Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION

     Exelon, ComEd, PECO and Generation

     Exelon and Generation have reclassified their December 31, 2004 and previous financial statements for the presentation of certain businesses as discontinued operations within Exelon’s and Generation’s Consolidated Statements of Income and a change in the reportable segments presented by Exelon. As discussed in Notes 25 and 26 of Exelon’s Notes to Consolidated Financial Statements, on January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. In addition, during 2004 and 2003, Exelon sold or unwound substantially all components of Enterprises and AllEnergy Gas & Electric Marketing LLC (AllEnergy), a business within Exelon Energy. As a result, the results of operations and any gain or loss on the sale of qualifying components of Enterprises have been presented as discontinued operations within Exelon’s Consolidated Statements of Income. As Exelon sold or wound down substantially all components of Enterprises, Exelon determined that it would no longer present Enterprises as a reportable segment. Accordingly, the remaining Enterprises businesses are reported within “Other.”

     The Critical Accounting Policies and Estimates and New Accounting Pronouncement sections presented below indicate the registrant or registrants to which each policy, estimate or accounting standard is applicable.

Critical Accounting Policies and Estimates

     The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management discusses these policies, estimates and assumptions within its Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates on management decisions to the Audit Committee of the Exelon Board of Directors. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Further discussion of the application of these accounting policies can be found in the Registrants’ Notes to Consolidated Financial Statements.

Asset Retirement Obligations (Exelon, ComEd, PECO and Generation)

     Nuclear Decommissioning (Exelon and Generation)

     Generation must make significant estimates and assumptions in accounting for its obligation to decommission its nuclear generating plants in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143).

     SFAS No. 143 requires that Generation estimate the fair value of its obligation for the future decommissioning of its nuclear generating plants. To estimate that fair value, Generation uses a probability-weighted, discounted cash flow model considering multiple outcome scenarios based upon significant assumptions embedded in the following:

     Decommissioning Cost Studies. Generation uses decommissioning cost studies prepared by a third party to provide a marketplace assessment of costs and the timing of decommissioning activities validated by comparison to current decommissioning projects and other third-party estimates.

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     Cost Escalation Studies. Cost escalation studies are used to determine escalation factors and are based on inflation indices for labor, equipment and materials, energy and low-level radioactive waste disposal costs.

     Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various cost levels and various timing scenarios. The probability of various timing scenarios incorporate the factors of current license lives, anticipated license renewals and the timing of DOE acceptance for disposal of spent nuclear fuel.

     Discount Rates. The probability-weighted estimated cash flows using these various scenarios are discounted using credit-adjusted, risk-free rates applicable to the various businesses.

     Changes in the assumptions underlying the foregoing items could materially affect the decommissioning obligation recorded and could affect future updates to the decommissioning obligation to be recorded in the consolidated financial statements. For example, the 20-year average cost escalation rates used in the current ARO calculation approximate 3% to 4%. A uniform increase in these escalation rates of 25 basis points would increase the total ARO recorded by Exelon by approximately 11% or more than $400 million. Under SFAS No. 143, the nuclear decommissioning obligation is adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimate of undiscounted cash flows. For more information regarding the adoption and ongoing application of SFAS No. 143, see Note 1 and Note 14 of Exelon’s Notes to Consolidated Financial Statements.

     Other Asset Retirement Obligations (Exelon, ComEd, PECO and Generation)

     The FASB has issued an exposure draft of proposed interpretations of SFAS No. 143. The exposure draft addresses the accounting for conditional asset retirement obligations. The proposed guidance is not anticipated to have any impact on Generation’s asset retirement obligations for nuclear decommissioning but may result in the recording of liabilities at Exelon, ComEd, PECO and Generation for conditional legal obligations meeting the scope of the interpretation.

Asset Impairments (Exelon, ComEd, PECO and Generation)

     Goodwill (Exelon and ComEd)

     Exelon and ComEd had approximately $4.7 billion of goodwill recorded at December 31, 2004, which relates entirely to the goodwill recorded upon the acquisition of ComEd. Exelon and ComEd perform assessments for impairment of their goodwill at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. Application of the goodwill impairment test requires management’s judgments, including the identification of reporting units, assigning assets and liabilities to reporting units, assigning goodwill to reporting units, and determining the fair value of each reporting unit.

     Exelon and ComEd performed their annual assessments of goodwill impairment as of November 1, 2004 and determined that goodwill was not impaired. Exelon assesses goodwill impairment at its Energy Delivery reporting unit; accordingly, a goodwill impairment charge at ComEd may not necessarily affect Exelon’s results of operations as the goodwill impairment test for Exelon considers the cash flows of the entire consolidated Energy Delivery business segment, which includes both ComEd and PECO.

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     In the assessments, Exelon and ComEd estimated the fair value of the Energy Delivery and ComEd reporting units using a probability-weighted, discounted cash flow model with multiple scenarios. The fair value determination is dependent on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, the capital structures of Energy Delivery and ComEd, market prices for power, post-2006 rate regulatory structures, operating and capital expenditure requirements, and other factors. Changes in assumptions regarding these variables or in the assessment of how they interrelate could produce a different impairment result, which could be material. For example, a hypothetical decrease of approximately 10% in Energy Delivery’s and ComEd’s expected discounted cash flows would result in no impairment at Exelon, but an estimated impairment of goodwill of approximately $1.7 billion at ComEd.

     Long-Lived Assets (Exelon, ComEd, PECO and Generation)

     Exelon, ComEd, PECO and Generation evaluate the carrying value of their long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and costs of fuel. A variation in the assumptions used could lead to a different conclusion regarding the realizability of an asset and, thus, could have a significant effect on the consolidated financial statements.

     Investments (Exelon, ComEd, PECO and Generation)

     Exelon, ComEd, PECO and Generation had approximately $6,066 million, $91 million, $109 million and $5,365 million, respectively, of investments, including investments held in nuclear decommissioning trust funds, recorded as of December 31, 2004. Exelon, ComEd, PECO and Generation consider investments to be impaired when a decline in fair value below cost is judged to be other-than-temporary. If the cost of an investment exceeds its fair value, they evaluate, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as well as their intent and ability to hold the investment. The Registrants also consider specific adverse conditions related to the financial health of and business outlook for the investee.

Defined Benefit Pension and Other Postretirement Welfare Benefits (Exelon, ComEd, PECO and Generation)

     Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans applicable to essentially all ComEd, PECO, Generation and BSC employees and certain Enterprises employees. See Note 15 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the accounting for Exelon’s defined benefit pension plans and postretirement welfare benefit plans.

     The costs of providing benefits under these plans are dependent on historical information such as employee age, length of service and level of compensation, and the actual rate of return on plan assets. Also, Exelon utilizes assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increases and the anticipated rate of increase in health care costs.

