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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the Fiscal Year Ended December 31, 2005

OR

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

COMMONWEALTH EDISON COMPANY:

Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2005, was as follows:

The number of shares outstanding of each registrant’s common stock as of January 31, 2006 was as follows:

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FILING FORMAT

This combined Form 10-K 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.

FORWARD-LOOKING STATEMENTS

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, including those discussed in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, (c) ITEM 8. Financial Statements and Supplementary Data: Exelon—Note 20, ComEd—Note 17, PECO—Note 15 and Generation—Note 17 and (d) 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.

WHERE TO FIND MORE INFORMATION

The public may read and copy any reports or other information that a registrant files with the SEC at the SEC’s public reference room at 100 F Street, N.E., 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. Information contained on Exelon’s website shall not be deemed incorporated into, or to be a part of, this Report.

The Exelon corporate governance guidelines and the charters of the standing committees of its Board of Directors, together with the Exelon Code of Business Conduct and additional information regarding Exelon’s corporate governance, are available on Exelon’s website at www.exeloncorp.com and will be made available, without charge, in print to any shareholder who requests such documents from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

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PART I

ITEM 1. BUSINESS

General

Exelon, a public utility holding company, operates through its principal subsidiaries—ComEd, PECO and Generation—as described below, each of which is treated as an operating segment by Exelon. In 2004, Exelon identified three operating segments—Energy Delivery (ComEd and PECO), Generation and Enterprises. Exelon sold or wound down substantially all components of Exelon Enterprises Company, LLC (Enterprises) in 2004 and 2003. As a result, Exelon ceased reporting Enterprises as a segment as of January 1, 2005. Additionally, Exelon concluded during the fourth quarter of 2005 that ComEd and PECO could no longer be aggregated as a combined Energy Delivery segment. As such, Exelon now presents three reportable segments: ComEd, PECO and Generation. Prior period presentation has been adjusted for comparative purposes. See Note 22 of Exelon’s Notes to Consolidated Financial Statements for further segment information.

Exelon was incorporated in Pennsylvania in February 1999. Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-7398.

Proposed Merger with Public Service Enterprise Group Incorporated

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), an exempt public utility holding company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). PSEG shareholders approved the Merger on July 19, 2005. Exelon shareholders approved the issuance of Exelon shares pursuant to the Merger on July 22, 2005. Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2005, PSEG’s market capitalization exceeded $16 billion. Additionally, at December 31, 2005, PSEG, on a consolidated basis, had approximately $13 billion of outstanding debt, which is currently anticipated to become part of Exelon’s consolidated debt.

In 2005, Exelon filed petitions or applications for approval or review of the Merger, or approval of matters related to the Merger, with various federal and state regulatory authorities, including the Federal Energy Regulatory Commission (FERC) under the Federal Power Act, the United States Department of Justice under the Hart Scott Rodino Antitrust Improvements Act of 1976, the Pennsylvania Public Utility Commission (PAPUC), the New Jersey Board of Public Utilities (NJBPU), the United States Nuclear Regulatory Commission (NRC), the New York Public Service Commission, the Connecticut Siting Council, the New Jersey Department of Environmental Protection (NJDEP) and the Public Utility Commission of Texas under the Texas Public Utility Regulatory Act. Various other state and Federal agencies and agencies of foreign countries have a role in reviewing various aspects of the transaction. ComEd filed a notice of the Merger with the Illinois Commerce Commission (ICC) and the ICC’s general counsel confirmed that its formal approval of the Merger is not required.

As of February 14, 2006, all material regulatory approvals or reviews necessary to complete the Merger have been completed with the exception of the approval from the NJBPU and the NRC and the review by the United States Department of Justice.

The FERC approved the Merger on June 30, 2005. Exelon and PSEG proposed in their application with the FERC, and FERC approved, a market concentration mitigation plan involving the divestiture of 4,000 MW of coal, mid-merit (or intermediate) and peaking generation in the PJM region and the ongoing auction of 2,600 MW of nuclear output and the interim mitigation of fossil generation

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pending divestiture. Exelon and PSEG also proposed to invest a total of $25 million in transmission improvements, which was included in the proposal that was accepted by FERC. The ultimate outcome of the market concentration mitigation is dependent upon various factors, including the market conditions and buyer interest at the time the generating units and the nuclear output are offered for sale. The results of these activities, therefore, are not assured, and could have a material impact on the results of operations and cash flows of Exelon and Generation if the sales price for the divested assets is different from management’s expectations. The FERC considered petitions for rehearing with respect to the order approving the Merger and affirmed its order on December 15, 2005. On January 6 and January 13, 2006, Philadelphia Gas Works/City of Philadelphia and subsidiaries of PPL Corporation, parties to the FERC proceeding, filed petitions for review of the FERC order in the United States Court of Appeals for the District of Columbia.

On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The settlement reflected the conclusion of a process involving the majority of PECO customer groups during which PECO’s cost data, return on equity and estimated Merger synergies were reviewed. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement rate reductions aggregating $120 million during a four-year period and to cap its rates through the end of 2010. During the rate cap period, the PAPUC retains the right to lower PECO’s rates if they are found to be excessive, and PECO retains the right to seek rate increases if certain events (such as significant increases in Federal or state income taxes or other significant changes in law or regulation that do not allow PECO to earn a fair rate of return) occur. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. By separate motion, the PAPUC also indicated its intent to initiate a separate investigation, to which PECO had agreed in the partial settlement, to examine issues related to a potential combination of Philadelphia Gas Works, which provides gas distribution service in the City of Philadelphia, into Exelon’s gas distribution businesses. This investigation will commence no earlier than 30 days after the close of the Merger. The outcome of this potential examination is uncertain. However, Exelon does not believe that the PAPUC has the authority to compel such a transaction if the two parties do not agree to terms through arms length negotiations.

On September 30, 2005, the administrative law judge in the proceeding before the NJBPU amended a prior prehearing order to modify the timetable for the regulatory approval process in New Jersey. The revised procedural schedule for the Merger review called for testimony to be filed from mid-November to mid-December and for hearings in January 2006. Under that revised schedule, the initial decision of the administrative law judge was expected in March 2006 and a final order from the full NJBPU was expected in May 2006. On January 25, 2006, the schedule for hearings was extended through March 27, 2006. On February 8, 2006, the administrative law judge approved a revised schedule calling for additional hearings on March 13, 14, 24 and 27, 2006. The dates originally scheduled for the administrative law judge’s initial decision and the final order of the full NJBPU will also be extended but no firm dates have been set. Settlement discussions in New Jersey began in December 2005 and are expected to resume after completion of hearings before the NJBPU. Exelon will attempt to reach a settlement that satisfactorily resolves issues and allows the Merger to close in the second quarter of 2006. However, in the absence of an earlier settlement, Exelon expects that the closing of the Merger will occur in the third quarter of 2006.

Various governmental, consumer and other parties have intervened in the proceedings before the NJBPU and other regulatory bodies. To facilitate approval of the Merger, Exelon may negotiate with

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these parties and may enter into settlement agreements. Orders resulting from the proceedings before the NJBPU and other regulatory bodies and settlements in connection with the proceedings could, for example, affect the extent to which Exelon and its subsidiaries may benefit from expected synergies following the Merger and could be materially different from what the Registrants expect in this and other respects, and could have a material impact on the financial condition, results of operations and cash flows of the Registrants if the Merger is completed.

The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million or (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. Either Exelon or PSEG can terminate the Merger Agreement without penalty if the closing of the Merger does not occur on or before June 20, 2006; however, this termination right is not available to a party whose failure to fulfill any obligation under the Merger Agreement resulted in the failure to close the Merger by June 20, 2006.

Further information concerning the proposed Merger is included in the definitive joint proxy statement/prospectus filed by Exelon with the SEC on June 3, 2005 under SEC Rule 424(b)(3) (Registration No. 333-122704). For additional information related to the Merger, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Executive Overview—Proposed Merger with PSEG and Note 3 of Exelon’s Notes to Consolidated Financial Statements. Except as otherwise specifically stated, any estimates of the Registrants for 2006 or thereafter disclosed in this Form 10-K do not reflect the effects of the Merger. In addition, PSEG and certain of its subsidiaries are reporting companies under the Securities Exchange Act of 1934, and their periodic reports and other filings are available on the web site maintained by the SEC at http://www.sec.gov. The information contained in the SEC filings of PSEG and its subsidiaries shall not be deemed incorporated into, or to be a part of, this Report.

ComEd

ComEd’s energy delivery business consists of the purchase and regulated sale of electricity and distribution and transmission services to retail and wholesale customers in northern Illinois, including the City of Chicago.

ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation named Commonwealth Edison Company, which was incorporated in 1907. ComEd’s principal executive offices are located at 440 South LaSalle Street, Chicago, Illinois 60605, and its telephone number is 312-394-4321.

PECO

PECO’s energy delivery business consists of the purchase and regulated sale of electricity and distribution and transmission services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated sale of natural gas and distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia.

PECO was incorporated in Pennsylvania in 1929. PECO’s principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19103, and its telephone number is 215-841-4000.

Generation

Exelon’s generation business consists of the owned and contracted-for electric generating facilities and energy marketing operations of Generation, a 49.5% interest in two power stations in Mexico and the competitive retail sales business of Exelon Energy Company (Exelon Energy).

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Generation was formed in 2000 as a Pennsylvania limited liability company. Generation began operations as a result of a corporate restructuring effective January 1, 2001 in which Exelon separated its generation and other competitive businesses from its regulated energy delivery business at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-6900.

Upon completion of Exelon’s proposed merger with PSEG, the generation business of PSEG known as PSEG Power will be merged into Generation, which will be the surviving entity and PSEG Power will cease to exist. As of December 31, 2005, PSEG Power had total assets of $9 billion and $3 billion of outstanding debt which is currently anticipated to become part of Generation’s consolidated debt. In addition, as part of the FERC approval of the Merger, Generation has proposed a market concentration mitigation plan involving the divestiture of 4,000 MW of coal, mid-merit and peaking generation in the PJM region and the ongoing auction of 2,600 MW of nuclear output, and the interim mitigation of fossil generation pending divestiture.

Federal and State Regulation

Exelon is subject to Federal and state regulation. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the ICC. PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the PAPUC. ComEd, PECO and Generation are electric utilities under the Federal Power Act subject to regulation by the FERC. Specific operations of Exelon are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC.

Exelon was a registered holding company and subject to a number of restrictions under the Public Utility Holding Company Act of 1935 (PUHCA) until the repeal of PUHCA, effective on February 8, 2006, pursuant to the Energy Policy Act of 2005 (the Energy Policy Act). Those restrictions involved financings, investments and affiliate transactions. Exelon had an order under PUHCA authorizing financing transactions for Exelon and the other Registrants within certain limits. With the repeal of PUHCA, the SEC’s financing jurisdiction under PUHCA for ComEd’s and PECO’s short-term financings and Generation’s financings reverted to FERC. Exelon’s financings are not subject to FERC jurisdiction. For additional information concerning regulatory approvals required for the Registrant’s financings, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources. Exelon also had an order under PUHCA authorizing development activities, the formation of new intermediate subsidiaries for internal corporate structuring, internal corporate reorganizations, and investments in certain non-United States (U.S.) energy-related subsidiaries. With the repeal of PUHCA, Exelon is no longer subject to these restrictions. PUHCA also limited the businesses in which Exelon could engage and the investments that Exelon could make, and required that Exelon’s utility subsidiaries constituted a single system that could be operated in an efficient, coordinated manner. With the repeal of PUHCA these restrictions are no longer applicable to Exelon.

Under the Energy Policy Act, FERC obtained additional jurisdiction for merger review and for the review of affiliate transactions, intercompany financings and cash management arrangements, certain internal corporate reorganizations, and certain holding company acquisitions of public utility and holding company securities. To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation, the repeal of PUHCA enhanced the authority of states to regulate Exelon and its utility subsidiaries.

For additional information about Federal and state restrictions on Exelon and its subsidiaries, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon.

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ComEd and PECO

Exelon’s regulated energy delivery operations consist of ComEd and PECO.

ComEd is engaged principally in the purchase, transmission, distribution and sale of electricity to a diverse base of residential, commercial, industrial and wholesale customers in northern Illinois. ComEd is subject to extensive regulation by the ICC as to rates and service, the issuance of securities, and certain other aspects of ComEd’s operations. ComEd is also subject to regulation by the FERC as to transmission rates and certain other aspects of ComEd’s business.

ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of eight million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.7 million customers.

ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generally nonexclusive rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights have stated expiration dates ranging from 2007 to 2061 and subsequent years. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

PECO is engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania and the purchase, distribution and sale of natural gas to residential, commercial and industrial customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO is subject to extensive regulation by the PAPUC as to electric and gas rates and service, the issuances of certain securities and certain other aspects of PECO’s operations. PECO is also subject to regulation by the FERC as to transmission rates and certain other aspects of PECO’s business.

PECO’s retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.8 million. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.7 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to the City of Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 472,000 customers.

PECO has the necessary authorizations to furnish regulated electric and gas service in the various municipalities or territories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued by the PAPUC and/or “grandfather rights.” These rights are generally unlimited as to time and are generally exclusive from competition from other electric and gas utilities. In a few defined municipalities, PECO’s gas service territory authorizations overlap with that of another gas utility but PECO does not consider those situations as posing a material competitive or financial threat.

ComEd’s and PECO’s kilowatthour (kWh) sales and load of electricity are generally higher during the summer periods and winter periods, when temperature extremes create demand for either summer cooling or winter heating. ComEd’s highest peak load occurred on August 21, 2003 and was 22,054 megawatts (MWs); its highest peak load during a winter season occurred on December 19, 2005 and was 16,081 MWs. PECO’s highest peak load occurred on July 27, 2005 and was 8,626 MWs; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MWs.

PECO’s gas sales are generally higher during the winter periods when cold temperatures create demand for winter heating. PECO’s highest daily gas send out occurred on January 17, 2000 and was 718 million cubic feet (mmcf).

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Retail Electric Services

Electric utility restructuring legislation was adopted in Pennsylvania in December 1996 and in Illinois in December 1997. Both Illinois and Pennsylvania permit competition by alternative generation suppliers for the supply of retail electricity while transmission and distribution service remains regulated. The legislation and related regulatory orders in both states allow customers to choose an alternative electric generation supplier; required rate reductions and imposed freezes or caps on rates during a transition period following the adoption of the legislation; and allow the collection of competitive transition charges (CTCs) from customers to recover a portion of the costs that might not otherwise be recovered in a competitive market (stranded costs) during the transition period.

Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers, except for certain large customers of ComEd, who do not or cannot choose an alternative supplier. Provider of last resort (POLR) obligations refer to the obligation of a utility to provide bundled services to those customers who do not take service from an alternative retail electric supplier or who choose to return to the utility after taking service from an alternative supplier. Because the choice generally lies with the customer, POLR obligations make it difficult for the utility to predict and plan for the level of customers and associated electricity demanded.

ComEd. All of ComEd’s customers are eligible to choose an alternative retail electric supplier and most non-residential customers can also elect the power purchase option (PPO) that allows the purchase of electricity from ComEd at market-based prices. As of December 31, 2005, one alternative electric supplier has approval from the ICC to serve residential customers in Illinois; however, no residential customers have actually selected an alternative electric supplier. At December 31, 2005, approximately 21,300 non-residential customers, representing approximately 33% of ComEd’s annual retail kilowatthour sales, had elected to purchase their electricity from an alternative electric supplier or had chosen the PPO. Customers who receive electricity from an alternative electric supplier and customers who have elected the PPO continue to pay a delivery charge to ComEd, which generally includes a CTC. Assuming ComEd is able to fully collect its costs of delivering electric service, there should be minimal long-term impact of customer choice on its results of operations. On January 24, 2006, the ICC unanimously approved the reverse-auction process as described below under “Illinois Procurement Filing,” with some modifications to enhance consumer protections and provide additional regulatory oversight. This approval, which is subject to rehearing and appeal, should provide ComEd with stability and greater certainty that it will be able to procure energy through the auction process and pass through the costs of that energy to ComEd’s customers beginning in 2007 through a transparent market mechanism in the reverse-auction process. ComEd petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. ComEd has offered to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. See risk factor “ComEd may be required to sell energy at capped rates while buying energy at market rates, which are more volatile and potentially higher” in ITEM 1A. Risk Factors for further details.

In addition to retail competition for generation services, the Illinois legislation provided for phased residential base rate reductions totaling 20%, a sharing with customers of any earnings over a defined threshold and a base rate freeze, reflecting the residential base rate reductions, through January 1, 2007. A utility may request a rate increase during the rate freeze period only when the return on equity falls beneath a defined floor to ensure the utility’s financial viability. Under the Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on a two-year average of the Monthly U.S. Treasury Long-Term Average Bond Rates (20 years and above) plus 8.5% in the years 2000 through 2006. Earnings for purposes of ComEd’s threshold include ComEd’s net income calculated in accordance with accounting principles generally accepted in the United States (GAAP) and reflect the

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amortization of regulatory assets. Under the Illinois statue, any impairment of goodwill has no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2005, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $43 million, which will be fully recovered and amortized during 2006. ComEd has not triggered the earnings sharing provision through 2005 and does not currently expect to trigger the earnings sharing provision in 2006.

ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2006. The base rate freeze, coupled with other provisions of the Illinois restructuring law, generally precludes rate recovery of and on such incremental investments prior to January 1, 2007. Unless ComEd can offset the additional carrying costs against cost reductions, its return on investment will be reduced during the remaining period of the rate freeze and until rate increases, post 2006, are approved authorizing a return of and on this new investment.

