Exhibit 99-4 Exelon Corporation and Subsidiary Companies Financial Statements and Supplementary Data Report of Independent Accountants To the Shareholders and Board of Directors of Exelon Corporation: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, cash flows and changes in shareholders' equity and comprehensive income present fairly, in all material respects, the financial position of Exelon Corporation and Subsidiary Companies (Exelon) at December 31, 2002 and December 31, 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Exelon's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 2 to the consolidated financial statements, Exelon acquired Unicom Corporation on October 20, 2000 in a business combination accounted for under the purchase method of accounting. The results of Unicom Corporation are included in the consolidated financial statements since the acquisition date. As discussed in Note 4 to the consolidated financial statements, Exelon changed its method of accounting for nuclear outage costs in 2000. As discussed in Note 1 to the consolidated financial statements, Exelon changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. As discussed in Note 4 to the consolidated financial statements, Exelon changed its method of accounting for goodwill effective January 1, 2002. Chicago, Illinois January 29, 2003, except for Note 23 for which the date is February 20, 2003. 74 Exelon Corporation and Subsidiary Companies Consolidated Statements of Income For the Years Ended December 31, ------------------------------------------------ in millions, except per share data 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Operating Revenues $ 14,955 $ 14,918 $ 7,499 Operating Expenses Purchased Power 3,262 3,156 1,620 Purchased Power from Unconsolidated Affiliate 273 57 52 Fuel 1,727 1,877 934 Operating and Maintenance 4,345 4,394 2,310 Merger-Related Costs -- -- 276 Depreciation and Amortization 1,340 1,449 458 Taxes Other Than Income 709 623 322 - ------------------------------------------------------------------------------------------------------------------- Total Operating Expenses 11,656 11,556 5,972 - ------------------------------------------------------------------------------------------------------------------- Operating Income 3,299 3,362 1,527 - ------------------------------------------------------------------------------------------------------------------- Other Income and Deductions Interest Expense, net of amounts capitalized (966) (1,107) (614) Distributions on Preferred Securities of Subsidiaries (45) (49) (24) Equity in Earnings (Losses) of Unconsolidated Affiliates, net 80 62 (41) Other, Net 300 79 53 - ------------------------------------------------------------------------------------------------------------------- Total Other Income and Deductions (631) (1,015) (626) - ------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes and the Cumulative Effect of Changes in Accounting Principles 2,668 2,347 901 Income Taxes 998 931 339 - ------------------------------------------------------------------------------------------------------------------- Income Before Cumulative Effect of Changes in Accounting Principles 1,670 1,416 562 Cumulative Effect of Changes in Accounting Principles (net of income taxes of $(90), $8 and $16 in 2002, 2001 and 2000, respectively) (230) 12 24 - ------------------------------------------------------------------------------------------------------------------- Net Income $ 1,440 $ 1,428 $ 586 - ------------------------------------------------------------------------------------------------------------------- Average Shares of Common Stock Outstanding Basic 322 320 202 Diluted 325 322 204 - ------------------------------------------------------------------------------------------------------------------- Earnings Per Common Share - Basic: Income Before Cumulative Effect of Changes in Accounting Principles $ 5.18 $ 4.42 $ 2.79 Cumulative Effect of Changes in Accounting Principles (0.71) 0.04 0.12 - ------------------------------------------------------------------------------------------------------------------- Net Income $ 4.47 $ 4.46 $ 2.91 - ------------------------------------------------------------------------------------------------------------------- Earnings Per Common Share - Diluted: Income Before Cumulative Effect of Changes in Accounting Principles $ 5.15 $ 4.39 $ 2.75 Cumulative Effect of Changes in Accounting Principles (0.71) 0.04 0.12 - ------------------------------------------------------------------------------------------------------------------- Net Income $ 4.44 $ 4.43 $ 2.87 - ------------------------------------------------------------------------------------------------------------------- Dividends Per Common Share $ 1.76 $ 1.82 $ 0.91 - ------------------------------------------------------------------------------------------------------------------- See Notes to Consolidated Financial Statements 75 Exelon Corporation and Subsidiary Companies Consolidated Statements of Cash Flows For the Years Ended December 31, ------------------------------------------- in millions 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities Net Income $ 1,440 $ 1,428 $ 586 Adjustments to reconcile Net Income to Net Cash Flows provided by Operating Activities: Depreciation and Amortization, including nuclear fuel 1,701 1,834 607 Cumulative Effects of Changes in Accounting Principles (net of income taxes) 230 (12) (24) Provision for Uncollectible Accounts 129 145 89 Net Gain on Sale of Investments (199) -- -- Deferred Income Taxes 278 (68) 193 Merger-Related Costs -- -- 276 Employee Severance Costs -- 46 -- Deferred Energy Costs 25 29 (79) Equity in (Earnings) Losses of Unconsolidated Affiliates, net (80) (62) 41 Write-down of Investments 41 36 -- Net Realized Losses on Nuclear Decommissioning Trust Funds 32 127 -- Other Operating Activities 12 (16) (165) Changes in Working Capital: Accounts Receivable (448) 318 (445) Repurchase of Accounts Receivable -- -- (50) Inventories (37) (33) 49 Accounts Payable, Accrued Expenses & Other Current Liabilities 470 (190) (2) Other Current Assets 20 33 20 - ------------------------------------------------------------------------------------------------------------------- Net Cash Flows provided by Operating Activities 3,614 3,615 1,096 - ------------------------------------------------------------------------------------------------------------------- Cash Flows from Investing Activities Capital Expenditures (2,150) (2,088) (752) Acquisitions of Generating Plants (445) -- -- Unicom Merger Consideration -- -- (507) Proceeds from Direct Financing Leases -- -- 1,228 Investment in Sithe Energies, Inc. -- -- (704) Enterprises Acquisitions, net of cash acquired -- (30) (245) Proceeds from the Sale of Investments 287 -- -- Proceeds from Nuclear Decommissioning Trust Funds 1,612 1,624 265 Investment in Nuclear Decommissioning Trust Funds (1,824) (1,863) (380) Note Receivable from Unconsolidated Affiliate (35) -- -- Other Investing Activities 17 (35) (108) - ------------------------------------------------------------------------------------------------------------------- Net Cash Flows used in Investing Activities (2,538) (2,392) (1,203) - ------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Issuance of Long-Term Debt 1,223 2,270 1,021 Common Stock Repurchases -- -- (501) Retirement of Long-Term Debt (2,134) (1,860) (665) Change in Short-Term Debt 321 (1,013) 10 Redemption of Preferred Securities of Subsidiaries (18) (17) (19) Dividends Paid on Common Stock (563) (583) (157) Change in Restricted Cash (24) (58) (140) Proceeds from Employee Stock Plans 78 39 67 Contribution from Minority Interest of Consolidated Subsidiary 43 -- -- Other Financing Activities (18) (42) (11) - ------------------------------------------------------------------------------------------------------------------- Net Cash Flows used in Financing Activities (1,092) (1,264) (395) - ------------------------------------------------------------------------------------------------------------------- Decrease in Cash and Cash Equivalents (16) (41) (502) Cash and Cash Equivalents at beginning of period 485 526 54 Cash Acquired in Unicom Merger -- -- 974 - ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at end of period $ 469 $ 485 $ 526 - ------------------------------------------------------------------------------------------------------------------- See Notes to Consolidated Financial Statements 76 Exelon Corporation and Subsidiary Companies Consolidated Balance Sheets December 31, ------------------------------------- in millions 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Assets Current Assets Cash and Cash Equivalents $ 469 $ 485 Restricted Cash 396 372 Accounts Receivable, net Customer 2,095 1,687 Other 265 381 Receivable from Unconsolidated Affiliate 32 44 Inventories, at average cost Fossil Fuel 218 222 Materials and Supplies 306 249 Deferred Income Taxes 6 23 Other 331 272 - ------------------------------------------------------------------------------------------------------------------- Total Current Assets 4,118 3,735 - ------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment, net 17,134 13,791 Deferred Debits and Other Assets Regulatory Assets 5,938 6,423 Nuclear Decommissioning Trust Funds 3,053 3,165 Investments 1,393 1,623 Goodwill, net 4,992 5,335 Other 850 672 - ------------------------------------------------------------------------------------------------------------------- Total Deferred Debits and Other Assets 16,226 17,218 - ------------------------------------------------------------------------------------------------------------------- Total Assets $ 37,478 $ 34,744 - ------------------------------------------------------------------------------------------------------------------- Liabilities and Shareholders' Equity Current Liabilities Notes Payable $ 681 $ 360 Note Payable to Unconsolidated Affiliate 534 -- Long-Term Debt Due Within One Year 1,402 1,406 Accounts Payable 1,563 964 Accrued Expenses 1,311 1,135 Other 483 505 - ------------------------------------------------------------------------------------------------------------------- Total Current Liabilities 5,974 4,370 - ------------------------------------------------------------------------------------------------------------------- Long-Term Debt 13,127 12,879 Deferred Credits and Other Liabilities Deferred Income Taxes 3,702 4,362 Unamortized Investment Tax Credits 301 316 Nuclear Decommissioning Liability for Retired Plants 1,395 1,353 Pension Obligation 1,959 334 Non-Pension Postretirement Benefits Obligation 877 847 Spent Nuclear Fuel Obligation 858 843 Other 871 694 - ------------------------------------------------------------------------------------------------------------------- Total Deferred Credits and Other Liabilities 9,963 8,749 - ------------------------------------------------------------------------------------------------------------------- Commitments and Contingencies Minority Interest of Consolidated Subsidiaries 77 31 Preferred Securities of Subsidiaries 595 613 Shareholders' Equity Common Stock 7,059 6,961 Deferred Compensation (1) (2) Retained Earnings 2,042 1,169 Accumulated Other Comprehensive Income (Loss) (1,358) (26) - ------------------------------------------------------------------------------------------------------------------- Total Shareholders' Equity 7,742 8,102 - ------------------------------------------------------------------------------------------------------------------- Total Liabilities and Shareholders' Equity $ 37,478 $ 34,744 - ------------------------------------------------------------------------------------------------------------------- See Notes to Consolidated Financial Statements 77 Exelon Corporation and Subsidiary Companies Consolidated Statements of Changes in Shareholders' Equity Accumulated Other Total Dollars in millions, Common Deferred Retained Treasury Comprehensive Shareholders' shares in thousands Shares Stock Compensation Earnings Shares Income (Loss) Equity - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 1999 225,354 $ 3,577 $ (3) $ (100) $ (1,705) $ 4 $ 1,773 Net Income -- -- 586 -- -- 586 Long-Term Incentive Plan Activity 563 75 (9) -- 7 -- 73 Shares Issued to Acquire Unicom 147,963 5,310 -- -- -- -- 5,310 Merger Consideration-Stock Options 111 -- -- -- -- 111 Amortization of Deferred Compensation -- 5 -- -- -- 5 Common Stock Dividends Declared -- -- (157) -- -- (157) Common Stock Repurchases -- -- (5) (496) -- (501) Stock Option Exercises -- -- -- 19 -- 19 Cancellation of Treasury Shares (54,875) (2,175) -- -- 2,175 -- -- Other Comprehensive Income (Loss), net of income taxes of $(1) -- -- -- -- (4) (4) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000 319,005 $ 6,898 $ (7) $ 324 $ -- $ -- $ 7,215 Net Income -- -- 1,428 -- -- 1,428 Long-Term Incentive Plan Activity 1,864 55 -- -- -- -- 55 Employee Stock Purchase Plan Issuances 138 6 -- -- -- -- 6 Merger Consideration-Stock Options 2 -- -- -- -- 2 Amortization of Deferred Compensation -- 5 -- -- -- 5 Common Stock Dividends Declared -- -- (583) -- -- (583) Reclassified Net Unrealized Losses on Marketable Securities, net of income taxes of $(22) -- -- -- -- (23) (23) Other Comprehensive Income (Loss), net of income taxes of $(7) -- -- -- -- (3) (3) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001 321,007 $ 6,961 $ (2) $ 1,169 $ -- $ (26) $ 8,102 Net Income -- -- 1,440 -- -- 1,440 Long-Term Incentive Plan Activity 2,049 87 -- -- -- -- 87 Employee Stock Purchase Plan Issuances 257 11 -- -- -- -- 11 Amortization of Deferred Compensation -- 1 -- -- -- 1 Common Stock Dividends Declared -- -- (567) -- -- (567) Other Comprehensive Income (Loss), net of income taxes of $(850) -- -- -- -- (1,332) (1,332) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002 323,313 $ 7,059 $ (1) $ 2,042 $ -- $ (1,358) $ 7,742 - -------------------------------------------------------------------------------------------------------------------- Exelon Corporation and Subsidiary Companies Consolidated Statements of Comprehensive Income For the Years Ended December 31, -------------------------------------- in millions 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Net Income $ 1,440 $ 1,428 $ 586 Other Comprehensive Income (Loss) Minimum Pension Liability, net of income taxes of $(597) (1,007) -- -- SFAS No. 133 Transition Adjustment, net of income taxes of $32 -- 44 -- Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(132) and $17, respectively (199) 22 -- Foreign Currency Translation Adjustment, net of income taxes of $0 -- (1) -- Unrealized Gain (Loss) on Marketable Securities, net of income taxes of $(116), $(40) and $(1), respectively (119) (41) (4) Interest in Other Comprehensive Income (Loss) of Unconsolidated Affiliates, net of income taxes of $(5) and $(16), respectively (7) (27) -- - ------------------------------------------------------------------------------------------------------------------- Total Other Comprehensive Income (Loss) (1,332) (3) (4) - ------------------------------------------------------------------------------------------------------------------- Total Comprehensive Income $ 108 $ 1,425 $ 582 - ------------------------------------------------------------------------------------------------------------------- See Notes to Consolidated Financial Statements 78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Exelon Corporation and Subsidiary Companies (Dollars in millions, except per share data unless otherwise noted) 1. Significant Accounting Policies Description of Business Exelon Corporation (Exelon) is a utility services holding company formed as a result of the merger of Unicom Corporation (Unicom), the former parent company of Commonwealth Edison Company (ComEd), and PECO Energy Company (PECO) (Merger) (see Note 2 - Merger). Exelon is engaged, through its subsidiaries, in the energy delivery, wholesale generation and the enterprises businesses discussed below (see Note 20 - Segment Information). The Energy Delivery segment's businesses include the sale of electricity and distribution and transmission services by ComEd in northern Illinois and PECO in southeastern Pennsylvania and the sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. The wholesale generation business consists of the electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation) and Generation's interests in Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen). Exelon Enterprises Company, LLC (Enterprises) includes energy and infrastructure services, competitive retail energy sales, communications joint ventures and other investments weighted towards the communications, energy services and retail services industries. Basis of Presentation The consolidated financial statements of Exelon include the accounts of its majority-owned subsidiaries after the elimination of intercompany transactions. Investments and joint ventures in which a 20% to 50% interest is owned and a significant influence is exerted are accounted for under the equity method of accounting. The proportionate interests in jointly owned electric utility plants are consolidated. Investments in which less than a 20% interest is owned are primarily accounted for under the cost method of accounting. Exelon owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for ComEd of which Exelon owns more than 99%, InfraSource Inc. (InfraSource) of which Exelon owns 95% and Southeast Chicago Energy Project, LLC of which Exelon owns 70% through Generation. Exelon has reflected the third-party interests in the above majority owned investments as minority interests in its Consolidated Statements of Cash Flows, Consolidated Balance Sheets and in Other, Net on the Consolidated Statements of Income. Accounting policies for regulated operations are in accordance with those prescribed by the regulatory authorities having jurisdiction, principally the Illinois Commerce Commission (ICC), the Pennsylvania Public Utility Commission (PUC), the Federal Energy Regulatory Commission (FERC) and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). On October 20, 2000, Exelon became the parent of PECO through a share exchange and Unicom was merged into Exelon. As a result of these transactions, Unicom ceased to exist and Exelon became the parent of ComEd and PECO (see Note 2 - Merger). For accounting purposes, PECO was deemed the acquiror in the Merger. Accordingly, the financial statements of Exelon for the periods presented prior to October 20, 2000 represent the historical financial statements of PECO and for the periods from October 20, 2000 include the operations acquired from Unicom. Accounting for the Effects of Regulation Exelon accounts for all of its regulated electric and gas operations in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS No. 71) requiring Exelon to record in its financial statements the effects of rate regulation. Use of SFAS No. 71 is applicable to the utility operations of Exelon 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 79 rates. Exelon believes that it is probable that currently recorded regulatory assets will be recovered. If a separable portion of Exelon's business no longer meets the provisions of SFAS No. 71, Exelon is required to eliminate the financial statement effects of regulation for that portion. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to, the accounting for derivatives, nuclear decommissioning liabilities, asset impairment analyses, environmental costs and pension costs. Revenues Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, Exelon accrues an estimate for the unbilled amount of energy delivered or services provided to its electric and gas customers (see Note 8 - Accounts Receivable). Exelon recognizes contract revenues and profits on certain long-term fixed-price contracts from its services businesses under the percentage-of-completion method of accounting based on costs incurred as a percentage of estimated total costs of individual contracts. Premiums received and paid on option contracts and swap arrangements are amortized to revenue and expense over the life of the contracts. Certain of these contracts are considered derivative instruments and are recorded at fair value with subsequent changes in fair value recognized as revenues and expenses unless hedge accounting is applied. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method. Under this methodology, these derivatives are adjusted to fair value, and the unrealized gains and losses are recognized in current period income. Long-Term Contract Accounting Enterprises recognizes contract revenue and profits on certain long-term fixed-price contracts by the percentage-of-completion method of accounting. In determining the amount of revenue to recognize, Exelon is required to estimate the total costs and profits expected to be recorded under the contract over its contract term, and the recoverability of costs related to change orders. Changes in these estimates could result in the recognition of differences in earnings. At December 31, 2002 and 2001, Current Assets includes $70 million and $77 million, respectively, of Costs and Earnings in Excess of Billings on uncompleted contracts and Current Liabilities includes $44 million and $56 million, respectively, of Billings and Earnings in Excess of Costs on uncompleted contracts. At December 31, 2002 and 2001, Accounts Receivable includes $49 million and $46 million, respectively, of contract retention. This amount represents revenue recognized on costs incurred that is not yet billable until final completion of the project and acceptance by the customer. In applying the percentage-of-completion accounting method, the collection of these estimated revenues is deemed probable. Purchased Gas Adjustment Clause PECO's natural gas rates are subject to a fuel adjustment clause designed to recover or refund the difference between the actual cost of purchased gas and the amount included in base rates. Differences between the amounts billed to customers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of prospective quarterly adjustments to rates. Nuclear Fuel 80 The cost of nuclear fuel is capitalized and charged to fuel expense using the unit of production method. Estimated costs of nuclear fuel storage and disposal at operating plants are charged to fuel expense as the related fuel is consumed. Stock-Based Compensation Exelon uses the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123). See Note 17 - Common Stock for further discussion of these plans. The table below shows the effect on net income and earnings per share had Exelon elected to account for its stock-based compensation plans using the fair value method under SFAS No. 123 for the years ended December 31, 2002, 2001 and 2000: 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Net income - as reported $ 1,440 $ 1,428 $ 586 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes 33 26 25 - ------------------------------------------------------------------------------------------------------------------- Pro forma net income $ 1,407 $ 1,402 $ 561 - ------------------------------------------------------------------------------------------------------------------- Earnings per share: Basic - as reported $ 4.47 $ 4.46 $ 2.91 Basic - pro forma $ 4.36 $ 4.38 $ 2.77 Diluted - as reported $ 4.44 $ 4.43 $ 2.87 Diluted - pro forma $ 4.33 $ 4.35 $ 2.75 - ------------------------------------------------------------------------------------------------------------------- Income Taxes Deferred Federal and state income taxes are provided on all significant temporary differences between book basis and tax basis of assets and liabilities. Investment tax credits previously utilized for income tax purposes have been deferred on the Consolidated Balance Sheets and are recognized in book income over the life of the related property. Exelon and its subsidiaries file a consolidated Federal income tax return. Income taxes are allocated to each of Exelon's subsidiaries within the consolidated group based on the separate return method. Exelon estimates its income tax valuation allowance by assessing which deferred tax assets are more likely than not to be recovered in the future (see Note 14 - Income Taxes). Gains and Losses on Reacquired Debt Recoverable gains and losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the period consistent with rate recovery for ratemaking purposes. Gains and losses on other debt are recognized in Exelon's Consolidated Statements of Income as incurred (see Note 6 - Supplemental Financial Information). Comprehensive Income Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Comprehensive income is reflected in the Consolidated Statements of Changes in Shareholders' Equity and the Consolidated Statements of Comprehensive Income. Cash and Cash Equivalents Exelon considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. 81 Restricted Cash Restricted cash reflects escrowed cash to be applied to the principal and interest payment on the transition bonds and transitional trust notes. Marketable Securities Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. Under regulatory accounting practices, unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds are reported in accumulated depreciation for operating units and as a reduction of regulatory assets for retired units. If regulatory accounting practices are not applicable, unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds are reported in accumulated other comprehensive income. At December 31, 2002 and 2001, Exelon had no held-to-maturity or trading securities. Property, Plant and Equipment Property, plant and equipment is recorded at cost. Exelon evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between the carrying value and fair value. The cost of maintenance, repairs and minor replacements of property is charged to maintenance expense as incurred. Upon retirement, the cost of regulated property plus removal costs less salvage value is charged to accumulated depreciation by the regulated subsidiaries in accordance with regulatory practices. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition. Depreciation, Amortization and Decommissioning Depreciation is provided over the estimated service lives of property, plant and equipment on a straight-line basis. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category, are presented in the table below. See Note 4 - Adoption of New Accounting Pronouncements and Accounting Changes for information on service life extensions for certain nuclear generating stations and Energy Delivery's change in depreciation rates. Asset Category 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Electric-Transmission and Distribution 3.11% 3.97% 4.16% Electric-Generation 3.65% 3.11% 5.02% Gas 2.13% 2.34% 2.39% Common - Gas and Electric 6.40% 6.26% 5.09% Other Property and Equipment 7.88% 9.53% 8.11% - ------------------------------------------------------------------------------------------------------------------- Amortization of regulatory assets is provided over the recovery period specified in the related regulatory agreement. Goodwill associated with the Merger was amortized on a straight-line basis over 40 years in 2001 and 2000. Goodwill associated with other acquisitions was amortized over periods from 10 to 20 years in 2001 and 2000. Accumulated amortization of goodwill was $185 million and $35 million at December 31, 2001 and 2000, respectively. Effective January 1, 2002, under SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142), goodwill recorded by Exelon is no longer subject to amortization but is subject to an annual impairment test (see Note 4 - Adoption of New Accounting Pronouncements and Accounting Changes). Exelon currently recovers costs for decommissioning its nuclear generating stations, excluding AmerGen, through regulated rates. The amounts recovered from customers are deposited in trust 82 accounts and invested for funding of future costs for operating and retired nuclear generating stations. The majority of the eventual work to decommission Exelon's nuclear generating stations will occur after 2029. Exelon accounts for the current period's cost of decommissioning related to generating plants previously owned by PECO following common regulatory accounting practices by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation concurrently with decommissioning collections. Financial activity of the decommissioning trust (e.g., investment income and realized and unrealized gains and losses on trust investments) is reflected in Nuclear Decommissioning Trust Funds in Exelon's Consolidated Balance Sheets with a corresponding offset recorded to the liability in accumulated depreciation. Under common regulatory practices, the deposit of funds into the decommissioning trust accounts plus the financial activity reflected in Nuclear Decommissioning Trust Funds in Exelon's Consolidated Balance Sheets will, over time, establish a corresponding liability in accumulated depreciation reflecting the cost to decommission the nuclear generating stations previously owned by PECO. Exelon will adopt SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143) as of January 1, 2003. See "New Accounting Pronouncements" within this note for a discussion as to how this standard will change the accounting for nuclear decommissioning costs. Regulatory accounting practices for the nuclear generating stations previously owned by ComEd were discontinued as a result of an ICC order capping ComEd's ultimate recovery of decommissioning costs. See Note 11 - Nuclear Decommissioning and Spent Fuel Storage regarding regulatory accounting practices for nuclear generating stations transferred by ComEd to Generation. The difference between the current decommissioning cost estimate and the decommissioning liability recorded in accumulated depreciation for the former ComEd operating stations is being amortized to depreciation expense on a straight-line basis over the remaining lives of the stations. The current decommissioning cost estimate (adjusted annually to reflect inflation) for the former ComEd retired units recorded in deferred credits and other liabilities is accreted to depreciation expense. Financial activity of the decommissioning trust related to Exelon's nuclear generating stations no longer accounted for under common regulatory practices (e.g., investment income and realized and unrealized gains and losses on trust investments) is reflected in Nuclear Decommissioning Trust Funds in Exelon's Consolidated Balance Sheets with a corresponding gain or expense recorded in Exelon's Consolidated Income Statement or in other comprehensive income. The offset to the financial activity in the decommissioning trust funds is summarized as follows: o Interest income is recorded in other income and deductions, o Realized gains and losses are recorded in other income and deductions, o Unrealized gains and losses are recorded in other comprehensive income, and o Trust fund operating expenses are recorded in operation and maintenance expense Exelon believes that the amounts being recovered from customers through electric rates along with the earnings on the trust funds will be sufficient to fully fund its decommissioning obligations. Capitalized Interest Exelon uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the costs during construction of debt funds used to finance its non-regulated construction projects. Exelon recorded capitalized interest of $20 million, $17 million and $2 million in 2002, 2001 and 2000, respectively. Allowance for Funds Used During Construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded as a charge to Construction Work in Progress and as a non-cash credit to AFUDC that is included in Other Income and Deductions. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities (see Note 6 - Supplemental Financial Information). 83 Capitalized Software Costs Costs incurred during the application development stage of software projects for software that is developed or obtained for internal use are capitalized. At December 31, 2002, 2001 and 2000, capitalized software costs totaled $335 million, $240 million and $285 million, respectively, net of $156 million, $85 million and $53 million of accumulated amortization, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed ten years. Certain capitalized software is being amortized over fifteen years pursuant to regulatory approval. Derivative Financial Instruments Exelon accounts for derivative financial instruments under SFAS No. 133, "Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. Changes in the fair value of the derivative financial instruments that do not qualify for a normal purchase and normal sales exception are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged. In connection with Exelon's Risk Management Policy (RMP), Exelon enters into derivatives to manage its exposure to fluctuations in interest rates related to its variable rate debt instruments, changes in interest rates related to planned future debt issuances prior to their actual issuance and changes in the fair value of outstanding debt which is planned for early retirement. As it relates to energy transactions, Exelon utilizes derivatives to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Exelon also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Exelon enters into certain energy related derivatives for trading or speculative purposes. As part of Exelon's energy marketing business, Exelon enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While these contracts are considered derivative financial instruments under SFAS No. 133, the majority of these transactions have been designated as "normal purchases" or "normal sales" and are not subject to the provisions of SFAS No. 133. Under these contracts, Exelon recognizes gains or losses when the underlying physical transaction affects earnings. Revenues and expenses associated with market price risk management contracts are amortized over the terms of such contracts. Commitments under these contracts are discussed in Note 19 - Commitments and Contingencies. The remainder of these contracts are generally considered cash flow hedges under SFAS No. 133. To the extent that the hedges are effective, changes in the fair value of these contracts are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged. Additionally, during 2001, as part of the creation of Exelon's energy trading operation, Exelon began to enter into contracts to buy and sell energy for trading purposes subject to limits. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. 84 Prior to the adoption of SFAS No. 133, Exelon applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. Exelon recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings. Contracts entered into by Exelon to limit market risk associated with forward energy commodity contracts are reflected in the financial statements at the lower of cost or market using the accrual method of accounting. Under these contracts, Exelon recognizes any gains or losses when the underlying physical transaction affects earnings. Revenues and expenses associated with market price risk management contracts are amortized over the terms of such contracts. New Accounting Pronouncements In 2001, the FASB issued SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. Exelon will adopt SFAS No. 143 as of January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the decommissioning of Generation's nuclear generating plants as well as certain other long-lived assets. As it relates to nuclear decommissioning, the effect of this cumulative adjustment will be to decrease the decommissioning liability to reflect the fair value of the decommissioning obligation at the balance sheet date. Additionally, SFAS No. 143 will require the recognition of an asset related to the decommissioning obligation, which will be amortized over the remaining lives of the plants. The net difference, between the asset recognized and the change in the liability to reflect fair value recorded upon adoption of SFAS No. 143, will be recorded in earnings and recognized as a cumulative effect of a change in accounting principle, net of expected regulatory recovery and income taxes. The decommissioning liability will then represent an obligation for the future decommissioning of the plants and, as a result, accretion expense will be accrued on this liability until such time as the obligation is satisfied. Currently, Generation records the obligation for decommissioning ratably over the lives of the plants. Based on the current information and the credit-adjusted risk-free rate, we estimate the increase in 2003 non-cash expense to impact earnings before the cumulative effect of a change in accounting principle for the adoption of SFAS No. 143 by approximately $24 million, after income taxes. Additionally, the adoption of SFAS No. 143 is expected to result in a large, non-cash, one-time cumulative effect of a change in accounting principle gain of at least $1.5 billion, after income taxes. The $1.5 billion gain and the $24 million charge includes our share of the impact of the SFAS No. 143 adoption related to AmerGen's nuclear plants. These impacts are based on our current interpretation of SFAS No. 143 and are subject to continued refinement based on the finalization of assumptions and interpretation at the time of adopting the standard, including the determination of the credit-adjusted risk-free rate. Under SFAS No. 143, the fair value of the nuclear decommissioning obligation will continue to be adjusted on an ongoing basis as these model input factors change. The final determination of the 2003 earnings impact and the cumulative effect of adopting SFAS No. 143, is in part a function of the credit adjusted risk-free rate at the time of the adoption of SFAS No. 143. Additionally, although over the life of the plant the charges to earnings for the depreciation of the asset and the interest on the liability will be equal to the amounts that would have been recognized as decommissioning expense under the current accounting, the timing of those charges will change and in the near-term period subsequent to adoption, the depreciation of the asset and the interest on the liability is expected to result in an increase in expense. 85 In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 requires that the liability for costs associated with exit or disposal activities be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. In November 2002, the FASB released FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45), providing for expanded disclosures and recognition of a liability for the fair value of the obligation undertaken by the guarantor. Under FIN No. 45, guarantors are required to disclose the nature of the guarantee, the maximum amount of potential future payments, the carrying amount of the liability and the nature and amount of recourse provisions or available collateral that would be recoverable by the guarantor. Exelon has adopted the disclosure requirements under FIN No. 45, (see Note 19 - Commitments and Contingencies) which were effective for financial statements for periods ended after December 15, 2002. The recognition and measurement provisions of FIN No. 45 are effective, on a prospective basis, for guarantees issued or modified after December 31, 2002. In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities" (FIN No. 46). FIN No. 46 addresses consolidating certain variable interest entities and applies immediately to variable interest entities created after January 31, 2003. The impact, if any, of adopting FIN 46 on our consolidated financial position, results of operations and cash flows, has not been fully determined. See Note 4 - Adoption of New Accounting Pronouncements and Accounting Changes for discussion of the impact of new accounting pronouncements adopted by Exelon. Reclassifications Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect net income or shareholders' equity. 2. Merger On October 20, 2000, Exelon became the parent corporation of PECO and ComEd as a result of the completion of the transactions contemplated by an Agreement and Plan of Exchange and Merger, as amended (Merger Agreement), among PECO, Unicom and Exelon. Pursuant to the Merger Agreement, Unicom merged with and into Exelon. In the Merger, each share of the outstanding common stock of Unicom was converted into 0.875 shares of common stock of Exelon plus $3.00 in cash. As a result of the Share Exchange, Exelon became the owner of all of the common stock of PECO. As a result of the Merger, Unicom ceased to exist and its subsidiaries, including ComEd, became subsidiaries of Exelon. 86 The Merger was accounted for using the purchase method of accounting. The total purchase price was $6,014 million. In connection with the Merger, Exelon issued 148 million shares of common stock in the amount of $5,310 million and paid $507 million in cash to Unicom shareholders pursuant to the terms of the Merger Agreement. The source of the cash consideration was borrowings under an Exelon term loan. In addition, the Merger consideration included $113 million of fair value of stock options and awards for certain Unicom employees and $84 million of direct acquisition costs. The cost in excess of net assets acquired was $5,150 million as adjusted to reflect final purchase price allocations. Exelon's results of operations include Unicom's results of operations since October 20, 2000. The fair value of the assets acquired, including the cost in excess of net assets acquired, and liabilities assumed in the Merger are as follows: - ------------------------------------------------------------------------------- Current Assets (including cash of $974) $ 2,744 Property, Plant and Equipment 7,641 Deferred Debits and Other Assets 5,535 Cost in excess of net assets acquired 5,150 Current Liabilities (2,390) Long-Term Debt (7,419) Deferred Credits and Other Liabilities (4,919) Preferred Securities of Subsidiaries (328) - ------------------------------------------------------------------------------- Total Purchase Price $ 6,014 - ------------------------------------------------------------------------------- Goodwill associated with the Merger increased by $14 million and $262 million in 2002 and 2001, respectively, as a result of the finalization of the purchase price allocation. The adjustment resulted primarily from the after-tax effects of the reduction of the regulatory asset for decommissioning retired nuclear plants, as discussed in Note 11 - Nuclear Decommissioning and Spent Fuel Storage, additional employee separation costs, the resolution of certain tax matters and the finalization of other purchase price allocations. Selected unaudited pro forma combined results of operations for the year ended December 31, 2000, assuming the Merger Transaction occurred on January 1, 2000 are presented as follows: (unaudited) 2000 - ------------------------------------------------------------------------------------------------------------------- Total revenues $ 13,531 Pro forma net income $ 1,003 Merger-related costs (net of income taxes of $147) 220 Cumulative effect of a change in accounting principle (net of income taxes of $16) 24 - ------------------------------------------------------------------------------------------------------------------- Pro forma net income before Merger-related costs and the cumulative effect of a change in accounting principle $ 1,247 - ------------------------------------------------------------------------------------------------------------------- Pro forma net income before Merger-related costs and the cumulative effect of a change in accounting principle per common share (diluted) $ 3.86 - ------------------------------------------------------------------------------------------------------------------- Pro forma information assumes the issuance of transition bonds in 2000 had occurred at the beginning of 2000. The pro forma financial information is not necessarily indicative of the operating results that would have occurred had the Merger been consummated as of the dates indicated, nor are they necessarily indicative of future operating results. 87 Merger-Related Costs In association with the Merger, Exelon recorded certain reserves for restructuring costs. The reserves associated with PECO were charged to expense pursuant to FASB Emerging Issues Task Force (EITF) Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)"; while the reserves associated with Unicom were recorded as part of the application of purchase accounting and did not affect results of operations, consistent with EITF Issue 95-3, "Recognition of Liabilities in Connection with a Purchase Business Combination." Merger costs charged to expense. PECO's merger-related costs charged to expense in 2000 were $248 million, consisting of $116 million for PECO employee costs and $132 million of direct incremental costs incurred by PECO in conjunction with the merger transaction. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fees, regulatory approval and settlement costs, and settlement of compensation arrangements. Employee costs represent estimated severance costs and pension and postretirement benefits provided under Exelon's merger separation plans for eligible employees who were expected to be involuntarily terminated before December 2002 due to integration activities of the merged companies. Additional employee severance costs of $48 million, primarily related to PECO employees, were charged to operating and maintenance expense in 2001, and a $10 million reduction in the estimated liability related to Generation employees was recorded in operating and maintenance expense in the first quarter of 2002. Employee costs are being paid from Exelon's pension and postretirement benefit plans, except for certain benefits such as outplacement services, continuation of health care coverage and educational benefits. As of December 31, 2002, a liability of $4 million is reflected on Exelon's consolidated balance sheet for payment of these benefits, of which $1 million is reflected on PECO's balance sheet and $1 million is reflected on Generation's balance sheet. A total of 960 PECO positions were expected to be eliminated as a result of the Merger, 274 of which related to generation, 230 of which related to PECO energy delivery and 456 of which related to enterprises and corporate support areas. As of December 31, 2002, 858 of the positions had been eliminated, of which 224 related to generation, 195 related to PECO energy delivery, and 439 to enterprises and corporate support. Of the remaining 102 positions, 58 were eliminated as a result of normal attrition and 44 positions will not be eliminated due to changes in certain business plans. Additionally, in the third quarter of 2000, approximately $20 million of closing costs and $8 million of stock compensation costs associated with Unicom were charged to expense. Merger costs included in purchase price allocation. The purchase price allocation as of December 31, 2000 included a liability of $307 million for Unicom employee costs and liabilities of approximately $39 million for estimated costs of exiting various business activities of former Unicom activities that were not compatible with the strategic business direction of Exelon. 