     The selection of key actuarial assumptions utilized in the measurement of the plan obligations and costs drives the results of the analysis and the resulting charges. The long-term expected rate of return on plan assets (EROA) assumption used in calculating pension cost was 9.00% in 2004 and 2003 compared to 9.50% for 2002. The weighted average EROA assumption used in calculating other postretirement benefit costs ranged from 8.33% to 8.35% in 2004 compared to 8.40% in 2003 and 8.80% for 2002. A lower EROA is used in the calculation of other postretirement benefit costs, as the other postretirement benefit trust activity is partially taxable while the pension trust activity is non-taxable. The Moody’s Aa Corporate Bond Index was used as the basis in selecting the discount rate for determining the plan obligations, using 5.75%, 6.25% and 6.75% at December 31, 2004, 2003 and 2002, respectively. The reduction in the discount rate is due to the decline in Moody’s Aa Corporate Bond Index in 2004 and 2003.

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     The following tables illustrate the effects of changing the major actuarial assumptions discussed above:

     Assumed health care cost trend rates also have a significant effect on the costs reported for Exelon’s postretirement benefit plans. To estimate the 2004 cost, Exelon assumed a health care cost trend rate of 10%, decreasing to an ultimate trend rate of 4.5% in 2011, compared to the 2003 assumption of 8.5%, decreasing to an ultimate trend rate of 4.5% in 2008. To estimate the 2005 cost, Exelon will assume a health care cost trend rate of 9%, decreasing to an ultimate trend rate of 5% in 2010. A one-percentage point change in assumed health care cost trend rates in 2004 would have the following effects:

     The assumptions are reviewed at the beginning of each year during Exelon’s annual review process and at any interim remeasurement of the plan obligations. The impact of assumption changes is reflected in the recorded pension amounts as they occur, or over a period of time if allowed under applicable accounting standards. As these assumptions change from period to period, recorded pension amounts and funding requirements could also change.

     In 2004, Exelon incurred approximately $294 million in costs associated with its pension and postretirement benefit plans, including curtailment and settlement costs of $24 million. Although 2005 pension and postretirement benefit costs will depend on market conditions, Exelon believes that its pension and postretirement benefit costs will decrease in 2005 due to an anticipated contribution of approximately $2 billion to the pension plans, partially offset by an increase in postretirement benefit costs due to a change in the assumed healthcare cost trend rate. Depending on the timing of the pension contribution, the estimated net decrease in 2005 pension and postretirement benefit costs could range from approximately $30 million to approximately $120 million. If the contribution is made on July 1, 2005, the estimated net decrease in 2005 pension and postretirement benefit cost would be approximately $75 million.

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Regulatory Accounting (Exelon, ComEd and PECO)

     Exelon, ComEd and PECO account for their regulated electric and gas operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires Exelon, ComEd and PECO to reflect the effects of rate regulation in their financial statements. Use of SFAS No. 71 is applicable to utility operations that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. As of December 31, 2004, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, ComEd and PECO are required to eliminate the financial statement effects of regulation for that part of their business, which would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets. The impact of not meeting the criteria of SFAS No. 71 could be material to the financial statements as a one-time extraordinary item and through impacts on continuing operations. See Note 5 and Note 2 of Exelon’s and ComEd’s Notes to Consolidated Financial Statements, respectively, for further information regarding regulatory issues.

     Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator will allow for recovery through rates charged to customers. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred. As of December 31, 2004, Exelon and PECO had recorded $4.8 billion of net regulatory assets within their Consolidated Balance Sheets. At December 31, 2004, Exelon and ComEd had recorded $2.2 billion of net regulatory liabilities within their Consolidated Balance Sheets. See Note 21 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the significant regulatory assets and liabilities of Exelon, ComEd and PECO.

     For each regulatory jurisdiction where they conduct business, Exelon, ComEd and PECO continually assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement. This assessment includes consideration of factors such as changes in applicable regulatory environments, recent rate orders to other regulated entities in the same jurisdiction, the status of any pending or potential deregulation legislation and the ability to recover costs through regulated rates.

     The electric businesses of both ComEd and PECO are currently subject to rate freezes or rate caps that limit the opportunity to recover increased costs and the costs of new investment in facilities through rates during the rate freeze or rate cap period. Because the current rates include the recovery of existing regulatory assets and liabilities and rates in effect during the rate freeze or rate cap periods are expected to allow Exelon, ComEd and PECO to earn a reasonable rate of return during that period, management believes the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current political and regulatory climate at the Federal level and in the states where ComEd and PECO do business but is subject to change in the future. If future recovery of costs ceases to be probable, the regulatory assets and liabilities would be recognized in current period earnings. A write-off of regulatory assets could limit the ability to pay dividends under PUHCA and state law.

Accounting for Derivative Instruments (Exelon, ComEd, PECO and Generation)

     The Registrants enter into derivatives to manage their exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation utilizes derivatives with respect to energy transactions to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Generation enters into energy-related derivatives for trading purposes. All of the Registrant’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

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     The Registrants account for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases or normal sales exception. Derivatives recorded at fair value on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transaction occur.

     Normal Purchases and Normal Sales Exception. The availability of the normal purchases and normal sales exception is based upon the assessment of the ability and intent to deliver or take delivery of the underlying item. This assessment is based primarily on internal models that forecast customer demand and electricity and gas supply. These models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice, and generating unit availability, particularly nuclear generating unit capability factors. Significant changes in these assumptions could result in these contracts not qualifying for the normal purchases and normal sales exception.

     Energy Contracts. Identification of an energy contract as a qualifying cash-flow hedge requires Generation to determine that the contract is in accordance with the RMP, the forecasted future transaction is probable, and the hedging relationship between the energy contract and the expected future purchase or sale of energy is expected to be highly effective at the initiation of the hedge and throughout the hedging relationship. Internal models that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. Generation reassesses its cash-flow hedges on a regular basis to determine if they continue to be effective and that the forecasted future transactions are probable. When a contract does not meet the effective or probable criteria of SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) hedge accounting is discontinued and changes in the fair value of the derivative are recorded through earnings.

     As a part of accounting for derivatives, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. Generation uses quoted exchange prices to the extent they are available or external broker quotes in order to determine the fair value of energy contracts. When external prices are not available, Generation uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy based on the specific market in which the energy is being purchased, using externally available forward market pricing curves for all periods possible under the pricing model. Generation uses the Black model, a standard industry valuation model, to determine the fair value of energy derivative contracts that are marked-to-market.

     Interest-Rate Derivative Instruments. To determine the fair value of interest-rate swap agreements, the Registrants use external dealer prices or internal valuation models that utilize assumptions of available market pricing curves.

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Depreciable Lives of Property, Plant and Equipment (Exelon, ComEd, PECO and Generation)

     The Registrants have a significant investment in electric generation assets and electric and natural gas transmission and distribution assets. Depreciation of these assets is generally provided over their estimated service lives on a straight-line basis using the composite method. The estimation of service lives requires management judgment regarding the period of time that the assets will be in use. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Changes to depreciation estimates in future periods could have a significant impact on the amount of depreciation charged to the financial statements.