Illinois Procurement Filing. In 2004, the ICC initiated and conducted a workshop process to consider issues related to retail electric service in the post-transition period (i.e., post 2006). Issues addressed included utility wholesale electricity procurement methodology, rates, competition and utility service obligations and energy assistance programs. All interested parties were invited to participate. The end result was a report from the ICC to the Illinois General Assembly that was generally supportive of utilities competitively procuring electricity through a reverse-auction process with full recovery of the supply costs from retail customers. In the proposed reverse-auction model, qualified energy suppliers would compete in a transparent, fair and structured auction to provide electricity to the utilities and their customers; winning bidders would provide the electricity needed at the price determined by the auction’s results; and the utilities would make no profit on the electricity but would recover from customers the price of procurement. The ICC staff would oversee the entire process.

On February 25, 2005, ComEd filed with the ICC seeking regulatory approval of tariffs that implement the methodologies supported by the report, including a proposal consistent with the reverse-auction process described above (the Procurement Case). As requested by ComEd, the ICC initiated hearings on the matter. The Illinois Attorney General, Citizens’ Utility Board (CUB), Cook County State’s Attorney’s Office and the Environmental Law and Public Policy Center subsequently filed a motion to dismiss the proceeding arguing that customers whose retail service has not been declared competitive are entitled to cost-based rates for electricity and delivery and that the ICC lacked authority to approve rates based on the market value of electricity, as proposed by ComEd. On June 1, 2005, the administrative law judge denied the motion and, on July 13, 2005, the ICC denied the appeal. On December 5, 2005, the administrative law judge issued a proposed order that recommended that the ICC approve the competitive procurement process similar to the ComEd proposal. The administrative law judge reaffirmed an earlier ruling that the ICC has legal authority under the Public Utility Act to approve an auction process and the resulting rates. The proposed order also increased the regulatory oversight of the process.

On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. The procurement process is similar to the process described in the Procurement Case and the administrative law judge’s order described above, with some modifications to enhance consumer protection. The auction will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during the fall of 2006, at which time ComEd’s entire load will be up for bid. To mitigate the effects of changes in future prices, the load will be staggered in three-year contracts. To further mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. A cap and deferral proposal, generally speaking, would limit the procurement costs that ComEd could pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years.

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Several parties that were opposed to the Procurement Case have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is also possible that interested parties could introduce legislation in Illinois in an attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue.

On September 1, 2005, the Illinois Attorney General, the Cook County State’s Attorney, CUB and the Environmental Law and Public Policy Center filed a two-count complaint in the Chancery Division of the Circuit Court of Cook County against the ICC and the individual ICC commissioners (the Procurement Litigation). The Procurement Litigation sought to block the ICC from approving the Procurement Case on the theory that the ICC lacked the authority to approve the rates because not all of the services that will be provided under the Procurement Case have been declared competitive and do not qualify for market-based rates. The legal argument underlying the Procurement Litigation is substantially similar to the legal argument that was presented to the administrative law judge, and to the ICC on appeal, and rejected by both, in the third quarter of 2005. ComEd intervened in the Procurement Litigation to deny the allegations in the complaint and sought a determination that the ICC has appropriate legal authority to approve the proposed electricity procurement process pending before the ICC in the Procurement Case. ComEd moved for summary judgment in the litigation, and the ICC moved to dismiss one claim in the litigation and for summary judgment on the other claim. A hearing on the motions was held on December 14, 2005 and the court issued a written order on January 20, 2006 denying the relief sought by the plaintiffs and dismissing the case with prejudice.

On October 17, 2005, ComEd and Generation filed an application with the FERC seeking approval that the proposed Illinois auction process meets FERC principles and that if Generation is selected as a winning bidder in the Illinois auction, the standard agreements under which Generation would sell energy, capacity and ancillary services to ComEd would be acceptable to the FERC. On December 16, 2005, the FERC issued an order granting both requests.

In November 2005, ComEd announced several actions intended to affirm the fact that ComEd is an independent entity, separate and distinct from its parent Exelon, and to strengthen ComEd’s ability to successfully manage some potentially challenging financial and strategic issues as Illinois continues its transition to restructuring after 2006. The actions include the election of a new board of directors of ComEd and selection of senior officers. The senior officers have responsibilities solely for ComEd.

The ICC, in its Order approving the Procurement Case, also ordered its Staff to “present orders initiating three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources to the Commission within thirty (30) days of the entry of this Order.” ComEd intends to participate in any such rulemakings.

Illinois Rate Case. On August 31, 2005, ComEd filed a rate case with the ICC, which seeks, among other things, to allocate the costs of delivering electricity and to adjust ComEd’s rates for delivering electricity effective January 2, 2007 (Rate Case). Several intervenors in the Rate Case, including the ICC staff and the Illinois Attorney General, have suggested, and provided testimony, that ComEd’s rates should actually be reduced. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC order in the Procurement Case, assuming the ICC order on this matter is upheld upon appeal. The results of the Rate Case are not expected to be known until at least the third quarter of 2006.

ComEd cannot predict the results of the Rate Case before the ICC or whether the Illinois General Assembly might take action that could have a material impact on the outcome of the regulatory process. However, if the price at which ComEd is allowed to sell electricity beginning in 2007 is below

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ComEd’s cost to procure and deliver electricity, there may be material adverse consequences to ComEd and, possibly, Exelon. Exelon and ComEd believe that these potential material adverse consequences could include, but may not be limited to, loss of ComEd’s investment grade credit rating and a possible reduction in the other Registrants’ credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term electricity procurement contracts, which would likely force ComEd to procure electricity at more volatile and potentially higher prices in the spot market. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the nearer term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible. ComEd also cannot predict the long-term impact of customer choice for electricity supply on its results of operations.

The Illinois restructuring legislation also provided for the collection of a CTC from customers who choose to purchase electricity from an alternative electric supplier or elect the PPO during the transition period which extends through 2006. The CTC is applied on a cents per kWh basis and considers the revenue that would have been collected from a customer under tariffed rates as reduced by the revenue the utility will receive for providing delivery services to the customer, the market price for electricity and a defined mitigation factor, which represents the utility’s opportunity to develop new revenue sources and achieve cost reductions. The CTC allows ComEd to recover some of its costs that might otherwise be unrecoverable under market-based rates.

ComEd’s market value energy credit is used to determine the price for specified market-based rate offerings and the amount of the CTC that ComEd is allowed to collect from customers who select an alternative electric supplier or the PPO. The credit has the effect of reducing ComEd’s CTCs to customers. The current annual market price adjustment reflects forward, rather than historical, market prices for electricity and allows customers to lock in current levels of CTCs for the remainder of the regulatory transition period ending in 2006.

In 2005 and 2004, ComEd collected $105 million and $169 million in CTC revenues, respectively. ComEd estimates that CTC revenue will range from $35 million to $50 million in 2006.

The Illinois restructuring legislation provides that an electric utility, such as ComEd, will be liable for actual damages suffered by customers in the event of a continuous electricity outage of four hours or more affecting 30,000 or more customers and provides for reimbursement of governmental emergency and contingency expenses incurred in connection with any such outage. The legislation bars recovery of consequential damages. The legislation also allows an affected utility to seek relief from these provisions from the ICC when the utility can show that the cause of the outage was unpreventable due to weather events or conditions, customer tampering or third-party causes. During the years 2005, 2004 and 2003, ComEd did not have any outages that triggered the reimbursement requirement.

ComEd has a purchase power agreement (PPA) with Generation under which ComEd obtains substantially all of its electric supply from Generation through 2006. Prices for this electricity vary depending on the time of day and month of delivery.

PECO. Under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), all of PECO’s retail electric customers have the right to choose their generation suppliers. At December 31, 2005, approximately 1% of PECO’s residential load, 13% of its small commercial and industrial load and 1% of its large commercial and industrial load were purchasing

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generation service from alternative generation suppliers. Customers who purchase electricity from an alternative electric supplier continue to pay a delivery charge to PECO.

In addition to retail competition for generation services, PECO’s 1998 settlement of its restructuring case mandated by the Competition Act established caps on generation and distribution rates. The 1998 settlement also authorized PECO to recover $5.3 billion of stranded costs and to securitize up to $4.0 billion of its stranded cost recovery, which was subsequently increased to $5.0 billion.

Under the 1998 settlement, PECO’s distribution and transmission rates were capped through June 30, 2005 at the level in effect on December 31, 1996. Generation rates, consisting of the charge for stranded cost recovery and a shopping credit or capacity and energy charge, were capped through December 31, 2010. For 2005, the generation rate cap was $0.0698 per kWh, increasing to $0.0751 per kWh in 2006 and $0.0801 per kWh in 2007. The rate caps are subject to limited exceptions, including significant increases in Federal or state taxes or other significant changes in law or regulations that would not allow PECO to earn a fair rate of return. Under the settlement agreement entered into by PECO in 2000 relating to the PAPUC’s approval of the merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (PECO / Unicom Merger), PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005 and extended the rate cap on distribution and transmission rates through December 31, 2006.

Partial Settlement before the PAPUC. On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The settlement reflected the conclusion of a process involving the majority of PECO customer groups during which PECO’s cost data, return on equity and estimated Merger synergies were reviewed. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement rate reductions aggregating $120 million during a four-year period and to cap its rates through the end of 2010. During the rate cap period, the PAPUC retains the right to lower PECO’s rates if they are found to be excessive, and PECO retains the right to seek rate increases if certain events (such as significant increases in Federal or state income taxes or other significant changes in law or regulation that do not allow PECO to earn a fair rate of return) occur. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. By separate motion, the PAPUC also indicated its intent to initiate a separate investigation, to which PECO had agreed in the partial settlement, to examine issues related to a potential combination of Philadelphia Gas Works, which provides gas distribution service in the City of Philadelphia, into Exelon’s gas distribution businesses. This investigation will commence no earlier than 30 days after the close of the Merger. The outcome of this potential examination is uncertain. However, Exelon does not believe that the PAPUC has the authority to compel such a transaction if the two parties do not agree to terms through arms length negotiations. See General—Proposed Merger with Public Service Enterprise Group Incorporated above and Note 4 of Exelon’s Notes to Consolidated Financial Statements for further discussion.

As a mechanism for utilities to recover their allowed stranded costs, the Competition Act provides for the imposition and collection of non-bypassable transition charges on customers’ bills. Transition charges are assessed to and collected from all retail customers who have been assigned stranded cost responsibility and access the utility’s transmission and distribution systems. As the transition charges are based on access to the utility’s transmission and distribution system, they are assessed regardless of whether the customer purchases electricity from the utility or an alternative electric supplier. The Competition Act provides, however, that the utility’s right to collect transition charges is contingent on the continued operation, at reasonable availability levels, of the assets for which the stranded costs

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were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.

As mentioned above, PECO has been authorized by the PAPUC to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010, with a return on the unamortized balance of 10.75%. At December 31, 2005, the unamortized balance of PECO’s stranded costs, or CTC regulatory asset, was $3.5 billion. The following table shows PECO’s allowed recovery of stranded costs, and amortization of the associated regulatory asset, for the years 2006 through 2010 as authorized by the PAPUC based on the level of transition charges established in the settlement of PECO’s restructuring case and the projected annual retail sales in PECO’s service territory. Recovery of transition charges for stranded costs and PECO’s allowed return on its recovery of stranded costs are included in revenues. To the extent the actual recoveries of transition charges in any one year differ from the authorized amount set forth below, an annual reconciliation adjustment to the transition charges rate is made to increase or decrease the subsequent year’s collections accordingly, except during 2010, in which the reconciling adjustments are made quarterly or monthly as needed.

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

PECO has a PPA with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. The price for this electricity is essentially equal to the energy revenues earned from customers as specified by PECO’s 1998 settlement of its restructuring case mandated by the Competition Act. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

Regulations applicable to all Pennsylvania electric utilities’ POLR obligations are being developed by the PAPUC. PECO will continue to monitor the developments of these regulations.

In November 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004. For more information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” below.

Transmission Services

ComEd and PECO provide wholesale and unbundled retail transmission service under rates established by the FERC. The FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. Under the FERC’s open transmission access policy promulgated in Order No. 888,

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ComEd and PECO, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. Under the FERC’s Order No. 889, ComEd and PECO are required to comply with the FERC’s Standards of Conduct regulation, as amended, governing the communication of non-public information between the transmission owner’s transmission employees and wholesale merchant employees or the employees of any energy affiliate of the transmission owner. The FERC’s amendments to the Standards of Conduct regulation under Order No. 2004 do not detrimentally affect Exelon’s business.

PJM Interconnection, LLC (PJM) is the independent system operator and the FERC-approved regional transmission organization (RTO) for the Mid-Atlantic and Midwest regions in which it operates. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM Interchange Energy Market and Capacity Credit Markets, and controls through central dispatch the day-to-day operations of the bulk power system of the PJM region. ComEd and PECO are members of PJM and provide regional transmission service pursuant to the PJM tariff. ComEd, PECO and the other transmission owners in PJM have turned over control of their transmission facilities to PJM and their transmission systems are currently under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service.

The FERC has attempted to expand the development of regional markets, which has generated substantial opposition from some state regulators and other governmental bodies. In addition, efforts to develop an RTO have been abandoned in certain regions. Notwithstanding these difficulties, the Midwest Independent System Operator, Inc. (MISO), has been certified as an RTO by FERC. MISO is attempting to develop central generation dispatch and transmission operations across the Midwestern United States, contiguous to PJM’s footprint. The FERC has ordered the elimination of rate barriers and protocol differences between MISO and PJM. Exelon supports the development of RTOs and implementation of standard market protocols.

In November 2004, the FERC issued two orders authorizing ComEd and PECO to recover amounts as a result of the elimination of through and out (T&O) rates for transmission service scheduled out of or across their respective transmission systems and ending within pre-expansion PJM or MISO territories. T&O rates were terminated pursuant to FERC orders effective December 1, 2004. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), are collected from load-serving entities within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. As load-serving entities, ComEd and PECO are also required to pay SECA rates based on the benefits they receive from the elimination of T&O rates of other transmission owners within PJM and MISO. On June 16, 2005, FERC issued an order setting a hearing to address SECA cost recovery issues, and consolidated that proceeding with a proceeding to address long-term transmission rate design.

Amounts collected under the SECA rates are subject to refund and surcharge and the ultimate outcome of the proceeding establishing SECA rates is uncertain.

Gas

PECO’s gas sales and gas transportation revenues are derived pursuant to rates regulated by the PAPUC. PECO’s purchased gas cost rates, which represent a portion of total rates, are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased gas and the amount included in rates.

PECO’s gas customers have the right to choose their gas suppliers or to purchase their gas supply from PECO at cost. Approximately 32% of PECO’s current total yearly throughput is provided by gas suppliers other than PECO and is related primarily to the supply of PECO’s large commercial

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and industrial customers. Gas transportation service provided to customers by PECO remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services.

PECO’s natural gas supply is provided by purchases from a number of suppliers for terms of up to eight years. These purchases are delivered under several long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 44.6 million dekatherms. Peak gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 22.0 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 33% of PECO’s 2005-2006 heating season planned supplies.

Construction Budget

ComEd’s and PECO’s businesses are capital intensive and require significant investments in energy transmission and distribution facilities, and in other internal infrastructure projects. The following table shows the most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2006:

Approximately 50% of the projected 2006 capital expenditures at ComEd and PECO are for continuing efforts to maintain and improve the reliability of their transmission and distribution systems. The remainder of the capital expenditures support customer and load growth.

Generation

Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MWs. Generation combines its large generation fleet with an experienced wholesale power marketing operation and the competitive retail sales business of Exelon Energy, which became part of Generation effective as of January 1, 2004.

At December 31, 2005, Generation owned generation assets with a net capacity of 25,099 MWs, including 16,856 MWs of nuclear capacity. In addition, Generation controlled another 8,191 MWs of capacity through long-term contracts.

Generation’s wholesale marketing unit, Power Team, a major wholesale marketer of energy, uses Generation’s energy generation portfolio, transmission rights and expertise to ensure delivery of energy to Generation’s wholesale customers under long-term and short-term contracts, including the load requirements of ComEd and PECO. In addition, Power Team markets energy in the wholesale bilateral and spot markets.

Exelon Energy provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Michigan and Ohio. Exelon Energy’s business is dependent upon continued deregulation of retail electric and gas markets and its ability to obtain supplies of electricity and gas at competitive prices in the wholesale market. The low-margin nature of the business makes it important to service customers with higher volumes so as to manage costs.

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Generating Resources

At December 31, 2005, the generating resources of Generation consisted of the following:

The owned generating resources of Generation are located in the Midwest region (approximately 45% of capacity), the Mid-Atlantic region (approximately 44% of capacity), the Southern region (approximately 9%), and the Northeast region (approximately 2% of capacity). The 8,191 MWs of capacity that Generation controls through long-term contracts are in the Midwest, Southeast and South Central regions.

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe Energies, Inc. (Sithe). Specifically, subsidiaries of Generation closed on the acquisition of Reservoir Capital Group’s 50% interest in Sithe and the sale of 100% of Sithe to Dynegy, Inc. (Dynegy). Prior to closing on the sale to Dynegy, subsidiaries of Generation received approximately $65 million in cash distributions from Sithe. As a result of the sale, Exelon and Generation deconsolidated approximately $820 million of debt from their balance sheets and were released from approximately $125 million of credit support. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the sale of Sithe.

The sale of Sithe did not include Tamuin International Inc., (formerly Sithe International, Inc.), which was sold to a subsidiary of Generation on October 13, 2004. Tamuin International, Inc., through its subsidiaries, has a 49.5% interest in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico.

Nuclear Facilities

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with 16,856 MWs of capacity. For additional information, see ITEM 2. Properties. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at the Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. AmerGen, wholly owned by Generation, operates the Clinton Nuclear Power Station, the Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek).

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Effective January 17, 2005, Generation began overseeing daily plant operations at Salem and Hope Creek nuclear generating stations through an Operating Services Contract (OSC) with PSEG Nuclear. Hope Creek is a nuclear generating station wholly owned by PSEG Nuclear. Under the OSC, PSEG Nuclear remains as the license holder with exclusive legal authority to operate and maintain the plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities.