88 During 2001, Exelon finalized plans for consolidation of functions, including negotiation of an agreement with the International Brotherhood of Electrical Workers Local 15 regarding severance benefits to union employees. In the third quarter of 2002, Exelon reduced its reserve by $12 million due to the elimination of identified positions through normal attrition, which did not require payments under Exelon's merger separation plans, and a determination that certain positions would not be eliminated by the end of 2002, as originally planned, due to a change in certain business plans. The reduction in the reserve was recorded as a purchase price adjustment to goodwill. In 2001 and 2002, Exelon recorded adjustments to the purchase price allocation as follows: Adjustments Original ------------------ Adjusted Estimate 2001 2002 Liabilities - ------------------------------------------------------------------------------------------------------------------- Employee severance payments $ 128 $ 33 $ (10) $ 151 (a) Other benefits 21 9 (2) 28 (a) - ------------------------------------------------------------------------------------------------------------------- Employee severance payments and other benefits 149 42 (12) 179 Actuarially determined pension and postretirement costs 158 (11) -- 147 (b) - ------------------------------------------------------------------------------------------------------------------- Total Unicom employee cost $ 307 $ 31 $ (12) $ 326 - ------------------------------------------------------------------------------------------------------------------- (a) The increase is a result of the identification in 2001 of additional positions to be eliminated, partially offset by the 2002 elimination of identified positions through normal attrition and changes in certain business plans. (b) The reduction results from lower estimated pension and postretirement welfare benefits reflecting revised actuarial estimates. The following table provides a reconciliation of the reserve for employee severance and other benefits associated with the Merger: - ------------------------------------------------------------------------------------------------------------------- Adjusted employee severance and other benefits reserve $ 179 Payments to employees in 2000 (5) Payments to employees in 2001 (72) Payments to employees in 2002 (74) - ------------------------------------------------------------------------------------------------------------------- Employee severance and other benefits reserve as of December 31, 2002 (1) $ 28 - ------------------------------------------------------------------------------------------------------------------- (1) Relates to certain benefits that are being paid after 2002. The following table provides a reconciliation of the former Unicom positions that were expected to be eliminated as a result of the Merger: Total - ------------------------------------------------------------------------------------------------------------------- Estimate at October 20, 2000 2,275 2001 adjustments (a) 118 - ------------------------------------------------------------------------------------------------------------------- Total positions 2,393 - ------------------------------------------------------------------------------------------------------------------- Employees terminated in 2000 279 Employees terminated in 2001 607 Employees terminated in 2002 1,053 Normal attrition 298 Business plan changes (b) 156 - ------------------------------------------------------------------------------------------------------------------- Total positions 2,393 - ------------------------------------------------------------------------------------------------------------------- (a) The increase is a result of the identification of additional positions to be eliminated in 2001. (b) The reduction is due to a determination in the third quarter of 2002, that certain positions would not be eliminated by the end of 2002 as originally planned due to a change in certain business plans. 89 3. Acquisitions and Dispositions Sithe New England Holdings Asset Acquisition On November 1, 2002, Generation purchased the assets of Sithe New England Holdings, LLC (Sithe New England), a subsidiary of Sithe, and related power marketing operations. Sithe New England's primary assets are gas-fired facilities currently under development. The purchase price for the Sithe New England assets consisted of a $534 million note to Sithe, $14 million of direct acquisition costs and an adjustment to Generation's investment in Sithe to reflect Sithe's sale of Sithe New England to Generation. Additionally, Generation will assume various Sithe guarantees related to an equity contribution agreement between Sithe New England and Sithe Boston Generation, LLC (SBG), a project subsidiary of Sithe New England. The equity contribution agreement requires, among other things, that Sithe New England, upon the occurrence of certain events, contribute up to $38 million of equity for the purpose of completing the construction of two generating facilities. SBG has a $1.25 billion credit facility (the SBG Facility) to finance the construction of these two generating facilities. The $1.0 billion outstanding under the facility at December 31, 2002 is reflected on Exelon's Consolidated Balance Sheet. Sithe New England owns 4,066 megawatts (MWs) of generation capacity, consisting of 1,645 MWs in operation and 2,421 MWs under construction. Sithe New England's generation facilities are located primarily in Massachusetts. The allocation of purchase price to the fair value of assets acquired and liabilities assumed in the acquisition is as follows: - ----------------------------------------------------------------------------- Current Assets (including $12 of cash acquired) $ 82 Property, Plant and Equipment 1,889 Deferred Debits and Other Assets 62 Current Liabilities (159) Deferred Credits and Other Liabilities (124) Long-Term Debt (1,036) - ----------------------------------------------------------------------------- Total Purchase Price $ 714 - ----------------------------------------------------------------------------- The SBG Facility provides that if these construction projects are not completed by June 12, 2003, the SBG Facility lenders will have the right, but will not be required, to, among other things, declare all amounts then outstanding under the SBG Facility and the interest rate swap agreements to be due. Generation believes that the construction projects will be substantially complete by May 31, 2003, but that all of the approvals required under the SBG Facility may not be issued by that date. Generation is currently evaluating whether the requirements of the SBG Facility relating to the construction projects can be satisfied by June 12, 2003. In the event that the requirements are not expected to be satisfied by June 12, 2003, Generation will contact the SBG Facility lenders concerning an amendment or waiver of these provisions of the SBG Facility. Generation currently expects that arrangements for such an amendment or waiver, if necessary, can be successfully negotiated with the SBG Facility lenders. See Note 19 - Commitments and Contingencies for further discussion of Sithe. 90 Acquisition of Generating Plants from TXU On April 25, 2002, Generation acquired two natural-gas and oil-fired plants from TXU Corp. (TXU) for an aggregate purchase price of $443 million. The purchase included the 893-megawatt Mountain Creek Steam Electric Station in Dallas and the 1,441-megawatt Handley Steam Electric Station in Fort Worth. The transaction included a purchased power agreement for TXU to purchase power during the months of May through September from 2002 through 2006. During the periods covered by the purchased power agreement, TXU will make fixed capacity payments, variable expense payments, and will provide fuel to Exelon in return for exclusive rights to the energy and capacity of the generation plants. Substantially all of the purchase price has been allocated to property, plant and equipment. Sale of AT&T Wireless On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285 million in cash. Enterprises recorded an after-tax gain of $116 million in Other Income and Deductions on Exelon's Consolidated Statements of Income on its $84 million investment, which had been reflected in Deferred Debits and Other Assets on Exelon's Consolidated Balance Sheets. InfraSource Acquisitions In 2001, Exelon's infrastructure services business (InfraSource), acquired the assets of a utility service contracting company for an aggregate purchase price of approximately $31 million. The acquisition was accounted for using the purchase method of accounting. The excess of purchase price over the fair value of net assets acquired was $19 million. The allocation of purchase price to the fair value of assets acquired and liabilities assumed in the acquisition is as follows: - ------------------------------------------------------------------------------ Current Assets (including cash acquired of $1) $ 11 Property, Plant and Equipment 11 Cost in excess of net assets acquired 19 Current Liabilities (10) - ------------------------------------------------------------------------------ Total $ 31 - ------------------------------------------------------------------------------ AmerGen Energy Company, LLC In August 2000, AmerGen, a joint venture with British Energy, Inc., a wholly owned subsidiary of British Energy plc, (British Energy), completed the purchase of Oyster Creek Nuclear Generating Facility (Oyster Creek) from GPU, Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU agreed to fund outage costs of $89 million, including the cost of fuel, for a refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU in equal annual installments through 2009. In addition, AmerGen assumed full responsibility for the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU provided funding for the decommissioning trust of $440 million. In conjunction with this acquisition, AmerGen has received a fully funded decommissioning trust fund which has been computed assuming the anticipated costs to appropriately decommission Oyster Creek discounted to net present value using the NRC's mandated rate of 2%. AmerGen believes that the amount of the trust fund and investment earnings thereon will be sufficient to meet its decommissioning obligation. GPU is purchasing the electricity generated by Oyster Creek pursuant to a three-year power purchase agreement. 4. Adoption of New Accounting Pronouncements and Accounting Changes SFAS No. 141 and SFAS No. 142 91 In 2001, FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141), which requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 became effective for business combinations initiated after June 30, 2001. In addition, SFAS No. 141 required that unamortized negative goodwill related to pre-July 1, 2001 purchases be recognized as a change in accounting principle concurrent with the adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). At December 31, 2001, AmerGen, an equity-method investee of Generation, had $43 million of negative goodwill, net of accumulated amortization, recorded on its balance sheet. Upon AmerGen's adoption of SFAS No. 141 in January 2002, Generation recognized its proportionate share of income of $22 million ($13 million, net of income taxes) as a cumulative effect of a change in accounting principle. Exelon adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. Other than goodwill, Exelon does not have significant other intangible assets recorded on its consolidated balance sheets. Under SFAS No. 142, goodwill is no longer subject to amortization; however, goodwill is subject to an assessment for impairment using a two-step fair value based test. The first step must be performed at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired and compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss is reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss is reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, Exelon's Consolidated Balance Sheets reflected approximately $5.3 billion in goodwill net of accumulated amortization, including $4.9 billion of net goodwill related to the Merger recorded on ComEd's Consolidated Balance Sheets, with the remainder related to Enterprises. The first step of the transitional impairment analysis indicated that ComEd's goodwill was not impaired but that an impairment did exist with respect to goodwill recorded in Enterprises' reporting units. InfraSource, the energy services business (Exelon Services) and the competitive retail energy sales business (Exelon Energy) were determined to be those reporting units of Enterprises that had goodwill allocated to them. The second step of the analysis, which compared the fair value of each of Enterprises' reporting units' goodwill to the carrying value at December 31, 2001, indicated a total goodwill impairment of $357 million ($243 million, net of income taxes and minority interest). The fair value of the Enterprises' reporting units was determined using discounted cash flow models reflecting the expected range of future cash flow outcomes related to each of the Enterprises reporting units over the life of the investment. These cash flows were discounted to 2002 using a risk-adjusted discount rate. The impairment was recorded as a cumulative effect of a change in accounting principle in the first quarter of 2002. The changes in the carrying amount of goodwill by reportable segment (see Note 20 - Segment Information) for the year ended December 31, 2002 are as follows: Energy Delivery Enterprises Total - ------------------------------------------------------------------------------------------------------------------- Balance as of January 1, 2002 $ 4,902 $ 433 $ 5,335 Impairment losses -- (357) (357) Resolution of certain tax matters 21 -- 21 Merger severance adjustment (7) -- (7) - ------------------------------------------------------------------------------------------------------------------- Balance as of December 31, 2002 $ 4,916 $ 76 $ 4,992 - ------------------------------------------------------------------------------------------------------------------- The December 31, 2002, Energy Delivery goodwill relates to ComEd and the remaining Enterprises goodwill relates to the InfraSource and Exelon Services reporting units. Consistent with 92 SFAS No. 142, the remaining goodwill will be reviewed for impairment on an annual basis, or more frequently if significant events occur that could indicate an impairment exists. ComEd and Enterprises performed an impairment review in the fourth quarter of 2002. Such review was consistent with the review conducted related to the implementation of SFAS No. 142, which required estimates of numerous items with varying degrees of uncertainty, such as discount rates, terminal value earnings multiples, future revenue levels and estimated future expenditure levels for ComEd and Enterprises; load growth and the resolution of future rate proceedings for ComEd; and customer base and construction back logs for Enterprises. These valuations determined the Step I calculated fair value of both ComEd and the Enterprises' units to be in excess of their respective book values at November 1, 2002. Significant changes from the assumptions used in the impairment review could possibly result in a future impairment loss. Illinois legislation provides that reductions to ComEd's common equity resulting from goodwill impairments will not impact ComEd's earnings through 2006 under the earnings provisions of the legislation. See Note 5 - Regulatory Issues for further discussion of ComEd's earnings provisions. The components of the net transitional impairment loss recognized in the first quarter of 2002 as a cumulative effect of a change in accounting principle are as follows: - ------------------------------------------------------------------------------------------------------------------- Enterprises goodwill impairment (net of income taxes of $103) $ (254) Minority interest (net of income taxes of $4) 11 Elimination of AmerGen negative goodwill (net of income taxes of $9) 13 - ------------------------------------------------------------------------------------------------------------------- Total cumulative effect of a change in accounting principle $ (230) - ------------------------------------------------------------------------------------------------------------------- The following tables set forth Exelon's net income and earnings per common share for 2002, 2001, and 2000 adjusted to exclude 2001 and 2000 amortization expense related to goodwill that is no longer being amortized. 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Reported income before cumulative effect of changes in accounting principles $ 1,670 $ 1,416 $ 562 Cumulative effect of changes in accounting principles (230) 12 24 - ------------------------------------------------------------------------------------------------------------------- Reported net income 1,440 1,428 586 Goodwill amortization -- 155 34 - ------------------------------------------------------------------------------------------------------------------- Adjusted net income $ 1,440 $ 1,583 $ 620 - ------------------------------------------------------------------------------------------------------------------- Basic earnings per common share: Reported income before cumulative effect of changes in accounting principles $ 5.18 $ 4.42 $ 2.79 Cumulative effect of changes in accounting principles (0.71) 0.04 0.12 - ------------------------------------------------------------------------------------------------------------------- Reported net income 4.47 4.46 2.91 Goodwill amortization -- 0.48 0.17 - ------------------------------------------------------------------------------------------------------------------- Adjusted net income $ 4.47 $ 4.94 $ 3.08 - ------------------------------------------------------------------------------------------------------------------- Diluted earnings per common share: Reported income before cumulative effect of changes in accounting principles $ 5.15 $ 4.39 $ 2.75 Cumulative effect of changes in accounting principles (0.71) 0.04 0.12 - ------------------------------------------------------------------------------------------------------------------- Reported net income 4.44 4.43 2.87 Goodwill amortization -- 0.48 0.17 - ------------------------------------------------------------------------------------------------------------------- Adjusted net income $ 4.44 $ 4.91 $ 3.04 - ------------------------------------------------------------------------------------------------------------------- 93 The cessation of the amortization of negative goodwill of AmerGen on January 1, 2002 did not have a material impact on Exelon's reported net income for 2002. EITF Issue 02-3 In the third quarter of 2002, Exelon and Generation adopted the provision of EITF Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-3) issued by the FASB EITF in June 2002 that requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement. Prior to the adoption, revenues from trading activity were presented in Revenue and the energy costs related to energy trading were presented as either Purchased Power or Fuel expense on Exelon and Generation's Consolidated Statements of Income. For comparative purposes, energy costs related to energy trading have been reclassified in prior periods to revenue to conform to the net basis of presentation required by EITF 02-3. Exelon commenced trading activities in April 2001, as such $207 million of purchased power expense and $15 million of fuel expense, respectively, was reclassified and reflected as a reduction to revenue for the year ended December 31, 2001. SFAS No. 144 In September 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Exelon adopted SFAS No. 144 on January 1, 2002. SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001 and its provisions are generally applied prospectively. The adoption of SFAS No. 144 had no effect on Exelon's reported financial position, results of operations or cash flows. SFAS No. 145 In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses from Extinguishment of Debt" and thus allows for only those gains or losses on the extinguishment of debt that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 145 also amends Statement of Financial Accounting Standards No. 13, "Accounting for Leases" to require sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The adoption of SFAS No. 145 required a reclassification of the 2000 extraordinary item of $4 million, net of income taxes, to interest expense; otherwise, it had no effect on Exelon's reported financial position or cash flows. SFAS No. 133 SFAS No. 133 applies to all derivative instruments and requires that such instruments be recorded on the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. On January 1, 2001, Exelon adopted SFAS No. 133. Generation recognized a non-cash gain of $12 million, net of income taxes, in earnings and deferred a non-cash gain of $4 million, net of income taxes, in accumulated other comprehensive income and PECO deferred a non-cash gain of $40 million, net of income taxes, in accumulated other comprehensive income. Nuclear Outage Costs During the fourth quarter of 2000, as a result of the synchronization of accounting policies with Unicom in connection with the Merger, PECO changed its method of accounting for nuclear outage costs to record such costs as incurred. Previously, PECO accrued these costs over the operating unit cycle. As a result of the change in accounting method for nuclear outage costs, PECO recorded income of $24 94 million, net of income taxes of $16 million. The change is reported as a cumulative effect of a change in accounting principle on the Consolidated Statements of Income as of December 31, 2000, representing the balance of the nuclear outage cost reserve at January 1, 2000. SFAS No. 148 In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation and requires disclosures in both annual and interim financial statements regarding the method of accounting for stock-based compensation and the effect of the method on financial results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. As of December 31, 2002, Exelon has adopted the additional disclosure requirements of SFAS No. 148 and continues to account for its stock-compensation plans under the disclosure only provision of SFAS No. 123. Changes in Accounting Estimates Effective July 1, 2002, ComEd decreased its depreciation rates based on a new depreciation study reflecting its significant construction program in recent years, changes in and development of new technologies, and changes in estimated plant service lives since the last depreciation study. The annualized reduction in depreciation expense, based on December 31, 2001 plant balances, is estimated to be approximately $100 million ($60 million, net of income taxes). As a result of the change, net income for 2002 increased approximately $48 million ($29 million, net of income taxes). Effective April 1, 2001, Generation changed its accounting estimates related to the depreciation and decommissioning of certain generating stations. The estimated service lives were extended by 20 years for three nuclear stations, by periods of up to 20 years for certain fossil stations and by 50 years for a pumped storage station. Effective July 1, 2001, the estimated service lives were extended by 20 years for the remainder of Exelon's operating nuclear stations. These changes were based on engineering and economic feasibility studies performed by Generation considering, among other things, future capital and maintenance expenditures at these plants. The service life extension is subject to Nuclear Regulatory Commission (NRC) approval of an extension of existing NRC operating licenses, which are generally 40 years. The estimated annualized reduction in expense from the change is $132 million ($79 million, net of income taxes). In April 2002, ComEd changed its accounting estimate related to the allowance for uncollectible accounts based on an independently prepared evaluation of the risk profile of ComEd's customer accounts receivable. As a result of the new evaluation, the allowance for uncollectible accounts reserve was reduced by $11 million in the second quarter of 2002. In December 2002, PECO changed its accounting estimate related to the allowance for uncollectible accounts based on an independently prepared evaluation of the risk profile of PECO's customer accounts receivable. As a result of the new evaluation, the allowance for uncollectible accounts reserve was reduced by $17 million in the fourth quarter of 2002. In 2002, Generation increased its allowance for uncollectible accounts by $6 million based on an independently prepared evaluation of the risk profile of Power Team's counterparties. Power Team is the unit within Generation that manages the output of Generation's assets and energy sales to reduce the volatility of Generation's earnings and cash flows. 5. Regulatory Issues ComEd 95 Delivery Service Rates. On June 1, 2001, ComEd filed with the ICC to establish delivery service charges for residential customers in preparation for residential customer choice, which began in May 2002. ComEd is authorized to charge customers who purchase electricity from an alternative supplier for the use of its distribution system to deliver that electricity. These delivery service rates are set through proceedings before the ICC based upon, among other things, the operating costs associated with ComEd's distribution system and the capital investment that ComEd has made in its distribution system. On April 1, 2002, the ICC issued an interim order in ComEd's Delivery Services Rate Case. The interim order is subject to an audit of test year (2000) expenditures, including capital plant expenditures, with a final order to be issued in 2003. The order sets delivery rates for residential customers choosing a new retail electric supplier. The new rates became effective May 1, 2002 when residential customers became eligible to choose their supplier of electricity. Traditional bundled rates paid by customers that retain ComEd as their electricity supplier are not affected by this order. Bundled rates will remain frozen through 2006, as a result of the June 6, 2002 amendments to the Illinois Restructuring Act that extended the freeze on bundled rates for an additional two years. Delivery service rates for non-residential customers are not affected by the order. In October 2002, the ICC received the report on the audit of the test year expenditures by a consulting firm engaged by the ICC to perform the audit. The consulting firm recommended certain additional disallowances to test year expenditures and rate base levels. ComEd does not expect this matter to have a significant impact on results of operations in 2003, however, the estimated potential investment write-off, before income taxes, could be up to approximately $100 million, if the ICC ultimately determines that all or some portion of ComEd's distribution plant is not recoverable through rates. In 2002, ComEd recorded a charge to earnings, before income taxes, of $12 million representing the estimated minimum probable exposure pursuant to SFAS No. 90, "Regulated Enterprises - Accounting for Abandonments and Disallowances of Plant Costs an Amendment of FASB Statement No. 71." ComEd is in negotiations with several parties to resolve the delivery service case. Customer Choice. As of December 31, 2002, all ComEd's customers were eligible to choose an alternative electric supplier and non-residential customers can also elect the power purchase option (PPO) that allows the purchase of electric energy from ComEd at market-based prices. ComEd's residential customers became eligible to choose a new electric supplier in May 2002. However, as of December 31, 2002, no alternative supplier had sought approval from the ICC and no electric utilities have chosen to enter the ComEd residential market for the supply of electricity. As of December 31, 2002, approximately 22,700 non-residential customers, representing approximately 26% of ComEd's annual retail kilowatt-hour sales, had elected to purchase their electric energy from an alternate electric supplier or had chosen the power purchase option. Customers who receive energy from an alternative supplier continue to pay a delivery charge. ComEd is unable to predict the long-term impact of customer choice on results of operations. Rate Reductions and Return on Common Equity Threshold. The Illinois restructuring legislation provided a 15% residential base rate reduction effective August 1, 1998 with an additional 5% residential base rate reduction effective October 1, 2001. ComEd's operating revenues were reduced by approximately $99 million and $24 million in 2002 and 2001, respectively due to the 5% residential rate reduction. Notwithstanding the rate reductions and subject to certain earnings tests, a rate freeze is generally in effect until at least January 1, 2007. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility's financial viability. Under the Illinois legislation, if the earned return on common equity of a utility during this period exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on the Monthly Treasury Bond Long-Term Average (25 years and above). Earnings for purposes of ComEd's threshold include ComEd's net income calculated in accordance with GAAP and 96 reflect the amortization of regulatory assets and goodwill. As a result of the Illinois legislation, at December 31, 2002, ComEd had a regulatory asset with an unamortized balance of $175 million that it expects to fully recover and amortize by the end of 2006. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The earned return on common equity and the threshold return on common equity for ComEd are each calculated on a two-year average basis. ComEd did not trigger the earnings sharing provision in 2002, 2001 or 2000 and does not currently expect to trigger the earnings sharing provisions in the years 2003 through 2006. PECO Revenue Neutral Reconciliation Adjustment. As permitted by the Pennsylvania Electric Competition Act, the Pennsylvania Department of Revenue calculated a 2002 Revenue Neutral Reconciliation (RNR) adjustment to the gross receipts tax rate in order to neutralize the impact of electric restructuring on its tax revenues. In January 2002, the PUC approved the RNR adjustment to the gross receipts tax rate collected from customers. Effective January 1, 2002, PECO implemented the change in the gross receipts tax rate. The RNR adjustment increases the gross receipts tax rate, which increased PECO's annual revenues and tax obligations by approximately $50 million in 2002. The RNR adjustment was appealed. The case was remanded to the PUC and in August 2002, the PUC ruled that PECO is properly authorized to recover these costs. In December 2002, the PUC approved the inclusion of the RNR factor in PECO's base rates eliminating the need for an annual filing to obtain approval for recovery. Customer Choice. The PUC's Final Electric Restructuring Order provided for the phase-in of customer choice of electric generation suppliers (EGS) and as of January 1, 2000, all customers were eligible for customer choice. The Final Restructuring Order also established market share thresholds (MST) to promote competition. The MST requirements provided that, if as of January 1, 2001 and January 1, 2003, respectively, less than 35% and 50% of residential and commercial customers were shopping, the number of customers sufficient to meet the MST shall be randomly selected and assigned to an EGS through a PUC-determined process. For residential and small commercial customers, the threshold measurement is by number of customers. For large commercial customers the measurement is by load. On January 1, 2001, the 35% MST threshold was met for all customer classes as a result of agreements assigning customers to New Power Company (New Power) and Green Mountain as providers of last resort default service. During 2002, PECO experienced an increase in the number of customers selecting or returning to PECO as their EGS and at December 31, 2002, approximately 21% of PECO's residential load, 10% of its small commercial and industrial load and 7% of its large commercial and industrial load were purchasing generation from an alternative generation supplier. Customers who purchase energy from an EGS continue to pay a delivery charge. In January 2003, PECO submitted to the PUC an MST plan to meet the 50% threshold requirement for its small and large commercial customer classes, which was approved on February 6, 2003. According to the approved plan, randomly assigned customers who participated will be switched to winning MST bidders as of their respective meter read dates. Also in February 2003, PECO filed an MST plan for the residential customer classes which is pending PUC approval. In February 2002, New Power notified PECO of its intent to withdraw from providing Competitive Default Service (CDS) to approximately 180,000 residential customers. As a result of that withdrawal, those CDS customers were returned to PECO in the second quarter of 2002. Pursuant to a tariff filing approved by the PUC, PECO is serving those returned customers at the discount energy rates on generation provided for under the original New Power CDS Agreement for the remaining term of that contract. Subsequently, in the second quarter of 2002, New Power also advised PECO it planned to 97 withdraw from serving all of its customers in Pennsylvania, including approximately 15,000 non-CDS PECO customers. These customers were returned to PECO during the third quarter of 2002. Rate Reductions and Caps. Under the Final Restructuring Order, retail electric rates were capped at year-end 1996 levels (system-wide average of 9.96 cents/kilowatt hour (kWh)) through June 2005. The Final Restructuring Order required PECO to reduce its retail electric rates by 8% from the 1996 system-wide average rate on January 1, 1999. This rate reduction decreased to 6% on January 1, 2000 until January 1, 2001. The transmission and distribution rate component was capped at a system-wide average rate of 2.98 cents/kWh through June 30, 2005. Additionally, generation rate caps, defined as the sum of the applicable transition charge and energy and capacity charge, will remain in effect through 2010. On March 16, 2000, the PUC issued an order authorizing PECO to securitize up to an additional $1 billion of its authorized stranded costs recovery. In accordance with the terms of that order, PECO provided its retail customers with rate reductions of $60 million for calendar year 2001 only. Under a comprehensive settlement agreement in connection with achieving regulatory approval of the Merger, PECO agreed to $200 million in aggregate rate reductions for all customers in Pennsylvania over the period January 1, 2002 through 2005 and extended the rate caps on PECO's retail electric distribution charges through December 31, 2006. 6. Supplemental Financial Information Supplemental Income Statement Information For the Years Ended December 31, ------------------------------------------------ 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Taxes Other Than Income Utility (a) $ 412 $ 342 $ 196 Real estate 149 140 68 Payroll 98 88 41 Other 50 53 17 - ------------------------------------------------------------------------------------------------------------------- Total $ 709 $ 623 $ 322 - ------------------------------------------------------------------------------------------------------------------- Other, Net Investment income $ 130 $ 47 $ 64 Gain (loss) on disposition of assets, net 199 4 (19) Write-down of impaired investments (41) (36) -- AFUDC, equity and borrowed 19 18 3 Reserve for potential plant disallowance (12) -- -- Settlement of power purchase agreement -- -- 6 Other 5 46 (1) - ------------------------------------------------------------------------------------------------------------------- Total $ 300 $ 79 $ 53 - ------------------------------------------------------------------------------------------------------------------- (a) Municipal and state utility taxes are also recorded in Revenues on Exelon's Consolidated Statements of Income. 98 Supplemental Cash Flow Information For the Years Ended December 31, ------------------------------------------------ 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Cash paid during the year: Interest (net of amount capitalized) $ 905 $ 963 $ 519 Income taxes (net of refunds) $ 614 $ 749 $ 272 Non-cash investing and financing activities: Regulatory Asset Fair Value Adjustment $ -- $ 347 $ -- Resolution of Certain Tax Matters and Merger Severance Adjustment 14 -- -- Purchase Accounting Estimate Adjustments -- (85) -- Issuance of Exelon Shares for Unicom -- -- 5,310 Capital Lease Obligations 52 -- -- Issuance of InfraSource Stock -- 35 14 Contribution of Land from Minority Interest of Consolidated Subsidiary 12 -- -- Note Issued to Sithe in the Sithe New England Acquisition 534 -- -- Depreciation and amortization: Property, plant and equipment $ 729 $ 697 $ 325 Regulatory assets 472 445 53 Nuclear fuel 374 393 149 Decommissioning 126 144 46 Goodwill -- 155 34 - ------------------------------------------------------------------------------------------------------------------- Total Depreciation and Amortization $ 1,701 $ 1,834 $ 607 - ------------------------------------------------------------------------------------------------------------------- Supplemental Balance Sheet Information December 31, ----------------------------------- 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Investments Investment in Sithe $ 478 $ 700 Direct financing leases 445 427 Energy services and other ventures 167 161 Investment in AmerGen 160 95 Affordable housing projects 88 98 Communication ventures 39 116 Investment in subsidiaries and joint ventures 16 26 - ------------------------------------------------------------------------------------------------------------------- Total $ 1,393 $ 1,623 - ------------------------------------------------------------------------------------------------------------------- 99 Prior to the Merger, Unicom entered into a like-kind exchange transaction pursuant to which approximately $1.6 billion was invested in passive generating station leases with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. For financial accounting purposes, the investments are accounted for as direct financing lease investments. Unicom Investments, Inc. holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. Under the terms of the lease agreements, Exelon received a prepayment of $1.2 billion in the fourth quarter of 2000, which reduced the investment in the lease. The remaining payments are payable at the end of the thirty year lease and there are no minimum scheduled lease payments to be received over the next five years. The components of the net investment in the direct financing leases are as follows: December 31, ----------------------------------- 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Total minimum lease payments $ 1,492 $ 1,492 Less: Unearned income 1,047 1,065 - ------------------------------------------------------------------------------------------------------------------- Net investment in direct financing leases $ 445 $ 427 - ------------------------------------------------------------------------------------------------------------------- December 31, ----------------------------------- 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Regulatory Assets Competitive transition charge $ 4,639 $ 4,947 Recoverable deferred income taxes (see Note 14) 661 701 Nuclear decommissioning costs for retired plants 248 310 Recoverable transition costs 175 277 Reacquired debt costs and interest rate swap settlements 137 112 Non-pension postretirement benefits 65 71 Compensated absences 6 5 Other 7 -- - ------------------------------------------------------------------------------------------------------------------- Long-Term Regulatory Assets 5,938 6,423 Deferred energy costs (current asset) 31 56 - ------------------------------------------------------------------------------------------------------------------- Total $ 5,969 $ 6,479 - ------------------------------------------------------------------------------------------------------------------- o Competitive Transition Charges (CTC) represent PECO's stranded costs that the PUC determined would be allowed to be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The unamortized balance of the CTC of $4.6 billion and $4.9 billion as of December 31, 2002 and 2001, respectively, was recorded on our Consolidated Balance Sheets. The CTC includes Intangible Transition Property sold to PECO Energy Transition Trust, a wholly owned subsidiary of PECO, in connection with the securitization of PECO's stranded cost recovery. These charges are being amortized through December 31, 2010 with a return on the unamortized balance of 10.75%. o Nuclear decommissioning costs for retired plants - recovery is provided through ComEd's current regulated rates and is expected to be fully recovered by the end of 2006. o Recoverable transition costs - recovery is provided for in regulated rates pursuant to the Illinois Restructuring Act and is expected to be recovered by the end of 2006. o Reacquired debt costs and interest rate swap settlements - recoverable gains and losses on reacquired debt are deferred and amortized over the rate-regulatory period, which is over the life of the new debt issued to finance the debt redemption. Interest rate swap settlements are deferred and amortized over the period that the related debt is outstanding. 100 The regulatory assets related to the nuclear decommissioning costs and deferred income taxes did not require a cash outlay of investor supplied funds; consequently, these costs are not earning a rate of return. Recovery of the regulatory assets for loss on reacquired debt and recoverable transition costs is provided for through regulated revenue sources that are based on the pre-open access cost of service. Therefore, they are earning a rate of return. December 31, ----------------------------------- 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Accrued Expenses Taxes Accrued $ 420 $ 91 Interest Accrued 307 299 Other Accrued Expenses 584 745 - ------------------------------------------------------------------------------------------------------------------- Total $ 1,311 $ 1,135 - ------------------------------------------------------------------------------------------------------------------- 7. Earnings Per Share Diluted earnings per share are calculated by dividing net income by the weighted average shares of common stock outstanding including shares issuable upon exercise of stock options outstanding under Exelon's stock option plans considered to be common stock equivalents. The following table shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share (in millions): 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Average Common Shares Outstanding 322 320 202 Assumed Exercise of Stock Options 3 2 2 - ------------------------------------------------------------------------------------------------------------------- Average Dilutive Common Shares Outstanding 325 322 204 - ------------------------------------------------------------------------------------------------------------------- Stock options not included in average common shares used in calculating diluted earnings per share due to their antidilutive effect were approximately five million, five million and 30,000 for 2002, 2001 and 2000, respectively. 8. Accounts Receivable Accounts Receivable -- Customer at December 31, 2002 and 2001 included unbilled operating revenues of $442 million and $438 million, respectively. The allowance for uncollectible accounts at December 31, 2002 and 2001 was $132 million and $213 million, respectively. PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. At December 31, 2002, PECO had sold a $225 million interest in accounts receivable, consisting of a $164 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - a Replacement of FASB Statement No. 125," and a $61 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable (see Note 13 - Long-Term Debt). PECO retains the servicing responsibility for these receivables. The agreement requires PECO to maintain the $225 million interest, which, if not met, requires cash, which would otherwise be received by PECO under this program, to be held in escrow until the requirement is met. At December 31, 2002 and 2001, PECO met this requirement and was not required to make any cash deposits. 101 9. Property, Plant, and Equipment A summary of property, plant and equipment by classification as of December 31, 2002 and 2001 is as follows: Asset Category 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Electric-Transmission and Distribution $ 10,980 $ 10,156 Electric-Generation 5,678 4,344 Gas 1,319 1,281 Common 404 399 Nuclear Fuel 3,112 2,681 Construction Work in Progress 2,783 1,294 Other Property, Plant and Equipment 1,628 1,371 - ------------------------------------------------------------------------------------------------------------------- Total Property, Plant and Equipment 25,904 21,526 Less Accumulated Depreciation (including accumulated amortization of nuclear fuel of $2,212 and $1,838 as of December 31, 2002 and 2001, respectively) 8,770 7,735 - ------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment, net $ 17,134 $13,791 - ------------------------------------------------------------------------------------------------------------------- 10. Jointly Owned Electric Utility Plant Exelon's undivided ownership interests in jointly owned electric plant at December 31, 2002 and 2001 were as follows: Production Plant ------------------------------------------------------------------------- Transmission December 31, 2002 Peach Bottom Salem Keystone Conemaugh Quad Cities and Other Plant - --------------------------------------------------------------------------------------------------------------------- Operator Generation PSE&G Reliant Reliant Generation Various Co. Participating Interest 50% 42.59% 20.99% 20.72% 75% 21 to 44% Exelon's Share: Plant $ 417 $ 44 $ 131 $ 214 $ 171 $ 58 Accumulated Depreciation 243 12 117 145 4 22 Construction Work in Progress 52 36 28 1 35 -- - --------------------------------------------------------------------------------------------------------------------- 102 Production Plant ------------------------------------------------------------------------- Transmission December 31, 2001 Peach Bottom Salem Keystone Conemaugh Quad Cities and Other Plant - ---------------------------------------------------------------------------------------------------------------------- Operator Generation PSE&G Reliant Reliant Generation Various Co. Participating Interest 50% 42.59% 20.99% 20.72% 75% 21 to 44% Exelon's Share: Plant $ 387 $ 12 $ 121 $ 193 $ 96 $ 66 Accumulated Depreciation 220 4 98 124 10 25 Construction Work in Progress 13 53 13 12 52 1 - --------------------------------------------------------------------------------------------------------------------- Exelon's undivided ownership interests are financed with Exelon funds and, when placed in service, all operations are accounted for as if such participating interests were wholly owned facilities. Direct expenses of the jointly owned plants are included in the corresponding operating expenses on the Consolidated Income Statements. 11. Nuclear Decommissioning and Spent Fuel Storage Exelon has an obligation to decommission its nuclear power plants. Exelon's current estimate of its nuclear facilities' decommissioning cost for its owned nuclear power plants is $7.4 billion in current year (2003) dollars. Based on the extended license lives of the nuclear plants, expenditures are expected to occur primarily when the operating plants are decommissioned, during the period 2029 through 2056. Decommissioning costs are currently recoverable through regulated rates. Under rates in effect through December 31, 2002, Exelon collected approximately $102 million in 2002 from customers. At December 31, 2002, the decommissioning liability, recorded in Accumulated Depreciation and Deferred Credits and Other Liabilities on Exelon's Consolidated Balance Sheets, was $2.8 billion and $1.4 billion, respectively. At December 31, 2001, the decommissioning liability, recorded in Accumulated Depreciation and Deferred Credits and Other Liabilities on Exelon's Consolidated Balance Sheets, was $2.7 billion and $1.4 billion, respectively. In order to fund future decommissioning costs, at December 31, 2002 and 2001, Exelon held $3.1 billion and $3.2 billion, respectively, in trust accounts that are included as Investments in Exelon's Consolidated Balance Sheets at their fair market value. Exelon believes that the amounts being recovered from customers through regulated rates and earnings on nuclear decommissioning trust funds will be sufficient to fully fund its decommissioning obligations. In connection with the transfer of ComEd's nuclear generating stations to Generation, ComEd asked the ICC to approve the continued recovery of decommissioning costs after the transfer. On December 20, 2000, the ICC issued an order finding that the ICC has the legal authority to permit ComEd to continue to recover decommissioning costs from customers for the six-year term of the power purchase agreements between ComEd and Generation. Under the ICC order, ComEd is permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from Generation. Under the ICC order, subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to customers. The amount of recovery in the ICC order is less than the $84 million annual amount ComEd recovered in 2000. The ICC order has been upheld on appeal in the Illinois Appellate Court and the Illinois Supreme Court has declined to review the Appellate Court's decision. To account for the effects of the ICC order, in the first quarter of 2001 ComEd reduced its nuclear decommissioning regulatory asset to $372 million, reflecting the reduction in expected probable future recoveries from customers through 2006. The reduction in the regulatory asset in the amount of $347 million was recorded as an adjustment to the initial Merger purchase price allocation and resulted in a corresponding increase in goodwill. Also, ComEd recorded an obligation to Generation of approximately 103 $440 million representing ComEd's legal requirement to remit funds to Generation for the remaining regulatory asset amount of $372 million upon collection from customers, and for collections from customers prior to the establishment of external decommissioning trust funds in 1989 to be remitted to Generation for deposit into the decommissioning trusts through 2006. Unrealized gains and losses on decommissioning trust funds (based on the market value of the assets on the Merger date, in accordance with purchase accounting) had previously been recorded in accumulated depreciation or regulatory assets. As a result of the transfer of the ComEd nuclear plants to Generation and the ICC order limiting the regulated recoveries of decommissioning costs, net unrealized losses of $23 million (net of income taxes) at that date were reclassified to accumulated other comprehensive income. All subsequent realized gains and losses on these decommissioning trust funds' assets are based on the cost basis of the trust fund assets established on the Merger date and are reflected in Other Income and Deductions in Exelon's Consolidated Statements of Income. Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be recovered currently through rates charged by PECO to regulated customers. These amounts are remitted to Generation as allowed by the PUC. Under an agreement effective September 2001, PECO remits $29 million per year to Generation related to nuclear decommissioning cost recovery. On December 31, 2002, PECO filed with the PUC for an annual increase in its decommissioning cost recovery of $20 million effective June 1, 2004. The filing is consistent with provisions in the Restructuring Settlement and the Merger Settlement which require PECO to update the cost of decommissioning every five years. The additional amount requested is expected to be reduced as it does not reflect pending life extensions at Peach Bottom. The approval of the life extensions is expected by mid-2003. Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel (SNF) and high-level radioactive waste. ComEd and PECO, as required by the NWPA, each signed contracts with the DOE (Standard Contract) to provide for disposal of SNF from their respective nuclear generating stations. In accordance with the NWPA and the Standard Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatt-hour of net nuclear generation for the cost of nuclear fuel long-term storage and disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contract required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE's current estimate for opening a SNF facility is 2010. This extended delay in SNF acceptance by the DOE has led to Exelon's adoption of dry storage at its Dresden, Quad Cities and Peach Bottom Units and its consideration of dry storage at other units. In July 1998, ComEd filed a complaint against the United States Government (Government) in the United States Court of Federal Claims (Court) seeking to recover damages caused by the DOE's failure to honor its contractual obligation to begin disposing of SNF in January 1998. In August 2001, the Court granted ComEd's motion for partial summary judgment for liability on ComEd's breach of contract claim. In November 2001, the Government filed two partial summary judgment motions relating to certain damage issues in the case as well as two motions to dismiss claims other than ComEd's breach of contract claim. On August 30, 2002, after taking certain damages related to discovery, ComEd filed briefs in response to the DOE's motions. The Court has postponed the time for the DOE to file reply briefs while it entertains additional DOE discovery motions. This litigation was assumed by Generation in the corporate restructuring. In July 2000, PECO entered into an agreement with the DOE relating to PECO's Peach Bottom nuclear generating unit to address the DOE's failure to begin removal of SNF in January 1998 as required by the Standard Contract. Under that agreement, the DOE agreed to provide PECO with credits against PECO's future contributions to the Nuclear Waste Fund over the next ten years to compensate PECO for SNF storage costs incurred as a result of the DOE's breach of the contract. The agreement also provides 104 that, upon PECO's request, the DOE will take title to the SNF and the interim storage facility at Peach Bottom provided certain conditions are met. Generation assumed this contract in restructuring. In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the agreement providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case, and Generation assumed the claim in the 2001 corporate restructuring. On September 24, 2002, the United States Court of Appeals for the Eleventh Circuit ruled that the fee adjustment provision of the agreement violates the NWPA and therefore is null and void. The Court did not hold that the agreement as a whole is invalid. Article XVI(I) of the Amendment provides that if any portion of the Amendment is found to be void, the DOE and Generation agree to negotiate in good faith and attempt to reach an enforceable agreement consistent with the spirit and purpose of this Amendment. That provision further provides that should a major term be declared void, and the DOE and Generation cannot reach a subsequent agreement, the entire Amendment would be rendered null and void, the original Peach Bottom Standard Contract would remain in effect and the parties would return to pre-Amendment status. Pursuant to Article XIV(I), Generation has begun negotiations with the DOE and those negotiations are ongoing. Under the agreement, Generation has received approximately $40 million in credits against contributions to the nuclear waste fund. In April 2001, an individual filed suit against the DOE with the United States District Court for the Middle District of Pennsylvania seeking to invalidate the agreement on the grounds that the DOE has violated the National Environmental Policy Act and the Administrative Procedure Act. PECO intervened as a defendant and moved to dismiss the complaint. Generation assumed the defense in restructuring. On September 30, 2002, the Court granted Generation's motion and dismissed the lawsuit on the ground that the Court did not have jurisdiction over the matter. The Standard Contract with the DOE also requires that PECO and ComEd pay the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO's fee has been paid. Pursuant to the Standard Contract, ComEd elected to pay the one-time fee of $277 million, with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2002, the unfunded liability for the one-time fee with interest was $858 million. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the corporate restructuring. 12. Notes Payable 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Average borrowings $ 337 $ 193 $ 186 Average interest rates, computed on daily basis 1.94% 4.01% 6.62% Maximum borrowings outstanding $ 783 $ 599 $ 500 Average interest rates, at December 31 1.88% 2.63% 7.18% - ------------------------------------------------------------------------------------------------------------------- Exelon, ComEd, PECO and Generation entered into a $1.5 billion unsecured revolving credit facility on November 22, 2002 with a group of banks. Under the credit facility, each borrower may borrow up to a designated sublimit amount on a revolving credit basis through November 20, 2003. This credit facility includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. This credit facility is used principally to support the commercial paper programs of Exelon, ComEd, PECO and Generation. At December 31, 2002, the amount of commercial paper outstanding was $681 million which does not include $267 million that has been classified as long-term debt. At December 31, 2001, the amount of commercial paper outstanding was $360 million. Interest rates on the advances under the credit facility are based on the London Interbank Offering Rate (LIBOR) as of the date of the advance. 105 13. Long-Term Debt December 31, ------------------------------------------------------------ Maturity Rates Date 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Securitized Long-Term Debt ComEd Transitional Trust Notes Series 1998-A: 5.39%-5.74% 2003-2008 $ 2,040 $ 2,380 PETT Bonds Series 1999-A: Fixed rates 5.63%-6.13% 2003-2008 (a) 2,426 2,577 Floating rates 1.48%-1.55% 2004-2007 (a) 274 310 PETT Bonds Series 2000-A: 7.63%-7.65% 2009 (a) 750 890 PETT Bonds Series 2001: 6.52% 2010 (a) 805 805 Other Long-Term Debt First and Refunding Mortgage Bonds (b) (c): Fixed rates 4.4%-9.875% 2003-2023 3,614 3,942 Floating rates 1.08%-1.41% 2012-2013 254 154 Notes payable and other 6.40%-9.20% 2003-2020 2,393 2,651 SBG Facility 6.37%(d) 2007 1,036 -- Pollution control notes: Fixed rates 5.2%-6.95% 2007-2034 199 44 Floating rates 1.05%-1.50% 2009-2034 456 583 Notes payable - accounts receivable agreement 1.42% 2005 61 55 Sinking fund debentures 3.125%-4.75% 2004-2011 20 23 Commercial Paper (e) 1.88% (f) 2003 267 -- - ------------------------------------------------------------------------------------------------------------------- Total Long-Term Debt (g) 14,595 14,414 Unamortized debt discount and premium, net (107) (129) Fair value hedge carrying value adjustment 41 -- Due within one year (1,402) (1,406) - ------------------------------------------------------------------------------------------------------------------- Long-Term Debt $ 13,127 $ 12,879 - ------------------------------------------------------------------------------------------------------------------- (a) The maturity date represents the expected final payment date which is the date when all principal and interest of the related class of transition bonds is expected to be paid in full in accordance with the expected amortization schedule for the applicable class. The date when all principal and interest must be paid in full for the PETT Bonds Series 1999-A, 2000-A and 2001-A are 2003 through 2009, 2010 and 2010, respectively. The current portion of transition bonds is based upon the expected maturity date. (b) Utility plant of ComEd and PECO is subject to the liens of their respective mortgage indentures. (c) Includes first mortgage bonds issued under the ComEd and PECO mortgage indentures securing pollution control notes. (d) The rate for the SBG Facility is stated as an average rate. Under the terms of the SBG Facility, SBG is required to effectively fix the interest rate on 50% of the borrowings under the facility through its maturity in 2007. The SBG Facility is subject to a variable rate based on the LIBOR rate plus a margin of 1.375%, however, through the required interest rate swaps, SBG has effectively fixed the LIBOR component of the interest rate at 5.73% on 83% of the debt balance as of December 31, 2002. (e) Classified as long-term at December 31, 2002 since it was refinanced with long-term debt in January 2003. (f) Average interest rate of commercial paper outstanding at December 31, 2002. (g) Long-term debt maturities in the period 2003 through 2007 and thereafter are as follows: 2003 $ 1,669 2004 962 2005 1,313 2006 1,273 2007 1,172 Thereafter 8,206 ----------------- Total $14,595 ----------------- 2003 maturities include $267 million of commercial paper classified as long-term debt (see Note 23 - Subsequent Events). 106 In 2002, ComEd issued $700 million of long-term debt primarily consisting of the issuance of $600 million of 6.15% First Mortgage Bonds, Series 98, due March 15, 2012 and the issuance of $100 million of Illinois Development Finance Authority floating-rate Pollution Control Revenue Refunding Bonds, Series 2002 due April 15, 2013. In 2002, ComEd redeemed or paid at maturity $1,540 million of long-term debt primarily consisting of the redemption of $100 million of 7.25% Illinois Development Finance Authority Pollution Control Revenue Refunding Bonds, Series 1991 due June 1, 2011, the redemption of $200 million of 8.625% First Mortgage Bonds, Series 81, due February 1, 2022, the redemption of $200 million of 8.5% First Mortgage Bonds, Series 84 due July 15, 2022, the payment at maturity of $200 million of 7.375% First Mortgage Bonds, Series 85, due September 15, 2002, the redemption of $200 million of 8.375% First Mortgage Bonds, Series 86, due September 15, 2022, the payment at maturity of $200 million of variable rate senior notes due September 30, 2002, the payment at maturity of $100 million of 9.17% medium-term notes due October 15, 2002, and the retirement of $340 million in transitional trust notes. In 2002, Generation exchanged $700 million of 6.95% Senior Notes issued in 2001 for notes which are registered under the Securities Act. ComEd exchanged $600 million of 6.15% First Mortgage Bonds, Series 98, due March 15, 2012, for bonds which are registered under the Securities Act. PECO exchanged $250 million of 5.95% private placement First and Refunding Mortgage Bonds, due November 1, 2011, for bonds which are registered under the Securities Act. The exchange bonds are identical to the outstanding bonds except for the elimination of certain transfer restrictions and registration rights pertaining to the outstanding bonds. ComEd, PECO and Generation did not receive any cash proceeds from issuance of the exchange bonds. In 2002 and 2001, ComEd entered into forward starting interest rate swaps with an aggregate notional amount of $830 million and $250 million, respectively, to manage interest rate exposure associated with anticipated debt issuance. In 2002, forward starting interest rate swaps with an aggregate notional amount of $450 million were settled with net proceeds to counterparties of $10 million that has been deferred in regulatory assets and is being amortized over the life of the First Mortgage Bonds as an increase to interest expense. In 2002 and 2001, ComEd entered into interest rate swap agreements with a notional amount of $250 million and $235 million, respectively, to effectively convert fixed rate debt to floating rate debt. In 2002, PECO issued $225 million of 4.75% First and Refunding Mortgage Bonds, due October 1, 2012. This bond issuance repaid commercial paper that was used to pay $222 million of First and Refunding Mortgage Bonds at maturity with a weighted average interest rate of 7.30%. In connection with the issuance of the First and Refunding Mortgage Bonds, PECO settled forward starting interest rate swaps in the aggregate notional amount of $200 million resulting in a $5 million pre-tax loss recorded in other comprehensive income, which is being amortized over the expected remaining life of the related debt. In 2001, ComEd redeemed $196 million of 9.875% First Mortgage Bonds, Series 75, due June 15, 2020 and retired $340 million in transitional trust notes. In 2001, PECO Energy Transition Trust (PETT), a Delaware business trust and a wholly owned subsidiary of PECO, refinanced $805 million of floating rate Series 1999-A Transition Bonds through the issuance by PETT of fixed-rate transition bonds (Series 2001-A Transition Bonds). The 2001-A Transition Bonds are non-callable, fixed rate securities with an interest rate of 6.52%. The Series 2001-A Transition Bonds have an expected final payment date of September 1, 2010 and a termination date of December 31, 2010. In connection with this refinancing, PECO settled $318 million of forward starting interest rate swaps resulting in a $6 million gain which is reflected in other income and deductions due to the transaction no longer being probable. Also, in connection with this refinancing, PECO settled a portion of the interest rate swaps and the remaining portion of the forward starting interest rate swaps resulting in gains of $25 million, which were deferred and are being amortized over the expected remaining lives of the related debt. In 1999, PECO entered into treasury forwards associated with the anticipated issuance of the Series 2000-A Transition Bonds. On May 2, 2000, these instruments were settled with net proceeds to 107 the counterparties of $13 million that has been deferred and is being amortized over the life of the Series 2000-A Transition Bonds as an increase to interest expense. In 1998, PECO entered into treasury forwards and forward starting interest rate swaps to manage interest rate exposure associated with the anticipated issuance of the Series 1999-A Transition Bonds. On March 18, 1999, these instruments were settled with net proceeds of $80 million to PECO that were deferred and are being amortized over the life of the Series 1999-A Transition Bonds as a reduction of interest expense. At December 31, 2002 and 2001, the aggregate unamortized net gain on the settlement of the PECO swap transactions was $36 million and $55 million, respectively, recorded in Other Comprehensive Income. ComEd prepayment premiums of $24 million, and net unamortized premiums, discounts and debt issuance expenses of $3 million, and prepayment premiums of $39 million, offset by unamortized issuance premiums of $17 million associated with the early retirement of debt in 2002 and 2001, respectively, have been deferred in regulatory assets and will be amortized to interest expense over the life of the related new debt issuance consistent with regulatory recovery. In 2000, PECO incurred charges aggregating $6 million ($4 million, net of tax) for prepayment premiums and the write-offs of unamortized deferred financing costs associated with the early retirement of debt that have been recorded in interest expense. 14. Income Taxes Income tax expense (benefit) is comprised of the following components: For the Years Ended December 31, ----------------------------------------------- 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Included in operations: Federal Current $ 624 $ 880 $ 161 Deferred 250 (61) 163 Investment tax credit amortization (15) (14) (15) State Current 96 119 -- Deferred 43 7 30 - ------------------------------------------------------------------------------------------------------------------- $ 998 $ 931 $ 339 - ------------------------------------------------------------------------------------------------------------------- Included in cumulative effect of changes in accounting principles: Federal Deferred $ (87) $ 6 $ 13 State Deferred (3) 2 3 - ------------------------------------------------------------------------------------------------------------------- $ (90) $ 8 $ 16 - ------------------------------------------------------------------------------------------------------------------- The effective income tax rate varies from the U.S. Federal statutory rate principally due to the following: 108 For the Years Ended December 31, ------------------------------------------------ 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- U.S. Federal statutory rate 35.0% 35.0% 35.0% Increase (decrease) due to: Property basis differences (0.4) (0.2) 0.1 State income taxes, net of Federal income tax benefit 3.2 3.4 2.1 Amortization of investment tax credit (0.4) (0.5) (1.6) Amortization of goodwill -- 1.9 0.9 Dividends on PECO Preferred Stock 0.1 0.2 0.4 Other, net (0.1) (0.1) 0.7 - ------------------------------------------------------------------------------------------------------------------- Effective income tax rate 37.4% 39.7% 37.6% - ------------------------------------------------------------------------------------------------------------------- The tax effects of temporary differences giving rise to significant portions of Exelon's deferred tax assets and liabilities as of December 31, 2002 and 2001 are presented below: 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Deferred tax liabilities: Plant basis difference $ 4,710 $ 4,630 Deferred gain on sale of plants 860 872 Deferred investment tax credit 212 222 Deferred debt refinancing costs 96 44 Tax deductible goodwill -- 2 Unrealized gain on derivative financial instruments -- 34 - ------------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities 5,878 5,804 - ------------------------------------------------------------------------------------------------------------------- Deferred tax assets: Decommissioning and decontamination obligations (607) (573) Deferred pension and postretirement obligations (911) (382) Tax deductible goodwill (95) -- Unrealized loss on derivative financial instruments (60) -- Other, net (208) (194) - ------------------------------------------------------------------------------------------------------------------- Total deferred tax assets (1,881) (1,149) - ------------------------------------------------------------------------------------------------------------------- Deferred income taxes (net) on the balance sheet $ 3,997 $ 4,655 - ------------------------------------------------------------------------------------------------------------------- In accordance with regulatory treatment of certain temporary differences, Exelon has recorded a regulatory asset for recoverable deferred income taxes, pursuant to SFAS No. 109, "Accounting for Income Taxes," of $661 million and $701 million at December 31, 2002 and 2001, respectively. These recoverable deferred income taxes include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking policies of the ICC and PUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. Exelon's predecessor entities, Unicom and PECO, have years that are under review at the audit or appeals level of the Internal Revenue Service (IRS) and certain state authorities. These reviews by the governmental taxing authorities are not expected to have an adverse impact on the financial condition or result of operations at Exelon. ComEd has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of December 31, 2002, a deferred tax liability of approximately $860 million related to the fossil plant sale is reflected in Deferred Income Taxes on Exelon's Consolidated Balance Sheets. ComEd's management believes an adequate reserve for interest has been established in the event that such positions are not sustained. Changes in IRS interpretations of existing tax authority or challenges to ComEd's positions could have the impact of accelerating future income tax payments and increasing interest expense above amounts reserved related to the deferred tax 109 gain that becomes current. The Federal tax returns covering the period of the 1999 fossil plant sale are anticipated to be under IRS audit beginning in 2003. Final resolution of this matter is not anticipated for several years. As of December 31, 2002 and 2001, Exelon had recorded valuation allowances of $13 million and $2 million, respectively. 15. Retirement Benefits Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans applicable to essentially all ComEd, PECO, Generation and Business Services Company (BSC) employees and certain employees of Enterprises. In 2001, Exelon consolidated the former Unicom and PECO plans into Exelon plans. Essentially all management employees, and electing union employees, hired on or after January 1, 2001 participate in newly established cash balance pension plans. Approximately 4,700 management employees who were active participants in the former Unicom and PECO pension plans on December 31, 2000, and remained employed by Exelon on January 1, 2002 elected to transfer to the cash balance plan. Benefits under Exelon's pension plans generally reflect each employee's compensation, years of service and age at retirement. Funding is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended. The following tables provide a reconciliation of benefit obligations, plan assets and funded status of the plans. 110 Pension Benefits Other Postretirement Benefits ------------------------------------------------------------ 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Change in benefit obligation: Net benefit obligation at beginning of year $ 7,101 $ 6,695 $ 2,331 $ 2,275 Service cost 95 94 57 42 Interest cost 525 498 160 161 Plan participants' contributions -- -- 8 4 Plan amendments 120 44 -- (191) Actuarial (gain)/loss 514 254 155 173 Curtailments/Settlements -- (38) -- -- Special accounting costs 4 48 -- 3 Gross benefits paid (505) (494) (156) (136) - ------------------------------------------------------------------------------------------------------------------- Net benefit obligation at end of year $ 7,854 $ 7,101 $ 2,555 $ 2,331 - ------------------------------------------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at beginning of year $ 6,279 $ 7,000 $ 1,132 $ 1,188 Actual return on plan assets (581) (265) (125) (14) Employer contributions 202 38 73 90 Plan participants' contributions -- -- 8 4 Gross benefits paid (505) (494) (156) (136) - ------------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of year $ 5,395 $ 6,279 $ 932 $ 1,132 - ------------------------------------------------------------------------------------------------------------------- Funded status at end of year: $ (2,459) $ (822) $ (1,623) $ (1,199) Miscellaneous adjustment (3) -- -- -- Unrecognized net actuarial (gain)/loss 2,118 397 793 440 Unrecognized prior service cost 211 108 (149) (191) Unrecognized net transition obligation (asset) (11) (17) 102 103 - ------------------------------------------------------------------------------------------------------------------- Net amount recognized at end of year $ (144) $ (334) $ (877) $ (847) - ------------------------------------------------------------------------------------------------------------------- Amounts recognized in statements of financial position: Prepaid benefit cost $ 145 $ -- $ -- $ -- Accrued benefit cost (289) (334) (877) (847) Additional minimum liability (1,815) -- -- -- Intangible asset 211 -- -- -- Accumulated other comprehensive income 1,604 -- -- -- - ------------------------------------------------------------------------------------------------------------------- Net amount recognized at end of year $ (144) $ (334) $ (877) $ (847) - ------------------------------------------------------------------------------------------------------------------- 111 Pension Benefits Other Postretirement Benefits ----------------------------------------------------------------------------- 2002 2001 2000 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Weighted-average assumptions as of December 31, Discount rate 6.75% 7.35% 7.60% 6.75% 7.35% 7.60% Expected return on plan assets 9.50% 9.50% 9.50% 8.80% 8.80% 8.80% Rate of compensation increase 4.00% 4.00% 4.30% 4.00% 4.00% 4.30% Health care cost trend on covered charges N/A N/A N/A 8.5% 10.00% 7.00% decreasing decreasing decreasing to ultimate to ultimate to ultimate trend of 4.5% trend of 4.5% trend of 5.0% in 2008 in 2008 in 2005 - ------------------------------------------------------------------------------------------------------------------- Pension Benefits Other Postretirement Benefits ----------------------------------------------------------------------------- 2002 2001 2000 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Components of net periodic benefit cost (benefit): Service cost $ 95 $ 94 $ 39 $ 57 $ 42 $ 24 Interest cost 525 498 219 160 161 83 Expected return on assets (628) (625) (316) (93) (99) (34) Amortization of: Transition obligation (asset) (4) (4) (4) 10 10 12 Prior service cost 16 9 7 (37) (9) -- Actuarial (gain) loss -- (25) (26) 6 1 -- Curtailment charge (credit) -- (12) (12) -- 9 24 Settlement charge (credit) -- (9) (16) -- -- -- - ------------------------------------------------------------------------------------------------------------------- Net periodic benefit cost (benefit) $ 4 $ (74) $ (109) $ 103 $ 115 $ 109 - ------------------------------------------------------------------------------------------------------------------- Special accounting costs $ 4 $ 48 $ 217 $ -- $ 3 $ 48 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- Sensitivity of retiree welfare results Effect of a one percentage point increase in assumed health care cost trend on total service and interest cost components $ 33 on postretirement benefit obligation $ 302 Effect of a one percentage point decrease in assumed health care cost trend on total service and interest cost components $ (27) on postretirement benefit obligation $ (252) - ------------------------------------------------------------------------------------------------------------------- Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Exelon's costs of providing pension and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on pension plan assets, discount rate, and the rate of increase in health care costs. The market value of plan assets has been affected by sharp declines in the equity market since the third quarter of 2000. As a result, at December 31, 2002, Exelon was required to recognize an additional minimum liability and an intangible asset as prescribed by SFAS No. 87 "Employers' Accounting for Pensions." The liability was recorded as a reduction to shareholders' equity, and the equity will be restored to the balance sheet in future periods when the fair value of plan assets exceeds the accumulated benefit obligations. The amount of the reduction to shareholders' equity (net of income taxes) in 2002 was $1.0 billion. The recording of this reduction did not affect net income or cash flow in 2002 or compliance with debt covenants. 112 Special accounting costs of $4 million in 2002 and $48 million in 2001 represent accelerated separation and enhancement benefits provided to PECO employees expected to be terminated as a result of the Merger. Special accounting costs in 2000 of $217 million represented PECO's accelerated separation and enhancement benefits of $96 million and ComEd's accelerated liability increase of $121 million inclusive of $96 million for separation benefits and $25 million for plan enhancements. Exelon provides certain health care and life insurance benefits for retired employees. In 2001, Exelon adopted an amendment to the former Unicom postretirement medical benefit plan that changed the eligibility requirement of the plan to cover only employees who retire with 10 years of service after age 45 rather than with 10 years of service and having attained the age of 55. Welfare benefits for active employees are provided by several insurance policies or self-funded plans whose premiums or contributions are based upon the benefits paid during the year. Exelon sponsors savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pretax income in accordance with specified guidelines. Exelon matches a percentage of the employee contribution up to certain limits. The cost of Exelon's matching contribution to the savings plans totaled $63 million, $57 million and $17 million in 2002, 2001 and 2000, respectively. 16. Preferred Securities of Subsidiaries Preferred and Preference Stock At December 31, 2002 and 2001, cumulative Preferred Stock of PECO, no par value, consisted of 15,000,000 shares authorized and the amounts set forth below: December 31, -------------------------------------------------------------------------- Current 2002 2001 2002 2001 Redemption -------------------------------------------------------------------------- Price(a) Shares Outstanding Dollar Amount - ------------------------------------------------------------------------------------------------------------------- Series (without mandatory redemption) $4.68 $ 104.00 150,000 150,000 $ 15 $ 15 $4.40 112.50 274,720 274,720 27 27 $4.30 102.00 150,000 150,000 15 15 $3.80 106.00 300,000 300,000 30 30 $7.48 (b) 500,000 500,000 50 50 - ------------------------------------------------------------------------------------------------------------------- 1,374,720 1,374,720 137 137 Series (with mandatory redemption) $6.12 (c) -- 185,400 -- 19 - ------------------------------------------------------------------------------------------------------------------- Total preferred stock 1,374,720 1,560,120 $ 137 $ 156 - ------------------------------------------------------------------------------------------------------------------- (a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends. (b) None of the shares of this series is subject to redemption prior to April 1, 2003. (c) PECO made the annual sinking fund payments of $18.5 million on August 1, 2002 and August 1, 2001. At December 31, 2000, shares and principal outstanding were 370,800 and $37 million, respectively. 113 At December 31, 2002 and 2001, ComEd Preferred Stock and ComEd Preference Stock consisted of 850,000 and 6,810,451 shares authorized, respectively, none of which were outstanding. Company Obligated Mandatorily Redeemable Preferred Securities At December 31, 2002 and 2001, subsidiary trusts of PECO and ComEd had outstanding the following preferred securities: December 31, ---------------------------------------------------- Mandatory Distri- Liqui- 2002 2001 2002 2001 Redemption bution dation -------------------------- ------------------------- Date Rate Value Trust Securities Outstanding Dollar Amount - ------------------------------------------------------------------------------------------------------------------- PECO Energy Capital Trust II 2037 8.00% $ 25 2,000,000 2,000,000 $ 50 $ 50 PECO Energy Capital Trust III 2028 7.38% 1,000 78,105 78,105 78 78 - ------------------------------------------------------------------------------------------------------------------- Total 2,078,105 2,078,105 $ 128 $ 128 - ------------------------------------------------------------------------------------------------------------------- ComEd Financing I 2035 8.48% $ 25 8,000,000 8,000,000 $ 200 $ 200 ComEd Financing II 2027 8.50% 1,000 150,000 150,000 150 150 Unamortized Discount (20) (21) - ------------------------------------------------------------------------------------------------------------------- Total 8,150,000 8,150,000 $ 330 $ 329 - ------------------------------------------------------------------------------------------------------------------- The securities issued by the PECO trusts represent Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) having a distribution rate and liquidation value equivalent to the trust securities. The COMRPS are the sole assets of these trusts and represent limited partnership interests of PECO Energy Capital, L.P. (Partnership), a Delaware limited partnership. Each holder of a trust's securities is entitled to withdraw the corresponding number of COMRPS from the trust in exchange for the trust securities so held. Each series of COMRPS is supported by PECO's deferrable interest subordinated debentures, held by the Partnership, which bear interest at rates equal to the distribution rates on the related series of COMRPS. ComEd Financing I and ComEd Financing II are wholly owned subsidiary trusts of ComEd. Each of ComEd trust's sole assets are subordinated deferrable interest securities issued by ComEd bearing interest rates equivalent to the distribution rate of the related trust security. The preferred securities issued by each of ComEd Financing I and ComEd Financing II have no voting privileges, except (i) for the right to approve a merger, consolidation or other transaction involving the applicable trust that would result in certain United States Federal income tax consequences to that trust, (ii) with respect to certain amendments to the applicable trust agreement, (iii) for certain voting privileges that arise upon an event of default under the applicable trust agreement or (iv) with respect to certain amendments to the related ComEd guarantee agreement. The interest expense on the debentures and deferrable interest securities is included in Distributions on Preferred Securities of Subsidiaries in the Consolidated Statements of Income and is deductible for income tax purposes. 17. Common Stock At December 31, 2002 and 2001, common stock without par value consisted of 600,000,000 and 600,000,000 shares authorized and 323,312,586 and 321,006,904 shares outstanding, respectively. Stock Repurchase In January 2000, in connection with the Merger Agreement, PECO entered into a forward purchase agreement to purchase $500 million of its common stock from time to time. Settlement of this forward purchase agreement was, at PECO's election, on a physical, net share or net cash basis. In May 2000, PECO utilized a portion of the proceeds from the securitization of its stranded cost recovery to 114 physically settle this agreement, resulting in the repurchase of 12 million shares of common stock for $496 million. In connection with the settlement of this agreement, PECO received $1 million in accumulated dividends on the repurchased shares and paid $6 million of interest. Stock-Based Compensation Plans Exelon maintains a Long-Term Incentive Plan (LTIP) for certain full-time salaried employees and previously maintained a broad-based incentive program for certain other employees. The types of long-term incentive awards that have been granted under the LTIP are non-qualified options to purchase shares of Exelon's common stock and common stock awards. At December 31, 2002, there were 13,000,000 options authorized for issuance under the LTIP and 2,000,000 options authorized under the broad-based incentive program. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Options granted under the LTIP and the broad-based incentive program become exercisable upon attainment of a target share value and/or time. All options expire 10 years from the date of grant. Information with respect to the LTIP and the broad-based incentive program at December 31, 2002 and changes for the three years then ended, is as follows: Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Price Price Price Shares (per share) Shares (per share) Shares (per share) 2002 2002 2001 2001 2000 2000 - ------------------------------------------------------------------------------------------------------------------- Balance at January 1 14,039,996 $ 43.96 15,287,859 $ 42.13 6,065,897 $ 31.91 Options granted/assumed 3,938,632 47.12 629,200 66.42 11,089,051 (a) 46.09 Options exercised (1,821,339) 33.37 (1,695,474) 34.84 (1,725,058) 31.79 Options canceled (270,299) 53.62 (181,589) 52.64 (142,031) 39.95 - ------------------------------------------------------------------------------------------------------------------- Balance at December 31 15,886,990 45.80 14,039,996 43.96 15,287,859 42.13 - ------------------------------------------------------------------------------------------------------------------- Exercisable at December 31 10,491,184 43.96 8,006,193 38.75 4,953,942 30.04 - ------------------------------------------------------------------------------------------------------------------- Weighted average fair value of options granted during year $ 13.62 $ 19.59 $ 16.62 - ------------------------------------------------------------------------------------------------------------------- (a) Includes 5.3 million options converted in the Merger. The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2002, 2001 and 2000, respectively: 2002 2001 2000 - ------------------------------------------------------------------------------- Dividend yield 3.3% 3.2% 3.6% Expected volatility 36.8% 36.8% 36.8% Risk-free interest rate 4.6% 4.9% 5.9% Expected life (years) 5.0 5.0 5.0 - ------------------------------------------------------------------------------- 115 At December 31, 2002, the options outstanding, based on ranges of exercise prices, were as follows: Options Outstanding Options Exercisable ------------------- ------------------- Weighted Average Remaining Weighted Weighted Contractual Average Average Range of Number Life Exercise Number Exercise Exercise Prices Outstanding (years) Price Exercisable Price - ------------------------------------------------------------------------------------------------------------------- $10.01-$20.00 560,700 6.14 $ 19.68 560,700 $ 19.68 $20.01-$30.00 926,332 4.64 25.49 926,332 25.49 $30.01-$40.00 4,668,877 7.53 37.87 4,031,683 37.76 $40.01-$50.00 4,844,505 9.39 45.61 1,419,748 42.25 $50.01-$60.00 4,265,109 8.84 59.39 3,159,481 59.47 $60.01-$70.00 621,467 9.03 67.32 393,240 67.28 - ------------------------------------------------------------------------------------------------------------------- Total 15,886,990 10,491,184 - ------------------------------------------------------------------------------------------------------------------- Exelon common stock awards under Exelon's LTIP of 316,025 shares were issued during 2000 and 1999. Vesting for the common stock awards is over a period not to exceed 10 years from the grant date. Compensation cost of $14 million associated with these awards is amortized to expense over the vesting period. The related accumulated amortization of $13 million includes amortization expense of approximately $1 million, $5 million and $5 million during 2002, 2001 and 2000, respectively. Exelon common share awards of 590,074, 426,794 and 159,129 shares were granted under Exelon's LTIP and board compensation plans during 2002, 2001 and 2000, respectively. Total accumulated compensation cost of $60 million is to be accrued to expense over the vesting period of up to 5 years from the grant date. The related accumulated amortization of $37 million includes amortization expense of $20 million, $11 million and $6 million during 2002, 2001 and 2000, respectively. In June 2001, the Board of Directors of Exelon approved the Employee Stock Purchase Plan (ESPP). The purpose of the ESPP is to provide employees of Exelon, and its subsidiary companies the right to purchase shares of Exelon's common stock at below-market prices. A total of 3,000,000 shares of Exelon's common stock have been reserved for issuance under the ESPP. Employees' purchases are limited to no more than 125 shares per quarter and no more than $25,000 in fair market value in any plan year. Employees purchased 257,455 and 137,648 shares of Exelon common stock under the ESPP in 2002 and 2001, respectively. Fund Transfer Restrictions Under PUHCA Under PUHCA, Exelon is precluded from borrowing or receiving any extension of credit or indemnity from its subsidiaries and can lend, but not borrow, from Exelon's intercompany money pool. Additionally, under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. However, the SEC order granted permission to ComEd, and to Exelon to the extent we receive dividends from ComEd paid from ComEd additional paid-in-capital, to pay up to $500 million in dividends out of additional paid-in capital, although Exelon may not pay dividends out of paid-in capital after December 31, 2002 if its ratio of common equity to total capitalization is less than 30%. At December 31, 2002, Exelon had retained earnings of $2.0 billion, which includes ComEd retained earnings of $577 million, PECO retained earnings of $401 million and Generation undistributed earnings of $924 million. In 2002, Exelon recorded a reduction to shareholders' equity of $1.0 billion related to the minimum pension liability. At December 31, 2002, Exelon's common equity to total capitalization ratio was 32%. 116 Undistributed Earnings of Equity Method Investments At December 31, 2002, Exelon had consolidated undistributed earnings of equity method investments of $145 million. 18. Fair Value of Financial Assets and Liabilities The carrying amounts and fair values of Exelon's financial assets and liabilities as of December 31, 2002 and 2001 were as follows: 2002 2001 ------------------------------ ------------------------------ Carrying Carrying Amount Fair Value Amount Fair Value - ------------------------------------------------------------------------------------------------------------------- Non-derivatives: Liabilities Long-term debt (including amounts due within one year) $ 14,529 $ 15,950 $ 14,285 $ 14,912 Preferred Securities of Subsidiaries 595 739 613 572 Derivatives: Fixed to floating interest rate swaps 41 41 (20) (20) Floating to fixed interest rate swaps (114) (114) -- -- Forward starting interest rate swaps (52) (52) (1) (1) Energy derivatives (143) (143) 78 78 - ------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents, customer accounts receivable and trust accounts for decommissioning nuclear plants are recorded at their fair value. As of December 31, 2002 and 2001, Exelon's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants, long-term debt and preferred securities of subsidiaries are estimated based on quoted market prices for the same or similar issues. The fair value of Exelon's interest rate swaps and power purchase and sale contracts is determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves. Financial instruments that potentially subject Exelon to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. Exelon places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to Exelon's large number of customers and, in the case of the Energy Delivery business, their dispersion across many industries. Exelon has entered into fixed to floating interest rate swaps in the aggregate amount of $485 million of fixed-rate obligations of ComEd. These swaps have been designated as fair-value hedges, as defined in SFAS No. 133 and as such, changes in the fair value of the swap will be recorded in earnings. However, as long as the hedges remain effective and the underlying transaction remains probable, changes in the fair value of the swaps will be offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedges as a result of ineffectiveness would be recorded immediately in earnings. The fair market value of these swaps was $41 million at December 31, 2002. 117 Under the terms of the SBG credit facility, SBG is required to effectively fix the interest rate on 50% of the borrowings under the facility through its maturity in 2007. As of December 31, 2002, Generation has entered into floating to fixed interest rate swap agreements which have effectively fixed the interest rate on $861 million of notional principal, or 83% of borrowings outstanding at December 31, 2002. These swaps have been designated as cash flow hedges under SFAS No. 133, and as such, as long as the hedge remains effective and the underlying transaction remains probable, changes in the fair value of these swaps will be recorded in accumulated other comprehensive income (loss) until earnings are affected by the variability of the cash flows being hedged. The fair market value exposure of these swaps was $92 million at December 31, 2002. Exelon has also entered into floating to fixed interest rate swaps to manage interest rate exposure associated with the floating rate series of transition bonds issued to securitize PECO's stranded cost recovery. These interest rate swaps were designated as cash flow hedges. These interest rate swaps had an aggregate fair market value exposure of $22 million at December 31, 2002. PECO also has interest rate swaps in place to satisfy counterparty credit requirements in regards to the floating rate series of transition bonds which are mirror swaps of each other. These swaps are not designated as cash flow hedges, therefore, they are required to be marked-to-market if there is a difference in their values. Since these swaps are offsetting each other, a mark-to-market adjustment is not expected to occur. During 2002, PECO entered into forward starting interest rate swaps, with an aggregate notional amount of $200 million, in anticipation of the issuance of debt at PECO. These interest rate swaps were designated as cash flow hedges. In connection with bond issuances in 2002, PECO settled these forward starting interest rate swaps resulting in a $5 million pretax loss recorded in other comprehensive income, which is being amortized over the life of the related debt. During 2002 and 2001, ComEd entered into forward-starting interest rate swaps, with an aggregate notional amount of $830 million and $250 million, respectively, in anticipation of the issuance of debt. In connection with bond issuances in 2002, ComEd settled forward starting interest rate swaps in the aggregate notional amount of $450 million, resulting in a $10 million pre-tax loss recorded as a regulatory asset, which is being amortized over the life of the related debt in interest expense. At December 31, 2002, ComEd had $630 million of forward starting interest rate swaps outstanding. These interest rate swaps, designated as cash flow hedges, had a fair market value exposure of $52 million at December 31, 2002. As it remained probable that the debt issuances, the forecasted future transactions these swaps were hedging, would occur, although the issuances had been delayed, we continued to account for these interest rate swap transactions as hedges. In connection with ComEd's January 22, 2003 issuance of $700 million in First Mortgage Bonds, ComEd settled swaps, in the aggregate notional amount of $550 million, for a payment of $43 million, which will be recorded as a regulatory asset and amortized over the life of the debt issuance. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of Exelon's exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates. Exelon utilizes derivatives to manage the utilization of its available generating capacity and provision of wholesale energy to its affiliates. Exelon also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity 118 contracts. Additionally, Exelon enters into certain energy-related derivatives for trading or speculative purposes. During 2002 and 2001, Generation recognized net losses of $6 million ($4 million, net of income taxes) and gains of $16 million ($10 million, net of income taxes), respectively, relating to mark-to-market adjustments of certain non-trading power purchase and sale contracts pursuant to SFAS No. 133. Mark-to-market adjustments on non-trading power purchase and sale contracts are reported in fuel and purchased power and mark-to-market adjustments on trading activities are reported as Operating Revenues in the Consolidated Statements of Income. During 2002 and 2001, Generation recognized net losses aggregating $9 million ($6 million, net of income taxes) and net gains aggregating $14 million ($10 million, net of income taxes), respectively, relating to mark-to-market adjustments on derivative instruments entered into for trading purposes. Exelon Generation commenced financial trading in the second quarter of 2001. Gains and losses associated with financial trading are reported as Operating Revenue in the Consolidated Statements of Income. During 2002 and 2001, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted energy commodity transactions no longer being probable. For 2002, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable. For 2001, a $6 million gain ($4 million, net of income taxes) was reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable. Enterprises has entered into a limited number of energy commodity derivative contracts in connection with its service of gas customers. While the majority of these contracts qualify as normal purchases and sales or as cash flow hedges under SFAS No. 133, $16 million was recorded as a reduction to fuel expense as a result of contracts being marked to market in 2002. Of this $16 million, $3 million was recorded upon contract settlement and $13 million was recorded as a change in fair value prior to contract settlement. The offset to this $13 million was recorded as an asset on the balance sheet and it is expected that $11 million and $2 million will reverse as fuel expense in 2003 and 2004, respectively. At December 31, 2002, there was a net asset of $20 million on the balance sheet related to Enterprises' mark-to-market contracts. The remaining $7 million of the offset to this asset was recorded in other comprehensive income and is expected to be reclassified to earnings within the next twelve months. Enterprises' counterparties in these contracts are all investment grade, with the exception of Dynegy Inc. (Dynegy), to whom Enterprises has $2 million of exposure. On January 1, 2001, Exelon recognized a non-cash gain of $12 million, net of income taxes, in earnings and deferred a non-cash gain of $44 million, net of income taxes, in accumulated other comprehensive income, a component of shareholders' equity, to reflect the initial adoption of SFAS No. 133, as amended. SFAS No. 133 must be applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. As of December 31, 2002, $102 million of deferred net losses on derivative instruments in accumulated other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to interest rate cash flows are reclassified into earnings when the forecasted interest payment occurs. Amounts in accumulated other comprehensive income related to energy commodity cash flows are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. The majority of Exelon's cash flow hedges are expected to settle within the next 4 years. Exelon would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments. The credit exposure of derivatives contracts is 119 represented by the fair value of contracts at the reporting date. Exelon's interest rate swaps are documented under master agreements. Among other things, these agreements provide for a maximum credit exposure for both parties. Payments are required by the appropriate party when the maximum limit is reached. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Exelon classifies investments in the trust accounts for decommissioning nuclear plants as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized costs bases for the securities held in these trust accounts. December 31, 2002 ------------------------------------------------------------------- Gross Gross Amortized Unrealized Unrealized Estimated Cost Gains Losses Fair Value - ------------------------------------------------------------------------------------------------------------------- Equity securities $ 1,763 $ 72 $ (482) $ 1,353 Debt securities Government obligations 938 62 -- 1,000 Other debt securities 698 32 (30) 700 - ------------------------------------------------------------------------------------------------------------------- Total debt securities 1,636 94 (30) 1,700 - ------------------------------------------------------------------------------------------------------------------- Total available-for-sale securities $ 3,399 $ 166 $ (512) $ 3,053 - ------------------------------------------------------------------------------------------------------------------- December 31, 2001 ------------------------------------------------------------------- Gross Gross Amortized Unrealized Unrealized Estimated Cost Gains Losses Fair Value - ------------------------------------------------------------------------------------------------------------------- Equity securities $ 1,666 $ 130 $ (236) $ 1,560 Debt securities Government obligations 882 28 (3) 907 Other debt securities 701 16 (19) 698 - ------------------------------------------------------------------------------------------------------------------- Total debt securities 1,583 44 (22) 1,605 - ------------------------------------------------------------------------------------------------------------------- Total available-for-sale securities $ 3,249 $ 174 $ (258) $ 3,165 - ------------------------------------------------------------------------------------------------------------------- Net unrealized losses of $346 million and $84 million were recognized in Accumulated Depreciation, Regulatory Assets and Accumulated Other Comprehensive Income in Exelon's Consolidated Balance Sheets at December 31, 2002 and 2001, respectively. For the Years Ended December 31 ------------------------------- 2002 2001 - -------------------------------------------------------------------------------- Proceeds from sales $ 1,612 $ 1,624 Gross realized gains 56 76 Gross realized losses (86) (189) - -------------------------------------------------------------------------------- Net realized gains of $2 million and $14 million were recognized in Accumulated Depreciation and Regulatory Assets in Exelon's Consolidated Balance Sheets at December 31, 2002 and 2001, respectively, and $32 million and $127 million of net realized losses were recognized in Other Income and Deductions in Exelon's Consolidated Income Statements for 2002 and 2001, respectively. The available-for-sale securities held at December 31, 2002 have an average maturity of six to seven years. The cost of these securities was determined on the basis of specific identification. See Note 11 - Nuclear 120 Decommissioning and Spent Fuel Storage for further information regarding the nuclear decommissioning trusts. 19. Commitments and Contingencies Capital Commitments Exelon and British Energy, Generation's joint venture partner in AmerGen, have each agreed to provide up to $100 million to AmerGen at any time that the Management Committee of AmerGen determines, that in order to protect the public health and safety and/or to comply with NRC requirements, such funds are necessary to meet ongoing operating expenses or to safely maintain any AmerGen plant. Although Exelon does not anticipate that AmerGen will make any acquisitions in 2003, Exelon has committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2003. Generation has a 70% interest in the Southeast Chicago Energy Project, LLC (Southeast Chicago), which owns a peaking facility in Chicago. Southeast Chicago is obligated to make equity distributions of $54 million over the next 20 years to the party, which is not affiliated with Generation, that owns the remaining 30% interest. This amount reflects a return of that party's investment in Southeast Chicago. Generation has the right to purchase, generally at a premium, and the other party has the right to require Generation to purchase, generally at a discount, the 30% interest in Southeast Chicago. Additionally, Generation may be required to purchase the 30% interest upon the occurrence of certain events, including Generation's failure to maintain an investment grade rating. Nuclear Insurance The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of January 1, 2003, the current limit is $9.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Through its subsidiaries, Exelon carries the maximum available commercial insurance of $300 million and the remaining $9.2 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $89 million per reactor per incident, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act expired on August 1, 2002 but existing facilities, including those owned and operated by Generation, remain covered. The U.S. Congress has extended the provisions of the Price-Anderson Act related to commercial facilities through 2003. The extension was passed as part of the Consolidated Appropriations Resolution, 2003, which will be presented to the President of the United States for his signature. The extension would affect facilities obtaining NRC operating licenses in 2003. Existing facilities are unaffected by the extension. Exelon carries property damage, decontamination and premature decommissioning insurance for each station loss resulting from damage to its nuclear plants. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Exelon is required by the NRC to maintain, to provide for decommissioning the facility. Exelon is unable to predict the timing of the availability of insurance proceeds to Exelon and the amount of such proceeds that would be available. Under the terms of the various insurance agreements, Exelon could be assessed up to $124 million for losses incurred at any plant insured by the insurance companies. In the event that one or more acts of terrorism cause accidental property damage within a twelve month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity, and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a "certified act of terrorism" as defined in the Terrorism Risk Insurance Act of 2002, as a result of government indemnity. Generally, a "certified act of terrorism" is defined in the Terrorism Risk Insurance Act to be any act, certified by the U.S. government, to be an act of terrorism committed on behalf of a foreign person or interest. Additionally, through its subsidiaries, Exelon is a member of an industry mutual insurance company that provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. 121 Exelon's maximum share of any assessment is $46 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would also not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act as described above. In addition, Exelon participates in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose "nuclear-related employment" began on or after the commencement date of reactor operations. Exelon will not be liable for a retrospective assessment under this new policy. However, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retroactive assessment of up to $50 million could apply. Exelon is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon's financial condition and results of operations. Energy Commitments Exelon's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long, intermediate and short-term contracts. Exelon maintains 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. Exelon has also contracted for access to additional generation through bilateral long-term power purchase agreements. These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Exelon enters into power purchase agreements with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Exelon has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Exelon with physical power supply to enable it to deliver energy to meet customer needs. Exelon primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Exelon also uses financial contracts to manage the risk surrounding trading for profit activities. Exelon has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators. Exelon also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Exelon provides delivery of its energy to these customers through access to its transmission assets or rights for firm transmission. Generation has power purchase agreements (PPAs) with Midwest Generation, LLC (Midwest Generation) for the purchase of capacity from its coal-fired stations through 2004. Contracted capacity and capacity available through the exercise of an annual option are 1,696 MWs and 3,949 MWs in 2003 and 2004, respectively. The agreements also provide for the option to purchase 1,084 MWs of oil and gas-fired capacity, and 857 MWs of peaking capacity, subject to reduction. Generation has entered into PPAs with AmerGen, under which it will purchase all the energy from Unit No. 1 at Three Mile Island Nuclear Station after December 31, 2001 through December 31, 2014. Under a January 1, 2003 PPA, Generation will purchase from AmerGen all of the residual energy from the Clinton Nuclear Power Station (Clinton), through December 31, 2003. Currently, the residual output is approximately 31% of the total output of Clinton. In accordance with the terms of the AmerGen partnership agreement, the 2003 PPA will be extended through the end of the AmerGen partnership agreement in 2006. 122 Exelon has a long-term supply agreement through December 2022 with Distrigas of Massachusetts, LLC to guarantee physical gas supply to its New England generating units. Under the agreement, prices are indexed to New England gas markets. At December 31, 2002, Exelon had long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from unaffiliated utilities and others, including the Midwest Generation and AmerGen contracts, as expressed in the following tables: Net Capacity Power Only Power Only Purchases from Transmission Rights Purchases (1) Sales AmerGen Non-Affiliates Purchases (2) - ------------------------------------------------------------------------------------------------------------------- 2003 $ 589 $ 2,606 $ 280 $ 1,722 $ 86 2004 639 1,181 292 768 93 2005 356 355 472 283 84 2006 328 92 472 239 3 2007 408 22 179 227 -- Thereafter 3,742 1 2,638 829 -- - ------------------------------------------------------------------------------------------------------------------- Total $ 6,062 $ 4,257 $ 4,333 $ 4,068 $ 266 - ------------------------------------------------------------------------------------------------------------------- (1) On October 2, 2002, Generation notified Midwest Generation of its exercise of termination options under the existing Collins Generating Station (Collins) and Peaking Unit (Peaking) Purchase Power Agreements. Generation exercised its termination options on 1,727 MWs in 2003 and 2004. In 2003, Generation will take 1,778 MWs of option capacity under the Collins and Peaking Unit Agreements as well as 1,265 MWs of option capacity under the Coal Generation Purchase Power Agreement. Net capacity purchases in 2004 include 3,474 MWs of optional capacity from Midwest Generation. Net Capacity Purchases also include capacity sales to TXU under the purchase power agreement entered into in connection with the purchase of two generating plants in April 2002, which states that TXU will purchase the plant output from May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU will make fixed capacity payments and will provide fuel to Exelon in return for exclusive rights to the energy and capacity of the generation plants. The combined capacity of the two plants is 2,334 MWs. (2) Transmission Rights Purchases include estimated commitments in 2004 and 2005 for additional transmission rights that will be required to fulfill firm sales contracts. 123 Commercial Commitments Exelon's commercial commitments as of December 31, 2002, representing commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure our obligations, are as follows: Expiration within ------------------------------------------------------------ 2008 Total 2003 2004-2005 2006-2007 and beyond - ------------------------------------------------------------------------------------------------------------------- Credit Facility (a) $ 1,500 $ 1,500 $ -- $ -- $ - Letters of Credit (non-debt) (b) 111 106 5 -- -- Letters of Credit (Long-Term Debt) (c) 456 305 151 -- -- Insured Long-Term Debt (d) 254 -- -- -- 254 Guarantees of Letters of Credit(e) 226 226 -- -- -- Performance Guarantees (f) 101 -- -- -- 101 Surety Bonds (g) 521 329 57 4 131 Energy Marketing Contract Guarantees (h) 124 114 10 -- -- Nuclear Insurance Guarantees (i) 1,380 -- -- -- 1,380 Lease Guarantees (j) 13 -- -- 2 11 Preferred Securities (k) 128 -- -- -- 128 Sithe New England Equity Guarantee (l) 38 38 -- -- -- Guarantees of Long-Term Debt (m) 41 2 -- -- 39 - ------------------------------------------------------------------------------------------------------------------- Total $ 4,893 $ 2,620 $ 223 $ 6 $ 2,044 - ------------------------------------------------------------------------------------------------------------------- (a) Credit Facility - Exelon, along with ComEd, PECO and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. At December 31, 2002, there were no borrowings against the credit facility. Additionally, at December 31, 2002, there was $948 million of commercial paper outstanding. (b) Letters of Credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. (c) Letters of Credit (Long-Term Debt) - Direct-pay letters of credit issued in connection with variable-rate debt in order to provide liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate on the debt. (d) Insured Long-Term Debt - Borrowings that have been credit-enhanced through the purchase of insurance coverage equal to the amount of principal outstanding plus interest. (e) Guarantees of letters of credit - Guarantees issued to provide support for letters of credit as required by third parties. These guarantees could be called upon only in the event of non-payment by a subsidiary. (f) Performance Guarantees - Guarantees issued to ensure execution under specific contracts. (g) Surety Bonds - Guarantees issued related to contract and commercial surety bonds, excluding bid bonds. (h) Energy Marketing Contract Guarantees - Guarantees issued to ensure performance under energy commodity contracts. (i) Nuclear Insurance Guarantees - Guarantees of nuclear insurance required under the Price-Anderson Act. $1.1 billion of this total exposure is exempt from the $4.5 billion PUHCA guarantee limit by SEC rule. (j) Lease Guarantees - Guarantees issued to ensure payments on building leases. (k) Preferred Securities - Guarantees issued to guarantee the preferred securities of the subsidiary trusts of PECO. See Note 16 - Preferred Securities of Subsidiaries for further information. (l) Sithe New England Equity Guarantee- See Note 3 - Acquisitions and Dispositions for further information on the $38 million guarantee. After construction of the SBG facilities is complete, Exelon could be required to guarantee up to an additional $42 million in order to ensure that the SBG facilities have adequate funds available for potential outage and other operating costs and requirements. (m) Guarantees of Long-Term Debt - Issued to guarantee payment of subsidiary debt. Unconsolidated Equity Investments. Generation is a 49.9% owner of Sithe and accounts for the investment as an unconsolidated equity investment. The Sithe New England purchase did not affect the accounting for Sithe as an equity investment. Separate from the Sithe New England transaction, Generation is subject to a Put and Call Agreement (PCA) that gives Generation the right to purchase (Call) the remaining 50.1% of Sithe, and gives the other Sithe shareholders the right to sell (Put) their interest to Generation. If the Put option is exercised, Generation has the obligation to complete the purchase. 124 The PCA originally provided that the Put and Call options became exercisable as of December 18, 2002 and expired in December 2005. However, upon Apollo Energy, LLC's (Apollo) purchase of Vivendi's 34.2% ownership and Sithe management's 1% share, Apollo agreed to delay the effective date of its Put right until June 1, 2003 and, if certain conditions are met, until September 1, 2003. There are also certain events that could trigger Apollo's Put right becoming effective prior to June 1, 2003 including Exelon being downgraded below investment grade by Standard and Poor's Rating Group or Moody's Investors Service, Inc., a stock purchase agreement between Exelon and Apollo being executed and subsequently terminated, or the occurence of any event of default, other than a change of control, under certain Exelon or Apollo credit agreements. Depending on the triggering event, Apollo's put price of approximately $460 million, growing at a market rate of interest, needs to be funded within 18 or 30 days of the Put being exercised. There have been no changes to the Put and Call terms with respect to Marubeni's remaining 14.9% interest. The delay in the effective date of Apollo's Put right allows Exelon to explore a further restructuring of our investment in Sithe. Exelon is continuing discussions with Apollo and Marubeni regarding restructuring alternatives that are designed in part to resolve Exelon's ownership limitations of Sithe's qualifying facilities. Exelon would hope to implement any additional restructuring of its Sithe investment in 2003. If Exelon is unsuccessful in restructuring the Sithe transaction, Exelon will proceed to implement measures to address the ownership of the qualified facilities as well as divest non-strategic assets, for which the financial outcome is uncertain. If Generation exercises its option to acquire the remaining outstanding common stock in Sithe, or if all the other stockholders exercise their Put Rights, the purchase price for Apollo's 35.2% interest will be approximately $460 million, growing at a market rate of interest. The additional 14.9% interest will be valued at fair market value subject to a floor of $141 million and a ceiling of $290 million. If Generation increases its ownership in Sithe to 50.1% or more, Sithe may become a consolidated subsidiary and our financial results may include Sithe's financial results from the date of purchase. At December 31, 2002, Sithe had total assets of $2.6 billion and total debt of $1.3 billion. This $1.3 billion includes $624 million of subsidiary debt incurred primarily to finance the construction of six new generating facilities, $461 million of subordinated debt, $103 million of line of credit borrowings, $43 million of the current portion of long-term debt and capital leases, $30 million of capital leases, and excludes $453 million of non-recourse project debt associated with Sithe's equity investments. For the year ended December 31, 2002, Sithe had revenues of $1.0 billion. As of December 31, 2002, Generation had a $449 million equity investment in Sithe. Environmental Issues Exelon's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, Exelon, through its subsidiaries, is generally liable for the costs of remediating environmental contamination of property now or formerly owned by Exelon and of property contaminated by hazardous substances generated by Exelon. Exelon owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. Exelon has identified 71 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. Exelon is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. As of December 31, 2002 and 2001, Exelon had accrued $156 million for environmental investigation and remediation costs, including $125 million and $127 million, respectively, for MGP investigation and remediation that currently can be reasonably estimated. Included in the environmental investigation and remediation cost obligation as of December 31, 2002 and 2001 is $97 million and $100 million, respectively, that has been recorded on a discount basis (reflecting discount rates of 5.0% and 5.5%, respectively). Such estimates, reflecting the effects of a 2.5% and 3.0% inflation rate before the effects of discounting were $138 million and $154 million at December 31, 2002 and 2001, respectively. 125 Exelon anticipates that payments related to the discounted environmental investigation and remediation costs, recorded on an undiscounted basis, of $76 million will be incurred for the five-year period through 2007. Exelon cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by Exelon, environmental agencies or others, or whether such costs will be recoverable from third parties. Leases Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars and office equipment, as of December 31, 2002 were: - --------------------------------------------------------------------------- 2003 $ 77 2004 59 2005 58 2006 54 2007 49 Remaining years 598 - --------------------------------------------------------------------------- Total minimum future lease payments $ 895 - --------------------------------------------------------------------------- Rental expense under operating leases totaled $85 million, $75 million and $41 million in 2002, 2001 and 2000, respectively. Litigation Securities Litigation. Between May 8 and June 14, 2002, several class action lawsuits were filed in the Federal District Court in Chicago asserting nearly identical securities law claims on behalf of purchasers of Exelon securities between April 24, 2001 and September 27, 2001 (Class Period). The complaints allege that Exelon violated Federal securities laws by issuing a series of materially false and misleading statements relating to its 2001 earnings expectations during the Class Period. The court consolidated the pending cases into one lawsuit and has appointed two lead plaintiffs as well as lead counsel. On October 1, 2002, the plaintiffs filed a consolidated amended complaint. In addition to the original claims, this complaint contains allegations of new facts and contains several new theories of liability. Exelon believes the lawsuit is without merit and is vigorously contesting this matter. FERC Municipal Request for Refund. Three of ComEd's wholesale municipal customers filed a complaint and request for refund with FERC, alleging that ComEd failed to properly adjust its rates, as provided for under the terms of the electric service contracts with the municipal customers and to track certain refunds made to ComEd's retail customers in the years 1992 through 1994. In the third quarter of 1998, FERC granted the complaint and directed that refunds be made, with interest. On April 30, 2001, FERC issued an order granting rehearing in which it determined that its 1998 order had been erroneous and that no refunds were due from ComEd to the municipal customers. In August 2001, each of the three wholesale municipal customers appealed the April 30, 2001 FERC order to the Federal circuit court, which consolidated the appeals for the purposes of briefing and decision. The Federal circuit court has stayed the proceedings pending settlement negotiations among the parties. Retail Rate Law. In 1996, several developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under the Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgment that their rights under their contracts with ComEd were not affected by the amendment. On November 25, 2002, the court granted developers' 126 motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment, and Illinois from denying ComEd a tax credit on account of such purchases. ComEd and Illinois have each appealed the ruling. ComEd believes that it did not breach the contracts in question and that the damages claimed far exceed any loss that any project incurred by reason of its ineligibility for the subsidized rate. ComEd intends to prosecute its appeal and defend each case vigorously. Cotter Corporation Litigation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. In 1994, a Federal jury returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld on appeal. The remaining claims in the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory and punitive damages, interest and medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the jury verdict, and remanded the case for new trial. These plaintiffs' cases were consolidated with the remaining 26 plaintiffs' cases, which had not been tried. The consolidated trial was completed on June 28, 2001. The jury returned a verdict against Cotter and awarded $16 million in various damages. On November 20, 2001, the District Court entered an amended final judgment that included an award of both pre-judgment and post-judgment interests, costs, and medical monitoring expenses that total $43 million. In November 2000, another trial involving a separate sub-group of 13 plaintiffs, seeking $19 million in damages plus interest was completed in Federal District Court in Denver. The jury awarded nominal damages of $42,500 to 11 of 13 plaintiffs, but awarded no damages for any personal injury or health claims, other than requiring Cotter to perform periodic medical monitoring at minimal cost. Cotter appealed these judgments to the Tenth Circuit Court of Appeals. Cotter is vigorously contesting the award. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions, as well as any liability arising in connection with the West Lake Landfill discussed in the next paragraph. In connection with Exelon's 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation. The United States Environmental Protection Agency (EPA) has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of remediation for the site range from $0 million to $87 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Until an agreement is reached, Generation cannot predict its share of the costs. Raytheon Arbitration. In March 2001, two subsidiaries of Sithe New England Holdings (now Exelon New England Holdings) brought an action in the New York Supreme Court against Raytheon Corporation (Raytheon) relating to its failure to honor its guaranty with respect to the performance of the Mystic and Fore River projects, as a result of the abandonment of the projects by the turnkey contractor. In a related proceeding, in May 2002, Raytheon submitted claims to the International Chamber of Commerce Court of Arbitration seeking equitable relief and damages for alleged owner caused performance delays in connection with the Fore River Power Plant Engineering, Procurement & Construction Agreement (EPC Agreement). The EPC Agreement, executed by a Raytheon subsidiary and guaranteed by Raytheon, governs the design, engineering, construction, start-up, testing and delivery of 127 an 800-MW combined-cycle power plant in Weymouth, Massachusetts. Raytheon recently amended its claim and now seeks 141 days of schedule relief (which would reduce Raytheon's liquidated damage payment for late delivery by approximately $25.4 million) and additional damages of $15.6 million. Raytheon also has asserted a claim for loss of efficiency and productivity as a result of an alleged constructive acceleration, for which a claim has not yet been quantified. Generation believes the Raytheon assertions are without merit and is vigorously contesting these claims. Hearings by the International Chamber of Commerce Court of Arbitration with respect to liability were held in January and February 2003. A decision on liability is expected to be issued in May 2003 and, if necessary, additional hearings will be held on damages in May and June of 2003. Real Estate Tax Appeals. Generation is involved in tax appeals regarding a number of its nuclear facilities, Limerick Generating Station (Montgomery County, PA), Peach Bottom Atomic Power Station (York County, PA), and Quad Cities Station (Rock Island County, IL). Generation is also involved in the tax appeal for Three Mile Island (Dauphin County, PA) through AmerGen. Generation does not believe the outcome of these matters will have a material adverse effect on Generation's results of operations or financial condition. General. Exelon is involved in various other litigation matters. The ultimate outcome of such matters, as well as the matters discussed above, while uncertain, are not expected to have a material adverse effect on its respective financial condition or results of operations. Credit Contingencies Generation is a counterparty to Dynegy in various energy transactions. In early July 2002, the credit ratings of Dynegy were downgraded by two credit rating agencies to below investment grade. As of December 31, 2002, Generation had a net receivable from Dynegy of approximately $3 million, and consistent with the terms of the existing credit arrangement, has received collateral in support of this receivable. Generation also has credit risk associated with Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of the Independence generating station, a 1,040-MW gas-fired qualified facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of December 31, 2002, Sithe had recognized an asset on its balance sheet related to the fair market value of the financial swap agreement with Dynegy that is marked-to-market under the terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. We estimate, as a 49.9% owner of Sithe, that the impairment would result in an after-tax reduction of our equity earnings of approximately $10 million. In addition to the impairment of the financial swap asset, if Dynegy was unable to fulfill its obligations under the financial swap agreement and the tolling agreement, we would likely incur a further impairment associated with the Independence plant. Depending upon the timing of Dynegy's failure to fulfill its obligations and the outcome of any restructuring initiatives, Exelon could realize an after-tax charge of between $0 and $130 million. In the event of a sale of our investment in Sithe to a third party, proceeds from the sale could be negatively impacted by approximately $120 million, which would represent an after-tax loss of approximately $65 million. Additionally, the future economic value of AmerGen's purchased power arrangement with Illinois Power, a subsidiary of Dynegy, could be impacted by events related to Dynegy's financial condition. 128 20. Segment Information Exelon evaluates the performance of its business segments based on Net Income. Energy Delivery consists of the retail electricity distribution and transmission businesses of ComEd in northern Illinois and PECO in southeastern Pennsylvania and the natural gas distribution business of PECO located in the Pennsylvania counties surrounding the City of Philadelphia. Generation consists of electric generating facilities, energy marketing operations and Exelon's interests in Sithe and AmerGen. Enterprises consists of competitive retail energy sales, energy and infrastructure services, communications and other investments weighted towards the communications, energy services and retail services industries. An analysis and reconciliation of Exelon's business segment information to the respective information in the consolidated financial statements are as follows: Energy Intersegment Delivery Generation Enterprises Corporate Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------- Total Revenues: 2002 $ 10,457 $ 6,858 $ 2,033 $ 346 $ (4,739) $ 14,955 2001 10,171 6,826 2,292 341 (4,712) 14,918 2000 4,511 3,274 1,395 -- (1,681) 7,499 Intersegment Revenues: 2002 $ 76 $ 4,226 $ 97 $ 341 $ (4,740) $ -- 2001 94 4,102 179 337 (4,712) -- 2000 24 1,185 472 -- (1,681) -- Depreciation and Amortization: 2002 $ 978 $ 276 $ 55 $ 31 $ -- $ 1,340 2001 1,081 282 69 17 -- 1,449 2000 297 123 35 3 -- 458 Operating Expenses: 2002 $ 7,597 $ 6,349 $ 2,047 $ 402 $ (4,739) $ 11,656 2001 7,578 5,954 2,369 371 (4,716) 11,556 2000 (a) 3,009 2,833 1,473 324 (1,667) 5,972 Interest Expense: 2002 $ 854 $ 75 $ 14 $ 74 $ (51) $ 966 2001 973 115 37 133 (151) 1,107 2000 522 41 17 63 (29) 614 Income Taxes: 2002 $ 765 $ 217 $ 69 $ (53) $ -- $ 998 2001 703 327 (43) (56) -- 931 2000 421 160 (52) (190) -- 339 Net Income/(Loss): 2002 $ 1,268 $ 400 $ (178) $ (50) $ -- $ 1,440 2001 1,022 524 (85) (33) -- 1,428 2000 (a) 587 260 (94) (167) -- 586 Capital Expenditures: 2002 $ 1,041 $ 990 $ 44 $ 75 $ -- $ 2,150 2001 1,105 858 61 64 -- 2,088 2000 367 288 70 27 -- 752 Total Assets: 2002 $ 26,550 $ 11,007 $ 1,297 $ (1,376) $ -- $ 37,478 2001 26,365 8,145 1,743 (1,509) -- 34,744 - ------------------------------------------------------------------------------------------------------------------- (a) Includes non-recurring items of $276 million ($177 million after income taxes) for Merger-related expenses in 2000. 129 Equity in earnings of AmerGen and Sithe of $88 million, $90 million and $4 million for 2002, 2001 and 2000, respectively, are included in Generation's Net Income. Equity in earnings (losses) of communications joint ventures and other investments of $3 million, $(19) million and $(45) million for 2002, 2001 and 2000, respectively, are included in Enterprises' Net Income. Equity in earnings (losses) of affordable housing investments of $(11) million and $(9) million for 2002 and 2001, respectively, are included in Corporate's Net Income. 21. Related Party Transactions Exelon's financial statements reflect related-party transactions with unconsolidated affiliates as reflected in the tables below. For the Years Ended December 31, ----------------------------------------- 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- Purchased Power from AmerGen (1) $ 273 $ 57 $ 52 Interest Income from AmerGen (2) 2 -- -- Interest Income from Sithe (3) -- 2 -- Interest Expense to Sithe (4) 2 -- -- Services Provided to AmerGen (5) 70 80 32 Services Provided to Sithe (6) 1 -- -- Services Provided by Sithe (7) 13 -- -- - ------------------------------------------------------------------------------------------------------------------ 130 December 31, ----------------------------------- 2002 2001 - -------------------------------------------------------------------------------- Net Receivable from AmerGen (1,2,3) $ 39 $ 44 Net Payable to Sithe (4,5) 7 -- Note Payable to Sithe (7) 534 -- - -------------------------------------------------------------------------------- (1) Generation has entered into PPAs dated December 18, 2001 and November 22, 1999 with AmerGen. Under the 2001 PPA, Generation has agreed to purchase from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear Station from January 1, 2002 through December 31, 2014. Under the 1999 PPA, Generation agreed to purchase from AmerGen all of the residual energy from Clinton Nuclear Power Station (Clinton) through December 31, 2002. Currently, the residual output is approximately 31% of the total output of Clinton. In accordance with the terms of the AmerGen partnership agreement, the 1999 PPA will be extended through the end of the AmerGen partnership agreement in 2006. (2) In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the 1-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. As of December 31 2002, the outstanding principal balance of the loan was $35 million. (3) In August 2001, Exelon loaned Sithe, an equity method investee of Generation, $150 million. The note, which bore interest at the eurodollar rate, plus 2.25%, was repaid in December 2001 with the proceeds of bank borrowings. In connection with the bank borrowings, Exelon provided the lenders with a support letter confirming its investment in Sithe and Exelon's agreement to maintain a positive net worth of Sithe. (4) Under the terms of the agreement to acquire Sithe New England dated November 1, 2002, Generation issued a $534 million note to be paid in full on June 18, 2003 to Sithe. The note bears interest at the rate equal to LIBOR plus 0.875%. Interest accrued on the note as of December 31, 2002 was $2 million. (5) Under a service agreement dated March 1, 1999, Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services in an amount agreed to in the work order, which is not less than the higher of its fully allocated cost for performing each service or the market price for such service. (6) Under a service agreement dated December 18, 2000, Generation provides certain engineering and environmental services for fossil facilities owned by Sithe and for certain developmental projects. Generation is compensated for these services in an amount agreed to in the work order, but not less than the higher of fully allocated costs for performing such services or the market price. (7) Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services in the amount agreed to in the work order, but not less than the higher of fully allocated costs for performing such services or the market price. 22. Quarterly Data (Unaudited) The data shown below include all reclassifications, including those required upon the adoption of EITF 02-3, which Exelon considers necessary for a fair presentation of such amounts: Income Before the Cumulative Effect of Changes Operating Revenues Operating Income in Accounting Principles Net Income ------------------ ---------------- ------------------------ -------------- 2002 2001 2002 2001 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Quarter ended: March 31 $ 3,357 $ 3,823 $ 605 $ 889 $ 238 $ 387 $ 8 $ 399 June 30 3,519 3,616 813 792 485 315 485 315 September 30 4,370 4,185 1,000 912 551 376 551 376 December 31 3,709 3,293 882 769 397 338 397 338 - ------------------------------------------------------------------------------------------------------------------- 131 Earnings per Basic Share Average Shares Before the Cumulative Earnings per Basic Outstanding Effect of Changes Basic Share (in millions) in Accounting Principles Net Income ------------- ------------------------ -------------- 2002 2001 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Quarter ended: March 31 321 320 $ 0.74 $ 1.21 $ 0.02 $ 1.25 June 30 322 321 1.50 0.98 1.50 0.98 September 30 323 321 1.71 1.17 1.71 1.17 December 31 323 321 1.23 1.05 1.23 1.05 - ------------------------------------------------------------------------------------------------------------------- Earnings per Diluted Share Average Shares Before the Cumulative Earnings per Diluted Outstanding Effect of Changes Diluted Share (in millions) in Accounting Principles Net Income ------------- ------------------------ -------------- 2002 2001 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Quarter ended: March 31 323 324 $ 0.73 $ 1.19 $ 0.02 $ 1.23 June 30 324 324 1.50 0.97 1.50 0.97 September 30 324 323 1.70 1.16 1.70 1.16 December 31 325 322 1.22 1.05 1.22 1.05 - ------------------------------------------------------------------------------------------------------------------- The following table presents the New York Stock Exchange - Composite Common Stock Prices and dividends by quarter on a per share basis: 2002 2001 ------------------------------------------ ------------------------------------------ Fourth Third Second First Fourth Third Second First Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter - ------------------------------------------------------------------------------------------------------------------- High Price $ 53.06 $ 52.83 $ 56.99 $ 53.88 $ 48.69 $ 67.65 $ 70.26 $ 69.75 Low Price 42.38 37.85 50.10 45.90 39.65 38.75 62.10 53.60 Close 52.77 47.50 52.30 52.97 47.88 44.60 64.12 65.60 Dividends 0.44 0.44 0.44 0.44 0.43 0.42 0.42 0.55 (a) - ------------------------------------------------------------------------------------------------------------------- (a) The first quarter dividend in 2001 was a pro rata dividend. Unicom and PECO each paid their shareholders pro rata, per diem dividends from their last regular dividend dates through October 19, 2000. The first quarter covered the 119-day period from the date of the Merger, through the February 15, 2001 record date. 23. Subsequent Events On January 22, 2003, ComEd issued $350 million of 3.70% First Mortgage Bonds, due on February 1, 2008 and $350 million of 5.875% First Mortgage Bonds, due on February 1, 2033. These bond proceeds were used to refinance long-term debt that had been retired during the third and fourth quarters of 2002. As part of these bond issuances, ComEd settled various forward starting interest rate swaps, for $43 million, which will be recorded as a regulatory asset and amortized over the life of the debt issuance. On January 31, 2003, ComEd called $236 million of its First Mortgage Bonds at a redemption price of 103.86% of the principal amount, plus accrued interest to the March 18, 2003 redemption date. The bonds, which carried an interest rate of 8.375% and had a maturity date of February 15, 2023, are expected to be refinanced with long-term debt. On February 14, 2003, ComEd called $200 million of its Trust Preferred securities at a redemption price of 100% of the principal amount, plus accrued interest to the March 20, 2003 redemption date. The preferred securities, which carried an interest rate of 8.48% and had a maturity date of September 30, 2035, are expected to be refinanced with trust preferred securities. 132 On February 20, 2003, ComEd entered into separate agreements with the City of Chicago (City) and with Midwest Generation (Midwest Agreement). Under the terms of the agreement with the City, ComEd will pay the City $60 million over ten years and be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd's fossil stations in 1999, to build a 500-MW generation facility. Under the terms of the Midwest Agreement, ComEd will receive from Midwest Generation $36 million over ten years, $22 million of which was received on February 20, 2003, to relieve Midwest Generation's obligation under the fossil sale agreement. Midwest Generation will also assume from the City a Capacity Reservation Agreement which the City had entered into with Calumet Energy Team, LLC (CET), that is effective through June 2012. ComEd will reimburse the City for any nonperformance by Midwest Generation under the Capacity Reservation Agreement and will pay approximately $2 million for amounts owed to CET by the City at the time the agreement is executed. The net effect of the settlement to ComEd will be amortized over the remaining life of the franchise agreement with the City. 133