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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the Fiscal Year Ended December 31, 2010

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    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.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange 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, 2010, was as follows:

The number of shares outstanding of each registrant’s common stock as of January 31, 2011 was as follows:

Documents Incorporated by Reference

Portions of the Exelon Proxy Statement for the 2011 Annual Meeting of

Shareholders are incorporated by reference in Part III.

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GLOSSARY OF TERMS AND ABBREVIATIONS

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FILING FORMAT

This combined Form 10-K is being filed separately by Exelon, Generation, ComEd and PECO. 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 factors with respect to such Registrant 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: Note 18 and (d) other factors discussed in filings with the 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 Bruce G. Wilson, Senior Vice President, Deputy General Counsel, and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

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PART I

General

Exelon, a utility services holding company, operates through its principal subsidiaries—Generation, ComEd and PECO—as described below, each of which is treated as a reportable segment by Exelon. See Note 20 of the Combined Notes to Consolidated Financial Statements for additional 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.

Generation

Generation’s business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and its competitive retail supply operations. Generation has three reportable segments consisting of the Mid-Atlantic, Midwest, and South and West regions.

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 businesses at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-5959.

ComEd

ComEd’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to retail 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 retail sale of electricity and the provision of transmission and distribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of 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

Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MW. Generation combines its large generation fleet with an

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experienced wholesale energy marketing operation and a competitive retail supply operation. Generation’s presence in well-developed wholesale energy markets, integrated hedging strategy that mitigates the adverse impact of short-term market volatility, and low-cost nuclear generating fleet, which is operated consistently at high capacity factors, position it well to succeed in competitive energy markets.

At December 31, 2010, Generation owned generation resources with an aggregate net capacity of 25,619 MW, including 17,047 MW of nuclear capacity. Generation controlled another 6,139 MW of capacity through long-term contracts.

Generation’s wholesale marketing unit, Power Team, draws upon Generation’s energy generation portfolio and logistical expertise to ensure delivery of energy to Generation’s wholesale customers under long-term and short-term contracts and in spot markets.

Generation’s retail business provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Pennsylvania, Michigan and Ohio. Generation’s retail business is dependent upon continued deregulation of retail electric and gas markets and Generation’s ability to obtain supplies of electricity and gas at competitive prices in the wholesale market.

Generation is a public utility under the Federal Power Act, which gives the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. The FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of utilities (including Generation, which is a public utility as FERC defines that term) and set cost-based rates should the FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities. Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC and Federal and state environmental protection agencies. Additionally, Generation is subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC.

RTOs exist in a number of regions to provide transmission service across multiple transmission systems. To date, PJM, the MISO, ISO-NE and Southwest Power Pool, have been approved as RTOs. These entities are responsible for regional planning, managing transmission congestion, developing larger wholesale markets for energy and capacity, maintaining reliability, market monitoring and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems.

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Generating Resources

At December 31, 2010, the generating resources of Generation consisted of the following:

Generation has three reportable segments, the Mid-Atlantic, Midwest, and South and West, representing the different geographical areas in which Generation’s power marketing activities are conducted and where Generation’s owned and contracted generating resources are located. Mid-Atlantic represents Generation’s operations primarily in Pennsylvania, New Jersey and Maryland (approximately 36% of capacity); Midwest includes the operations in Illinois, Indiana, Michigan and Minnesota (approximately 46% of capacity); and the South and West includes operations primarily in Texas, Georgia, Oklahoma, Kansas, Missouri, Idaho and Oregon (approximately 18% of capacity).

Nuclear Facilities

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with an aggregate of 17,047 MW of capacity. Generation wholly-owns all of its nuclear generating stations, except for Quad Cities Generating Station (75% ownership), Peach Bottom Generating Station (50% ownership) and Salem Generating Station (Salem) (42.59% ownership). Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2010 and 2009, electric supply (in GWh) generated from the nuclear generating facilities was 82% and 81%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric and renewable generation and electric supply purchased for resale. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion of Generation’s electric supply sources.

AmerGen Reorganization. AmerGen, a wholly owned subsidiary of Generation through January 8, 2009, owned and operated the Clinton Nuclear Power Station (Clinton), the Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek) through that time. Effective January 8, 2009, AmerGen was merged into Generation, which now holds the operating licenses for Clinton, TMI and Oyster Creek.

Oyster Creek Station Shutdown. On December 8, 2010, in connection with the executed Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding the closure of Oyster Creek.

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Nuclear Operations. Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on Generation’s results of operations. 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 minimal environmental impact from operations and a safe operating history.

During 2010 and 2009, the nuclear generating facilities operated by Generation achieved capacity factors of 93.9% and 93.6%, respectively. Generation aggressively manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s short and long-term supply commitments and Power Team marketing and trading activities. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe reliable operations.

In addition to the rigorous maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation has extensive safety systems in place to protect the plant, personnel and surrounding area in the unlikely event of an accident.

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 for operation of each unit. 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. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results, and communicates its assessment on a semi-annual basis. As of December 31, 2010, the NRC categorized each unit operated by Generation in the Licensee Response Column, which is the highest performance band. 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 the operating 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.

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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, Quad Cities Units 1 and 2, Oyster Creek and Three Mile Island Unit 1. The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:

On May 29, 2009, a coalition of citizen groups filed a Petition for Review of the NRC’s renewal of Oyster Creek’s operating license in the United States Court of Appeals for the Third Circuit. Oral argument was held before the Court on January 5, 2011. If the appeal is successful, it is unlikely that it would result in a revocation of the renewed license; however, it could cause the NRC to impose additional conditions over the course of the period of extended operation.