In 2005, 71% of Generation’s electric supply was generated from the nuclear generating facilities. During 2005 and 2004, the nuclear generating facilities operated by Generation achieved a 93.5% capacity factor.

During 2004, both Quad Cities’ units operated only intermittently at Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. As of the third quarter of 2005, both of the Quad Cities’ units returned to EPU generation levels after extensive testing and load verification on new replacement steam dryers was completed.

Near the end of 2005, the generation levels of both Quad Cities’ units were again reduced to pre-EPU generation levels to address vibration–related equipment issues not directly related to the steam dryers. The units will be brought back to full EPU generation levels after all issues are addressed to ensure safe and reliable operations at the EPU output levels which is expected to occur in 2006.

In 2004, Generation joined a consortium of eleven companies, NuStart Energy Development, LLC (NuStart), which was formed for the purpose of seeking a license to build a new nuclear facility under the NRC’s new permitting process. As of December 31, 2005, Generation’s investment in NuStart was $2 million.

Regulation of Nuclear Power Generation. Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing of operation of each station. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures for nuclear generating facilities and/or increased operating costs of nuclear generating units.

NRC reactor oversight results, as of December 31, 2005, indicate that the performance indicators for the nuclear plants operated by Generation are all in the highest performance band.

Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for Peach Bottom Units 2 and 3, Dresden Units 2 and 3, and Quad Cities Units 1 and 2. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal was filed July 22, 2005, in compliance with this order. Generation is currently evaluating its other nuclear units for possible license renewal. The operating license renewal process takes approximately four to five years from the commencement of the project until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the current license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which assume the renewal of the operating licenses for all of Generation’s operating nuclear generating stations. In the first quarter of 2005, Generation applied the same depreciation estimated useful life assumption to its ownership share in the Salem Generating Station.

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The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:

Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel (SNF) currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by nuclear generating facilities in on-site storage pools and, in the case of Peach Bottom, Oyster Creek, Dresden and Quad Cities, some SNF has been placed in dry cask storage facilities. Not all of Generation’s SNF storage pools have sufficient storage capacity for the life of the respective plant. Generation is developing dry cask storage facilities, as necessary, to support operations.

As of December 31, 2005, Generation had approximately 44,792 SNF assemblies (10,402 tons) stored on site in SNF pools or dry cask storage. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites. The following table describes the current status of Generation’s SNF storage facilities.

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Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE’s current estimate for opening a SNF permanent disposal facility is 2012. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Peach Bottom and Oyster Creek Stations and its consideration of dry cask storage at other stations. See Note 13 of Exelon’s Notes to Consolidated Financial Statements and Note 13 of Generation’s Notes to Consolidated Financial Statements for additional information regarding spent fuel storage claims and issues.

During 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement of a suit originally commenced by ComEd in 1998. Under the settlement, the government has agreed to reimburse Exelon for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfilment of its obligations to take possession of SNF. Under the settlement agreement, Generation received $80 million in gross reimbursements for storage costs already incurred ($53 million net, after considering amounts due from Exelon to co-owners of certain nuclear stations). In 2005, Generation received $58 million in gross reimbursements for storage costs incurred between October 1, 2003 and June 30, 2005, ($35 million net, after considering amounts due from Exelon to co-owners and previous owners of certain nuclear stations). Generation plans to submit annual reimbursement requests for costs associated with the storage of spent nuclear fuel. In all cases, reimbursement requests will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to pay the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2005, the unfunded liability for the one-time fee with interest (which has been assumed by Generation) was $906 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2005, was 3.983%. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owners. The Clinton Unit has no outstanding obligation.

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

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

The National Energy Policy Act of 1992 requires that the owners of nuclear reactors pay for the decommissioning and decontamination of the DOE uranium enrichment facilities. The total cost to all domestic utilities covered by this requirement was originally $150 million per year through 2006, of which Generation’s share was approximately $20 million per year. Payments are adjusted annually to reflect inflation. Including the effect of inflation, Generation paid $31 million in 2005 ($27 million net after considering amounts collected from co-owners of certain nuclear stations).

Nuclear Insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The Price-Anderson Act was extended to December 31, 2025 under the terms of the Energy Policy Act. As of December 31, 2005, the current limit was $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.46 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $15 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.

See “Nuclear Insurance” within Note 20 of Exelon’s Notes to Consolidated Financial Statements and Note 17 of Generation’s Notes to Consolidated Financial Statements for a description of nuclear-related insurance coverage.

For information regarding property insurance, see ITEM 2. Properties—Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Generation’s financial condition and results of operations.

Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. As more fully described below, both ComEd and PECO are currently collecting amounts from customers, which are ultimately remitted to the trust funds maintained by Generation that will be used to decommission nuclear facilities. The AmerGen facilities are not covered by ComEd, PECO or any other rate recovery of decommissioning funding from customers. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current operating licenses and anticipated license renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029.

Under the ICC order, ComEd is permitted to recover up to $73 million per year through 2006 from customers to decommission former ComEd nuclear plants. Collections are limited based on the ratio of electricity purchased by ComEd to the total amount generated from those units. In 2005, decommissioning revenues collected from ComEd customers totaled approximately $68 million and are expected to be approximately the same in 2006. Under the current ICC order, ComEd is not permitted to collect amounts for decommissioning subsequent to 2006. Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be

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recovered currently through rates charged by PECO to customers. Amounts recovered, currently $33 million per year, are remitted to Generation as allowed by the PAPUC. The PAPUC will allow PECO to collect from customers and remit to Generation, annually, through the operating life of the plants.

In 2003, the General Accounting Office (GAO) published a study on the NRC’s need for more effective analyses to ensure the adequate accumulation of funds to decommission nuclear power plants in the United States. See the risk factor “Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of nuclear facilities” for further detail. Generation has reviewed the GAO’s report and believes that, in reaching its conclusions, the GAO did not consider all aspects of Generation’s decommissioning strategy, such as fund growth during the decommissioning period. The inclusion of estimated earnings growth on Generation’s nuclear trust funds during the decommissioning period virtually eliminates any funding shortfalls identified in the GAO report.

Generation believes that the amounts currently being collected from ComEd and PECO, coupled with Generation’s nuclear decommissioning trust funds and the expected investment earnings thereon will be sufficient to fully fund Generation’s decommissioning obligations. AmerGen maintains decommissioning trust funds for each of its plants in accordance with NRC regulations. Generation believes that amounts in these trust funds together with expected investment earnings thereon will be sufficient to fully fund AmerGen’s decommissioning obligations.

See Critical Accounting Policies and Estimates within ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Generation for a further discussion of nuclear decommissioning.

Zion, a two-unit nuclear generation station, Peach Bottom Unit 1 and Dresden Unit 1 have permanently ceased power generation. SNF at Zion and Dresden Unit 1 is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. All of Peach Bottom Unit 1’s SNF has been moved off site. Generation has recorded a liability totaling $766 million at December 31, 2005, which represents the estimated cost of decommissioning Zion, Peach Bottom Unit 1 and Dresden Unit 1 in current year dollars. Certain decommissioning costs are currently being incurred; however, the majority of decommissioning expenditures are expected to occur primarily after 2013, 2033 and 2031 for Zion, Peach Bottom Unit 1 and Dresden Unit 1, respectively.

Fossil and Hydroelectric Facilities

Generation operates various fossil and hydroelectric facilities and maintains ownership interest in several other facilities such as LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2005, approximately 7% of Generation’s electric supply was generated from Generation’s owned fossil and hydroelectric generating facilities. The majority of this output was dispatched to support Generation’s power marketing activities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. Properties—Generation.

Licenses. Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. Hydroelectric plants are licensed by the FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is in the process of performing pre-application analyses and anticipates filing a Notice of Intent to renew the licenses in 2009 pursuant to FERC regulations.

Insurance. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. For its other types of insured losses, Generation is self-insured to

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the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon and Generation’s financial condition and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. Properties—Generation.

Long-Term Contracts

In addition to energy produced by owned generation assets, Generation sells electricity purchased under the long-term contracts described below:

Federal Power Act

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

Because Generation sells power in the wholesale markets, Generation is a public utility for purposes of the Federal Power Act and is required to obtain the FERC’s acceptance of the rate schedules for wholesale sales of electricity. In 2000, Generation received authorization from the FERC to sell power at market-based rates. As is customary with market-based rate schedules, the FERC reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determined that Generation or any of its affiliates violated the terms and conditions of its tariff or the Federal Power Act. The FERC is also authorized to order refunds if it finds that the market-based rates are not just and reasonable under the Federal Power Act.

For a number of years, the FERC has been encouraging the voluntary formation of RTOs, such as PJM, to provide transmission service across multiple transmission systems. The intended benefits of establishing these entities include managing transmission congestion, developing larger wholesale markets for energy and capacity, and the elimination or reduction of transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity.

To date, PJM, the Midwest ISO, and ISO New England, have been approved as RTOs. Because of some states’ opposition to imposition of centralized energy and capacity markets, the new FERC Chairman has been seeking to enhance the independence of transmission operations without the overlay of centralized markets.

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Exelon supports the development of RTOs and implementation of standard market protocols but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The FERC issued a final rule establishing standardized generator interconnection policies and procedures. Under this interconnection policy generators will benefit from not having to deal on a case-by-case basis with different and sometimes inconsistent requirements of different transmission providers.

In 2004, the FERC implemented market power tests for suppliers to qualify to sell power at market-based rates. These new tests, the market share test and the pivotal supplier test, must both be passed by Generation, or market power mitigation must be imposed for Generation to continue to make sales of capacity and energy in the wholesale market at market-based rates. The FERC allows the relevant geographic market to include a RTO’s footprint, and Generation used an expanded PJM footprint as the relevant market.

On July 5, 2005, the FERC approved Generation’s continued authority to charge market-based rates for wholesale sales of electricity, including to its affiliates ComEd and PECO. In the same order, the FERC stated that Generation had failed to address the affiliate abuse prong of the FERC’s market-based rate eligibility test and used that statement as the basis for instituting a proceeding under the provision of the Federal Power Act, Section 206 and establishing a refund effective date of July 26, 2005 in the event that the FERC ultimately found that Generation did not, in fact, qualify for market-based rates. The FERC ordered Generation to make a compliance filing within 30 days of the order addressing the affiliate abuse and reciprocal dealing prong of the market-based rate test.

On August 4, 2005, Generation filed a Petition for Rehearing asking the FERC to rescind the part of its market-based rate order that had opened a Section 206 investigation into the issue of affiliate abuse and had established a refund effective date. Generation had addressed the affiliate abuse issue in its original November 2003 triennial update filing. The September 2004 filing had addressed only the new generation market power issue, as the FERC had directed. In the August 2005 filing, Generation noted the original reference in the September 2004 filing to the fact that the FERC had previously found that circumstances existed that guarded against affiliate abuse. Generation further noted that as of both the September 2004 and August 2005 filings there had been no change in the circumstances cited in the FERC’s original order granting authority to Generation to sell electricity at market-based rates. Generation’s pleading asked the FERC to either grant the rehearing request or to consider the August filing to be the required compliance filing.

The July 2005 market-based rate order also directed Exelon to make compliance filings within 30 days of the order amending the market-based rate tariffs of Exelon’s various subsidiaries to include prohibiting sales of electricity to Public Service Electric and Gas Company (PSE&G), PSEG’s regulated utility, unless specific authority were sought for such sales under Section 203 of the Federal Power Act. These compliance filings were made in accordance with the Order.

The Energy Policy Act of 2005. The Energy Policy Act, which was signed into law on August 8, 2005, implements several significant changes intended to improve electric reliability, promote investment in electric facilities, streamline electric regulation, improve wholesale competition, address problems identified in the western energy crisis and Enron collapse, promote fuel diversity and cleaner fuel sources, and promote greater efficiency in electric generation, delivery and use.

The Energy Policy Act, through amendment of the Federal Power Act, also transfers to the FERC certain additional authority. The FERC obtains new authority to review the acquisition or merger of generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. The FERC now has the authority to approve siting of electric transmission facilities located in national interest electric transmission corridors if states cannot or will not act in a timely manner to approve siting. The Energy Policy Act also creates a self-regulating electric reliability organization with the FERC oversight to enforce reliability rules.

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Fuel

The following table shows sources of electric supply in gigawatthours (GWhs) for 2005 and estimated for 2006:

The fuel costs for nuclear generation are substantially less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its commitment to supply the requirements of ComEd and PECO, some of Exelon Energy’s requirements, and for sales to other utilities.

The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2008. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2008. All of Generation’s enrichment requirements have been contracted through 2010. Contracts for fuel fabrication have been obtained through 2008. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for its nuclear units.

Generation obtains approximately 40% of its uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. alleging dumping in the United States against European enrichment services suppliers. In January 2002, the U.S. International Trade Commission determined that USEC, Inc. was “materially injured or threatened with material injury” by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC, Inc. and the European suppliers have appealed these decisions. Generation is uncertain at this time as to the outcome of the pending appeals; however, as a result of these actions, Generation may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.

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

Natural gas requirements for operating stations are procured through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or gas as fuel. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.

Generation uses financial instruments to mitigate price risk associated with commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments.

Power Team

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation seeks to

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maintain a net positive supply of energy and capacity, through ownership of generation assets and purchase power and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are commitments related to power generation of specific generation plants and/or are dispatchable in nature similar to asset ownership. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to customers. Power Team may buy power to meet the energy demand of its customers, including ComEd and PECO. These purchases may be made for more than the energy demanded by Power Team’s customers. Power Team then sells this open position, along with capacity not used to meet customer demand, in the wholesale energy market. Generation has also purchased transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs.

Power Team also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. The maximum length of time over which cash flows related to energy commodities are currently being hedged is three years. Generation’s hedge ratio in 2006 for its energy marketing portfolio is approximately 88%. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to ComEd’s and PECO’s retail load. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. During summer peak demand periods, the hedge ratio declines to assure Generation’s commitment to meet demand in ComEd’s and PECO’s regions. For the portion of generation supply that is unhedged, fluctuations in market price of energy will cause volatility in Generation’s results of operations.

Power Team also uses financial and commodity contracts for proprietary trading purposes but this activity accounts for only a small portion of Power Team’s efforts. The trading portfolio is subject to a risk management policy that includes stringent risk management limits including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the corporate risk management group and Exelon’s Risk Management Committee (RMC) monitor the financial risks of the power marketing activities.

At December 31, 2005, Generation’s long-term commitments relating to the purchase and sale of energy, capacity and transmission rights from and to unaffiliated utilities and others were as follows:

In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of

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delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, Generation has a PPA with PECO under which Generation has agreed to supply PECO with substantially all of PECO’s electric supply needs through 2010. PECO has also assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies electricity to PECO from the transferred generation assets, assigned PPAs and other market sources. Subsequent to 2010, PECO expects to procure all of its electricity from market sources, which could include Generation.

Capital Expenditures

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2006 are as follows:

Employees

As of December 31, 2005, Exelon and its subsidiaries had approximately 17,200 employees in the following companies:

Approximately 5,400 employees, including 3,800 employees of ComEd, 1,600 employees of Generation and 100 employees of Exelon Business Services Company (BSC), are covered by collective bargaining agreements (CBAs) with Local 15 of the International Brotherhood of Electrical Workers (IBEW Local 15). AmerGen has separate CBAs for each of its nuclear facilities, which cover an aggregate of approximately 700 employees. The Generation CBA with IBEW Local 15 has been extended to September 30, 2007. The CBA for ComEd and BSC expires on September 30, 2008. The Clinton, Oyster Creek and TMI CBAs expire on December 15, 2010, January 31, 2010 and February 28, 2009, respectively. Exelon Power, an operating unit of Generation, has an agreement with Utility Workers of America (UWA) Local 369, which expires on January 31, 2007 and covers approximately 50 employees. In addition, Exelon Power has an agreement with IBEW Local 614, which expires on January 31, 2008 and covers approximately 200 employees.

In addition to IBEW Local 15, IBEW Local 614 and the four IBEW locals covering the AmerGen facilities, approximately 40 Generation employees are represented by the Utility Workers Union of America.

During 2004, two elections were held at PECO which resulted in union representation for approximately 1,100 employees in the Philadelphia service territory. PECO and IBEW Local 614 began negotiations for an initial agreement in 2005. No agreement has been finalized to date.

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The employees of the Limerick and Peach Bottom nuclear stations are not represented by a union. On May 5, 2005, a majority of these employees elected not to be represented by the IBEW 614. The union has contested the election, which is currently under review by the National Labor Relations Board.

Environmental Regulation

General

Specific operations of Exelon, primarily those of ComEd, PECO and Generation, are subject to regulation regarding environmental matters by the United States and by various states and local jurisdictions where Exelon operates its facilities. The United States Environmental Protection Agency (EPA) administers certain Federal statutes relating to such matters, as do various interstate and local agencies. The Illinois Pollution Control Board (IPCB) has jurisdiction over environmental control in the State of Illinois, together with the Illinois Environmental Protection Agency, which enforces regulations of the IPCB and issues permits in connection with environmental control. The Pennsylvania Department of Environmental Protection (PDEP) has jurisdiction over environmental control in the Commonwealth of Pennsylvania. The Texas Commission on Environmental Quality has jurisdiction in Texas, the New Jersey Department of Environmental Protection has jurisdiction in New Jersey and the Massachusetts Department of Environmental Protection has jurisdiction in Massachusetts. State regulation includes the authority to regulate air, water and noise emissions and solid waste disposals.

Water

Under the Federal Clean Water Act, National Pollutant Discharge Elimination System (NPDES) permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated. Those permits must be renewed periodically. Generation either has NPDES permits for all of its generating stations or has pending applications for renewals of such permits while operating under an administrative extension.

In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g. cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility, and performing environmental and economic cost benefit evaluations of the potential compliance alternatives in accordance with the requirements.

