Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o.

The number of shares outstanding of each registrant’s common stock as of ~~March 31,~~June 30, 2004 was:

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Exelon Corporation Yes þ No o Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC Yes o No þ.

This combined Form 10-Q is being filed separately by Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.

~~Except for the historical information contained herein, certain~~Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, as well as the items discussed in (a) the Registrants’ 2003 Annual Report on Form 10-K — ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants’ 2003 Annual Report on Form 10-K — ITEM 8. Financial Statements and Supplementary Data: Exelon — Note 19, ComEd — Note 15, PECO — Note 14 and Generation — Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. 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, the web site maintained by the SEC at www.sec.gov and Exelon’s website at www.exeloncorp.com.

Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the energy delivery, wholesale generation and ~~the~~ enterprises businesses discussed below (see Note 1517 — Segment Information). The energy delivery business segment consists of the purchase and sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and by PECO Energy Company (PECO) in southeastern Pennsylvania and the purchase and sale of natural gas and related distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. The generation business segment consists of the electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation) and Generation’s equity interest in EXRES SHC, Inc., the holding company of Sithe Energies, Inc. and its subsidiaries, ~~and hereafter~~ referred to herein as Sithe. The enterprises business segment consists of the energy and infrastructure services of Exelon Enterprises Company, LLC (Enterprises), a communications joint venture and other investments weighted towards the communications, energy services and retail services industries. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. As of June 30, 2004, the enterprises business segment consists of the energy, infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises) and other investments related to the communications, energy services and retail services industries. See Note 3 — Acquisitions and Dispositions for further information regarding the disposition of businesses within the Enterprises segment.

~~In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), the~~The consolidated financial statements ~~of each~~ of Exelon, ComEd, PECO and Generation each include the accounts of entities in which it has a controlling financial interest, other than certain financing trusts of ComEd and PECO described below, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies the registrant as the primary beneficiary of the variable interest entity. Investments and joint ventures in which Exelon, ComEd, PECO and Generation do not have a controlling financial interest and certain financing trusts of ComEd and PECO are accounted for under the equity or cost methods of accounting.

In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), Sithe, a 50% owned subsidiary of Generation, iswas consolidated in the financial statements of Exelon and Generation as of March 31, ~~2004 due to the adoption of FIN No. 46-R.~~2004. Certain trusts and limited partnerships that are financing subsidiaries of ComEd and PECO have issued debt or mandatorily redeemable preferred securities. Due to the adoption of FIN No. 46-R, these trusts and limited partnerships are no longer consolidated within the financial statements of Exelon, ~~and~~ ComEd or PECO as of December 31, 2003, or as of July 1, 2003 for PECO Energy Capital Trust IV (PECO Trust IV). See Note 2 — New Accounting Principles for further discussion onof the adoption of FIN 46-R and the resulting consolidation of Sithe and the deconsolidation of these financing entities.

The accompanying consolidated financial statements as of ~~March 31,~~June 30, 2004 and for the three and six months then ended are unaudited but, in the ~~opinions~~opinion of the ~~managements~~management of each of Exelon, ComEd, PECO and Generation, include all adjustments that are considered necessary for a fair presentation of ~~their~~its respective financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). All adjustments are of a normal, recurring nature, except as otherwise disclosed. The share and per-share amounts included in Exelon’s consolidated financial statements and combined notes to consolidated financial statements have been adjusted for all periods presented to reflect a 2-for-1 stock split of Exelon’s common stock. See Note 14 — Earnings Per Share and Shareholders’ Equity for additional information regarding the stock split. The December 31, 2003 Consolidated Balance Sheets were derived from audited financial statements. These combined notes to consolidated financial statements ~~but~~ do not include all disclosures required by GAAP. Certain prior-year amounts have been reclassified for comparative purposes.

These reclassifications had no effect on net income or shareholders’ or member’s equity. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation included in or incorporated by reference in ITEM 8 of their Annual Reports on Form 10-K for the year ended December 31, 2003.

~~CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

The FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN No. 46) in January 2003 and subsequently issued its revision in FIN No. 46-R in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46 was effective for Exelon’s variable interest entities created after January 31, 2003 and FIN No. 46-R was effective December 31, 2003 for Exelon’s other variable interest entities that were considered to be special-purpose entities. FIN No. 46-R applied to all other variable interest entities as of March 31, 2004.

Exelon and Generation consolidated Sithe as of March 31, 2004 pursuant to the provisions of FIN No. 46-R and recorded income of $32 million (net of income taxes) as a result of the elimination of a guarantee of Sithe’s commitments previously recorded by Generation. This income was reported as a cumulative effect of a change in accounting principle in the first quarter of 2004. Generation is a 50% owner of Sithe, and Exelon and Generation had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owns and operates power-generating facilities. See Note 4 — Sithe for ~~a further discussion of~~additional information on the consolidation of ~~Sithe as of March 31, 2004.~~Sithe.

PECO ~~Energy Capital~~ Trust IV, ~~(PECO Trust IV),~~ a financing subsidiary of PECO created in May 2003, was deconsolidated from the financial statements of Exelon and PECO pursuant to the provisions of FIN No. 46 as of July 1, 2003. AsPursuant to the provisions of FIN No. 46-R, as of December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II, ComEd Financing III, ComEd Funding LLC and ComEd Transitional Funding Trust, were deconsolidated from the financial statements of Exelon and ComEd, and the other financing trusts of PECO, namely PECO Energy Capital Trust III (PECO Trust III) and PECO Energy Transition Trust (PETT), were deconsolidated from the financial statements of Exelon and ~~of ComEd and PECO, respectively, pursuant to the provisions of FIN No. 46-R.~~PECO. Amounts owed to these financing trusts were recorded as debt to financing trusts or affiliates within the Consolidated Balance Sheets at ~~March 31,~~June 30, 2004 and December 31, 2003 as follows:

This change in presentation had no ~~impact~~effect on the net income of Exelon, ComEd or PECO. In accordance with FIN No. 46-R, prior periods were not reclassified.

FASB Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Exelon, ComEd, PECO and Generation were required to adopt SFAS No. 143 as of January 1, 2003. A significant retirement obligation is Generation’s obligation to decommission its nuclear plants at the end of their license lives. See Note 11 — Asset Retirement Obligations for additional information.

After considering interpretations of the transitional guidance included in SFAS No. 143, Exelon recorded income of $112 million (net of income taxes) as a cumulative effect of a change in accounting principle in

~~CONDENSED~~ COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A significant retirement obligation is Generation’s obligation to decommission its nuclear plants at the end of their license lives. See Note 13 — Asset Retirement Obligations for additional information.

Exelon recorded income of $112 million (net of income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of ~~this standard~~SFAS No. 143 in the first quarter of 2003. The components of the cumulative effect of a change in accounting principle, net of income taxes, were as follows:

The cumulative effect of the change in accounting principle in adopting SFAS No. 143 had no ~~impact~~effect on PECO’s income statement.

In July 2003, the Emerging Issues Task Force (EITF) of the FASB reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’ ” (EITF 03-11), which was ratified by the FASB in August 2003. The EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Exelon and Generation adopted EITF 03-11 as of January 1, 2004 and presented ~~$213~~$239 million of revenue, ~~$206~~$238 million of purchased power and $7$1 million of fuel expense net within revenues during the three months ended ~~March 31,~~June 30, 2004 and $452 million of revenue, $444 million of purchased power and $8 million of fuel expense net within revenues during the six months ended June 30, 2004. Prior periods were not reclassified. The adoption of EITF 03-11 had no effect on the net income of Exelon or Generation. Had EITF 03-11 been retroactively applied to 2003, operating revenues, purchased power ~~expense~~ and fuel expense would have been ~~$252 million, $232 million, and $20 million lower for the three months ended March 31, 2003, respectively. The adoption of EITF 03-11 had no impact on net income of Exelon or Generation.~~affected as follows:

Through its postretirement benefit plans, Exelon provides retirees with prescription drug coverage. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, the FASB issued FASB Staff Position (FSP) FAS 106-1 (FSP FAS 106-1) in January 2004, which permits a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon has made the one-time election allowed by FSP FAS 106-1. Thus, any measures of non-pension postretirement benefit obligations or net periodic postretirement benefit costs in the financial statements and included in Note 9 — Retirement Benefits do not reflect the effects of the Prescription Drug Act on Exelon’s postretirement plans. Exelon is evaluating what impact the Prescription Drug Act will have on its postretirement benefit plans and whether it will be eligible for a Federal subsidy beginning in 2006. Specific

~~CONDENSED~~ COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Through its postretirement benefit plans, Exelon provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Actuarial equivalence has not yet been formally defined by the U.S. Department of Health and Human Services and thus is a matter of judgment by the plan sponsor and its actuaries. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), which provides transition guidance for accounting for the effects of the Prescription Drug Act and supersedes FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004.

During the second quarter of 2004, Exelon early adopted the provisions of FSP FAS 106-2, resulting in a remeasurement of its postretirement benefit plans’ assets and accumulated postretirement benefit obligations (APBO) as of December 31, 2003. Upon adoption, the effect of the subsidy on benefits attributable to past service was accounted for as an actuarial experience gain, resulting in a decrease of the APBO of approximately $177 million. The annualized reduction in the net periodic postretirement benefit cost is estimated to be approximately $32 million compared to the annual cost calculated without considering the effects of the Prescription Drug Act. The effect of the subsidy on the components of net periodic

~~authoritative guidance on the accounting~~postretirement benefit cost for the ~~Federal subsidy is pending,~~three and ~~that guidance,~~six months ended June 30, 2004 included in the consolidated financial statements and Note 11 — Retirement Benefits was as follows:

The following table presents Exelon’s net income and earnings per share for the three months ended March 31, 2004 as if FSP FAS 106-2 was adopted as of January 1, 2004. Previously reported historical financial information for the three months ended March 31, 2004 has been adjusted in the table below and will be adjusted when ~~issued, could require Exelon~~presented for comparative purposes in future periods to ~~change previously reported information.~~reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.


(a)	A portion of the net periodic postretirement benefit cost is capitalized within Exelon’s Consolidated Balance Sheets.

The following table presents net income of ComEd and Generation and net income on common stock of PECO for the three months ended March 31, 2004 as if FSP FAS 106-2 was adopted as of January 1, 2004. Historical financial information for the three months ended March 31, 2004 has been adjusted in the table below and will be adjusted when presented for comparative purposes in future periods to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.


(b)	A portion of the net periodic postretirement benefit cost is capitalized within the Consolidated Balance Sheets.

In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-01, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-01). EITF 03-01 provides guidance for evaluating whether an investment is other-than-temporarily impaired and

will be applied in other-than-temporary impairment evaluations made by Exelon beginning in the third quarter of 2004. Exelon adopted the disclosure requirements of EITF 03-01 for investments accounted for under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity ~~Securities”~~Securities,” within its financial statements for the year ended December 31, 2003. For all other investments within the scope of EITF 03-01 and for cost method investments, the disclosures will be effective for Exelon for the year ended December 31, 2004. Comparative information for periods prior to initial application is not required. Exelon, isComEd, PECO and Generation are still evaluating the potential ~~impacts~~impact of the adoption of EITF 03-01.

In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). The EITF concluded that if investors in a limited liability company have specific ownership accounts, they should follow the guidance prescribed in Statement of Position 78-9, “Accounting for Investments in Real Estate Ventures,” and EITF Topic No. D-46, “Accounting for Limited Partnership Investments.” Otherwise, investors should follow the significant influence model prescribed in Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” EITF 03-16 will be effective for Exelon, ComEd, PECO and Generation during the third quarter of 2004. Exelon, isComEd, PECO and Generation are still evaluating the potential impact of the adoption of EITF 03-16.

On May 25, 2004, Exelon and Generation ~~are in~~completed the ~~process~~sale, transfer and assignment of ~~an orderly transition out of the~~ ownership of their indirect wholly owned subsidiary Boston Generating, LLC (Boston Generating), which was formerly owned by Sithe, and Boston Generating’s Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities. The decision to transition out of the projects was made as a result of an evaluation of the projects and discussions with the lenders under Boston Generating’s $1.25 billion credit facility, which was entered into primarily to finance the development and construction of the Mystic 8 and 9 and Fore River generating facilities. The Boston Generating Facility is non-recourse to Exelon and Generation, and an event of default under the Boston Generating Facility does not constitute an event of default under any other of Exelon’s debt instruments or the debt instruments of Exelon’s subsidiaries.

On February 23, 2004, Generation and the lenders entered into a settlement that (subject to closing conditions being met) will result in a sale to a special purpose entity owned by the lenders of the equity interest in Boston Generating, which owns the companies that own ~~the~~ Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, ~~and~~to a ~~transfer of responsibility for plant operations and power marketing activities.~~special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility (Boston Generating Credit Facility).

The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. The Federal Energy Regulatory Commission (FERC) approved the sale of Boston Generating will be substantively a non-cash transaction, with the Boston Generating credit facility continuing as a liability of Boston Generating at the time it is sold, without recourse to Exelon or Generation. Generation affiliates will continue to operate and market power from the plants pending completion of the second stage, when Generation affiliates will transfer plant operations and power marketing

~~CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~activities to an entity or entities designated by the lenders. The agreement for the sale and transfer remains~~ in full force and effect regardless of the future financial performance or condition of Boston Generating. Upon reaching this agreement, Exelon and Generation have classified the assets and liabilities of Boston Generating as held for sale. See Assets and Liabilities Held for Sale below for information regarding the classification of the assets and liabilities of Boston Generating as held for sale as of March 31,May 2004.

~~Certain aspects of the sale of the ownership interest in Boston Generating and the transfer of responsibility~~ Responsibility for plant operations and power marketing activities ~~require~~will be transferred to the lenders’ special purpose entity in a separate transaction. Certain aspects of the transfer of operations and marketing are also subject to approval of the Federal Energy Regulatory Commission (FERC). The parties have filed an application with the FERC for an order authorizing the sale of ownership of Boston Generating. The parties anticipate the sale of ownership will be completed during the second quarter of 2004. Subsequent to the sale of ownership of Boston Generating,FERC. On June 24, 2004, the parties ~~will file~~filed an application with the FERC for an order authorizing the transfer of responsibility for plant operations and power marketing, ~~activities. Although~~and the parties ~~anticipate the~~expect to complete that transfer ~~of responsibility for plant operations and power marketing will be completed~~ during the third quarter of ~~2004,~~2004. Pending completion of the transfer of operations and marketing activities, Generation ~~has~~affiliates will continue to operate and market power from the plants on behalf of the owners. Due to ongoing power marketing agreements ~~to market a portion~~between Generation and Boston Generating, the results of Boston ~~Generating’s power through 2005.~~Generating have not been classified as a discontinued operation within the Consolidated Statements of Income and Comprehensive Income of Exelon and Generation. Exelon and Generation are hedged to eliminate the financial effects of these power-marketing-agreements from their results of operations.

In connection with the settlement reached on February 23, 2004, Exelon, Generation, the lenders and Raytheon Company (Raytheon), the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements, entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities. See Note 1315 — Commitments and Contingencies for information regarding the settlement of litigation associated with the projects.

In connection with the decision to transition out of ~~the ownership of~~ Boston Generating and the generating units, Generation recorded during the third quarter of 2003 an impairment charge of its long-lived assets pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), of $945 million ($573 million net of income taxes) in operating expenses within its Consolidated Statements of Income and Comprehensive Income. As a result of Boston Generating’s liabilities being greater than its assets at the time of the sale, transfer and assignment of ownership, Exelon and Generation recorded a gain of $85 million ($52 million net of income taxes) in other income and deductions within the Consolidated Statements of Income and Comprehensive Income in the second quarter of 2004. In connection with the sale, Exelon and Generation recorded a liability associated with a guarantee by their subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. See Note 15 — Commitments and Contingencies for further information regarding the guarantee.

Boston Generating was reported in the Generation segment of Exelon’s consolidated financial statements prior to its sale. At the date of the sale, Boston Generating had approximately $1.2 billion in assets, primarily consisting of property, plant and equipment, and approximately $1.3 billion of liabilities of which approximately $1.0 billion was debt outstanding under the Boston Generating Credit Facility. As of the date of transfer, these amounts were eliminated from the Consolidated Balance Sheets of both Exelon and Generation. Exelon’s and Generation’s Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2004 and 2003 include the following financial results related to Boston Generating:


(a)	Net income for the three and six months ended June 30, 2004 included an after-tax gain of $52 million related to the sale of Boston Generating in the second quarter of 2004.

See Note 5 — Selected Pro Forma and Consolidating Financial Information for the effect of the sale of Boston Generating as if the transaction had occurred on January 1, 2003 and was included in Exelon and Generation’s results from that date.

Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, resulting in prepayment penalties of $9 million, which were recorded in interest expense.

Exelon Services, Inc. During the six months ended June 30, 2004, Enterprises disposed of certain businesses of Exelon Services, Inc. (Services), including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale (before income taxes) recorded during the ~~third~~six months ended June 30, 2004 related to the disposition of these Services businesses were $34 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of June 30, 2004,

Services had assets and liabilities of $58 million and $90 million, respectively, which primarily represented the corporate operations and the remaining businesses of the Mechanical and Integrated Technology Group. See Assets and Liabilities Held for Sale below for information regarding the classification of the assets and liabilities of the remaining business of Services as held for sale as of June 30, 2004.

PECO TelCove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003. ~~Generation does not expect~~

InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. (InfraSource). See the Notes to ~~incur any additional losses as a result~~Consolidated Financial Statements in Exelon’s 2003 Form 10-K for further information regarding this sale. Enterprises’ results of operations for the ~~consummation of~~three and six months ended June 30, 2004 compared to the same periods in 2003 were significantly affected by the sale ~~contemplated by~~of InfraSource.

The results of Exelon Thermal and Services have been included in income from continuing operations within Exelon’s Consolidated Statements of Income and Comprehensive Income (as opposed to discontinued operations) as the ~~settlement agreement.~~impact of these entities on Exelon’s consolidated financial statements was not significant.

Effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. The transaction had no ~~impact~~effect on the assets and liabilities of Exelon Energy Company, which were previously reported as a part of the Enterprises segment. Beginning in 2004, Exelon Energy Company’s assets and liabilities and results of operations are included in Generation’s financial statements. Generation and Enterprises’ 2003 segment information ~~was~~has been adjusted to reflect this transfer in Note 1517 — Segment Information.

The following summary represents the assets and liabilities of Exelon Energy Company that were transferred to Generation as of January 1, 2004:

26See Note 5 — Selected Pro Forma and Consolidating Financial Information for the effect of the transfer of Exelon Energy Company to Generation as if the transaction had occurred on January 1, 2003 and was included in Generation’s results from that date.

On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen) for $277 million. The allocation of fair value related to the

~~CONDENSED~~ COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Onvaluation of long-lived assets will be affected by the finalization of the purchase price based on the completion of the review of the closing AmerGen balances at December ~~22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen) for $277 million.~~31, 2003.

Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity method investment. For the three and six months ended ~~March 31,~~June 30, 2003, Generation recorded ~~$64~~$20 million and $84 million, respectively, of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and recorded ~~$67~~$110 million and $177 million, respectively, of purchased power from AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $311 million. For the ~~first quarter of~~six months ended June 30, 2004, AmerGen’s assets and liabilities and results of operations are included in Generation’s financial statements.

~~Effective January 1, 2004, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities. The estimated service lives were extended by 20 years~~See Note 5 — Selected Pro Forma and Consolidating Financial Information for the three AmerGen stations. These changes were based on engineering and economic feasibility analyses performed by Generation. The service life extension is subject to approval by the Nuclear Regulatory Commission (NRC)effect of an extension of the existing NRC operating licenses. Generation has not applied for license extensions at these facilities, but anticipates filing an extension request for the Oyster Creek Nuclear Generating Station (Oyster Creek), and is planning on filing for license extensions at Unit 1 at the Three Mile Island Nuclear Station (TMI) and the Clinton Nuclear Power Station (Clinton) in a timeline consistent and integrated with the other planned extension filings of the Generation nuclear fleet.

~~The following unaudited pro forma financial information gives effect to~~ the acquisition of the remaining 50% interest in AmerGen by Generation ~~and the transfer of Exelon Energy Company to Generation~~ as if the ~~transactions~~transaction had occurred on January 1, 2003 and ~~were~~was included in Exelon and Generation’s results from that date.

~~CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~


~~(a)~~	~~Exelon did not recognize the full benefit of the cumulative effect of change in accounting principle related to AmerGen’s adoption of SFAS No. 143.~~

The above unaudited pro forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if these acquisitions had actually occurred on that date, nor of the results that may be obtained in the future.

~~The major classes of assets and liabilities classified as held for sale within Exelon’s Consolidated Balance Sheets as of March 31, 2004 consisted of the following:~~

~~Generation.~~ Generation classified the assets and liabilities of Boston Generating with net liabilities of $179 million as held for sale as of March 31, 2004. The net liabilities held for sale for Boston Generating exclude receivables from Generation that eliminate in consolidation. See Sale of Ownership Interest in Boston Generating, LLC above for further information regarding a settlement with the lenders under the Boston

~~CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

Generating Facility. Additionally, $17 million of the net assets of Sithe that were consolidated at March 31, 2004 under the provisions of FIN No. 46-R were classified as assets and liabilities held for sale.

~~Exelon Thermal Holdings Inc.~~ In December 2003, Enterprises signed an agreement to sell its Chicago business of Exelon Thermal Holdings, Inc. (Thermal) for approximately $135 million, subject to working capital adjustments. The agreement to sell the Chicago thermal operations is subject to customary closing conditions and approval from the City of Chicago (Chicago) under Thermal’s Chicago franchise agreement and is expected to close during the second quarter of 2004. The debt of the Chicago thermal operations is required to be repaid by Enterprises prior to closing, which, in the absence of relief from the debt holders, will result in prepayment penalties. The total debt outstanding of the Chicago thermal operations as of March 31, 2004 was $37 million. The assets and liabilities of certain entities of Exelon Thermal were classified as held for sale as of March 31, 2004.

~~Exelon Services Inc.~~ Exelon classified the assets and liabilities of certain Exelon Services, Inc. (Exelon Services) entities as held for sale as of March 31, 2004 due to ongoing efforts to dispose of these businesses. These entities are expected to be sold in 2004.

In November 2003, Exelon purchased interests in two synthetic fuel-producing facilities. The purchase price for these facilities included a combination of cash, notes payable and contingent consideration dependent upon the production level of the facilities. These facilities are not consolidated within Exelon’s financial statements because Exelon does not have a controlling financial interest in these facilities. The notes payable recorded for the purchase of the facilities was $238 million. Exelon’s right to acquire its share of tax credits generated by the facilities was recorded as an intangible asset and will be amortized as the tax credits are earned. Synthetic fuel facilities chemically change coal, including waste and marginal coal, into a fuel used at power plants. In April 2004, the Internal Revenue Service (IRS) issued two private letter rulings that affirmed that the process used by the facilities will produce a solid synthetic fuel that qualifies for tax credits under Section 29 of the Internal Revenue Code. See Note 19 — Subsequent Events for information regarding investments in synthetic fuel-producing facilities that occurred in July 2004.

The major classes of assets and liabilities classified as held for sale within Exelon’s and Generation’s Consolidated Balance Sheets as of June 30, 2004 consisted of the following:

Generation. Generation classified certain assets and liabilities of Sithe as held for sale as of June 30, 2004. Sithe is consolidated within the financial statements of Generation pursuant to FIN No. 46-R. During

the three months ended June 30, 2004, Sithe completed the sale of its gas and Australian businesses, which represented $151 million and $140 million of assets and liabilities held for sale, respectively, at March 31, 2004.

Enterprises. Enterprises classified the assets and liabilities of certain Services businesses as held for sale as of June 30, 2004 due to ongoing efforts to dispose of these businesses. These businesses are expected to be sold in 2004. See “Disposition of Enterprises Entities” above for further information.

Sithe is primarily engaged in the development, construction, ownership and operation of electric wholesale generating facilities in North America. At ~~March 31,~~June 30, 2004, excluding assets held for sale, Sithe operated nine power plants ~~representing an aggregate~~with total average net capacity of 1,323 megawatts (MW). Sithe also has 49.5% interests in two ~~230 MW~~230-MW projects in Mexico, which ~~are expected to commence~~commenced commercial operations during the second quarter of 2004.

The financial statements of all foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for the Consolidated Statements of Income and Comprehensive Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on the Consolidated Statements of Income and Comprehensive Income and accordingly have no effect on net income.

On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe (Generation owned 49.9% prior to November 25, 2003). Generation’s intent is to fully divest ofits interest in Sithe. See the 2003 Form 10-K for further details regarding these transactions.

Exelon and Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN No. 46-R. See Note 2 — New Accounting Principles ~~and Accounting Changes~~ for ~~a discussion of Sithe in relation to FIN No. 46-R.~~further discussion.

As a result of the series of transactions referred to above, the consolidation of Sithe at March 31, 2004 was accounted for as a step acquisition pursuant to purchase accounting policies. Under the provisions of FIN No. 46-R, the operating results of Sithe ~~will be~~were included in Exelon’s and Generation’s results of operations beginning April 1, 2004. Sithe has entered into tolling arrangements (Tolling Agreement) with Dynegy Power Marketing and its affiliates ~~that~~with respect to Sithe’s Independence Station. The Tolling Agreement commenced on July 1, 2001 and ~~run~~runs through 2014. Additionally, Sithe has entered into an ~~Energy~~energy purchase agreement (Energy Purchase ~~Agreement (EPA)~~Agreement) with Consolidated Edison Company relating to the Independence Station, which continues through 2014. As a result of the acquisition accounting described above, values were assigned to the Tolling Agreement and ~~EPA~~the Energy Purchase Agreement on March 31, 2004 of approximately $91 million and $282 million, respectively, which have been recorded as intangible assets on Exelon’s and Generation’s Consolidated Balance Sheets in deferred debits and other assets. These amounts were determined based on fair value techniques utilizing the contract terms and various other estimates including forward power prices, discount rates and option pricing models. The intangible assets representing the Tolling Agreement and the Energy Purchase Agreement are being amortized using a method that reflects the pattern in which the economic benefits of the intangible assets are consumed or used up in accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), not to exceed the

~~CONDENSED~~ COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

have been recorded as intangible assets on Exelon’s and Generation’s Consolidated Balance Sheets in deferred debits and other assets. The Tolling Agreement and EPA will be amortized using a method that reflects the pattern in which the economic benefits of the intangible assets are consumed or used up in accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” not to exceed the terms of the ~~contract.~~related contracts. The allocation of fair value related to the valuation of long-lived assets is preliminary and ~~will~~is anticipated to be finalized in the ~~second~~third quarter of 2004.

Sithe’s intangible assets are subject to amortization and are included in other non-current assets on Generation’s Consolidated Balance Sheet. Amortization expense for intangible assets was $15 million for the three months ended June 30, 2004. The components of Sithe’s intangible assets at June 30, 2004 were as follows:

Annual amortization expense for intangible assets is estimated to be $43 million for 2004, $58 million for 2005, $56 million for 2006, $50 million for 2007, and $44 million for 2008.

In connection with the consolidation of Sithe, certain indemnification guarantees, which were previously recorded in accordance with the provisions of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of ~~Indebtness~~Indebtedness of Others” (FIN No. 45), at Generation on November 25, 2003 pursuant to the series of transactions referred to above, were reversed in accordance with FIN No. 45 as Generation can no longer record liabilities associated with guarantees for the performance of a consolidated entity. The reversal of the guarantees resulted in Exelon and Generation recording income of $32 million (net of income taxes) as a cumulative effect of a change in accounting principle. The ~~following~~ condensed consolidating financial information included in Note 5 — Selected Pro Forma and Consolidating Financial Information presents the financial position of Exelon, Generation and Sithe, as well as consolidating entries related primarily to acquisition notes payables and receivables between Generation and Sithe.

Generation was the primary beneficiary under FIN No. 46-R required analysis of the economic benefits accruing to all parties pursuant to their ownership interests supplemented by management’s judgment. Sithe’s

total assets and total liabilities as of ~~March 31,~~June 30, 2004 were ~~$1,503~~$1,423 million and ~~$1,399~~$1,338 million, respectively. As required by FIN No. 46-R, upon the occurrence of a future triggering event, such as a change in ownership, management will reassess its investment in Sithe to determine if Generation continues to qualify as the primary beneficiary. If management determines in a future period that Sithe no longer qualifies to be consolidated within the financial statements of Exelon and Generation pursuant to FIN No. 46-R, ~~this determination~~the resulting deconsolidation of Sithe could have a significant ~~impact~~effect on the Consolidated Balance Sheets of Exelon and Generation and classifications within their Consolidated Statements of Income and Comprehensive Income. The consolidation of Sithe did not have an ~~impact~~effect on Exelon’s and Generation’s income before the cumulative effect of changes in accounting principles for the ~~three~~six months ended ~~March 31,~~June 30, 2004, and Exelon and Generation do not anticipate that the consolidation will have a significant ~~impact~~effect on net income in future periods.

In addition to Sithe, management reviewed other entities with which Exelon and its subsidiaries have business relationships to determine if those entities were variable interest entities that ~~required consolidation~~should be consolidated under FIN No. 46-R and concluded that those entities should not be consolidated within ~~Exelon’s~~the financial ~~statements. Had management determined that consolidation~~statements of ~~one or more of these entities was required, this determination could have had an impact on the consolidated financial statements.~~Exelon, ComEd, PECO and Generation.

New Accounting Pronouncements

See Note 2 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for discussion of new accounting pronouncements.

5871

EXELON CORPORATION

Executive ~~Summary~~Overview

Financial Results. Exelon’s diluted earnings per average common share increased by ~~10%~~37% for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003, primarily as a result of decreased losses at Enterprises, an increase in net income at Generation and favorable tax effects from investments in synthetic ~~fuel producing~~fuel-producing facilities. Enterprises recorded a gain on the sale of Exelon Thermal Holdings, Inc. (Exelon Thermal) of $36 million (before income taxes and net of debt prepayment penalties), while Enterprises’ 2003 income reflected a goodwill impairment charge of $47 million (before income taxes) and investment-related impairment charges of $35 million (before income taxes). The increase in Generation’s net income reflects an $85 million gain (before income taxes) on the sale of Boston Generating, LLC (Boston Generating) during the second quarter of 2004. Exelon’s investments in synthetic fuel-producing facilities ~~partially offset~~provided a tax benefit of $48 million and increased Exelon’s net income for the three months ended June 30, 2004 by $15 million.

Exelon’s diluted earnings per average common share increased by 25% for the six months ended June 30, 2004 as compared to the same period in 2003, primarily as a ~~decrease~~result of decreased losses at Enterprises, an increase in net income at ~~Energy Delivery.~~Generation and favorable tax effects from investments in synthetic fuel-producing facilities. Enterprises results were affected by the 2004 gain recorded on the sale of Thermal and the 2003 goodwill and investment impairment charges discussed above. The increase in Generation’s net income reflects a 2003 impairment charge of $200 million (before income taxes) related to Generation’s investment in Sithe and an ~~increase in~~$85 million gain (before income taxes) on the ~~first~~sale of Boston Generating during the second quarter of 2004 in revenues net of purchased power and fuel expense, partially offset by increased operating and maintenance expense primarily resulting from the acquisition of AmerGen in December 2003. The net income of Energy Delivery was unfavorably affected by a decrease in revenues net of purchased power and fuel expense and increased depreciation and amortization expense, partially offset by reduced operating and maintenance expense and interest expense.2004. In the first quarter of 2004, Exelon recorded an after-tax gain of $32 million in accordance with FIN No. ~~46-R.~~46-R and the resulting consolidation of Sithe. In the first quarter of 2003, Exelon recorded an after-tax gain of $112 million upon the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Asset Retirement Obligations” (SFAS No. 143).

The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Exelon — Executive Summary” in the 2003 Form 10-K for a discussion of Exelon’s implementation of The Exelon Way.

Investment Strategy. Exelon continued to follow a disciplined approach in investing to maximize the earnings and cash flows from its assets and businesses and to divest those assets and businesses that do not meet its goals. Highlights in the first ~~quarter~~half of 2004 ~~included:~~include:

• On ~~February 23,~~May 25, 2004, Generation ~~and the lenders under the Boston Generating, LLC (Boston Generating) $1.25 billion credit facility (Boston Generating Facility) entered into a settlement that will result in~~completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns the companies that own ~~the~~ Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, ~~and the transfer of responsibility for plant operations and power marketing activities~~ to a special purpose entity owned by the ~~lenders. Exelon also settled certain litigation associated with the projects. Upon entering into the sale agreement with the~~ lenders ~~the assets and liabilities~~under Boston Generating’s $1.25 billion credit facility. The resulting pre-tax gain of ~~Boston Generating were classified as held for sale~~$85 million ($52 million after-tax) was recorded within Exelon’s Consolidated ~~Balance Sheet.~~Statements of Income and Comprehensive Income during the second quarter of 2004.

• Exelon continued to execute its divestiture strategy for Enterprises by selling ~~three~~five units of Exelon Services, Inc. (Services) during the ~~first quarter of~~six months ended June 30, 2004 for ~~estimated sales~~total expected proceeds of $3$34 million ~~plus existing working capital~~subject to post-closing adjustments, and ~~entering into an agreement in April 2004 to sell~~selling its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for ~~estimated sales~~ proceeds of $49 ~~million.~~million in June 2004. Exelon ~~expects to close~~closed on the sale of the Chicago business of Exelon Thermal during the second quarter of 2004 for net cash proceeds of $134 million and expects to close on the sale of the Aladdin thermal facility during the second half of 2004.

Enterprises continues to pursue the divestiture of other businesses and investments; however, it may be unable to fully divest certain businesses and investments for a number of reasons, including an inability to locate appropriate buyers or negotiate acceptable terms for the transactions. In addition, the amount that Enterprises may realize from a divestiture is subject to market conditions that may contribute to pricing and other terms that are materially less than expected and could result in a loss on the sale. Timing of any divestitures may positively or negatively affect the results of operations. As of June 30, 2004, Enterprises had total assets and liabilities of $592 million and $200 million, respectively.

Financing Activities. Exelon made payments of approximately $345 million for the purpose of retiring PECO and ComEd transition trust long-term debt and repaid approximately ~~$181~~$237 million of ~~transition trust notes and $182 million of~~other net long-term debt ~~resulting in expected annual interest savings of $23 million.~~during the six months ended June 30, 2004. Exelon met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions. In January 2004, Exelon announced a 10% increase in its quarterly dividend on its common stock ~~from $0.50 to $0.55 per share,~~ and approved a 2-for-1 ~~stock~~ split of its common stock. The ~~record~~distribution date was May 5, 2004. The share and per-share amounts included in this Form 10-Q have been adjusted for all periods presented to reflect the stock ~~split was April 19,~~split. In the second quarter of 2004, Exelon’s Board of Directors approved a discretionary share repurchase program. Exelon purchased common stock, held as treasury shares as of June 30, 2004, totaling $75 million during the second quarter of 2004. Exelon also replaced its $750 million 364-day unsecured revolving credit agreement with a $1 billion five-year facility and ~~the distribution date will be May 5,~~reduced its $750 million three-year facility to $500 million in a transaction that closed on July 16, 2004.

~~Operations.~~Regulatory Developments. On ~~March 18,~~May 1, 2004, ~~the Federal Energy Regulatory Commission (FERC) approved ComEd’s plan to complete the integration of~~ComEd fully integrated its transmission facilities into PJM Interconnection (PJM) subject to the North American Electric Regulatory Commission (NERC) approval of PJM and Midwest ISO reliability plans to assure no adverse impacts. The NERC granted the required approval on April 2, 2004. On April 27, 2004, the FERC issued its order approving ComEd’s application to fully integrate into PJM on May 1, 2004. ComEd intends to accept the conditions in the FERC order and expects full integration to occur on that date.. PECO and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and

competitive markets for the sale and purchase of ~~electricity.~~electric energy and capacity. Upon joining PJM, ComEd ~~will begin to incur incremental~~began incurring administrative fees, which are expected to approximate $30 million annually. ~~However,~~ Exelon believes such costs will ultimately be ~~more than~~partially offset by the benefits of full access to a wholesale competitive marketplace, ~~but~~particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on Exelon.

ComEd currently earns approximately $66 million annually from through and out (T&O) rates for energy flowing across ComEd’s transmission system. On March 19, 2004, the Federal Energy Regulatory Commission (FERC) issued an order to ~~Exelon.~~

eliminate these rates effective May 1, 2004, which was subsequently deferred until December 1, 2004. The T&O rates are to be replaced by a new long-term transmission pricing structure that will eliminate seams in the PJM and Midwest ISO regions. Transmission owners in PJM and Midwest ISO and other parties must file one or more pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. While Exelon and ComEd cannot predict the outcome of the FERC’s final determination of a new long-term transmission pricing structure, such pricing structure could adversely impact Exelon’s and ComEd’s results of operations.