     In 2001, Generation extended the estimated service lives of certain nuclear-fuel generating facilities based upon Generation’s intent to apply for license renewals for these facilities. While Generation expects to apply for and obtain approval of license renewals for these facilities, circumstances may arise that would prevent Generation from obtaining additional license renewals. A change in depreciation estimates resulting from Generation’s inability to receive additional license renewals could have a significant effect on Generation’s results of operations.

Accounting for Contingencies (Exelon, ComEd, PECO and Generation)

     In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record amounts that are probable and reasonably estimated based upon available information. The amounts recorded may differ from the actual income or expense that occurs when the uncertainty is resolved. The estimates that the Registrants make in accounting for contingencies and the gains and losses that they record upon the ultimate resolution of these uncertainties have a significant effect on their financial statements. The accounting for taxation and environmental costs are further discussed below.

     Taxation

     The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and ongoing operations to estimate their obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes, including taxes that are subject to ongoing appeals. Judgments include estimating reserves for potential adverse outcomes regarding tax positions that they have taken. The Registrants must also assess their ability to generate capital gains in future periods to realize tax benefits associated with capital losses previously generated or expected to be generated in future periods. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the three prior or five succeeding years. 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. Generation has recorded valuation allowances against certain deferred assets associated with capital losses due to the consolidation of Sithe. While the Registrants believe the resulting tax reserve balances as of December 31, 2004 reflect the probable expected outcome of these tax matters in accordance with SFAS No. 5, “Accounting for Contingencies,” and SFAS No. 109, “Accounting for Income Taxes,” the ultimate outcome of such matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material.

     Environmental Costs

     As of December 31, 2004, Exelon, ComEd, PECO and Generation had accrued liabilities of $124 million, $61 million, $47 million and $16 million, respectively, for environmental investigation and remediation costs. These liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties and the timing of the remediation work. Where timing and costs of expenditures can be reliably estimated, amounts are discounted. These amounts represent $96 million, $55 million and $41 million, respectively, of the total accrued for Exelon, ComEd and PECO.

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Where timing and amounts cannot be reliably estimated, amounts are recognized on an undiscounted basis. Such amounts represent $28 million, $6 million, $6 million and $16 million, respectively, of the total accrued liabilities for Exelon, ComEd, PECO and Generation. Estimates can be affected by the factors noted above as well as by changes in technology, regulations or the requirements of local governmental authorities.

Severance Accounting (Exelon, ComEd, PECO and Generation)

     The Registrants provide severance benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with the Registrants and compensation level. The Registrants accrue severance benefits that are considered probable and can be reasonably estimated in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112). A significant assumption in estimating severance charges is the determination of the number of positions to be eliminated. The Registrants base their estimates on their current plans and ability to determine the appropriate staffing levels to effectively operate their businesses. Exelon, ComEd, PECO and Generation recorded severance charges of $32 million, $10 million, $3 million and $2 million, respectively, in 2004 and severance charges of $135 million, $61 million, $16 million and $38 million, respectively, in 2003, related to personnel reductions. The Registrants may incur further severance costs if they identify additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.

Revenue Recognition (Exelon, ComEd, PECO and Generation)

     Revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The determination of Energy Delivery’s and Exelon Energy Company’s energy sales to individual customers, however, is based on systematic readings of customer meters generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. This unbilled revenue is estimated each month based on daily customer usage measured by generation or gas throughput volume, estimated customer usage by class, estimated losses of energy during delivery to customers and applicable customer rates. Customer accounts receivable of ComEd, PECO, and Generation included estimates of $275 million, $143 million, and $64 million, respectively, for unbilled revenue as of December 31, 2004 as a result of unread meters at ComEd, PECO and Exelon Energy Company. Increases in volumes delivered to the utilities’ customers and favorable rate mix due to changes in usage patterns in customer classes in the period would increase unbilled revenue. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date would also have an effect on the estimated unbilled revenue; however, total operating revenues would remain materially unchanged.

     The determination of Generation’s energy sales, excluding Exelon Energy Company, is based on estimated amounts delivered as well as fixed quantity sales. At the end of each month, amounts of energy delivered to customers during the month are estimated and the corresponding unbilled revenue is recorded. Customer accounts receivable of Exelon and Generation as of December 31, 2004 include unbilled energy revenues of $385 million related to unbilled energy sales of Generation. Increases in volumes delivered to the wholesale customers in the period would increase unbilled revenue.

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Accounting for Ownership Interests in Variable Interest Entities (Exelon, ComEd, PECO and Generation)

     At December 31, 2004, Exelon, through Generation, had a 50% interest in Sithe. In accordance with FIN 46-R, Exelon and Generation consolidated Sithe within their financial statements as of March 31, 2004. The determination that Sithe qualified as a variable interest entity and that Generation was the primary beneficiary under FIN 46-R required analysis of the economic benefits accruing to all parties pursuant to their ownership interests supplemented by management’s judgment. Sithe’s total assets and total liabilities as of December 31, 2004 were $1,356 million and $1,289 million, respectively. As required by FIN 46-R, upon the occurrence of a future triggering event, such as a change in ownership, the Registrant would reassess their investments to determine if they continue to qualify as the primary beneficiary. See Notes 3 and 25 of Exelon’s Notes to Consolidated Financial Statements for a discussion of the sale of Generation’s interest in Sithe, which was completed on January 31, 2005. Subsequent to the sale, Sithe will no longer be consolidated within the financial statements of Exelon or Generation.

     In addition to Sithe, the Registrants reviewed other entities with which they have business relationships to determine if those entities were variable interest entities that should be consolidated under FIN 46-R and concluded that those entities should not be consolidated within the financial statements.

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Exelon

Executive Overview

     Financial Results. Exelon’s net income was $1,864 million in 2004 as compared to $905 million in 2003 and diluted earnings per average common share were $2.78 for 2004 as compared to $1.38 for 2003, primarily as a result of increased net income at Generation, lower losses at Enterprises and several significant charges in 2003 that did not recur in 2004, partially offset by decreased net income at Energy Delivery. Key drivers included the following:

	•	Increased net income at Generation – Generation provided net income of $673 million in 2004 compared to a net loss of $151 million in 2003. The increase in Generation’s net income reflects improved wholesale prices in 2004, the inclusion of a full year of AmerGen’s results in 2004, and impairment charges in 2003 of $945 million and $255 million (before income taxes) related to the long-lived assets of Boston Generating and Generation’s investment in Sithe, respectively. Generation’s 2004 income also includes an after-tax gain of $52 million on the sale of Boston Generating during the second quarter of 2004. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Generation.”
	•	Decreased losses at Enterprises – The businesses associated with the former Enterprises segment, which are included within other, reported a net loss of $22 million in 2004 compared to a net loss of $118 million in 2003. These comparative results reflect net pre-tax gains of $41 million recorded in 2004 related to the dispositions of certain businesses and investments, as well as investment impairment charges of $54 million recorded in 2003. See further discussion under “Investment Strategy” below and in “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Exelon Corporation – Results of Operation – Discontinued Operations.”
	•	Favorable tax effects from investments in synthetic fuel-producing facilities – Exelon’s investments in synthetic fuel-producing facilities increased 2004 after-tax earnings by $65 million as compared to 2003.
	•	Decreased net income at Energy Delivery – Energy Delivery provided net income of $1,128 million in 2004 compared to $1,175 million in 2003. This decrease was primarily attributable to unfavorable weather conditions and charges recorded in connection with the early retirement of debt, partially offset by growth in Energy Delivery’s retail customer base and reduced severance and other charges in 2004 as compared to 2003. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Energy Delivery.”