In a pre-draft permit dated May 13, 2005 and a draft permit issued on July 19, 2005, as part of the pending NPDES permit renewal process for Oyster Creek, the NJDEP preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for

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Section 316(b) compliance at Oyster Creek. AmerGen has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations, but believes that other compliance options under the final Phase II rule are viable and will be analyzed as part of the plant’s comprehensive demonstration study. If application of the Section 316(b) regulations requires the retrofitting of Oyster Creek’s cooling water intake structure or system, or extensive wetlands restoration, this could result in material costs of compliance and increased depreciation expense. In addition, the amount of the costs required to retrofit Oyster Creek may negatively impact Generation’s decision to renew the operating license.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. If application of the Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

On December 16, 2005, the Illinois Environmental Protection Agency (Illinois EPA) issued a Violation Notice to Generation alleging that the company had violated state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station. In November 2005, Generation discovered that spills from the line in 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels of tritium in portions of the plume are in excess of the Illinois EPA groundwater standard. Levels in portions of the plume also exceed the Illinois EPA and Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant have shown that, with one exception, tritium levels in these wells are below levels that naturally occur. The tritium level in one drinking water well is elevated above levels that naturally occur, but is significantly below the state and federal drinking water standards, and Generation believes that this level poses no threat to human health. Generation has suspended liquid tritium discharges into the affected pipeline, and is investigating the causes of the releases to ensure that necessary corrective actions are taken to prevent another occurrence. Generation has analyzed the various remediation options for the groundwater, and submitted an initial report to the Illinois EPA on February 2, 2006. The Illinois EPA will determine the required remediation and whether a civil penalty will be assessed against Generation. Generation has notified 14 potentially affected adjacent property owners that, upon sale of their property, it will reimburse them for any diminution in property value caused by the release, and has purchased the property of one adjacent owner. As of December 31, 2005, Generation, recorded a reserve of $7 million (pre-tax) for this matter, which Generation deems adequate to cover the costs of remediation and potential related corrective measures.

Also, as a result of intensified monitoring and inspection efforts in 2006, Exelon detected a small underground tritium leak at the Dresden Generating Station and tritium concentrations in standing water within concrete vaults at the Byron Generating Station. Neither of these discharges occurred outside the property lines of the plant, nor does Exelon believe either of these matters poses health or safety threats to employees or to the public. In response to the detection of tritium in water samples taken at the aforementioned nuclear generating stations, Exelon has launched an initiative across its ten-station nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium to the environment. The assessments

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will take place in 2006 and will cover pipes, pumps, valves, tanks and other pieces of equipment that carry tritiated water in and around the plants. At this time, Exelon cannot estimate the costs that may be incurred in connection with tritium assessment initiatives or possible remediation efforts of the Dresden and Byron matters.

Generation is also subject to the jurisdiction of certain other state and interstate agencies, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.

Solid and Hazardous Waste

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

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

By notice issued in November 1986, the EPA notified over 800 entities, including ComEd and PECO, that they may be PRPs under CERCLA with respect to releases of radioactive and/or toxic substances from the Maxey Flats disposal site, a LLRW disposal site near Moorehead, Kentucky, where ComEd and PECO disposed of low level radioactive wastes resulting from their nuclear generation activities, which are now the responsibility of Generation. A settlement was reached among the Federal and private PRPs, including ComEd and PECO, the Commonwealth of Kentucky (Kentucky) and the EPA concerning their respective roles and responsibilities in conducting remedial activities at the site. Under the settlement, which was incorporated into a Federal court Consent Decree, the private PRPs agreed to perform the initial remedial work at the site and Kentucky agreed to assume responsibility for long-range maintenance and final remediation of the site. On October 5, 2003, the EPA issued a Certificate of Completion indicating that the private PRPs have completed their obligations under the Consent Decree. The site is being turned over to Kentucky as provided in the Consent Decree. The private PRPs, including Generation, will maintain oversight of Kentucky’s activities to assure the stability of the site since the private PRPs have residual liability if there is a remedy failure over the next ten years.

By notice issued in December 1987, the EPA notified several entities, including PECO, that they may be PRPs under CERCLA with respect to wastes resulting from the treatment and disposal of transformers and miscellaneous electrical equipment at a site located in Philadelphia, Pennsylvania (Metal Bank of America site). Several of the PRPs, including PECO, formed a steering committee to investigate the nature and extent of possible involvement in this matter. On May 29, 1991, a Consent Order was issued by the EPA pursuant to which the members of the steering committee agreed to perform the remedial investigation and feasibility study as described in the work plan issued with the Consent Order. PECO’s share of the cost of the study was approximately 25%. On July 19, 1995, the EPA issued a proposed plan for remediation of the site, which involves removal of contaminated soil,

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sediment and groundwater and which the EPA estimated would cost approximately $17 million to implement. On June 26, 1998, the EPA issued an order to the non-de minimis PRP group members, and others, including the owner, to implement the remedial design and remedial action. The PRP group conducted the remedial design and submitted to the EPA the revised final design on January 15, 2003.

A final settlement agreement has been reached between the EPA, the PRP group and the former owners and operators of the site. The final design estimates for the cost to implement the remedial action range from $14 million to $17 million. This amount does not include the PRP group’s future legal and technical expenses, which are not expected to be material. The settlement amount also does not include any damages for natural resource damages that the EPA or state environmental agencies may seek to obtain in the future, and at this time PECO cannot predict with reasonable certainty the likelihood that such damages will be sought or the amount of any such damages. Based on the amounts already contributed by the PRP group, it is expected that payments from the former owners and operators of the site will be sufficient to pay for the remedial action. Should any additional payments be required from the PRP group, PECO’s share would be 25%.

The parties lodged the settlement with the U.S. District Court for the Eastern District of Pennsylvania (the “District Court”). Prior to the dismissal of the litigation, the District Court must approve the settlement, after an opportunity for public comment. Following publication of a notice of the settlement and a public meeting on the settlement, the Delaware River Basin Commission, the PDEP, and the NJDEP filed petitions to intervene in the litigation. Following a conference with the judge, the proposed intervenors filed a motion with the District Court to withdraw their petitions to intervene. On January 26, 2006 the Court granted the motion and dismissed the petitions. It is expected that the District Court will approve the Consent Decrees, thereby settling the case.

Cotter Corporation

The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as PRPs, has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site ranges up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for liability from the West Lake Landfill and the litigation described under ITEM 3. Litigation—Generation. In connection with Exelon’s 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation.

MGP Sites

MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to 1950. ComEd and PECO generally did not operate MGPs as corporate entities but did, however, acquire MGP sites as part of the absorption of smaller utilities. To date, ComEd has identified 42 former MGP sites for which it may be liable for remediation. Of these 42 sites, the Illinois Environmental Protection Agency has approved the clean-up of six sites. Similarly, PECO has identified 27 sites where former MGP activities may have resulted in site contamination. Of these 27 sites, the PDEP has approved the clean-up of nine sites. With respect to these sites, ComEd and PECO are presently engaged in performing various levels of activities, including initial evaluation to determine the existence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation. ComEd and PECO are working closely with regulatory authorities in the various jurisdictions to develop and implement appropriate plans and schedules for evaluation, risk ranking, detailed study and remediation activities on an individual site and overall program basis. The status of each of the sites in the program varies and is reviewed periodically with the regulatory authorities. At December 31, 2005, ComEd and

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PECO had accrued $48 million (discounted) and $41 million (discounted), respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. ComEd and PECO believe that they could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at this time. In 2005, PECO finalized settlement agreements with all of its insurers of PECO’s claims for recovery of remediation costs associated with environmental remediation projects and received $14 million of insurance proceeds. In 2005, ComEd finalized a settlement agreement with its insurance carrier in the amount of approximately $4 million for costs associated with environmental remediation projects. Additionally, PECO is currently collecting through regulated gas rates, revenues to offset expenditures on MGP site remediation.

Air

Air quality regulations promulgated by the EPA and the various state environmental agencies in Pennsylvania, Massachusetts, Illinois and Texas in accordance with the Federal Clean Air Act and the Clean Air Act (CAA) Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO₂), nitrogen oxides (NO_x) and other pollutants and require permits for operation of emission sources. Such permits have been obtained by Exelon’s subsidiaries and must be renewed periodically.

The Amendments establish a comprehensive and complex national program to substantially reduce air pollution. The Amendments include a two-phase program to reduce acid rain effects by significantly reducing emissions of SO₂ and NO_x from power plants. Flue-gas desulphurization systems (scrubbers) have been installed at all of Generation’s coal-fired units other than the Keystone Station. Keystone is subject to, and in compliance with, the Phase II SO₂ and NO_x limits of the Amendments, which became effective January 1, 2000. Generation and the other Keystone co-owners are purchasing SO₂ emission allowances to comply with the Phase II limits.

Generation has completed implementation of measures, including the installation of NO_x emissions controls and the imposition of certain operational constraints, to comply with the Reasonably Available Control Technology limitations and state-level ozone season (May to September) NO_x reduction regulations. These state-level regulations were developed by eastern states to reduce summertime NO_x emissions pursuant to several Federal NO_x reduction regulations (“NO_x SIP Call” regulations) adopted by the EPA during 1998 and 1999 to address regional “ozone transport.” State level NO_x reduction regulations took effect May 1, 2003 in Pennsylvania and Massachusetts. Compliance in Illinois started May 31, 2004. Texas is not covered by the EPA’s NOx SIP Call regulations. The EPA’s NOx SIP Call regulations currently require 19 eastern states to reduce summertime NO_x emissions.

Generation has evaluated options for compliance with the NO_x SIP Call regulations and installed controls on the two coal-fired units at the Eddystone Generating Station (Selective Non-Catalytic Reduction) and installed controls on the two coal-fired units (Selective Catalytic Reduction) at the Keystone Generating Station. Generation’s NO_x compliance program is supplemented with the purchase of additional NO_x allowances on an as-needed basis. The eight new peaking units commissioned during 2002 at the Southeast Chicago Generating Station are equipped with NO_x controls that meet requirements for new sources. The Handley and Mountain Creek stations in the Dallas/Fort Worth (DFW) area are required to comply with the DFW NO_x State Implementation Plan (SIP) that commenced on May 1, 2003, and that was fully implemented on May 1, 2005. Additionally, beginning May 1, 2003, these plants were required to comply with the Emission Banking and Trading of Allowances (EBTA) program established by the State of Texas for the purpose of achieving substantial reductions in NO_x from grandfathered electric generating facilities. To comply with both the DFW NO_x SIP and EBTA program, Generation, installed Selective Catalytic Reduction technology on Handley Units 3, 4 and 5, as well as Mountain Creek Unit 8. Additionally, Induced Flue Gas Recirculation Technology was installed on Mountain Creek Units 6 and 7.

During March 2005, the EPA finalized several new rulemakings designed to reduce powerplant emissions of SO₂, NO_x and mercury. In its Clean Air Interstate Rule (CAIR), the EPA established new

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annual (applicable in 23 eastern states) and ozone season (applicable in 25 eastern states) NO_x emission caps that are scheduled to take effect in 2009. Further, CAIR requires an additional reduction of SO₂ emissions in 23 eastern states starting in 2010. CAIR also requires an additional reduction of NO_x and SO₂ emissions in 2015. The new SO₂ and NO_x emission caps finalized by the EPA are substantially below current industry emission levels. In a separate rulemaking also issued in March 2005, the Clean Air Mercury Rule (CAMR), the EPA also finalized a national program to cap mercury emissions from coal-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. In its final CAMR, the EPA determined that it would not regulate nickel emissions from oil-fired power plants, as it had considered in its proposed rulemaking. Generation is currently evaluating its compliance options with regard to the final CAIR and CAMR regulations. Final compliance decisions will be affected by a number of factors, including, but not limited to, the final form of state implementing regulations that are currently under development, as well as the resolution of legal challenges initiated by certain parties (not including Exelon) in the Federal courts regarding the final CAIR and CAMR regulations. Legal challenges to a related final rulemaking, also published in March 2005, in which the EPA rescinded its December 2000 regulatory finding on hazardous air pollutants from electric utility steam generating units, may also have an effect on Generation’s final compliance decisions to the extent such litigation has an effect on the CAMR. During late 2005, the EPA also agreed to reconsider and take additional public comment regarding certain aspects of its final CAIR and CAMR rulemakings. The EPA will consider these comments in early 2006.

Finally, a number of states in which Generation operates are considering establishing state and/or regional requirements for NO_x, SO₂ and mercury emissions that could require larger emission reductions, on shorter time schedules, than are required by the EPA’s CAMR and CAIR. For example, the PDEP has initiated a state-specific mercury rulemaking process that may result in a Pennsylvania mercury regulation that exceeds the requirements of CAMR. Pennsylvania is also participating with other Ozone Transport Commission (OTC) states in the northeast, in the development of a “CAIR-Plus” program for the northeast states that could require NO_x, SO₂ and mercury reductions in excess of the EPA’s requirements.

In addition to Federal and state regulatory activities, several legislative proposals regarding the control of emissions of air pollutants from a variety of sources, including generating plants, have been proposed in the United States Congress. For example, several multi-pollutant bills have been introduced that would reduce generating plant emissions of NO_x, SO₂, mercury and carbon dioxide starting late this decade and into the next decade.

At this time, Exelon can provide no assurance that new legislative and regulatory proposals, if adopted, will not have a significant effect on Generation’s operations and cash flows.

Global Climate Change

The United States is currently not a party to the United Nations’ Kyoto Protocol (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas (GHG) emissions at certain levels during the 2008-2012 time period. Although it is not a signatory to the Protocol, the United States may adopt a national, mandatory GHG program at some point in the future. In addition, on August 24, 2005, the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by Northeastern and Mid-Atlantic states to reduce carbon dioxide (CO₂) emissions, one of the greenhouse gases, released a program proposal. Central to this proposal is the implementation of a multi-state cap-and-trade program with a market-based emissions trading system. The proposed program would apply to electric power generators of 25MW or greater in the participating states. On December 20, 2005, seven of the nine RGGI states signed a Memorandum of Understanding (MOU) under which they committed to develop a detailed model rule during 2006 to be used by individual states to adopt the RGGI requirements outlined in the MOU. The RGGI MOU is an agreement to stabilize aggregate carbon dioxide emissions from power plants in participating states at current levels from 2009 to 2015. Further, a 10 percent reduction from current levels would be required to be phased in starting in 2016 such that by 2019

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there would be a 10 percent reduction in participating state power plant emissions. States participating in the RGGI MOU include Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont. Maryland and Pennsylvania have been observers of the process. Generation owns a small amount of peaking and intermediate generating capacity in the RGGI region. At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legislative or regulatory requirements on its businesses.

In the absence of a mandatory national program, Exelon has joined the U.S. EPA Climate Leaders Partnership (Climate Leader). As a Climate Leader partner, Exelon is conducting an annual inventory of its GHG emissions and annually reporting its GHG emissions and progress toward achieving GHG reductions. In addition, on May 6, 2005, Exelon announced that it has established a voluntary goal to reduce its GHG emissions by eight percent from 2001 levels by the end of 2008. The eight percent reduction goal represents a decrease of an estimated 1.3 million metric tons of GHG emissions. Exelon will incorporate recognition of GHG emissions and their potential cost into its business analyses as a means to promote internal investment in climate-reducing activities. Exelon believes that its planned greenhouse gas management efforts, including increased use of renewable energy, its current energy efficiency initiatives and its efforts in the areas of carbon sequestration, will allow it to achieve this goal. The anticipated cost of achieving the voluntary GHG emissions reduction goal will not have a material effect on Exelon’s future results of operations, financial condition and cash flows.

As an integrated electric and gas utility, approximately 90% of Exelon’s GHG emissions result from Generation’s combustion of fossil fuels to generate electricity, with CO₂ representing the largest quantity of GHG emitted. The majority of Generation’s owned generation is comprised of nuclear and hydroelectric assets that have negligible GHG emissions compared to fossil-based electric generation alternatives. By virtue of Generation’s significant investment in these low carbon intensity assets, Generation’s owned-generation portfolio CO₂ emission intensity, or rate of CO₂ emitted per kilowatt-hour of electricity generated, is among the lowest in the industry.

Renewable and Alternative Energy Portfolio Standards

Approximately 26 states have adopted some form of renewable portfolio standard (RPS) legislation. On November 30, 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act). The AEPS Act mandates that two years after its effective date (February 28, 2005) at least 1.5% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from Tier I alternative energy resources. The Tier I requirement escalates to 8.0% by the 15^th year after the effective date of the AEPS Act. The AEPS Act also establishes a Tier II requirement of 4.2% for years one through four. This requirement grows to 10.0% by the 15^th year. In March 2005, the PAPUC issued its first implementation order related to the AEPS. In this order, the PAPUC established a schedule for Tier I and Tier II resources with year one covering the period June 1, 2006 through May 31, 2007. During year one, compliance with the Tier I and Tier II requirements begins on February 28, 2007.

Tier I resources include: solar photovoltaic energy, wind power, low-impact hydro, geothermal energy, biologically derived methane gas, fuel cells, biomass energy and coal mine methane. A small percentage of the Tier I requirements must be met specifically by solar photovoltaic technologies (starting at 0.0013% in year 1 and escalating to 0.25% by year 10). Tier II resources include: waste coal, distributed generation systems, demand side management, large-scale hydropower, municipal solid waste and several other technologies.

The AEPS Act provides an exemption for electric distribution companies that have not reached the end of their cost recovery period during which competitive transition charges or intangible transition charges are being recovered. At the conclusion of the electric distribution company’s cost recovery period, this exemption no longer applies and compliance by the electric distribution company is

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required at the percentages in effect at that time. PECO’s cost recovery period expires December 31, 2010.