See ComEd’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Executive Overview” for further information regarding Regulatory Developments.

Operations. Generation’s nuclear fleet achieved a ~~90.5%~~93.3% capacity factor infor the ~~first quarter of~~six months ended June 30, 2004 compared to ~~94.4%~~94.2% in the ~~first quarter~~same period of 2003 primarily as a result of increased planned outage days.

Outlook for the Remainder of 2004 and Beyond. Exelon’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Exelon — Executive Summary” in the 2003 Form 10-K.

Results of Operations — Exelon Corporation


	Three Months Ended ~~March 31,~~June 30, 2004 Compared To Three Months Ended ~~March 31,~~June 30, 2003


	2004			2003			Variance			% Change			2004			2003			Variance			% Change

Operating revenues	$	3,722		$	4,074		$	(352	)		(8.6	)%	$	3,550		$	3,721		$	(171	)		(4.6	)%
Purchased power and fuel expense		1,398			1,737			(339	)		(19.5	)%		1,211			1,387			(176	)		(12.7	)%
Operating and maintenance expense		1,115			1,109			6			0.5	%		1,056			1,100			(44	)		(4.0	)%
Operating income		716			757			(41	)		(5.4	)%		783			800			(17	)		(2.1	)%
Other income and deductions		(193	)		(360	)		167			(46.4	)%		(48	)		(205	)		157			(76.6	)%
Income before income taxes and cumulative effect of changes in accounting principles		523			397			126			31.7	%
Income before cumulative effect of changes in accounting principles		374			249			125			50.2	%
Cumulative effect of changes in accounting principles		32			112			(80	)		(71.4	)%
Income before income taxes and minority interest														735			595			140			23.5	%
Net income		406			361			45			12.5	%		521			372			149			40.1	%
Diluted earnings per share		1.22			1.11			0.11			9.9	%		0.78			0.57			0.21			36.8	%

Operating Revenues. Operating revenues decreased for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003 primarily due to decreased revenues at Enterprises due to the sale of the majority of the businesses of InfraSource, Inc. (InfraSource) during the third quarter of 2003, decreased competitive transition charge (CTC) collections at ComEd and Generation’s adoption of Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’ ” (EITF 03-11) in ~~the first quarter~~2004. Generation’s adoption of EITF 03-11 during 2004 ~~that~~ changed the presentation of certain power transactions and decreased operating revenues by ~~$213 million. The adoption of EITF 03-11~~$239 million for the three months ended June 30, 2004 but had no ~~impact~~effect on net income. The decreases in operating revenues were partially offset by higher delivery volume and favorable weather conditions at Energy Delivery and an increase in market sales at Generation due to the acquisition of the remaining 50% of AmerGen Energy Company, LLC (AmerGen) and the consolidation of Sithe. See further discussion of operating revenues by segment below.

Purchased Power and Fuel Expense.Purchased power and fuel expense decreased during the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003 primarily due to Generation’s adoption of EITF 03-11 during 2004, ~~that changed the presentation of certain power transactions and~~which resulted in a decrease in purchased power ~~expense~~ and fuel expense of ~~$206 million and $7 million, respectively.~~$239 million. In addition, purchased power decreased due to ~~the~~ Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense. Purchased power represented 23% of Generation’s total supply for the three months ended ~~March 31,~~June 30, 2004 compared to ~~37%~~36% for the same period in 2003. See further discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense. Operating and maintenance expense decreased ~~slightly~~ for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003 primarily due to decreased expenses at Enterprises due to the sale of the majority of the businesses of InfraSource during the third quarter of 2003 and ~~decreased expenses at Energy Delivery due to~~ a goodwill impairment charge recorded induring 2003, ~~related to an~~

~~agreement with various Illinois retail market participants and other interested parties,~~ partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen, ~~generating assets placed into service after~~ the ~~first quarter~~consolidation of ~~2003~~Sithe and ~~investments~~increased costs at Boston Generating. Investments made by Exelon in the fourth quarter of 2003 in synthetic fuel-producing ~~facilities.~~facilities increased operating and maintenance expense by $24 million. See further discussion of operating and maintenance expenses by segment below.

Operating Income. The ~~decrease~~change in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was primarily the result of increased depreciation expense due to ~~an increase~~additional plant placed in service after the second quarter of ~~$27 million~~2003 and increased amortization expense due to investments made in ~~depreciation and amortization expense~~the fourth quarter of 2003 in synthetic fuel-producing facilities. Taxes other than income were higher in 2004 as compared to 2003, primarily at Energy Delivery, as a result of a refund of Illinois Electricity Distribution taxes at ComEd and ~~Generation, partially offset by~~the reversal of a ~~$5 million decrease~~use tax accrual resulting from an audit settlement at PECO, both in ~~taxes other than income, primarily at Energy Delivery.~~2003.

Other Income and Deductions. Other income and deductions changed primarily due to ~~an impairment charge~~2004 gains on the sales of ~~$200~~Boston Generating and Exelon Thermal and 2003 investment impairments of $35 million ~~(before income taxes)~~ recorded ~~during the first quarter of 2003 related to Generation’s investment in Sithe.~~by Enterprises. Equity in earnings of unconsolidated affiliates decreased by ~~$42~~$46 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. Interest expense and distributions on preferred securities of subsidiaries collectively ~~decreased $13~~increased $17 million, primarily due to ~~lower outstanding debt and refinancing of existing debt at lower interest rates at Energy Delivery, partially offset by~~ increased interest expense at Generation.

Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 37% for the three months ended ~~March 31,~~June 30, 2003 to ~~28%~~31% for the same period in 2004, primarily due to investments made in synthetic ~~fuel producing~~fuel-producing facilities during the fourth quarter of 2003.

~~Cumulative Effect of Changes in Accounting Principles.~~ Net income for the three months ended March 31, 2004 reflects income of $32 million, net of income taxes, related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, while net income for the three months ended March 31, 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143. See Note 212 of the ~~Condensed~~ Combined Notes to the Consolidated Financial Statements for further ~~information regarding~~discussion of the ~~adoptions of FIN No. 46-R and SFAS No. 143.~~change in the effective income tax rate.


	*Results of Operations by Business Segment*

Exelon evaluates its performance on a business segment basis. The comparisons of operating results and other statistical information for the three months ended ~~March 31,~~June 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.


	~~Income (Loss) Before Cumulative Effect of Change in Accounting Principle by Business Segment~~

Three Months
Ended March 31,
2004 2003 Variance % Change
Energy Delivery $ 312 $ 325 $ (13 ) (4.0 )%
Generation 67 (52 ) 119 n.m.
Enterprises (16 ) (17 ) 1 (5.9 )%
Corporate 11 (7 ) 18 n.m.

Total $ 374 $ 249 $ 125 50.2 %

~~n.m. — not meaningful~~


	Net Income (Loss) by Business Segment



	Three Months												Three Months
	Ended March 31,												Ended June 30,

	2004			2003			Variance			% Change			2004		2003			Variance		% Change

Energy Delivery	$	312		$	330		$	(18	)		(5.5	)%	$	303	$	291		$	12		4.1	%
Generation		99			56			43			76.8	%		178		142			36		25.4%
Enterprises		(16	)		(18	)		2			(11.1	)%		27		(61	)		88		n.m.
Corporate		11			(7	)		18			n.m.			13		—			13		n.m.

Total	$	406		$	361		$	45			12.5	%	$	521	$	372		$	149		40.1	%

n.m. — not meaningful

Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, ~~became part of~~was transferred to Generation. The information for the three months ended ~~March 31,~~June 30, 2003 related to the Enterprises and Generation segments discussed below has not been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy ~~Company reported the following~~Company’s results for the three months ended ~~March 31, 2003:~~June 30, 2003 were as follows:


Total revenues	$	330		$	174
Intersegment revenues		6			2
Income (loss) before income taxes		(16	)
Income taxes (benefit)		(6	)
Income before income taxes					1
Income taxes					1
Net income (loss)		(10	)		—


	*Results of Operations — Energy Delivery*



	Three Months										Three Months
	Ended March 31,										Ended June 30,

	2004		2003		Variance			% Change			2004		2003		Variance			% Change

Operating revenues	$	2,575	$	2,642	$	(67	)		(2.5	)%	$	2,435	$	2,322	$	113			4.9	%
Purchased power and fuel expense		1,179		1,191		(12	)		(1.0	)%		1,059		986		73			7.4	%
Operating and maintenance expense		352		400		(48	)		(12.0	)%		355		342		13			3.8	%
Depreciation and amortization expense		227		214		13			6.1	%		228		213		15			7.0	%
Operating income		680		694		(14	)		(2.0	)%		661		666		(5	)		(0.8	)%
Interest expense		183		196		(13	)		(6.6	)%		172		189		(17	)		(9.0	)%
Income before income taxes and cumulative effect of a change in accounting principle		497		517		(20	)		(3.9	)%
Income before cumulative effect of a change in accounting principle		312		325		(13	)		(4.0	)%
Net income		312		330		(18	)		(5.5	)%		303		291		12			4.1	%

Operating Revenues.The changes in Energy Delivery’s operating revenues for the three months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


	Electric			Gas			Total Variance									Total
										Electric			Gas			Variance

Volume										$	107		$	4		$	111
ComEd’s integration into PJM											43			—			43
Weather											43			(14	)		29
Rate changes and mix											(11	)		13			2
Customer choice	$	(82	)	$	—		$	(82	)		(67	)		—			(67	)
Weather		(30	)		(7	)		(37	)
Volume		52			(7	)		45
Rate changes and mix		(57	)		69			12
Other effects		(6	)		1			(5	)		(11	)		6			(5	)

(Decrease) increase in operating revenues	$	(123	)	$	56		$	(67	)
Increase (decrease) in operating revenues										$	104		$	9		$	113

~~Customer Choice.~~Volume. ~~For~~Both ComEd’s and PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large commercial and industrial customers for ComEd and across all customer classes for PECO.

ComEd’s Integration into PJM. Energy Delivery’s operating revenues and purchased power expense each increased by $43 million in the three months ended ~~March 31,~~June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. The increases relate to the change in control of the transmission assets from ComEd to PJM as a result of which ComEd receives revenues for its proportionate share of the transmission revenues generated by PJM, but also pays PJM for the use of its transmission assets. This is consistent with how PECO accounts for its PJM transmission revenues and ~~2003, 26%~~expenses. For 2004, ComEd’s operating revenues are estimated to increase by approximately $180 million, offset by a corresponding and ~~22%, respectively,~~equal increase in purchased power expense. Starting in 2005, on an annual basis, ComEd’s operating revenues and purchased power expense are estimated to increase between $200 to $250 million. However, there is no expected effect on revenues net of energy delivered to Energy Delivery’s retail customers was provided by alternative electric suppliers or under the ComEd Power Purchase Option (PPO). The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $56 million from customers in Illinois electing to purchase energy from an alternative retail energy supplier (ARES) or ComEd’s PPO and a decrease in revenues of $26 million from customers in Pennsylvania being assigned to or selecting an alternative electric generation supplier.purchased power expense.

Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. Energy Delivery’s electric revenues were positively affected by ~~unfavorable~~favorable weather ~~conditions resulting from milder winter weather~~conditions. Cooling degree-days in the ~~first quarter of 2004.~~ComEd and PECO service territories were 68% and 66% higher, respectively. Heating degree-days in the ComEd and PECO service territories were 5%18% lower and 3%32% lower, ~~respectively,~~respectively.

Energy Delivery’s gas revenues were negatively affected by unfavorable weather conditions.

Rate Changes and Mix. ComEd’s CTC is reset in the second quarter of each year to reflect market price adjustments. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component decreased the collection of CTCs as compared to the

respective prior year period. As a result, ComEd’s CTC revenues decreased $44 million for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under ComEd’s power purchase option (PPO) by $28 million.

~~Energy Delivery’s gas~~Decreased average rates paid by ComEd’s residential customers resulted in a $10 million decrease in revenues. Although residential rates are frozen through 2006, ComEd’s average effective residential rates fluctuate due to the usage patterns of customers.

Electric revenues ~~were also affected by milder winter weather in the first quarter of 2004.~~

~~Volume.~~ ~~ComEd’s electric revenues~~ increased $17 million at PECO as a result of ~~higher delivery volume, exclusive~~$12 million of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large commercial and industrial. PECO’s electric operating revenues increased as a result of a higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased usage per customer across all customer classes.

~~Rate Changes and Mix.~~ Energy Delivery’s electric revenues decreased $42 million at ComEd primarily due to decreased average energy rates under ComEd’s PPO as a result of lower wholesale market prices. Electric revenues decreased $15 million at PECO primarily as a result offavorable rate mix due to changes in monthly usage patterns in all customer classes ~~during~~and $5 million related to a scheduled phase-out of merger-related rate reductions. In connection with the Pennsylvania Public Utility Commission’s (PUC) approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 ~~as compared to 2003.~~and 2005.

Energy Delivery’s gas revenues ~~increased due to~~reflect increases in rates through ~~Pennsylvania Public Utility Commission (PUC)~~PUC approved changes to the purchased gas adjustment clause that became effective ~~March 1, 2003, December~~June 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for the three months ended ~~March 31,~~June 30, 2004 was ~~43%~~30% higher than the rate for the same period in 2003. PECO’s purchased gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. PECO has asked the PUC for a decrease in its rates through the purchased gas adjustment clause effective December 1, 2004 as a result of lower current gas costs. This proposed decrease would have no impact on PECO’s operating income.

Customer Choice. For the three months ended June 30, 2004 and 2003, 29% and 25%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by alternative electric suppliers (AES) or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $51 million from customers in Illinois electing to purchase energy from an AES or under ComEd’s PPO and a decrease in revenues of $16 million from customers in Pennsylvania being assigned to or selecting an AES.

Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for the three months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


							Total									Total
	Electric			Gas			Variance			Electric			Gas			Variance

Volume										$	44		$	3		$	47
ComEd’s integration into PJM											43			—			43
Prices											13			13			26
Weather											16			(10	)		6
Customer choice	$	(78	)	$	—		$	(78	)		(56	)		—			(56	)
Weather		(11	)		(4	)		(15	)
Prices		(13	)		69			56
Volume		29			(7	)		22
Other		2			1			3			(3	)		10			7

(Decrease) increase in purchased power and fuel expense	$	(71	)	$	59		$	(12	)
Increase in purchased power and fuel expense										$	57		$	16		$	73

Volume. ComEd’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather and customer choice, in the number of customers and average usage per customer, primarily residential and large commercial and industrial customers. PECO’s electric purchased power and fuel expense increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to increased customer growth and usage per customer across all customer classes.

ComEd’s Integration into PJM. Energy Delivery’s operating revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.

Prices. Energy Delivery’s electric purchased power increased primarily due to an increase at PECO as a result of higher wholesale market prices associated with certain large commercial and industrial customers whose billing rates are tied to wholesale market prices for energy. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

Weather. Energy Delivery’s purchased power and fuel expense increased due to the effect of favorable weather conditions.

Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an ~~ARES~~AES or ComEd’s PPO and PECO’s residential and small commercial and industrial customers selecting or being assigned to purchase energy from ~~alternative~~an AES.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Higher corporate allocations(a)	$	29
Severance, pension and postretirement benefit costs associated with The Exelon Way		12
Tax consultant fees(b)		5
Employee fringe benefits(c)		(15	)
Contractors		(8	)
Environmental matters		(4	)
Other		(6	)

Increase in operating and maintenance expense	$	13


(a)		Higher corporate allocations primarily result from a higher percentage allocation to Energy Delivery due to the sale of certain Enterprises businesses.

(b)		ComEd recorded a $5 million charge for contingent fees paid to a tax consultant (see Note 15 of the Combined Notes to Consolidated Financial Statements for more information).

(c)		During the second quarter of 2004, ComEd and PECO adopted the provisions of FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2). Employee fringe benefits include a $2 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2. See Note 11 of the Combined Notes to Consolidated Financial Statements for additional information related to employee fringe benefits.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $7 million at PECO and increased depreciation of $5 million due to capital additions across Energy Delivery.

Operating Income. The change in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was the result of increased taxes other than income. This increase was primarily attributable to $12 million related to the reversal of a PECO use tax accrual resulting from an audit settlement in 2003 and a 2003 ComEd refund of $5 million for Illinois Electricity Distribution Taxes.

Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments.


	Energy Delivery Operating Statistics and Revenue Detail

Energy Delivery’s electric sales statistics and revenue detail were as follows:



		Three Months
		Ended June 30,

Retail Deliveries — (in gigawatthours (GWhs))(a)		2004		2003		Variance			% Change

Full service(b)
Residential			8,065		7,437		628			8.4	%
Small commercial & industrial			6,477		6,646		(169	)		(2.5	)%
Large commercial & industrial			5,129		5,378		(249	)		(4.6	)%
Public authorities & electric railroads			1,424		1,555		(131	)		(8.4	)%

	Total full service		21,095		21,016		79			0.4	%

PPO (ComEd only)
Small commercial & industrial			870		869		1			0.1	%
Large commercial & industrial			877		1,318		(441	)		(33.5	)%
Public authorities & electric railroads			577		531		46			8.7	%

			2,324		2,718		(394	)		(14.5	)%

Delivery only(c)
Residential			488		186		302			162.4	%
Small commercial & industrial			2,194		1,580		614			38.9	%
Large commercial & industrial			3,280		2,320		960			41.4	%
Public authorities & electric railroads			406		247		159			64.4	%

			6,368		4,333		2,035			47.0	%

	Total PPO and delivery only		8,692		7,051		1,641			23.3	%

Total retail deliveries			29,787		28,067		1,720			6.1	%


(a)		One GWh is the equivalent of one million kilowatthours (kWh).

(b)		Full service reflects deliveries to customers taking electric generation service under tariffed rates.

(c)		Delivery only service reflects customers receiving electric generation service from an AES.



		Three Months
		Ended June 30,

Electric Revenue		2004		2003		Variance			% Change

Full service(a)
Residential		$	819	$	769	$	50			6.5	%
Small commercial & industrial			593		585		8			1.4	%
Large commercial & industrial			352		351		1			0.3	%
Public authorities & electric railroads			94		102		(8	)		(7.8	)%

	Total full service		1,858		1,807		51			2.8	%

PPO (ComEd only)(b)
Small commercial & industrial			60		59		1			1.7	%
Large commercial & industrial			51		72		(21	)		(29.2	)%
Public authorities & electric railroads			31		28		3			10.7	%

			142		159		(17	)		(10.7	)%

Delivery only(c)
Residential			38		14		24			171.4	%
Small commercial & industrial			58		49		9			18.4	%
Large commercial & industrial			48		48		—			—
Public authorities & electric railroads			9		8		1			12.5	%

			153		119		34			28.6	%

	Total PPO and delivery only		295		278		17			6.1	%

Total electric retail revenues			2,153		2,085		68			3.3	%

	Wholesale and miscellaneous revenue(d)		163		127		36			28.3	%

Total electric revenue		$	2,316	$	2,212	$	104			4.7	%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO’s tariffed rates also include a CTC.

(b)		Revenue from customers choosing ComEd’s PPO includes an energy charge at market rates, transmission and distribution charges and a CTC.

(c)		Delivery only revenue reflects revenue from customers receiving electric generation service from an AES. Revenue from customers choosing an AES includes a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from an AES were included in wholesale and miscellaneous revenue.

(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

Energy Delivery’s gas sales statistics and revenue detail were as follows:



	Three Months
	Ended June 30,

Deliveries to customers (in million cubic feet (mmcf))	2004		2003		Variance			% Change

Retail sales		8,162		9,222		(1,060	)		(11.5	)%
Transportation		6,410		5,779		631			10.9	%

Total		14,572		15,001		(429	)		(2.9	)%



	Three Months
	Ended June 30,

Revenue	2004		2003		Variance		% Change

Retail sales	$	102	$	99	$	3		3.0	%
Transportation		4		4		—		—
Resales and other		13		7		6		85.7	%

Total	$	119	$	110	$	9		8.2	%


	*Results of Operations — Generation*



	Three Months
	Ended June 30,

	2004		2003		Variance			% Change

Operating revenues	$	1,948	$	1,886	$	62			3.3	%
Purchased power and fuel expense		1,025		1,148		(123	)		(10.7	)%
Operating and maintenance expense		623		451		172			38.1	%
Operating income		183		201		(18	)		(9.0	)%
Income before income taxes and minority interest		266		233		33			14.2	%
Net income		178		142		36			25.4	%

Operating Revenues. The changes in Generation’s operating revenues for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Retail gas revenue	$	84
Wholesale and retail electric sales		(39	)
Electric revenue from affiliates		(31	)
Other		48

Increase in operating revenues	$	62

Retail Gas Revenue. Retail gas revenue increased $84 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the three months ended June 30, 2004 compared to the same period in 2003, consisted of the following:


	Variance

Effects of the adoption of EITF 03-11(a)	$	(238	)
Sale of Boston Generating		(43	)
Exelon Energy Company and AmerGen operations		104
Other operations		138

Decrease in wholesale and retail electric sales	$	(39	)


(a)		Does not include $1 million of EITF 03-11 adjustments related to fuel sales that are included in other revenues.

The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. See Note 2 of the Combined Notes to Consolidated Financial Statements for further discussion of EITF 03-11. The sale of Boston Generating in May 2004 resulted in less revenues from this entity compared to the same period in the prior year. The acquisition of Exelon Energy and AmerGen resulted in increased wholesale and retail electric sales of approximately $104 million compared to the same period in the prior year.

The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, and in the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.

Electric Revenue from Affiliates. Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004 as a result of which sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the three months ended June 30, 2003 was $44 million.

The decrease in revenue from sales to affiliates was partially offset by $15 million in higher sales to Energy Delivery. The higher sales to Energy Delivery were primarily due to overall increased usage per customer and favorable weather conditions.

Other. Certain other revenues increased for the three months ended June 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s operations beginning April 1, 2004.

Purchased Power and Fuel Expense. The changes in Generation’s purchased power and fuel expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Effects of the adoption of EITF 03-11	$	(239	)
Boston Generating		(33	)
Midwest Generation		(25	)
AmerGen and Exelon Energy Company		(11	)
Volume		92
Sithe Energies, Inc.		62
Price		49
Mark-to-market adjustments on hedging activity		11
Other		(29	)

Decrease in purchased power and fuel expense	$	(123	)

Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $238 million and fuel expense of $1 million.

Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding Boston Generating.

Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation.

Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $86 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results.

Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).

Sithe Energies, Inc. Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of Sithe.

Price. The increase reflects higher market energy prices due to increased natural gas, oil and coal prices.

Hedging Activity. Mark-to-market gains on hedging activities were $21 million for the three months ended June 30, 2004 compared to gains of $32 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating accounted for a gain of $6 million and hedging activities relating to other Generation operations in 2004 accounted for a gain of $15 million.

Other. Other decreases in purchased power and fuel expense were primarily due to $21 million of lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM during the second quarter of 2004 and $10 million of nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

AmerGen and Exelon Energy Company	$	87
Sithe Energies, Inc.		22
Decommissioning accretion costs(a)		18
Boston Generating		13
Pension, payroll and benefit costs, primarily associated with The Exelon Way		(14	)
Other		46

Increase in operating and maintenance expense	$	172


(a)		Includes $10 million due to AmerGen asset retirement obligation accretion.

The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen, Exelon Energy Company and Sithe in Generation’s consolidated financial results for 2004. The increase in operating and maintenance expenses attributable to Boston Generating was due to the Mystic 8 and 9 and Fore River facilities commencing commercial operation at the end of the second quarter of 2003 and in the third quarter of 2003, respectively, which more than offset the reduction in operating and maintenance expenses resulting

from their sale in May 2004. Decommissioning accretion costs increased primarily due to the inclusion of AmerGen for the three months ended June 30, 2004 as compared to the same period in the prior year. The reduction in payroll-related costs associated with the implementation of the programs associated with The Exelon Way partially offset the other increases to operating and maintenance expense.

Depreciation and Amortization. The increase in depreciation and amortization expense for the three months ended June 30, 2004 as compared to the same period in 2003 includes the impact of capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities as the assets were classified as held for sale during the period.

Effective Income Tax Rate. The effective income tax rate was 38% for the three months ended June 30, 2004 compared to 39% for the same period in 2003. This decrease is primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe which resulted in a pre-tax loss. This impairment charge was taxed at a rate different than the overall generation effective income tax rate. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.


	Generation Operating Statistics

Generation’s sales and the supply of these sales, excluding the trading portfolio, were as follows:



	Three Months
	Ended June 30,

Revenue	2004			2003			Variance			% Change

Sales to affiliates(a)	$	846		$	877		$	(31	)		(3.5	)%
Wholesale and retail electric sales(b)		858			897			(39	)		(4.3	)%

Total energy sales revenue		1,704			1,774			(70	)		(3.9	)%

Retail gas sales		84			—			84			n.m.
Trading portfolio		(2	)		(1	)		(1	)		100.0	%
Other revenue(c)		162			113			49			43.4	%

Total revenue	$	1,948		$	1,886		$	62			3.3	%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

(c)		Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

n.m. — not meaningful



	Three Months
	Ended June 30,

Sales (in GWhs)	2004(c)		2003		Variance			% Change

Sales to affiliates(a)		26,133		26,869		(736	)		(2.7	)%
Wholesale and retail electric sales(b)		24,976		27,449		(2,473	)		(9.0	)%

Total sales		51,109		54,318		(3,209	)		(5.9	)%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

(c)		Sales in 2004 do not include 6,185 GWhs, which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11.



	Three Months
	Ended June 30,

Supply Source (in GWhs)	2004		2003		Variance			% Change

Nuclear generation(a)		34,254		29,619		4,635			15.6	%
Purchases — non-trading portfolio(b)		11,904		19,344		(7,440	)		(38.5	)%
Fossil and hydroelectric generation		4,951		5,355		(404	)		(7.5	)%

Total supply		51,109		54,318		(3,209	)		(5.9	)%


(a)		Excludes AmerGen in 2003. AmerGen generated 5,122 GWhs during the three months ended June 30, 2004.

(b)		Sales in 2004 do not include 6,185 GWhs that were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 3,731 GWhs in 2003.

Trading volumes of 5,324 GWhs and 7,919 GWhs for the three months ended June 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

Generation’s supply mix changed primarily as a result of the sale of Boston Generating in May 2004.

Generation’s average margin and other operating data for the three months ended June 30, 2004 and 2003 were as follows:



		Three Months
		Ended June 30,

($/MWh)		2004		2003		% Change

Average revenue
	Electric sales to affiliates(a)	$	32.37	$	32.64		(0.8	)%
	Market and retail electric sales(b)		34.35		32.68		5.1	%
	Total — excluding the trading portfolio		33.34		32.66		2.1	%
Average supply cost(c) — excluding the trading portfolio		$	20.06	$	21.13		(5.1	)%
Average margin — excluding the trading portfolio		$	13.28	$	11.53		15.2	%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

(c)		Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003.

Generation’s average margin, excluding the trading portfolio, increased primarily due to decreased average supply cost as a result of forward hedging of fuel at lower costs during the three months ended June 30, 2004 as compared to the same period in the prior year. Also, Generation experienced a decrease in purchased power due to reducing the capacity purchased from Midwest Generation and the affect of acquiring the remaining 50% of AmerGen in 2003. The increase in nuclear generation during the quarter, which is

generally less expensive than purchased power, along with the effect of the adoption of EITF 03-11, also contributed to the increase in average margin.



	Three Months
	Ended June 30,

	2004			2003

Nuclear fleet capacity factor(a)		96.1	%		94.0	%
Nuclear fleet production cost per MWh(a)	$	10.88		$	12.08
Average purchased power cost for wholesale operations per MWh(b)	$	47.13		$	41.36


(a)		Includes AmerGen and excludes Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G).

(b)		Includes PPAs with AmerGen in 2003.

Higher nuclear capacity factors and lower nuclear production costs were primarily due to nine fewer planned refueling outage days, resulting in a $14 million decrease in planned outage costs for the three months ended June 30, 2004 as compared to the same period in 2003. There was one planned refueling outage that began in late March 2004 and was completed during the three months ended June 30, 2004, while there was one refueling outage that began and was completed during the three months ended June 30, 2003. The three months ended June 30, 2004 included seven unplanned outages compared to nine unplanned outages during the same period in 2003.

In the three months ended June 30, 2004 as compared to the three months ended June 30, 2003, the Quad Cities units operated at pre-Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.


	*Results of Operations — Enterprises*



	Three Months
	Ended June 30,

	2004			2003			Variance			% Change

Operating revenues	$	43		$	443		$	(400	)		(90.3	)%
Purchased power and fuel expense		—			166			(166	)		(100.0	)%
Operating and maintenance expense		65			322			(257	)		(79.8	)%
Depreciation and amortization expense		—			10			(10	)		(100.0	)%
Operating income (loss)		(23	)		(57	)		34			(59.6	)%
Other income and deductions		74			(38	)		112			n.m.
Loss before income taxes		51			(95	)		146			n.m.
Net income (loss)		27			(61	)		88			n.m.

Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. Enterprises’ results for the three months ended June 30, 2004 compared to the three months ended June 30, 2003 were significantly affected by the following transactions:

InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource.

Exelon Energy Company. Effective January 1, 2004, the operations and assets of Enterprises’ competitive retail sales business, Exelon Energy Company, were transferred to Generation. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of this transfer.

Exelon Services, Inc. During the three months ended June 30, 2004, Enterprises disposed of certain businesses of Services, including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale recorded during the three months ended June 30, 2004 related to the disposition of these Services businesses were $16 million and $12 million,

respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of June 30, 2004, Services had assets and liabilities of $58 million and $90 million, respectively, which primarily represented the corporate operations and the remaining businesses of the Mechanical and Integrated Technology Group.

In addition, during the three months ended June 30, 2004, Enterprises disposed of the following business and investment. These dispositions and the transactions described above will affect Enterprises future results of operations.

Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Exelon Thermal for proceeds of $134 million, subject to working capital adjustments. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, which resulted in prepayment penalties of $9 million, which were recorded as interest expense. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income.

PECO Telcove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003.

Operating Revenues. The changes in Enterprises’ operating revenues for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Transfer of Exelon Energy Company to Generation	$	(174	)
Sale of InfraSource businesses		(145	)
Services(a)		(61	)
F&M Holdings, LLC(b)		(28	)
Other		8

Decrease in operating revenues	$	(400	)


(a)		Primarily due to the sale of certain businesses.

(b)		For the remaining businesses of F & M Holdings, LLC, operating revenues decreased as a result of the sale of certain businesses and the reduction of new business as a result of wind-down efforts.

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004.

Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Sale of InfraSource businesses	$	(135	)
Services(a)		(52	)
Goodwill impairment charge(b)		(47	)
F & M Holdings, LLC(c)		(22	)
Other		(1	)

Decrease in operating and maintenance expense	$	(257	)


(a)		Primarily due to the sale of certain businesses.

(b)		Enterprises recorded a goodwill impairment charge of $47 million during the second quarter of 2003 related to the goodwill recorded within the InfraSource reporting unit.


(c)		For the remaining businesses of F & M Holdings, LLC, operating and maintenance expense decreased $29 million as a result of wind-down efforts for these businesses. These decreases were partially offset by increased expense of $7 million due to margin deterioration on various construction projects.

Depreciation and Amortization. Depreciation and amortization expense decreased primarily as a result of the sale of the majority of the InfraSource businesses in the third quarter of 2003 and property, plant and equipment classified as held for sale.

Other Income and Deductions. The increase in other income and deductions was primarily due to 2004 gains on the sales of Exelon Thermal, the Services businesses and Enterprises’ investment in PECO Telcove of an aggregate of $66 million (before income taxes and debt prepayment penalties) and income of $18 million recorded during the second quarter of 2004 related to the collection of a note receivable prior to its maturity. Other income and deductions in 2003 included impairment charges of energy-related and communications investments of $35 million.

Effective Income Tax Rate. The effective income tax rate was 47% for the three months ended June 30, 2004 compared to 36% for the same period in 2003. The increase in the effective tax rate was primarily attributable to state tax impact on the Thermal divestiture and tax adjustments resulting from various income tax related items.


	*Results of Operations — Exelon Corporation*


	Six Months Ended June 30, 2004 Compared To Six Months Ended June 30, 2003


	2004			2003			Variance			% Change

Operating revenues	$	7,272		$	7,795		$	(523	)		(6.7	)%
Purchased power and fuel expense		2,608			3,119			(511	)		(16.4	)%
Operating and maintenance expense		2,165			2,212			(47	)		(2.1	)%
Operating income		1,505			1,557			(52	)		(3.3	)%
Other income and deductions		(239	)		(563	)		324			(57.5	)%
Income before income taxes, minority interest and cumulative effect of changes in accounting principles		1,266			994			272			27.4	%
Income before cumulative effect of changes in accounting principles		901			621			280			45.1	%
Cumulative effect of changes in accounting principles		32			112			(80	)		(71.4	)%
Net income		933			733			200			27.3	%
Diluted earnings per share		1.40			1.12			0.28			25.0	%

Operating Revenues. Operating revenues decreased for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to decreased revenues at Enterprises due to the sale of the majority of the businesses of InfraSource during the third quarter of 2003 and Generation’s adoption of EITF 03-11 in the first quarter of 2004 which changed the presentation of certain power transactions and decreased operating revenues by $452 million. The adoption of EITF 03-11 had no impact on net income. See further discussion of operating revenues by segment below.

Purchased Power and Fuel Expense.Purchased power and fuel expense decreased during the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to Generation’s adoption of EITF 03-11 during 2004 which resulted in a decrease in purchased power expense and fuel expense of $452 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense, and the consolidation of Sithe. Purchased power represented 23% of Generation’s total supply for the six months ended June 30, 2004 compared to 36% for the same period in 2003. See further discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense. Operating and maintenance expense decreased slightly for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to decreased expenses at Enterprises due to the sale of the majority of the businesses of InfraSource during the third quarter of 2003 and decreased expenses at Energy Delivery due to a charge recorded in 2003 related to an agreement with various Illinois retail market participants and other interested parties, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen and generating assets placed in service after the first quarter of 2003. Operating and maintenance expense increased $48 million due to investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. See further discussion of operating and maintenance expenses by segment below.

Operating Income. The slight decrease in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was primarily due to an increase of $67 million in depreciation expense and increased taxes other than income at Energy Delivery. The increase in depreciation and amortization expense was primarily related to assets placed in service after the second quarter of 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities.

Other Income and Deductions. Other income and deductions changed primarily due to an impairment charge of $200 million (before income taxes) recorded during the first quarter of 2003 related to Generation’s investment in Sithe, an $85 million gain (before income taxes) on the sale of Boston Generating and a $36 million gain on the sale of Exelon Thermal (before income taxes and net of debt prepayment penalties). Equity in earnings of unconsolidated affiliates decreased by $88 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. Interest expense and distributions on preferred securities of subsidiaries collectively increased $6 million, primarily due to increased interest expense at Generation, partially offset by lower outstanding debt and refinancings at lower rates at Energy Delivery.

Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 37% for the six months ended June 30, 2003 to 30% for the same period in 2004, primarily due to investments made in synthetic fuel-producing facilities during the fourth quarter of 2003. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Cumulative Effect of Changes in Accounting Principles. Net income for the six months ended June 30, 2004 reflects income of $32 million, net of income taxes, related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, while net income for the six months ended June 30, 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN No. 46-R and SFAS No. 143.


	*Results of Operations by Business Segment*

The comparisons of operating results and other statistical information for the six months ended June 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.


	Income (Loss) Before Cumulative Effect of Change in Accounting Principle by Business Segment



	Six Months
	Ended June 30,

	2004		2003			Variance		% Change

Energy Delivery	$	619	$	616		$	3		0.5	%
Generation		248		89			159		178.7	%
Enterprises		11		(78	)		89		n.m.
Corporate		23		(6	)		29		n.m.

Total	$	901	$	621		$	280		45.1	%

n.m. — not meaningful


	Net Income (Loss) by Business Segment



	Six Months
	Ended June 30,

	2004		2003			Variance			% Change

Energy Delivery	$	619	$	621		$	(2	)		(0.3	)%
Generation		280		197			83			42.1	%
Enterprises		11		(79	)		90			n.m.
Corporate		23		(6	)		29			n.m.

