs to appropriately decommission Oyster Creek discounted to net
present value using the NRC's mandated rate of 2%. AmerGen believes that the
amount of the trust fund and investment earnings thereon will be sufficient to
meet its decommissioning obligation. GPU is purchasing the electricity
generated by Oyster Creek pursuant to a three-year PPA.

In conjunction with the corporate restructuring in January 2001, PECO
transferred its investment in AmerGen to Generation.

5. Accounting Changes

On January 1, 2001, PECO recognized a deferred non-cash gain of $40 million
(net of income taxes of $29 million), in accumulated other comprehensive
income, a component of shareholders' equity, to reflect the adoption of SFAS
No. 133, as amended.

During the fourth quarter of 2000, as a result of the synchronization of
accounting policies with Unicom in connection with the Merger, PECO changed its
method of accounting for nuclear outage costs to record such costs as incurred.
Previously, PECO accrued these costs over the operating unit cycle. As a result
of the change in accounting method for nuclear outage costs, PECO recorded
income of $24 million (net of income taxes of

F-21

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

$16 million). The change is reported as a Cumulative Effect of a Change in
Accounting Principle on the Consolidated Statements of Income as of December
31, 2000, representing the balance of the nuclear outage cost reserve at
January 1, 2000.

6. Regulatory Issues

In 2001, the phased process to implement competition in the electric
industry continued as mandated by the requirements of the PUC's Final
Restructuring Order.

Customer Choice The PUC's Final Restructuring Order provided for the
phase-in of customer choice of electric generation supplier (EGS) for all
customers by January 1, 2000. The Final Restructuring Order also established
market share thresholds to ensure that a minimum number of residential and
commercial customers choose an EGS or a PECO affiliate. If less than 35% and
50% of residential and commercial customers have chosen an EGS, including
residential customers assigned to an EGS as a provider of last resort default
supplier, by January 1, 2001 and January 1, 2003, respectively, the number of
customers sufficient to meet the necessary threshold levels shall be randomly
selected and assigned to an EGS through a PUC-determined process. On January 1,
2001, the 35% threshold was met for all three customer classes as a result of
agreements assigning customers to New Power Company and Green Mountain Energy
Company as providers of last resort default service. During 2001, PECO
experienced an increase in the number of customers selecting or returning to
PECO as their EGS and 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 from an
alternative generation supplier. Customers who purchase energy from an EGS
continue to pay a delivery charge.

Rate Reductions and Caps Under the Final Restructuring Order, retail
electric rates were capped at year-end 1996 levels (system-wide average of 9.96
cents/kilowatt hour (kWh)) through June 2005. The Final Restructuring Order
required PECO to reduce its retail electric rates by 8% from the 1996
system-wide average rate on January 1, 1999. This rate reduction decreased to
6% on January 1, 2000 until January 1, 2001. The transmission and distribution
rate component was capped at a system-wide average rate of 2.98 cents/kWh
through June 30, 2005. Additionally, generation rate caps, defined as the sum
of the applicable transition charge and energy and capacity charge, remain in
effect through 2010.

On March 16, 2000, the PUC issued an order authorizing PECO to securitize up
to an additional $1 billion of its authorized stranded costs recovery. In
accordance with the terms of that order, PECO provided its retail customers
with rate reductions of $60 million for calendar year 2001 only.

F-22

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Under a comprehensive settlement agreement in connection with achieving
regulatory approval of the Merger, PECO agreed to $200 million in aggregate
rate reductions for all customers in Pennsylvania over the period January 1,
2002 through 2005 and extended the rate caps on PECO's retail electric
distribution charges through December 31, 2006.

7. Supplemental Financial Information

Supplemental Income Statement Information

For the Years Ended
December 31,
------------------
2001 2000 1999
---- ---- ----

Taxes Other Than Income..................
Utility.................................. $135 $144 $155
Real estate.............................. 12 45 72
Payroll.................................. 12 27 28
Other.................................... 2 21 7
---- ---- ----
Total.................................... $161 $237 $262
==== ==== ====
Other, Net...............................
Investment income........................ $ 24 $ 50 $ 52
Gain (loss) on disposition of assets, net 6 (20) (1)
Settlement of power purchase agreement... -- 6 --
AFUDC, equity and borrowed............... 2 2 4
Other income (expense)................... 4 3 4
---- ---- ----
Total.................................... $ 36 $ 41 $ 59
==== ==== ====

Supplemental Cash Flow Information

For the Years Ended
December 31,
-------------------
2001 2000 1999
------ ---- ----

Cash paid during the year:
Interest (net of amount capitalized)................... $ 416 $431 $350
Income taxes (net of refunds).......................... $ 271 $261 $304
Non-cash investing and financing:
Contribution of Receivable from Parent.............. $1,878 -- --
Net Assets Transferred as a Result of Restructuring. $1,608 -- --
Investment in Sithe................................. -- $696 --
Issuance of InfraSource stock....................... $ -- $ 14 $ 11
Depreciation and amortization:
Property, plant and equipment....................... $ 135 $229 $207
Nuclear fuel........................................ -- 112 104
Regulatory assets................................... 275 57 --
Decommissioning..................................... 6 29 29
Goodwill............................................ -- 10 1
Leased property..................................... -- -- 17
------ ---- ----
Total Depreciation and Amortization.................... $ 416 $437 $358
====== ==== ====

F-23

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Supplemental Balance Sheet Information

At December 31,
---------------
2001 2000
- ---- ----

Investments
Investment in Sithe............... $-- $704
Energy services and other ventures -- 39
Communication ventures............ -- 35
Investment in AmerGen............. -- 44
Other Investments................. 24 25
--- ----
Total............................. $24 $847
=== ====

Regulatory Assets

Competitive transition charge.................. $4,947 $5,218
Recoverable deferred income taxes (see Note 12) 675 661
Loss on reacquired debt........................ 58 64
Compensated absences........................... 5 5
Non-pension postretirement benefits............ 71 78
------ ------
Long-Term Regulatory Assets.................... 5,756 6,026
Deferred energy costs (current asset).......... 56 86
------ ------
Total.......................................... $5,812 $6,112
====== ======

At December 31, 2001 and 2000, the Competitive Transition Charge (CTC)
includes the unamortized balance of $4.5 billion and $4.8 billion,
respectively, of Intangible Transition Property (ITP) sold to PECO Energy
Transition Trust (PETT), a wholly owned subsidiary of PECO, in connection with
the securitization of PECO's stranded cost recovery. PETT financed its purchase
of the ITP through the issuance of transition bonds. See Note 11--Long-Term
Debt. ITP represents the irrevocable right of PECO or its assignee to collect
non-bypassable charges from customers to recover stranded costs. The CTC
represents PECO's stranded costs that are recoverable through regulated rates.
The CTC is recoverable over a twelve-year period ending December 31, 2010 with
a return on the unamortized balance of 10.75%.

8. Accounts Receivable

Accounts receivable--Customer at December 31, 2001 and 2000 included
unbilled operating revenues of $100 million and $180 million, respectively. The
allowance for uncollectible accounts at December 31, 2001 and 2000 was $110
million and $131 million, respectively.

Accounts receivable--Other at December 31, 2000 included demand notes
receivable from a communications joint venture in the amount of $153 million.
The receivable has been adjusted for PECO's share of this joint venture's
operating losses incurred in excess of its investment. The notes bear interest
at the Applicable Federal Rate, compounded semi-annually. The average interest
rate on the notes receivable was 6.22% at December 31, 2000. Interest income
related to the notes receivable was $10 million in 2000. In conjunction with
the corporate restructuring in January 2001, these demand notes were
transferred to Enterprises.

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

F-24

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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 Note 11--Long-Term Debt. 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.

9. Property, Plant, and Equipment

A summary of property, plant and equipment by classification as of December
31, 2001 and 2000 is as follows:

Asset Category 2001 2000
-------------- ------ ------

Electric--Transmission and Distribution $4,058 $3,836
Electric--Generation................... -- 2,086
Gas.................................... 1,281 1,181
Common................................. 399 408
Nuclear Fuel........................... -- 1,664
Construction Work in Progress.......... 88 498
Leased Property........................ -- 2
Other Property, Plant and Equipment.... 20 197
------ ------
Total Property, Plant and Equipment. 5,846 9,872
Less Accumulated Depreciation....... 1,799 4,714
------ ------
Property, Plant and Equipment, net..... $4,047 $5,158
====== ======

Accumulated depreciation included accumulated amortization of nuclear fuel
of $1.4 billion, as well as the nuclear decommissioning liability for the
nuclear operating units of $406 million as of December 31, 2000.

The decrease in the net property, plant and equipment balance from the prior
year was primarily due to the corporate restructuring in which PECO's
generation and enterprise assets were transferred to separate subsidiaries of
Exelon (see Note 2--Corporate Restructuring).

10. Notes Payable

2001 2000 1999
----- ----- -----

Average borrowings............................. $ 3 $ 186 $ 242
Average interest rates, computed on daily basis 2.99% 6.62% 5.62%
Maximum borrowings outstanding................. $ 471 $ 500 $ 728
Average interest rates, at December 31......... 2.25% 7.18% 6.80%

PECO, along with Exelon, ComEd and Generation, is a party to a $1.5 billion
364-day unsecured revolving credit facility on December 12, 2001 with a group
of banks. PECO has a $300 million sublimit under this credit facility, which is
used principally to support PECO's commercial paper program. At December 31,
2001 and 2000, the amount of commercial paper outstanding was $101 million and
$161 million, respectively. At December 31, 2001 and 2000, there were no
borrowings under this credit facility. Interest rates on borrowings under the
credit facility are based on the London Interbank Offering Rate as of the date
of the advance.

F-25

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

11. Long-Term Debt

At December 31, 2001 At December 31,
--------------------- --------------
Maturity
Rates Date 2001 2000
----------- --------- ------ ------

PETT Bonds Series 1999-A:
Fixed rates............................... 5.63%-6.13% 2003-2007(a) $2,577 $2,706
Floating rates............................ 2.11%-2.18% 2003-2007(a) 310 1,132
PETT Bonds Series 2000-A:.................... 7.3%-7.65% 2002-2009(a) 890 1,000
PETT Bonds Series 2001:...................... 6.52% 2010(a) 805 --
First and Refunding Mortgage Bonds (b) (c):
Fixed rates............................... 5.95%-8.00% 2002-2022 1,027 1,148
Floating rates............................ 1.35%-2.35% 2012 154 154
Notes payable................................ 7.25% 2003-2004 -- 14
Pollution control notes:
Fixed rates............................... 5.20%-5.30% 2021-2034 157 157
Floating rates............................ 1.75% 2027 17 212
Notes payable - accounts receivable agreement 2.00% 2005 55 40
----------- --------- ------ ------
Total Long-Term debt (d)..................... 5,992 6,563
Unamortized debt discount and premium, net... (6) (8)
Due within one year.......................... (548) (553)
------ ------
Long-Term debt............................... $5,438 $6,002
====== ======

--------
(a) The maturity date represents the expected final payment date which is the
date when all principal and interest of the related class of transition
bonds is expected to be paid in full in accordance with the expected
amortization schedule for the applicable class. The date when all principal
and interest must be paid in full for the PETT Bonds Series 1999-A, 2000-A
and 2001-A are 2003 through 2009, 2003 through 2010 and 2010, respectively.
The current portion of transition bonds is based upon the expected maturity
date.
(b) Utility plant of PECO is subject to the lien of its mortgage indenture.
(c) Includes first mortgage bonds issued under the PECO mortgage indenture
securing pollution control notes.
(d) Long-term debt maturities in the period 2002 through 2006 and thereafter
are as follows:

2002...... $ 548
2003...... 690
2004...... 318
2005...... 503
2006...... 500
Thereafter 3,433
------
Total..... $5,992

In 2001, PECO Energy Transition Trust (PETT), a Delaware business trust and
a wholly-owned subsidiary of PECO, refinanced $805 million of floating rate
Series 1999-A transition bonds through the issuance by PETT of fixed-rate
transition bonds (Series 2001-A transition bonds). Approximately 72% of Class
A-3 and 70% of the Class A-5 Series 1999-A transition bonds were redeemed. The
Series 2001-A transition bonds are non-callable, fixed-rate securities with an
interest rate of 6.52%. The Series 2001-A transition bonds have an expected
final payment date of September 1, 2010 and a termination date of December 31,
2010.

Also in 2001, PECO issued, through a private placement, $250 million of its
First and Refunding Mortgage Bonds, with an interest rate of 5.95% and a
maturity date of November 11, 2011. Proceeds from the first mortgage bonds were
used to repay a $250 million aggregate principal amount of PECO's First and
Refunding Mortgage Bonds having an interest rate of 5.625% and a maturity date
of November 1, 2001.

F-26

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

In 1999, PECO entered into treasury forwards associated with the anticipated
issuance of the Series 2000-A transition bonds. On May 2, 2000, these
instruments were settled with net proceeds to the counterparties of $13 million
which has been deferred and is being amortized over the life of the Series
2000-A transition bonds as an increase to interest expense.

In 1998, PECO entered into treasury forwards and forward-starting interest
rate swaps to manage interest rate exposure associated with the anticipated
issuance of the Series 1999-A transition bonds. On March 18, 1999, these
instruments were settled with net proceeds of $80 million to PECO which were
deferred and are being amortized over the life of the Series 1999-A transition
bonds as a reduction of interest expense.

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 due to the transaction no
longer being probable. 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.

At December 31, 2001 and 2000, the aggregate unamortized net gain on the
settlement of PECO transactions was $55 million and $51 million, respectively.

In 2000 and 1999, PECO incurred extraordinary charges aggregating $6 million
($4 million, net of tax) and $62 million ($37 million, net of tax),
respectively for prepayment premiums and the write-offs of unamortized deferred
financing costs associated with the early retirement of debt.

12. Income Taxes

Income tax expense (benefit) is comprised of the following components:

For the Year Ended
December 31,
----------------
2001 2000 1999
---- ---- ----

Included in operations:
Federal
Current......................................................... $255 $181 $293
Deferred........................................................ (49) 91 6
Investment tax credit, net...................................... (3) (15) (14)
State
Current......................................................... 8 2 72
Deferred........................................................ (14) 11 1
---- ---- ----
$197 $270 $358
==== ==== ====
Included in extraordinary item:
Federal
Current......................................................... $ -- $ (2) $(19)
State
Current......................................................... -- -- (6)
---- ---- ----
$ -- $ (2) $(25)
==== ==== ====
Included in cumulative effects of changes in accounting principles:
Federal
Deferred........................................................ $ -- $ 13 $ --
State
Deferred........................................................ -- 3 --
---- ---- ----
$ -- $ 16 $ --
==== ==== ====

F-27

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

The effective income tax rate varies from the U.S. Federal statutory rate
for the years ended December 31 principally due to the following:

For the Year Ended
December 31,
----------------
2001 2000 1999
---- ---- ----

U.S. Federal statutory rate.............................. 35.0% 35.0% 35.0%
Increase (decrease) due to:
Plant basis differences............................... (0.8) (0.8) (0.8)
State income taxes, net of Federal income tax benefit. (0.6) 2.7 4.8
Amortization of investment tax credit................. (0.4) (1.9) (1.6)
Prior period income taxes............................. (1.5) 0.5 (0.7)
Other, net............................................ -- 0.2 (0.1)
---- ---- ----
Effective income tax rate................................ 31.7% 35.7% 36.6%
==== ==== ====

The tax effects of temporary differences giving rise to significant portions
of PECO's deferred tax assets and liabilities as of December 31, 2001 and 2000
are presented below:

2001 2000
------ ------

Deferred tax liabilities:
Plant basis difference.......................... $2,990 $2,839
Deferred investment tax credit.................. 27 271
Deferred debt refinancing costs................. 31 34
------ ------
Total deferred tax liabilities..................... 3,048 3,144
------ ------
Deferred tax assets:
Deferred pension and postretirement obligations. (12) (187)
Other, net...................................... (44) (127)
------ ------
Total deferred tax assets.......................... (56) (314)
------ ------
Deferred income taxes (net) on the balance sheet... $2,992 $2,830
====== ======

In accordance with regulatory treatment of certain temporary differences,
PECO has recorded a regulatory asset for recoverable deferred income taxes of
$675 million and $661 million at December 31, 2001 and 2000, respectively.
These recoverable deferred income taxes include the deferred tax effects
associated principally with liberalized depreciation accounted for in
accordance with the ratemaking policies of the PUC, as well as the revenue
impacts thereon, and assume continued recovery of these costs in future rates.

The Internal Revenue Service and certain state tax authorities are currently
auditing certain tax returns of PECO. The current audits are not expected to
have an adverse impact on financial condition or results of operations of PECO.

13. Retirement Benefits

PECO has adopted defined benefit pension plans and postretirement welfare
benefit plans 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

F-28

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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.
Benefits under these pension plans generally reflect each employee's
compensation, years of service, and age at retirement. Funding is based upon
actuarially determined contributions that take into account the amount
deductible for income tax purposes and the minimum contribution required under
the Employee Retirement Income Security Act of 1974, as amended. The following
tables provide a reconciliation of benefit obligations, plan assets, and funded
status for PECO's proportionate allocated interest in the plans.

Other
Postretirement
Pension Benefits Benefits
--------------- ------------
2001 2000 2001 2000
------- ------ ----- -----

Change in Benefit Obligation:
Net benefit obligation at beginning of year.... $ 2,230 $2,054 $ 922 $ 798
Service cost................................... 11 24 9 18
Interest cost.................................. 84 158 43 66
Plan amendments................................ 20 -- -- --
Actuarial (gain)loss........................... 11 140 92 69
Curtailments/Settlements....................... 2 (74) -- 4
Special accounting costs(benefit).............. (16) 96 (2) 11
Gross benefits paid............................ (93) (168) (24) (44)
Corporate Restructuring Transfer............... (1,206) -- (499) --
------- ------ ----- -----
Net benefit obligation at end of year.......... $ 1,043 $2,230 $ 541 $ 922
======= ====== ===== =====
Change in Plan Assets:
Fair value of plan assets at beginning of year. $ 3,005 $2,982 $ 263 $ 244
Actual return on plan assets................... (59) 190 (2) 8
Employer contributions......................... 9 1 26 54
Plan participants' contributions............... -- -- -- 1
Gross benefits paid............................ (93) (168) (24) (44)
Corporate Restructuring Transfer............... (1,625) -- (142) --
------- ------ ----- -----
Fair value of plan assets at end of year....... $ 1,237 $3,005 $ 121 $ 263
======= ====== ===== =====
Funded status at end of year................... $ 194 $ 775 $(420) $(659)
Unrecognized net actuarial (gain)loss.......... (225) (960) 132 36
Unrecognized prior service cost................ 51 77 -- --
Unrecognized net transition obligation (asset). (7) (21) 49 122
------- ------ ----- -----
Net asset (liability) recognized at end of year $ 13 $ (129) $(239) $(501)
======= ====== ===== =====

Pension Benefits Other Postretirement Benefits
---------------- -------------------------------------------
2001 2000 1999 2001 2000 1999
---- ---- ---- ------------- ------------- -------------

Weighted-average assumptions as of
December 31,
Discount rate............................ 7.35% 7.60% 8.00% 7.35% 7.60% 8.00%
Expected return on plan assets........... 9.50% 9.50% 9.50% 9.50% 8.00% 8.00%
Rate of compensation increase............ 4.00% 5.00% 5.00% 4.00% 4.30% 5.00%
Health care cost trend on covered charges N/A N/A N/A 10.00% 7.00% 8.00%
decreasing decreasing decreasing
to ultimate to ultimate to ultimate
trend of 4.5% trend of 5.0% trend of 5.0%
in 2008 in 2005 in 2006

F-29

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Other Postretirement
Pension Benefits Benefits
------------------- -------------------
2001 2000 1999 2001 2000 1999
----- ----- ----- ---- ---- ----

Components of net periodic benefit cost (benefit):
Service cost...................................... $ 12 $ 25 $ 29 $ 10 $ 18 $ 19
Interest cost..................................... 84 158 154 43 66 57
Expected return on assets......................... (131) (238) (222) (11) (18) (16)
Amortization of:
Transition obligation (asset)..................... (2) (5) (4) 6 12 12
Prior service cost................................ 4 7 5 -- -- --
Actuarial (gain) loss............................. (13) (26) (8) -- -- --
Curtailment charge (credit)....................... 1 (12) -- (5) 24 --
Settlement charge (credit)........................ (1) (16) -- -- -- --
----- ----- ----- ---- ---- ----
Net periodic benefit cost (benefit)............... $ (46) $(107) $ (46) $ 43 $102 $ 72
===== ===== ===== ==== ==== ====
Special accounting costs.......................... $ 16 $ 96 $ -- $ (2) $ 11 $ --
===== ===== ===== ==== ==== ====

Sensitivity of retiree welfare results

Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components........................... $ 7
on postretirement benefit obligation.................................... $ 59
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components........................... $ (6)
on postretirement benefit obligation.................................... $(50)

The decrease in the net benefit obligation and the fair value of plan assets
in 2001 as compared to 2000 is due primarily to the corporate restructuring
(See Note 2--Corporate Restructuring). Amounts of the obligation allocated to
affiliates in the restructuring were primarily based on the relative number of
active employees transferred to each affiliate.

Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plans.

Special accounting costs of $16 million and $96 million in 2001 and 2000,
respectively, represent accelerated separation and enhancement benefits
provided to PECO employees expected to be terminated as a result of the Merger.
PECO provides certain health care and life insurance benefits for retired
employees through plans sponsored by Exelon. Welfare benefits for active
employees are provided by several insurance policies or self-funded plans whose
premiums or contributions are based upon the benefits paid during the year.

PECO has savings plans for the majority of its employees. The plans allow
employees to contribute a portion of their pretax income in accordance with
specified guidelines. PECO matches a percentage of the employee contribution up
to certain limits. The cost of PECO's matching contribution to the savings
plans totaled $7 million, $11 million and $7 million in 2001, 2000, and 1999,
respectively.

F-30

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

14. Preferred and Preference Stock

At December 31, 2001 and 2000, Series Preference Stock of PECO, no par
value, consisted of 100,000,000 shares authorized, of which no shares were
outstanding. At December 31, 2001 and 2000, cumulative Preferred Stock of PECO,
no par value, consisted of 15,000,000 shares authorized and the amounts set
forth below:

At December 31,
-----------------------------
Current 2001 2000 2001 2000
Redemption --------- --------- ---- ----
Price (a) Shares Outstanding Amount
---------- ------------------- ---------

Series (without mandatory redemption)
$4.68................................ $104.00 150,000 150,000 $ 15 $ 15
$4.40................................ 112.50 274,720 274,720 27 27
$4.30................................ 102.00 150,000 150,000 15 15
$3.80................................ 106.00 300,000 300,000 30 30
$7.48................................ (b) 500,000 500,000 50 50
------- --------- --------- ---- ----
1,374,720 1,374,720 137 137
Series (with mandatory redemption)
$6.12................................ (c) 185,400 370,800 19 37
------- --------- --------- ---- ----
Total preferred stock................ 1,560,120 1,745,520 $156 $174
======= ========= ========= ==== ====

--------
(a) Redeemable, at the option of PECO, at the indicated dollar amounts per
share, plus accrued dividends.
(b) None of the shares of this series is subject to redemption prior to April
1, 2003.
(c) PECO made the annual sinking fund payments of $18.5 million on August 1,
2001 and August 2, 2000. The future sinking fund requirement in 2002 is
$18.5 million.

15. Company--Obligated Mandatorily Redeemable Preferred Securities of a
Partnership

At December 31, 2001 and 2000, PECO Energy Capital, L.P. (Partnership), a
Delaware limited partnership of which a wholly owned subsidiary of PECO is the
sole general partner, had outstanding Company-Obligated Mandatorily Redeemable
Preferred Securities of a Partnership (COMRPS) as set forth in the following
table:

At December 31,
--------------------------------------
Mandatory 2001 2000 2001 2000
Redemption Distribution Liquidation --------- --------- ---- ----
Date Rate Value Trust Securities Outstanding Amount
---------- ------------ ----------- ---------------------------- ---------

PECO Energy
Capital Trust II. 2037 8.00% $ 25 2,000,000 2,000,000 $ 50 $ 50
PECO Energy
Capital Trust III 2028 7.38% 1,000 78,105 78,105 78 78
---- ---- ------ --------- --------- ---- ----
Total............. 2,078,105 2,078,105 $128 $128
==== ==== ====== ========= ========= ==== ====

The securities issued by the PECO trusts represent Company-Obligated
Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) having a
distribution rate and liquidation value equivalent to the trust securities. The
COMRPS are the sole assets of these trusts and represent limited partnership
interests of PECO Energy Capital, L.P. (Partnership), a Delaware limited
partnership. Each holder of a trust's securities is entitled to withdraw the
corresponding number of COMRPS from the trust in exchange for the trust
securities so held. Each series of COMRPS is supported by PECO's deferrable
interest subordinated debentures, held by the Partnership, which bear interest
at rates equal to the distribution rates on the related series of COMRPS.

The interest expense on the debentures is included in Other Income and
Deductions in the Consolidated Statements of Income and is deductible for
income tax purposes.

F-31

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

16. Common Stock

At December 31, 2001 and 2000, common stock without par value consisted of
600,000,000 and 600,000,000 shares authorized and 170,478,507 and 170,478,507
shares outstanding, respectively.

Stock Repurchase In January 2000, in connection with the Merger Agreement,
PECO entered into a forward purchase agreement to purchase $500 million of its
common stock from time to time. Settlement of this forward purchase agreement
was, at PECO's election, on a physical, net share or net cash basis. In May
2000, PECO utilized a portion of the proceeds from the securitization of its
stranded cost recovery to physically settle this agreement, resulting in the
repurchase of 12 million shares of common stock for $496 million. In connection
with the settlement of this agreement, PECO received $1 million in accumulated
dividends on the repurchased shares and paid $6 million of interest.

During 1997, PECO's Board of Directors authorized the repurchase of up to 25
million shares of its common stock from time to time through open-market,
privately negotiated and/or other types of transactions in conformity with the
rules of the SEC. Pursuant to these authorizations, PECO entered into forward
purchase agreements to be settled from time to time, at PECO's election, on a
physical, net share or net cash basis. PECO utilized the proceeds from the
securitization of a portion of its stranded cost recovery in the first quarter
of 1999, to physically settle these agreements, resulting in the purchase of 21
million shares of common stock for $696 million. In connection with the
settlement of these agreements, PECO received $18 million in accumulated
dividends on the repurchased shares and paid $6 million of interest.

Shares Outstanding The following table details PECO's common stock and
treasury stock:

Common Treasury
Shares Shares
------- --------
(in thousands)

Balance, December 31, 1998........ 224,684 --
Long-Term Incentive Plan Issuances 670 --
Common Stock Repurchases.......... -- 44,082
------- -------
Balance, December 31, 1999........ 225,354 44,082
Long-Term Incentive Plan Issuances -- (195)
Cancellation of Treasury Shares... (54,875) (54,875)
Common Stock Repurchases.......... -- 11,950
Stock Option Exercises............ -- (962)
------- -------
Balance, December 31, 2000........ 170,479 --
------- -------
Balance, December 31, 2001........ 170,479 --
======= =======

F-32

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

17. Fair Value of Financial Assets and Liabilities

The carrying amounts and fair values of PECO's financial assets and
liabilities as of December 31, 2001 and 2000 were as follows:

2001 2000
--------------- ---------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------ -------- ------

Non-derivatives:
Liabilities...............................................
Long-term debt (including amounts due within one year). $5,986 $6,199 $6,555 $6,797
COMRPS.................................................... $ 128 $ 127 $ 128 $ 122
Mandatorily Redeemable....................................
Preferred Stock........................................ $ 19 $ 10 $ 37 $ 30
Derivatives:
Interest rate swaps.................................... $ (19) $ (19) -- $ (19)
Forward interest rate swaps............................ -- -- -- $ 40

Cash and cash equivalents, customer accounts receivable and trust accounts
for decommissioning nuclear plants are recorded at their fair value.

As of December 31, 2001 and 2000, PECO's carrying amounts of cash and cash
equivalents and accounts receivable are representative of fair value because of
the short-term nature of these instruments. Fair values of the trust accounts
for decommissioning nuclear plants, long-term debt, COMRPS and Mandatorily
Redeemable Preferred Stock are estimated based on quoted market prices for the
same or similar issues. The fair value of PECO's interest rate swaps and power
purchase and sale contracts is determined using quoted exchange prices,
external dealer prices, or internal valuation models which utilize assumptions
of future energy prices and available market pricing curves.

Financial instruments that potentially subject PECO to concentrations of
credit risk consist principally of cash equivalents and customer accounts
receivable. PECO places its cash equivalents with high-credit quality financial
institutions. Generally, such investments are in excess of the Federal Deposit
Insurance Corporation limits. Concentrations of credit risk with respect to
customer accounts receivable are limited due to PECO's large number of
customers and their dispersion across many industries.

In 1999, PECO entered into interest rate swaps to manage interest rate
exposure in the aggregate notional amount of $326 million. These swaps have
been designated as cash-flow hedges under SFAS No. 133, and as such, as long as
the hedge remains effective and the underlying transaction remains probable,
changes in the fair value of these swaps will be recorded in accumulated other
comprehensive income (loss) until earnings are affected by the variability of
the cash flows being hedged.

The notional amount of derivatives do not represent amounts that are
exchanged by the parties and, thus, are not a measure of PECO's exposure. The
amounts exchanged are calculated on the basis of the notional or contract
amounts, as well as on the other terms of the derivatives, which relate to
interest rates and the volatility of these rates.

PECO would be exposed to credit-related losses in the event of
non-performance by the counterparties that issued the derivative instruments.
The credit exposure of derivatives contracts is represented by the fair value
of contracts at the reporting date. PECO's interest rate swaps are documented
under master agreements. Among other things, these agreements provide for a
maximum credit exposure for both parties. Payments are required by the
appropriate party when the maximum limit is reached.

F-33

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

On January 1, 2001, PECO deferred a non-cash gain of $40 million, net of
income taxes, in accumulated other comprehensive income, a component of
shareholders' equity, to reflect the initial adoption of SFAS No. 133, as
amended. SFAS No. 133 is applied to all derivative instruments and requires
that such instruments be recorded in the balance sheet either as an asset or a
liability measured at their fair value through earnings, with special
accounting permitted for certain qualifying hedges.

For 2001, $6 million ($4 million, net of income taxes) was reclassified from
accumulated other comprehensive income into earnings as a result of forecasted
financing transactions no longer being probable.

As of December 31, 2001, $15 million of deferred net gains on derivative
instruments accumulated in other comprehensive income are expected to be
reclassified to earnings during the next twelve months. Amounts in accumulated
other comprehensive income related to interest rate cash flows are reclassified
into earnings when the forecasted interest payment occurs.

18. Commitments and Contingencies

Environmental Issues 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 manufactured gas plant (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, PECO transferred a portion of the
environmental investigation and remediation costs to Generation. PECO cannot
reasonably estimate whether it will incur other significant liabilities for
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.

Leases Minimum future operating lease payments, which consist primarily of
lease payments for autos, as of December 31, 2001 were:

2002............................... $ 2
2003............................... 2
2004............................... 2
2005............................... 2
2006............................... 2
Remaining years.................... 3
---
Total minimum future lease payments $13
===

Rental expense under operating leases totaled $2 million, $36 million, and
$54 million in 2001, 2000 and 1999, respectively.

Litigation

General. PECO is involved in various litigation matters. The ultimate
outcome of such matters, while uncertain, is not expected to have a material
adverse effect on its respective financial condition or results of operations.

F-34

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

19. Segment Information

As a result of the corporate restructuring in January 2001, PECO operates in
one segment--energy delivery. Energy delivery consists of the retail
electricity distribution and transmission business of PECO in southeastern
Pennsylvania and the natural gas distribution business of PECO located in the
Pennsylvania counties surrounding the City of Philadelphia. Prior to 2001, PECO
operated in two other business segments, generation and enterprises. See Note
2--Corporate Restructuring.

Generation consisted of electric generating facilities, energy marketing
operations and PECO's interests in Sithe and AmerGen. Enterprises consisted of
competitive retail energy sales, energy and infrastructure services,
communications and other investments weighted towards the communications,
energy services and retail services industries. Prior to 2001, PECO evaluated
the performance of its business segments based on Earnings Before Interest
Expense and Income Taxes (EBIT). An analysis and reconciliation of PECO's
business segment information to the respective information in the consolidated
financial statements are as follows:

Energy Intersegment
Delivery Generation Enterprises Corporate Eliminations Consolidated
-------- ---------- ----------- --------- ------------ ------------

Total Revenues:
2000.......................... $ 3,373 $2,803 $ 697 $ -- $(923) $ 5,950
1999.......................... 3,265 2,411 644 -- (842) 5,478
Intersegment Revenues:
2000.......................... $ 4 $ 872 $ 47 $ -- $(923) $ --
1999.......................... -- 842 -- -- (842) --
EBIT (a):
2000 (b)...................... $ 1,139 $ 341 $(136) $(172) $ -- $ 1,172
1999.......................... 1,372 379 (212) (194) -- 1,345
Depreciation and Amortization:
2000.......................... $ 195 $ 98 $ 32 $ -- $ -- $ 325
1999.......................... 108 125 4 -- -- 237
Capital Expenditures:
2000.......................... $ 219 $ 243 $ 64 $ 23 $ -- $ 549
1999.......................... 205 245 1 40 -- 491
Total Assets:
2000.......................... $13,100 $1,648 $ 991 $(963) $ -- $14,776
1999.......................... 10,306 1,734 640 407 -- 13,087

--------
(a) EBIT consists of operating income, equity in earnings (losses) of
unconsolidated affiliates, and other income and expenses recorded in other,
net with the exception of investment income. Investment income for 2000 and
1999 was $50 million and $52 million, respectively.
(b) Includes non-recurring items of $248 million for Merger-related expenses in
2000.

Equity in losses of communications joint ventures of $45 million and $38
million for 2000, and 1999, respectively, are included in the Enterprises
business unit's EBIT. Equity in earnings of AmerGen and Sithe of $4 million for
2000 are included in the generation business unit's EBIT.

20. Related Party Transactions

At December 31, 2000, PECO had a $400 million payable to ComEd, which was
repaid in the second quarter of 2001. The average annual interest rate on this
payable for the period outstanding was 6.5%. Interest expense related to this
payable for 2001 was $8 million.

F-35

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Effective January 1, 2001, Exelon contributed to PECO a $2.0 billion
non-interest bearing receivable related to Exelon's agreement to fund future
income tax payments resulting from the collection of competitive transition
charges. This receivable is reflected as a reduction of Shareholders' Equity in
PECO's Consolidated Balance Sheets and is expected to be settled over the years
2002 through 2010. As of December 31, 2001, the balance of this receivable from
Exelon was $1.9 billion. In addition, at December 31, 2001, PECO had a $60
million payable to Exelon related to stock options in 2000.

PECO paid common stock dividends of $342 million to Exelon in 2001.

In connection with the transfer of the generation assets in the corporate
restructuring, PECO entered into a PPA with Generation. See Note 2--Corporate
Restructuring. Intercompany power purchases pursuant to the PPA for 2001 were
$1,162 million. As of December 31, 2001, PECO's payable related to the PPA was
$90 million. In addition, at December 31, 2001, PECO had a $28 million payable
to Generation for various services.

Effective January 1, 2001, upon the corporate restructuring, PECO receives a
variety of corporate support services from BSC, including legal, human
resources, financial and information technology services. Such services,
provided at cost including applicable overhead, were $36 million for 2001.

At December 31, 2001, there was a $41 million payable to BSC. During 2001,
PECO received intercompany interest income of $10 million primarily related to
bills and payroll paid on behalf of BSC.

PECO received services from Enterprises during 2001 for deployment of
automated meters and meter reading services for $24 million. At December 31,
2001, PECO had recorded a $8 million payable to Enterprises.

21. Quarterly Data (Unaudited)

The data shown below include all adjustments which PECO considers necessary
for a fair presentation of such amounts:

Income (Loss) Before
Extraordinary Items and
Operating Operating Cumulative Effect of a Change
Revenues Income in Accounting Principle Net Income (Loss)
------------- ------------ ---------------------------- ----------------
2001 2000 2001 2000(a) 2001 2000(a) 2001 2000(a)
Quarter ended: ------ ------ ---- ------- ---- ------- ---- -------

March 31..... $1,051 $1,352 $287 $343 $122 $166 $122 $195
June 30...... $ 906 $1,385 $246 $313 $ 85 $124 $ 85 $118
September 30. $1,051 $1,629 $258 $449 $104 $238 $104 $235
December 31.. $ 957 $1,584 $208 $117 $114 $(41) $114 $(41)

--------
(a) Reflects incremental Merger expenses of $11 million, $9 million, $13
million and $215 million ($129 million, net of tax) for each of the four
quarters in 2000, respectively, which were reflected in Operating and
Maintenance expense.

F-36

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

Schedule II--Valuation and Qualifying Accounts
(in millions)

Column A Column B Column C Column D Column E Column F
-------- ---------- ------------------- ---------- ------------- ----------
Additions
-------------------
Balance at Charged to Changed Balance at
Beginning Cost and to Other Restructuring End of
Description of Year Expenses Accounts Deductions Transfers (a) Year
----------- ---------- ---------- -------- ---------- ------------- ----------

For the Year Ended December 31,
2001
Allowance for Uncollectible Accounts $131 $69 $-- $67(b) $23 $110
Reserve for:
Injuries and Damages............. $ 21 $13 $-- $ 9(c) $-- $ 25
Environmental Investigation and
Litigation..................... $ 54 $-- $-- $ 2(d) $15 $ 37
Obsolete Materials............... $ 3 $ 6 $-- $ 7 $ 1 $ 1
For the Year Ended December 31,
2000
Allowance for Uncollectible Accounts $121 $68 $-- $49(b) $-- $131
Reserve for:
Injuries and Damages............. $ 23 $ 7 $-- $ 9(c) $-- $ 21
Environmental Investigation and
Litigation..................... $ 57 $-- $-- $ 3(d) $-- $ 54
For the Year Ended December 31,
1999
Allowance for Uncollectible Accounts $122 $59 $-- $69(b) $-- $112
Reserve for:
Injuries and Damages............. $ 27 $ 7 $-- $11(c) $-- $ 23
Environmental Investigation and
Litigation..................... $ 60 $-- $-- $ 3(d) $-- $ 57

--------
(a) Represents amounts transferred as part of the Corporate Restructuring. See
Note 2 of the Notes to the Consolidated Financial Statements.
(b) Write-off of individual accounts receivable.
(c) Payments of claims and related costs.
(d) Expenditures for site investigation and remediation.

F-37

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

[LOGO]
Peco/R/
An Exelon Company

PECO Energy Company

OFFER TO EXCHANGE

$250,000,000
5.95% First and Refunding
Mortgage Bonds due 2011
(Exchange Bonds)

Which have been registered under the Securities Act
For Any and All Outstanding

$250,000,000
5.95% First and Refunding
Mortgage Bonds due 2011

Which have not been so registered

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