In the first year after the end of an electric distribution company’s cost recovery period, the AEPS Act provides for cost recovery on a full and current basis pursuant to an automatic energy adjustment charge as a cost of generation supply. The banking of credits from voluntary sales of Tier I and Tier II sources sold by electric distribution companies prior to the expiration of their specific cost recovery periods is also allowed under the AEPS Act. Voluntary sales under the AEPS Act are deferred as a regulatory asset by the electric distribution company and are fully recoverable at the end of the cost recovery period, also pursuant to an automatic energy adjustment clause as a cost of generation supply.

While Generation is not directly affected by the AEPS Act from a compliance perspective, increased deployment of renewable and alternative energy resources within the regional power pool resulting from the AEPS Act will have some influence on regional energy markets.

It is anticipated that, during 2006 and 2007, the PAPUC will promulgate regulations or policy statements concerning the registration, banking, and cost recovery associated with alternative energy generation and associated credits. Once these regulations and the aforementioned regulations being promulgated for PECO’s POLR role become effective, PECO will determine whether those regulations present any risk for PECO’s recovery of purchase power costs associated with alternative energy and other POLR power purchases post-2010.

During 2005, the Governor of Illinois proposed a voluntary Sustainable Energy Plan, which was subsequently endorsed by the ICC. Under the terms of the Plan, that includes both renewable and efficiency/demand response components, retail suppliers, including ComEd, would obtain renewable energy products equivalent to 2% of the energy supplied to customers in 2007, increasing by 1% annually to an ultimate target of 8% by 2013, with 75% of the targeted amounts to come from wind sources. ComEd’s response to this program will be made as part of its overall post 2006 strategy. Resolution of several outstanding legal and regulatory issues with respect to post-transition procurement and cost recovery is required. See “Retail Electric Services—ComEd” above for further detail on these outstanding legal and regulatory issues.

In addition to state level activity, RPS legislation has been considered and may be considered again in the future by the United States Congress. Also, states that currently do not have RPS requirements may determine to adopt such legislation in the future.

Exelon is currently evaluating the potential impacts of RPS legislation on its businesses.

Costs of Environmental Remediation

At December 31, 2005, Exelon, ComEd, PECO and Generation had accrued $128 million, $54 million, $47 million and $27 million, respectively, for various environmental investigation and remediation. These costs include approximately $48 million at ComEd and $41 million at PECO for former MGP sites as described above. Exelon, ComEd, PECO and Generation cannot currently predict whether they will incur other significant liabilities for additional investigation and remediation costs at sites presently identified or additional sites which may be identified by Exelon, ComEd, PECO and Generation, environmental agencies or others, or whether all such costs will be recoverable through rates or from third parties.

The budgets for expenditures in 2006 at Exelon, ComEd, PECO and Generation for compliance with environmental requirements total approximately $16 million, $6 million, $7 million and $3 million, respectively. In addition, ComEd, PECO and Generation may be required to make significant additional expenditures not presently determinable.

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Security

Exelon does not fully know the impact that future terrorist attacks may have on the electric and gas industry in general and on Exelon in particular. Exelon has implemented security measures to safeguard its employees and critical operations and is actively participating in industry initiatives to identify methods to maintain the reliability of Exelon’s energy production and delivery systems. Additionally, the energy industry is working with governmental agencies to coordinate emergency plans and to address vulnerabilities of critical infrastructures to maintain the reliability of the country’s energy systems. These measures have resulted in and are expected to continue to result in increased costs, but will provide increased assurances for Exelon’s ability to maintain critical operations.

Generation has met or exceeded all security measures mandated by the NRC for nuclear plants. On a continuing basis, Exelon is evaluating enhanced security measures at certain critical locations, enhanced response, and recovery plans and assessing long-term design changes and redundancy measures.

Other Subsidiaries of ComEd and PECO with Publicly Held Securities

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

ComEd Financing Trust II, a Delaware statutory trust, was formed by ComEd on November 20, 1996. ComEd Financing Trust II was created solely for the purpose of issuing and selling preferred and common securities. On January 24, 1997, ComEd Financing Trust II issued $150 million of trust preferred securities, carrying an annual distribution rate of 8.50%, which are mandatorily redeemable on January 15, 2027. ComEd is the sole owner of all of the common securities of ComEd Financing Trust II. The sole assets of ComEd Financing Trust II are $155 million principal amount of 8.50% subordinated deferrable interest debentures due January 15, 2027, issued by ComEd.

ComEd Financing Trust III, a Delaware statutory trust, was formed by ComEd on September 5, 2002. ComEd Financing Trust III was created for the sole purpose of issuing and selling preferred and common securities. On March 17, 2003, ComEd Financing Trust III issued $200 million of trust preferred securities, carrying an annual distribution rate of 6.35%, which are mandatorily redeemable on March 15, 2033. ComEd is the sole owner of all of the common securities of ComEd Financing Trust III. The sole assets of ComEd Financing III are $206 million principal amount of 6.35% subordinated deferrable interest debentures due March 15, 2033, issued by ComEd.

PECO Energy Transition Trust (PETT), a Delaware statutory trust wholly owned by PECO, was formed on June 23, 1998 pursuant to a trust agreement among PECO, as grantor, First Union Trust Company, National Association, now US Bank Trust, National Association, as issuer trustee, and two

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beneficiary trustees appointed by PECO. PETT was created for the sole purpose of issuing transition bonds to securitize a portion of PECO’s authorized stranded cost recovery. On March 25, 1999, PETT issued $4 billion of its Series 1999-A Transition Bonds. On May 2, 2000, PETT issued $1 billion of its Series 2000-A Transition Bonds and on March 1, 2001, PETT issued $805 million of its Series 2001-A Transition Bonds to refinance a portion of the Series 1999-A Transition Bonds. The transition bonds are solely obligations of PETT secured by intangible transition property, representing the right to collect from customers transition charges sufficient to pay the principal and interest on the transition bonds.

PECO Energy Capital Corp., a wholly owned subsidiary of PECO (PECC), is the sole general partner of PECO Energy Capital, L.P., a Delaware limited partnership (PEC L.P.). PEC L.P. was created solely for the purpose of issuing preferred securities, representing limited partnership interests and lending the proceeds thereof to PECO and entering into similar financing arrangements. The loans to PECO are evidenced by PECO’s deferrable interest subordinated debentures (Subordinated Debentures), which are the only assets of PEC L.P. The only revenues of PEC L.P. are interest on the Subordinated Debentures. All of the operating expenses of PEC L.P. are paid by PECC. As of December 31, 2005, PEC L.P. held $81 million aggregate principal amount of the Subordinated Debentures.

PECO Energy Capital Trust III (PECO Trust III), a Delaware statutory trust, was formed by PECO in April 1998. PECO Trust III was created solely for the purpose of issuing $78 million trust receipts (Trust III Receipts) each representing a 7.38% Cumulative Preferred Security, Series D (Series D Preferred Securities) of PEC L.P. PEC L.P. is the sponsor of PECO Trust III. As of December 31, 2005, PECO Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2005, the assets of PECO Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $81 million.

PECO Energy Capital Trust IV (PECO Trust IV), a Delaware statutory trust, was formed by PECO in May 2003. PECO Trust IV was created solely for the purpose of issuing and selling preferred and common securities. On June 17, 2003, PECO Trust IV issued $100 million of trust preferred securities, carrying an annual distribution rate of 5.75%, which are mandatorily redeemable on June 15, 2033. PECO is the sole owner of all of the common securities of the PECO Trust IV. The sole assets of PECO Trust IV are $103 million principal amount of 5.75% subordinated debentures issued by PECO.

See Note 1 of Exelon’s Notes to Consolidated Financial Statements for additional information.

Managing the Risks in the Business

Exelon, ComEd, PECO and Generation have considered the business challenges facing them and have adopted certain risk management activities. The Registrants recognize that their risk management activities address only certain of the challenges facing the Registrants and that those activities may not be effective in all circumstances. A discussion of the risks to which the Registrants’ businesses are subject and the potential consequences of those risks are contained in ITEM 1A. Risk Factors. On a continuing basis, the Registrants evaluate the challenges of their businesses and their ability to identify and mitigate these risks.

ComEd and PECO

Rate and equity return limitations. While ComEd and PECO continue to make significant capital expenditures to maintain and improve the reliability of each respective transmission and distribution system and to support new business and customer growth, ComEd and PECO also continue to work more efficiently to lower operating and maintenance costs. Exelon believes that ComEd, subject to the resolution of regulatory issues—see Retail Electric Services above, and PECO will continue to provide a significant and steady source of earnings and cash flows over the next several years.

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Post-transition rates. In order to address post-transition uncertainty, ComEd has made two different regulatory filings to establish the rates to be charged to customers effective January 2, 2007. The first filing relates to ComEd’s ability to procure electricity supply. The second filing established the delivery service rates that will be charged to customers. Through these proceedings ComEd is working with the ICC, consumer advocates and business community leadership to facilitate the development of a competitive electricity market while providing system reliability and safety. ComEd is promoting constructs that will move it towards transparent and liquid markets to allow for electricity procurement that will be deemed prudent, provide consumers assurance of equitable pricing and ensure adequate cost recoverability.

On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. The procurement process is similar to the process described in the Procurement Case with some modifications to enhance consumer protection. The auction will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during the fall of 2006, at which time ComEd’s entire load will be up for bid. To mitigate the effects of changes in future prices, the load will be staggered in three-year contracts. To further mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. A cap and deferral proposal, generally speaking, would limit the procurement costs that ComEd could pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years.

Several parties that were opposed to the Procurement Case have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is also possible that interested parties could introduce legislation in Illinois in an attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue.

While PECO has made no regulatory filings to date to revise its transmission and distribution rates, PECO will continue to work with Federal and state regulators, state and local governments, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured electricity markets. PECO will strive to ensure that future rate structures recognize the substantial improvements PECO has made, and will continue to make, in its transmission and distribution systems. PECO will also work to ensure that its post-2010 rates are adequate to cover its costs of obtaining electricity from its suppliers, which could include Generation, for the costs associated with procuring full requirements power given PECO’s POLR obligations. As in the past, by working together with interested parties, PECO believes it can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers after the transition periods.

Power supply risks. To effectively manage its obligation to provide power to meet its customers’ demand, ComEd and PECO have established full-requirements, power supply agreements with Generation which reduce exposure to the volatility of customer demand and market prices through 2006 for ComEd and through 2010 for PECO. Market prices relative to ComEd’s and PECO’s regulated rates still influence whether retail customers purchase electricity from ComEd, PECO or from an alternative electric supplier.

Beyond 2006 for ComEd, assuming the auction process that was approved by the ICC for the procurement of electricity remains in effect, ComEd would be allowed to recover from customers the

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cost of purchased electricity. Therefore, should an approved supplier default and ComEd be required to purchase replacement electricity, ComEd would be entitled to recover these costs from customers.

Transmission congestion. ComEd and PECO have made, and expect to continue to make, significant capital expenditures to ensure the adequate capacity and reliability of their transmission systems. On an ongoing basis, PJM, in cooperation with ComEd and PECO, performs screening analyses based on forecasts of future transmission system conditions in order to determine system reinforcements needed to maintain the reliable operation of both systems.

Loss of electricity customers to other generation suppliers. When ComEd’s and PECO’s respective customers choose alternative electric generation suppliers, ComEd and PECO lose their associated revenues. In the case of PECO, operating results are not affected by customers choosing an alternative supplier since lost revenues are completely offset by decreased purchased power expense. In ComEd’s case, the loss of revenues is largely offset by related reduced purchased power expense resulting in operating results being impacted only by any lost margin.

With respect to planning for electricity supply, ComEd and PECO have no obligation to purchase power reserves to cover the load served by others. ComEd and PECO manage their POLR obligations through full-requirements contracts with Generation, under which Generation supplies the electricity requirements of ComEd and PECO. Also, ComEd has sought through the regulatory process, as permitted by law, to limit the POLR obligation for those customers that do have competitive supply options. In 2003, ComEd received ICC approval to phase out over several years its obligation to provide fixed-price electricity under bundled rates to approximately 370 of its largest electricity customers, which have demands of at least three MWs and represent an aggregate of approximately 2,500 MWs of load. To date, ComEd has not requested to phase out its obligation to provide fixed-price electricity under bundled rates for other customers but continues to evaluate its options.

Generation

Costs to meet contractual commitments. Generation’s resources include interests in 11 nuclear generation stations, consisting of 19 units in operation. Generation’s nuclear fleet plus its ownership interest in the Salem Generating Station, operated by PSEG Nuclear, generated 137,936 GWhs, or approximately 90% of Generation’s total output, for the year ended December 31, 2005. As the largest generator of nuclear power in the United States, Generation can negotiate favorable terms for the materials and services that its business requires. Generation’s nuclear plants have historically benefited from stable fuel costs, minimal environmental impact from operations and a safe operating history.

Refueling outages. Generation continues to maintain the decreased average length of refueling outages achieved in recent years at the nuclear stations it operates, resulting in a stable generation base for Power Team trading activities.

Operating services arrangement. In 2005, as a result of the OSC with PSEG Nuclear, Generation is providing services to oversee daily plant operations and guidance to implement the Exelon Nuclear Management Model at the Salem and Hope Creek nuclear generating stations. As a result, Generation has decreased certain exposures in 2005 and increased revenues from its share of the Salem Generating Station, which it co-owns with PSEG Nuclear.

Adequacy of funds to decommission nuclear power plants. In 2003, the GAO published a study on the NRC’s need for more effective analyses to ensure the adequate accumulation of funds to decommission nuclear power plants in the United States. See the risk factor “Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of

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nuclear facilities” for further detail. Generation has reviewed the GAO’s report and believes that, in reaching its conclusions, the GAO did not consider all aspects of Generation’s decommissioning strategy, such as fund growth during the decommissioning period. The inclusion of estimated earnings growth on Generation’s nuclear trust funds during the decommissioning period virtually eliminates any funding shortfalls identified in the GAO report. Generation currently believes that the amounts in nuclear decommissioning trust funds and future collections from ComEd’s and PECO’s customers, together with earnings thereon, will provide adequate funding to decommission its nuclear facilities in accordance with regulatory requirements.

Credit risk. In order to evaluate the viability of Generation’s counterparties, Generation has implemented credit risk management procedures designed to mitigate the risks associated with these transactions. These policies include counterparty credit limits and, in some cases, require deposits 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 enabling agreements that allow for netting of payables and receivables with the majority of its large counterparties. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. Due to the termination of its PPA with ComEd on December 31, 2006 and its obligation to auction off output from its nuclear plants mandated by the FERC order approving the Merger, Generation’s liquidity requirements and credit risk exposure could increase.

Extreme weather. Generation incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet summer loads at levels representative of warmer-than-normal weather conditions.

Wholesale energy market prices. The price of power purchased and sold in the open wholesale energy markets can vary significantly in response to market conditions. Generally, between 60% and 70% of Generation’s supply serves ComEd and PECO customers. Consequently, Generation has limited its earnings exposure from the volatility of the wholesale energy market to the energy generated in excess of the ComEd and PECO requirements, as well as any other contracted longer term obligations. Following the expiration of the PPA arrangement with ComEd at the end of 2006, Generation’s supply will be more exposed to energy market prices.

Commodity prices. Generation’s Power Team manages the output of Generation’s assets and energy sales to optimize value and reduce the volatility of Generation’s earnings and cash flows. Generation attempts to manage its exposure through enforcement of established risk limits and risk management procedures.

General Business

Security risk. The Registrants have initiated and work to maintain security measures. See “Security” in ITEM 1. Business for further detail. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans and assess long-term design changes and redundancy measures. Additionally, the energy industry is working with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.

Potential phase-out of tax credits. Tax credits generated by the production of synthetic fuel are subject to a phase-out provision that gradually reduces tax credits in the event crude oil prices for a year exceed certain thresholds. See the risk factor “Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact the Registrants’ results of operations” in ITEM 1A. Risk Factors for further detail. In 2005, Exelon and

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Generation entered into certain derivatives to economically hedge a portion of the oil price exposure related to the phase-out of tax credits. These derivatives could result in after-tax cash proceeds to Exelon of up to $42 million per year in 2006 and 2007 in the event the tax credits are completely phased out. See Note 12 of Exelon’s Notes to Consolidated Financial Statements and the Executive Overview in Management’s Discussion and Analysis of Financial Condition and Results of Operation for further detail.

Interest rates. Exelon uses a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. Exelon also uses interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, Exelon uses forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk for further information.

Executive Officers of the Registrants at December 31, 2005

Exelon

ComEd

PECO

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Generation

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

Prior to his election to his listed positions, Mr. Rowe was President and Co-Chief Executive of Exelon, Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer of PECO; and Chairman, President and Chief Executive Officer of ComEd and Unicom. Mr. Rowe was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed position, Mr. Clark was Vice President and Chief of Staff of Exelon and President of ComEd; Senior Vice President, Distribution Customer and Marketing Services and External Affairs of ComEd; Senior Vice President of ComEd and Unicom; Vice President of ComEd; Governmental Affairs Vice President; and Governmental Affairs Manager. Mr. Clark was elected Chairman of ComEd effective November 28, 2005.

Prior to his election to his listed position, Mr. McLean was Senior Vice President of Exelon; President of the Power Team division of PECO; and Group Vice President of Engelhard Corporation. Mr. McLean was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed position, Mr. Mehrberg was Senior Vice President of Exelon; an equity partner with the law firm of Jenner & Block; and General Counsel and Lakefront Director of the Chicago Park District. Mr. Mehrberg was elected as an officer of Exelon effective December 3, 2001.

Prior to her election to her listed position, Ms. Moler was Senior Vice President, Government Affairs and Policy of Exelon; Senior Vice President of ComEd and Unicom; Director of Unicom and ComEd; Partner at the law firm of Vinson & Elkins, LLP; Deputy Secretary of the U.S. Department of Energy; and Chair of the Federal Energy Regulatory Commission. Ms. Moler was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed positions, Mr. Skolds was Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear; and President and Chief Operating Officer of South Carolina Electric and Gas. Mr. Skolds was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed position, Mr. Snodgrass was Chief Administrative Officer of Exelon; Senior Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and Vice President of USG Corporation. Mr. Snodgrass was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed positions, Mr. Young was President of Exelon Generation; President of Exelon Power; Senior Vice President of Sierra Pacific Resources Corporation; President of Avalon Consulting; and Executive Vice President of Southern Generation. Mr. Young was elected as an officer effective March 3, 2003.