Total	$	933	$	733		$	200			27.3	%

n.m. — not meaningful

Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. The information for the six months ended June 30, 2003 related to the Enterprises and Generation segments discussed below has not been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy Company’s results for the six months ended June 30, 2003 were as follows:


Total revenues	$	504
Intersegment revenues		9
Loss before income taxes		(16	)
Income tax benefit		(6	)
Net loss		(10	)


	*Results of Operations — Energy Delivery*



	Six Months
	Ended June 30,

	2004		2003		Variance			% Change

Operating revenues	$	5,010	$	4,964	$	46			0.9	%
Purchased power and fuel expense		2,239		2,175		64			2.9	%
Operating and maintenance expense		704		744		(40	)		(5.4	)%
Depreciation and amortization expense		455		427		28			6.6	%
Operating income		1,343		1,360		(17	)		(1.3	)%
Interest expense		355		383		(28	)		(7.3	)%
Income before income taxes and cumulative effect of a change in accounting principle		986		998		(12	)		(1.2	)%
Income before cumulative effect of a change in accounting principle		619		616		3			0.5	%
Net income		619		621		(2	)		(0.3	)%

Operating Revenues.The changes in Energy Delivery’s operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


							Total
	Electric			Gas			Variance

Volume	$	158		$	(4	)	$	154
ComEd’s integration in PJM		43			—			43
Rate changes and mix		(68	)		82			14
Customer choice		(149	)		—			(149	)
Weather		13			(19	)		(6	)
Other effects		(16	)		6			(10	)

(Decrease) increase in operating revenues	$	(19	)	$	65		$	46

Volume. Both ComEd’s and PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large commercial and industrial customers for ComEd and across all customer classes for PECO.

ComEd’s Integration into PJM. Energy Delivery’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.

Rate Changes and Mix. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component decreased the collection of CTCs as compared to the respective prior year period. As a result, ComEd’s CTC revenues decreased by $120 million for the six months ended June 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under ComEd’s PPO by $47 million.

Customer Choice. For the six months ended June 30, 2004 and 2003, 28% and 24%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by an AES or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $107 million from customers in Illinois electing to purchase energy from an AES or ComEd’s PPO and a decrease in revenues of $42 million from customers in Pennsylvania being assigned to or selecting an AES.

For the six months ended June 30, 2004 and June 30, 2003, ComEd collected approximately $87 million and $207 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy

prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, and increases in ComEd’s open access transmission tariff rates (OATT) effective May 1, 2004, ComEd anticipates that this revenue source will decline to approximately $180 million for 2004 and range from $100 million to $180 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.

Electric revenues increased $2 million at PECO as a result of $9 million related to a scheduled phase-out of merger-related rate reductions, largely offset by a $7 million decrease reflecting a change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 as compared to 2003. In connection with the PUC’s approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005

Energy Delivery’s gas revenues increased due to increases in rates through PUC approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for the six months ended June 30, 2004 was 39% higher than the rate for the same period in 2003.

Weather. Energy Delivery’s ~~purchased power~~electric revenues were affected by favorable weather conditions. Cooling degree-days in the ComEd and ~~fuel expense decreased due~~PECO service territories were 68% higher and 66% higher, respectively, for the six months ended June 30, 2004 as compared to the ~~effect of milder winter weather~~same period in 2003. Heating degree-days were 8% lower in both the ComEd and PECO service territories for the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003.

Energy Delivery’s gas revenues were affected by unfavorable weather conditions.

Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Electric			Gas			Total Variance

Prices	$	—		$	82		$	82
Volume		81			(4	)		77
ComEd’s integration into PJM		43			—			43
Customer choice		(134	)		—			(134	)
Weather		5			(16	)		(11	)
Other		(6	)		13			7

(Decrease) increase in purchased power and fuel expense	$	(11	)	$	75		$	64

Prices. Energy Delivery’s purchased power ~~decreased for electric due to a decrease in the mix of on-peak/off-peak cost of electricity at ComEd.~~expense remained constant. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

Volume. ComEd’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather and customer choice, in the number of customers and average usage per customer, primarily residential and large commercial and industrial customers at ComEd. PECO’s electric purchased power and fuel expense increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased customer growth and usage per customer across all customer classes.

ComEd’s PPO and PECO’s residential and small commercial and industrial customers selecting or being assigned to purchase energy from an AES.

Weather. Energy Delivery’s purchased power and fuel expense were affected by unfavorable weather conditions.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance			Variance

Charge recorded at ComEd in 2003(a)	$	(41	)	$	(41	)
Decreased payroll expense due to fewer employees(b)		(31	)		(21	)
Allowance for uncollectible accounts expense(d)		(10	)
Higher corporate allocations(b,c)		28
Employee fringe benefits		8
Contractors					(9	)
Allowance for uncollectible accounts expense					(6	)
Environmental charges					(5	)
Employee fringe benefits(b, d)					(3	)
Higher corporate allocations(c)					42
Severance, pension and postretirement benefit costs associated with The Exelon Way		5			19
Tax Consultant fees(e)					5
Other		(7	)		(21	)

Decrease in operating and maintenance expense	$	(48	)	$	(40	)


(a)		In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties.

(b)		Energy Delivery has fewer employees as a result of The Exelon Way ~~terminations and restructuring initiatives.~~terminations.

(c)		Higher corporate allocations primarily result from ~~payroll expenses and employee fringe benefits. To provide greater efficiencies, certain employees that provide services~~a higher percentage allocation to ~~ComEd and PECO were transferred to BSC, resulting in lower payroll expense at~~ Energy Delivery ~~but higher corporate allocations.~~due to the sale of certain Enterprises businesses.

(d)	In	During the second quarter of 2004, ~~PECO’s uncollectible accounts expense decreased by $8~~ComEd and PECO adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $5 million asreduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.

(e)		ComEd recorded a ~~result of increased collection efforts and customer deposits.~~$5 million charge for contingent fees paid to a tax consultant (see Note 15 to the Combined Notes to Consolidated Financial Statements for more information).

Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $7$14 million at PECO and increased depreciation of $5$10 million due to capital additions across Energy Delivery.

Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments and ~~refinancing existing debt~~refinancings at lower rates.


	*Energy Delivery Operating Statistics and Revenue Detail*

Energy Delivery’s electric sales statistics and revenue detail were as follows:



		Three Months											Six Months
		Ended March 31,											Ended June 30,

Retail Deliveries — (in gigawatthours (GWhs))(a)		2004		2003		Variance			% Change
Retail Deliveries — (in GWhs)												Retail Deliveries — (in GWhs)	2004		2003		Variance			% Change

Full service~~(b)~~(a)	Full service~~(b)~~(a)											Full service~~(b)~~(a)
Residential	Residential		9,757		10,001		(244	)		(2.4	)%	Residential		17,821		17,438		383			2.2	%
Small commercial & industrial	Small commercial & industrial		6,817		7,407		(590	)		(8.0	)%	Small commercial & industrial		13,294		14,053		(759	)		(5.4	)%
Large commercial & industrial	Large commercial & industrial		4,962		4,966		(4	)		(0.1	)%	Large commercial & industrial		10,091		10,344		(253	)		(2.4	)%
Public authorities & electric railroads	Public authorities & electric railroads		1,469		1,669		(200	)		(12.0	)%	Public authorities & electric railroads		2,893		3,224		(331	)		(10.3	)%

	Total full service		23,005		24,043		(1,038	)		(4.3	)%	Total full service		44,099		45,059		(960	)		(2.1	)%

PPO (ComEd only)	PPO (ComEd only)											PPO (ComEd only)
Small commercial & industrial	Small commercial & industrial		731		793		(62	)		(7.8	)%	Small commercial & industrial		1,600		1,662		(62	)		(3.7	)%
Large commercial & industrial	Large commercial & industrial		747		1,433		(686	)		(47.9	)%	Large commercial & industrial		1,624		2,750		(1,126	)		(40.9	)%
Public authorities & electric railroads	Public authorities & electric railroads		434		537		(103	)		(19.2	)%	Public authorities & electric railroads		1,012		1,069		(57	)		(5.3	)%

			1,912		2,763		(851	)		(30.8	)%			4,236		5,481		(1,245	)		(22.7	)%

Delivery only~~(c)~~(b)	Delivery only~~(c)~~(b)											Delivery only~~(c)~~(b)
Residential	Residential		582		264		318			120.5	%	Residential		1,070		450		620			137.8	%
Small commercial & industrial	Small commercial & industrial		2,196		1,550		646			41.7	%	Small commercial & industrial		4,389		3,131		1,258			40.2	%
Large commercial & industrial	Large commercial & industrial		3,090		2,042		1,048			51.3	%	Large commercial & industrial		6,371		4,362		2,009			46.1	%
Public authorities & electric railroads	Public authorities & electric railroads		488		282		206			73.0	%	Public authorities & electric railroads		894		529		365			69.0	%

			6,356		4,138		2,218			53.6	%			12,724		8,472		4,252			50.2	%
	Total PPO and delivery only		8,268		6,901		1,367			19.8	%
												Total PPO and delivery only		16,960		13,953		3,007			21.6	%

Total retail deliveries	Total retail deliveries		31,273		30,944		329			1.1	%	Total retail deliveries		61,059		59,012		2,047			3.5	%


(a)	~~One GWh is the equivalent of one million kilowatthours (kWh).~~

~~(b)~~	Full service reflects deliveries to customers taking electric generation service under tariffed rates.

~~(c)~~ (b)		Delivery only service reflects customers receiving electric generation service from an ~~alternative energy supplier.~~AES.

6594



		Three Months											Six Months Ended
		Ended March 31,											June 30,

Electric Revenue	Electric Revenue	2004		2003		Variance			% Change			Electric Revenue	2004		2003		Variance			% Change

Full service(a)	Full service(a)											Full service(a)
Residential	Residential	$	874	$	905	$	(31	)		(3.4	)%	Residential	$	1,691	$	1,673	$	18			1.1	%
Small commercial & industrial	Small commercial & industrial		549		591		(42	)		(7.1	)%	Small commercial & industrial		1,143		1,177		(34	)		(2.9	)%
Large commercial & industrial	Large commercial & industrial		330		340		(10	)		(2.9	)%	Large commercial & industrial		682		692		(10	)		(1.4	)%
Public authorities & electric railroads	Public authorities & electric railroads		93		106		(13	)		(12.3	)%	Public authorities & electric railroads		188		207		(19	)		(9.2	)%

	Total full service		1,846		1,942		(96	)		(4.9	)%	Total full service		3,704		3,749		(45	)		(1.2	)%

PPO (ComEd only)(b)	PPO (ComEd only)(b)											PPO (ComEd only)(b)
Small commercial & industrial	Small commercial & industrial		48		50		(2	)		(4.0	)%	Small commercial & industrial		108		109		(1	)		(0.9	)%
Large commercial & industrial	Large commercial & industrial		42		72		(30	)		(41.7	)%	Large commercial & industrial		92		144		(52	)		(36.1	)%
Public authorities & electric railroads	Public authorities & electric railroads		22		27		(5	)		(18.5	)%	Public authorities & electric railroads		53		55		(2	)		(3.6	)%

			112		149		(37	)		(24.8	)%			253		308		(55	)		(17.9	)%

Delivery only(c)	Delivery only(c)											Delivery only(c)
Residential	Residential		42		17		25			147.1	%	Residential		80		31		49			158.1	%
Small commercial & industrial	Small commercial & industrial		53		51		2			3.9	%	Small commercial & industrial		110		99		11			11.1	%
Large commercial & industrial	Large commercial & industrial		44		54		(10	)		(18.5	)%	Large commercial & industrial		93		103		(10	)		(9.7	)%
Public authorities & electric railroads	Public authorities & electric railroads		8		9		(1	)		(11.1	)%	Public authorities & electric railroads		18		17		1			5.9	%

			147		131		16			12.2	%			301		250		51			20.4	%

	Total PPO and delivery only		259		280		(21	)		(7.5	)%	Total PPO and delivery only		554		558		(4	)		(0.7	)%

Total electric retail revenues	Total electric retail revenues		2,105		2,222		(117	)		(5.3	)%	Total electric retail revenues		4,258		4,307		(49	)		(1.1	)%
												Wholesale and miscellaneous revenue(d)		288		258		30			11.6	%
	Wholesale and miscellaneous revenue(d)		126		132		(6	)		(4.5	)%

Total electric revenue	Total electric revenue	$	2,231	$	2,354	$	(123	)		(5.2	)%	Total electric revenue	$	4,546	$	4,565	$	(19	)		(0.4	)%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO’s tariffed rates also include a ~~competitive transition charge.~~CTC.

(b)		Revenue from customers choosing ComEd’s PPO includes onan energy charge at market rates, transmission and distribution charges and a CTC.

(c)		Delivery only ~~revenue~~ reflects revenue from customers receiving electric generation service from an ~~alternative energy supplier.~~AES. Revenue from customers choosing an ~~alternative energy supplier~~AES includes a distribution charge and a CTC. ~~Transmission~~Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from ~~alternative energy suppliers are~~an AES were included in wholesale and miscellaneous revenue.

(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

Energy Delivery’s gas sales statistics and revenue detail were as follows:



	Three Months										Six Months
	Ended March 31,										Ended June 30,

Deliveries to customers (in million cubic feet (mmcf))	2004		2003		Variance			% Change
Deliveries to customers (in mmcf)											2004		2003		Variance			% Change

Retail sales		29,803		31,460		(1,657	)		(5.3	)%		37,965		40,685		(2,720	)		(6.7	)%
Transportation		7,132		8,166		(1,034	)		(12.7	)%		13,542		13,942		(400	)		(2.9	)%

Total		36,935		39,626		(2,691	)		(6.8	)%		51,507		54,627		(3,120	)		(5.7	)%

6695



	Three Months
	Ended									Six Months
	March 31,									Ended June 30,

Revenue	2004		2003		Variance		% Change			2004		2003		Variance		% Change

Retail sales	$	328	$	273	$	55		20.1	%	$	431	$	372	$	59		15.9	%
Transportation		5		5		—		—			9		9		—		—
Resales and other		11		10		1		10.0	%		24		18		6		33.3	%

Total	$	344	$	288	$	56		19.4	%	$	464	$	399	$	65		16.3	%


	*Results of Operations — Generation*



	Three Months											Six Months
	Ended March 31,											Ended June 30,

	2004		2003			Variance			% Change			2004		2003		Variance			% Change

Operating revenues	$	1,953	$	1,879		$	74			3.9	%	$	3,900	$	3,765	$	135			3.6	%
Purchased power and fuel expense		1,105		1,205			(100	)		(8.3	)%		2,129		2,348		(219	)		(9.3	)%
Operating and maintenance expense		652		487			165			33.9	%		1,273		943		330			35.0	%
Operating income		94		94			—			—			279		295		(16	)		(5.4	)%
Income (loss) before income taxes and cumulative effect of changes in accounting principles		113		(73	)		186			n.m.
Income (loss) before cumulative effect of changes in accounting principles		67		(52	)		119			n.m.
Income before income taxes, minority interest and cumulative effect of changes in accounting principles													383		162		221			136.4	%
Income before cumulative effect of changes in accounting principles													248		89		159			178.7	%
Cumulative effect of changes in accounting principles		32		108			(76	)		(70.4	)%		32		108		(76	)		(70.4	)%
Net income		99		56			43			76.8	%		280		197		83			42.1	%

~~n.m. — not meaningful~~

Operating Revenues. The changes in Generation’s operating revenues for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance			Variance

Retail gas revenue	$	176		$	260
Energy Delivery and Exelon Energy Company		(111	)
Market and retail electric sales		40
Electric sales to affiliates					(136	)
Wholesale and retail electric sales					(12	)
Other		(31	)		23

Increase in operating revenues	$	74		$	135

Retail Gas Revenue. Retail gas revenue increased ~~$176 million~~ as a result of the transfer of Exelon Energy Company ~~retail operations, which were not included in Generation’s financial results in 2003.~~to Generation as of January 1, 2004.

~~Energy Delivery and Exelon Energy Company.~~Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily ~~due~~as a result of the transfer of Exelon Energy Company’s assets and operations to ~~$55~~Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the six months ended June 30, 2003 was $108 million.

The decrease in revenue from affiliates included $40 million in lower ~~volume~~sales to Energy Delivery. The lower sales to Energy Delivery were primarily due to ~~Energy Delivery’s~~ customers purchasing energy from alternative electric suppliers ~~or ComEd’s PPO~~ and unfavorable weather conditions in the ComEd and PECO service ~~territories. Price increases in~~territories compared to the ~~PECO region partially offset by minimal price decreases in the ComEd region resulted in an overall $5 million increase in affiliate revenue due to price fluctuations.~~prior year.

As a result of Exelon Energy Company’s assets and operations being transferred to Generation effective January 1, 2004, sales to Exelon Energy Company are no longer reported as affiliate revenue. Revenue from sales to Exelon Energy Company for the three months ended March 31, 2003 was $64 million.

6796

~~Market~~Wholesale and Retail Electric Sales. The changes in Generation’s ~~market~~wholesale and retail electric sales for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003, consisted of the following:


	Variance			Variance

Effects of EITF 03-11 adoption	$	(206	)
Effects of the adoption of EITF 03-11(a)				$	(444	)
Boston Generating		117			74
Exelon Energy Company and AmerGen operations		78			182
Other operations		51			176

Increase in market and retail electric sales	$	40
Decrease in wholesale and retail electric sales				$	(12	)


(a)		Does not include $8 million of EITF 03-11 adjustments related to fuel sales that are included in other revenues.

The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004.

Other. ~~Revenues decreased~~Certain other revenues increased for the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003, primarily due to ~~a $10 million decrease in fuel sales which is due primarily to gas sales in 2003 to Exelon Energy Company which is consolidated in 2004, as well as decreased coal sales year over year due to~~ the ~~unwinding~~consolidation of ~~coal contracts, and the effects~~Sithe’s results of adopting EITF 03-11, which calls for fuel expense to offset revenue derived from certain fossil fuel transactions. See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for additional information regarding EITF 03-11. As a result, revenues and fuel expense were lowered by $7 million, of which $5 million was related to Boston Generating operations.operations beginning April 1, 2004.

Purchased Power and Fuel Expense. The changes in Generation’s purchased power and fuel expense for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance			Variance

Effects of the adoption of EITF 03-11				$	(452	)
Midwest Generation					(48	)
Price					(47	)
Volume	$	(176	)		129
Price		(96	)
AmerGen and Exelon Energy Company		112			101
Midwest Generation		(23	)
Sithe Energies, Inc.					62
Boston Generating		108			75
Mark-to-market adjustments on hedging activity		8			19
Other		(33	)		(58	)

Decrease in purchased power and fuel expense	$	(100	)	$	(219	)

~~Volume.~~Effects of the Adoption of EITF 03-11. The ~~decrease reflects the effects~~adoption of ~~adopting~~ EITF 03-11 ~~resulting~~resulted in a decrease ~~of $200 million. The decrease was partially offset by a $21 million increase~~ in purchased power ~~volume and a $3 million increase due to increased generation.~~

~~Prices.~~ ~~The decrease reflects lower market prices~~expense of ~~$48 million and lower average fossil fuel costs used for non-Boston Generating operations of $48 million during the three months ended March 31, 2004 as compared to the same period in 2003.~~

~~AmerGen and Exelon Energy Company.~~ As result of Generation’s acquisition of the remaining 50% interest in AmerGen and the transfer of Exelon Energy Company to Generation effective January 1, 2004, purchased power decreased $62 million$444 and fuel expense ~~increased $174~~of $8 million. ~~Generation recorded no related party purchased power for the quarter ended March 31, 2004. During the quarter ended March 31, 2003, Generation recorded $68 million for purchased power from AmerGen.~~

Price. The decrease primarily reflects lower average fossil fuel costs of $47 million during the six months ended June 30, 2004 as compared to the same period in 2003.

Volume. Generation experienced increased purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).

AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $160 million. In prior periods,

Generation reported energy purchased from AmerGen as purchased power expense. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $261 million as fuel purchases made by Exelon Energy Company were not previously included in Generation’s results.

Boston Generating. ~~The~~ The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May of 2004. The Mystic 8 and 9 generating facilities began commercial operations ~~during~~at the end of the second quarter of 2003, and the Fore River generating facilities began commercial operations during the third quarter of 2003. ~~As a result, purchased power and fuel expense increased $121 million. The increase was offset by a decrease~~

Sithe Energies, Inc. Under the provisions of ~~$13 million related~~FIN No. 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to ~~the effects~~Consolidated Financial Statements for further discussion of ~~adopting EITF 03-11.~~Sithe.

Hedging Activity. Mark-to-market losses on hedging activities were ~~$39~~$18 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~losses~~gains of ~~$31~~$1 million for the same period ofin 2003. Hedging activities in 2004 ~~relating~~related to ~~non-Boston~~Boston Generating operations accounted for a ~~loss~~gain of ~~$37~~$4 million and ~~Boston Generating~~hedging activities for other Generation operations in 2004 accounted for a loss of $2$22 million.

Other. Other decreases in purchased power and fuel were primarily due to ~~$21~~$46 million in lower transmission expense resulting from reduced inter-region transmission ~~and~~as a $4result of ComEd’s integration into PJM in the second quarter of 2004, offset by $16 million ~~decrease~~of nuclear fuel amortization recorded in ~~intercompany purchased power expense.~~2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.


	Variance			Variance

AmerGen and Exelon Energy Company(a)	$	110		$	197
Refueling outage costs~~(b)~~		36			38
Boston Generating		20			33
Decommissioning accretion costs~~(c)~~(b)		7			25
Co-owned facilities		5
Sithe Energies, Inc.					22
Pension, payroll and benefit costs associated with The Exelon Way		(9	)		(23	)
Other		(4	)		38

Increase in operating and maintenance expense	$	165		$	330


(a)		Includes refueling outage expense of $24 million at AmerGen.

(b)	~~Refueling outage days increased from 50 days for the three months ended March 31, 2003 to 114 days during the same period in 2004.~~

~~(c)~~	Includes ~~$10~~$20 million due to AmerGen asset retirement obligation accretion.

Depreciation and Amortization.The increase in depreciation and amortization expense for the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003 was primarily attributable to ~~$8 million~~the impact of ~~additional depreciation expense on~~ capital additions ~~placed~~and the consolidation of Sithe Energies, AmerGen, and Exelon Energy. These increases were partially offset by a decrease in ~~service after the first quarter of 2003, of which $3 million of~~depreciation expense ~~was~~ related to the Boston Generating ~~facilities. In addition, depreciation and amortization expense increased $2 million due to increased amortization of long-term debt and capital leases.~~facilities as the assets were classified as held for sale during the period.

Effective Income Tax Rate. The effective income tax rate was ~~40.6%~~38% for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~28.8%~~44% for the same period in 2003. ~~This increase~~The decrease was primarily attributable to the ~~impairments~~impairment charge recorded in 2003 related to Generation’s investment in Sithe ~~which~~that resulted in a pre-tax loss. ~~In addition,~~The impairment charge was taxed at a rate different than the ~~rate increased due~~overall Generation effective tax rate. See Note 12 of the Combined Notes to the ~~additional nuclear decommissioning investment~~Consolidated Financial Statements for further discussion of the change in the effective income ~~and its related taxes.~~tax rate.

Cumulative Effect of Changes in Accounting Principles. ~~Cumulative~~The cumulative effect of changes in accounting principles recorded during the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 included $32 million, net of income taxes, recorded in 2004 related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from

the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, and income of $108 million, net of income taxes, recorded in 2003 related to the adoption of SFAS No. 143. See Note 2 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for further discussion of these effects.


	Generation Operating Statistics

Generation’s sales and the supply of these sales, excluding the trading portfolio, were as follows:



	Three Months											Six Months
	Ended March 31,											Ended June 30,

Revenue	2004		2003			Variance			% Change			2004			2003			Variance			% Change

Energy Delivery and Exelon Energy Company(a)	$	860	$	965		$	(105	)		(10.9	)%
Market and retail electric sales(b)		884		857			27			3.2	%
Sales to affiliates(a)												$	1,706		$	1,842		$	(136	)		(7.4	)%
Wholesale and retail electric sales(b)													1,742			1,754			(12	)		(0.7	)%

Total energy sales revenue		1,744		1,822			(78	)		(4.3	)%		3,448			3,596			(148	)		(4.1	)%

Retail gas sales		176		—			176			n.m.			260			—			260			n.m.
Trading portfolio		—		(1	)		1			(100.0	)%		(2	)		(2	)		—			n.m.
Other revenue		33		58			(25	)		(43.1	)%		194			171			23			13.5	%

Total revenue	$	1,953	$	1,879		$	74			3.9	%	$	3,900		$	3,765		$	135			3.6	%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

(c)		Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

n.m. — not meaningful



	Three Months										Six Months Ended
	Ended,										June 30,

Sales (in GWhs)	2004^(c)		2003		Variance			% Change			2004		2003		Variance			% Change

Energy Delivery and Exelon Energy Company(a)		27,464		30,594		(3,130	)		(10.2	)%
Market and retail electric sales(b)		23,983		23,815		168			0.7	%
Sale to affiliates(a)												53,597		57,463		(3,866	)		(6.7	)%
Wholesale and retail electric sales(b)												48,959		51,264		(2,305	)		(4.5	)%

Total sales		51,447		54,409		(2,962	)		(5.4	)%		102,556		108,727		(6,171	)		(5.7	)%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b)	~~Includes retail electric sales of Exelon Energy Company in 2004.~~

~~(c)~~	Sales in 2004 do not include ~~5,453~~11,638 GWhs, which ~~are~~were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes retail electric sales of Exelon Energy Company in 2004.



	Three Months										Six Months Ended
	Ended March 31,										June 30,

Supply Source (in GWhs)	2004^(c)		2003		Variance			% Change			2004		2003		Variance			% Change

Nuclear generation(a)		33,411		29,330		4,081			13.9	%		67,665		58,949		8,716			14.8	%
Purchases — non-trading portfolio(b)		11,691		20,029		(8,338	)		(41.6	)%		23,595		39,373		(15,778	)		(40.1	)%
Fossil and hydro generation		6,345		5,050		1,295			25.6	%
Fossil and hydroelectric generation												11,296		10,405		891			8.6	%

Total supply		51,447		54,409		(2,962	)		(5.4	)%		102,556		108,727		(6,171	)		(5.7	)%


(a)		Excludes AmerGen in 2003. AmerGen generated ~~4,639~~9,761 GWhs during the ~~three~~six months ended ~~March 31,~~June 30, 2004.

(b)	~~Includes PPAs with AmerGen, which represented 2,488 GWhs in 2003.~~

~~(c)~~	Sales in 2004 do not include ~~5,453~~11,638 GWhs, which ~~are~~were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 6,219 GWhs in 2003.

Trading volumes of ~~5,113~~10,437 GWhs and ~~9,527~~17,446 GWhs for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

Generation’s supply mix changed as a result of increased fossil generation due to ~~the effect of~~ Boston Generating’s Mystic units 8 and 9 and Fore River generating facilities becoming operational in the second and third quarter of 2003, which in total account for an increase of 2,266 GWhs, and as a result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003. All of the power generated by AmerGen plants is included in nuclear generation for 2004; previously, power obtained from AmerGen facilities was treated as purchased power. Purchased power from AmerGen during the three months ended March 31, 2003 was 2,4882,688 GWhs.

Generation’s average margin and other operating data for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were as follows:



		Three Months								Six Months Ended
		Ended March 31,								June 30,

		2004		2003		% Change


($/MWh)									($/MWh)	2004		2003		% Change
		($/MWh)
Average revenue	Average revenue								Average revenue
	Energy Delivery and Exelon Energy Company(a)	$	31.31	$	31.54		(0.7	)%	Energy Delivery and Exelon Energy Company(a)	$	31.83	$	32.06		(0.7	)%
	Market and retail electric sales(b)		36.86		35.99		2.4	%	Market and retail electric sales(b)		35.58		34.22		4.0	%
	Total — excluding the trading portfolio		33.90		33.49		1.2	%	Total — excluding the trading portfolio		33.62		33.07		1.7	%
Average supply cost(c) — excluding the trading portfolio	Average supply cost(c) — excluding the trading portfolio	$	21.48	$	22.06		(2.6	)%	Average supply cost(c) — excluding the trading portfolio	$	20.77	$	21.60		(3.8	)%
Average margin — excluding the trading portfolio	Average margin — excluding the trading portfolio	$	12.42	$	11.43		8.7	%	Average margin — excluding the trading portfolio	$	12.85	$	11.47		12.0	%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

(c)		Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003.

Generation’s average margin, excluding the trading portfolio, increased primarily due to ~~higher market prices~~decreased average supply cost as a result of ~~increased~~forward hedging of fuel ~~prices and decreased average supply cost due to~~at lower costs than prior periods. Also, Generation experienced a decrease in purchased power due to reducing the capacity purchased from Midwest Generation and ~~increased~~the impact of consolidating AmerGen in 2003. The increase in nuclear ~~generation.~~generation during the period, which is generally less expensive than purchased power, along with the effect of the adoption of EITF 03-11, contributed to the increase in average margin. The increase in nuclear generation is due primarily to the consolidation of AmerGen.



	Three Months						Six Months
	Ended March 31,?						Ended June 30,

	2004			2003			2004			2003

Nuclear fleet capacity factor(a)		90.5	%		94.4	%		93.3	%		94.2	%
Nuclear fleet production cost per MWh(a)	$	14.29		$	12.80		$	12.54		$	12.40
Average purchased power cost for wholesale operations per MWh(b)	$	44.48		$	41.99		$	45.81		$	41.68


(a)		Includes AmerGen and excludes Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G).

(b)		Includes PPAs with AmerGen in 2003.

Lower nuclear capacity factors and increased nuclear production costs ~~are~~were primarily due to 6455 additional planned refueling outage days, resulting in a ~~$60~~$46 million increase in planned outage costs in the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003. There were ~~four~~five planned outages during the ~~three~~six months ended ~~March 31,~~June 30, 2004, compared to ~~two~~three planned outages during the same period in 2003. The ~~three~~six months ended ~~March 31,~~June 30, 2004 included ~~five~~twelve unplanned outages compared to ~~three~~eleven unplanned outages during the same period in 2003. Nuclear capacity factors were also affected by Quad Cities operating at lower than anticipated capacity levels.

The Quad Cities units have intermittently been operating at ~~pre-Extended Power Uprate (EPU)~~pre-EPU generation levels due to performance issues with their steam dryers. Exelon is currently evaluating data to determine when the units can return to EPU output levels. There is a continued risk that the Quad Cities units will not return to EPU operating levels in the near future. There is also a risk thatGeneration plans additional expenditures ~~will be required on these units~~ to ~~allow extended~~ensure safe and reliable operations at the EPU output ~~levels.~~levels by mid-2005.

71100


	*Results of Operations — Enterprises*



	Three Months												Six Months
	Ended March 31,												Ended June 30,

	2004			2003			Variance			% Change			2004			2003			Variance			% Change

Operating revenues	$	90		$	580		$	(490	)		(84.5	)%	$	133		$	1,022		$	(889	)		(87.0	)%
Purchased power and fuel expense		—			339			(339	)		(100.0	)%		—			505			(505	)		(100.0	)%
Operating and maintenance expense		106			256			(150	)		(58.6	)%		170			575			(405	)		(70.4	)%
Depreciation and amortization expense		—			10			(10	)		(100.0	)%		—			20			(20	)		(100.0	)%
Operating income (loss)		(20	)		(27	)		7			(25.9	)%		(42	)		(84	)		42			(50.0	)%
Other income and deductions														68			(41	)		109			n.m.
Loss before income taxes and cumulative effect of change in accounting principle		(25	)		(30	)		5			(16.7	)%		26			(125	)		151			n.m.
Loss before cumulative effect of change in accounting principle		(16	)		(17	)		1			(5.9	)%		11			(78	)		89			n.m.
Net income (loss)		(16	)		(18	)		2			(11.1	)%		11			(79	)		90			n.m.

Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. Enterprises’ result for the six months ended June 30, 2004 compared to the six months ended June 30, 2003 were significantly affected by the following transactions:

InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource.

Exelon Services, Inc. During the six months ended June 30, 2004, Enterprises disposed of certain businesses of Services, including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale recorded during the six months ended June 30, 2004 related to the disposition of these Services businesses were $34 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of June 30, 2004, Services had assets and liabilities of $58 million and $90 million, respectively, which primarily represented the corporate operations and the remaining businesses of the Mechanical and Integrated Technology Group.

In addition, during the six months ended June 30, 2004, Enterprises disposed of the following business and investment. These dispositions and the transactions described above will affect Enterprises future results of operations.

Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Thermal for proceeds of $134 million, subject to working capital adjustments. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, which resulted in prepayment penalties of $9 million, which were recorded in interest expense. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income.

101

Operating Revenues. The changes in Enterprises’ operating revenues for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:

Variance
Exelon Energy Company $ (330 )
F & M Holdings, LLC(a) (149 )
Exelon Services (11 )

Decrease in operating revenues $ (490 )


	Variance

Transfer of Exelon Energy Company to Generation	$	(504	)
Sale of InfraSource businesses		(262	)
Services(a)		(72	)
F & M Holdings, LLC(b)		(60	)
Other		9

Decrease in operating revenues	$	(889	)


(a)	~~Includes~~	Primarily due to the ~~operations~~sale of ~~former InfraSource~~certain businesses.

(b)		Operating revenues decreased $60 million as a result of the sale of certain businesses and the reduction of new business as a result of wind-down efforts.

~~Exelon Energy Company.~~ ~~Operating revenues decreased as a result of Exelon Energy Company becoming part of Generation effective January 1, 2004.~~

~~F & M Holdings, LLC.~~ Operating revenues decreased $117 million as a result of the sale of the majority of the InfraSource businesses in the third quarter of 2003. For the remaining businesses, F & M Holdings, LLC, operating revenues decreased $32 million as a result of the sale of certain businesses and the reduction of new business as a result of wind-down efforts.

~~Exelon Services.~~ Operating revenues decreased $14 million at Exelon Services due to unfavorable economic conditions in the construction market and the sale of certain Exelon Services business units. This decrease was partially offset by improved performance contracting activities of $3 million.

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased as a result of the transfer of Exelon Energy Company ~~becoming part of~~to Generation effective January 1, 2004.

Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance			Variance

F & M Holdings, LLC(a)	$	(131	)
Exelon Services		(4	)
Sale of InfraSource businesses				$	(246	)
Services(a)					(56	)
Goodwill impairment charge(b)					(47	)
F & M Holdings, LLC(c)					(43	)
Other		(15	)		(13	)

Decrease in operating and maintenance expense	$	(150	)	$	(405	)


(a)	~~Includes~~	Primarily due to the ~~operations~~sale of ~~former InfraSource~~certain businesses.

(b)		Enterprises recorded a goodwill impairment charge of $47 million during the second quarter of 2003 related to the goodwill recorded within the InfraSource reporting unit.

(c)		Operating and maintenance expense decreased $62 million as a result of wind-down efforts for these businesses. These decreases were partially offset by increased expense of $19 million due to margin deterioration on various construction projects.

~~F & M Holdings, LLC.~~ Operating and maintenance expense decreased $111 million as a result of the sale of the majority of the InfraSource businesses in the third quarter of 2003. For the remaining businesses, F & M Holdings, LLC, operating and maintenance expense decreased $33 million as a result of wind-down efforts for these businesses. These decreases were partially offset by increased expense of $12 million due to margin deterioration on various construction projects.

~~Exelon Services.~~ Operating and maintenance expense decreased $4 million at Exelon Services due primarily to delays on mechanical construction projects resulting from poor economic conditions in the construction market and the sale of certain Exelon Services business units. This decrease was partially offset by additional costs from increased performance contracting activities of $2 million and other asset impairments of $2 million.

Other Income and Deductions. The increase in other income and deductions was primarily due to 2004 gains on the sale of Exelon Thermal and Enterprises’ investment in PECO Telcove of $54 million (before income taxes and net of debt prepayment penalties) and income of $18 million recorded during the second quarter of 2004 related to the collection of a note receivable prior to its maturity. Other income and deductions in 2003 included impairment charges of energy, software and communications investments of $40 million.

Effective Income Tax Rate. The effective income tax rate was ~~36.0%~~58% for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~43.3%~~38% for the same period in 2003. The ~~decrease~~increase in the effective tax rate was primarily attributable to ~~impacts~~state tax impact on the Thermal divestiture and a 16.4% increase of ~~state~~tax expense resulting from various income tax ~~adjustments in 2003.~~related items.

~~Divestiture of Businesses.~~ In the first quarter of 2004, Enterprises sold three business units of Exelon Services. Cash proceeds to Enterprises from the sales were approximately $3 million. Enterprises recorded a net loss of $3 million before income taxes in other income and deductions on the sale.102

In December 2003, Enterprises signed an agreement to sell its Chicago business of Exelon Thermal for approximately $135 million, subject to working capital adjustments. The agreement to sell the Chicago thermal operations is subject to customary closing conditions and approval from the City of Chicago (Chicago) and is expected to close during the second quarter of 2004. The sale of the Aladdin thermal facility is expected to close during the second half of 2004. In April 2004, Enterprises signed an agreement to sell its investment in PECO TelCove, a communications joint venture, for $49 million. The agreement to sell is subject to customary closing conditions and various regulatory approvals and is expected to close during the second quarter of 2004.

Enterprises continues to pursue the divestiture of other businesses; however, it may be unable to successfully implement its divestiture strategy of certain businesses for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for the transactions. In addition, the amount that Enterprises may realize from a divestiture is subject to fluctuating market conditions that may contribute to pricing and other terms that are materially different than expected and could result in a loss on the sale. Timing of any divestitures may positively or negatively affect the results of operations.

Liquidity and Capital Resources

Exelon’s businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from Energy Delivery’s and Generation’s operations. The working capital deficit at March 31, 2004 is expected to be eliminated through the anticipated continuance of positive operating cash flows and the eventual elimination of the Boston Generating debt balance (included in liabilities held for sale) upon the sale of Boston Generating. The sale of Boston Generating will be substantively a non-cash transaction, with the Boston Generating credit facility continuing as a liability of Boston Generating at the time it is sold, without recourse to Exelon or Generation. See Note 3 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of the sale of Boston Generating. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon’s access to external financing at reasonable terms depends on Exelon and its subsidiaries’ credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Exelon no longer has access to the capital markets at reasonable terms, Exelon has access to ~~$1.5 billion through~~ revolving credit facilities with aggregate bank commitments of $1.5 billion that it currently utilizes to support its commercial paper programs. See the ~~Credit Issues~~“Credit Issues” section of ~~Liquidity~~“Liquidity and Capital ~~Resources~~Resources” for further

discussion. Exelon primarily uses its capital resources to fund capital requirements, including construction, to repay maturing debt, to pay common stock dividends, to fund its pension obligations and to invest in new and existing ventures. Future acquisitions that Exelon may undertake may require external financing, which might include issuing Exelon common stock.


	*Cash Flows from Operating Activities*

Energy Delivery’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the third quarter. Energy Delivery’s future cash flows will be affected by its ability to achieve cost savings in operations and the impact of the economy, weather, customer choice and future regulatory proceedings on its revenues. Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Energy Delivery. Generation’s future cash flows from operating activities will be affected by future demand and market prices for energy and its ability to continue to produce and supply power at competitive costs.

Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements for the foreseeable future. Operating cash flows after 2006 could be negatively affected by changes in the rate regulatory environments of ComEd and PECO, although any effects are not expected to hinder Exelon’s ability to fund its business requirements.

Cash flows from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$851~~$1,907 million and ~~$383~~$1,292 million, respectively. Changes in Exelon’s cash flows from operations are generally consistent with changes in its results of operations, and further adjusted by changes in working capital in the normal course of business.

In addition to the items mentioned in ~~Results~~“Results of Operations,” the following items affected Exelon’s operating cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003:

• During the six months ended June 30, 2004, Exelon’s federal income tax position changed from a net federal income tax payable to a net federal income tax receivable. The large increase in cash from the changes in receivables is due primarily to the current year federal income tax provision of approximately $200 million and the receipt of a $150 million federal income tax refund in the first quarter of 2004, partially offset by a $58 million increase in customer accounts receivable and the payment of $67 million for federal income taxes.
• Natural gas inventories and deferred natural gas costs decreased ~~$71~~$24 million and ~~$30~~$56 million, respectively, during the ~~three~~six months ended ~~March 31,~~June 30, 2004 resulting in ~~a $101~~an $80 million increase to operating cash flows. During 2003, ~~a decrease~~an increase in natural gas inventories of ~~$43~~$1 million ~~partially offset by~~and an increase in deferred natural gas costs of ~~$28~~$24 million resulted in a ~~$15~~$25 million ~~increase in~~decrease to operating cash flow. PECO’s gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. During 2004, PECO was recovering fuel revenues from customers in excess of gas costs being incurred. During 2003, PECO was incurring gas costs in excess of fuel revenues being recovered from customers.

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• An increase in required deposits for energy trading activity of ~~$118~~$136 million resulted from Generation exceeding its negotiated credit positions with counterparties during the ~~three~~six months ended ~~March 31,~~June 30, 2003.
• ~~An income tax refund of $150~~ During 2004, required deposits for trading activity resulted in a $2 million ~~increased~~net cash from operations during the three months ended March 31, 2004. Income tax payments of $137 million and interest payments of $63 million contributed to the $217 million use of cash for accounts payable, accrued expenses and other current liabilities during 2003.inflow.

• Discretionary tax-deductible pension plan payments were ~~$143~~$288 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~$125~~$246 million for the same period in 2003. Additionally, ~~$22~~$42 million and ~~$15~~$30 million ~~was~~were contributed to the postretirement welfare benefit plans infor the ~~first quarter of~~six months ended June 30, 2004 and 2003, respectively.

Exelon expects to contribute up to approximately $419 million to its pension plans in 2004. These contributions exclude benefit payments expected to be made directly from corporate assets. Of the $419 million expected to be contributed to the pension plans during 2004, ~~$17~~$11 million is estimated to be needed to satisfy ~~IRS~~Internal Revenue Service (IRS) minimum funding requirements.

Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the ~~Internal Revenue Service (IRS),~~IRS to defer the tax gain on the 1999 sale of its fossil generating assets. As of ~~March 31,~~June 30, 2004, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s Consolidated

Balance Sheets with the majority allocated to the Consolidated Balance Sheets of ComEd and the remainder to the Consolidated Balance Sheets of Generation. The 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. Any required payments could be significant to the cash flows of Exelon. Exelon’s management believes Exelon’s reserve for interest, which has been established in the event that such positions are not sustained, ~~reflects the most likely probable expected outcome~~has been appropriately recorded in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5). However, the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.


	*Cash Flows from Investing Activities*

Cash flows used in investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$373~~$669 million and ~~$383~~$1,016 million, respectively. The ~~$10~~$347 million ~~decrease in~~reduction of cash used in investing activities ~~during the three months ended March 31,~~in 2004 versus 2003 is primarily attributable to ~~cash proceeds of $42 million received during~~ the three months ended March 31, 2004 from the sale of three gas turbines at Generation that were classified as assets held for sale at December 31, 2003, partially offset by an increase in capital expenditures of $12 million and an increase in investments in nuclear decommissioning trust funds of $21 million over amounts invested during the same period in 2003. Additionally, onfollowing:

• Cash proceeds of $210 million received during the six months ended June 30, 2004 from the sales of Exelon Thermal, certain businesses of Exelon Services and Enterprises’ investments in PECO TelCove and other equity method investments.
• Cash proceeds of $42 million received from the sale of three gas turbines at Generation that were classified as assets held for sale at December 31, 2003.
• A decrease in capital expenditures of $89 million net of liquidating damages received in 2003.
• An increase in investments in nuclear decommissioning trust funds of $30 million.
• On March 31, 2004, Exelon consolidated the assets and liabilities of Sithe under the provisions of FIN No. 46-R, which resulted in an increase in cash of $19 million. See Note 2 and Note 4 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for further information regarding the FIN No. 46-R consolidation of Sithe.
• Early settlement on an acquisition note receivable from the 2003 disposition of InfraSource resulted in cash proceeds of $30 million during the six months ended June 30, 2004.

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Capital expenditures by business segment for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were as follows:



	Three Months				Six Months
	Ended March 31,				Ended June 30,

	2004		2003		2004		2003

Energy Delivery	$	226	$	239	$	474	$	487
Generation		213		175		366		424
Enterprises		—		6		—		11
Corporate and other		—		7		4		11

Total capital expenditures	$	439	$	427
Total capital expenditures, net of liquidating damages received					$	844	$	933

Energy Delivery’s capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2004 reflect continuing efforts to improve the reliability of its transmission and distribution systems and capital additions to support new business and customer growth. ComEd estimates that it will spend up to approximately $715 million in total capital expenditures for 2004. This represents an increase of approximately $100 million more than had been previously planned, primarily as a result of expansion of the ComEd distribution system to support new business and customer growth. However, Exelon is continuing to evaluate its total capital spending requirements and potential mitigating opportunities across the company. Exelon anticipates that Energy Delivery’s capital expenditures will be funded by internally generated funds, borrowings and the issuance of debt or preferred securities or capital contributions from Exelon.

Generation’s capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2004 reflect additions and upgrades to existing facilities (including nuclear refueling outages), nuclear fuel and increases in capacity at existing plants. Generation’s capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2003 ~~reflect~~reflected the construction of ~~three~~the Mystic 8 and 9 and Fore River Boston Generating ~~facilities~~facilities. During 2003, Boston Generating received $86 million of liquidated damages from Raytheon Company (Raytheon) as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with ~~capacity~~Raytheon’s construction of ~~2,288 MWs of energy.~~these generating facilities. Exelon anticipates that Generation’s capital expenditures will be funded by internally generated funds, Generation’s borrowings or capital contributions from Exelon.


	*Cash Flows from Financing Activities*

Cash flows used in financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2004 were ~~$472~~$937 million compared to $255 million for the same period in 2003. The increase in cash ~~provided by~~used in financing activities ~~for~~is primarily attributable to the ~~three~~net retirement of $582 million of long-term debt during the six months ended ~~March 31, 2003~~June 30, 2004 versus the net issuance of ~~$34 million.~~long-term debt of $334 million during the six months ended June 30, 2003. See Note 79 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for further information regarding debt issuances and retirements during the ~~three~~six months ended ~~March 31,~~June 30, 2004. During the six months ended June 30, 2004, Exelon repaid $65 million of commercial paper and received cash proceeds of $31 million from the settlement of interest-rate swaps. During the six months ended June 30, 2003, Exelon repaid $100 million of commercial paper and paid $51 million to settle an interest-rate swap. Additionally, Exelon purchased treasury shares totaling $75 million during the second quarter of 2004 and received proceeds from employee stock plans of $140 million and $91 million for the six months ended June 30, 2004 and 2003, respectively.

�� The cash dividend payments on common stock for the ~~three~~six months ended ~~March 31,~~June 30, 2004 ~~and~~increased $79 million over the six months ended June 30, 2003, ~~were $181 million~~reflecting a 9% increase in the common stock dividend in the third quarter of 2003 and ~~$145 million, respectively. On January 27, 2004, the Exelon Board of Directors approved~~ a 10% increase in the ~~quarterly dividend to $0.55 per share.~~first quarter of 2004. Payment of future dividends is subject to approval and declaration by the Board.

From time to time and as market conditions warrant, Exelon may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of Exelon’s balance sheet.

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	*Credit Issues*

Exelon Credit Facility. Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by Exelon corporate holding company (Exelon Corporate) and by ComEd, PECO and Generation. At June 30, 2004, Exelon Corporate, ~~participates,~~ along with ComEd, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility, and the $750 million three-year facility was reduced to $500 million. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon Corporate, ComEd, PECO and Generation and to issue letters of credit. ~~The 364-day agreement includes a term-out option provision that allows a borrower to extend the maturity of revolving credit borrowings outstanding at the end of the 364-day period for one year.~~ At ~~March 31,~~June 30, 2004, Exelon Corporate, ComEd, PECO and Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:


	Bank		Available		Outstanding		Bank		Available		Outstanding
Borrower	Sublimit(a)		Capacity(b)		Commercial Paper		Sublimit(a)		Capacity(b)		Commercial Paper

Exelon Corporate	$	550	$	529	$	70	$	550	$	531	$	50
ComEd		100		66		—		100		74		—
PECO		250		221		81		250		250		—
Generation		600		449		165		600		460		211


(a)		Sublimits under the credit agreements can change upon written notification to the bank group.

(b)		Available capacity represents primarily the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the Exelon Credit Facility.

Interest rates on the advances under the credit facility are based on either the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing or prime. The maximum LIBOR adder would be 175 basis points. For the ~~three~~six months ended ~~March 31,~~June 30, 2004, the average interest rate on notes payable was approximately 1.05%.

The credit agreements require Exelon Corporate, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon Corporate and Generation, revenues from Exelon New England Holding Company, LLC (Exelon New England) and Sithe and interest on the debt of ~~Exelon New England’s~~their project subsidiaries. Exelon Corporate is measured at the Exelon consolidated level. The following table summarizes the minimum thresholds reflected in the credit ~~agreement~~agreements for the twelve-month period ended ~~March 31,~~June 30, 2004:

Exelon Corporate

ComEd

PECO

Generation

Credit agreement threshold

2.65 to 1

2.25 to 1

3.25 to 1

At ~~March 31,~~June 30, 2004, each of Exelon Corporate, ComEd, PECO and Generation were in compliance with the foregoing thresholds.

76106

Capital Structure. At ~~March 31,~~June 30, 2004, Exelon’s, ComEd’s, PECO’s and Generation’s capital structure consisted of the following:


	Exelon												Exelon
	Consolidated			ComEd(a)			PECO(a)			Generation			Consolidated			ComEd(a)			PECO(a)			Generation

Long-term debt		40	%(b)		34	%		21	%		53	%(b)		37	%		33	%		21	%		42	%
Long-term debt to affiliates		24	(c)		15	(c)		61	(c)		—			24	(b)		15	(b)		61	(b)		—
Common equity		35			51			16			—			38			52			17			—
Member’s equity		—			—			—			41			—			—			—			50
Preferred securities		—			—			1			—			—			—			1			—
Notes payable		1			—			1			5			1			—			—			7
Minority interest		—			—			—			1			—			—			—			1


(a)		At ~~March 31,~~June 30, 2004, ComEd’s capital structure, excluding the deduction from shareholders’ equity of the ~~$219~~$188 million receivable from Exelon (which amount is deducted for GAAP purposes, as reflected in the table, but is excluded from the percentages in this ~~footnote~~footnote) to reflect amounts expected to be received by ComEd from Exelon to pay future ~~taxes),~~taxes, consisted of 33% long-term debt, ~~15%~~14% long-term debt to affiliates and ~~52%~~53% common equity. Likewise, PECO’s capital structure, excluding the deduction from shareholder’s equity of the $1.6 billion receivable from Exelon, consisted of ~~32%~~33% common equity, ~~1% notes payable,~~ 1% preferred securities and 66% long-term debt, including long-term debt to unconsolidated affiliates.

(b)	Includes $1.0 billion Boston Generating project debt, classified as liabilities held for sale on the Consolidated Balance Sheets, and $1.2 billion of senior unsecured notes representing 9% and 33% of capitalization for Exelon and Generation, respectively.

~~(c)~~	Includes $6 billion, $2 billion and $4 billion owed to unconsolidated affiliates of Exelon, ComEd and PECO, respectively, that qualify as special purpose entities under FIN No. 46-R. These special purpose entities were created for the sole purpose of issuing debt obligations to securitize intangible transition property and CTCs of Energy Delivery or mandatorily redeemable preferred securities. See Note 2 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for further information regarding FIN No. 46-R.

Boston Generating Project Debt. Boston Generating ~~has~~had a $1.25 billion credit facility (Boston Generating Credit Facility), which was entered into primarily to finance the development and construction of the Mystic 8 and 9 and Fore River generating facilities. ~~Approximately $1.0 billion of debt was outstanding under the credit facility at March 31,~~On May 25, 2004, ~~all of which was reflected in Exelon’s Consolidated Balance Sheets as a liability held for sale. The Boston Generating Facility is non-recourse to~~ Exelon and Generation ~~and an event of default under the Boston Generating Facility does not constitute an event of default under any other of Exelon’s debt instruments or the debt instruments of Exelon’s subsidiaries.~~

~~Exelon is in the process of~~completed the sale, transfer and assignment of ownership of Boston Generating ~~which owns the companies that own the Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities. Exelon’s decision~~ to ~~transition out of the projects was made as~~ a ~~result of its evaluation of the projects and discussions with~~special purpose entity owned by the lenders under the Boston Generating Credit Facility. Accordingly, the Boston Generating Credit Facility was eliminated from the consolidated financial statements of Exelon and Generation during the second quarter of 2004.

See Note 3 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for information regarding the sale of Generation’s ownership interest in Boston Generating to the lenders under the Boston Generating Credit Facility.

Intercompany Money Pool. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by Exelon’s corporate treasurer. ComEd and its subsidiary, Commonwealth Edison of Indiana, Inc. (ComEd of Indiana), PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate and Unicom Investment, Inc., a wholly owned subsidiary of Exelon, may participate as lenders. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in

economic benefits. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During 2004, ComEd, ComEd of Indiana and PECO had various

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contributions to the money pool, and Generation and BSC had various loans from the money pool as described in the ~~attached~~following table:


					March 31, 2004							June 30, 2004
	Maximum		Maximum		Contributed			Maximum		Maximum		Contributed
	Invested		Borrowed		(Borrowed)			Invested		Borrowed		(Borrowed)

ComEd	$	487	$	—	$	226		$	487	$	—	$	198
ComEd of Indiana									21		—		21	(a)
PECO		162		—		—			162		—		35
Generation		—		407		(226	)		—		407		(198	)
BSC		—		197		—			—		197		(35	)


(a)		The activity at ComEd of Indiana at June 30, 2004 was eliminated in the consolidation of ComEd.

Sithe Long-Term Debt. At ~~March 31,~~June 30, 2004, $852 million of Sithe’s long-term debt, ~~of $850 million~~including current maturities, was ~~consolidated~~included in Exelon and Generation’s Consolidated Balance ~~Sheets as a result of the adoption of FIN No. 46-R.~~Sheets. See Note 2 and Note 4 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for ~~further~~ information regarding the consolidation of Sithe and see Note 79 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for ~~further~~ information regarding Sithe’s long-term debt and the annual maturities.

Security Ratings. ~~See “Management’s Discussion~~Exelon’s access to the capital markets, including the commercial paper market, and ~~Analysis~~its financing costs in those markets depend on the securities ratings of ~~Financial Condition and Results~~the entity that is accessing the capital markets. On July 22, 2004, Standard & Poor’s Ratings Services lowered the ratings on PECO’s First Mortgage Bonds from A to A-. None of ~~Operations — Liquidity and Capital Resources” in~~ the ~~2003 Form 10-K for a discussion~~other securities ratings of Exelon, PECO or Exelon subsidiaries has changed. None of Exelon’s ~~security ratings.~~borrowings is subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under Exelon’s credit facilities.

Shelf Registration. As of ~~March 31,~~June 30, 2004, Exelon, ComEd and PECO have current shelf registration statements for the sale of ~~$3.2~~$2.0 billion, $555 million and $550 million, respectively, of securities that are effective with the SEC. ~~Each company’s~~Exelon’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, the current financial condition of the company, its securities ratings and market conditions.

PUHCA Restrictions. On April 1, 2004, Exelon obtained a new order from the SEC under the Public Utilities Holding Company Act of 1935 (PUHCA) authorizing, through April 15, 2007, financing transactions, including the issuance of common stock, preferred securities, equity-linked securities, long-term debt and short-term debt in an aggregate amount not to exceed $8.0 billion above the amount outstanding for Exelon Corporate and Generation at December 31, ~~2003.~~2003 with no separate sublimit for short-term debt. The new financing order replaced a prior SEC order that expired on March 31, 2004 that had authorized up to $4.0 billion of financing. ~~As of March 31, 2004, there was $2.1 billion of financing authority remaining~~No securities have been issued under the prior SEC order. The prior order limited Exelon’s short-term debt outstanding to $3.0 billion of the $4.0 billion total financing authority. The new order eliminates the short-term debt sub-limit restriction.above described limit. The prior order also authorized Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. The new order gives Exelon an additional $1.5 billion of guaranty authority. At ~~March 31,~~June 30, 2004, Exelon had provided ~~$2.0~~$1.9 billion of guarantees under the SEC order. See ~~Contractual~~“Contractual Obligations and Off-Balance Sheet ~~Arrangements~~Arrangements” in this section for further discussion of guarantees. The SEC order requires Exelon to maintain a ratio of common equity to total capitalization (including securitization debt) of not less than 30%. At ~~March 31,~~June 30, 2004, Exelon’s common equity ratio was ~~35%~~38%. Exelon expects that it will maintain a common equity ratio of at least 30%.

Exelon is also limited by order of the SEC under PUHCA to an aggregate investment of $4.0 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). At ~~March 31,~~June 30, 2004, Exelon had invested ~~$2.8~~$1.9 billion in EWGs, leaving ~~$1.2~~$2.1 billion of investment authority under the order. In its April 1, 2004 financing order, the SEC authorized Exelon to invest $4 billion in EWGs and reserved jurisdiction over an additional $3.0 billion in investments in EWGs.

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Under applicable law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless its earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves, or unless it has specific authorization from the Illinois Commerce Commission (ICC). Furthermore, aA significant loss recorded at ComEd, PECO or Generation may limit the dividends that ~~ComEd~~these companies can distribute to

Exelon. At ~~March 31,~~June 30, 2004, Exelon had retained earnings of ~~$2.5~~$2.9 billion, including ComEd’s retained earnings of ~~$962~~$1,064 million ~~(of~~(all of which ~~$891 million~~ had been appropriated for future dividend payments), PECO’s retained earnings of ~~$586~~$597 million and Generation’s undistributed earnings of ~~$647~~$773 million.


	*Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations*

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Exelon’s, ComEd’s, PECO’s and Generation’s contractual obligations and commercial commitments as of ~~March 31,~~June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

• ~~In connection with the consolidation of Sithe pursuant to FIN No. 46-R,~~ Generation ~~maintains~~acquired a $50 million ~~non-debt~~ letter of credit ~~under~~that supports the contractual obligations of Sithe and its ~~credit agreement.~~subsidiaries.

• See Note 79 and Note 1719 to the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for discussion of material changes in the registrants’ respective debt from the amounts set forth in the 2003 Form 10-K.

79109

COMMONWEALTH EDISON COMPANY

General

ComEd operates in a single business segment and its operations consist of the regulated sale of electricity and distribution and transmission services in northern Illinois.

Executive ~~Summary~~Overview

Financial Results. ComEd’s net income was consistent for the three months ended June 30, 2004 as compared to the same period in 2003.

ComEd experienced an overall decline in net income of ~~7% in~~3% during the ~~first quarter of~~six months ended June 30, 2004. This decline primarily reflects lower collections of CTCs, partially offset by lower operating and maintenance expense compared to the ~~first quarter of~~corresponding period in 2003 in which ComEd recorded charges associated with an agreement with various Illinois retail market participants and other interested parties.

The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd — Executive Summary” in the 2003 Form 10-K for a discussion of ComEd’s implementation of The Exelon Way.

Financing Activities. During the six months ended June 30, 2004, ComEd repaid ~~$176~~$178 million of long-term debt and made a ~~$93~~$179 million payment on long-term debt to ComEd Transitional Funding ~~Trust during the first quarter of 2004.~~Trust. ComEd met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable ~~future.~~future, absent new acquisitions.

~~Operations.~~Regulatory Developments — PJM Integration. On April 1, 2003, ComEd received approval from the FERC to transfer control of its transmission assets to PJM. The FERC also accepted for filing the amended PJM Tariff to reflect the inclusion of the transmission assets of ComEd and other new members, subject to a compliance filing and hearing on certain issues. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. On March 18, 2004, the FERC approved ComEd’s plan to complete ~~the~~its integration ~~of its transmission facilities~~ into PJM, subject to the ~~NERC~~North American Electric Reliability Council (NERC) approval of the PJM and Midwest ISO reliability plans to assure no adverse ~~impacts.~~effects. The NERC granted the required approval on April 2, 2004. On April 27, 2004, the FERC issued its order approving ComEd’s application, subject to certain stipulations, including a provision to hold certain other utilities harmless from the impacts of ComEd joining PJM. ComEd agreed to these stipulations and fully ~~integrate~~integrated into PJM on May 1, 2004. ~~ComEd intends to accept the conditions in the FERC order and expects full integration to occur on that date.~~

PECO and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of ~~electricity.~~electric energy and capacity. Upon joining PJM, ComEd ~~will begin to incur incremental~~began incurring administrative fees, which are expected to approximate $30 million annually. ComEd believes such costs will ultimately be partially offset by the benefits of full access to a wholesale competitive marketplace, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on ComEd.

Through and Out Rates. ComEd currently earns approximately $66 million annually from T&O rates for energy flowing across ComEd’s transmission system. On March 19, 2004, the FERC issued an order to eliminate these rates effective May 1, 2004, which was subsequently deferred until December 1, 2004. The T&O rates are to be replaced by a new long-term transmission pricing structure that will eliminate seams in the PJM and Midwest ISO regions. Transmission owners in PJM and Midwest ISO and other parties must file one or more pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. While Exelon and ComEd cannot predict the outcome of the FERC’s final determination of a new long-term transmission pricing structure, such pricing structure could adversely impact Exelon’s and ComEd’s after-tax results of operations.

Delivery Services Rates. On March 3, 2003, ComEd entered into, and the ICC subsequently entered orders, which are now final, that effectuated an agreement (Agreement) with various Illinois retail market

110

participants and other interested parties that settled, among other things, delivery service rates and the market value index proceeding and facilitates competitive service declarations for large-load customers and an extension of the PPA with Generation.

Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. However, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to have a significant effect on operating revenues until after December 31, 2006. ComEd began charging the new rates May 1, 2004. ComEd’s management believes an adequate reserve for any required refunds has been established in the event that the new rates are adjusted based on rehearing or settlement negotiations.

Outlook for the Remainder of 2004 and Beyond. ComEd’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd — Executive Summary” in the 2003 Form 10-K.

Results of Operations


	Three Months Ended ~~March 31,~~June 30, 2004 Compared to Three Months Ended ~~March 31,~~June 30, 2003



			Three Months														Three Months
			Ended March 31,														Ended June 30,

			2004			2003			Variance			% Change					2004			2003			Variance			% Change

Operating revenues	Operating revenues		$	1,336		$	1,424		$	(88	)		(6.2	)%	Operating revenues		$	1,403		$	1,361		$	42			3.1	%
Operating expenses	Operating expenses														Operating expenses
	Purchased power			533			578			(45	)		(7.8	)%	Purchased power			574			533			41			7.7	%
	Operating and maintenance			217			261			(44	)		(16.9	)%	Operating and maintenance			223			221			2			0.9	%
	Depreciation and amortization			102			94			8			8.5	%	Depreciation and amortization			103			96			7			7.3	%
	Taxes other than income			79			80			(1	)		(1.3	)%	Taxes other than income			72			68			4			5.9	%

		Total operating expense		931			1,013			(82	)		(8.1	)%		Total operating expense		972			918			54			5.9	%

Operating income	Operating income			405			411			(6	)		(1.5	)%	Operating income			431			443			(12	)		(2.7	)%

Other income and deductions	Other income and deductions														Other income and deductions
	Interest expense			(106	)		(110	)		4			(3.6	)%	Interest expense			(96	)		(106	)		10			(9.4	)%
	Distributions on mandatorily redeemable preferred securities			—			(7	)		7			(100.0	)%	Distributions on mandatorily redeemable preferred securities			—			(6	)		6			(100.0	)%
	Equity in earnings (losses) of unconsolidated affiliates			(3	)		—			(3	)		n.m.		Equity in earnings (losses) of unconsolidated affiliates			(6	)		—			(6	)		n.m.
	Other, net			9			22			(13	)		(59.1	)%	Other, net			7			12			(5	)		(41.7	)%

		Total other income and deductions		(100	)		(95	)		(5	)		5.3	%		Total other income and deductions		(95	)		(100	)		5			(5.0	)%

Income before income taxes and cumulative effect of a change in accounting principle				305			316			(11	)		(3.5	)%
Income before income taxes															Income before income taxes			336			343			(7	)		(2.0	)%
Income taxes	Income taxes			123			126			(3	)		(2.4	)%	Income taxes			132			138			(6	)		(4.3	)%

Net income before cumulative effect of a change in accounting principle				182			190			(8	)		(4.2	)%
Cumulative effect of a change in accounting principle				—			5			(5	)		(100.0	)%

Net income	Net income		$	182		$	195		$	(13	)		(6.7	)%	Net income		$	204		$	205		$	(1	)		(0.5	)%

~~n.m. —~~ n.m. — not meaningful

81111


	*Operating Revenues*

ComEd’s electric sales statistics were as follows:



		Three Months											Three Months
		Ended March 31,											Ended June 30,

Retail Deliveries — (in GWhs)	Retail Deliveries — (in GWhs)	2004		2003		Variance			% Change			Retail Deliveries — (in GWhs)	2004		2003		Variance			% Change

Full service(a)	Full service(a)											Full service(a)
Residential	Residential		7,013		6,886		127			1.8	%	Residential		5,793		5,163		630			12.2	%
Small commercial & industrial	Small commercial & industrial		5,133		5,627		(494	)		(8.8	)%	Small commercial & industrial		4,791		5,114		(323	)		(6.3	)%
Large commercial & industrial	Large commercial & industrial		1,345		1,484		(139	)		(9.4	)%	Large commercial & industrial		1,426		1,683		(257	)		(15.3	)%
Public authorities & electric railroads	Public authorities & electric railroads		1,240		1,416		(176	)		(12.4	)%	Public authorities & electric railroads		1,200		1,333		(133	)		(10.0	)%

	Total full service		14,731		15,413		(682	)		(4.4	)%	Total full service		13,210		13,293		(83	)		(0.6	)%

PPO	PPO											PPO
Small commercial & industrial	Small commercial & industrial		731		793		(62	)		(7.8	)%	Small commercial & industrial		870		869		1			0.1	%
Large commercial & industrial	Large commercial & industrial		747		1,433		(686	)		(47.9	)%	Large commercial & industrial		877		1,318		(441	)		(33.5	)%
Public authorities & electric railroads	Public authorities & electric railroads		434		537		(103	)		(19.2	)%	Public authorities & electric railroads		577		531		46			8.7	%

			1,912		2,763		(851	)		(30.8	)%			2,324		2,718		(394	)		(14.5	)%

Delivery only(b)	Delivery only(b)											Delivery only(b)
Small commercial & industrial	Small commercial & industrial		1,772		1,348		424			31.5	%	Small commercial & industrial		1,761		1,257		504			40.1	%
Large commercial & industrial	Large commercial & industrial		2,940		1,832		1,108			60.5	%	Large commercial & industrial		3,090		2,128		962			45.2	%
Public authorities & electric railroads	Public authorities & electric railroads		488		282		206			73.0	%	Public authorities & electric railroads		406		247		159			64.4	%

			5,200		3,462		1,738			50.2	%			5,257		3,632		1,625			44.7	%

	Total PPO and delivery only		7,112		6,225		887			14.2	%	Total PPO and delivery only		7,581		6,350		1,231			19.4	%

Total retail deliveries	Total retail deliveries		21,843		21,638		205			0.9	%	Total retail deliveries		20,791		19,643		1,148			5.8	%


(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.

(b)		Delivery only service reflects customers receiving electric generation service from an ~~ARES.~~AES.

82112



	Three Months											Three Months
	Ended March 31,											Ended June 30,

Electric Revenue	2004		2003		Variance			% Change			Electric Revenue	2004		2003		Variance			% Change

Full service(a)
Full service(a)											Full service(a)
Residential	$	560	$	546	$	14			2.6	%	Residential	$	521	$	472	$	49			10.4	%
Small commercial & industrial		373		397		(24	)		(6.0	)%
Large commercial & industrial		60		74		(14	)		(18.9	)%
Public authorities & electric railroads		73		84		(11	)		(13.1	)%

Total full service		1,066		1,101		(35	)		(3.2	)%

PPO(b)
Small commercial & industrial		48		50		(2	)		(4.0	)%	Small commercial & industrial		396		405		(9	)		(2.2	)%
Large commercial & industrial		42		72		(30	)		(41.7	)%	Large commercial & industrial		71		84		(13	)		(15.5	)%
Public authorities & electric railroads		22		27		(5	)		(18.5	)%	Public authorities & electric railroads		74		81		(7	)		(8.6	)%

		112		149		(37	)		(24.8	)%	Total full service		1,062		1,042		20			1.9	%

Delivery only(c)
PPO(b)											PPO(b)
Small commercial & industrial											Small commercial & industrial		60		59		1			1.7	%
Large commercial & industrial											Large commercial & industrial		51		72		(21	)		(29.2	)%
Public authorities & electric railroads											Public authorities & electric railroads		31		28		3			10.7	%

													142		159		(17	)		(10.7	)%

Delivery only(c)											Delivery only(c)
Small commercial & industrial		33		41		(8	)		(19.5	)%	Small commercial & industrial		35		32		3			9.4	%
Large commercial & industrial		40		49		(9	)		(18.4	)%	Large commercial & industrial		43		43		—			—
Public authorities & electric railroads		8		9		(1	)		(11.1	)%	Public authorities & electric railroads		9		8		1			12.5	%

		81		99		(18	)		(18.2	)%			87		83		4			4.8	%

Total PPO and delivery only		193		248		(55	)		(22.2	)%	Total PPO and delivery only		229		242		(13	)		(5.4	)%

Total electric retail revenues		1,259		1,349		(90	)		(6.7	)%	Total electric retail revenues		1,291		1,284		7			0.5	%
Wholesale and miscellaneous revenue(d)		77		75		2			2.7	%	Wholesale and miscellaneous revenue(d)		112		77		35			45.5	%

Total electric revenue	$	1,336	$	1,424	$	(88	)		(6.2	)%	Total electric revenue	$	1,403	$	1,361	$	42			3.1	%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.

(b)		Revenue from customers choosing ComEd’s PPO includes an energy charge at market rates, transmission and distribution charges and a ~~CTC.~~CTC charge.

(c)		Delivery only revenue from customers choosing an ~~ARES~~AES includes a distribution charge and a CTC charge. ~~Transmission~~Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from ~~ARES are~~AES were included in wholesale and miscellaneous revenue.

(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

113

The changes in electric retail revenues for the three months ended ~~March 31,~~June 30, 2004, as compared to the same period in 2003, are attributable to the following:


	Variance				Variance

Volume				Volume	$	61
Weather				Weather		29
Customer choice	$	(56	)	Customer choice		(51	)
Rate changes		(42	)	Rate changes		(28	)
Weather		(23	)
Volume		31
Other				Other		(4	)

Electric retail revenue	$	(90	)
				Electric retail revenue		7

ComEd’s integration into PJM				ComEd’s integration into PJM		43
Other				Other		(8	)

				Wholesale and miscellaneous revenue		35

				Total electric retail revenue	$	42

~~Customer Choice.~~Volume. ~~All ComEd customers have the choice to purchase energy~~Revenues from ~~other suppliers. This choice generally does not impact the~~higher delivery volume, exclusive of deliveries, but affects revenue collected from customers related to energy supplied by ComEd. However, as of March 31, 2004, no ARES has sought approval from the ICC, and no electric utilities have chosen, to enter the ComEd residential market for the supply of electricity.

~~For the three months ended March 31, 2004, the energy provided by alternative suppliers was 5,200 GWhs, or 23.8%, as compared to 3,462 GWhs, or 16.0%, for the same period in 2003.~~

The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. As of March 31, 2004, the number of retail customers that had elected to purchase energy from an ARES or the ComEd PPO was approximately 20,200 as compared to 22,700 as of March 31, 2003, representing less than 1% of total customers in each period. MWhs delivered to such customersweather, increased ~~from approximately 6.2~~$61 million ~~for the three months ended March 31, 2003 to 7.1 million for three months ended March 31, 2004, or from 29% to 33% of total quarterly retail deliveries.~~

~~Rate Changes.~~ ~~The $76 million decrease in ComEd’s collection of CTCs for the three months ended March 31, 2004 as compared to the same period in 2003 was~~ due to ~~a decrease in the CTC rates as a result of higher wholesale market prices of electricity, net of~~ increased ~~mitigation factors. This decrease was partially offset by~~residential customer growth and an increased ~~wholesale market prices which increased energy revenue received under ComEd’s PPO by $19 million~~usage per customer, primarily residential and by increased average rates paid by residential customers of $5 million. Although residential rates are frozen through 2006, average residential rates fluctuate due to the usage patterns of customers. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity, net of increased mitigation factors, decreases the collection of CTCs as compared to the respective prior year period.large commercial and industrial.

Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather conditions for the three months ended ~~March 31,~~June 30, 2004 were ~~unfavorable~~favorable compared to the same period in ~~2003 as a result of milder winter weather in 2004. Heating~~2003. Cooling degree-days ~~decreased 5%~~increased 68% for the three months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003, and were 2%14% lower than normal. Heating degree-days decreased 18% for the three months ended June 30, 2004 compared to the same period in 2003, and were 13% lower than normal.