On August 18, 2009, PSEG submitted an application to the NRC to extend the operating licenses of Salem Units 1 and 2 by 20 years. The NRC is expected to spend a total of 22 to 30 months to review the application before making a decision.

Generation expects to apply for and obtain approval of license renewals for the remaining nuclear units. The operating license renewal process takes approximately four to five years from the commencement of the renewal process 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 original license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual and assumed renewal of operating licenses for all of Generation’s operating nuclear generating stations.

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Nuclear Uprate Program. During 2009, Generation announced a series of planned power uprates across its nuclear fleet that will result in between 1,300 and 1,500 MW of additional generation capacity within eight years. The uprate projects represent a total investment of approximately $3.65 billion in overnight cost, as measured in 2010 dollars. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects, representing approximately 60% of the planned uprate MW, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The remainder will come from additional projects across Generation’s nuclear fleet beginning in 2011 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates are being undertaken pursuant to an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the projects in light of changing market conditions. As part of this periodic review process, the uprate project at Three Mile Island is currently under evaluation. The amount of expenditures to implement the plan ultimately will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards. The ability to implement several projects requires the successful resolution of various technical issues. The resolution of these issues may affect the timing and amount of the power increases associated with the power uprate initiative. Through December 31, 2010, Generation has added 101 MWs of nuclear generation through its uprate program, with another 98 MWs scheduled to be added in 2011.

New Site Development. Generation is keeping open the option of a new nuclear plant located in Victoria County in southeast Texas; however, Generation has not made a decision to build a nuclear plant at this time. In response to the overall downturn of the economy and the projection of sustained, low natural gas prices, Exelon revised its new nuclear plant development strategy. Exelon had previously submitted a Combined Construction and Operating License (COL) application to the NRC for the Victoria site. On March 25, 2010, Exelon submitted an application for an Early Site Permit (ESP) application for the site and subsequently withdrew its COL application. The ESP allows Exelon to establish the suitability of the Victoria site, which lessens the amount of work to do should it later decide to reapply for a COL. Additionally, the ESP accommodates a variety of possible future plant designs, allowing for flexibility in selecting a reactor technology later as part of a COL application. If approved by the NRC, the ESP would effectively reserve the site for 20 years with the possibility of renewal for another 20 years. Any decision to build at the Victoria County site would be made later based on then current economics. The Exelon board authorized a budget of $130 million for the Victoria County project, of which a total of $108 million had been expensed through December 31, 2010. The review and approval schedule published by the NRC estimates final issuance of the ESP in late 2014.

Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities in on-site storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask storage facilities to support operations.

As of December 31, 2010, Generation had approximately 54,300 SNF assemblies (13,100 tons) stored on site in SNF pools or dry cask storage (this includes SNF at Zion Station, for which Generation retains ownership, see Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning). 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 through the end of the license renewal periods, and through

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decommissioning. The following table describes the current status of Generation’s SNF storage facilities.

For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 18 of the Combined Notes to Consolidated Financial Statements.

As a by-product of their operations, nuclear generating units produce 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 anticipated to be operational until after 2020. Pennsylvania, which had agreed to be the host site for LLRW disposal facilities for generators located in Pennsylvania, Delaware, Maryland and West Virginia, has suspended the search for a permanent disposal site.

Generation is currently utilizing on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its Class A LLRW, which represent 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Oyster Creek and Salem), and Connecticut. Generation has pending license amendments for its Peach Bottom and LaSalle stations that will allow it to store LLRW from its remaining stations that have limited capacity. If approved, there will enough storage capacity to store all Class B and C LLRW for the life of all stations in Generations nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize cost impacts and on-site storage.

Nuclear Insurance. Generation is subject to liability, property damage and other risks associated with a major accidental outage at any of its nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 18 of the Combined Notes to Consolidated Financial Statements for details.

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 Exelon’s and Generation’s financial condition and results of operations.

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Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Exelon Corporation, Executive Overview; ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates, Nuclear Decommissioning Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Notes 2, 8 and 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.

Dresden Unit 1 and Peach Bottom Unit 1 have ceased power generation. SNF at Dresden Unit 1 is currently being stored in dry cask storage until a permanent repository under the NWPA is completed. All SNF for Peach Bottom Unit 1, which ceased operation in 1974, has been removed from the site and the SNF pool is drained and decontaminated. Generation’s estimated liability to decommission Dresden Unit 1 and Peach Bottom Unit 1 was $182 million at December 31, 2010. As of December 31, 2010, NDT funds set aside to pay for these obligations were $330 million.

Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC. (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998.

On September 1, 2010, Generation and EnergySolutions completed the transactions contemplated by the ASA. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities associated with Zion Station. Pursuant to the ASA, ZionSolutions can periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request reimbursement; specifically, if certain milestones as defined in the ASA are not met, all or a portion of requested reimbursements shall be deferred until such milestones are met. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning.

Fossil, Hydroelectric and Renewable Facilities

Generation operates various fossil, hydroelectric and renewable facilities and maintains ownership interests in several other facilities including LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2010 and 2009, electric supply (in GWh) generated from owned fossil, hydroelectric and renewable generating facilities was 6% of Generation’s total electric supply. 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.