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Prior to his election to his listed position, Mr. Hilzinger was Executive Vice President and Chief Financial Officer of Credit Acceptance Corporation; Vice President, Controller of Kmart Corporation; Divisional Vice President, Strategic Planning and Financial Reporting of Kmart Corporation; and Assistant Treasurer of Kmart Corporation. Mr. Hilzinger was elected as an officer of Exelon effective April 15, 2002.

Prior to his election to his listed position, Mr. Mitchell was Senior Vice President, Chief Financial Officer and Treasurer of Exelon, ComEd, PECO and Generation; Vice President and Treasurer of Exelon; and Vice President, Treasury and Evaluation, and Treasurer of PECO. Mr. Mitchell was elected as President of ComEd effective November 28, 2005.

Prior to his election to his listed position, Mr. Costello served as Senior Vice President of Exelon Energy Delivery Technical Services. Mr. Costello has also served as Senior Vice President of Exelon Energy Delivery Customer and Marketing Services; and Vice President, Customer Operations. Mr. Costello was elected to his listed position with ComEd effective November 28, 2005.

Prior to his election to his listed position, Mr. McDonald served as Senior Vice President of Planning and Chief Risk Officer of Exelon. Mr. McDonald has also served as Chief Risk Officer of Exelon, Vice President of Planning of Exelon and Vice President of Risk Management of Exelon. He was elected to his listed position with ComEd effective November 28, 2005.

Prior to her election to her listed position, Ms. Pramaggiore served as Vice President, Regulatory and Strategic Services of ComEd. She has also served as Lead Counsel of ComEd. Ms. Pramaggiore was elected to her listed position with ComEd effective November 28, 2005.

Prior to his election to his listed position, Mr. Hooker served as Senior Vice President, ComEd, Legislative and External Affairs and Exelon Energy Delivery Real Estate and Property Management. Mr. Hooker has also served as Vice President Exelon Energy Delivery Property Management and ComEd Legislative and External Affairs; Vice President Distribution Services and Public Affairs; and Vice President of Governmental Affairs.

Prior to his election to his listed position, Mr. O’Brien was Executive Vice President of PECO; Vice President of Operations of PECO; Director of Transmission and Substations of PECO; and Director of BucksMont Region of PECO. Mr. O’Brien was elected as an officer of PECO effective January 1, 2001.

Prior to his election to his listed position, Mr. Crane was Vice President for Exelon Nuclear; and Vice President for BWR Operations of ComEd. Mr. Crane was elected as an officer of Generation effective December 27, 2000.

Prior to his election to his listed position, Mr. Schiavoni was Vice President of Operations; and Vice President of Northeast Operations of Exelon Power. Mr. Schiavoni was elected as an officer of Generation effective September 8, 2003.

Prior to his election to his listed position, Mr. Veurink was a partner at Deloitte & Touche LLP. Mr. Veurink was elected as an officer of Generation effective January 5, 2004.

Exelon, ComEd, PECO and Generation operate in a market environment that involves significant risks, many of which are beyond their control. The following risk factors, as well as the risks discussed in ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Liquidity and Capital Resources, may adversely impact the Registrants’ results of operations,

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cash flows and market price of their publicly traded securities. While each of the Registrants believes it has identified and discussed below the key risk factors affecting its business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect its performance or financial condition.

ComEd and PECO

Regulatory Risks

The process for establishing ComEd’s and PECO’s rates after the rate freeze and rate caps expire is contentious, in view of requested rate increase requests, and involves uncertainty as to their form and adequacy.

ComEd and PECO cannot currently predict the ultimate outcomes of the actions by the Illinois and Pennsylvania state regulators for establishing rates after the rate freeze and caps expire. Nevertheless, the expectation is that ComEd and PECO will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant POLR obligations, whereby each utility is required to provide electricity service to customers in its service area who choose to obtain their electricity from the utility. ComEd has filed two proceedings seeking regulatory approval of the process by which it proposes to procure electricity and the rates it proposes to charge to deliver electricity to customers. Various governmental parties and consumer groups have contested the proposed electricity procurement process as well as the requests made in the proceedings. The ultimate outcome of these matters, and in particular the ComEd Procurement case in Illinois and regulatory proceedings related to the end of PECO’s transition period, will have a significant effect on the ability of ComEd and PECO, as applicable, to recover their costs and could have a material adverse effect on ComEd’s and PECO’s results of operations and cash flows.

ComEd may be required to sell electricity at capped rates while buying electricity at market rates, which are more volatile and potentially higher.

Although the ICC has issued an order authorizing the reverse-auction competitive bidding process for procurement of power after 2006, that decision remains subject to petitions for rehearing and is likely to be challenged in court. ComEd cannot predict the results of those challenges or whether the Illinois General Assembly might take action that could have a material impact on the procurement process. If the price at which ComEd is allowed to sell electricity beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there may be material adverse consequences to ComEd and, possibly, Exelon. Exelon and ComEd believe that these potential material adverse consequences could include, but may not be limited to, loss of ComEd’s investment grade credit rating and a possible reduction in the other Registrants’ credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term electricity procurement contracts, which would likely force ComEd to procure electricity at more volatile and potentially higher prices in the spot market. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the nearer term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible. In addition, ComEd has indicated it is willing to develop a “cap and deferral” arrangement to keep residential rates at or below 1996 levels through 2009. A “cap and deferral” arrangement would limit the procurement costs that ComEd could pass through to its customers for a period of time and allow ComEd to collect those unrecovered costs in future years.

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Changes in ComEd’s and PECO’s terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings that are contentious, lengthy and subject to appeal, which introduce time delays in effecting rate changes as well as uncertainty as to the ultimate result.

ComEd and PECO are involved in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have long time lines, which may not be limited by statute. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings.

ComEd’s and PECO’s ability to cover their respective operating and capital costs may be limited by rate caps currently in effect, which will affect their respective results of operations during the rate cap period.

The rate freezes or caps in effect at ComEd and PECO currently limit their ability to recover increased operating expenses and to recover the costs of investments in new transmission and distribution facilities. ComEd is subject to a rate freeze on bundled retail rates that will remain in effect through January 1, 2007. PECO is subject to rate caps on its transmission and distribution rates through December 31, 2006 and on its generation rates through December 31, 2010. The transmission and distribution rate caps at PECO may be extended to December 31, 2010 as a result of a settlement in the Merger approval process in Pennsylvania. See Note 4 of Exelon’s Notes to Consolidated Financial Statements for further information.

ComEd and PECO expect to continue to make significant capital expenditures to maintain and improve the reliability of their transmission and distribution systems and for capital additions to support new business and customer growth. As a result, ComEd’s and PECO’s future results of operations, during the periods indicated above, may be adversely affected if ComEd and PECO are not able to deliver electricity in a cost-efficient manner and are unable to offset inflation and the cost of infrastructure investments with cost savings. Their ability to identify and implement cost savings is more challenging in the later years of the freeze and caps. Further, the rate freeze and caps will generally preclude rate recovery on any of its incremental capital investments through January 2, 2007.

A mandatory RPS could negatively affect the cost of electricity purchased and sold by ComEd and PECO.

Federal or state legislation mandating the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal, could result in significant changes in ComEd’s and PECO’s businesses, including fuel cost and capital expenditures. ComEd and PECO continue to monitor discussions related to RPSs at the Federal and state levels.

For additional information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” in ITEM 1 of this Form 10-K.

Operating Risk

ComEd and PECO may be subject to the risk of power supplier defaults and the unplanned costs associated with those defaults.

Neither ComEd nor PECO own generation facilities. Both currently purchase their electricity from Generation pursuant to PPAs that expire at the end of 2006, in the case of ComEd, and the end of 2010, in the case of PECO. Assuming a competitive procurement process thereafter, both companies

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may be subject to supplier defaults and supply risk. If a supplier defaults, ComEd or PECO, as the case may be, would be required to purchase replacement electricity in the spot market to meet the needs of its customers, which may increase electricity purchase and transmission costs and negatively affect results of operations.

ComEd’s and PECO’s respective ability to deliver electricity, their operating costs and their capital expenditures may be negatively affected by transmission congestion.

Demand for electricity within ComEd’s and PECO’s service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in PJM or the FERC requiring ComEd and PECO to upgrade or expand their respective transmission system through additional capital expenditures.

ComEd’s and PECO’s operating costs and their respective perception by customers and regulators are affected by their ability to maintain the availability and reliability of their delivery systems.

Failures of the equipment or facilities used in ComEd’s and PECO’s delivery systems can interrupt the delivery of electricity and related revenues and increase repair expenses and capital expenditures. Those failures or those of other utilities, including prolonged or repeated failures, can affect customer satisfaction, the level of regulatory oversight and ComEd’s and PECO’s maintenance and capital expenditures. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd can be required to pay damages to its customers in the event of extended outages affecting large numbers of its customers.

ComEd and PECO face the continued loss of electricity customers and associated revenues to other generation suppliers since those customers have the right to select their own generation supplier.

ComEd’s and PECO’s retail electric customers may purchase their electricity from alternative electric suppliers, although ComEd and PECO remain obligated to provide transmission and distribution service to customers in their service territories regardless of their generation supplier. ComEd and PECO are each generally obligated to provide generation and delivery service to customers in their service territories at fixed rates or, in some instances, market-derived rates. In addition, customers who take service from an alternative supplier may later return to ComEd or PECO. The number of customers taking service from alternative electric suppliers depends in part on the prices being offered by those suppliers relative to the fixed prices that ComEd and PECO are authorized to charge by their state regulatory commissions. To the extent that customers leave traditional bundled tariffs and select a different electric supplier, ComEd’s and PECO’s revenues are likely to decline, and revenues and gross margins could vary from period to period.

The effect of higher purchased gas cost charges to customers may decrease PECO’s results of operations and cash flows.

Gas rates charged to customers are comprised primarily of purchased gas cost charges, which provide no return or profit to PECO, and distribution charges, which provide a return or profit to PECO. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted quarterly, represent gas commodity costs that PECO recovers from customers. PECO’s cash flows can be impacted by differences between the time period when gas is purchased and the ultimate recovery from customers. When purchased gas cost charges increase substantially, as they have throughout

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2005 in response to higher gas procurement costs incurred by PECO, customer usage may decrease, resulting in lower distribution charges and lower profit margins for PECO. In addition, increased purchased gas cost charges to customers also may result in increased bad debt expense from an increase in the number of uncollectible accounts receivable.

The effects of weather and the related impact on electricity and gas usage may decrease ComEd’s and PECO’s results of operations.

Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues. As a corollary, moderate temperatures adversely affect the usage of energy and resulting revenues. Because of seasonal pricing differentials, coupled with higher consumption levels, ComEd and PECO typically report higher revenues in the third quarter of the fiscal year. However, extreme weather conditions or storms may stress ComEd’s and PECO’s transmission and distribution systems, resulting in increased maintenance and capital costs and limiting its ability to meet peak customer demand. These extreme conditions may have detrimental effects on ComEd’s and PECO’s operations.

ComEd’s and PECO’s businesses are capital intensive and the costs of capital projects may be significant.

ComEd’s and PECO’s businesses are capital intensive and require significant investments in internal infrastructure projects. ComEd’s and PECO’s results of operations and financial condition could be adversely affected if either is unable to effectively manage their respective capital projects.

Other

Exelon’s and ComEd’s goodwill may become further impaired, which would result in write-offs of the impaired amounts.

Exelon and ComEd had approximately $3.5 billion of goodwill recorded at December 31, 2005. This goodwill was recognized and recorded in connection with the PECO / Unicom merger. With the proposed Merger with PSEG, it is anticipated that approximately $6 billion to $7 billion of additional goodwill will be recorded at Exelon across various business units. See the Merger section below for further discussion. Under GAAP, the goodwill will remain at its recorded amount unless it is determined to be impaired, which is based upon an annual analysis prescribed by SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142) that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, such as the one recorded during 2005, the amount of the impaired goodwill will be written off and expensed, reducing equity. Under Illinois law, any impairment of goodwill has no impact on the determination of ComEd’s rate cap through the transition period.

There is a possibility that additional goodwill may be impaired at ComEd, and at Exelon, in 2006 or later periods. The actual timing and amounts of any goodwill impairments in future years will depend on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, ComEd’s capital structure, market prices for power, results of ComEd’s post 2006 rate proceedings, operating and capital expenditure requirements and other factors, some not yet known.

See Critical Accounting Policies and Estimates for further discussion on goodwill impairments.

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Generation

Market Transition Risks

Generation will be exposed to increased market risk and price volatility after the expiration of significant purchase power arrangements after 2006.

Generation sells a majority of its output to ComEd and PECO under long-term PPAs. As a result of the pending expiration of the PPA between Generation and ComEd at the end of 2006, Generation will be exposed to increased commodity price risk associated with the electricity historically sold to serve ComEd’s load obligations. Generation will continue to be exposed to fluctuations in commodity prices for electricity after 2006 for the unhedged portion of its electricity trading portfolio. Generation has been and will continue to be proactive in looking for hedging strategies to mitigate this risk. Accordingly, Generation may need to sell more electricity at market-based prices than it currently does. Increased market sales and new contractual arrangements under a competitive model may adversely affect Generation’s credit risk due to an increase in the number of customers and the loss of a highly predictable revenue source.

Although the order issued by the ICC authorizes the reverse-auction competitive bidding process for procurement of power after 2006 for ComEd, that decision remains subject to petitions for rehearing and is likely to be challenged in court. In addition, the Illinois General Assembly has held hearings concerning generation procurement post 2006 and it may choose to take further action on this issue. In April 2005, a proposed amendment to the Illinois Public Utilities Act was introduced in Committee hearings in the Illinois legislature, which, if enacted into law, would have extended the current “rate freeze” and transition period for an additional two years. However, the proposed amendment was defeated in Committee. Generation cannot predict the results of those challenges or whether the Illinois General Assembly might take further action that could have a material impact on Generation, including actions that would attempt to require Generation to enter into a full requirements PPA with ComEd to sell power at below market prices beginning in 2007.

Generation’s business may be negatively affected by the restructuring of the energy industry.

Regional Transmission Organizations. Generation is dependent on wholesale energy markets and open transmission access and rights by which Generation delivers power to its wholesale customers, including ComEd and PECO. Generation uses the wholesale regional energy markets to sell power that Generation does not need to satisfy its long-term contractual obligations, to meet long-term obligations not provided by its own resources and to take advantage of price opportunities.

Wholesale markets have only been implemented in certain areas of the country and each market has unique features which may create trading barriers among the markets. The FERC has proposed initiatives, including RTOs, to encourage the development of large regional, uniform markets and to eliminate trade barriers. The FERC’s effort to promote RTOs throughout the states has generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop a RTO have been abandoned in certain regions. Generation supports the development of RTOs and implementation of standard market protocols for these regions, and others, but cannot predict their success or whether they will lead to the development of the large, successful wholesale markets.

Approximately 79% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the region encompassed by PJM, following PJM’s expansion to the Midwest markets in 2004. The PJM market has been the most successful and liquid regional market. Generation’s future results of operations may be negatively affected by the continued expansion of that market or the implementation of any market changes mandated by the FERC.

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Provider of Last Resort. As discussed above, ComEd and PECO have POLR obligations that they have effectively transferred to Generation through full-requirements contracts. Because the choice of an electricity generation supplier lies with the customer, planning to meet these obligations has a higher level of uncertainty than that traditionally experienced due to weather and the economy. It is difficult for Generation to plan the electricity demand of ComEd and PECO customers. The uncertainty regarding the amount of ComEd and PECO load for which Generation must provide increases Generation’s costs and may limit its sales opportunities. A significant under-estimation of the electric-load requirements of ComEd and PECO could result in Generation not having enough power to cover its supply obligation, in which case Generation would be required to buy power from third parties or in the spot markets at prevailing market prices. Those prices may not be as favorable, or as manageable, as Generation’s long-term supply expenses and thus could increase Generation’s total costs.

Generation may not be able to effectively respond to competition in the energy industry.

As a result of industry restructuring, numerous generation companies created by the disaggregation of vertically integrated utilities have become active in the wholesale power generation business. In addition, independent power producers (IPP) have become prevalent in the wholesale power industry. These new generating facilities may be more efficient than Generation’s facilities. The introduction of new technologies could increase competition, which could lower prices and have an adverse effect on Generation’s results of operations or financial condition. Generation’s financial performance depends on its ability to respond to competition in the energy industry.

Generation may not be able to effectively respond to increased demand for energy.

As the demand for electricity rises in the future, it may be necessary to increase capacity through the construction of new generating facilities. Both Illinois and Pennsylvania statutes contemplate that future generation will be built at the risk of market participants. Any construction of new generating facilities by Generation would be subject to market concentration tests administered by the FERC. If Generation cannot pass these tests administered by the FERC, it could be limited in how it responds to increased demand for energy. Generation’s financial growth depends on its ability to respond to increased demand for energy.

Nuclear Operations Risks

Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of nuclear facilities.

Nuclear capacity factors. Capacity factors, particularly nuclear capacity factors, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to generate additional energy from its fossil or hydroelectric facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to ComEd and PECO and other committed third-party sales. These sources generally have a higher operating cost than Generation incurs to generate energy from its nuclear stations.