~~Volume.~~Customer Choice. ~~Revenues~~All ComEd customers have the choice to purchase energy from ~~higher delivery~~an AES. This choice generally does not impact the volume ~~exclusive~~ of ~~weather, increased $31 million due~~deliveries, but affects revenue collected from customers related to ~~an increased usage per customer, primarily~~energy supplied by ComEd. As of June 30, 2004, no AES has sought approval from the ICC, and no electric utilities have chosen to enter the ComEd residential ~~and large~~market for the supply of electricity. ComEd competes with AESs in the commercial ~~and industrial.~~market.

~~Wholesale and miscellaneous revenue~~For the three months ended June 30, 2004, the energy provided by AESs was 5,257 GWhs, or 25%, as compared to 3,632 GWhs, or 18%, for the same period in 2003.

The decrease in revenues reflects customers in Illinois electing to purchase energy from an AES or the PPO. As of June 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,400 as compared to 22,000 as of the same period in 2003, representing less than 1% of total customers in each period. MWhs delivered to such customers increased from approximately 6.3 million for the three months ended ~~March 31,~~June 30, 2003 to 7.6 million for three months ended June 30, 2004, or from 32% to 36% of total quarterly retail deliveries.

Rate Changes. ComEd’s CTC is reset in the second quarter of each year to reflect market price adjustments. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component, decreased the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased $44 million for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under ComEd’s PPO by $28 million.

Decreased average rates paid by residential customers resulted in a $10 million decrease. Although residential rates are frozen through 2006, average residential rates fluctuate due to the usage patterns of customers.

114

ComEd’s Integration into PJM. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 ~~remained constant.~~due to ComEd’s May 1, 2004 entry into PJM. The increase relates to the change in control of the transmission assets from ComEd to PJM whereby ComEd receives revenues for its proportionate share of the transmission revenues generated by PJM, but also pays PJM for the use of its transmission assets. For 2004, ComEd’s operating revenues are estimated to increase by approximately $180 million, offset by a corresponding and equal increase in purchased power expense. Starting in 2005, on an annual basis, ComEd’s operating revenues and purchased power expense are estimated to increase between $200 to $250 million; however, there is no expected impact on revenues net of purchased power expense.


	*Purchased Power*

The ~~decrease~~increase in purchased power expense was primarily attributable to an increase of $28 million due to higher volume and a ~~$52~~$10 million increase due to favorable weather conditions offset by a $40 million decrease as a result of non-residential customers choosing to purchase energy from an ~~ARES, an $8~~AES. ComEd’s operating revenues and purchased power expense each increased by $43 million ~~decrease~~in the three months ended June 30, 2004 relative to 2003 due to ~~unfavorable weather conditions, and a $7 million decrease due to the mix of average pricing related to~~ ComEd’s ~~PPA with Generation partially offset by an increase of $15 million due to higher volume.~~May 1, 2004 entry into PJM. See “Operating Revenues” above.


	*Operating and Maintenance*

The ~~decrease~~changes in ~~O&M~~operating and maintenance expense ~~was primarily attributable~~for the three months ended June 30, 2004 compared to ~~a net one-time charge of $41 million~~the same period in 2003 ~~as a result~~consisted of an agreement with various Illinois retail market participants and other interested parties (Agreement) and a decrease in payroll expenses at ComEd of $22 million due to fewer employees as a result of Exelon Way terminations and the centralization of key functions partially offset by $17 million due to higher corporate allocations and $8 million of higher employee fringe benefits in 2004. The increase in corporate allocations was driven by payroll expenses and employee fringe benefits resulting from the centralization of certain functions which transferred certain employees from ComEd to BSC in 2004.

84following:


	Variance

Higher corporate allocations(a)	$	17
Severance, pension and postretirement benefit costs associated with The Exelon Way		8
Tax consultant fees(b)		5
Employee fringe benefits(c)		(10	)
Contractors		(11	)
Environmental charges		(4	)
Other		(3	)

Increase in operating and maintenance expense	$	2


(a)		Higher corporate allocations primarily result from higher corporate governance allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprise companies resulting in ComEd comprising a greater percentage of Exelon.

(b)		ComEd recorded a $5 million charge for contingent fees paid to a tax consultant (see Note 15 of the Combined Notes to Consolidated Financial Statements for more information).

(c)		During the second quarter of 2004, ComEd adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $1 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.


	*Depreciation and Amortization*



	Three Months									Three Months
	Ended March 31,									Ended June 30,

	2004		2003		Variance		% Change			2004		2003		Variance		% Change

Depreciation expense	$	81	$	75	$	6		8.0	%	$	81	$	76	$	5		6.6	%
Recoverable transition costs amortization		11		11		—		—			12		12		—		—
Other amortization expense		10		8		2		25.0	%		10		8		2		25.0	%

Total depreciation and amortization	$	102	$	94	$	8		8.5	%	$	103	$	96	$	7		7.3	%

The increase in depreciation expense is primarily due to ~~higher property, plant and equipment balances.~~capital additions.

115

Recoverable transition costs amortization remained constant in the three months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of ~~$120~~$109 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.


	*Taxes Other Than Income*

Taxes other than income ~~remained constant~~increased for three months ended ~~March 31,~~June 30, 2004 as compared to the same period in ~~2003.~~2003 as a result of a 2003 refund of $5 million for Illinois Electricity Distribution Taxes.


	*Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities*

The aggregate of interest expense ~~interest expense to affiliates~~ and distributions on mandatorily redeemable preferred securities decreased as a result of scheduled principal payments and ~~refinancing existing debt~~refinancings at lower ~~interest~~ rates. Effective December 31, 2003, atupon the adoption of FIN No. 46-R, ComEd deconsolidated its financing trusts (see Note 2 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements). ComEd no longer records distributions on mandatorily redeemable preferred securities but records interest expense to affiliates related to ComEd’s obligations to the financing trusts.


	*Equity in Earnings (Losses) of Unconsolidated Affiliates*

In 2004, ComEd has $3$6 million of equity in net ~~loss~~losses of subsidiaries as a result of deconsolidating its financing trusts.


	*Other, Net*

The change in Other, net is primarily related to the 2003 $2 million gain on sale of non-utility property and $1 million decrease in interest income on the long-term receivable from Unicom Investments, Inc. as a result of a lower principal balance.


	*Income Taxes*

The effective income tax rate was 39% for the three months ended June 30, 2004, compared to 40% for the three months ended June 30, 2003. The decrease in the effective tax rate was primarily attributable to the adoption of FSP FAS 106-2 and other items. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

116


	Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003



			Six Months
			Ended June 30,

			2004			2003			Variance			% Change

Operating revenues			$	2,739		$	2,785		$	(46	)		(1.7	)%
Operating expenses
	Purchased power			1,108			1,110			(2	)		(0.2	)%
	Operating and maintenance			438			483			(45	)		(9.3	)%
	Depreciation and amortization			205			190			15			7.9	%
	Taxes other than income			151			148			3			2.0	%

		Total operating expense		1,902			1,931			(29	)		(1.5	)%

Operating income				837			854			(17	)		(2.0	)%

Other income and deductions
	Interest expense			(202	)		(215	)		13			(6.0	)%
	Distributions on mandatorily redeemable preferred securities			—			(14	)		14			(100.0	)%
	Equity in earnings (losses) of unconsolidated affiliates			(9	)		—			(9	)		n.m.
	Other, net			17			34			(17	)		(50.0	)%

		Total other income and deductions		(194	)		(195	)		1			(0.5	)%

Income before income taxes and cumulative effect of a change in accounting principle				643			659			(16	)		(2.4	)%
Income taxes				255			263			(8	)		(3.0	)%

Net income before cumulative effect of a change in accounting principle				388			396			(8	)		(2.0	)%
Cumulative effect of a change in accounting principle				—			5			(5	)		(100.0	)%

Net income			$	388		$	401		$	(13	)		(3.2	)%

n.m. — not meaningful

117


	*Operating Revenues*

ComEd’s electric sales statistics were as follows:



		Six Months
		Ended June 30,

Retail Deliveries — (in GWhs)		2004		2003		Variance			% Change

Full service(a)
Residential			12,805		12,049		756			6.3	%
Small commercial & industrial			9,924		10,741		(817	)		(7.6	)%
Large commercial & industrial			2,771		3,167		(396	)		(12.5	)%
Public authorities & electric railroads			2,440		2,749		(309	)		(11.2	)%

	Total full service		27,940		28,706		(766	)		(2.7	)%

PPO
Small commercial & industrial			1,600		1,662		(62	)		(3.7	)%
Large commercial & industrial			1,624		2,750		(1,126	)		(40.9	)%
Public authorities & electric railroads			1,012		1,069		(57	)		(5.3	)%

			4,236		5,481		(1,245	)		(22.7	)%

Delivery only(b)
Small commercial & industrial			3,532		2,606		926			35.5	%
Large commercial & industrial			6,031		3,960		2,071			52.3	%
Public authorities & electric railroads			894		529		365			69.0	%

			10,457		7,095		3,362			47.4	%

	Total PPO and delivery only		14,693		12,576		2,117			16.8	%

Total retail deliveries			42,633		41,282		1,351			3.3	%


(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.

(b)		Delivery only service reflects customers receiving electric generation service from an AES.

118



		Six Months
		Ended June 30,

Electric Revenue		2004		2003		Variance			% Change

Full service(a)
Residential		$	1,080	$	1,018	$	62			6.1	%
Small commercial & industrial			769		802		(33	)		(4.1	)%
Large commercial & industrial			131		158		(27	)		(17.1	)%
Public authorities & electric railroads			148		165		(17	)		(10.3	)%

	Total full service		2,128		2,143		(15	)		(0.7	)%

PPO(b)
Small commercial & industrial			108		109		(1	)		(0.9	)%
Large commercial & industrial			92		144		(52	)		(36.1	)%
Public authorities & electric railroads			53		55		(2	)		(3.6	)%

			253		308		(55	)		(17.9	)%

Delivery only(c)
Small commercial & industrial			67		73		(6	)		(8.2	)%
Large commercial & industrial			84		91		(7	)		(7.7	)%
Public authorities & electric railroads			18		17		1			5.9	%

			169		181		(12	)		(6.6	)%

Total PPO and delivery only			422		489		(67	)		(13.7	)%

Total electric retail revenues			2,550		2,632		(82	)		(3.1	)%
Wholesale and miscellaneous revenue(d)			189		153		36			23.5	%

Total electric revenue		$	2,739	$	2,785	$	(46	)		(1.7	)%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.

(b)		Revenue from customers choosing ComEd’s PPO includes an energy charge at market rates, transmission and distribution charges and a CTC charge.

(c)		Delivery only revenue from customers choosing an AES includes a distribution charge and a CTC charge. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from AES were included in wholesale and miscellaneous revenue.

(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue form PJM), sales to municipalities and other wholesale energy sales.

119

The changes in electric retail revenues for the six months ended June 30, 2004, as compared to the same period in 2003, are attributable to the following:


		Variance

Customer choice		$	(107	)
Rate changes			(70	)
Volume			92
Weather			6
Other			(3	)

	Electric retail revenue	$	(82	)

ComEd’s integration into PJM			43
Other			(7	)

	Wholesale and miscellaneous revenue		36

	Electric retail revenue	$	(46	)

Customer Choice. As noted, all ComEd customers have the choice to purchase energy from an AES. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd.

For the six months ended June 30, 2004, the energy provided by AESs was 10,457 GWhs, or 25%, as compared to 7,095 GWhs, or 17%, for the same period in 2003.

The decrease in revenues reflects customers in Illinois electing to purchase energy from an AES or the PPO. As of June 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,400 as compared to 22,000 as of June 30, 2003, representing less than 1% of total customers in each period. MWhs delivered to such customers increased from approximately 12.6 million for the six months ended June 30, 2003 to approximately 14.7 million for six months ended June 30, 2004, or from 30% to 34% of total quarterly retail deliveries.

Rate Changes. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component, decreases the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased by $120 million for the six months ended June 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under ComEd’s PPO by $47 million. For the six months ended June 30, 2004 and June 30, 2003, ComEd collected approximately $87 million and $207 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, and increases in ComEd’s OATT effective May 1, 2004, ComEd anticipates that this revenue source will decline to approximately $180 million for 2004 and range from $100 million to $180 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.

Volume. ComEd’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large commercial and industrial.

Weather. The weather conditions for the six months ended June 30, 2004 were favorable compared to the same period in 2003. Cooling degree-days increased 68% for the six months ended June 30, 2004 compared to the same period in 2003 and were 14% lower than normal. Heating degree-days decreased 8% for the six months ended June 30, 2004 compared to the same period in 2003, and were 4% lower than normal.

ComEd’s Integration into PJM. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.

120


	*Purchased Power*

The decrease in purchased power expense was primarily attributable to a $92 million decrease as a result of customers choosing to purchase energy from an AES and an $8 million decrease due to the mix of average pricing related to ComEd’s PPA with Generation partially offset by an increase of $50 million due to higher volume. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.


	*Operating and Maintenance*

The changes in operating and maintenance expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Charge recorded at ComEd in 2003(a)	$	(41	)
Contractors		(13	)
Decreased payroll expense due to fewer employees(b)		(10	)
Environmental charges		(5	)
Allowance for uncollectible accounts expense		(4	)
Higher corporate allocations(c)		23
Severance, pension and postretirement benefit costs associated with The Exelon Way		9
Tax consultant fees(d)		5
Employee fringe benefits(e)		1
Other		(10	)

Decrease in operating and maintenance expense	$	(45	)


(a)		In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties.

(b)		ComEd has fewer employees as a result of The Exelon Way terminations.

(c)		Higher corporate allocations primarily result from higher corporate governance allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprise companies resulting in ComEd comprising a greater percentage of Exelon.

(d)		ComEd recorded a $5 million charge for contingent fees paid to a tax consultant (see Note 15 to the Combined Notes to Consolidated Financial Statements for more information).

(e)		During the second quarter of 2004, ComEd adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $3 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.


	*Depreciation and Amortization*



	Six Months
	Ended June 30,

	2004		2003		Variance		% Change

Depreciation expense	$	163	$	152	$	11		7.2	%
Recoverable transition costs amortization		23		23		—		—
Other amortization expense		19		15		4		26.7	%

Total depreciation and amortization	$	205	$	190	$	15		7.9	%

The increase in depreciation expense is primarily due to capital additions.

Recoverable transition costs amortization remained constant in the six months ended June 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of $109 million by 2006. Consistent with the provision of the Illinois legislation,

121

regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.


	*Taxes Other Than Income*

Taxes other than income increased for six months ended June 30, 2004 as compared to the same period in 2003 as a result of a 2003 refund of $5 million for Illinois Electricity Distribution taxes.


	*Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities*

The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased as a result of scheduled principal payments and refinancings at lower rates. Effective December 31, 2003, upon the adoption of FIN No. 46-R, ComEd deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). ComEd no longer records distributions on mandatorily redeemable preferred securities, but records interest expense to affiliates related to ComEd’s obligations to the financing trusts. This decrease was offset by $3 million of less allowance for funds used during construction (AFUDC) debt recorded during the six months ended June 30, 2004 as a result of lower construction work in process balances.


	*Equity in Earnings (Losses) of Unconsolidated Affiliates*

In 2004, ComEd has $9 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.


	*Other, Net*

The change in Other, net is primarily related to the reversal of a $12 million reserve for potential plant disallowance in 2003 ~~at ComEd~~ as a result of the Agreement (see ~~Operating~~“Operating and ~~Maintenance~~Maintenance” above)., a reduction in AFUDC equity of $4 million during 2004 as a result of lower construction work in process balances and a $3 million decrease in interest income on the long-term receivable from Unicom Investments, Inc. as a result of a lower principal balance.


	*Income Taxes*

The effective income tax rate was ~~40.3%~~40% for the ~~three~~six months ended ~~March 31,~~June 30, 2004, compared to ~~39.9%~~40% for the ~~three~~six months ended ~~March 31,~~June 30, 2003. The reduction in the effective tax rate is primarily attributable to the adoption of FSP FAS 106-2. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.


	*Cumulative Effect of a Change in Accounting Principle*

On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of $5 million.

Liquidity and Capital Resources

ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. ComEd’s access to external financing at reasonable terms is

dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where ComEd no longer has access to the capital markets at reasonable terms, ComEd has access to a revolving credit facility that ComEd currently utilizes to support its commercial paper program. See the ~~Credit Issues~~“Credit Issues” section of ~~Liquidity~~“Liquidity and Capital ~~Resources~~Resources” for further discussion. Capital resources are used primarily to fund ComEd’s capital requirements, including construction, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans.

122


	*Cash Flows from Operating Activities*

ComEd’s cash flows from operating activities primarily results from sales of electricity to a stable and diverse base of retail customers at fixed prices. ComEd’s future cash flows will be affected by its ability to achieve operating cost reductions and the impact of the economy, weather and customer choice on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements. Operating cash flows after 2006 could be negatively affected by changes in ComEd’s rate regulatory environment, although any effects are not expected to hinder ComEd’s ability to fund its business requirements.

Cash flows from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$299~~$602 million and ~~$36~~$369 million, respectively. Changes in ComEd’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.

In addition to the items mentioned in ~~Results~~“Results of Operations,” ComEd’s operating cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were affected by the following items:

• During the first ~~quarter~~half of 2003, ComEd made additional payments to Generation for amounts owed under the PPA. At ~~March 31,~~June 30, 2004 and December 31, 2003, ComEd had accrued payments due to Generation under the PPA of ~~$152~~$182 million and $171 million, respectively. At ~~March 31,~~June 30, 2003 and December 31, 2002, ComEd had accrued payments due to Generation under the PPA of ~~$154~~$185 million and $339 million, respectively.

• Discretionary contributions by ComEd to Exelon’s defined benefit pension plans were ~~$72~~$144 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~$59~~$117 million for the same period in 2003.

ComEd participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including ~~$17~~$11 million to satisfy IRS minimum funding ~~requirements, of which~~requirements. Of the $419 million, $216 million is expected to be funded by ComEd.

ComEd has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of ~~March 31,~~June 30, 2004, the majority of the deferred tax liabilities related to the fossil plant sale are reflected in ComEd’s Consolidated Balance Sheets with the remainder having been allocated to the Consolidated Balance Sheets of Generation in connection with Exelon’s 2001 corporate restructuring. The total 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. Any required payments could be significant to the cash flows of ComEd. ComEd’s management believes ComEd’s reserve for interest, which has been established in the event that such positions are not sustained, ~~reflects the most likely probable expected outcome~~has been appropriately recorded in accordance with SFAS No. 5. However, the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.


	*Cash Flows from Investing Activities*

Cash flows ~~from~~used in investing activities were ~~$24~~$133 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to cash flows used in investing activities of ~~$169~~$524 million for the same period in 2003. The ~~increase~~change in

cash flows from investing activities was primarily attributable to ~~$179~~$372 million of net proceeds from an investment in the Exelon intercompany money pool and ~~$22~~$36 million of net changes in restricted cash. ComEd’s investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2004 were funded primarily through operating activities.

ComEd’s capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$178~~$369 million and ~~$174~~$355 million, respectively. ComEd estimates that it will spend up to approximately ~~$616~~$715 million in total

123

capital expenditures for 2004. ~~Approximately one half~~This represents an increase of approximately $100 million more than had been previously planned, primarily as a result of expansion of the ~~budgeted 2004 expenditures are for continuing efforts to improve the reliability of its transmission and~~ComEd distribution ~~systems. The remaining amount is for capital additions~~system to support new business and customer growth. Although not anticipated, ComEd ~~anticipates that~~believes it ~~will~~could obtain any needed financing ~~when necessary,~~ through borrowings, the issuance of debt or preferred securities, or capital contributions from Exelon. ComEd’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.


	*Cash Flows from Financing Activities*

Cash flows used in financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2004 were ~~$341~~$476 million as compared to cash flows from financing activities of ~~$149~~$173 million in 2003. The ~~increase~~decrease in cash flows ~~used in~~from financing activities is primarily attributable to ~~net changes in~~the retirement of long-term debt of ~~$592~~$357 million ~~partially offset by~~during the six months ended June 30, 2004 versus the net ~~changes in short-term~~proceeds from the issuance of long-term debt of ~~$26~~$473 million ~~and interest-rate swap settlements of $43 million. Additionally, ComEd paid a $103 million dividend to Exelon during the three months ended March 31, 2004 compared to a $120 million dividend~~ during the same period in 2003. During the six months ended June 30, 2003, ComEd also repaid $71 million of commercial paper and paid $51 million to settle interest-rate swaps. During the six months ended June 30, 2004, ComEd received $26 million from the settlement of interest-rate swaps. Additionally, ComEd paid $207 million in dividends to Exelon during the six months ended June 30, 2004 compared to $211 million in dividends during the same period in 2003.

From time to time and as market conditions warrant, ComEd may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of ComEd’s balance sheet.


	*Credit Issues*

Exelon Credit Facility. ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. ComEd, ~~participates,~~ along with Exelon Corporate, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and ComEd’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”

Capital Structure. ComEd’s capital structure at ~~March 31,~~June 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”

Intercompany Money Pool. A description of the intercompany money pool, and ComEd’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” During the ~~three~~six months ended ~~March 31,~~June 30, 2004, ComEd earned $1$2 million in interest on its investments in the intercompany money pool.

Security Ratings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in the 2003 Form 10-K for a discussion of ComEd’s security ratings.

Shelf Registration. As of ~~March 31,~~June 30, 2004, ComEd has a current shelf registration statement for the sale of $555 million of securities that is effective with the SEC. ComEd’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, ComEd’s current financial condition, its securities ratings and market conditions.

Fund Transfer Restrictions. At ~~March 31,~~June 30, 2004, ComEd had retained earnings of ~~$962~~$1,064 million, of which ~~$891 million~~ had been appropriated for future dividend payments. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd” in the 2003 Form 10-K for information regarding restrictions under ~~Federal~~

124

federal and Illinois law and under the agreements governing ComEd Financing II and III regarding dividend payments by ComEd. ComEd is precluded from lending or extending credit or indemnity to Exelon.


	*Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations*

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. ComEd’s contractual obligations and commercial commitments as of ~~March 31,~~June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

• See Note 79 and Note 19 to the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for discussion of material changes in ComEd’s debt from the amounts set forth in the 2003 Form 10-K.

88125


	PECO ENERGY COMPANY

General

PECO operates in a single business segment, and its operations consist of the regulated sale of electricity and distribution and transmission services in southeastern Pennsylvania and the sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

Executive ~~Summary~~Overview

Financial Results. ~~PECO experienced an overall decline in~~PECO’s net income ofincreased 14% for the three months ended June 30, 2004 as compared to the same period in 2003. This increase reflects higher electric revenues, partially offset by higher operating expenses.

PECO’s net income increased 4% for the six months ended June 30, 2004 as compared to the same period in ~~the first quarter of 2004. This decline was a result of lower electric operating revenues net of purchased power, primarily due to lower full service residential~~2003 and ~~small commercial and industrial sales.~~is generally comparable between periods.

The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO — Executive Summary” in the 2003 Form 10-K for a discussion of PECO’s implementation of ~~the~~The Exelon Way. PECO recorded a severance charge of $5 million associated with the implementation of The Exelon Way for the three months ended March 31, 2004 and is considering whether it will incur additional severance related costs in future periods.

Financing Activities. During the six months ended June 30, 2004, PECO refinanced $75 million of First and Refunding Mortgage Bonds and repaid ~~$88~~$166 million of long-term debt to PECO Energy Transition Trust. PECO met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable ~~future.~~future, absent new acquisitions.

Outlook for the Remainder of 2004 and Beyond. PECO’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO — Executive Summary” in the 2003 Form 10-K.

89126

Results of Operations


	Three Months Ended ~~March 31,~~June 30, 2004 Compared to Three Months Ended ~~March 31,~~June 30, 2003



			Three Months														Three Months
			Ended March 31,														Ended June 30,

			2004			2003			Variance			% Change					2004			2003			Variance			% Change

Operating revenues	Operating revenues		$	1,239		$	1,217		$	22			1.8	%	Operating revenues		$	1,032		$	961		$	71			7.4	%
Operating expenses	Operating expenses														Operating expenses
	Purchased power			396			422			(26	)		(6.2	)%	Purchased power			402			386			16			4.1	%
	Fuel			250			191			59			30.9	%	Fuel			83			67			16			23.9	%
	Operating and maintenance			135			139			(4	)		(2.9	)%	Operating and maintenance			132			121			11			9.1	%
	Depreciation and amortization			125			120			5			4.2	%	Depreciation and amortization			125			116			9			7.8	%
	Taxes other than income			58			63			(5	)		(7.9	)%	Taxes other than income			60			47			13			27.7	%

		Total operating expenses		964			935			29			3.1	%		Total operating expenses		802			737			65			8.8	%

Operating income	Operating income			275			282			(7	)		(2.5	)%	Operating income			230			224			6			2.7	%

Other income and deductions	Other income and deductions														Other income and deductions
	Interest expense			(14	)		(86	)		72			(83.7	)%	Interest expense			(76	)		(83	)		7			(8.4	)%
	Interest expense to affiliates			(63	)		—			(63	)		n.m.		Distributions on mandatorily redeemable preferred securities			—			(2	)		2			(100.0	)%
	Distributions on mandatorily redeemable preferred securities			—			(2	)		2			(100.0	)%	Equity in losses of unconsolidated affiliates			(7	)		—			(7	)		n.m.
	Equity in earnings (losses) of unconsolidated affiliates			(7	)		—			(7	)		n.m.		Other, net			3			1			2			n.m.
	Other, net			2			9			(7	)		(77.8	)%
																Total other income and deductions		(80	)		(84	)		4			(4.8	)%
		Total other income and deductions		(82	)		(79	)		(3	)		3.8	%

Income before income taxes	Income before income taxes			193			203			(10	)		(4.9	)%	Income before income taxes			150			140			10			7.1	%
Income taxes	Income taxes			62			66			(4	)		(6.1	)%	Income taxes			50			52			(2	)		(3.8	)%

Net income	Net income			131			137			(6	)		(4.4	)%	Net income			100			88			12			13.6	%
Preferred stock dividends	Preferred stock dividends			1			2			(1	)		(50.0	)%	Preferred stock dividends			1			2			(1	)		(50.0	)%

Net income on common stock	Net income on common stock		$	130		$	135		$	(5	)		(3.7	)%	Net income on common stock		$	99		$	86		$	13			15.1	%

n.m. — not meaningful

90127


	*Operating Revenue*

PECO’s electric sales statistics were as follows:



		Three Months											Three Months
		March 31,											Ended June 30,

Retail Deliveries — (in GWhs)	Retail Deliveries — (in GWhs)	2004		2003		Variance			% Change			Retail Deliveries — (in GWhs)	2004		2003		Variance			% Change

Full service(a)	Full service(a)											Full service(a)
Residential	Residential		2,744		3,115		(371	)		(11.9	)%	Residential		2,272		2,274		(2	)		(0.1	)%
Small commercial & industrial	Small commercial & industrial		1,684		1,780		(96	)		(5.4	)%	Small commercial & industrial		1,686		1,532		154			10.1	%
Large commercial & industrial	Large commercial & industrial		3,617		3,482		135			3.9	%	Large commercial & industrial		3,703		3,695		8			0.2	%
Public authorities & electric railroads	Public authorities & electric railroads		229		253		(24	)		(9.5	)%	Public authorities & electric railroads		224		222		2			0.9	%

	Total full service		8,274		8,630		(356	)		(4.1	)%	Total full service		7,885		7,723		162			2.1	%

Delivery only(b)	Delivery only(b)											Delivery only(b)
Residential	Residential		582		264		318			120.5	%	Residential		488		186		302			162.4	%
Small commercial & industrial	Small commercial & industrial		424		202		222			109.9	%	Small commercial & industrial		433		323		110			34.1	%
Large commercial & industrial	Large commercial & industrial		150		210		(60	)		(28.6	)%	Large commercial & industrial		190		192		(2	)		(1.0	)%
Public authorities & electric railroads(c)	Public authorities & electric railroads(c)		—		—		—			—		Public authorities & electric railroads(c)		—		—		—			—

	Total delivery only		1,156		676		480			71.0	%	Total delivery only		1,111		701		410			58.5	%

Total retail deliveries	Total retail deliveries		9,430		9,306		124			1.3	%	Total retail deliveries		8,996		8,424		572			6.8	%


(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.

(b)		Delivery only service reflects customers receiving electric generation service from an ~~alternative energy supplier.~~AES.

(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than one GWh per quarter.



		Three Months											Three Months
		Ended March 31,											Ended June 30,

Electric Revenue	Electric Revenue	2004		2003		Variance			% Change			Electric Revenue	2004		2003		Variance			% Change

Full service(a)	Full service(a)											Full service(a)
Residential	Residential	$	314	$	359	$	(45	)		(12.5	)%	Residential	$	298	$	297	$	1			0.3	%
Small commercial & industrial	Small commercial & industrial		176		194		(18	)		(9.3	)%	Small commercial & industrial		197		180		17			9.4	%
Large commercial & industrial	Large commercial & industrial		270		266		4			1.5	%	Large commercial & industrial		281		267		14			5.2	%
Public authorities & electric railroads	Public authorities & electric railroads		20		22		(2	)		(9.1	)%	Public authorities & electric railroads		20		21		(1	)		(4.8	)%

	Total full service		780		841		(61	)		(7.3	)%	Total full service		796		765		31			4.1	%

Delivery only(b)	Delivery only(b)											Delivery only(b)
Residential	Residential		42		17		25			147.1	%	Residential		38		14		24			171.4	%
Small commercial & industrial	Small commercial & industrial		20		10		10			100.0	%	Small commercial & industrial		23		17		6			35.3	%
Large commercial & industrial	Large commercial & industrial		4		6		(2	)		(33.3	)%	Large commercial & industrial		5		5		—			—
Public authorities & electric railroads(c)	Public authorities & electric railroads(c)		—		—		—			—		Public authorities & electric railroads(c)		—		—		—			—

	Total delivery only		66		33		33			100.0	%	Total delivery only		66		36		30			83.3	%

Total electric retail revenues	Total electric retail revenues		846		874		(28	)		(3.2	)%	Total electric retail revenues		862		801		61			7.6	%
Wholesale and miscellaneous revenue(d)	Wholesale and miscellaneous revenue(d)		49		55		(6	)		(10.9	)%	Wholesale and miscellaneous revenue(d)		51		50		1			2.0	%

Total electric revenue	Total electric revenue	$	895	$	929	$	(34	)		(3.7	)%	Total electric revenue	$	913	$	851	$	62			7.3	%


(a)		Full service revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge.

128


(b)		Delivery only revenue reflects revenue from customers receiving generation from an ~~alternative supplier,~~AES, which includes a distribution charge and a CTC charge.

(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than $1 million per quarter.

(d)		Wholesale and miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

The changes in electric retail revenues for the three months ended ~~March 31,~~June 30, 2004, as compared to the same period in 2003, were as follows:


	Variance			Variance

Volume				$	46
Weather					14
Rate mix					12
Rate change					5
Customer choice	$	(26	)		(16	)
Rate mix		(19	)
Weather		(7	)
Volume		20
Rate change		4

Retail revenue	$	(28	)	$	61

~~Customer Choice.~~Volume. ~~All PECO customers may choose~~Exclusive of the effect of weather conditions and customer choice, higher delivery volume related primarily to ~~purchase energy from other suppliers. This choice generally does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.~~

~~For the three months ended March 31, 2004, the energy provided~~increased customer growth and increased usage by alternative suppliers was 1,156 GWhs, or 12.3%, as compared to 676 GWhs, or 7.3%, for the three months ended March 31, 2003. As of March 31, 2004, the number of customers served by alternative suppliers was 302,000, or 19.6%, as compared to 273,700, or 17.9%, as of March 31, 2003. The increase in both the energy provided by alternative suppliers and the number of customers served by alternative suppliers was due to the assignment of customers to alternative suppliers in 2003 as required by the PUC and PECO’s final electric restructuring order.

~~Rate Mix.~~ ~~The decrease in revenues from rate mix was due to changes in monthly usage patterns in~~ all customer ~~classes during the three months ended March 31, 2004 as compared to the same period in 2003.~~classes.

Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather ~~conditions were unfavorable~~impact was favorable compared to the prior ~~year as a result of milder winter weather during the quarter. Heating~~year. Cooling degree-days increased 66% and heating degree-days decreased ~~3% compared to the same period in 2003.~~32%.

~~Volume.~~Rate Mix. ~~Exclusive of the effect of weather conditions and customer choice, higher delivery volume related primarily~~The increase in revenues from rate mix was due to ~~increased~~changes in monthly usage bypatterns in all customer classes.

Rate change. Revenues increased $4$5 million due to a scheduled phase-out of merger-related rate reductions. ~~Under the settlement agreement entered into by PECO in 2000 relating to~~In connection with the PUC’s approval of the merger ~~among~~of PECO, Unicom Corporation, ~~the former parent company of ComEd,~~ and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005.

Customer Choice. All PECO customers may choose to purchase energy from an AES. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.

For the three months ended June 30, 2004, the energy provided by AESs was 1,111 GWhs, or 12%, as compared to 701 GWhs, or 8%, for the three months ended June 30, 2003. As of June 30, 2004, the number of customers served by AESs was 292,100, or 19%, as compared to 125,000, or 8%, as of June 30, 2003. The increases in both the energy provided by AESs and the number of customers served by AESs were due to the assignment of small commercial and industrial customers and residential customers to AESs in May and December 2003, respectively, as required by the PUC and PECO’s final electric restructuring order.

Electric wholesale and miscellaneous revenue ~~decreased $6 million primarily due to lower~~includes PECO’s proportionate share of the transmission ~~revenue from PJM.~~revenues generated by PJM’s control of the PJM network transmission assets, including PECO’s. Additionally, PECO pays PJM for its use of these transmission assets, and this expense is recorded in purchased power.

92129

PECO’s gas sales statistics for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003 were as follows:



	Three Months										Three Months
	Ended March 31,										Ended June 30,

Deliveries to customers (in mmcf)	2004		2003		Variance			% Change			2004		2003		Variance			% Change

Retail sales		29,803		31,460		(1,657	)		(5.3	)%		8,162		9,222		(1,060	)		(11.5	)%
Transportation		7,132		8,166		(1,034	)		(12.7	)%		6,410		5,779		631			10.9	%

Total		36,935		39,626		(2,691	)		(6.8	)%		14,572		15,001		(429	)		(2.9	)%



	Three Months									Three Months
	Ended March 31,									Ended June 30,

Revenue	2004		2003		Variance		% Change			2004		2003		Variance		% Change

Retail sales	$	328	$	273	$	55		20.1	%	$	102	$	99	$	3		3.0	%
Transportation		5		5		—		—			4		4		—		—
Resales and other		11		10		1		10.0	%		13		7		6		85.7	%

Total	$	344	$	288	$	56		19.4	%	$	119	$	110	$	9		8.2	%

The changes in gas retail revenue for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003, were as follows:


	Variance			Variance

Rate changes	$	69		$	13
Volume		(7	)		4
Weather		(7	)		(14	)

Total gas retail revenues	$	55		$	3

Rate Changes. The favorable variance in rates was attributable to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective ~~March 1, 2003, December~~June 1, 2003 and March 1, 2004. The average rate per mmcf for the three months ended ~~March 31,~~June 30, 2004 was ~~43%~~30% higher than the rate for the same period in 2003. PECO’s gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. PECO has asked the PUC for a decrease in its rates through the purchased gas adjustment clause effective December 1, 2004 as a result of lower current gas costs. This proposed decrease would have no impact on PECO’s operating income.

Volume. Exclusive of the effect of weather conditions, revenues were ~~lower in the three months ended March 31, 2004 compared to the same period in 2003~~higher due primarily to ~~decreased~~increased sales in the residential and small commercial and industrial classes.

Weather. The weather conditions were unfavorable compared to the prior ~~year as a result of milder winter weather during the quarter.~~year. Heating degree-days decreased ~~3% compared~~32%.

Resales and other revenue increased $6 million primarily due to ~~the same period in 2003.~~increased off-system sales.


	*Purchased Power*

The ~~decrease~~increase in purchased power expense was attributable to ~~$26~~$16 million of increased sales exclusive of the effect of weather conditions, $14 million of higher prices, and $6 million related to higher sales due to favorable weather conditions, offset by $16 million from customers in Pennsylvania assigned to or selecting an ~~alternative electric generation supplier, $6~~AES and $4 million of lower ~~prices, a $5 million decrease in~~ PJM transmission charges, and a $3 million decrease associated with lower sales due to unfavorable weather conditions, partially offset by an increase of $14 million related to increased sales exclusive of the effect of weather conditions.expense.

130


	*Fuel*

The increase in fuel expense was ~~primarily~~ attributable to ~~$69~~$13 million of higher gas costs, $10 million related to increased off-system sales, and $3 million related to increased sales exclusive of weather conditions, partially offset by a ~~decrease of $7 million related to decreased sales exclusive of the effect of weather conditions and a $4~~$10 million decrease associated with lower sales due to unfavorable weather conditions.


	*Operating and Maintenance*

The ~~decrease~~changes in operating and maintenance expense ~~was primarily attributable to $9 million of lower payroll due to The Exelon Way and $8 million of lower expenses related~~for the three months ended June 30, 2004 compared to the ~~allowance for uncollectible accounts due to increased collection efforts and customer deposits, partially offset by $11 million~~same period in 2003 consisted of higher corporate allocations and $5 million of severance and severance-related costs associated with The Exelon Way. The increase in corporate allocations was driven by payroll expenses and employee fringe benefits resulting from the ~~centralization of certain functions which transferred certain employees from PECO to BSC in 2004.~~following:


	Variance

Higher corporate allocations(a)	$	12
Severance, pension and postretirement benefit costs associated with The Exelon Way		4
Decreased payroll expense due to fewer employees(b)		(4	)
Employee fringe benefits(c)		(5	)
Other		4

Increase in operating and maintenance expense	$	11


(a)		Higher corporate allocations primarily result from a higher percentage allocation to Energy Delivery due to the sales of certain Enterprises businesses.

(b)		PECO has fewer employees as a result of The Exelon Way.

(c)		During the second quarter of 2004, PECO adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $1 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.


	*Depreciation and Amortization*



	Three Months										Three Months
	Ended March 31,										Ended June 30,

	2004		2003		Variance			% Change			2004		2003		Variance		% Change

Competitive transition charge amortization	$	88	$	81	$	7			8.6	%	$	86	$	79	$	7		8.9	%
Depreciation expense		33		33		—			—			33		33		—		—
Other amortization expense		4		6		(2	)		(33.3	)%		6		4		2		50.0	%

Total depreciation and amortization	$	125	$	120	$	5			4.2	%	$	125	$	116	$	9		7.8	%

The additional amortization of the CTC is in accordance with PECO’s original settlement under the Pennsylvania Competition Act.


	*Taxes Other Than Income*

The ~~decrease~~increase in taxes other than income was primarily attributable to $12 million related to the reversal of a use tax accrual resulting from an audit settlement in 2003.


	*Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities*

The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased primarily due to lower outstanding debt and refinancings at lower rates. Effective December 31, 2003, with the adoption of FIN No. 46-R, PECO deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). PECO no longer records distributions on mandatorily redeemable preferred securities of subsidiaries but records interest expense to affiliates related to PECO’s obligations to the financing trusts.

131


	*Equity in Earnings (Losses) of Unconsolidated Affiliates*

In 2004, PECO has $7 million of equity in net losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.


	*Other, Net*

The increase was attributable to a $2 million increase in interest income.


	*Income Taxes*

The effective tax rate was 33% for the three months ended June 30, 2004 as compared to 37% for the same period in 2003. The decrease in the effective tax rate was primarily attributable to plant-related differences. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Results of Operations


	Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003



			Six Months
			Ended June 30,

			2004			2003			Variance			% Change

Operating revenues			$	2,271		$	2,178		$	93			4.3	%
Operating expenses
	Purchased power			799			808			(9	)		(1.1	)%
	Fuel			332			257			75			29.2	%
	Operating and maintenance			266			261			5			1.9	%
	Depreciation and amortization			250			236			14			5.9	%
	Taxes other than income			118			110			8			7.3	%

		Total operating expenses		1,765			1,672			93			5.6	%

Operating income				506			506			—			—

Other income and deductions
	Interest expense			(153	)		(168	)		15			(8.9	)%
	Distributions on mandatorily redeemable preferred securities			—			(5	)		5			(100.0	)%
	Equity in earnings (losses) of unconsolidated affiliates			(13	)		—			(13	)		n.m.
	Other, net			5			10			(5	)		(50.0	)%

		Total other income and deductions		(161	)		(163	)		2			(1.2	)%

Income before income taxes				345			343			2			0.6	%
Income taxes				112			119			(7	)		(5.9	)%

Net income				233			224			9			4.0	%
Preferred stock dividends				2			3			(1	)		(33.3	)%

Net income on common stock			$	231		$	221		$	10			4.5	%

n.m. — not meaningful

132


	*Operating Revenue*

PECO’s electric sales statistics were as follows:



		Six Months
		Ended June 30,

Retail Deliveries — (in GWhs)		2004		2003		Variance			% Change

Full service(a)
Residential			5,016		5,389		(373	)		(6.9	)%
Small commercial & industrial			3,370		3,312		58			1.8	%
Large commercial & industrial			7,320		7,177		143			2.0	%
Public authorities & electric railroads			453		475		(22	)		(4.6	)%

	Total full service		16,159		16,353		(194	)		(1.2	)%

Delivery only(b)
Residential			1,070		450		620			137.8	%
Small commercial & industrial			857		525		332			63.2	%
Large commercial & industrial			340		402		(62	)		(15.4	)%
Public authorities & electric railroads(c)			—		—		—			—

	Total delivery only		2,267		1,377		890			64.6	%

Total retail deliveries			18,426		17,730		696			3.9	%


(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.

(b)		Delivery only service reflects customers receiving electric generation service from an AES.

(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than one GWh per quarter.



		Six Months
		Ended June 30,

Electric Revenue		2004		2003		Variance			% Change

Full service(a)
Residential		$	611	$	656	$	(45	)		(6.9	)%
Small commercial & industrial			374		374		—			—
Large commercial & industrial			551		534		17			3.2	%
Public authorities & electric railroads			40		42		(2	)		(4.8	)%

	Total full service		1,576		1,606		(30	)		(1.9	)%

Delivery only(b)
Residential			80		31		49			158.1	%
Small commercial & industrial			43		27		16			59.3	%
Large commercial & industrial			9		11		(2	)		(18.2	)%
Public authorities & electric railroads(c)			—		—		—			—

	Total delivery only		132		69		63			91.3	%

Total electric retail revenues			1,708		1,675		33			2.0	%
Wholesale and miscellaneous revenue(d)			99		104		(5	)		(4.8	)%

Total electric revenue		$	1,807	$	1,779	$	28			1.6	%


(a)		Full service revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge.

133


(b)		Delivery only revenue reflects revenue from customers receiving generation from an AES, which includes a distribution charge and a CTC charge.

(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than $1 million per quarter.

(d)		Wholesale and miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

The changes in electric retail revenues for the six months ended June 30, 2004, as compared to the same period in 2003, were as follows:


	Variance

Volume	$	66
Rate change		9
Weather		7
Customer choice		(42	)
Rate mix		(7	)

Retail revenue	$	33

Volume. Exclusive of the effect of weather conditions and customer choice, higher delivery volume related primarily to increased customer growth and increased usage by all customer classes.

Rate change. Revenues increased $9 million due to a scheduled phase-out of merger-related rate reductions.

Weather. The weather impact was favorable compared to the prior year. Cooling degree-days increased 66% and heating degree-days decreased 8%.

Customer Choice. As noted, all PECO customers may choose to purchase energy from an AES. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.

For the six months ended June 30, 2004, the energy provided by AESs was 2,267 GWhs, or 12%, as compared to 1,377 GWhs, or 8%, for the six months ended June 30, 2003. As of June 30, 2004, the number of customers served by AESs was 292,100, or 19%, as compared to 125,000, or 8%, as of June 30, 2003. The increases in both the energy provided by AESs and the number of customers served by AESs were due to the assignment of small commercial and industrial customers and residential customers to AESs in May and December 2003, respectively, as required by the PUC and PECO’s final electric restructuring order.

Rate Mix. The decrease in revenues from rate mix was due to changes in monthly usage patterns in all customer classes during the six months ended June 30, 2004 as compared to the same period in 2003.

Electric wholesale and miscellaneous revenue includes PECO’s proportionate share of the transmission revenues generated by PJM’s control of the PJM network transmission assets, including PECO’s. Additionally, PECO pays PJM for its use of these transmission assets, and this expense is recorded in purchased power. Electric wholesale and miscellaneous revenue decreased $5 million primarily due to lower PJM transmission revenue.

PECO’s gas sales statistics for the six months ended June 30, 2004 as compared to the same period in 2003 were as follows:



	Six Months
	Ended June 30,

Deliveries to customers (in mmcf)	2004		2003		Variance			% Change

Retail sales		37,965		40,685		(2,720	)		(6.7	)%
Transportation		13,542		13,942		(400	)		(2.9	)%

Total		51,507		54,627		(3,120	)		(5.7	)%

134



		Six Months
		Ended June 30,

Revenue		2004		2003		Variance		% Change

Retail sales		$	431	$	372	$	59		15.9	%
Transportation			9		9		—		—
Resales and other			24		18		6		33.3	%

	Total	$	464	$	399	$	65		16.3	%

The changes in gas retail revenue for the six months ended June 30, 2004 as compared to the same period in 2003, were as follows:


	Variance

Rate changes	$	82
Weather		(19	)
Volume		(4	)

Total gas retail revenues	$	59

Weather. The weather conditions were unfavorable compared to the prior year. Heating degree-days decreased 8% compared to the same period in 2003.

Volume. Exclusive of the effect of weather conditions, revenues were lower in the six months ended June 30, 2004 compared to the same period in 2003 due primarily to decreased sales in the residential and small commercial and industrial classes.

Resales and other revenue increased $6 million primarily due to increased off-system sales.


	*Purchased Power*

The decrease in purchased power expense was attributable to $42 million from customers in Pennsylvania assigned to or selecting an AES and a $9 million decrease in PJM transmission expense, partially offset by an increase of $31 million related to increased sales exclusive of weather conditions, $8 million of higher prices, and a $3 million increase associated with higher sales due to favorable weather conditions.


	*Fuel*

The increase in fuel expense was attributable to $82 million of higher gas costs and $13 million related to increased off-system sales, partially offset by a $16 million decrease associated with lower sales due to unfavorable weather conditions and a decrease of $4 million related to decreased sales exclusive of the effect of weather conditions.

135


	*Operating and Maintenance*

The changes in operating and maintenance expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Higher corporate allocations(a)	$	19
Severance, pension and postretirement benefit costs associated with The Exelon Way		10
Decreased payroll expense due to fewer employees(b)		(11	)
Employee fringe benefits(c)		(4	)
Allowance for uncollectible accounts expense		(2	)
Other		(7	)

Increase in operating and maintenance expense	$	5


(a)		Higher corporate allocations primarily result from a higher percentage allocation to Energy Delivery due to the sales of certain Enterprises businesses.

(b)		PECO has fewer employees as a result of The Exelon Way terminations.

(c)		During the second quarter of 2004, PECO adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $2 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.


	*Depreciation and Amortization*



	Six Months
	Ended June 30,

	2004		2003		Variance		% Change

Competitive transition charge amortization	$	174	$	161	$	13		8.1	%
Depreciation expense		66		66		—		—
Other amortization expense		10		9		1		11.1	%

Total depreciation and amortization	$	250	$	236	$	14		5.9	%

The additional amortization of the CTC is in accordance with PECO’s original settlement under the Pennsylvania Competition Act.


	*Taxes Other Than Income*

The increase in taxes other than income was primarily attributable to $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $6 million of lower capital stock ~~tax and $1 million related to lower payroll taxes.~~tax.


	*Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities*

The aggregate of interest expense ~~interest expense to affiliates~~ and distributions on mandatorily redeemable preferred securities decreased primarily due to lower outstanding debt and ~~refinancing existing debt~~refinancings at lower rates. Effective December 31, 2003, atwith the adoption of FIN No. 46-R, PECO deconsolidated its financing trusts (see Note 2 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements). PECO no longer records distributions on mandatorily redeemable preferred securities of subsidiaries but records interest expense to affiliates related to PECO’s obligations to the financing trusts.


	*Equity in Earnings (Losses) of Unconsolidated Affiliates*

In 2004, PECO ~~has $7~~recorded $13 million ~~in the~~of equity in net ~~loss~~losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.

136


	*Other, Net*

The decrease was attributable to a $4$2 million decrease in interest income and a $3$4 million favorable settlement of a customer contract in 2003.


	*Income Taxes*

The effective tax rate was ~~32.1%~~33% for the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to ~~32.5%~~35% for the same period in 2003. The decrease in the effective tax rate was primarily attributable to plant-related differences. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Liquidity and Capital Resources

PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent

necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility that PECO currently utilizes to support its commercial paper program. See the ~~Credit Issues~~“Credit Issues” section of ~~Liquidity~~“Liquidity and Capital ~~Resources~~Resources” for further discussion. Capital resources are used primarily to fund PECO’s capital requirements, including construction, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans.


	*Cash Flows from Operating Activities*

PECO’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices. PECO’s future cash flows will be affected by its ability to achieve operating cost reductions and the impact of the economy and weather on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements for the foreseeable future.

Cash flows from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$218~~$509 million and ~~$96~~$425 million, respectively. Changes in PECO’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.

In addition to the items mentioned in ~~Results~~“Results of Operations,” PECO’s operating cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were affected by the following items:

• ~~Natural gas inventories and deferred~~Deferred natural gas costs decreased ~~$30~~$56 million ~~and $70 million, respectively,~~ during the ~~three~~six months ended ~~March 31,~~June 30, 2004 resulting in ~~a $100 million~~an increase to operating cash flows. During 2003, ~~a decrease in natural gas inventories of $45 million partially offset by~~ an increase in deferred natural gas costs of ~~$28~~$24 million resulted in a decrease to operating cash flows. PECO’s gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from ~~operations~~or refund to customers the difference between the actual cost of ~~$17 million.~~purchased gas and the amount included in rates. During 2004, PECO was recovering fuel revenues from customers in excess of gas costs being incurred. During 2003, PECO was incurring gas costs in excess of fuel revenues being recovered from customers.

• Discretionary contributions by PECO to Exelon’s defined benefit pension plans were $3$5 million during the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to $6$12 million for the same period in 2003.

PECO participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including ~~$17~~$11 million to satisfy IRS minimum funding ~~requirements, of which~~requirements. Of the $419 million, $8 million is expected to be funded by PECO.

137


	*Cash Flows from Investing Activities*

Cash flows used in investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$48~~$137 million ~~compared to $77~~and $98 million, ~~of cash flows provided by investing activities in 2003.~~respectively. The ~~decrease~~$39 million increase in cash ~~flows~~ used in investing activities was primarily attributable to a $35 million investment in the Exelon intercompany money pool in 2004 and a change in restricted cash which provided cash flows of ~~$136~~$28 million ~~and a decrease~~ in ~~capital~~2003, partially offset by lower construction expenditures of ~~$17 million.~~$27 million in 2004. PECO’s investing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2004 were funded ~~primarily~~ by operating activities.

PECO’s projected capital expenditures for 2004 are $233 million. Approximately 60% of the budgeted 2004 expenditures are for additions to or upgrades of existing facilities, including reliability improvements. The remainder of the capital expenditures support customer and load growth. PECO anticipates that it will obtain financing, when necessary, through borrowings, the issuance of preferred securities, or capital contributions from Exelon. PECO’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.


	*Cash Flows from Financing Activities*

Cash flows used in financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2004 were ~~$107~~$317 million compared to ~~$132~~$329 million for the same period in 2003. ~~Cash flows used in financing activities are primarily attributable to debt service and payment of dividends to Exelon.~~ The decrease in cash flows used in financing

activities ~~was~~is primarily ~~attributable~~due to ~~decreased debt redemptions~~a decrease in the retirement of ~~$276~~preferred securities of $100 million and an increase in contributions received from Exelon of $54 million, partially offset by ~~decreased issuances~~an increase in net retirements of long-term debt of ~~$250~~$124 million. Additionally, PECO paid dividends of ~~$91~~$182 million and $168 during the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003, respectively, of which ~~$90~~$180 million and ~~$89~~$165 million, respectively, were common dividends paid to Exelon.

From time to time and as market conditions warrant, PECO may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of PECO’s balance sheet.


	*Credit Issues*

Exelon Credit Facility. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. PECO participates, along with Exelon Corporate, ComEd and Generation, in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and PECO’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”

Capital Structure. PECO’s capital structure at ~~March 31,~~June 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”

Intercompany Money Pool.A description of the intercompany money pool, and PECO’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” During the ~~three~~six months ended ~~March 31,~~June 30, 2004, PECO earned less than $1 million in interest from its investments in the intercompany money pool.

Security Ratings. ~~See “Management’s Discussion~~PECO’s access to the capital markets, including the commercial paper market, and ~~Analysis~~its financing costs in those markets depend on the securities ratings of ~~Financial Condition and Results of Operations — Liquidity and Capital Resources” in~~ the ~~2003 Form 10-K for a discussion~~entity that is accessing the capital markets. On July 22, 2004, Standard & Poor’s Ratings Services lowered the ratings on PECO’s First Mortgage Bonds from A to A-. None of PECO’s ~~security ratings.~~other securities ratings has changed. None of PECO’s borrowings is subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under Exelon’s credit facilities.

138

Shelf Registration. As of ~~March 31,~~June 30, 2004, PECO has a current shelf registration statement for the sale of ~~$625~~$550 million of securities that is effective with the SEC. PECO’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, PECO’s current financial condition, its securities ratings and market conditions.

Fund Transfer Restrictions. At ~~March 31,~~June 30, 2004, PECO had retained earnings of ~~$586~~$597 million. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO” in the 2003 Form 10-K for information regarding fund transfer restrictions.


	*Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations*

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. PECO’s contractual obligations and commercial commitments as of ~~March 31,~~June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

• See Note 179 and 19 to the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for discussion of material changes in PECO’s debt from the amounts set forth in the 2003 Form 10-K.

96139

EXELON GENERATION COMPANY, LLC

General

Generation operates as a single segment and consists of electric generating facilities, energy marketing operations, a 50% interest in Sithe and, effective January 1, 2004, the competitive retail sales business of Exelon Energy Company.

Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. Generation’s results of operations have not been adjusted to reflect Exelon Energy Company as a part of Generation for 2003. Exelon Energy ~~Company reported the following~~Company’s results for the three and six months ended ~~March 31, 2003:~~June 30, 2003 were as follows:


				Three Months		Six Months
				Ended June 30,		Ended June 30,
				2003		2003

Total revenues	$	330		$	174	$	504
Intersegment revenues		6			2		9
Income (loss) before income taxes		(16	)		1		(16	)
Income taxes (benefit)		(6	)		1		(6	)
Net income (loss)		(10	)		—		(10	)

Executive ~~Summary~~Overview

Financial Results. Generation reported an overall increase in net income of $36 million for the ~~first~~ quarter ofended June 30, 2004 as compared to the ~~first~~prior year, due primarily to the gain of $52 million, net of income taxes, recorded on the sale of Boston Generating, partially offset by operating net losses of $10 million for Boston Generating, incurred during the second quarter of 2004. Generation reported an overall increase in net income of $83 million for the six months ended June 30, 2004 as compared to the same period in 2003. This increase was primarily attributable to a gain of $52 million, net of income taxes, recorded on the ~~result~~sale of Boston Generating, partially offset by operating net losses of $28 million for Boston Generating incurred during the first ~~quarter 2003 $200~~five months of 2004, $43 million ~~impairment charge~~attributable to the incremental results of ~~Generation’s investment~~AmerGen, Exelon Energy and Sithe and $32 million of net income for the cumulative effect of a change in ~~Sithe. Overall~~accounting principle. Generation also experienced improved results ~~were also affected by modest improvements in wholesale energy prices in 2004, which~~due to increased ~~Generation’s energy margins. Generation’s revenue, net of purchased power and fuel, increased significantly in 2004 as compared to 2003, primarily~~realized margins as a result of its successful forward hedging strategy and increased market prices. Generation’s results of operations for the ~~acquisition~~six months ended June 30, 2003 included the pre-tax impairment charge on Generation’s investment in Sithe of $200 million and a $108 million net gain resulting from the ~~remaining 50%~~cumulative effect of ~~AmerGen~~a change in December 2003, the transfer of Exelon Energy Company to Generation on January 1, 2004 and the commencement of commercial operations at Boston Generating’s Mystic 8 and 9 and Fore River generating facilities after the first quarter of 2003. In 2004, Generation recorded an after-tax gain of $32 million due toaccounting principle for the adoption of FIN No. 46-R, which resulted in the consolidation of Sithe within Generation’s financial statements as of March 31, 2004, compared to an after-tax gain of $108 million recorded in 2003 upon the adoption of SFAS ~~No.~~ 143.

The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation — Executive Summary” in the 2003 Form 10-K for a discussion of Generation’s implementation of The Exelon Way. ~~Generation released related reserves of $6 million during the first quarter of 2004. Based upon current estimates, Generation expects that 513 employees will be severed through 2004.~~

~~Investment Strategy.~~Divestiture Activities. During the second quarter, Generation ~~continues to follow a disciplined approach in investing to maximize the earnings and cash flows from its assets and businesses and to sell those that do not meet its goals.~~

~~On February 23, 2004, Generation and the lenders under the Boston Generating Facility entered into a settlement that will result in~~completed the sale and transfer of the assets of Boston Generating ~~which owns the companies that own the Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, and the transfer of responsibility for plant operations and power marketing activities~~ to a special purpose entity ~~owned~~formed by the ~~lenders. Generation also settled certain litigation associated~~lenders of the Boston Generating credit facility.

In connection with the ~~projects. Upon entering into the sale agreement with the lenders, the~~consolidation of Sithe, Generation recorded assets ~~and liabilities of Boston Generating were classified as~~ held for sale ~~within~~related to Sithe’s investments in certain hydroelectric facilities. At June 30, 2004, Generation’s ~~Consolidated Balance Sheet.~~consolidated balance sheets reflect $9 million of assets, and $3 million of liabilities held for sale related to these investments. Generation continues to explore various transactional strategies related to its investment in Sithe.

Financing Activities. ~~During the first quarter,~~On June 30, 2004, Generation ~~issued $165~~had $211 million of commercial paper outstanding and $198 million in outstanding money pool loans to fund ~~operations, however, following~~operations. Also, Generation increased its distributions to Exelon by approximately $64 million during the ~~sale~~first six months of ~~Boston Generating,~~2004 compared to the same period in the prior year. Generation ~~expects~~continues to meet ~~all of~~ its capital resource commitments with internally generated cash ~~for~~and expects to do so in the foreseeable future, absent new ~~acquisitions~~acquisitions.

140

Operations. Generation’s nuclear fleet achieved a ~~90.5%~~93.3% capacity factor induring the ~~first quarter of~~six months ended June 30, 2004 compared to ~~94.4%~~94.2% during the same period in ~~the first quarter of~~ 2003, primarily as a result of an increased number of planned outages ~~and outage days~~ in 2004 as compared to 2003. Generation ~~continued~~anticipates transferring plant operations and power marketing activities of Boston Generating to a special purpose entity designated by the ~~integration~~lenders of the ~~AmerGen fleet into~~

~~Generation, following~~Boston Generating credit facility during the ~~2003 acquisition~~third quarter of ~~the remaining 50% interest in the venture, which was previously held by British Energy plc (British Energy).~~

2004.

Outlook for the Remainder of 2004 and Beyond. Generation’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation — Executive Summary” in the 2003 Form 10-K.

Results of Operations


	Three Months Ended ~~March 31,~~June 30, 2004 Compared to Three Months Ended ~~March 31,~~June 30, 2003



			Three Months														Three Months
			Ended March 31,														Ended June 30,

			2004			2003			Variance			% Change					2004			2003			Variance			% Change

Operating revenues	Operating revenues		$	1,953		$	1,879		$	74			3.9	%	Operating revenues		$	1,948		$	1,886		$	62			3.3	%
Operating expenses	Operating expenses														Operating expenses
	Purchased power			519			841			(322	)		(38.3	)%	Purchased power			563			800			(237	)		(29.6	)%
	Fuel			586			364			222			61.0	%	Fuel			462			348			114			32.8	%
	Operating and maintenance			652			487			165			33.9	%	Operating and maintenance			623			451			172			38.1	%
	Depreciation and amortization			55			45			10			22.2	%	Depreciation and amortization			69			46			23			50.0	%
	Taxes other than income			47			48			(1	)		(2.1	)%	Taxes other than income			48			40			8			20.0	%

		Total operating expenses		1,859			1,785			74			4.1	%		Total operating expenses		1,765			1,685			80			4.7	%

Operating income	Operating income			94			94			—			—		Operating income			183			201			(18	)		(9.0	)%

Other income and deductions	Other income and deductions														Other income and deductions
	Interest expense			(26	)		(19	)		(7	)		36.8	%	Interest expense			(51	)		(20	)		(31	)		155.0	%
	Equity in earnings (losses) of unconsolidated affiliates			(2	)		19			(21	)		(110.5	)%	Equity in earnings of unconsolidated affiliates			—			18			(18	)		(100.0	)%
	Other, net			47			(167	)		214			(128.1	)%	Other, net			134			34			100			n.m.

		Total other income and deductions		19			(167	)		186			(111.4	)%		Total other income and deductions		83			32			51			159.4	%

Income (loss) before income taxes				113			(73	)		186			n.m.
Income tax expense (benefit)				46			(21	)		67			n.m.
Income before income taxes and minority interest															Income before income taxes and minority interest			266			233			33			14.2	%
Income taxes															Income taxes			100			91			9			9.9	%

Income (loss) before cumulative effect of changes in accounting principles				67			(52	)		119			n.m.
Cumulative effect of changes in accounting principles, net of income taxes				32			108			(76	)		(70.4	)%
Income before minority interest															Income before minority interest			166			142			24			16.9	%
Minority interest															Minority interest			12			—			12			n.m.

Net income	Net income		$	99		$	56		$	43			76.8	%	Net income		$	178		$	142		$	36			25.4	%

n.m. — not meaningful

98141


	*Operating Revenues*

For the three months ended ~~March 31,~~June 30, 2004 and 2003, Generation’s sales were as follows:



	Three Months											Three Months
	Ended March 31,											Ended June 30,

Revenue	2004		2003			Variance			% Change			2004			2003			Variance			% Change

Energy Delivery and Exelon Energy Company(a)	$	860	$	965		$	(105	)		(10.9	)%
Market and retail electric sales(b)		884		857			27			3.2	%
Electric sales to affiliates(a)												$	846		$	877		$	(31	)		(3.5	)%
Wholesale and retail electric sales(b)													858			897			(39	)		(4.3	)%

Total electric energy sales revenue		1,744		1,822			(78	)		(4.3	)%		1,704			1,774			(70	)		(3.9	)%

Retail gas sales		176		—			176			n.m.			84			—			84			n.m.
Trading portfolio		—		(1	)		1			(100.0	)%		(2	)		(1	)		(1	)		100.0	%
Other revenue(c)		33		58			(25	)		(43.1	)%		162			113			49			43.4	%

Total revenue	$	1,953	$	1,879		$	74			3.9	%	$	1,948		$	1,886		$	62			3.3	%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

(c)		Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

n.m. — not meaningful



	Three Months
	Ended June 30,

Sales (in GWhs)	2004(c)		2003		Variance			% Change

Sales to affiliates(a)		26,133		26,869		(736	)		(2.7	)%
Wholesale and retail electric sales(b)		24,976		27,449		(2,473	)		(9.0	)%

Total sales		51,109		54,318		(3,209	)		(5.9	)%


~~n.m. —~~	~~not meaningful~~

Three Months
Ended,
Sales (in GWhs) 2004^(c) 2003 Variance % Change
Energy Delivery and Exelon Energy Company(a) 27,464 30,594 (3,130 ) (10.2 )%
Market and retail electric sales(b) 23,983 23,815 168 0.7 %

Total sales 51,447 54,409 (2,962 ) (5.4 )%

(a) Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b) Includes retail electric sales of Exelon Energy Company in 2004.

(c) Sales in 2004 do not include ~~5,453~~6,185 GWhs, which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11.

Trading volumes of ~~5,113~~5,324 GWhs and ~~9,527~~7,919 GWhs for the three months ended ~~March 31,~~June 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

142

Generation’s average margin and other operating data for the three months ended ~~March 31,~~June 30, 2004 and 2003 are as follows:



		Three Months								Three Months
		Ended March 31,								Ended June 30,

($/MWh)	($/MWh)	2004		2003		% Change			($/MWh)	2004		2003		% Change

Average revenue	Average revenue								Average revenue
	Energy Delivery and Exelon Energy Company(a)	$	31.31	$	31.54		(0.7	)%	Electric sales to affiliates(a)	$	32.37	$	32.64		(0.8	)%
	Market and retail electric sales(b)		36.86		35.99		2.4	%	Wholesale and retail electric sales(b)		34.35		32.68		5.1	%
	Total — excluding the trading portfolio		33.90		33.49		1.2	%	Total — excluding the trading portfolio		33.34		32.66		2.1	%
Average supply cost(c) — excluding the trading portfolio	Average supply cost(c) — excluding the trading portfolio	$	21.48	$	22.06		(2.6	)%	Average supply cost(c) — excluding the trading portfolio	$	20.06	$	21.13		(5.1	)%
Average margin — excluding the trading portfolio	Average margin — excluding the trading portfolio	$	12.42	$	11.43		8.7	%	Average margin — excluding the trading portfolio	$	13.28	$	11.53		15.2	%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail sales.

(b) Includes retail electric sales of Exelon Energy Company in 2004.

(c) Average supply cost includes purchased power, fuel costs, and PPAs with AmerGen in 2003.

~~Market and Retail Electric Sales.~~ ~~Market and retail electric sales increased $40 million~~The changes in Generation’s operating revenues for the three months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 ~~primarily resulting from~~consisted of the following:

Variance
Effects of EITF 03-11 adoption $ (206 )
Boston Generating 117
Exelon Energy Company and AmerGen operations 78
Other operations 51

Increase in market and retail electric sales $ 40


	Variance

Retail gas revenue	$	84
Wholesale and retail electric sales		(39	)
Electric revenue from affiliates		(31	)
Other		48

Increase in operating revenues	$	62

Retail Gas ~~Sales.~~Revenue. Retail gas revenue increased ~~$176~~$84 million as a result of the transfer of Exelon Energy Company ~~retail operations, which were not included in Generation’s financial results in 2003.~~to Generation as of January 1, 2004.

~~Energy Delivery~~Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the three months ended June 30, 2004 compared to the same period in 2003, consisted of the following:


	Variance

Effects of EITF 03-11 adoption(a)	$	(238	)
Boston Generating		(43	)
Exelon Energy Company and AmerGen operations		104
Other operations		138

Decrease in wholesale and retail electric sales	$	(39	)


(a)		Does not include $1 million of EITF 03-11 adjustments related to fuel sales that are included in other revenues.

As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The sale of Boston Generating in May 2004 resulted in less revenues from this entity compared to the same period in the prior year. The acquisition of Exelon Energy ~~Company.~~and AmerGen resulted in increased market and retail electric sales of approximately $104 million compared to the same period in the prior year.

143

Electric Sales to Affiliates. AsRevenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy ~~Company’s assets and operations being transferred~~Company to Generation effective January 1, ~~2004, sales~~2004. Sales to Exelon Energy Company are no longer reported as affiliate ~~revenue.~~revenue by Generation. Revenue from sales to Exelon Energy Company for the three months ended ~~March 31,~~June 30, 2003 was ~~$64~~$44 million.

~~Revenue~~The decrease in revenue from sales to affiliates ~~decreased primarily due~~was partially offset by $15 million in higher sales to ~~lower volume~~Energy Delivery. The higher sales to Energy Delivery ~~of $55 million~~were primarily due to ~~customers electing to purchase energy from alternative electric suppliers or ComEd’s PPO~~an overall increased usage per customer and ~~unfavorable~~favorable weather conditions in the ComEd and PECO service territories. Price increases in the PECO region, partially offset by minimal price decreases in the ComEd region, resulted in a $5 million increase in affiliate revenue.conditions.

Other. ~~Revenues decreased~~Certain other revenues increased for the three months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003, primarily due to a $10 million decrease in fuel sales which is due primarily to gas sales in 2003 to Exelon Energy Company which is consolidated in 2004, as well as decreased coal sales year over year due to fewer coal contracts; and the ~~effects~~consolidation of ~~adopting EITF 03-11, which calls for fuel expense to offset revenue derived from certain fossil fuel transactions. See Note 2~~Sithe’s results of the Condensed Combined Notes to Consolidated Financial Statements for additional information regarding EITF 03-11. As a result, revenues and fuel expense were lowered by $7 million, of which $5 million was related to Boston Generating operations.operations beginning April 1, 2004.


	*Purchased Power and Fuel*

Generation’s supply source is summarized below:



	Three Months										Three Months
	Ended March 31,										Ended June 30,

Supply Source (in GWhs)	2004^(c)		2003		Variance			% Change			2004		2003		Variance			% Change

Nuclear generation(a)		33,411		29,330		4,081			13.9	%		34,254		29,619		4,635			15.6	%
Purchases — non-trading portfolio(b)		11,691		20,029		(8,338	)		(41.6	)%		11,904		19,344		(7,440	)		(38.5	)%
Fossil and hydro generation		6,345		5,050		1,295			25.6	%		4,951		5,355		(404	)		(7.5	)%

Total supply		51,447		54,409		(2,962	)		(5.4	)%		51,109		54,318		(3,209	)		(5.9	)%


(a)		Excludes AmerGen for 2003. AmerGen generated 5,122 GWhs during the three months ended June 30, 2004.

(b)		Sales in 2004 do not include 6,185 GWhs that were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 3,731 GWhs in 2003.

Generation’s supply mix changed as a result of the sale of Boston Generating in May 2004.


	Variance

Effects of the adoption of EITF 03-11	$	(239	)
Volume		92
Price		49
Boston Generating		(33	)
Midwest Generation		(25	)
AmerGen and Exelon Energy Company		(11	)
Sithe Energies, Inc.		62
Mark-to-market adjustments on hedging activity		11
Other		(29	)

Decrease in purchased power and fuel expense	$	(123	)

Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $238 million and fuel expense of $1 million.

Price. The increase reflects higher market energy prices due to increased natural gas, oil and coal prices.

144

Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004.

AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $97 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $86 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results.

Hedging Activity. Mark-to-market gains on hedging activities were $21 million for the three months ended June 30, 2004 compared to gains of $32 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $6 million and hedging activities relating to other Generation operations in 2004 accounted for a gain of $15 million.


	*Operating and Maintenance*

The changes in operating and maintenance expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

AmerGen and Exelon Energy Company	$	87
Sithe Energies, Inc.		22
Decommissioning accretion costs(a)		18
Boston Generating		13
Pension, payroll and benefit costs, primarily associated with The Exelon Way		(14	)
Other		46

Increase in operating and maintenance expense	$	172


(a)		Includes $10 million due to AmerGen asset retirement obligation accretion.

The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen, Exelon Energy Company and Sithe in Generation’s consolidated results for 2004. The increase in operating and maintenance expenses attributable to Boston Generating was due to Mystic 8 and 9 and Fore River commencing commercial operation at the end of the second quarter of 2003 and in the third quarter of 2003, respectively, which more than offset the reduction in operating and maintenance expenses resulting from their sale in May 2004. Decommissioning accretion costs increased primarily due to the inclusion of AmerGen in this period compared to the prior year. The reduction in payroll-related costs associated with the implementation of the programs associated with The Exelon Way partially offset the other increases to operating and maintenance expense.

145

Nuclear fleet operating data and purchased power costs data for the three months ended June 30, 2004 and 2003 were as follows:



	Three Months
	Ended June 30,

	2004			2003

Nuclear fleet capacity factor(a)		96.1	%		94.0	%
Nuclear fleet production cost per MWh(a)	$	10.88		$	12.08
Average purchased power cost for wholesale operations per MWh(b)	$	47.13		$	41.36


(a)		Includes AmerGen and excludes Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G).

(b)		Includes PPAs with AmerGen in 2003.

In the three months ended June 30, 2004 as compared to the three months ended June 30, 2003, the Quad Cities units operated at pre-EPU generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.


	*Depreciation and Amortization*

The increase in depreciation and amortization expense for the three months ended June 30, 2004 as compared to the same period in 2003 includes the impact of capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities as the assets were classified as held for sale during the period.


	*Interest Expense*

The increase in interest expense was primarily due to the issuance of $500 million of Senior Notes in December 2003 and interest expense related to Sithe long-term debt.


	*Equity in Earnings (Losses) of Unconsolidated Affiliates*

The decrease in equity in earnings of unconsolidated affiliates was primarily due to a $20 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of Generation’s purchase of British Energy’s 50% interest in AmerGen.

146


	*Other, Net*

The components of other, net for the three months ended June 30, 2004 as compared to the same period in the prior year, are as follows:



	Three Months
	Ended June 30,

Other, Net	2004		2003		Variance			% Change

Gain on sale of Boston Generating(a)		85		—		85			n.m.
Decommissioning trust funds(b)		29		32		(3	)		(9.4	)%
Decommissioning trust funds — AmerGen(b)		9		—		9			n.m.
Other income from Sithe		9		—		9			n.m.
Other		2		2		—			—

Total		134		34		100			n.m.

(a) ~~Excludes AmerGen~~See Note 3 of the Combined Notes to the Consolidated Financial Statements for further discussion of Generation’s sale of Boston Generating.

(b) Includes investment income and realized gains/(losses).

n.m. — not meaningful


	*Effective Income Tax Rate*

The effective income tax rate was 38% for the three months ended June 30, 2004 compared to 39% for the same period in 2003. This decrease was primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe that resulted in a pre-tax loss. In addition, the rate increased due to the additional nuclear decommissioning investment income associated with AmerGen and its related taxes. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

147

Results of Operations


	Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003



			Six Months Ended
			June 30,

			2004			2003			Variance			% Change

Operating revenues			$	3,900		$	3,765		$	135			3.6	%
Operating expenses
	Purchased power			1,081			1,642			(561	)		(34.2	)%
	Fuel			1,048			706			342			48.4	%
	Operating and maintenance			1,273			943			330			35.0	%
	Depreciation and amortization			124			91			33			36.3	%
	Taxes other than income			95			88			7			8.0	%

		Total operating expenses		3,621			3,470			151			4.4	%

Operating income				279			295			(16	)		(5.4	)%

Other income and deductions
	Interest expense			(77	)		(38	)		(39	)		(102.6	)%
	Equity in earnings (losses) of unconsolidated affiliates			(2	)		37			(39	)		(105.4	)%
	Other, net			183			(132	)		315			n.m.

		Total other income and deductions		104			(133	)		237			178.2	%

Income before income taxes, minority interest and cumulative effect of changes in accounting principles				383			162			221			136.4	%
Income taxes				146			71			75			105.6	%

Income before minority interest and cumulative effect of changes in accounting principles				237			91			146			160.4	%
Minority interest				11			(2	)		13			n.m.

Income before cumulative effect of changes in accounting principles				248			89			159			178.7	%
Cumulative effect of changes in accounting principles, net of income taxes				32			108			(76	)		(70.4	)%

Net income			$	280		$	197		$	83			42.1	%

n.m. — not meaningful

148


	*Operating Revenues*

For the six months ended June 30, 2004 and 2003, Generation’s sales were as follows:



	Six Months Ended
	June 30,

Revenue	2004			2003			Variance			% Change

Electric sales to affiliates(a)	$	1,706		$	1,842		$	(136	)		(7.4	)%
Wholesale and retail electric sales(b)		1,742			1,754			(12	)		(0.7	)%

Total electric energy sales revenue		3,448			3,596			(148	)		(4.1	)%

Retail gas sales		260			—			260			n.m.
Trading portfolio		(2	)		(2	)		—			—
Other revenue(c)		194			171			23			13.5	%

Total revenue	$	3,900		$	3,765		$	135			3.6	%


(a)		Includes sales to Exelon Energy Company during 2003. ~~AmerGen generated 4,639 GWhs during the three months ended March 31,~~As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

~~(b)~~ (c)		Includes ~~PPAs with AmerGen, which represented 2,488 GWhs~~sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

n.m. — not meaningful



	Six Months Ended
	June 30,

Sales (in GWhs)	2004		2003		Variance			% Change

Electric sales to affiliates(a)		53,597		57,463		(3,866	)		(6.7	)%
Wholesale and retail electric sales(b)		48,959		51,264		(2,305	)		(4.5	)%

Total sales		102,556		108,727		(6,171	)		(5.7	)%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

~~(c)~~ (b)		Sales in 2004 do not include ~~5,453~~11,638 GWhs which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes retail electric sales of Exelon Energy Company in 2004.

~~100~~ Trading volumes of 10,437 GWhs and 17,446 GWhs for the six months ended June 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

149

Generation’s average margin and other operating data for the six months ended June 30, 2004 and 2003 are as follows:



		Six Months Ended
		June 30,

($/MWh)		2004		2003		% Change

Average revenue
	Electric sales to affiliates(a)	$	31.83	$	32.06		(0.7	)%
	Wholesale and retail electric sales(b)		35.58		34.22		4.0	%
	Total — excluding the trading portfolio		33.62		33.07		1.7	%
Average supply cost(c) — excluding the trading portfolio		$	20.77	$	21.60		(3.8	)%
Average margin — excluding the trading portfolio		$	12.85	$	11.47		12.0	%


(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail sales.

(b)		Includes retail electric sales of Exelon Energy Company in 2004.

(c)		Average supply cost includes purchased power, fuel costs, and PPAs with AmerGen in 2003.

The changes in Generation’s operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance

Retail gas revenue	$	260
Electric sales to affiliates		(136	)
Wholesale and retail electric sales		(12	)
Other		23

Increase in operating revenues	$	135

Retail Gas Revenue. Retail gas revenue increased as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the six months ended June 30, 2004 compared to the same period in 2003, consisted of the following:


	Variance

Effects of EITF 03-11 adoption(a)	$	(444	)
Boston Generating		74
Exelon Energy Company and AmerGen operations		182
Other operations		176

Decrease in wholesale and retail electric sales	$	(12	)


(a)		Does not include $8 million of EITF 03-11 adjustments related to fuel sales that are included in other revenues.

As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The acquisition of Exelon Energy and AmerGen resulted in increased market and retail electric sales of approximately $182 million compared to the same period in the prior year.

The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, while the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.

150

Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of Exelon Energy Company’s assets and operations being transferred to Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the six months ended June 30, 2003 was $108 million.

The decrease in revenue from sales to affiliates included $40 million in lower sales to Energy Delivery. The lower sales to Energy Delivery was primarily due to customers purchasing energy from alternative electric suppliers and unfavorable weather conditions in the ComEd and PECO service territories compared to the prior year.

Other. Certain other revenues increased for the six months ended June 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s results of operations beginning April 1, 2004.


	*Purchased Power and Fuel*

Generation’s supply source is summarized below:



	Six Months Ended
	June 30,

Supply Source (in GWhs)	2004(c)		2003		Variance			% Change

Nuclear generation(a)		67,665		58,949		8,716			14.8	%
Purchases — non-trading portfolio(b)		23,595		39,373		(15,778	)		(40.1	)%
Fossil and hydroelectric generation		11,296		10,405		891			8.6	%

Total supply		102,556		108,727		(6,171	)		(5.7	)%


(a)		Excludes AmerGen for 2003. AmerGen generated 9,761 GWhs during the six months ended June 30, 2004.

(b)		Sales in 2004 do not include 11,638 GWhs, which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 6,219 GWhs in 2003.

Generation’s supply mix changed as a result of increased fossil generation due to Boston Generating’s Mystic units 8 and 9 and Fore River generating facilities becoming operational in the second and third quarter of 2003, which in total ~~account~~accounted for an increase of ~~2,266~~2,688 GWhs ~~and Generation’s acquisition of the remaining 50% interest~~offset by decreases in AmerGen in December 2003. All of the power generated by AmerGen plants is included in nuclear generation for 2004; previously, power obtained from the AmerGen facilities was treated as purchased power. Purchased power from AmerGen during the three months ended March 31, 2003 was 2,488 GWhs.other fossil generating facilities.

The changes in Generation’s purchased power and fuel expense for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance			Variance

Effects of the adoption of EITF 03-11				$	(452	)
Volume	$	(176	)		129
Price		(96	)		(47	)
Midwest Generation					(48	)
AmerGen and Exelon Energy Company		112			101
Midwest Generation		(23	)
Sithe Energies, Inc.					62
Boston Generating		108			75
Mark-to-market adjustments on hedging activity		8			19
Other		(33	)		(58	)

Decrease in purchased power and fuel expense	$	(100	)	$	(219	)

Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $444 million and fuel expense of $8 million.

151

Volume. ~~The decrease reflects the effects of adopting EITF 03-11, resulting~~Generation experienced increases in ~~a decrease of $200 million.~~purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The ~~decrease was partially offset by a $21 million~~ increase in purchased power ~~volume and a $3 million increase due to increased generation.~~is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation below for further information).

Price. The decrease primarily reflects ~~lower market purchased power prices of $48 million and~~ lower average fossil fuel costs ~~used for non-Boston Generating operations~~ of ~~$48~~$47 million during the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003. Natural gas, oil and coal prices all decreased during this period.

AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen ~~and~~in December 2003, purchased power decreased $160 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, ~~purchased power decreased $62 million and~~ fuel expense increased ~~$174 million. Generation recorded no related party purchased power for the quarter ended March 31, 2004. During the quarter ended March 31, 2003, Generation recorded $68~~$261 million ~~for purchased power from AmerGen.~~as fuel purchases made by Exelon Energy Company did not previously impact Generation’s results.

~~Midwest Generation.~~Sithe Energies, Inc. ~~Generation decreased~~Under the ~~volume~~provisions of ~~purchased power from Midwest Generation as a result~~FIN No. 46-R, the operating results of ~~Generation exercising its option~~Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to ~~reduce the capacity purchased from Midwest Generation.~~Consolidated Financial Statements for further discussion of Sithe.

Boston Generating. The increase in fuel and purchased power expense for Boston Generating is due primarily to the Mystic 8 and 9 generating facilities which began commercial operations ~~during~~at the end of the second quarter of 2003, and the Fore River generating ~~facility~~facilities which began commercial operations during the third quarter of 2003. ~~As a result, purchased power and fuel expense increased $121 million.~~See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding Boston Generating. The increase was ~~partially~~ offset by a decrease of $13 million related to the effects of adopting EITF 03-11.

Hedging Activity. Mark-to-market losses on hedging activities were ~~$39~~$18 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~losses~~gains of ~~$31~~$1 million for the same period of 2003. Hedging activities in 2004 relating to ~~non-Boston~~Boston Generating operations accounted for a ~~loss~~gain of ~~$37~~$4 million and ~~non-Boston Generating~~hedging activities for other Generation operations in 2004 accounted for a loss of $2$22 million.

Other. Other decreases in purchased power and fuel were primarily due to ~~a $21~~$46 million ~~decrease~~ in lower transmission expense resulting from reduced inter-region transmission ~~and~~as a $4result of ComEd’s integration into PJM in the second quarter of 2004, offset by $16 million ~~decrease~~of additional nuclear fuel amortization recorded in ~~intercompany purchased power expense.~~2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

~~101~~


	*Operating and Maintenance*

The changes in operating and maintenance expense for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to the same period in 2003 consisted of the following:


	Variance			Variance

AmerGen and Exelon Energy Company(a)	$	110		$	197
Refueling outage costs~~(b)~~		36			38
Boston Generating		20			33
Decommissioning accretion costs~~(c)~~(b)		7			25
Co-owned facilities		5
Sithe Energies, Inc.					22
Pension, payroll and benefit costs associated with The Exelon Way		(9	)		(23	)
Other		(4	)		38

Increase in operating and maintenance expense	$	165		$	330

152


(a)		Includes refueling outage ~~expenses~~expense of $24 million at AmerGen.

(b)	~~Refueling outage days increased from 50 days for the three months ended March 31, 2003 to 114 days during the same period in 2004.~~

~~(c)~~	Includes ~~$10~~$20 million due to AmerGen asset retirement obligation accretion.

The increase in operating and maintenance expense is due primarily to the inclusion of AmerGen, Exelon Energy Company and Sithe in 2004. Also, operating and maintenance expenses increased at Boston Generating due to Mystic 8 and 9 and Fore River commencing commercial operations in the second and third quarters of 2003. Decommissioning accretion costs also increased primarily due to the inclusion of AmerGen in this period as compared to the prior year. A reduction in payroll-related costs associated with the implementation of the programs associated with The Exelon Way partially offset the other increases to operating and maintenance expense.

Nuclear fleet operating data and purchased power costs data for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were as follows:



	Three Months						Six Months Ended
	Ended March 31,						June 30,

	2004			2003			2004			2003

Nuclear fleet capacity factor(a)		90.5	%		94.4	%		93.3	%		94.2	%
Nuclear fleet production cost per MWh(a)	$	14.29		$	12.80		$	12.54		$	12.40
Average purchased power cost for wholesale operations per MWh(b)	$	44.48		$	41.99		$	45.81		$	41.68


(a)		Includes AmerGen and ~~excluding~~excludes Salem, which is operated by PSE&G.

(b)		Includes PPAs with AmerGen in 2003.

Lower nuclear capacity factors and increased nuclear production costs were primarily due to 6455 additional planned refueling outage days, resulting in a ~~$60~~$46 million increase in planned outage costs ~~including $24 million of planned refueling outage costs at AmerGen,~~ in the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003. There were ~~four~~five planned outages during the ~~three~~six months ended ~~March 31,~~June 30, 2004, compared to ~~two~~three planned outages during the same period in 2003. The ~~three~~six months ended ~~March 31,~~June 30, 2004 included ~~five~~twelve unplanned outages compared to ~~three~~eleven unplanned outages during the same period in 2003. Nuclear capacity factors were also affected by Quad Cities operating at lower than anticipated capacity levels.

The Quad Cities units have intermittently been operating at ~~pre-Extended Power Uprate (EPU)~~pre-EPU generation levels due to performance issues with their steam dryers. Generation is currently evaluating data to determine when the units can return to EPU output levels. There is a continued risk that the Quad Cities units will not return to EPU operating levels in the near future. There is also a risk thatplans additional expenditures ~~will be required on these units~~ to ~~allow extended~~ensure safe and reliable operations at the EPU output ~~levels.~~levels by mid-2005.


	*Depreciation and Amortization*

The increase in depreciation and amortization expense for the ~~three~~six months ended ~~March 31,~~June 30, 2004 as compared to the same period in 2003 was primarily attributable to ~~$8 million~~the impact of ~~additional~~capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense ~~on capital additions placed in service after the first quarter of 2003, of which $3 million of expense is~~

~~102~~

related to the Boston Generating ~~facilities. In addition, depreciation and amortization expense increased $2 million due to increased amortization of long-term debt and capital leases.~~

facilities as the assets were classified as held for sale during the period.


	*Interest Expense*

The increase in interest expense was primarily due to the issuance of $500 million of Senior Notes in December ~~2003.~~2003 and interest expense related to Sithe long-term debt.


	*Equity in Earnings (Losses) of Unconsolidated Affiliates*

The decrease in equity in earnings of unconsolidated affiliates was ~~partially~~primarily due to a ~~$17~~$37 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003. See Note 3 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for further discussion of Generation’s purchase of British Energy’s 50% interest in AmerGen. ~~The decrease was also due to a $4 million decrease in Generation’s equity in earnings of Sithe. Sithe’s earnings were primarily affected by unfavorable mark-to-market activity.~~

153


	*Other, Net*

The ~~increase in~~components of other, net ~~was primarily due to a $200 million impairment charge during~~for the ~~three~~six months ended ~~March 31, 2003~~June 30, 2004 as ~~a result of a change~~compared to the same period in ~~fair value of Generation’s investment in Sithe, and $11 million of nuclear decommissioning trust income related to AmerGen in 2004.~~the prior year, are as follows:



	Six Months
	Ended June 30,

Other, Net	2004		2003			Variance			% Change

Gain on sale of Boston Generating(a)		85		—			85			n.m.
Decommissioning trust funds(b)		60		63			(3	)		(4.8	)%
Decommissioning trust funds — AmerGen(b)		20		—			20			n.m.
Other income from Sithe		9		—			9			n.m.
Impairment of Investment in Sithe		—		(200	)		200			(100.0	)%
Other		9		5			4			80.0	%

Total		183		(132	)		315			n.m.


(a)		See Note 3 of the Combined Notes to the Consolidated Financial Statements for further discussion of Generation’s sale of Boston Generating.

(b)		Includes investment income and realized gains/(losses)

n.m. — not meaningful


	*Effective Income ~~Taxes~~Tax Rate*

The effective income tax rate was ~~40.6%~~38% for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~28.8%~~44% for the same period in 2003. This ~~increase~~decrease was primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe ~~which~~that resulted in a pre-tax loss. In addition, the rate ~~increased~~decreased due to the additional nuclear decommissioning investment income associated with AmerGen and its related taxes. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.


	*Cumulative Effect of Changes in Accounting Principles*

Net income for the ~~three~~six months ended ~~March 31,~~June 30, 2004 reflects income of $32 million, net of income taxes, related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, while net income for the ~~three~~six months ended ~~March 31,~~June 30, 2003 reflects income of $108 million, net of income taxes, for the adoption of SFAS No. 143. See Note 2 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN No. 46-R and SFAS No. 143.

Liquidity and Capital Resources

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool ~~and/~~or capital contributions from Exelon. Generation’s working capital deficit at March 31, 2004 is expected to be eliminated with its anticipated continuance of positive operating cash flows and the eventual elimination of Boston Generating’s debt balance upon the sale of Boston Generating. The sale of Boston Generating will be substantively a non-cash transaction, with the Boston Generating credit facility continuing as a liability of Boston Generating at the time it is sold, without recourse to Exelon or Generation. See Note 3 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of the sale of Boston Generating. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to a revolving credit facility. See the ~~Credit Issues~~“Credit Issues” section of ~~Liquidity~~“Liquidity and Capital ~~Resources~~Resources” for further discussion. Capital resources are used primarily to fund Generation’s capital requirements, including

~~103~~

construction, repayments of maturing debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. ~~Any future~~Future acquisitions could require external financing or borrowings or capital contributions from Exelon.

154


	*Cash Flows from Operating Activities*

Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Generation’s affiliated companies. Generation’s future cash flows from operating activities will be affected by future demand and market prices for energy and its ability to continue to produce and supply power at competitive costs. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flows, sufficient to meet operating and capital expenditures requirements for the foreseeable future.

Cash flows from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$202~~$616 million and ~~$278~~$539 million, respectively. Changes in Generation’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business and non-cash charges.

In addition to the items mentioned in ~~Results~~“Results of ~~Operation,~~Operations,” Generation’s operating cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were affected by the following items:

• ~~Sales~~Receivables from Exelon Delivery under the PPA increased $31 million for the six months ended June 30, 2004, compared to ~~ComEd decreased~~a decrease of $157 million during the same period in ~~2003~~2003.
• Net cash received for collateral for the six months ended June 30, 2004 was $2 million, compared to $136 million paid during the same period in ~~line with the lower load requirements of the territory due to the customer choice initiative.~~2003.

• Discretionary contributions to Exelon’s defined benefit pension plans were ~~$59~~$121 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004 compared to ~~$50~~$98 million for the same period in 2003.

Generation participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including ~~$17~~$11 million to satisfy IRS minimum funding ~~requirements, of which~~requirements. Of the $419 million, $170 million is expected to be funded by Generation during 2004.


	*Cash Flows from Investing Activities*

Cash flows used in investing activities were ~~$152~~$438 million and ~~$272~~$534 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003, respectively. The decrease in cash used in investing activities during the three months ended March 31, 2004 is primarily attributable to $53 million of restricted cash used for Boston Generating operations during the three months ended March 31, 2004, compared to $56 million of restricted cash received during the three months ended March 31, 2003. In addition, Generation received $42 million during the three months ended March 31, 2004 from the sale of three gas turbines at Generation that were classified as assets held for sale at December 31, 2003. Generation’s capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2004 and 2003 were ~~$213~~$366 million and ~~$175~~$424 million, respectively. Generation’s capital expenditures represent additions to nuclear fuel and additions and upgrades to existing facilities. Capital expenditures for the six months ended June 30, 2003 are stated net of proceeds from liquidated damages of $86 million. Generation estimates that it will spend approximately $972 million in total capital expenditures in 2004. Generation anticipates that nuclear refueling outages will increase from eight in 2003 to ~~ten~~nine in 2004. Generation’s capital expenditures are expected to be funded by internally generated funds.


	*Cash Flows from Financing Activities*

Cash flows used in financing activities were ~~$108~~$141 million for the ~~three~~six months ended ~~March 31,~~June 30, 2004, compared to $7cash flows provided by financing activities of $11 million ~~cash provided~~for the same period in 2003. The increase in cash flows used in financing activities was primarily a result of ~~the~~a net repayment of intercompany borrowings of ~~$190~~$218 million during the ~~three~~six months ended ~~March 31,~~June 30, 2004, compared to $6a $58 million net increase in intercompany borrowings during the same period in 2003 and a $64 million increase in distributions to Exelon during the six months ended June 30, 2004 as compared to the same period in 2003. This use of cash was partially offset by the issuance of $211 million of commercial paper during the six months ended June 30, 2004 and the partial repayment of the acquisition note payable to Sithe of $27 ~~million. An additional use of cash was the payment of distributions to Exelon totaling $54 million. This use of cash was partially offset by the issuance of $165~~ million ~~of commercial paper~~ during the ~~three~~six months ended ~~March 31, 2004.~~June 30, 2004, compared a $210 million payment during the same period in 2003.

~~104~~ From time to time and as market conditions warrant, Generation may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of Generation’s balance sheet.

155


	*Credit Issues*

Exelon Credit Facility. Generation meets its short-term liquidity requirements primarily through the issuance of commercial paper and intercompany borrowings from Exelon’s intercompany money pool. Generation participates, along with Exelon Corporate, ComEd and PECO, in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and Generation’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”

Capital Structure. Generation’s capital structure at ~~March 31,~~June 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”

~~Boston Generating Project Debt.~~ A description of this project financing, and the orderly transition out of the ownership of the related assets, is set forth above under “Credit Issues — Boston Generating Project Debt” in “Exelon Corporation — Liquidity and Capital Resources.”

Intercompany Money Pool.A description of the intercompany money pool, and Generation’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” For the ~~three~~six months ended ~~March 31,~~June 30, 2004, Generation paid $1$1.5 million in interest to the money pool.

Sithe Long-Term Debt. A description of the Sithe long-term debt consolidated as a result of the adoption of FIN No. 46-R is set forth above under “Credit Issues — Sithe Long-Term Debt” in “Exelon Corporation — Liquidity and Capital Resources.”

Fund Transfer Restrictions.At ~~March 31,~~June 30, 2004, Generation had undistributed earnings of ~~$647~~$773 million. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation” in the 2003 Form 10-K for information regarding fund transfer restrictions.


	*Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations*

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Generation’s contractual obligations and commercial commitments as of ~~March 31,~~June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

• In connection with the transfer of Exelon Energy Company to Generation effective January 1, 2004, Generation acquired $162 million in energy marketing contract guarantees.

• ~~In connection with the consolidation of Sithe pursuant to FIN No. 46-R,~~ Generation ~~maintains~~acquired a $50 million ~~non-debt~~ letter of credit ~~under~~to support the contractual obligations of Sithe and its ~~credit agreement.~~subsidiaries.

~~105~~156


Item 3.	Quantitative and Qualitative Disclosure About Market Risk

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

Commodity Price Risk


	*Generation*

Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and other factors. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity, energy and fossil fuels, including oil, gas, coal, and emission allowances. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, governmental environmental policies, changes in supply and demand, state and ~~Federal~~federal regulatory policies and other events.


	Normal Operations and Hedging Activities

Electricity available from Generation’s owned or contracted generation supply in excess of its obligations to customers, including Energy Delivery’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge its anticipated exposures. Generation has an estimated 90% hedge ratio in 2004 for its energy marketing portfolio. This hedge ratio represents the percentage of Generation’s forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. Energy Delivery’s retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. During peak periods the amount hedged declines to meet ~~our~~Generation’s commitment to Energy Delivery. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for Generation’s non-trading portfolio associated with a ~~ten percent~~10% reduction in the annual average around-the-clock market price of electricity is approximately a ~~$64~~$19 million decrease in net income. This sensitivity assumes a 90% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.


	Proprietary Trading Activities

Generation uses financial contracts for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of its overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than one percent of Generation’s owned and contracted supply of electricity. Generation expects this level of proprietary trading activity to continue in the future. The results of the trading portfolio for the ~~first quarter of~~six months ended June 30, 2004 was a loss ~~of less than $1~~$2 million (before taxes) which included a $1 million unrealized mark-to-market loss. The daily Value-at-Risk (VaR) on proprietary trading activity averaged $200,000 ~~dollars~~ of exposure ~~over the~~

~~106~~157

over the last 18 months. Because of the diminutive nature of the proprietary trading portfolio in comparison to Generation’s total gross margin of ~~$848~~$1,771 million, Generation has not segregated proprietary trading activity in the following tables. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and VaR limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the power marketing activities.

Generation’s energy contracts are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). Most non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in Exelon’s 2003 Form 10-K. Those that do not are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in Other Comprehensive Income (OCI), and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 and the ineffective portion of hedge contracts are recognized in earnings on a current basis.

The following detailed presentation of the proprietary trading and non-trading marketing activities atof Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. Generation does not consider its proprietary trading to be a significant activity inof its business; however, Generation believes it is important to include these risk management disclosures.

The following tables describe the drivers of Generation’s energy trading and marketing business and gross margin included in the income statement for the three and six months ended ~~March 31,~~June 30, 2004 and 2003. Normal operations and hedging activities represent the marketing of electricity available from Generation’s owned or contracted generation, including generation used to serve Energy Delivery’s retail load, sold into the wholesale market. As the information in these tables highlights, mark-to-market activities represent a small portion of the overall gross margin for Generation. Accrual activities, including normal purchases and sales, account for the majority of the gross margin. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices. Further delineation of gross margin by the type of accounting treatment typically afforded each type of activity is also presented (i.e., mark-to-market vs. accrual accounting treatment).



		Three Months							Three Months
		Ended March 31,							Ended June 30,

		2004			2003				2004			2003

Mark-to-market activities:	Mark-to-market activities:							Mark-to-market activities:
Unrealized mark-to-market gain/(loss)	Unrealized mark-to-market gain/(loss)							Unrealized mark-to-market gain/(loss)
	Origination unrealized gain/(loss) at inception	$	—		$	—		Origination unrealized gain/(loss) at inception	$	—		$	—
	Changes in fair value prior to settlements(a)		35			24		Changes in fair value prior to settlements		115			108
	Changes in valuation techniques and assumptions		—			—		Changes in valuation techniques and assumptions		—			—
	Reclassification to realized at settlement of contracts		(75	)		(57	)	Reclassification to realized at settlement of contracts		(125	)		(78	)

	Total change in unrealized fair value(b)		(40	)		(33	)	Total change in unrealized fair value(a)		(10	)		30
Realized net settlement of transactions subject to mark-to-market	Realized net settlement of transactions subject to mark-to-market		75			57		Realized net settlement of transactions subject to mark-to-market		125			78

Total mark-to-market activities gross margin	Total mark-to-market activities gross margin	$	35		$	24		Total mark-to-market activities gross margin	$	115		$	108

~~107~~158



		Three Months					Three Months
		Ended March 31,					Ended June 30,

		2004		2003			2004		2003

Accrual activities:	Accrual activities:					Accrual activities:
Accrual activities revenue	Accrual activities revenue	$	1,395	$	1,352	Accrual activities revenue	$	1,132	$	1,107
Hedge gains reclassified from OCI	Hedge gains reclassified from OCI		501		398	Hedge gains reclassified from OCI		684		616

	Total revenue — accrual activities		1,896		1,750	Total revenue — accrual activities		1,816		1,723

Purchased power and fuel	Purchased power and fuel		458		597	Purchased power and fuel		200		388
Hedges of purchased power and fuel reclassified from OCI	Hedges of purchased power and fuel reclassified from OCI		625		503	Hedges of purchased power and fuel reclassified from OCI		808		705

	Total purchased power and fuel		1,083		1,100	Total purchased power and fuel		1,008		1,093

	Total accrual activities gross margin		813		650	Total accrual activities gross margin		808		630

Total gross margin~~(c)~~(b)	Total gross margin~~(c)~~(b)	$	848	$	674	Total gross margin~~(c)~~(b)	$	923	$	738


(a)		Includes ~~hedge ineffectiveness of $1 million recorded in earnings.~~

~~(b)~~	~~Includes $1 million and~~ $2 million of unrealized losses due to proprietary trading activity during the three months ended ~~March 31,~~June 30, 2003.

(b)		Total gross margin represents revenue, net of purchased power and fuel expense.



		Six Months Ended
		June 30,

		2004			2003

Mark-to-market activities:
Unrealized mark-to-market gain/(loss)
	Origination unrealized gain/(loss) at inception	$	—		$	—
	Changes in fair value prior to settlements(a)		150			132
	Changes in valuation techniques and assumptions		—			—
	Reclassification to realized at settlement of contracts		(200	)		(135	)

	Total change in unrealized fair value(b)		(50	)		(3	)
Realized net settlement of transactions subject to mark-to-market			200			135

Total mark-to-market activities gross margin		$	150		$	132


Accrual activities:
Accrual activities revenue		$	2,527		$	2,459
Hedge gains reclassified from OCI			1,185			1,014

	Total revenue — accrual activities		3,712			3,473

Purchased power and fuel			657			980
Hedges of purchased power and fuel reclassified from OCI			1,434			1,208

	Total purchased power and fuel		2,091			2,188

	Total accrual activities gross margin		1,621			1,285

Total gross margin(c)		$	1,771		$	1,417


(a)		Includes hedge ineffectiveness of $1 million recorded in earnings.

(b)		Includes $1 million and $4 million of unrealized losses due to proprietary trading activity during the six months ended June 30, 2004 and 2003, respectively.

(c)		Total gross margin represents revenue, net of purchased power and fuel expense.

The following table provides detail on changes in Generation’s mark-to-market net asset or liability balance sheet position from January 1, 2004 to ~~March 31,~~June 30, 2004. It indicates the drivers behind changes in the

159

balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings, as shown in the previous table, as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in Accumulated Other Comprehensive Income on the ~~March 31,~~June 30, 2004 Consolidated Balance Sheet.


Total mark-to-market energy contract net assets at January 1, 2004	$	(216	)	$	(216	)
Total change in fair value during 2004 of contracts recorded in earnings		33			148
Reclassification to realized at settlement of contracts recorded in earnings		(74	)		(199	)
Reclassification to realized at settlement from OCI		124			248
Effective portion of changes in fair value — recorded in OCI		(438	)		(535	)
Purchase/sale of existing contracts or portfolios subject to mark-to-market		144
Purchase/sale/disposal of existing contracts or portfolios subject to mark-to-market					147

Total mark-to-market energy contract net assets (liabilities) at March 31, 2004	$	(427	)
Total mark-to-market energy contract net assets (liabilities) at June 30, 2004				$	(407	)

The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of ~~March 31,~~June 30, 2004 and December 31, 2003:


		March 31,			December 31,				June 30,			December 31,
		2004			2003				2004			2003

Current assets	Current assets	$	399		$	322		Current assets	$	433		$	322
Noncurrent assets	Noncurrent assets		375			100		Noncurrent assets		390			100

	Total mark-to-market energy contract assets		774			422		Total mark-to-market energy contract assets		823			422

Current liabilities(a)	Current liabilities(a)		(811	)		(505	)	Current liabilities(a)		(805	)		(505	)
Noncurrent liabilities	Noncurrent liabilities		(390	)		(133	)	Noncurrent liabilities		(425	)		(133	)

	Total mark-to-market energy contract liabilities		(1,201	)		(638	)	Total mark-to-market energy contract liabilities		(1,230	)		(638	)

Total mark-to-market energy contract net assets (liabilities)	Total mark-to-market energy contract net assets (liabilities)	$	(427	)	$	(216	)	Total mark-to-market energy contract net assets (liabilities)	$	(407	)	$	(216	)


(a)		Mark-to-market energy contract liabilities at December 31, 2003 do not reflect a $76 million interest rate swap which was included in current mark-to-market derivative liabilities within Generation’s Consolidated Balance Sheet.

The majority of Generation’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line

~~108~~

exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available ~~varies~~vary by commodity, region and product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of ~~March 31,~~June 30, 2004 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds ~~and~~or sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

160

The following table, which presents maturity and source of fair value of mark-to-market energy contract net liabilities, provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Generation’s total mark-to-market asset or liability. Second, ~~this~~the table provides the maturity, by year, of Generation’s net assets/liabilities, giving an indication of when ~~these~~the mark-to-market amounts will settle and either generate or require cash.



			Maturities Within																			Maturities Within

															2008 and		Total Fair																	2008 and		Total Fair
			2004			2005			2006			2007			Beyond		Value					2004			2005			2006			2007			Beyond		Value

Normal operations, qualifying cash-flow hedge contracts(a):	Normal operations, qualifying cash-flow hedge contracts(a):																			Normal operations, qualifying cash-flow hedge contracts(a):
	Actively quoted prices		$	47		$	1		$	—		$	—		$	—	$	48		Actively quoted prices		$	2		$	1		$	—		$	—		$	—	$	3
	Prices provided by other external sources			(361	)		(177	)		(31	)		(7	)		—		(576	)	Prices provided by other external sources			(227	)		(217	)		(30	)		(6	)		—		(480	)

		Total	$	(314	)	$	(176	)	$	(31	)	$	(7	)	$	—	$	(528	)		Total	$	(225	)	$	(216	)	$	(30	)	$	(6	)	$	—	$	(477	)

Normal operations, other derivative contracts(b):	Normal operations, other derivative contracts(b):																			Normal operations, other derivative contracts(b):
	Actively quoted prices		$	36		$	1		$	—		$	—		$	—	$	37		Actively quoted prices		$	32		$	8		$	(1	)	$	—		$	—	$	39
	Prices provided by other external sources			(71	)		8			1			—			—		(62	)	Prices provided by other external sources			(59	)		11			5			—			—		(43	)
	Prices based on model or other valuation methods			14			(5	)		15			13			89		126		Prices based on model or other valuation methods			9			(13	)		13			9			56		74

		Total	$	(21	)	$	4		$	16		$	13		$	89	$	101			Total	$	(18	)	$	6		$	17		$	9		$	56	$	70


(a)		Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in other comprehensive income.

(b)		Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.

~~109~~

The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of ~~March 31,~~June 30, 2004. The table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s hedges. The table also includes a roll-forward of accumulated other comprehensive income related to cash-flow hedges for the ~~three~~six months ended ~~March 31,~~June 30, 2004, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest-rate hedging activities.



	Total Cash-Flow Hedge Other Comprehensive Income									Total Cash-Flow Hedge Other Comprehensive
	Activity, Net of Income Tax									Income Activity, Net of Income Tax

	Normal									Normal			Interest Rate			Total
	Operations and			Interest Rate and			Total Cash			Operations and			and			Cash Flow
	Hedging Activities			Other Hedges(a)			Flow Hedges			Hedging Activities			Other Hedges(a)			Hedges

Accumulated OCI derivative loss at January 1, 2004	$	(133	)	$	(13	)	$	(146	)	$	(133	)	$	(13	)	$	(146	)
Changes in fair value		(266	)		—			(266	)		(310	)		—			(310	)
Reclassifications from OCI to net income		75			(4	)		71			151			12			163
Exelon Energy Company opening balance		2			—			2			2			—			2
Sithe		—			(10	)		(10	)		—			(11	)		(11	)

Accumulated OCI derivative loss at March 31, 2004	$	(322	)	$	(27	)	$	(349	)
Accumulated OCI derivative loss at June 30, 2004										$	(290	)	$	(12	)	$	(302	)


(a)		Includes interest rate hedges at Generation.

161

Credit Risk


	*Generation*

Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment. Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits ~~and~~or letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which ~~reduce~~reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

~~110~~

The following tables provide information on Generation’s wholesale credit exposure, net of collateral, as of ~~March 31,~~June 30, 2004. ~~They~~The tables further delineate that exposure by the credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of ~~a company’s~~Generation’s credit risk by credit rating of ~~the~~its counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through Independent System Operators, which are discussed below.


		Total						Number Of		Net Exposure Of			Total						Number Of		Net Exposure Of
		Exposure						Counterparties		Counterparties			Exposure						Counterparties		Counterparties
		Before Credit		Credit		Net		Greater than 10%		Greater than 10%			Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating^(a)		Collateral		Collateral		Exposure		of Net Exposure		of Net Exposure
Rating(a)												Rating(a)	Collateral		Collateral		Exposure		of Net Exposure		of Net Exposure

Investment grade	Investment grade	$	98	$	15	$	83		1	$	18	Investment grade	$	138	$	17	$	121		3	$	71
Split rating	Split rating		—		—		—		—		—	Split rating		—		—		—		—		—
Non-investment grade	Non-investment grade		67		6		61		1		54	Non-investment grade		77		10		67		1		55
No external ratings	No external ratings											No external ratings
	Internally rated — investment grade		15		—		15		—		—	Internally rated — investment grade		13		2		11		—		—
	Internally rated — non-investment grade		1		—		1		—		—	Internally rated — non-investment grade		1		—		1		—		—

Total	Total	$	181	$	21	$	160		2	$	72	Total	$	229	$	29	$	200		4	$	126


(a)		Table does not include credit risk associated with Generation’s retail operations.



		Maturity of Credit Risk Exposure									Maturity of Credit Risk Exposure

						Exposure		Total Exposure							Exposure		Total Exposure
		Less than				Greater than		Before Credit			Less than				Greater than		Before Credit
Rating^(a)		2 Years		2-5 Years		5 Years		Collateral
Rating(a)										Rating(a)	2 Years		2-5 Years		5 Years		Collateral

Investment grade	Investment grade	$	87	$	11	$	—	$	98	Investment grade	$	128	$	10	$	—	$	138
Split rating	Split rating		—		—		—		—	Split rating		—		—		—		—
Non-investment grade	Non-investment grade		67		—		—		67	Non-investment grade		75		2		—		77
No external ratings	No external ratings									No external ratings
	Internally rated — investment grade		15		—		—		15	Internally rated — investment grade		13		—		—		13
	Internally rated — non-investment grade		1		—		—		1	Internally rated — non-investment grade		1		—		—		1

Total	Total	$	170	$	11	$	—	$	181	Total	$	217	$	12	$	—	$	229


(a)		Table does not include credit risk associated with Generation’s retail operations.

Dynegy. Generation is a counterparty to Dynegy, Inc. (Dynegy) in various energy transactions. The credit ratings of Dynegy are below investment grade. As of ~~March 31,~~June 30, 2004, Generation has credit risk

162

associated with Dynegy through Generation’s investment in Sithe. Sithe is a 100% owner of the Independence generating station, a 1,028-MW gas-fired facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of March 31, 2004, Generation consolidated the assets and liabilities of Sithe in accordance with the provisions of FIN No. 46-R. As a result, Generation has recorded an asset of ~~$156~~$114 million on its Consolidated Balance Sheets related to the fair market value of the financial swap agreement with Dynegy that is marked-to-market under the terms of SFAS No. 133, “Accounting for Derivatives and Hedging Activities.” If Dynegy were unable to fulfill the terms of ~~this~~the financial swap agreement, Generation would be required to impair ~~this financial swap~~the related asset. Exelon estimates, as a 50% owner of Sithe, that the impairment would result in an after-tax reduction of its net income of approximately ~~$28~~$21 million.

In addition to the asset impairment, ~~of the financial swap asset,~~ if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation would likely incur ~~a further~~an impairment of the intangible asset associated with the tolling agreement associated with the Independence plant. Depending upon the timing of Dynegy’s failure to fulfill its obligations and the outcome of any restructuring initiatives, Generation could realize an after-tax charge of

~~111~~

up to $50 million. In the event of a sale of Generation’s investment in Sithe to a third party, proceeds from the sale could be negatively affected by up to $84 million, which would represent an after-tax loss of up to $50 million. Additionally, the future economic value of AmerGen’s purchased power arrangement with Illinois Power Company (Illinois Power), a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. In February 2004, Dynegy announced an agreement to sell Illinois Power to a third party, which, upon closing of the transaction, would reduce Generation’s credit risk associated with Dynegy.

~~Additionally, the future economic value of AmerGen’s PPA with Illinois Power~~ could be affected by events related to Dynegy’s financial condition. In February 2004, Dynegy announced an agreement to sell Illinois Power to a third party, which, upon closing of the transaction, would reduce Generation’s credit risk associated with Dynegy.

Collateral. As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of express contractual provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Generation’s situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

ISOs. Generation participates in the following established, real-time energy markets, which are administered by ISOs: PJM, ISO New England, New York ISO, California ISO, Midwest ISO, Inc., Southwest Power Pool, Inc. and Texas, which is administered by the Electric

Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the ISOs. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by the ISOs, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on ~~our~~Generation’s financial condition, results of operations or net cash flows.

Interest Rate Risk


	*ComEd*

ComEd uses a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Interest-rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. ComEd

163

also utilizes forward-starting interest-rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. These strategies are employed to achieve a lower cost of capital. At ~~March 31,~~June 30, 2004, ComEd did not have any interest-rate swaps designated as cash-flow hedges.

In 2004, ComEd ~~has~~ entered into fixed-to-floating interest-rate swaps in order to maintain its targeted percentage of variable-rate debt associated with fixed-rate debt issuances in the aggregate amount of ~~$485~~$240 million. At ~~March 31,~~June 30, 2004, these interest-rate swaps, designated as fair-value hedges, had an aggregate fair market value of ~~$37~~$1 million based on the present value difference between the contract and market rates at ~~March 31,~~June 30, 2004. If these derivative instruments had been terminated at ~~March 31,~~June 30, 2004, this estimated fair value represents the amount that would be paid by the counterparties to ComEd.

~~112~~

The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at ~~March 31,~~June 30, 2004 is estimated to be ~~$42~~$8 million in ComEd’s favor. If the derivative instrument had been terminated at ~~March 31,~~June 30, 2004, this estimated fair value represents the amount the counterparties would pay ComEd.

The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at ~~March 31,~~June 30, 2004 is estimated to be ~~$31~~$7 million in ~~ComEd’s~~the counterparties’ favor. If the derivative instrument had been terminated at ~~March 31,~~June 30, 2004, this estimated fair value represents the amount ~~the counterparties~~ComEd would pay ~~ComEd.~~the counterparties.

In April 2004, ComEd settled ~~these~~certain interest-rate swaps designated as fair-value hedges in the aggregate amount of $485 million for ~~net~~total proceeds of approximately $32 ~~million.~~million, which included the $26 million settlement amount and $6 million of accrued interest. The ~~proceeds~~$26 million settlement amount will be amortized as a reduction to interest expense over the remaining life of the related debt.


	*PECO*

In March 2004, PECO entered into a forward-starting interest rate swap in the aggregate amount of $75 million to lock in interest rate levels in anticipation of a future financing. The debt issuance that this swap was hedging was considered probable in March 2004 and closed in April 2004; therefore, PECO accounted for this interest-rate swap transaction as a hedge. At March 31, 2004, this swap had an aggregate fair market value of less than $1 million based on the present value difference between the contract and market rates at March 31, 2004. If the derivative instrument had been terminated at March 31, 2004, this estimated fair value represents the amount the counterparties would pay PECO.

The aggregate fair value of the interest-rate swap designated as a cash-flow hedge that would have resulted from a hypothetical 50 basis point decrease in the spot yield at March 31, 2004 is estimated to be $6 million in the counterparty’s favor. If the derivative instrument had been terminated at March 31, 2004, this estimated fair value represents the amount PECO would pay the counterparty.

The aggregate fair value of the interest-rate swap designated as a cash-flow hedge that would have resulted from a hypothetical 50 basis point increase in the spot yield at March 31, 2004 is estimated to be $6 million in PECO’s favor. If the derivative instrument had been terminated at March 31, 2004, this estimated fair value represents the amount the counterparty would pay PECO.

In April 2004, PECO settled this interest-rate swap designated as a cash-flow hedge for net proceeds of approximately $5 million. The proceeds were recorded in other comprehensive income and are being amortized over the life of the debt issuance.


	*Generation*

Generation uses a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Generation also uses interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. These strategies are employed to achieve a lower cost of capital. As of ~~March 31,~~June 30, 2004, a hypothetical 10% increase in the interest rates associated with ~~variable-rate~~variable- rate debt would not have a material impact on Generation’s pre-tax earnings.

Under the terms of the Boston Generating Facility, Boston Generating was required to effectively fix the interest rate on 50% of borrowings under the facility through its maturity in 2007. In January 2004, the counterparties terminated the interest-rate swaps with Boston Generating. The total net value of these swaps as of the respective termination dates was $82 million, which is a net payable to the counterparties. The Boston Generating Facility and the related cost of interest rate swaps are non-recourse to Exelon and Generation and an event of default under the Boston Generating Facility does not constitute an event of default under any other of Exelon’s debt instruments or the debt instruments of Exelon’s subsidiaries.

~~113~~

Equity Price Risk


	*Generation*

Generation maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of decommissioning its nuclear plants. As of ~~March 31,~~June 30, 2004, decommissioning trust funds are reflected at fair value on Generation’s Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a ~~$291~~$308 million reduction in the fair value of the trust assets.

164


Item 4.	Controls and Procedures

During the ~~first~~second quarter of 2004, each registrant’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarization and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake.

Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Each registrant’s controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. A registrant’s access and ability to apply its disclosure controls and procedures to unconsolidated entities and entities that are consolidated under FIN No. 46-R may be more limited than is the case for majority-owned subsidiaries.

Accordingly, as of ~~March 31,~~June 30, 2004, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives. Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant.

PART II — OTHER INFORMATION


Item 1.	Legal Proceedings

ComEd

See “Retail Rate Law” within the litigation section of Note 1315 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for a discussion of legal proceeding developments.

Generation

See “Raytheon and Mitsubishi ~~Litigation,” “Clean Air Act”~~Litigation” and “Oyster Creek” within the litigation section of Note 1315 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements for a discussion of legal proceeding developments.

~~114~~165


Item 3.2.	~~Defaults Upon Senior~~Changes in Securities and Use of Proceeds


	(e) Exelon

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock. All share and per-share amounts included in the table below have been adjusted to reflect the stock split.


							Maximum Number
							(or Approximate
					Total Number of		Dollar Value) of
					Shares Purchased		Shares that May
	Total Number				As Part of Publicly		Yet Be Purchased
	of Shares		Average Price		Announced Plans		Under the Plans
Period	Purchased(a)		Paid per Share		or Programs(b)		or Programs

January 1 — January 31, 2004		157,785	$	32.57		—		—
February 1 — February 29, 2004		14,491		33.36		—		—
March 1 — March 31, 2004		18,657		33.92		—		—
April 1 — April 30, 2004		—		—		—		(a	)
May 1 — May 31, 2004		1,809,817		31.87		1,809,000		(a	)
June 1 — June 30, 2004		523,966		33.05		518,100		(a	)

Total		2,524,716		32.18		2,327,100		(a	)


(a)	~~(a)~~	Shares other than those purchased as a part of a publicly announced plan primarily represent restricted shares surrendered by employees to satisfy tax obligations arising upon the vesting of restricted shares.

(b)		In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of direct cash proceeds from purchases of stock and tax benefits associated with exercises of stock options. The share repurchase program has no specified limit and no specified termination date.


~~Generation~~Item 4.	Submission of Matters to a Vote of Security Holders

~~See “Boston Generating Facility”~~Exelon

Exelon held its 2004 Annual Meeting of ~~Note 7~~Shareholders on April 27, 2004.

Proposal 1 was the election of four Class I directors to serve three-year terms expiring in 2007. The following directors were elected:


	Votes For		Votes Withheld

Nicholas DeBenedictis		259,939,186		10,816,919
G. Fred DiBona, Jr.		264,314,416		6,441,689
Sue L. Gin		262,458,220		8,297,885
Edgar D. Jannotta		265,237,110		5,518,995

Proposal 2 was the ratification of PricewaterhouseCoopers LLP as independent accountants for Exelon and its subsidiaries for 2004. The shareholders approved the proposal with 262,663,675 votes cast for, 784,220 votes cast against and 2,308,210 votes abstaining.

Proposal 3 was the approval of the ~~Condensed Combined Notes~~Exelon Corporation Annual Incentive Plan (the Plan) for Senior Executives effective January 1, 2004, as described in the proxy statement. The shareholders approved the Plan with 246,985,526 votes cast for, 18,996,405 votes cast against and 4,804,174 votes abstaining.

166

PECO

PECO held its 2004 Annual Meeting of Shareholders on May 27, 2004. At the PECO annual meeting, the only proposal was the election of two Class III directors to ~~Consolidated Financial Statements~~serve three-year terms expiring in 2007. Denis P. O’Brien and Robert S. Shapard were elected with 170,478,507 votes cast for ~~a description of the event of default under the Boston Generating Facility.~~each director, no votes cast against and no votes abstaining.


Item 5.	Other Information

(a) ComEd, PECO and Generation


	~~(a)~~	*~~ComEd~~Regulatory Issues (ComEd)*

See Note 67 of the ~~Condensed~~ Combined Notes to Consolidated Financial Statements and ComEd’s “Management’s Discuss and Analysis of Financial Condition and Results of Operations — Executive Overview” for a discussion of regulatory developments.


	~~(b)~~	*~~Exelon, ComEd, PECO and Generation~~Labor Relations (PECO)*

As previously reported in the 2003 Form 10-K, on August 15, 2002, the International Brotherhood of Electrical Workers (IBEW) filed a petition with the National Labor Relations Board (NLRB) to conduct a unionization vote of certain of PECO’s employees. On May 21, 2003, the PECO union election was held and a majority of PECO workers voted against union representation. The results of the election were not certified due to pending challenges and objections. On March 22, 2004, the IBEW withdrew its objections to the May 21, 2003 election, and asked the NLRB to allow for a new election at PECO. On April 22, 2004, the NLRB granted IBEW’s request. A new election was held on July 21, 2004, and a majority of PECO employees eligible to vote voted in favor of representation by the IBEW. The NLRB will certify the election on July 29, 2004.


	*Jointly Owned Electric Utility Plant (Generation)*

On January 28, 2004, the NRC issued a letter requesting PSE&G to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSE&G responded to the letter on February 28, 2004, and had independent assessments of the work environment at the facility performed. Assessment results were provided to the NRC in May. The assessments concluded that Salem was safe for continued operation, but also identified issues that need to be addressed. At an NRC public meeting on June 16, 2004, PSE&G outlined its action plans to address these issues, which focus on safety conscious work environment, the corrective action program, and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004.

In June 2001, the NJDEP issued a renewed NPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published FWPCA Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless the agency grants additional time to collect information to comply with the new regulations. NJDEP advised PSE&G in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSE&G has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations require the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit would result in material costs of compliance to the owners of the facility.

(b) Exelon, ComEd, PECO and Generation

None.

167


Item 6.	*Exhibits and Reports on Form 8-K*

(a) Exhibits:

~~10 .1 — Michael B. Bemis separation letter, dated December 19, 2003. Filed on behalf of ComEd and PECO.~~


3-1	—	Amendment to Articles of Incorporation for Exelon Corporation effective as of April 19, 2004.
10-1	—	Amended and Restated Power Purchase Agreement between Exelon Generation Company, LLC and Commonwealth Edison Company as of April 30, 2004.
10-2	—	$1,000,000,000 Five Year Credit Agreement dated as of July 16, 2004 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers and Various Financial Institutions as Lenders.
10-3	—	First Amendment dated as of July 16, 2004 to Three Year Credit Agreement dated as of October 31, 2003 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Exelon Generation Company, LLC, various financial institutions and Bank One, NA, as administrative agent.

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~March 31,~~June 30, 2004 filed by the following officers for the following companies:


31-1	—	Filed by John W. Rowe for Exelon Corporation
31-2	—	Filed by Robert S. Shapard for Exelon Corporation
31-3	—	Filed by John L. Skolds for Commonwealth Edison Company
31-4	—	Filed by J. Barry Mitchell for Commonwealth Edison Company
31-5	—	Filed by John L. Skolds for PECO Energy Company
31-6	—	Filed by J. Barry Mitchell for PECO Energy Company
31-7	—	Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC
31-8	—	Filed by J. Barry Mitchell for Exelon Generation Company, LLC

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code ~~(Sarbanes — Oxley~~(Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~March 31,~~June 30, 2004 filed by the following officers for the following companies:


32-1	—	Filed by John W. Rowe for Exelon Corporation
32-2	—	Filed by Robert S. Shapard for Exelon Corporation
32-3	—	Filed by John L. Skolds for Commonwealth Edison Company
32-4	—	Filed by J. Barry Mitchell for Commonwealth Edison Company
32-5	—	Filed by John L. Skolds for PECO Energy Company
32-6	—	Filed by J. Barry Mitchell for PECO Energy Company
32-7	—	Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC
32-8	—	Filed by J. Barry Mitchell for Exelon Generation Company, LLC

~~115~~168

(b) Reports on Form 8-K:

Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during the three months ended ~~March 31,~~June 30, 2004 regarding the following items:


Date of Earliest
Event Reported		Description of Item Reported

	~~January~~April 8, 2004	“ITEM 5. OTHER EVENTS” filed for Exelon announcing the record and distribution dates for the previously announced 2-for-1 stock split.
	April 16, 2004	“ITEM 5. OTHER EVENTS” and “ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS” filed for PECO regarding an Underwriting Agreement entered into due to the issuance of First and Refunding Mortgage Bonds.
	April 27, 2004	“ITEM 5. OTHER EVENTS” filed for Exelon announcing the declaration of a quarterly dividend and ~~a 2-for-1 stock split.~~an equity plan share repurchase program.
	~~January 29, 2004~~	~~“ITEM 5. OTHER EVENTS” filed for Exelon announcing the election of Honorable Nelson A. Diaz to the board of directors.~~
	~~February 20, 2004~~	“ITEM 5. OTHER EVENTS” filed for Exelon regarding certain financial information of Exelon Corporation and Subsidiary Companies. The exhibits under “ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS” filed for Exelon include Consent of the Independent Public Accountants, Selected Financial Data, Market for Registrant’s Common Equity and Related Stockholder Matters, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Financial Statements and Supplementary Data.
	~~February 23,~~May 10, 2004	“ITEM 5. OTHER EVENTS” filed for Exelon and Generation regarding ~~a settlement with~~ the ~~lenders under~~FERC’s authorization of the ~~Boston Generating Facility and~~transfer of ownership of BG to the ~~resolution of certain disputes associated with the projects of Boston Generating.~~lenders’ special purpose entity.
	~~February 26,~~May 25, 2004	“ITEM 5. OTHER EVENTS” filed for Exelon and Generation regarding ~~a structured, prearranged trading plan established by John W. Rowe, Chairman~~the completion of the transfer of ownership of Boston Generating to the lenders’ special purpose entity.
	May 25, 2004	“ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS” AND “ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS” filed for Exelon and ~~Chief Executive Officer~~Generation including pro forma financial information related to the transfer of ~~Exelon.~~ownership of Boston Generating.

~~116~~169

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION



/s/ JOHN W. ROWE John W. Rowe				Chairman and Chief Executive Officer (Principal Executive Officer)

/s/ ROBERT S. SHAPARD Robert S. Shapard				Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger				Vice President and Corporate Controller (Principal Accounting Officer)

~~April~~July 28, 2004

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY



/s/ JOHN L. SKOLDS John L. Skolds				President, Exelon Energy Delivery (Principal Executive Officer)

/s/ J. BARRY MITCHELL J. Barry Mitchell				Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

/s/ ~~DUANE M. DESPARTE~~MATTHEW F. HILZINGER ~~Duane M. DesParte~~Matthew F. Hilzinger				Vice President and Corporate Controller, Exelon ~~Energy Delivery~~ (Principal Accounting Officer)

/s/ FRANK M. CLARK Frank M. Clark				President, ComEd

~~April~~July 28, 2004

~~117~~170

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY



/s/ JOHN L. SKOLDS John L. Skolds				President, Exelon Energy Delivery (Principal Executive Officer)

/s/ J. BARRY MITCHELL J. Barry Mitchell				Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

/s/ ~~DUANE M. DESPARTE~~MATTHEW F. HILZINGER ~~Duane M. DesParte~~Matthew F. Hilzinger				Vice President and Corporate Controller, Exelon ~~Energy Delivery~~ (Principal Accounting Officer)

/s/ DENIS P. O’BRIEN Denis P. O’Brien				President, PECO

~~April~~July 28, 2004

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON GENERATION COMPANY, LLC



/s/ OLIVER D. KINGSLEY JR. Oliver D. Kingsley Jr.				Chief Executive Officer and President (Principal Executive Officer)

/s/ J. BARRY MITCHELL J. Barry Mitchell				Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

/s/ JON D. VEURINK Jon D. Veurink				Vice President and Controller (Principal Accounting Officer)

~~April~~July 28, 2004

~~118~~171


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OFof 1934
		For the Quarterly Period Ended ~~March 31,~~June 30, 2004

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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

	1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street – 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398		23-2990190
	1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 10 South Dearborn Street – 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-4321		36-0938600
	1-1401	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000		23-0970240
	333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348 (610) 765-6900		23-3064219


Exelon Corporation Common Stock, without par value		~~330,488,032~~660,149,965
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,486
PECO Energy Company Common Stock, without par value		170,478,507
Exelon Generation Company, LLC		not applicable



				Three Months									Six Months
				Ended March 31,									Ended June 30,

				2004			2003						2004			2003
(In millions)	(In millions)									(In millions)
Cash flows from operating activities	Cash flows from operating activities									Cash flows from operating activities
										Net income			$	933		$	733
										Adjustments to reconcile net income to net cash flows provided by operating activities
	Net income			$	406		$	361			Depreciation, amortization and accretion, including nuclear fuel			930			846
	Adjustments to reconcile net income to net cash flows provided by operating activities:										Cumulative effect of changes in accounting principles (net of income taxes)			(32	)		(112	)
		Depreciation, amortization and accretion, including nuclear fuel			458			423			Impairment of investments			1			238
		Cumulative effect of changes in accounting principles (net of income taxes)			(32	)		(112	)		Impairment of goodwill and other long-lived assets			—			53
		Impairment of investments			3			205			Deferred income taxes and amortization of investment tax credits			154			(100	)
		Deferred income taxes and amortization of investment tax credits			217			(64	)		Provision for uncollectible accounts			39			43
		Provision for uncollectible accounts			23			31			Equity in losses (earnings) of unconsolidated affiliates			55			(33	)
		Equity in losses (earnings) of unconsolidated affiliates			24			(18	)		Gains on sales of investments and wholly-owned subsidiaries			(155	)		—
		Net realized gains on nuclear decommissioning trust funds			(3	)		(6	)		Net realized losses (gains) on nuclear decommissioning trust funds			1			(12	)
		Other operating activities			7			(7	)		Other operating activities			(16	)		52
		Changes in assets and liabilities:									Changes in assets and liabilities
			Accounts receivable		22			4				Receivables		269			70
			Inventories		71			43				Inventories		14			(16	)
			Other current assets		(82	)		(290	)			Other current assets		(66	)		(219	)
			Accounts payable, accrued expenses and other current liabilities		(165	)		(217	)			Accounts payable, accrued expenses and other current liabilities		(134	)		(143	)
			Net realized and unrealized mark-to-market and hedging transactions		24			25				Net realized and unrealized mark-to-market and hedging transactions		54			76
			Pension and non-pension postretirement benefits obligations		(85	)		(77	)			Pension and non-pension postretirement benefits obligations		(175	)		(146	)
			Other noncurrent assets and liabilities		(37	)		82				Other noncurrent assets and liabilities		35			(38	)

Net cash flows provided by operating activities	Net cash flows provided by operating activities				851			383		Net cash flows provided by operating activities				1,907			1,292

Cash flows from investing activities	Cash flows from investing activities									Cash flows from investing activities
	Capital expenditures				(439	)		(427	)	Capital expenditures				(844	)		(1,019	)
	Proceeds from nuclear decommissioning trust fund sales				307			572		Proceeds from liquidated damages				—			86
	Investment in nuclear decommissioning trust funds				(378	)		(622	)	Proceeds from nuclear decommissioning trust fund sales				1,042			1,262
	Change in restricted cash				70			74		Investment in nuclear decommissioning trust funds				(1,178	)		(1,368	)
	Net cash increase from consolidation of Sithe Energies, Inc.				19			—		Note receivable from unconsolidated affiliate				—			35
	Other investing activities				48			20		Proceeds from sales of investments and wholly-owned subsidiaries				227			6
										Change in restricted cash				(2	)		(29	)
										Net cash increase from consolidation of Sithe Energies, Inc.				19			—
										Other investing activities				67			11

Net cash flows used in investing activities	Net cash flows used in investing activities				(373	)		(383	)	Net cash flows used in investing activities				(669	)		(1,016	)

Cash flows from financing activities	Cash flows from financing activities									Cash flows from financing activities
	Issuance of long-term debt				—			951		Issuance of long-term debt				75			1,813
	Retirement of long-term debt				(182	)		(963	)	Retirement of long-term debt				(312	)		(1,479	)
	Retirement of long-term debt to financing affiliates				(181	)		—		Retirement of long-term debt to financing affiliates				(345	)		—
	Change in short-term debt				(10	)		219		Change in short-term debt				(65	)		(100	)
	Issuance of mandatorily redeemable preferred securities				—			200		Issuance of mandatorily redeemable preferred securities				—			300
	Retirement of mandatorily redeemable preferred securities				—			(200	)	Retirement of mandatorily redeemable preferred securities				—			(300	)
	Payment on acquisition note payable to Sithe Energies, Inc.				(27	)		—		Payment on acquisition note payable to Sithe Energies, Inc.				(27	)		(210	)
	Dividends paid on common stock				(181	)		(145	)	Dividends paid on common stock				(364	)		(285	)
	Proceeds from employee stock plans				106			31		Proceeds from employee stock plans				140			91
	Other financing activities				3			(59	)	Purchase of treasury stock				(75	)		—
										Other financing activities				36			(85	)
Net cash flows (used in) provided by financing activities					(472	)		34

Net cash flows used in financing activities										Net cash flows used in financing activities				(937	)		(255	)

Increase in cash and cash equivalents	Increase in cash and cash equivalents				6			34		Increase in cash and cash equivalents				301			21
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period				493			469		Cash and cash equivalents at beginning of period				493			469

Cash and cash equivalents, including cash classified as held for sale										Cash and cash equivalents, including cash classified as held for sale				794			490
Cash classified as held for sale on the consolidated balance sheet										Cash classified as held for sale on the consolidated balance sheet				—			(26	)

Cash and cash equivalents at end of period	Cash and cash equivalents at end of period			$	499		$	503		Cash and cash equivalents at end of period			$	794		$	464

Supplemental cash flow information										Supplemental cash flow information
Noncash investing and financing activities:										Noncash investing and financing activities:
										Consolidation of Sithe Energies, Inc. pursuant to FASB Interpretation No. 46-R, “Consolidation of Variable Interest Entities”			$	85		$	—


			March 31,		December 31,				June 30,		December 31,
			2004		2003				2004		2003
(In millions)	(In millions)						(In millions)
ASSETS	ASSETS						ASSETS
Current assets	Current assets						Current assets
	Cash and cash equivalents		$	499	$	493	Cash and cash equivalents		$	794	$	493
	Restricted cash and investments			149		97	Restricted cash and investments			179		97
	Accounts receivable, net						Accounts receivable, net
		Customer		1,601		1,567		Customer		1,645		1,567
		Other		333		343		Other		403		582
	Mark-to-market derivative assets — energy			399		337	Mark-to-market derivative assets			433		337
	Inventories, at average cost						Inventories, at average cost
		Fossil fuel		120		212		Fossil fuel		165		212
		Materials and supplies		306		310		Materials and supplies		318		310
	Notes receivable from affiliate			—		92	Notes receivable from affiliate			—		92
	Deferred income taxes			650		567	Deferred income taxes			145		162
	Assets held for sale			1,309		242	Assets held for sale			20		242
	Other			614		413	Other			449		413

		Total current assets		5,980		4,673		Total current assets		4,551		4,507

Property, plant and equipment, net	Property, plant and equipment, net			20,133		20,630	Property, plant and equipment, net			20,228		20,630
Deferred debits and other assets	Deferred debits and other assets						Deferred debits and other assets
	Regulatory assets			5,118		5,226	Regulatory assets			5,038		5,226
	Nuclear decommissioning trust funds			4,890		4,721	Nuclear decommissioning trust funds			4,890		4,721
	Investments			964		941	Investments			922		955
	Goodwill			4,714		4,719	Goodwill			4,714		4,719
	Mark-to-market derivative assets — energy			375		100	Mark-to-market derivative assets			391		133
	Other			1,385		1,024	Other			1,368		991

		Total deferred debits and other assets		17,446		16,731		Total deferred debits and other assets		17,323		16,745

Total assets	Total assets		$	43,559	$	42,034	Total assets		$	42,102	$	41,882


		Page No.

FILING FORMAT			3
FORWARD-LOOKING STATEMENTS			3
WHERE TO FIND MORE INFORMATION			3

PART I.	FINANCIAL INFORMATION		5
Item 1.	Financial Statements		5
	Exelon Corporation
	Consolidated Statements of Income and Comprehensive Income		6
	Consolidated Statements of Cash Flows		7
	Consolidated Balance Sheets		8
	Commonwealth Edison Company
	Consolidated Statements of Income and Comprehensive Income		10
	Consolidated Statements of Cash Flows		11
	Consolidated Balance Sheets		12
	PECO Energy Company
	Consolidated Statements of Income and Comprehensive Income		14
	Consolidated Statements of Cash Flows		15
	Consolidated Balance Sheets		16
	Exelon Generation Company, LLC
	Consolidated Statements of Income and Comprehensive Income		18
	Consolidated Statements of Cash Flows		19
	Consolidated Balance Sheets		20
	~~Condensed~~ Combined Notes to Consolidated Financial Statements		22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		5770
	Exelon Corporation		5972
	Commonwealth Edison Company		80110
	PECO Energy Company		89126
	Exelon Generation Company, LLC		97140
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		~~107~~157
Item 4.	Controls and Procedures		~~115~~165

PART II.	OTHER INFORMATION		~~115~~165
Item 1.	Legal Proceedings		~~115~~165
	Exelon Corporation		~~115~~165
	Commonwealth Edison Company		~~115~~165
	Exelon Generation Company, LLC		~~115~~165
Item 3.2.	~~Defaults Upon Senior~~Changes in Securities and Use of Proceeds		~~116~~166
	Exelon Corporation		~~116~~166
Item 4.	Submission of Matters to a Vote of Security Holders		166
	Exelon ~~Generation Company, LLC~~Corporation		~~116~~166
	PECO Energy Company		166


2.	New Accounting Principles (Exelon, ComEd, PECO and Generation)


	*New Accounting Principles with a Cumulative Effect upon Adoption*


	March 31, 2004		December 31, 2003		June 30, 2004		December 31, 2003

Exelon	$	5,889	$	6,070	$	5,725	$	6,070
ComEd		1,944		2,037		1,858		2,037
PECO		3,945		4,033		3,867		4,033


Generation (net of income taxes of $52)	$	80
Generation’s investments in AmerGen Energy Company, LLC and Sithe (net of income taxes of $18)		28
ComEd (net of income taxes of $0)		5
Enterprises (net of income taxes of $(1))		(1	)

Total	$	112


			EITF 03-11
For the Three Months Ended June 30, 2003	As Reported		Impact			Pro Forma

Operating revenue	$	3,721	$	(234	)	$	3,487
Purchased power		856		(216	)		640
Fuel expense		531		(18	)		513


			EITF 03-11
For the Six Months Ended June 30, 2003	As Reported		Impact			Pro Forma

Operating revenue	$	7,795	$	(485	)	$	7,310
Purchased power		1,763		(448	)		1,315
Fuel expense		1,356		(37	)		1,319


	Three Months Ended		Six Months Ended
	June 30, 2004		June 30, 2004

Amortization of the actuarial experience gain	$	4	$	8
Reduction in current period service cost		1		2
Reduction in interest cost on the APBO		3		6


		Three Months Ended
		March 31, 2004

Net income — as reported		$	406
Reduction in net periodic postretirement benefit expense(a)			6

Adjusted net income		$	412

Earnings per share:
	Basic — as reported	$	0.62
	Basic — as adjusted	$	0.63
	Diluted — as reported	$	0.61
	Diluted — as adjusted	$	0.62


Three Months Ended March 31, 2004	ComEd		PECO			Generation

Net income — as reported	$	182	$	130	(a)	$	99
Reduction in net periodic postretirement benefit expense(b)		2		1			3

Adjusted net income	$	184	$	131		$	102


	SFAS No. 143


	EITF 03-11


	~~FSP FAS 106-1~~Exelon


	Generation


	*Sale of Ownership Interest in Boston Generating, LLC (Exelon and Generation)*


Current assets (including $5 million of cash)	$	89
Property, plant and equipment		2
Deferred debits and other assets		13
Current liabilities		(96	)
Deferred credits and other liabilities		(10	)
Accumulated other comprehensive loss		(2	)
Member’s equity		4


		Three Months Ended
		March 31, 2003

Total operating revenue		$	4,155
Operating income			771
Income before cumulative effect of changes in accounting principles			266
Net income(a)			884

Earnings per share:
Pro forma earnings per average common share — basic:
	Income before cumulative effect of changes in accounting principles	$	0.82
	Cumulative effect of changes in accounting principles		1.89

Net income		$	2.71

Pro forma earnings per average common share — diluted:
Income before cumulative effect of changes in accounting principles		$	0.82
	Cumulative effect of changes in accounting principles		1.89

Net income		$	2.71


~~(a)~~		~~Generation did not recognize the full benefit of the cumulative effect of changes in accounting principle related to AmerGen’s adoption of SFAS No. 143.~~


	*~~Assets and Liabilities Held for Sale~~Synthetic Fuel-Producing Facilities (Exelon)*


	Generation		Thermal		Exelon Services		Total

Cash	$	—	$	10	$	1	$	11
Accounts receivable, net		9		13		19		41
Other current assets		66		—		5		71
Property, plant and equipment, net		1,063		86		1		1,150
Other long-term assets		16		11		9		36

Assets classified as held for sale	$	1,154	$	120	$	35	$	1,309


	*Assets and Liabilities Held for Sale (Exelon and Generation)*


	Generation		Enterprises		Exelon

Accounts receivable, net	$	—	$	8	$	8
Other current assets		—		2		2
Property, plant and equipment, net		9		1		10

Assets classified as held for sale	$	9	$	11	$	20


			Accumulated
	Gross Carrying		Amortization		Intangible
Agreement Type	Amount		June 30, 2004		Asset, net

Energy Purchase Agreement	$	376	$	13	$	363
Tolling Agreement		71		2		69

Total	$	447	$	15	$	432


	*~~Exelon Condensed Consolidating Balance Sheet at March 31, 2004~~*


					Eliminating			Exelon
	Exelon		Sithe		Entries			Consolidated

Assets
Current assets	$	4,500	$	326	$	(155	)	$	4,671
Assets held for sale		1,149		160		—			1,309
Property, plant and equipment, net		19,855		278		—			20,133
Other noncurrent assets		16,756		739		(49	)		17,446

Total assets	$	42,260	$	1,503	$	(204	)	$	43,559


Liabilities and stockholders’ equity
Current liabilities	$	4,488	$	227	$	(155	)	$	4,560
Liabilities held for sale		1,213		143		—			1,356
Long-term debt		13,207		817		—			14,024
Other liabilities(a)		14,566		212		55			14,833
Stockholders’ equity(b)		8,786		104		(104	)		8,786

Total liabilities and stockholders’ equity	$	42,260	$	1,503	$	(204	)	$	43,559


~~(a)~~		~~Includes minority interest of consolidated subsidiaries.~~

~~(b)~~		~~Includes preferred securities of subsidiaries.~~


	*~~Generation Condensed Consolidating Balance Sheet at March 31, 2004~~*


5.	~~Stock-Based Compensation (Exelon, ComEd, PECO~~Selected Pro Forma and ~~Generation)~~Consolidating Financial Information


			Acquisition		Sale of						Pro Forma
	Exelon		of 50% of		Boston			Eliminating			Exelon
Three Months Ended June 30, 2003	As Reported		AmerGen		Generating			Entries			Consolidated

Total operating revenue	$	3,721	$	159	$	130		$	(110	)	$	3,640
Operating income (loss)		800		21		(10	)		—			831
Income (loss) before cumulative effect of changes in accounting principles		372		38		(8	)		(20	)		398


	*Exelon Condensed Consolidating Balance Sheet at June 30, 2004*


(a)	*~~ComEd~~*Excludes assets and liabilities held for sale.


(b)	*~~PECO~~*Includes minority interest of consolidated subsidiaries.


											Pro Forma
	Generation		Businesses		Businesses			Eliminating			Generation
Three Months Ended June 30, 2003	As Reported		Acquired(a)		Disposed(b)			Entries			Consolidated

Total operating revenue	$	1,886	$	333	$	130		$	(154	)	$	1,935
Operating income (loss)		201		23		(10	)		—			234
Income (loss) before cumulative effect of changes in accounting principles		142		38		(8	)		(20	)		168


6.(a)	~~Regulatory Issues (Exelon~~Includes the acquisition of the remaining 50% interest in AmerGen, and ~~ComEd)~~the transfer of Exelon Energy Company to Generation.