     Investment Strategy. In 2004, Exelon continued to follow a disciplined approach to investing to maximize earnings and cash flows from its assets and businesses, while selling those that do not meet its strategic goals. Highlights from 2004 include the following:

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Proposed Merger with PSEG – On December 20, 2004, Exelon entered into the Merger Agreement with PSEG, the holding company for an electric and gas utility company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon. 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, 2004, PSEG’s market capitalization was over $12 billion. Additionally, PSEG, on a consolidated basis, has approximately $14 billion of outstanding debt which is currently anticipated to become part of Exelon’s consolidated debt.

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		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 and (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. On February 4, 2005, Exelon and PSEG filed for approval of the merger with the FERC, the New Jersey Board of Public Utilities (BPU) and the PUC. Exelon also filed a notice of the Merger with the ICC.
		Exelon anticipates that the Merger will close within 12 months to 15 months after the environment of the Merger Agreement in December 2004, subject to shareholder and regulatory approvals which cannot be assured.
	•	OSC with PSEG – Concurrent with the Merger Agreement, Generation entered into the OSC with PSEG Nuclear, LLC which commenced on January 17, 2005 relating to the operation of the Salem and Hope Creek nuclear generating stations. The OSC provides for Generation to provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon operating model. PSEG Nuclear, LLC will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities.
	•	Boston Generating – On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns directly or indirectly the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility, resulting in an after-tax gain of $52 million. On September 1, 2004, Generation completed the transfer of plant operations and power marketing arrangements to the lenders’ special purpose entity and its contractors under Boston Generating’s credit facility.
	•	Sithe – On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million and, on November 1, 2004, Generation entered into an agreement to sell its anticipated 100% interest in Sithe to Dynegy Inc. for $135 million in cash. Generation closed on the call exercise and the sale of the resulting 100% interest in Sithe on January 31, 2005. As a result, the operations of Sithe have been reported as discontinued operations. The sale did not include Sithe International, Inc. (Sithe International), which was sold to a subsidiary of Generation on October 13, 2004.
	•	Enterprises – Exelon continued its divestiture strategy for the businesses associated with the former Enterprises segment by selling or winding down substantially all components of that former segment. At December 31, 2004, the remaining assets totaled approximately $274 million in comparison to $697 million at December 31, 2003. Exelon expects to receive aggregate proceeds of $268 million and recorded in discontinued operations a net pre-tax gain of $41 million related to the dispositions of assets and investments in 2004.

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     Financing Activities. During 2004, Exelon substantially strengthened its balance sheet and met its capital resource requirements primarily with internally generated cash. When necessary, Exelon obtains funds from external sources, including capital markets, and through bank borrowings. Highlights from 2004 include the following:

	•	ComEd retired $1.2 billion of its outstanding debt, including $1.0 billion prior to its maturity and $206 million at maturity, pursuant to an accelerated liability management plan. In connection with these retirements, ComEd recorded pre-tax charges totaling $130 million related to debt prepayment premiums and the write-off of previously deferred debt financing fees.
	•	In addition to the accelerated liability management plan, payments of approximately $728 million were made for the purpose of retiring PECO and ComEd transition trust long-term debt and approximately $176 million of other net long-term debt during 2004.
	•	Exelon replaced its $750 million 364-day unsecured revolving credit agreement with a $1 billion five-year facility and reduced its $750 million three-year facility to $500 million.
	•	Exelon’s Board of Directors approved a discretionary share repurchase program under which Exelon purchased common stock, now held as treasury shares, totaling $75 million during 2004.
	•	Exelon’s Board of Directors approved a policy of targeting a dividend payout ratio of 50% to 60% of ongoing earnings, and Exelon expects a dividend payout in that range for the full year of 2005. The actual dividend payout rate depends on Exelon achieving its objectives, including meeting cash flow targets and strengthening its balance sheet. On October 29, 2004, the Exelon Board of Directors approved an increased quarterly dividend of $0.40 per share, which was consistent with the dividend policy approved in 2004. The Board of Directors must approve the dividends each quarter after review of Exelon’s financial condition at the time, and there can be no guarantees that this targeted dividend payout ratio will be achieved.

     Regulatory Developments – PJM Integration. On May 1, 2004, ComEd fully integrated its transmission facilities into PJM. PECO’s and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of electric energy and capacity. Upon joining PJM, ComEd began incurring administrative fees, which are expected to approximate $25 million annually. Exelon believes such costs will ultimately be offset by the benefits of full access to a wholesale competitive marketplace and increased revenue requirements, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on Exelon.

     Outlook for 2005 and Beyond. Exelon’s future financial results will be affected by a number of factors, including the following:

     Shorter Term: Weather conditions, wholesale market prices of electricity, fuel costs, interest rates, successful implementation of operational improvement initiatives and Exelon’s ability to generate electricity at low costs all affect Exelon’s operating revenues and related costs. If weather is warmer than normal in the summer months or colder than normal in the winter months, operating revenues at Exelon generally will be favorably affected. Operating revenues will also generally be favorably affected by increases in wholesale market prices.

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     Longer Term: The proposed merger with PSEG is expected to have a significant impact on Exelon’s results of operations, cash flows and financial position. See further discussion above at “Proposed Merger with PSEG” and in ITEM 1. Business — Proposed Merger with PSEG. Following is a discussion of the other non-merger-related items that will have a longer term impact on Exelon.

     Restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, with continuing debate on RTO and standard market platform issues, and in many states on the “post-transition” format. Some states abandoned failed transition plans (e.g., California); some states are adjusting current transition plans (e.g., Ohio); and the states of Illinois (by 2007) and Pennsylvania (by 2011) are considering options to preserve choice for large customers and rate stability for mass-market customers, while ensuring the financial returns needed for continuing investments in reliability. Exelon will continue to be an active participant in these policy debates, while continuing to focus on improving operations, controlling costs and providing a fair return to its investors.

     As Exelon looks toward the end of the restructuring transition periods and related rate freezes or caps in Illinois and Pennsylvania, Exelon will also 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. Exelon will strive to ensure that future rate structures recognize the substantial improvements Exelon has made, and will continue to make, in its transmission and distribution systems. ComEd and PECO will also work to ensure that ComEd’s and PECO’s rates are adequate to cover their costs of obtaining electric power and energy from their suppliers, which could include Generation, for the costs associated with procuring full-requirements power given Energy Delivery’s POLR obligations. ComEd intends to make various filings during 2005 to begin the process to establish rates for the post-transition period. As in the past, by working together with all interested parties, Exelon believes it can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers; however, if Exelon is unsuccessful, its results of operations and cash flows could be negatively affected after the transition periods.

     Generation’s financial results will be affected by a number of factors, including the market changes in Illinois and Pennsylvania discussed above. While Generation has significantly hedged its market exposure in the short-term, over the long-term, Generation’s results will be affected by long-term changes in the market prices of power and fuel caused by supply and demand forces and environmental regulations. Generating companies must also work with regulators to ensure that a viable capacity market exists and that new units will be constructed in a timely manner to meet the growing demand for power. On the operating side, to meet Exelon’s financial goals, Generation’s nuclear units must continue their superior performance while controlling costs despite inflationary pressures and increasing security costs.

     Exelon’s current plans are based on moderate kilowatthour sales growth (1% to 2%) from their current levels and stable wholesale power markets. Continued cost reduction initiatives are important to offset labor and material cost escalation, especially the double digit increases in health care costs. Despite these challenges, Exelon’s diverse mix of generation (nuclear, coal, purchased power, natural gas, hydroelectric, wind and other renewables), linked to a stable base of over five million customers, will provide a solid platform from which it will strive to meet these challenges.

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Results of Operations

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Significant Operating Trends – Exelon

     Net Income. Net income for 2004 reflects income of $32 million, net of income taxes, for the adoption of FIN 46-R, partially offset by a loss of $9 million, net of income taxes, related to the adoption of Emerging Issues Task Force (EITF) Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). Net income for 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN 46-R, EITF 03-16 and SFAS No. 143.

     Operating Revenues. Operating revenues decreased primarily due to decreased revenues at Enterprises due to the sale of InfraSource in the third quarter of 2003, the sale of Boston Generating and Generation’s adoption of EITF No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11) in the first quarter of 2004, which changed the presentation of certain power transactions and decreased 2004 operating revenues by $980 million. The adoption of EITF 03-11 had no impact on net income. Operating revenues were favorably affected by Generation’s acquisition of the remaining 50% of AmerGen. Operating revenues were also favorably affected by Energy Delivery’s increased volume growth and transmission revenues collected from PJM, partially offset by unfavorable weather conditions and customer choice initiatives. See further discussion of operating revenues by segment below.

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     Purchased Power and Fuel Expense. Purchased power and fuel expense decreased primarily due to Generation’s adoption of EITF 03-11 during 2004 which resulted in a decrease in purchased power expense and fuel expense of $980 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense, and the sale of Boston Generating. Purchased power represented 24% of Generation’s total supply in 2004 compared to 37% in 2003. Purchased power also decreased due to Energy Delivery’s unfavorable weather conditions and customer choice initiatives, partially offset by volume growth and transmission costs paid to PJM. See further discussion of purchased power and fuel expense by segment below.

     Impairment of the Long-Lived Assets of Boston Generating. Generation recorded a $945 million charge (before income taxes) during 2003 to impair the long-lived assets of Boston Generating.

     Operating and Maintenance Expense. Operating and maintenance expense decreased primarily as a result of decreased expenses at InfraSource due to its sale in the third quarter of 2003 and decreased severance and severance-related expenses, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen. Operating and maintenance expense increased $65 million due to investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004. See further discussion of operating and maintenance expenses by segment below.

     Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to additional plant placed in service at Energy Delivery and Generation, the acquisition of the remaining 50% in AmerGen in December 2003 and the recording and subsequent impairment of an asset retirement cost (ARC) at Generation in 2004. See Note 14 of Exelon’s Notes to Consolidated Financial Statements for additional information. The increase also resulted from increased amortization expense due to investments made in the fourth quarter of 2003 and the third quarter of 2004 in synthetic fuel-producing facilities and increased competitive transition charge amortization at PECO. These increases were partially offset by reduced depreciation and amortization expense at Enterprises due to the sale of InfraSource in the third quarter of 2003.

     Operating Income. Exclusive of the changes in operating revenues, purchased power and fuel expense, the impairment of Boston Generating’s long-lived assets, operating and maintenance expense and depreciation and amortization expense discussed above, the change in operating income was primarily the result of increased taxes other than income in 2004 as compared to 2003, primarily due to the reduction of certain real estate tax accruals at PECO and Generation during 2003.

     Other Income and Deductions. Other income and deductions in 2004 reflects interest expense of $828 million, equity in losses of unconsolidated affiliates of $154 million, debt retirement charges of $130 million (before income taxes) recorded at ComEd associated with an accelerated liability management plan, and an $85 million gain (before income taxes) on the 2004 sale of Boston Generating. Other income and deductions in 2003 reflects interest expense of $873 million and impairment charges of $255 million (before income taxes) related to Generation’s investment in Sithe. Equity in earnings of unconsolidated affiliates decreased by $187 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004.

     Effective Income Tax Rate. The effective income tax rate from continuing operations was 28% for 2004 compared to 30% for 2003. The decrease in the effective rate was primarily attributable to investments in synthetic fuel-producing facilities made in the fourth quarter of 2003.

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     Discontinued Operations. 2004 and 2003 discontinued operations consist of Sithe’s 2004 results (beginning April 1, 2004), certain qualifying components of Enterprises, and AllEnergy. AllEnergy is a business within Exelon Energy, which is a business within Generation. A discussion of the results of Sithe and AllEnergy is included in the Generation segment results discussion below. Enterprises’ after-tax loss from discontinued operations of $78 million in 2003 and $13 million in 2004 decreased by $65 million primarily due to a 2004 gain on the sale of the Chicago operations of Thermal and a decrease in operating and maintenance expense of $401, partially offset by a decrease in revenues. At December 31, 2004, the remaining assets of the businesses associated with the former Enterprises segment totaled approximately $274 million in comparison to $697 million at December 31, 2003.

Results of Operations by Business Segment

     Historically, Exelon had reported Enterprises as a segment. Exelon sold or unwound substantially all components of Enterprises in 2004 and 2003. As a result, Enterprises is no longer reported as a segment and is included within the “other” category within the results of operations by business segment below. Other consists of corporate operations, including Exelon Business Services Company, Enterprises and investments in synthetic fuel-producing facilities.

     The comparison of 2004 and 2003 operating results and other statistical information set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

     Transfer of Exelon Energy Company from Enterprises to Generation. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. The 2003 information related to the Generation segment discussed below has been adjusted to reflect the transfer of Exelon Energy Company from Enterprises to the Generation segment. Exelon Energy Company’s 2003 results were as follows:

     Income (Loss) from Continuing Operations

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     Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment

     Net Income (Loss) by Business Segment

Results of Operations – Energy Delivery

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     Net Income. Energy Delivery’s net income in 2004 decreased primarily due to costs associated with ComEd’s accelerated retirement of long-term debt, reflected in other income and deductions — other, net, offset in part by lower interest expense. Operating income, while reflecting various changes in operating revenues and expenses, was relatively unchanged between periods.

     Operating Revenues. The changes in Energy Delivery’s operating revenues for 2004 compared to 2003 consisted of the following:

     Volume. Both ComEd’s and PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effects of weather and customer choice, due to an increased number of customers and increased usage per customer, generally across all customer classes.

     PJM Transmission. Energy Delivery’s transmission revenues and purchased power expense each increased by $164 million due to ComEd’s May 1, 2004 entry into PJM, partially offset by $15 million of lower transmission revenues and expenses at PECO.

     Rate Changes and Mix. Starting in ComEd’s June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component decreased the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased by $135 million in 2004 as compared to 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenues received under the ComEd PPO and by increased average rates paid by small and large commercial and industrial customers totaling $53 million. For 2004 and 2003, ComEd collected approximately $169 million and $304 million, respectively, of CTC revenues. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, ComEd anticipates that this revenue source will range from $90 million to $110 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.

     Electric revenues increased $1 million at PECO as a result of a $20 million increase related to a scheduled phase-out of merger-related rate reductions, offset by a $19 million decrease reflecting a change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 as compared to 2003.

     Energy Delivery’s gas revenues increased due to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for 2004 was 33% higher than the rate in 2003. PECO’s purchased gas cost rates were reduced effective December 1, 2004.

     Weather. Energy Delivery’s electric and gas revenues were negatively affected by unfavorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 12% lower and relatively unchanged, respectively, in 2004 as compared to 2003. Heating degree-days were 6% and 5% lower in both the ComEd and PECO service territories, respectively, in 2004 as compared to 2003.

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     Customer Choice. For 2004 and 2003, 28% and 25%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by an alternative electric supplier or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $104 million from customers in Illinois electing to purchase energy from an alternative electric supplier or under the ComEd PPO and a decrease in revenues of $78 million from customers in Pennsylvania being assigned to or selecting an alternative electric supplier.

     T &O Charges. Prior to FERC orders issued in November 2004, ComEd collected through and out (T&O) charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 5 of Exelon’s Notes to Consolidated Financial Statements for more information on T&O charges.

     Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for 2004 compared to 2003 consisted of the following:

     Volume. ComEd’s and PECO’s purchased power and fuel expense increased due to increases, exclusive of the effects of weather and customer choice, in the number of customers and average usage per customer, generally across all customer classes.

     PJM Transmission. Energy Delivery’s transmission revenues and purchased power expense each increased by $164 million in 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM, partially offset by $15 million of lower transmission revenues and expenses at PECO. See “Operating Revenues” above.

     PJM Administrative Fees. ComEd fully integrated into PJM on May 1, 2004.

     Prices. Energy Delivery’s purchased power expense increased due to a change in the mix of average pricing related to ComEd’s and PECO’s PPAs with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

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

     Weather. Energy Delivery’s purchased power and fuel expense decreased due to unfavorable weather conditions.

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     T &O Charges. Prior to FERC orders issued in November 2004, ComEd collected through and out (T&O) charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 5 of Exelon’s Notes to Consolidated Financial Statements for more information on T&O charges.

     Operating and Maintenance Expense. The changes in operating and maintenance expense for 2004 compared to 2003 consisted of the following:

     Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $31 million at PECO and increased depreciation of $22 million due to capital additions across Energy Delivery. In January 2005, PECO’s Board of Directors approved the implementation of a new customer information and billing system as part of a broader Energy Delivery systems strategy. The approval of this new system will result in the accelerated depreciation of PECO’s current system, which is expected to result in additional annual depreciation expense in 2005 and 2006 of $15 million and $8 million, respectively, relative to 2004 levels. If additional system changes are approved, additional accelerated depreciation may be required.

     Taxes Other Than Income. The increase in taxes other than income reflects increases at PECO and ComEd of $63 million and $24 million, respectively. The increase at PECO was primarily attributable to a $58 million reduction of real estate tax accruals during 2003 and $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $4 million of lower payroll taxes in 2004. The increase at ComEd was primarily attributable to a $25 million credit in 2003 for use tax payments for periods prior to the PECO / Unicom Merger and a refund of $5 million for Illinois Electricity Distribution taxes in 2003 partially offset by a refund of $8 million for Illinois Electricity Distribution taxes in 2004.

     Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates.

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     Distributions on Preferred Securities of Subsidiaries. Effective July 1, 2003, upon the adoption of FIN 46 and effective December 31, 2003, upon the adoption of FIN 46-R, ComEd and PECO deconsolidated their financing trusts (see Note 1 of Exelon’s Notes to Consolidated Financial Statements). ComEd and PECO no longer record distributions on mandatorily redeemable preferred securities, but record interest expense to affiliates related to their obligations to the financing trusts.

     Equity in Losses of Unconsolidated Affiliates. During 2004, ComEd and PECO recorded $19 million and $25 million, respectively, of equity in net losses of subsidiaries as a result of ComEd and PECO deconsolidating their financing trusts.

     Other, net. The change in other, net is primarily due to Exelon’s initiation in 2004 of an accelerated liability management plan at ComEd that resulted in the retirement of approximately $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity. ComEd recorded charges of $130 million associated with the retirement of debt under the plan. The components of these charges included the following: $86 million related to prepayment premiums; $12 million related to net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.

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Energy Delivery Operating Statistics and Revenue Detail

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

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

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Results of Operations — Generation

     As previously described, effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. For comparative discussion and analysis, Exelon Energy Company’s results of operations have been included within the Generation segment results of operations as if this transfer had occurred on January 1, 2003.

     Net Income (Loss). Generation’s net income in 2004 increased from 2003 due to a number of factors. The increase in Generation’s 2004 net income was driven primarily by charges incurred in 2003 for the impairment of the long-lived assets of Boston Generating of $945 million (before income taxes) and the impairment and other transaction-related charges of $280 million (before income taxes) related to Generation’s investment in Sithe. Also, 2004 results were favorably affected by the acquisition of the remaining 50% of AmerGen and an increase in revenue, net of purchased power and fuel expense,

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primarily due to the decrease in average realized costs resulting from the increased success in the hedging program of fuel costs in 2004.

     Cumulative effect of changes in accounting principles recorded in 2004 included a benefit of $32 million, net of income taxes, related to the adoption of FIN 46-R and in 2003 included income of $108 million, net of income taxes related to the of adoption of SFAS No. 143. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of these effects.

     Operating Revenues. Operating revenues decreased in 2004 as compared to 2003, primarily as a result of the adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in revenues of $980 million in 2004 as compared with the prior year. Generation’s sales in 2004 and 2003 were as follows:

     Trading volumes of 24,001 GWhs and 32,584 GWhs for the years ended December 31, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2004, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.

     Electric Sales to Affiliates. Sales to Energy Delivery declined $82 million in 2004 as compared to the prior year. The lower sales to Energy Delivery were primarily driven by cooler than normal summer weather and lower average transfer prices in 2004 compared to the prior year.

     Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:

     The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchased power and fuel expense in 2004. The sale of Boston Generating in May 2004 resulted in less revenues from this entity in 2004 compared to the prior year. The acquisition of AmerGen resulted in increased market and retail electric sales of approximately $189 million in 2004.

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     The remaining increase in wholesale and retail electric sales was primarily due to higher volumes sold to the market at overall higher prices. The increase in market prices was primarily driven by higher coal prices in the Midwest region and higher oil and gas prices in the Mid-Atlantic region.

     Retail Gas Sales. Retail gas sales increased $34 million as a result of higher natural gas prices in 2004.

     Other revenues. Other revenues include increased sales from tolling agreements, offset by a decrease in fossil fuel revenues.

     Purchased Power and Fuel Expense. Generation’s supply of sales in 2004 and 2003, excluding the trading portfolio, was as follows:

     The changes in Generation’s purchased power and fuel expense for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:

     Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $980 million.

     Addition of AmerGen Operations. As a result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $379 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. The decrease in purchased power was partially offset by an increase of $35 million related to AmerGen’s nuclear fuel expense.

     Sale of Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004.

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     Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.

     Price. The decrease reflects the forward hedging of fuel at lower costs than 2003 realized costs.

     Hedging Activity. Mark-to-market losses on hedging activities at Generation were $2 million for the year ended December 31, 2004 compared to losses of $16 million for 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $4 million and hedging activities relating to other Generation operations in 2004 accounted for losses of $6 million.

     Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions.

     Other. Other decreases in purchased power and fuel expense were primarily due to lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM.

     Generation’s average margins per megawatt hour (MWh) sold for the years ended December 31, 2004 and 2003 were as follows:

     Impairment of the Long-Lived Assets of Boston Generating. In connection with the decision to transition out of the ownership of Boston Generating during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 2 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.

     Operating and Maintenance Expense. The changes in operating and maintenance expense for 2004 compared to 2003 consisted of the following:

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     The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen in Generation’s consolidated results for 2004. Decommissioning-related costs increased primarily due to the inclusion of AmerGen in 2004 compared to the prior year. Accretion expense includes accretion of the asset retirement obligation and adjustments to offset the earnings impacts of certain decommissioning related activities revenues earned from ComEd and PECO, income taxes and depreciation of the ARC asset to zero. The increase in operating and maintenance expense was partially offset by reductions in payroll-related costs due to the implementation of the programs associated with The Exelon Way, the sale of Boston Generating in May 2004 and the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel.

     Nuclear fleet operating data and purchased power costs data for the year ended December 31, 2004 and 2003 were as follows:

     The higher nuclear capacity factor and lower nuclear production costs are primarily due to ten fewer unplanned outages which offset the impact of one additional planned refuel outage. The lower production cost in 2004 as compared to 2003 is primarily due to the lower fuel costs and the impact of the spent fuel storage cost settlement agreement with the DOE which offset the added cost for one additional planned refuel outage and costs associated with the Dresden generator repairs during outages in the fourth quarter of 2004.

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

     Depreciation and Amortization. The increase in depreciation and amortization expense in 2004 as compared to 2003 was primarily due to the immediate expensing of an ARC, totaling $49 million, recorded in 2004 for which no useful life remains. The ARC was originally recorded in accordance with SFAS No. 143, which requires the establishment of an asset to offset the impact of an increased asset retirement obligation (ARO). See Note 14 of Exelon’s Notes to Consolidated Financial Statements for more information on the 2004 update to the ARO and ARC. The remaining increase is due to capital additions and the consolidation of AmerGen. These increase were partially offset by a decrease in depreciation expense related to the Boston Generating facilities, which were sold in May 2004.

     Effective Income Tax Rate. The effective income tax rate from continuing operations was 38% for 2004 compared to 43% for 2003. The decrease in the effective rate was primarily attributable to income taxes associated with nuclear decommissioning trust activity, income tax deductions related to non-taxable employee benefits and the dilution of the permanent income tax benefits due to the increase in pre-tax income in 2004.

     Discontinued Operations. In 2004, the loss from discontinued operations included Sithe’s results from April 1, 2004 through the end of the year and the results from AllEnergy, a former subsidiary of Exelon Energy. Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN 46-R. The loss from discontinued operations in 2003 included the results of AllEnergy. Sithe’s net impact to Generation was a loss of $19 million in 2004, while AllEnergy produced $3 million of net income in 2004. In 2003, AllEnergy had a net loss of $21 million. See Note 26 of Exelon’s Notes to Consolidated Financial Statements for further information.

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Results of Operations – Exelon Corporation

Year Ended December 31, 2003 Compared To Year Ended December 31, 2002

Significant Operating Trends – Exelon

     Net Income. Net income for 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143, while net income for 2002 reflects a $230 million charge, net of income taxes, as a result of the adoption of SFAS No. 142. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the adoptions of SFAS No. 143 and SFAS No. 142.

     Operating Revenues. Operating revenues increased in 2003 primarily due to increased market sales at Generation due to generating assets acquired in 2002 and higher wholesale market prices in 2003. Total market sales at Generation, excluding the trading portfolio, increased from 88,985 GWhs in 2002 to 112,816 GWhs in 2003, and the average revenue per MWh on Generation’s market sales, excluding the trading portfolio, increased from $32.36 in 2002 to $35.20 in 2003. This increase in operating revenues was partially offset by a decrease in Energy Delivery’s revenues of $255 million primarily due to unfavorable weather impacts and an increase in customers selecting an alternative electric supplier or ComEd’s PPO. Revenues also decreased by over $215 million primarily due to the sale of InfraSource during the third quarter of 2003. See further discussion of operating revenues by segment below.

     Purchased Power and Fuel Expense. Purchased power and fuel expense increased in 2003 primarily due to generating assets acquired in 2002 and higher market prices for purchased power in 2003. The average cost per MWh supplied by Generation, excluding the trading portfolio, increased from $22.51 in 2002 to $25.48 in 2003 due to increased fossil generation and increased purchased power at higher market prices. Fossil and hydroelectric generation represented 11% of Generation’s total supply in 2003 compared to 6% in 2002. See further discussion of purchased power and fuel expense by segment below.

     Impairment of the Long-Lived Assets of Boston Generating. Generation recorded a $945 million charge (before income taxes) during 2003 to impair the long-lived assets of Boston Generating.

     Operating and Maintenance Expense. Operating and maintenance expense increased in 2003 primarily due to a change in the accounting methodology for nuclear decommissioning, severance and severance-related costs associated with The Exelon Way, and increased costs at Generation associated with generating assets acquired in 2002. Partially offsetting these increases was an overall reduction in operating and maintenance expenses at InfraSource, due to its sale during the third quarter of 2003. See further discussion of operating and maintenance expenses by segment below.

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     Operating Income. The decrease in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense, Boston Generating long-lived asset impairment charge and operating and maintenance expense discussed above, was primarily due to a decrease of $215 million in depreciation and amortization expense primarily due to the adoption of SFAS No. 143 and lower depreciation and amortization expense in the Energy Delivery segment. In addition, taxes other than income also decreased by $135 million primarily due to a reduction in reserves for real estate taxes within the Energy Delivery and Generation segments.

     Other Income and Deductions. Other income and deductions changed primarily due to impairment and other transaction-related charges of $280 million recorded in 2003 related to Generation’s investment in Sithe. Interest expense decreased 9% from $955 million in 2002 to $873 million in 2003 primarily due to less outstanding debt and refinancing of existing debt at lower interest rates at Energy Delivery partially offset by increased interest expense at Generation due to debt related to 2002 acquisitions and reduced capitalized interest in 2003. In 2002, Enterprises recorded a gain on the sale of its investment in AT&T Wireless of $198 million (before income taxes).

     Effective Income Tax Rate. The effective income tax rate from continuing operations was 30% for 2003 compared to 37% for 2002. The decrease in the effective rate was primarily attributable to a decrease in state income taxes, net of Federal income tax benefit.

     Discontinued Operations. Certain qualifying components of Enterprises and AllEnergy for 2003 and 2002 have been classified as discontinued operations within the Consolidated Statements of Income. A discussion of the results of AllEnergy is included in the Generation segment discussion below. Enterprises’ after-tax loss from discontinued operations increased $48 million from $30 million in 2002 to $78 million in 2003, primarily due to a reduction in revenues, only partially offset by a decrease in operating and maintenance expenses. Operating and maintenance expense in 2003 included impairment charges of $14 million (before income taxes) related to the classification of the assets and liabilities of Exelon Services as held for sale and goodwill impairment charges of $24 million (before income taxes) related to the remaining goodwill within the Exelon Services reporting unit.

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Results of Operations by Business Segment

     Historically, Exelon had presented Enterprises as a segment. Exelon sold or unwound substantially all components of Enterprises in 2004 and 2003. As a result, Enterprises is no longer reported as a segment and is included within the “other” category within the results of operations by business segment below. Other consists of corporate operations, including Exelon Business Services Company, Enterprises and investments in synthetic fuel-producing facilities.

     The comparisons of 2003 and 2002 operating results and other statistical information set forth below reflect intercompany transactions, which are eliminated in the consolidated financial statements.

     Transfer of Exelon Energy Company from Enterprises to Generation. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. The information for 2003 and 2002 related to the Generation segment discussed below has been adjusted to reflect the transfer of Exelon Energy Company to the Generation segment. Exelon Energy Company’s 2003 and 2002 results were as follows:

     Income from Continuing Operations

     Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment

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     Net Income (Loss) by Business Segment

Results of Operations – Energy Delivery

     Net Income. Energy Delivery’s net income in 2003 decreased primarily due to increased operating and maintenance expense resulting from severance and curtailment charges associated with The Exelon Way, a charge at ComEd associated with a regulatory settlement, lower revenues, net of purchased power primarily attributable to weather and higher purchased power prices, partially offset by reductions in depreciation and amortization expense, taxes other than income, and interest expense.

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     Operating Revenues. The changes in Energy Delivery’s operating revenues for 2003 compared to 2002 consisted of the following:

     Customer Choice. For 2003 and 2002, 25% and 21%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by an alternative electric supplier or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $155 million from customers in Illinois electing to purchase energy from an alternative electric supplier and a decrease in revenues of $12 million from customers in Pennsylvania selecting or being assigned to an alternative electric generation supplier.

     Weather. Energy Delivery’s electric revenues were affected by cooler summer weather in 2003, partially offset by colder winter weather in the first quarter of 2003. Cooling degree-days in the ComEd and PECO service territories were 36% lower and 21% lower, respectively, in 2003 as compared to 2002. Heating degree-days in the ComEd and PECO service territories were 5% higher and 16% higher, respectively, in 2003 as compared to 2002.

     Energy Delivery’s gas revenues were affected by colder winter weather in the first quarter of 2003.

     Resales and Other. Energy Delivery’s gas revenues decreased as a result of a decrease in off-system sales, exchanges and capacity releases.

     Rate Changes and Mix. Energy Delivery’s electric revenues decreased $33 million at ComEd primarily due to decreased average energy rates under ComEd’s PPO as a result of lower wholesale market prices. Electric revenues decreased $25 million at PECO as a result of rate mix due to changes in monthly usage patterns in all customer classes during 2003 as compared to 2002.

     Energy Delivery’s gas revenues increased due to increases in rates through the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003 and December 1, 2003. The average purchased gas cost rate per million cubic feet for 2003 was 11% higher than the rate in 2002. PECO’s purchased gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates.

     Volume. Energy Delivery’s electric revenues increased as a result of higher delivery volume, exclusive of the effects of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily in the large and small commercial and industrial customer classes.

     Other. The decrease was attributable to a reduction in wholesale revenues. This reduction reflects a $12 million reimbursement from Generation in 2002.

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     Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for 2003 compared to 2002 consisted of the following:

     Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an alternative electric supplier or ComEd’s PPO and PECO’s non-residential customers electing or being assigned to purchase energy from alternative energy suppliers.

     Weather. Energy Delivery’s purchased power and fuel expense decreased due to the impacts of cooler summer weather in 2003, partially offset by colder winter weather in the first quarter of 2003.

     Resales and other. Energy Delivery’s fuel expense decreased as a result of reduced resale transactions.

     Prices. Energy Delivery’s purchased power increased for electric due to an increase in the weighted average on-peak/off-peak cost of electricity at ComEd, and fuel expense for gas increased due to PECO’s higher gas prices.

     Volume. Energy Delivery’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather, in the number of customers and average usage per customer, primarily large and small commercial and industrial customers at ComEd and PECO.

     Decommissioning. ComEd changed its presentation for accounting for decommissioning collections upon the adoption of SFAS No. 143 (see Note 14 of Exelon’s Notes to Consolidated Financial Statements). Decommissioning collections, which are remitted to Generation, were previously recorded as amortization expense and are recorded as purchased power expense in 2003.

     Other. Energy Delivery’s purchased power decreased due to additional energy billed in 2002 under the purchase power agreement (PPA) with Generation discussed in other operating revenues above.

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     Operating and Maintenance Expense. The changes in operating and maintenance expense for 2003 compared to 2002 consisted of the following:

     Depreciation and Amortization Expense. The reduction in depreciation and amortization expense was primarily due to a change in the accounting for nuclear decommissioning at ComEd, lower amortization of ComEd’s recoverable transition costs of $58 million and a $48 million reduction due to changes in ComEd’s depreciation rates in 2002, partially offset by increased depreciation of $30 million due to capital additions across Energy Delivery and increased competitive transition charge amortization of $28 million at PECO.

     Taxes Other Than Income. The reduction in taxes other than income was primarily due to a reduction of real estate tax accruals recorded by PECO of $58 million during the third quarter of 2003 and a favorable settlement of coal use tax at ComEd of $25 million. See Note 20 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the reduction of real estate tax accruals recorded by PECO.

     Interest Expense. The reduction in interest expense was primarily due to refinancing existing debt at lower rates and the pay down of transitional trust notes.

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Energy Delivery Operating Statistics and Revenue Detail

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

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