Refueling outages. Outages at nuclear stations to replenish fuel require the station to be “turned off.” Refueling outages are planned to occur once every 18 to 24 months and currently average approximately 24 days in duration. When refueling outages at wholly and co-owned plants last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales. Each 24-day outage, depending on the capacity of the station, will decrease the total nuclear annual

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capacity factor between 0.3% and 0.5%. The number of refueling outages, including the AmerGen plants and the co-owned plants, was eleven in 2005 with eleven planned for 2006. The projected total non-fuel capital expenditures for the nuclear plants operated by Generation will increase in 2006 compared to 2005 by approximately $39 million as Generation continues to invest in equipment upgrades to ensure safe reliable operations. Maintenance expenditures are expected to increase by approximately $67 million in 2006 compared to 2005 as a result of inflationary cost increases and one additional planned nuclear outage at the nuclear stations operated and wholly owned by Generation.

Nuclear fuel quality. The quality of nuclear fuel utilized by Generation can affect the efficiency and costs of Generation’s operations. Certain of Generation’s nuclear units have been identified as having a limited number of fuel performance issues. Remediation actions, including those required to address performance issues, could result in increased costs due to accelerated fuel amortization and/or increased outage costs. It is difficult to predict the total cost of these remediation procedures.

Spent nuclear fuel storage. Generation incurs costs on an annual basis for the storage of spent nuclear fuel. Under the terms of the settlement reached with the DOE in 2004, Generation is being reimbursed for costs of spent fuel storage only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel. The approval of a national repository for the storage of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of spent nuclear fuel, and the ultimate amounts received from the DOE under the settlement. Also, the availability of a repository for spent nuclear fuel may affect the ability to fully decommission the nuclear units. In addition, the State of Nevada recently challenged the NRC’s “waste confidence” rule, 10 CFR 51.23, pursuant to which, the NRC has determined that, if necessary, spent fuel generated in any reactor can be stored safely and without significant environmental impacts for at least 30 years beyond the licensed life for operation, which may include the term of a revised or renewed license of that reactor, at its spent fuel storage basis or at either onsite or offsite independent spent fuel storage installations. The rule remains in place at this time, and is unlikely to be revised in the near future unless the D.C. Circuit overturns the NRC’s denial of Nevada’s petition. Under the waste confidence rule, the NRC has made a determination that, if necessary, spent fuel generated in any reactor can be stored safely and without significant environmental impacts for at least 30 years beyond the licensed life for operation, which may include the term of a revised or renewed license, of that reactor at its spent fuel storage basis or at either onsite or offsite independent spent fuel storage installations. If the NRC changes or is forced to change its determination it could affect the nuclear generating stations ability to store additional waste.

License Renewals. Generation’s nuclear facilities are currently operating under 40-year NRC licenses. Generation has applied for and received 20-year renewals for the licenses that will be expiring in the next ten years or, in the case of Oyster Creek, an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. Generation intends to evaluate opportunities, as permitted by the NRC, to apply for license renewals for some or all of the remaining licenses. If the renewals are granted, Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of the renewed license. If the NRC does not renew the operating licenses for Generation’s nuclear stations or a station cannot be operated until the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning payments.

Should a national policy for the disposal of spent nuclear fuel not be developed, the unavailability of a repository for spent nuclear fuel could become a consideration by the NRC during future nuclear license renewal proceedings, including applications for new licenses, and may affect Generation’s ability to fully decommission its nuclear units.

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Environmental risk. In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g. cooling towers) are potentially most affected. Those facilities are Clinton, Cromby Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. During the NJDEP system permit renewal process for both Salem and Oyster Creek, the NJDEP primarily concluded that closed-cycle cooling for Salem and Oyster Creek and environmental restoration for Oyster Creek are the only viable compliance options for Section 316(b). See ITEM 1. Business section for further details on Environmental Water Regulations. AmerGen and PSEG have not made a determination regarding how compliance of Section 316(b) will be met for Oyster Creek and Salem. If application of the Section 316(b) regulations requires the retrofitting of Oyster Creek and Salem’s cooling water intake structure, or extensive wetlands restoration, this could result in material costs of compliance. In addition, the amount of the costs required to retrofit Oyster Creek may negatively impact Generation’s decision to renew the operating license.

Regulatory risk. The NRC may modify, suspend or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and significantly affect Generation’s results of operations or financial position. Events at nuclear plants owned by others, as well as those owned by Generation, may cause the NRC to initiate such actions.

Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners.

In January 2004, the NRC issued a letter to PSEG 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. Since that time, PSEG has worked with the NRC under its oversight program to address the matters, which focus on a safety conscious work environment, raised by the NRC’s letter. Throughout 2005, PSEG has and will continue to provide updated information to the NRC as required under their workplan.

The spent fuel pool at each Salem Unit has an installed leakage collection system. This normal leakage path was found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building’s concrete structure. PSEG is developing a solution to maintain the design function of the leakage collection system and is investigating the extent of any structural degradation caused by the leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs to the owners of the facility could be material. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Generation cannot predict what further actions the NRC may take on this matter.

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Nuclear accident risk. Although the safety record of nuclear reactors, including Generation’s, generally has been very good, accidents and other unforeseen problems have occurred both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident may exceed Generation’s resources, including insurance coverages, and significantly affect Generation’s results of operations or financial position.

Nuclear insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The limit as of December 31, 2005 is $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site). Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $10.76 billion limit.

Nuclear Electric Insurance Limited (NEIL), a mutual insurance company to which Generation belongs, provides property and business interruption insurance for Generation’s nuclear operations. In recent years, NEIL has made distributions to its members. Generation’s distribution for 2005 was $40 million, which was recorded as a reduction to operating and maintenance expenses in its Consolidated Statement of Income. Generation cannot predict the level of future distributions or if they will continue at all.

Decommissioning. Generation has an obligation to decommission its nuclear power plants. The ICC permits ComEd, and the PAPUC permits PECO, to collect funds from their customers, which are deposited in nuclear decommissioning trust funds maintained by Generation. Collections by ComEd are limited and permitted only through 2006. The collections by ComEd and PECO are based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, other than AmerGen facilities. The ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004 and, depending upon the portion of the output of certain generating stations taken by ComEd, up to $73 million in 2005 and 2006. Because ComEd did not take all of the output of these stations, actual collections were $68 million in 2005 and are expected to be approximately the same in 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. PECO is currently recovering $33 million annually for nuclear decommissioning. Generation expects that these collections will continue through the operating license life of each of the former PECO units, with adjustments every five years to reflect changes in cost estimates and decommissioning trust fund performance. These trust funds, together with earnings thereon, will be used to decommission such nuclear facilities. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029. To fund future decommissioning costs, Generation held $5.6 billion of investments in trust funds at December 31, 2005.

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for Generation’s four retired units) addressing Generation’s ability to meet the NRC-estimated funding levels (NRC Funding Levels) including scheduled contributions to and earnings on the decommissioning trust funds. As of December 31, 2005, one of Generation’s 23 units is currently underfunded by less than three percent with respect to NRC Funding Levels. Generation will submit its next biennial report to the NRC in March 2006.

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In 2003, GAO published a study on the NRC’s need for more effective analyses to ensure the adequate accumulation of funds to decommission nuclear power plants in the United States. As it has in the past, the GAO concluded that accumulated and future proposed funding was inadequate to achieve NRC Funding Levels at a number of U.S. nuclear plants, including a number of Generation’s plants. Forecasting investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from current estimates. Ultimately, when decommissioning activities are initiated, if the investments held by Generation’s nuclear decommissioning trusts are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to provide other means of funding its decommissioning obligations.

Other Operating Risks

Financial performance and load requirements may be adversely affected if Generation is unable to effectively manage its power portfolio.

The majority of Generation’s portfolio is used to provide power under long-term PPAs with ComEd and PECO. To the extent portions of the portfolio are not needed for that purpose, Generation’s output is sold on the wholesale market. To the extent its portfolio is not sufficient to meet the requirements of ComEd and PECO, Generation must purchase power in the wholesale power markets. Generation’s financial results may be negatively affected if it is unable to cost-effectively meet the load requirements of ComEd and PECO, manage its power portfolio and effectively handle the changes in the wholesale power markets.

Generation relies on the availability of electric transmission facilities that it does not own or control to deliver its wholesale electric power to the purchasers of the power, which may adversely affect its ability to deliver power to its customers.

Generation depends on transmission facilities owned and operated by other companies, including ComEd and PECO, to deliver the power that it sells at wholesale. If transmission at these facilities is disrupted or transmission capacity is inadequate, Generation may not be able to sell and deliver its wholesale power. The North American transmission grid is highly interconnected and, in extraordinary circumstances, disruptions at a point within the grid can cause a systemic response that results in an extensive power outage. If a region’s power transmission infrastructure is inadequate, Generation’s recovery of wholesale costs and profits may be limited. In addition, if restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has commenced electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Generation also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

Generation is exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations.

Generation fulfills its energy commitments from the output of the generating facilities that it owns as well as through buying electricity under long- and short-term contracts in both the wholesale bilateral and spot markets. The excess or deficiency of energy owned or controlled by Generation compared to its obligations exposes Generation to the risks of rising and falling prices in those markets, and Generation’s cash flows may vary accordingly. Generation’s cash flows from generation

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that is not used to meet its commitments to ComEd and PECO are largely dependent on wholesale prices of electricity and Generation’s ability to successfully market energy, capacity and ancillary services. In the event that lower wholesale prices of electricity reduce Generation’s current or forecasted cash flows, the carrying value of Generation’s generating units may be determined to be impaired and Generation would be required to incur an impairment loss.

The wholesale spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. Many times, the next unit of electricity supplied would be supplied from generating stations fueled by fossil fuels, primarily natural gas. Consequently, the open-market wholesale price of electricity may reflect the cost of natural gas plus the cost to convert natural gas to electricity. Therefore, changes in the supply and cost of natural gas generally affect the open market wholesale price of electricity.

Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or energy will not perform their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation might be forced to purchase or sell power in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to the risks of whatever default mechanisms exist in that market, some of which attempt to spread the risk across all participants, which may or may not be an effective way of lessening the severity of the risk and the amounts at stake. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. Due to the termination of its PPA with ComEd on December 31, 2006 and its obligation to auction off output from its nuclear plants mandated by the FERC order approving the Merger, Generation’s liquidity requirements and credit risk exposure could increase.

In addition, the retail businesses of Exelon Energy subject Generation to credit risk resulting from a different customer base.

Risk of Credit Downgrades. Generation’s trading business is required to meet credit quality standards. If it were to lose its investment grade credit rating or otherwise fail to satisfy the credit standards of trading counterparties, Generation would be required under trading agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect its liquidity. If Generation had lost its investment grade credit as of December 31, 2005, it would have been required to provide approximately $1,388 million in collateral.

Immature Markets. Certain wholesale spot markets are new and evolving markets that vary from region to region and are still developing practices and procedures. While the FERC has proposed initiatives to standardize wholesale spot markets, Generation cannot predict whether that effort will be successful, what form any of these markets will eventually take or what roles Generation will play in them. Problems in or the failure of any of these markets, as was experienced in California in 2000, could adversely affect Generation’s business.

Hedging. The Power Team buys and sells energy and other products in the wholesale markets and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. This activity, along with the effects of any specialized accounting for trading contracts, may cause volatility in Generation’s future results of operations.

Weather. Generation’s operations are affected by weather, which affects demand for electricity as well as operating conditions. Generation plans its business based upon normal weather assumptions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation may require greater resources to meet its contractual requirements to ComEd and PECO. Extreme

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weather conditions or storms may affect the availability of generation capacity and transmission, limiting Generation’s ability to source or send power to where it is sold. These conditions, which may not have been fully anticipated, may have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when those markets are weak.

Power Team’s risk management policies cannot fully eliminate the risk associated with its energy trading activities.

Power Team’s power trading (including fuel procurement and power marketing) activities expose Generation to risks of commodity price movements. Generation attempts to manage its exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its power trading and risk management decisions may have on its business, operating results or financial position.

Generation’s business is capital intensive and the costs of capital projects may be significant.

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s results of operations could be adversely affected if Generation were unable to effectively manage its capital projects.

General Business

The following risk factors may adversely impact all of the Registrants’ results of operations and cash flows.

Results of operations may be negatively affected by increasing costs.

Inflation affects the Registrants through increased operating costs and increased capital costs for plant and equipment. As a result of the rate freezes for ComEd and caps for PECO under which the businesses operate and price pressures due to competition, ComEd and PECO may not be able to pass the costs of inflation through to their customers. In addition, the Registrants face rising medical benefit costs, which are increasing at a rate that greatly exceeds the rate of general inflation. If the Registrants are unable to successfully manage their medical benefit costs or other increasing costs, their results of operations could be negatively affected.

Market performance may decrease the value of decommissioning trust funds and benefit plan assets, which then could require significant additional funding.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations to decommission Generation’s nuclear plants and under Exelon’s pension and postretirement benefit plans. The Registrants have significant obligations in these areas and hold significant assets in these trusts. A decline in the market value of those assets, as was experienced from 2000 to 2002, may increase the funding requirements of these obligations.

Exelon’s holding company structure could limit its ability to pay dividends.

Exelon is a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Exelon’s ability to pay dividends on

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its common stock depends on the payment to it of dividends by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. Under applicable Federal law, ComEd, PECO and Generation can pay dividends only from the amount of retained, undistributed or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless ComEd has specific authorization from the ICC. During 2005, a new board of directors with responsibilities solely for ComEd was selected. The ComEd board of directors may elect to adopt a different dividend policy.

The Registrants may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which the Registrants operate are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures. These regulations affect how the Registrants handle air and water emissions and solid waste disposal and are an important aspect of their operations. In addition, the Registrants are subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies will be one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

In addition, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action, such as that proposed in The Fairness in Asbestos Injury Resolution Act of 2005, could require Generation to contribute to a fund with a material contribution to settle lawsuits for alleged asbestos-related disease and exposure.

For additional information regarding environmental matters, see “Environmental Regulation” in ITEM 1 of this Form 10-K.

War, acts and threats of terrorism and natural disaster may adversely affect Exelon’s results of operations, its ability to raise capital and its future growth.

Exelon does not know the impact that any future terrorist attacks may have on the industry in general and on Exelon in particular. In addition, any retaliatory military strikes or sustained military campaign may affect its operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. The possibility alone that infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of terror may affect Exelon’s operations. Additionally, the continuing military activity in Iraq and other wars may have an adverse effect on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect Exelon’s revenues or restrict its future growth. Instability in the financial markets as a result of terrorism or war may affect Exelon’s results of operations and its ability to raise capital. In addition, the implementation of security guidelines and measures have resulted in and are expected to continue to result in increased costs.

Additionally, Exelon is affected by changes in weather and the occurrence of hurricanes, storms and other natural disaster in its service territory and throughout the U.S. Severe weather or other

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natural disasters could be destructive which could result in increased costs, including supply chain costs. See Management’s Discussion and Analysis of Financial Conditions and Results of Operation—Executive Overview in ITEM 7 for additional information on the expected impact due to Hurricanes Katrina and Rita.

Changes in the availability and cost of insurance mean that the Registrants have greater exposure to economic loss due to property damage and liability.

The Registrants carry property damage and liability insurance for their properties and operations. As a result of significant changes in the insurance marketplace, the available coverage and limits may be less than the amount of insurance obtained in the past, the costs of obtaining such insurance may be higher and the recovery for losses due to terrorist acts may be limited. The Registrants are self-insured for deductibles and to the extent that any losses may exceed the amount of insurance maintained. A claim that exceeds the amounts available under their property damage and liability insurance, together with the deductible, could negatively affect their results of operations.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact the Registrants’ results of operations.

Tax reserves and the recoverability of deferred tax assets. The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeals issues related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. The Registrants also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Other than as noted below, the Registrants do not record valuation allowances for deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. See Note 12 of Exelon’s Notes to Consolidated Financial Statements for further detail.

Increases in state income taxes. Due to the revenue needs of the states in which the Registrants operate, various state income tax and fee increases have been proposed or are being considered. The Registrants cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, or, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. If enacted, these changes could increase state income tax expense and could have a negative impact on the Registrants’ results of operations and cash flows.

1999 Sale of the Fossil Generating Assets. Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the Internal Revenue Service (IRS), to defer the taxation of the gain realized on the 1999 sale of its fossil generation assets. Exelon’s ability to continue to defer all or a portion of this liability depends on whether its treatment of a portion of the sale proceeds, as having been received in connection with an involuntary conversion, is proper pursuant to applicable law. Exelon’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction it entered into in connection with the sale is proper pursuant to applicable law. A successful IRS challenge to ComEd’s positions would have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax liability that becomes current. 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. Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $951 million. It is presently unclear the extent to which the IRS will seek to disallow the deferral of tax liability resulting from the 1999 sale of fossil generating assets, if at all, and if it were to do so, the extent to which any

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such challenge would be successful. If the deferral were successfully challenged by the IRS, it could negatively impact Exelon’s results of operations by as much as $135 million (after tax). See Note 12 of Exelon’s Notes to Consolidated Financial Statements for further detail.

Investments in synthetic fuel-producing facilities. Exelon, through three wholly owned subsidiaries has investments in synthetic fuel-producing facilities. Section 45k of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. Exelon’s right to tax credits generated by the facilities was recorded as intangible assets which are amortized as the tax credits are earned. Section 45k contains a provision under which tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. Recent events, such as terrorism, natural disasters and strong worldwide demand, have significantly increased the price of domestic crude oil and, therefore, have created uncertainty as to the value of future synthetic fuel tax credits and the net carrying value of the intangible assets. Exelon estimates that there could be a significant phase-out of tax credits in 2006 and 2007 based on the expected futures prices. Absent any efforts to mitigate price exposure, a phase-out could result in the reduction of non-operating net income generated by the investments and could result in substantial non-operating losses in 2006 and 2007 in the event all tax credits are completely eliminated. See Note 12 of Exelon’s Notes to Consolidated Financial Statements, the Executive Overview and Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operation for further detail.

Exelon and its subsidiaries have guaranteed the performance of third parties, which may result in substantial costs in the event of non-performance.