John Deere Renewables. On December 9, 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power, for approximately $893 million in cash. Generation acquired 735 MWs of installed, operating wind capacity located in eight states. Approximately 75% of the operating portfolio’s expected output is already sold under long-term power purchase arrangements. Additionally, Generation will pay up to $40 million related to three projects with a capacity of 230 MWs which are currently in advanced stages of development, contingent upon meeting certain contractual commitments related to the commencement of construction of each project. This contingent consideration was valued at $32 million of which approximately $16 million has been recorded as a current liability and the remainder has been recorded as a noncurrent liability. As a result, total

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consideration recorded for the Exelon Wind acquisition was $925 million. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Exelon Wind acquisition.

Plant Retirements. On December 2, 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station (Cromby) Unit 1 and Unit 2 and Eddystone Generating Station (Eddystone) Unit 1 and Unit 2. These actions were in response to the economic outlook related to the continued operation of these four units. Subsequently, PJM determined that transmission reliability upgrades will be necessary to alleviate reliability impacts and that those upgrades will be completed in a manner that will permit Generation’s retirement of the units on the following schedule: Cromby Unit 1 and Eddystone Unit 1 on May 31, 2011; Cromby Unit 2 on December 31, 2011; and Eddystone Unit 2 on June 1, 2012. These dates are dependent upon the completion of required transmission reliability upgrades and may be subject to further change. Generation revised the depreciable useful lives for the affected units to reflect the revised deactivation dates. For more information regarding plant retirements, see Note 14 of the Combined Notes to Consolidated Financial Statements.

Licenses. Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid. The license for the Conowingo Hydroelectric Project expires on August 31, 2014 and for the Muddy Run Pumped Storage Facility Project expires on September 1, 2014. In March 2009, Generation filed a Pre-Application Document and Notice of Intent to renew the licenses, pursuant to FERC relicensing requirements. For those plants located within the control areas administered by PJM or the New England control area administered by ISO-NE, notice is required to be provided to PJM or ISO-NE, as applicable, before a plant can be retired.

Insurance. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. Generation maintains both property damage and liability insurance. For property damage and liability claims, Generation is self-insured to 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 following long-term contracts in effect as of December 31, 2010:

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Fuel

The following table shows sources of electric supply in GWh for 2010 and estimated for 2011:

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 wholesale obligations, including to ComEd and PECO, and some of Generation’s retail business requirements.

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 2015. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2015. All of Generation’s enrichment requirements have been contracted through 2012. Contracts for fuel fabrication have been obtained through 2013. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services to meet the nuclear fuel requirements of its nuclear units.

Coal is procured primarily through annual supply contracts, with the remainder supplied through either short-term contracts or spot-market purchases.

Natural gas is procured through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or natural 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 certain commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments. See Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates and Note 9 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.

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Power Team

Generation’s wholesale marketing and retail electric supplier operations include the physical delivery and marketing of power obtained through its generation capacity and through long-term, intermediate-term and short-term contracts. Generation seeks to maintain a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential 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. PPAs are commitments related to power generation of specific generation plants and/or are dispatchable in nature similar to asset ownership. Generation enters into PPAs as part of its overall strategic plan, with objectives such as obtaining low-cost energy supply sources to meet its physical delivery obligations to customers and assisting customers to meet renewable portfolio standards. Generation may buy power to meet the energy demand of its customers, including ComEd and PECO. These purchases may be 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 electricity markets. Where necessary, Generation also purchases transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs in markets without an organized RTO. Generation also 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.

Generation also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation also enters into transactions that are outside of this ratable sales plan, such as a financial swap with ComEd that is described below and runs into 2013. However, except for the ComEd swap arrangement, Generation is exposed to relatively greater commodity price risk beyond 2011 for which a larger portion of its electricity portfolio may be unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years. As of December 31, 2010, the percentage of expected generation hedged was 90%-93%, 67%-70%, and 32%-35% for 2011, 2012 and 2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts, including sales to ComEd and PECO to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. 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 RMC monitor the financial risks of the power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts.

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At December 31, 2010, Generation’s short and long-term commitments relating to the purchase and sale of energy and capacity from and to unaffiliated utilities and others were as follows:

ComEd procures all of its electricity through a competitive procurement process, through which Generation supplies a portion of ComEd’s load. Additionally, in order to fulfill a requirement of the Illinois Settlement, Generation and ComEd entered into a five-year financial swap contract that expires on May 31, 2013. See ComEd—Retail Electric Services, Procurement Related Proceedings for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

Generation had a PPA with PECO under which Generation supplied PECO with all of PECO’s electric supply needs through December 31, 2010. Generation supplied electricity to PECO from its portfolio of generation assets, PPAs and other market sources. As of January 1, 2011, PECO procures all of its electricity through a competitive procurement process, through which Generation will continue to supply a portion of PECO’s load. See PECO—Retail Electric Services, Procurement Related Proceedings for additional information regarding PECO’s competitive, full-requirements energy-supply procurement process after 2010.

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 2011 are as follows:

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ComEd

ComEd is engaged principally in the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to a diverse base of residential, commercial and industrial customers in northern Illinois. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the ICC related to distribution rates and service, the issuance of securities, and certain other aspects of ComEd’s business. ComEd is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of ComEd’s business. Specific operations of ComEd are also subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, ComEd is subject to mandatory reliability standards set by the NERC.

ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of 9 million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of 3 million. ComEd has approximately 3.8 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 2011 to 2066. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

ComEd’s kWh sales and peak electricity load are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating. ComEd’s highest peak load occurred on August 1, 2006 and was 23,613 MW; its highest peak load during a winter season occurred on January 15, 2009 and was 16,328 MW.

Retail Electric Services

Under Illinois law, transmission and distribution service is regulated, while electric customers are allowed to purchase generation from a competitive electric generation supplier.

At December 31, 2010, approximately 66,200 retail customers (primarily commercial and industrial customers), representing approximately 52% of ComEd’s annual retail kWh sales, had elected to purchase their electricity from a competitive electric generation supplier. There are currently a minimal number of residential customers being served by alternate suppliers. Customers who receive electricity from a competitive electric generation supplier continue to pay a delivery charge to ComEd. Under the current regulatory mechanisms in effect, ComEd is permitted to recover its electricity procurement costs from retail customers, without mark-up. Thus, although energy sales affect ComEd’s reported revenues, they do not affect its net income, as the energy sales are offset by equal amount of purchased power expense.

Under Illinois law, ComEd is required to deliver electricity to all customers. ComEd’s obligation to provide generation supply service, which is referred to as a POLR obligation, primarily varies by customer size. ComEd’s obligation to provide such service to residential customers and other small customers with demands of under 100 kW continues for all customers who do not or cannot choose a competitive electric generation supplier or who choose to return to the utility after taking service from a competitive electric generation supplier. ComEd does not have a fixed-price generation supply service obligation to most of its largest customers with demands of 100 kW or greater, as this group of customers has previously been declared competitive. Beginning June 2010 ComEd had no fixed price generation supply service obligations for customers with demands of 100-400 kW. Customers with competitive declarations may still purchase power and energy from ComEd, but only at hourly market prices.

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Procurement Related Proceedings. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Beginning on January 1, 2007, ComEd procured 100% of energy to meet its load service requirements through ICC-approved staggered SFCs with various suppliers, including Generation. Beginning in June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement, ComEd hedged the price of a significant portion of energy purchased on the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. See Notes 2 and 9 of the Combined Notes to Consolidated Financial Statements for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

Electric Distribution Rate Cases. The ICC issued an order in ComEd’s 2007 electric distribution rate case approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). On November 18, 2010, the Court denied ComEd’s petition for rehearing in connection with the September 30, 2010 ruling. On January 25, 2011, ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court. Subsequent to the Illinois Appellate Court’s ruling, ComEd filed a request with the ICC to allow it to request recovery, through inclusion in the 2010 Rate Case, of $3 million in operation and maintenance costs, as well as carrying costs associated with capital investment in the ICC-approved AMI/Customer Applications pilot program. The AMI pilot program capital investment had already been requested in rate base in the 2010 Rate Case. On December 2, 2010, the ICC approved ComEd’s request. The investment and the pilot program costs are subject to challenge in the 2010 Rate Case proceeding.

On June 30, 2010, ComEd requested ICC approval for an increase of $396 million, subsequently changed to $326 million, to its annual delivery services revenue requirement (2010 Rate Case) to allow ComEd to continue modernizing its electric delivery system and recover the costs of substantial investments made since its last rate filing in 2007. The requested rate increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The Court’s September 30, 2010 ruling in connection with ComEd’s 2007 electric distribution rate case makes it highly unlikely that the ICC would decide the post-test year accumulated depreciation issue in ComEd’s favor in the 2010 Rate Case. ComEd estimates that its requested revenue requirement increase of $326 million could be reduced by approximately $85 million as a result of this adjustment. Certain parties have submitted testimony recommending significant reductions to ComEd’s requested increase as well as the write-off of certain assets, most notably the regulatory asset associated with severance costs, which was approximately $74 million as of December 31, 2010. Management believes the regulatory asset is appropriate based on the ICC’s orders in ComEd’s last two rate cases. The new electric distribution rates are expected to take effect no later than June 2011. ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s rate case proceedings.

Other. Illinois law provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) 30,000 or more customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the

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utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. ComEd does not believe that during the years 2010, 2009 and 2008 it had any interruptions that have triggered this damage liability or reimbursement requirement.

Construction Budget

ComEd’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities, to ensure the adequate capacity and reliability of its system. Based on PJM’s RTEP, ComEd has various construction commitments, as discussed in Note 18 of the Combined Notes to Consolidated Financial Statements. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2011 is $1,015 million which includes RTEP projects. See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for further information.

PECO

PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the PAPUC as to electric and gas distribution rates and service, the issuances of certain securities and certain other aspects of PECO’s operations. PECO is a public utility under the Federal Power Act subject to regulation by FERC as to transmission rates and certain other aspects of PECO’s business and by the U.S. Department of Transportation as to pipeline safety and other aspects of gas operations. Specific operations of PECO are subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, PECO is also subject to NERC mandatory reliability standards.

PECO’s combined electric and natural gas 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 1,900 square miles, with a population of approximately 3.8 million, including approximately 1.5 million in the City of Philadelphia. PECO supplies natural gas service 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 1.6 million customers and natural gas to approximately 490,000 customers.

PECO has the necessary authorizations to deliver regulated electric and natural 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 “grandfathered rights,” which are rights generally unlimited as to time and generally exclusive from competition from other electric and natural gas utilities. In a few defined municipalities, PECO’s natural gas service territory authorizations overlap with that of another natural gas utility but PECO does not consider those situations as posing a material competitive or financial threat.

PECO’s kWh sales and peak electricity load are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating. PECO’s highest peak load occurred on August 3, 2006 and was 8,932 MW; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MW.

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

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Retail Electric Services

PECO’s retail electric sales and distribution revenues are derived pursuant to rates regulated by the PAPUC. Under the 1998 restructuring settlement, PECO’s electric generation rates were capped through a transition period which ended on December 31, 2010. During the transition period, PECO was authorized to recover from customers $5.3 billion of costs that might not have otherwise been recovered in a competitive market (stranded costs) with a 10.75% return on the unamortized balance through the imposition and collection of a non-bypassable CTC, which was a component of the capped electric generation rate on customer bills. At December 31, 2010, PECO’s stranded costs were fully recovered.

Beginning January 1, 2011, PECO’s electric supply procurement cost rates charged to default service customers are subject to quarterly adjustments designed to recover or refund the difference between PECO’s actual cost of electricity delivered and the amount included in rates without markup through the GSA.

Pennsylvania permits competition by EGSs for the supply of retail electricity while transmission and distribution service remains regulated under the Competition Act. For the year ended December 31, 2010, less than 1% of PECO’s residential and large commercial and industrial and 4% of its small commercial and industrial loads were purchased from alternative EGSs. The small percentage of customer load provided by an alternative EGS is due to the electric generation rate caps that were lower than current market prices throughout the transition period. Customers that choose an alternative EGS are not subject to PECO’s electric supply procurement cost rates. In preparation for the transition to market-based competitive pricing, multiple alternative EGSs began marketing to customers in PECO’s service territory. As of January 31, 2011, PECO believes that at least 10% of residential, 46% of small commercial and industrial and 86% of large commercial and industrial loads will be purchased from alternative EGSs. Beginning with January 2011 customer bills, PECO presented its electric supply Price to Compare, which will be updated quarterly, to assist customers with the evaluation of offers from alternative EGSs. PECO’s average residential Price to Compare for the first three months of 2011 is 9.92 cents per kWh.

Customer selection of an alternative EGS or PECO as default service provider does not impact PECO’s results of operations or financial position. PECO’s cost of electric supply is passed directly through to default service customers without markup. For those customers that choose an alternative EGS, PECO will act as the billing agent but will not record revenues or expenses related to this electric supply. PECO remains the distribution service provider for all the customers in its service territory and charges a regulated rate for delivery service. PECO receives transmission revenue from PJM for customers that select an alternative EGS.

Procurement Proceedings. Prior to January 1, 2011, PECO procured all its electric supply under a full requirements PPA with Generation, which expired on December 31, 2010. The term and procurement costs under the PPA with Generation corresponded with PECO’s transition period and capped electric generation rates in accordance with its 1998 restructuring settlement. Beginning January 1, 2011, PECO’s electric supply for its customers is procured through a competitive process in accordance with its PAPUC-approved DSP Program. During 2010, PECO entered into contracts with PAPUC-approved bidders for its third and fourth competitive procurements of electric supply for default electric service commencing January 2011, which included fixed price full requirement contracts for all procurement classes, spot market price full requirements contracts for the commercial and industrial procurement classes, and block energy contracts for the residential procurement class. As of December 31, 2010, including the previous competitive procurements completed in 2009 and 2010, the 2011 expected electric supply for all customer classes had been substantially procured. PECO will conduct five additional competitive procurements for electric supply for all customer classes during the term of its DSP Program.

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Electric Distribution Rate Case. In December 2010, the PAPUC approved a settlement of PECO’s electric distribution rate case filed in August 2010 that provides for an annual revenue increase of $225 million. The approved electric distribution rates became effective on January 1, 2011. The electric distribution rate case settlement and the electric supply procurement results indicate an increase of 5.1% in the average residential customer total electric bill in January 2011, above 2010 bills.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Smart Meter and Energy Efficiency Programs

Smart Meter Programs. In April 2010, the PAPUC approved PECO’s $550 million Smart Meter Procurement and Installation Plan, which was filed in accordance with the requirements of Act 129. PECO filed for PAPUC approval of an initial dynamic pricing and customer acceptance program in October 2010, and plans to file for approval of a universal meter deployment plan for its remaining customers in 2012.

Also, in April 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project—Smart Future Greater Philadelphia. As a result of the SGIG funding, PECO will deploy 600,000 smart meters within three years, accelerate universal deployment of more than 1.6 million smart meters from 15 years to 10 years and increase smart grid investments to approximately $100 million over the next three years. In total, over the next 10 years, PECO is planning to spend up to $650 million on its smart grid and smart meter infrastructure. The SGIG funding will be used to significantly reduce the impact of those investments on PECO customers.

Energy Efficiency Programs. In February 2010, the PAPUC approved PECO’s EE&C plan, which was filed pursuant to Act 129’s EE&C reduction targets. The approved four-year plan totals more than $330 million and includes a CFL program, weatherization programs, an energy efficiency appliance rebate and trade-in program, rebates and energy efficiency programs for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. In September 2010, PECO filed revisions to the EE&C Plan previously approved in February 2010 that included adjustments to certain incentive levels and the addition of energy efficiency measures to the existing portfolio. These revisions do not impact the total spending or timely recovery under the approved EE&C plan. On January 27, 2011, the PAPUC unanimously approved PECO’s EE&C Plan revisions.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Natural Gas

PECO’s natural gas sales and distribution revenues are derived pursuant to rates regulated by the PAPUC. PECO’s purchased natural 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 natural gas and the amount included in rates without markup through the PGC.

PECO’s natural gas customers have the right to choose their natural gas suppliers or to purchase their gas supply from PECO at cost. In 2010, 39% of PECO’s current total yearly throughput was provided by natural gas suppliers other than PECO and is related primarily to the supply of PECO’s large commercial and industrial customers. Natural gas distribution service provided to customers by

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PECO remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services at regulated rates.

Procurement Proceedings. PECO’s natural gas supply is provided through purchases from a number of suppliers. These purchases are primarily delivered under long-term firm transportation contracts for terms of up to two years. PECO’s aggregate annual firm supply under these firm transportation contracts is 46 million dekatherms. Peak natural gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 23 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 30% of PECO’s 2010-2011 heating season planned supplies.

Natural Gas Distribution Rate Cases. On January 1, 2009, PECO implemented the natural gas distribution rates approved by the PAPUC in its settlement of the 2008 natural gas distribution rate case that provided for an additional $77 million of revenue annually. In December 2010, the PAPUC approved a settlement of PECO’s natural gas distribution rate case filed in August 2010 that provides an increase in annual revenue of $20 million. The approved natural gas distribution rates became effective on January 1, 2011.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Construction Budget

PECO’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities to ensure the adequate capacity, reliability and efficiency of its system. Based on PJM’s RTEP, PECO has various construction commitments, including costs related to transmission system reliability upgrades due to Generation’s plant retirements, as discussed in Notes 14 and 18 of the Combined Notes to Consolidated Financial Statements. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2011 is $450 million, which includes capital expenditures related to the smart meter program and SGIG project net of DOE expected reimbursements.

ComEd and PECO

Transmission Services

ComEd and PECO provide unbundled transmission service under rates established by FERC. FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. Under FERC’s open access transmission policy promulgated in Order No. 888, 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. ComEd and PECO are required to comply with FERC’s Standards of Conduct regulation, as amended, governing the communication of non-public information between the transmission owner’s employees and wholesale merchant employees.

PJM is the ISO and the FERC-approved RTO for the Mid-Atlantic and Midwest regions. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for 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.

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ComEd’s transmission rates are established based on a formula that was approved by FERC in January 2008. FERC’s order establishes the agreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formula rate calculation on an annual basis.

As a result of PECO’s 1998 restructuring settlement, retail transmission rates were capped at the level in effect on December 31, 1996, which remained unchanged through December 31, 2010. PECO’s transmission rate included in the PJM Open Access Transmission Tariff is a FERC-approved rate. This is the rate that all load serving entities in the PECO transmission zone pay for transmission service. PECO’s 2010 electric distribution rate case settlement provided for recovery of PJM transmission network service charges and RTEP charges from default service customers, on a full and current basis through a rider.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information regarding transmission services.

Employees

As of December 31, 2010, Exelon and its subsidiaries had 19,214 employees in the following companies, of which 8,550 or 44% were covered by collective bargaining agreements (CBAs):

Environmental Regulation

General

Exelon, Generation, ComEd and PECO are subject to environmental regulation administered by the U.S. EPA and various state and local environmental protection agencies or boards. State and local regulation includes the authority to regulate air, water and noise emissions and solid waste disposals. The Registrants are also subject to legislation regarding environmental matters by the United States Congress and by various state and local jurisdictions where the Registrants operate their facilities.

The Exelon board of directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental matters, including the CEO who also serves as Exelon’s Chief Environmental Officer; the Vice President, Corporate Strategy and

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Exelon 2020; the Corporate Environmental Strategy Director and the Environmental Regulatory Strategy Director, as well as senior management of Generation, ComEd and PECO. Performance for those individuals directly involved in environmental strategy activities is reviewed and affects compensation as part of the annual individual performance review process. The Exelon board has delegated to its corporate governance committee authority to oversee Exelon’s strategies and efforts to protect and improve the quality of the environment, including, but not limited to, Exelon’s climate change and sustainability policies and programs, and Exelon 2020, Exelon’s comprehensive business and environmental plan, as discussed in further detail below. The Exelon board has also delegated to its generation oversight committee authority to oversee environmental, health and safety issues relating to Generation, and to its energy delivery oversight committee authority to oversee environmental, health and safety issues related to ComEd, PECO and Exelon Transmission Company.

Water

Under the Federal Clean Water Act (Clean Water Act), NPDES permits for discharges into waterways are required to be obtained from the U.S. EPA or from the state environmental agency to which the permit program has been delegated and must be renewed periodically. All of Generation’s power generation facilities discharge industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension.

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding the impact to Exelon of state permitting agencies’ administration of the Phase II rule implementing Section 316(b) of the Clean Water Act, as well as the planned cessation of generation operations at Oyster Creek.

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

Solid and Hazardous Waste

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the U.S. 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 U.S. EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with a U.S. 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 also enacted statutes that contain provisions substantially similar to CERCLA. In addition, the RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.

Generation, ComEd and PECO and their subsidiaries are or are likely to become parties to proceedings initiated by the U.S. EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including 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.

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Environmental Remediation

ComEd and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to the 1950s. ComEd and PECO generally did not operate MGPs as corporate entities but did acquire MGP sites as part of the absorption of smaller utilities, for which they may be liable for environmental remediation. ComEd, pursuant to an ICC order, and PECO, pursuant to the joint settlements of the 2008 and 2010 natural gas distribution rate cases, are recovering environmental remediation costs of the MGP sites through a provision within customer rates. PECO’s 2010 natural gas distribution rate case increased the annual MGP recovery to be collected from customers beginning in January 2011.

The amount to be expended in 2011 at Exelon for compliance with environmental remediation is expected to total $23 million, consisting of $17 million and $6 million at ComEd and PECO, respectively. In addition, Generation, ComEd and PECO may be required to make significant additional expenditures not presently determinable.

See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental remediation efforts and related impacts to the Registrants’ results of operations, cash flows and financial position.

Air

Air quality regulations promulgated by the U.S. EPA and the various state and local environmental agencies in Illinois, Massachusetts, Pennsylvania and Texas in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO₂), nitrogen oxides (NO_x), mercury and other pollutants and require permits for operation of emissions 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, including a two-phase program to reduce acid rain effects by significantly reducing emissions of SO₂ and NO_x from power plants. Flue-gas desulfurization systems (SO₂ scrubbers) have been installed at all of Generation’s coal-fired units.

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding clean air regulation and legislation in the forms of the proposed Transport Rule, the regulation of hazardous air pollutants from fossil generating stations, and regulation of GHG emissions, in addition to NOVs issued to Generation and ComEd for alleged violations of the Clean Air Act.

Global Climate Change

Exelon believes the evidence of global climate change is compelling and that the energy industry, though not alone, is a significant contributor to the human-caused emissions of GHGs that many in the scientific community believe contribute to global climate change, as reported by the National Academy of Sciences in May 2010. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear, wind and hydroelectric), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity. By virtue of its significant investment in low-carbon intensity assets, Generation’s emission intensity, or rate of carbon dioxide equivalent (CO₂e) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions, primarily at its fossil fuel-fired generating plants; CO₂, methane and nitrous oxide are all emitted in this process, with CO₂ representing the largest portion of these GHG emissions. GHG emissions from Generation’s combustion of fossil fuels represent approximately 90% of Exelon’s total GHG emissions. However, only approximately 6% of Exelon’s total electric supply is provided by its fossil fuel generating plants. Other GHG emission sources at Exelon include natural gas (methane) leakage on the gas pipeline system and the coal piles at its generating plants,

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sulfur hexafluoride (SF₆) leakage in its electric operations and refrigerant leakage from its chilling and cooling equipment as well as fossil fuel combustion in its motor vehicles and usage of electricity in its facilities. Despite its small carbon footprint, Exelon believes its operations could be significantly affected by the possible physical risks of climate change and by mandatory programs to reduce GHG emissions. See Item 1A. Risk Factors for information regarding the market and financial, regulatory and legislative, and operational risks associated with climate change.

Climate Change Regulation. Exelon is, or may become, subject to climate change regulation or legislation at the international, Federal, regional and state levels.

International Climate Change Regulation. At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, the United States agreed to the non-binding Copenhagen Accord at the conclusion of the 15th Conference of the Parties under the UNFCCC. Under the Copenhagen Accord, the United States agreed to undertake a number of voluntary measures, including the establishment of a goal to reduce GHG emissions and contributions toward a fund to assist developing nations to address their GHG emissions. The Conference of the Parties met in Mexico in December 2010 and while some progress was made in the Cancun Agreement, the fundamental issues around GHG emission reductions and a successor to the Kyoto Protocol remain unresolved. The next Conference of the Parties meeting will be held in December 2011 in South Africa.

Federal Climate Change Legislation and Regulation. Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.

Numerous bills were introduced in Congress during the 111^th Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio Standards, but none were passed by both houses of Congress. Exelon supports the enactment, through Federal legislation, of a cap-and-trade program for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable. In reaction to the U.S. EPA’s proposed regulation of GHG emissions, various bills have been introduced in the U.S. House of Representatives that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the consideration of such legislation is unknown.

The issue of GHG regulation of stationary sources will likely be addressed either under the existing provisions of the Clean Air Act by U.S. EPA regulation, or by new and comprehensive Federal

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legislation. The Obama administration and the U.S. EPA have stated a preference for addressing the issue through Federal legislation. The extent to which GHG emissions will be regulated is currently unknown; however, potential regulation of GHG emissions from stationary sources could cause Exelon to incur material costs of compliance.

Regional and State Climate Change Legislation and Regulation. At a regional level, on November 15, 2007, six Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) signed the Midwestern Greenhouse Gas Accord. Under that Accord, an inter-state work group was formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). In May 2010, an advisory group appointed by the Governors issued recommendations, but no actions have been taken on the recommendations.

At the state level, the PCCA was signed into law in Pennsylvania in July 2008. The PCCA requires, among other things, that: a Climate Change Advisory Committee be formed; a report on the potential impact of climate change in Pennsylvania be developed; the PA DEP develop a GHG inventory for Pennsylvania; a voluntary GHG registry be identified; and the PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. The Climate Change Advisory Committee issued its recommendations for an Action Plan for consideration by the Pennsylvania legislature on October 9, 2009.

Exelon’s Voluntary Climate Change Efforts. In a world increasingly concerned about global climate change, nuclear power as well as other virtually non-GHG emitting power will play a pivotal role. As a result, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon believes that the significance of its low GHG emission profile can only grow as policymakers take action to address global climate change.

Despite Exelon’s low GHG emission inventory and the absence of a mandatory national program in the United States, Exelon is actively engaged in voluntary reduction efforts. Exelon made a voluntary commitment in 2005 under the U.S. EPA’s Climate Leaders Program to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. Exelon achieved this goal by reducing its carbon dioxide-equivalent (CO₂e) emissions to 9.7 million metric tons in 2008, from a 2001 baseline of 15.7 million metric tons. This was accomplished through the retirement of older, inefficient fossil power plants, reduced leakage of SF₆, increased use of renewable energy and energy efficiency initiatives.

In 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental strategic plan. The plan, Exelon 2020, details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce Exelon’s GHG emissions and those of its customers, communities, suppliers and markets. Exelon 2020 sets a goal for Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels).

Through Exelon 2020, Exelon is pursuing three broad strategies: reducing or offsetting its own carbon footprint, helping customers and communities reduce their GHG emissions, and offering more low-carbon electricity in the marketplace. In 2010, Exelon announced that it had achieved just over 50% of the annual Exelon 2020 goal. The planned retirement of fossil units, Cromby Units 1 and 2 and Eddystone Unit 1 in 2011 and Eddystone Unit 2 in 2012, will further contribute to fully achieving the goal. The early retirement of Oyster Creek may result in increased generation from fossil generating plants in the PJM RTO, which could result in increased GHG emissions under Exelon 2020 through reverse displacement. The current plan for achieving the Exelon 2020 goal accounts for these events.

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Initiatives to reduce Exelon’s own carbon footprint include reducing building energy consumption by 25%, reducing vehicle fleet emissions, improving the efficiency of the generation and delivery system for electricity and natural gas, and developing an industry-leading green supply chain. Plans to help customers reduce their GHG emissions include ComEd’s Smart Ideas portfolio of energy efficiency programs, a similar portfolio of energy efficiency programs at PECO to meet the requirements of Act 129, the implementation of smart-meters and real-time pricing programs and a broad array of communication initiatives to increase customer awareness of approaches to manage their energy consumption. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding ComEd and PECO smart grid filings and stimulus grant awards. Finally, Exelon will offer more low-carbon electricity in the marketplace by increasing its investment in renewable power and adding capacity to existing nuclear plants through uprates.

Exelon has incorporated Exelon 2020 into its overall business plans and has an organized implementation effort underway. This implementation effort includes a periodic review and refinement of Exelon 2020 initiatives in light of changing market conditions. Specific initiatives and the amount of expenditures to implement the plan will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards. As further legislation and regulation imposing requirements on emissions of air pollutants are promulgated, Exelon’s emissions reduction efforts will position the company to benefit from the long-term positive impact of the requirements on capacity and energy prices while minimizing the impact of costs of compliance on Exelon’s operations, cash flows or financial position.

The Exelon 2020 strategy is reviewed annually and updated to reflect changes in the market, regulations, technology and other factors that affect the merit of various GHG abatement options. In spite of the recent economic downturn, the decline in wholesale power prices and the uncertainty of Federal climate policy, Exelon 2020 has been demonstrated to be a sustainable business strategy.

Renewable and Alternative Energy Portfolio Standards

Thirty-three states have adopted some form of RPS requirement. As previously described, Illinois and Pennsylvania have laws specifically addressing energy efficiency and renewable energy initiatives. 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.

The Illinois Settlement Legislation required that procurement plans implemented by electric utilities include cost-effective renewable energy resources or approved equivalents such as RECs in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers by June 1, 2008, increasing to 10% by June 1, 2015, with a goal of 25% by June 1, 2025. Utilities are allowed to pass-through any costs from the procurement of these renewable resources or approved equivalents subject to legislated rate impact criteria. As of December 31, 2010, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois Settlement Legislation. See Note 2 and Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

The AEPS Act is effective for PECO beginning in 2011, following the expiration of PECO’s transition period. During 2011, PECO will be required to supply approximately 3.5% and 6.2% of electric energy generated from Tier I (including solar, wind power, low-impact hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy, coal mine methane and black liquor generated within Pennsylvania) and Tier II (including waste coal, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing by-products of the pulping process and wood, distributed generation systems and integrated combined coal gasification

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technology) alternative energy resources, respectively, as measured in AECs. The compliance requirements will incrementally escalate to 8.0% for Tier I and 10.0% for Tier II by 2021. In order to prepare for the first year of required compliance, PECO procured and banked AECs in accordance with their PAPUC-approved plan over the past three years. PECO has entered into five-year agreements and ten-year agreements with accepted bidders, including Generation, to purchase annually 452,000 non-solar and 8,000 solar Tier 1 AECs, respectively. PECO also purchases AECs through its DSP Program full requirement contracts. In November 2010, PECO filed a petition with the PAPUC for approval to procure Tier II AECs to satisfy PECO’s compliance requirements for the AEPS reporting years ending 2011 and 2012.

Similar to ComEd and PECO, Generation’s retail electric business must source a portion of the electric load it serves in IL and PA from renewable resources or approved equivalents such as RECs. While Generation is not directly affected by RPS or AEPS legislation from a compliance perspective, potential regulation and legislation regarding renewable and alternative energy resources could increase the pace of development of wind and other renewable/alternative energy resources, which could put downward pressure on wholesale market prices for electricity in some markets where Exelon operates generation assets. At the same time, such developments may present some opportunities for sales of Generation’s renewable power, including from Exelon Wind, Generation’s hydroelectric and landfill gas generating stations and wind energy PPAs.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Executive Officers of the Registrants as of February 10, 2011

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