Exelon and certain of its subsidiaries have issued certain guarantees of the performance of others, which obligate Exelon to perform in the event that the third parties do not perform. In the event of non-performance of these guaranteed obligations by the third parties, Exelon and its subsidiaries could incur substantial cost to fulfill their obligations under these guarantees. Such performance could have a material impact on the financial statements of Exelon and its subsidiaries. See Note 20 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding guarantees.

The Registrants may make acquisitions that do not achieve the intended financial results.

The Registrants may continue to pursue investments that fit their strategic objectives and improve their financial performance. With the repeal of PUHCA, the Registrants are free to make investments and pursue mergers and acquisitions that were formerly not permitted under PUHCA and that might present more risk than the types of investments and mergers and acquisitions that were permitted under PUHCA. However, with the repeal of PUHCA, it is possible that the public utility commissions of each state may impose certain other restrictions on the investments that the Registrants may make.

On December 20, 2004, Exelon announced the execution of the Merger Agreement with PSEG. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of Exelon and PSEG are integrated in an efficient and effective manner, as well as general competitive factors in the market place. Failure to achieve these anticipated benefits from the Merger or other strategic investments could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial condition, operating results and prospects. See the Proposed Merger with PSEG section below for further risk information.

Proposed Merger with PSEG

The business of PSEG and its subsidiaries is subject to various risks similar to risks associated with the business of Exelon and its subsidiaries. Upon completion of the Merger, the combined

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company will be subject to these risks of PSEG and its subsidiaries. In addition, there are various risks associated with the proposed Merger including the following:

Exelon and PSEG could fail to complete the Merger for various reasons, which could have an adverse effect on Exelon.

Several events must occur before the Merger may be completed, such as the receipt of the required regulatory approvals and the satisfaction of various conditions to the obligations of each of Exelon and PSEG, including:

In addition, the Merger Agreement may be terminated at any time prior to completion of the Merger by mutual written consent of Exelon and PSEG, by either party if a governmental authority takes any final action prohibiting the Merger, by either party if a governmental authority approves the Merger but issues a burdensome order (as defined in the Merger Agreement), or by either party if the Merger is not completed by June 20, 2006. In addition, the Merger Agreement may be terminated by Exelon for various specific reasons, including a material breach of any agreement of PSEG in the Merger Agreement which would result in a closing condition to the Merger not being satisfied and which cannot be cured by PSEG within 30 days after written notice is given by Exelon. PSEG can terminate the Merger Agreement for various specific reasons, including a material breach of any agreement of Exelon in the Merger Agreement which would result in a closing condition to the Merger not being satisfied and which cannot be cured by Exelon within 30 days after written notice is given by PSEG. If the Merger were unable to be consummated, Exelon would be required to expense previously capitalized Merger costs, totaling $46 million at December 31, 2005, which would negatively impact its results of operations.

Exelon may be unable to successfully integrate PSEG’s operations or realize all of the synergies expected to be derived from the Merger.

The Merger involves the integration of two companies that previously operated independently. The difficulties of combining each company’s operations include:

In addition, the integration of some of Exelon’s and PSEG’s operations will require regulatory approval.

Exelon recognizes that the process of integrating operations could cause an interruption of, or loss of momentum in, the activities of one or more of the combined company’s businesses. The diversion of management’s attention and any delays or difficulties encountered in connection with the Merger and the integration of the two companies’ operations could have an adverse effect on the business,

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financial condition, operating results and prospects of the combined company after the Merger, and could impair the combined company’s ability to realize the expected synergies and other anticipated benefits of the Merger.

The application of the purchase method of accounting will result in approximately $6 billion to $7 billion of additional goodwill, which could become impaired following completion of the Merger.

Under the purchase method of accounting, the total purchase price paid by Exelon in the Merger will be allocated to PSEG’s tangible and intangible assets and liabilities based on their fair values as of the date of completion of the Merger. The excess of the purchase price over those fair values will be recorded as goodwill. Exelon expects that the Merger will result in the creation of approximately $6 billion to $7 billion in goodwill based upon the assumptions as of the date of the completion of the Merger. As a result, upon completion of the Merger, the combined company will have approximately $10 billion to $11 billion in goodwill. To the extent the value of goodwill or intangibles becomes impaired, the combined company may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on the combined company’s operating results.

The combined company may be unable to obtain permission from the NJBPU to recover Public Service Electric and Gas Company’s pension and other postretirement benefit expenses, which could have an adverse effect on its cash flow and results of operation.

Public Service Electric and Gas Company (PSE&G), a public utility subsidiary of PSEG, is permitted by its current NJBPU rate order to recover through its rates the amortized portion of its pension expenses and other postretirement benefit expenses associated with its pension and postretirement obligations. As a result of the application of the purchase method of accounting to these costs, the recognition of certain unrecognized pension and other postretirement benefit expenses will be accelerated and, as a result, will no longer be reflected in the calculation of pension and other postretirement benefit expenses that PSE&G’s current rate order permits it to recover. PSE&G estimates that it could have as much as $1.4 billion in unrecognized pension and other postretirement benefit expenses that it may be unable to recover following completion of the Merger unless it obtains approval from the NJBPU to permit continued recovery of those expenses in the manner the current rate order permits. Exelon and PSEG have made it a condition to completion of the Merger that PSE&G receive an order from the NJBPU permitting PSE&G to continue to recover the pension expenses as it did prior to completion of the Merger. PSE&G has requested such an order in the Merger approval proceeding, and no party has objected to the request for recovery, provided that the requested recovery of pension and postretirement expense would not be expected to increase rates above current levels. However, there is no assurance that PSE&G will receive such an order from NJBPU or that if it does receive such an order, it will be permitted in future rate proceedings to continue to recover these expenses. Failure to obtain or maintain the right to recover the pension and other postretirement benefit expenses would have an adverse effect on the combined company’s cash flow and results of operations.

Exelon will incur significant transaction and Merger-related integration costs in connection with the Merger.

Exelon expects to incur costs associated with consummating the Merger and integrating the operations of Exelon and PSEG, as well as approximately $41 million in transaction costs. The estimated $41 million of transaction costs incurred by Exelon will be included as a component of the purchase price for purposes of purchase accounting. The amount of transaction fees expected to be incurred is a preliminary estimate and subject to change. Exelon has estimated the integration costs

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associated with the Merger to be approximately $700 million over a period of four years, with approximately $400 million being incurred in the first full year of operations following completion of the Merger. These estimates may change, and additional unanticipated costs may be incurred in the integration of the businesses of the two companies. Although Exelon believes that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, will offset incremental transaction and Merger-related costs over time, it cannot give any assurance that this net benefit will be achieved in the near term, or at all.

Exelon and PSEG will be subject to business uncertainties and contractual restrictions while completion of the Merger is pending that could adversely affect their businesses.

Uncertainty about the effect of the Merger on employees and customers may have an adverse effect on Exelon and PSEG and, consequently, on the combined company. Although Exelon and PSEG have taken and will continue to take steps to reduce adverse effects, these uncertainties may impair Exelon’s and PSEG’s ability to attract, retain and motivate key personnel until the Merger is consummated and for a period of time thereafter, and could cause customers, suppliers and others that deal with Exelon and PSEG to seek to change existing business relationships with Exelon and PSEG. Employee retention may be particularly challenging during the pendency of the Merger, as employees may experience uncertainty about their future roles with the combined company. If, despite Exelon’s and PSEG’s retention efforts, key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, the combined company’s business could be seriously harmed. In addition, the Merger Agreement restricts Exelon and PSEG from making certain acquisitions and taking other specified actions until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent Exelon and PSEG from pursuing attractive business opportunities and making other changes to their businesses that may arise prior to completion of the Merger or termination of the Merger Agreement.

The combined company and its subsidiaries may be subject to adverse regulatory conditions following completion of the Merger.

Before the Merger may be completed, various approvals or consents must be obtained from various utility regulatory, antitrust and other authorities in the United States and in foreign jurisdictions. The governmental entities from which these approvals are required may fail to approve the Merger, impose conditions on completion of the Merger, or require changes to the terms of the Merger. These conditions or changes could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company following the Merger, any of which might have a material adverse effect on the combined company following completion of the Merger.

On July 1, 2005, the FERC issued an order approving the Merger and the market concentration mitigation plan proposed by Exelon and PSEG. Exelon, PSEG and the combined company may incur significant expenses in completing the divestitures contemplated by the market concentration mitigation plan. In addition, they may have difficulty in successfully completing the divestitures for a variety of reasons and the amounts that may be realized from the divestitures will depend on market conditions that fluctuate. As a result, the pricing and other terms realized on the divestiture may be materially different from what is currently expected.

On September 13, 2005, PECO filed before the PAPUC a partial settlement regarding PECO’s distribution and transmission rates through 2010 and made other financial commitments contingent upon the approval of PECO’s application to the PAPUC related to the Merger. See “Partial Settlements Before the PAPUC” in ITEM 1. Business for further detail. The settlement and the Merger have received PAPUC approval but the settlement will not become effective unless the Merger is completed. The completion of this settlement will negatively impact the results of operations of PECO and the combined company.

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Under the combined company’s holding company structure, the payment of dividends to shareholders will be subject to the ability of its subsidiaries to pay dividends.

The combined company will be a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of the combined company’s operations will be conducted by its subsidiaries. The combined company’s ability to pay dividends on its common stock will depend on the payment to it of dividends by its operating subsidiaries. These subsidiaries’ payments of dividends to the combined company in turn depend on their results of operations and cash flows and other items impacting retained earnings. Under applicable law, PSE&G can pay dividends only from the amount of retained, undistributed or current earnings. Following completion of the Merger, a significant loss recorded at PSE&G may limit the dividends that PSE&G can distribute to Exelon. As a condition to approval of other utility mergers, the NJBPU has imposed dividends restrictions. Exelon can give no assurance that a similar restriction will not be imposed on PSE&G. In addition, PSEG Energy Holdings LLC and its subsidiaries are parties to debt agreements that restrict their ability to pay dividends, make cash distributions or otherwise transfer funds to PSEG, or after completion of the Merger, the combined company.

PSEG’s business is, and the combined company’s business will be, subject to extensive regulation that will affect operations and costs.

The combined company will be subject to regulation by FERC and the NRC, by Federal, state and local authorities under environmental laws and by state public utility commissions under laws regulating Exelon’s and PSEG’s distribution businesses, among others. See “Changes in ComEd’s and PECO’s terms and conditions of service, including its rates, are subject to regulatory approval proceedings that are contentious, lengthy and subject to appeal, which introduce time delays in effecting rate changes as well as uncertainty as to the ultimate result” above for further discussion. Additionally, the combined company will also be subject to additional risks currently applicable to PSEG as described below.

PSE&G’s New Jersey base rates for electric and gas distribution are subject to regulation by the NJBPU and are effective until a new base rate case is filed and concluded. In addition, limited categories of costs are recovered through adjustment charges that are periodically reset to reflect current costs. The inability to recover material costs not included in base rates or adjustment clauses could have an adverse effect on cash flow and financial position of the combined company.

PSEG Global LLC (PSEG Global) is a subsidiary of PSEG with rate-regulated electric and gas distribution facilities located in various foreign jurisdictions. Governmental authorities establish rates charged to customers. While these rates are designed to cover all operating costs and provide a return, considerable fiscal and cash uncertainties in certain countries due to local regulation or economic, political and social crisis could have an adverse impact. In addition, future rates may not be adequate to provide cash flow to pay principal and interest on the debt of PSEG Global’s subsidiaries and affiliates or to enable its subsidiaries and affiliates to comply with the terms of debt agreements.

The combined company’s generation business may incur additional costs and liabilities due to its ownership and operation of additional nuclear facilities.

Following completion of the Merger, it is expected that, prior to giving effect to any divestitures required by governmental authorities to complete the Merger and prior to implementing the combined company’s anticipated strategy of divesting assets that do not meet the strategic objectives of the combined company, approximately 46% of the combined company’s owned generation capacity will be nuclear and the combined company will own approximately 20% of the nuclear generation capacity in the United States. To the extent there are divestitures of fossil assets, such as described in “The

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combined company may be subject to adverse regulatory conditions following completion of the Merger” above, the percentage of the combined company’s owned generation capacity which is nuclear will increase. Accordingly, the combined company will have greater exposure to risks that adversely affect the nuclear generation industry compared to other companies in the utility industry. See “Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of nuclear facilities” above for further discussion.

The combined company’s generation business may incur additional costs and liabilities and be exposed to volatility as a result of expanded participation in the wholesale energy markets.

Generation and PSEG, and the combined company, will sell electricity in the wholesale energy markets. Generation and PSEG are subject to many of the same risks in the wholesale energy markets. See “Generation is exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations” above for further discussion. Following completion of the proposed Merger, the combined company will be subject to additional risks associated with participation in the wholesale energy markets as described below.

The trading business of the combined company after the Merger will be required to meet credit quality standards. If the generation business of the combined company were to lose its investment grade credit rating or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under trading agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect the liquidity of the combined company. See “Generation is exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations” above for further discussion. If PSEG Power had lost its investment grade credit rating as of December 31, 2005, it would have been required to provide approximately $916 million in additional collateral. Due to the increased size of the combined company’s generation business, a trading counterparty that does business with both Generation and PSEG Power might impose credit limits or other credit quality standards on the combined company’s generation business that are more restrictive than would otherwise be applicable to Generation and PSEG Power as separate operations.

The IRS might successfully challenge certain leveraged lease transactions entered into by PSEG, which could have a material adverse impact on the combined company’s operating results.

From 1996 through 2002, PSEG, through its indirect wholly owned subsidiary, PSEG Resources, entered into a number of leveraged lease transactions in the ordinary course of business. Certain of those transactions that were previously entered into are similar to a type that the IRS subsequently announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of review and challenge by the IRS. The IRS is presently reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2000, years when Resources entered into some of these transactions.

On September 27, 2005, the IRS proposed to disallow PSEG’s deductions associated with certain of these leveraged leases which have been designated by the IRS as listed transactions. Other lease transactions within the audit period are still under the IRS’s review. The IRS may propose additional disallowances in the future. If deductions associated with these lease transactions entered into by PSEG are successfully challenged by the IRS, it could have a material adverse impact on the combined company’s financial position, results of operations and net cash flows and could impact future returns on these transactions.

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If the tax benefits associated with the above referenced lease transactions were completely disallowed by the IRS, approximately $660 million of deferred tax liabilities that have been recorded under leveraged lease accounting through December 31, 2005 could become currently payable. In addition, interest expense of approximately $86 million, after tax, and penalties could be assessed.

The FASB is currently considering a modification to GAAP for leveraged leases. Under present GAAP, a tax settlement with the IRS that results in a change in the timing of tax liabilities would not require an accounting repricing of the lease investment. As such, income from the lease would continue to accrue at the original economic yield computed for the lease and there would be no write-down of the lease investment.

The proposal concerning leveraged leases would require a lessor to perform a recalculation of a leveraged lease when there is a change in the timing of the realization of tax benefits generated by the lease. It would also require a lessor to re-evaluate classification as a leveraged lease when a recalculation of the lease is performed. If implemented in its present form, the impact of this proposal on the combined company could be material.

Because a portion of the combined company’s business will be conducted outside the United States, adverse international developments could negatively impact its business.

Following completion of the Merger and prior to implementing the combined company’s anticipated strategy of divesting assets that do not meet the strategic objectives of the combined company, it is expected that revenues generated from sources outside the United States and assets located outside the United States will each be less than 5% of the total combined company, most of which will be held by and generated from PSEG Global.

The economic and political conditions in certain countries where PSEG Global has interests present risks that may be different from, or more extensive than, those found in the United States including:

Changes in the legal environment in foreign countries in which PSEG Global has investments could make it more difficult to obtain non-recourse project refinancing on suitable terms and could impair PSEG Global’s ability to enforce its rights under agreements relating to such projects. In addition, such changes could make it more difficult for the combined company to pursue an accelerated strategy of selling certain of PSEG Global’s investments that no longer meet the strategic objectives of the combined company.

Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In countries in which PSEG Global operates in the future, economic and monetary conditions and other factors could affect PSEG Global’s ability to convert its cash distributions to United States dollars or other freely convertible currencies, or to move funds offshore from these countries. Furthermore, the central bank of any of these countries may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to

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approve distributions to foreign investors. Although PSEG Global generally seeks to structure purchase power contracts and other project revenue agreements to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars, its ability to do so in all cases may be limited.

The combined company’s results of operations may be affected by its ability to divest unprofitable or under-performing businesses.

The combined company will pursue opportunities to sell businesses and assets that either do not meet the strategic objectives of the combined company or are unprofitable. The combined company may incur significant expenses in divesting these businesses. The combined company also may be unable to successfully implement this strategy for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for the transactions. In addition, the amounts that the combined company may realize from a divestiture are 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 combined company’s results of operations and cash flows.

Exelon, ComEd, PECO and Generation

None.

ComEd and PECO

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

Transmission and Distribution

ComEd’s and PECO’s higher voltage electric transmission lines owned and in service at December 31, 2005 were as follows:

ComEd’s electric distribution system includes 43,082 circuit miles of overhead lines and 33,804 cable miles of underground lines. PECO’s electric distribution system includes 12,873 circuit miles of overhead lines and 15,201 cable miles of underground lines.

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Gas

The following table sets forth PECO’s gas pipeline miles at December 31, 2005:

PECO has an LNG facility located in West Conshohocken, Pennsylvania which has a storage capacity of 1,200 mmcf and a send-out capacity of 157 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peaking capability of 25 mmcf/day. In addition, PECO owns 29 natural gas city gate stations at various locations throughout its gas service territory.

Mortgages

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

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

Insurance

ComEd and PECO maintain property insurance against loss or damage to their respective properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd and PECO are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of ComEd or PECO.

Generation

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2005. The table does not include properties held by equity method investments: