UNITED STATES SECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o.
The number of shares outstanding of each registrant’s common stock as of June 30, 2004 was:
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Exelon Corporation Yes þ No o Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC Yes o No þ.
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TABLE OF CONTENTS
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FILING FORMAT
This combined Form 10-Q is being filed separately by Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.
FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, as well as the items discussed in (a) the Registrants’ 2003 Annual Report on Form 10-K — ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants’ 2003 Annual Report on Form 10-K — ITEM 8. Financial Statements and Supplementary Data: Exelon — Note 19, ComEd — Note 15, PECO — Note 14 and Generation — Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the web site maintained by the SEC at www.sec.gov and Exelon’s website at www.exeloncorp.com.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
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EXELON CORPORATION
See Combined Notes to Consolidated Financial Statements
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EXELON CORPORATION AND SUBSIDIARY COMPANIES
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COMMONWEALTH EDISON COMPANY
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COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
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PECO ENERGY COMPANY
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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
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EXELON GENERATION COMPANY, LLC
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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
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1. Basis of Presentation (Exelon, ComEd, PECO and Generation)
Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the energy delivery, wholesale generation and enterprises businesses discussed below (see Note 17 — Segment Information). The energy delivery business segment consists of the purchase and sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and by PECO Energy Company (PECO) in southeastern Pennsylvania and the purchase and sale of natural gas and related distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. The generation business segment consists of the electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation) and Generation’s equity interest in EXRES SHC, Inc., the holding company of Sithe Energies, Inc. and its subsidiaries, referred to herein as Sithe. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. As of June 30, 2004, the enterprises business segment consists of the energy, infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises) and other investments related to the communications, energy services and retail services industries. See Note 3 — Acquisitions and Dispositions for further information regarding the disposition of businesses within the Enterprises segment.
The consolidated financial statements of Exelon, ComEd, PECO and Generation each include the accounts of entities in which it has a controlling financial interest, other than certain financing trusts of ComEd and PECO described below, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies the registrant as the primary beneficiary of the variable interest entity. Investments and joint ventures in which Exelon, ComEd, PECO and Generation do not have a controlling financial interest and certain financing trusts of ComEd and PECO are accounted for under the equity or cost methods of accounting.
In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), Sithe, a 50% owned subsidiary of Generation, was consolidated in the financial statements of Exelon and Generation as of March 31, 2004. Certain trusts and limited partnerships that are financing subsidiaries of ComEd and PECO have issued debt or mandatorily redeemable preferred securities. Due to the adoption of FIN No. 46-R, these trusts and limited partnerships are no longer consolidated within the financial statements of Exelon, ComEd or PECO as of December 31, 2003, or as of July 1, 2003 for PECO Energy Capital Trust IV (PECO Trust IV). See Note 2 — New Accounting Principles for further discussion of the adoption of FIN 46-R and the resulting consolidation of Sithe and the deconsolidation of these financing entities.
The accompanying consolidated financial statements as of June 30, 2004 and for the three and six months then ended are unaudited but, in the opinion of the management of each of Exelon, ComEd, PECO and Generation, include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). All adjustments are of a normal, recurring nature, except as otherwise disclosed. The share and per-share amounts included in Exelon’s consolidated financial statements and combined notes to consolidated financial statements have been adjusted for all periods presented to reflect a 2-for-1 stock split of Exelon’s common stock. See Note 14 — Earnings Per Share and Shareholders’ Equity for additional information regarding the stock split. The December 31, 2003 Consolidated Balance Sheets were derived from audited financial statements. These combined notes to consolidated financial statements do not include all disclosures required by GAAP. Certain prior-year amounts have been reclassified for comparative purposes.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
These reclassifications had no effect on net income or shareholders’ or member’s equity. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation included in or incorporated by reference in ITEM 8 of their Annual Reports on Form 10-K for the year ended December 31, 2003.
The FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN No. 46) in January 2003 and subsequently issued its revision in FIN No. 46-R in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46 was effective for Exelon’s variable interest entities created after January 31, 2003 and FIN No. 46-R was effective December 31, 2003 for Exelon’s other variable interest entities that were considered to be special-purpose entities. FIN No. 46-R applied to all other variable interest entities as of March 31, 2004.
Exelon and Generation consolidated Sithe as of March 31, 2004 pursuant to the provisions of FIN No. 46-R and recorded income of $32 million (net of income taxes) as a result of the elimination of a guarantee of Sithe’s commitments previously recorded by Generation. This income was reported as a cumulative effect of a change in accounting principle in the first quarter of 2004. Generation is a 50% owner of Sithe, and Exelon and Generation had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owns and operates power-generating facilities. See Note 4 — Sithe for additional information on the consolidation of Sithe.
PECO Trust IV, a financing subsidiary of PECO created in May 2003, was deconsolidated from the financial statements of Exelon and PECO pursuant to the provisions of FIN No. 46 as of July 1, 2003. Pursuant to the provisions of FIN No. 46-R, as of December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II, ComEd Financing III, ComEd Funding LLC and ComEd Transitional Funding Trust, were deconsolidated from the financial statements of Exelon and ComEd, and the other financing trusts of PECO, namely PECO Energy Capital Trust III (PECO Trust III) and PECO Energy Transition Trust (PETT), were deconsolidated from the financial statements of Exelon and PECO. Amounts owed to these financing trusts were recorded as debt to financing trusts or affiliates within the Consolidated Balance Sheets at June 30, 2004 and December 31, 2003 as follows:
This change in presentation had no effect on the net income of Exelon, ComEd or PECO. In accordance with FIN No. 46-R, prior periods were not reclassified.
FASB Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Exelon, ComEd, PECO and Generation were required to adopt SFAS No. 143 as of January 1, 2003.
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A significant retirement obligation is Generation’s obligation to decommission its nuclear plants at the end of their license lives. See Note 13 — Asset Retirement Obligations for additional information.
Exelon recorded income of $112 million (net of income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of SFAS No. 143 in the first quarter of 2003. The components of the cumulative effect of a change in accounting principle, net of income taxes, were as follows:
The cumulative effect of the change in accounting principle in adopting SFAS No. 143 had no effect on PECO’s income statement.
In July 2003, the Emerging Issues Task Force (EITF) of the FASB reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’ ” (EITF 03-11), which was ratified by the FASB in August 2003. The EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Exelon and Generation adopted EITF 03-11 as of January 1, 2004 and presented $239 million of revenue, $238 million of purchased power and $1 million of fuel expense net within revenues during the three months ended June 30, 2004 and $452 million of revenue, $444 million of purchased power and $8 million of fuel expense net within revenues during the six months ended June 30, 2004. Prior periods were not reclassified. The adoption of EITF 03-11 had no effect on the net income of Exelon or Generation. Had EITF 03-11 been retroactively applied to 2003, operating revenues, purchased power and fuel expense would have been affected as follows:
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Through its postretirement benefit plans, Exelon provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Actuarial equivalence has not yet been formally defined by the U.S. Department of Health and Human Services and thus is a matter of judgment by the plan sponsor and its actuaries. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), which provides transition guidance for accounting for the effects of the Prescription Drug Act and supersedes FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004.
During the second quarter of 2004, Exelon early adopted the provisions of FSP FAS 106-2, resulting in a remeasurement of its postretirement benefit plans’ assets and accumulated postretirement benefit obligations (APBO) as of December 31, 2003. Upon adoption, the effect of the subsidy on benefits attributable to past service was accounted for as an actuarial experience gain, resulting in a decrease of the APBO of approximately $177 million. The annualized reduction in the net periodic postretirement benefit cost is estimated to be approximately $32 million compared to the annual cost calculated without considering the effects of the Prescription Drug Act. The effect of the subsidy on the components of net periodic
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postretirement benefit cost for the three and six months ended June 30, 2004 included in the consolidated financial statements and Note 11 — Retirement Benefits was as follows:
The following table presents Exelon’s net income and earnings per share for the three months ended March 31, 2004 as if FSP FAS 106-2 was adopted as of January 1, 2004. Previously reported historical financial information for the three months ended March 31, 2004 has been adjusted in the table below and will be adjusted when presented for comparative purposes in future periods to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.
The following table presents net income of ComEd and Generation and net income on common stock of PECO for the three months ended March 31, 2004 as if FSP FAS 106-2 was adopted as of January 1, 2004. Historical financial information for the three months ended March 31, 2004 has been adjusted in the table below and will be adjusted when presented for comparative purposes in future periods to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.
In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-01, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-01). EITF 03-01 provides guidance for evaluating whether an investment is other-than-temporarily impaired and
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will be applied in other-than-temporary impairment evaluations made by Exelon beginning in the third quarter of 2004. Exelon adopted the disclosure requirements of EITF 03-01 for investments accounted for under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” within its financial statements for the year ended December 31, 2003. For all other investments within the scope of EITF 03-01 and for cost method investments, the disclosures will be effective for Exelon for the year ended December 31, 2004. Comparative information for periods prior to initial application is not required. Exelon, ComEd, PECO and Generation are still evaluating the potential impact of the adoption of EITF 03-01.
In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). The EITF concluded that if investors in a limited liability company have specific ownership accounts, they should follow the guidance prescribed in Statement of Position 78-9, “Accounting for Investments in Real Estate Ventures,” and EITF Topic No. D-46, “Accounting for Limited Partnership Investments.” Otherwise, investors should follow the significant influence model prescribed in Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” EITF 03-16 will be effective for Exelon, ComEd, PECO and Generation during the third quarter of 2004. Exelon, ComEd, PECO and Generation are still evaluating the potential impact of the adoption of EITF 03-16.
On May 25, 2004, Exelon and Generation completed the sale, transfer and assignment of ownership of their indirect wholly owned subsidiary Boston Generating, LLC (Boston Generating), which owns the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility (Boston Generating Credit Facility).
The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. The Federal Energy Regulatory Commission (FERC) approved the sale of Boston Generating in May 2004. Responsibility for plant operations and power marketing activities will be transferred to the lenders’ special purpose entity in a separate transaction. Certain aspects of the transfer of operations and marketing are also subject to approval of the FERC. On June 24, 2004, the parties filed an application with the FERC for an order authorizing the transfer of responsibility for plant operations and power marketing, and the parties expect to complete that transfer during the third quarter of 2004. Pending completion of the transfer of operations and marketing activities, Generation affiliates will continue to operate and market power from the plants on behalf of the owners. Due to ongoing power marketing agreements between Generation and Boston Generating, the results of Boston Generating have not been classified as a discontinued operation within the Consolidated Statements of Income and Comprehensive Income of Exelon and Generation. Exelon and Generation are hedged to eliminate the financial effects of these power-marketing-agreements from their results of operations.
In connection with the settlement reached on February 23, 2004, Exelon, Generation, the lenders and Raytheon Company (Raytheon), the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements, entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities. See Note 15 — Commitments and Contingencies for information regarding the settlement of litigation associated with the projects.
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In connection with the decision to transition out of Boston Generating and the generating units, Generation recorded during the third quarter of 2003 an impairment charge of its long-lived assets pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), of $945 million ($573 million net of income taxes) in operating expenses within its Consolidated Statements of Income and Comprehensive Income. As a result of Boston Generating’s liabilities being greater than its assets at the time of the sale, transfer and assignment of ownership, Exelon and Generation recorded a gain of $85 million ($52 million net of income taxes) in other income and deductions within the Consolidated Statements of Income and Comprehensive Income in the second quarter of 2004. In connection with the sale, Exelon and Generation recorded a liability associated with a guarantee by their subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. See Note 15 — Commitments and Contingencies for further information regarding the guarantee.
Boston Generating was reported in the Generation segment of Exelon’s consolidated financial statements prior to its sale. At the date of the sale, Boston Generating had approximately $1.2 billion in assets, primarily consisting of property, plant and equipment, and approximately $1.3 billion of liabilities of which approximately $1.0 billion was debt outstanding under the Boston Generating Credit Facility. As of the date of transfer, these amounts were eliminated from the Consolidated Balance Sheets of both Exelon and Generation. Exelon’s and Generation’s Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2004 and 2003 include the following financial results related to Boston Generating:
See Note 5 — Selected Pro Forma and Consolidating Financial Information for the effect of the sale of Boston Generating as if the transaction had occurred on January 1, 2003 and was included in Exelon and Generation’s results from that date.
Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, resulting in prepayment penalties of $9 million, which were recorded in interest expense.
Exelon Services, Inc. During the six months ended June 30, 2004, Enterprises disposed of certain businesses of Exelon Services, Inc. (Services), including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale (before income taxes) recorded during the six months ended June 30, 2004 related to the disposition of these Services businesses were $34 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of June 30, 2004,
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Services had assets and liabilities of $58 million and $90 million, respectively, which primarily represented the corporate operations and the remaining businesses of the Mechanical and Integrated Technology Group. See Assets and Liabilities Held for Sale below for information regarding the classification of the assets and liabilities of the remaining business of Services as held for sale as of June 30, 2004.
PECO TelCove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003.
InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. (InfraSource). See the Notes to Consolidated Financial Statements in Exelon’s 2003 Form 10-K for further information regarding this sale. Enterprises’ results of operations for the three and six months ended June 30, 2004 compared to the same periods in 2003 were significantly affected by the sale of InfraSource.
The results of Exelon Thermal and Services have been included in income from continuing operations within Exelon’s Consolidated Statements of Income and Comprehensive Income (as opposed to discontinued operations) as the impact of these entities on Exelon’s consolidated financial statements was not significant.
Effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. The transaction had no effect on the assets and liabilities of Exelon Energy Company, which were previously reported as a part of the Enterprises segment. Beginning in 2004, Exelon Energy Company’s assets and liabilities and results of operations are included in Generation’s financial statements. Generation and Enterprises’ 2003 segment information has been adjusted to reflect this transfer in Note 17 — Segment Information.
The following summary represents the assets and liabilities of Exelon Energy Company that were transferred to Generation as of January 1, 2004:
See Note 5 — Selected Pro Forma and Consolidating Financial Information for the effect of the transfer of Exelon Energy Company to Generation as if the transaction had occurred on January 1, 2003 and was included in Generation’s results from that date.
On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen) for $277 million. The allocation of fair value related to the
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valuation of long-lived assets will be affected by the finalization of the purchase price based on the completion of the review of the closing AmerGen balances at December 31, 2003.
Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity method investment. For the three and six months ended June 30, 2003, Generation recorded $20 million and $84 million, respectively, of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and recorded $110 million and $177 million, respectively, of purchased power from AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $311 million. For the six months ended June 30, 2004, AmerGen’s assets and liabilities and results of operations are included in Generation’s financial statements.
See Note 5 — Selected Pro Forma and Consolidating Financial Information for the effect of the acquisition of the remaining 50% interest in AmerGen by Generation as if the transaction had occurred on January 1, 2003 and was included in Exelon and Generation’s results from that date.
In November 2003, Exelon purchased interests in two synthetic fuel-producing facilities. The purchase price for these facilities included a combination of cash, notes payable and contingent consideration dependent upon the production level of the facilities. These facilities are not consolidated within Exelon’s financial statements because Exelon does not have a controlling financial interest in these facilities. The notes payable recorded for the purchase of the facilities was $238 million. Exelon’s right to acquire its share of tax credits generated by the facilities was recorded as an intangible asset and will be amortized as the tax credits are earned. Synthetic fuel facilities chemically change coal, including waste and marginal coal, into a fuel used at power plants. In April 2004, the Internal Revenue Service (IRS) issued two private letter rulings that affirmed that the process used by the facilities will produce a solid synthetic fuel that qualifies for tax credits under Section 29 of the Internal Revenue Code. See Note 19 — Subsequent Events for information regarding investments in synthetic fuel-producing facilities that occurred in July 2004.
The major classes of assets and liabilities classified as held for sale within Exelon’s and Generation’s Consolidated Balance Sheets as of June 30, 2004 consisted of the following:
Generation.Generation classified certain assets and liabilities of Sithe as held for sale as of June 30, 2004. Sithe is consolidated within the financial statements of Generation pursuant to FIN No. 46-R. During
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the three months ended June 30, 2004, Sithe completed the sale of its gas and Australian businesses, which represented $151 million and $140 million of assets and liabilities held for sale, respectively, at March 31, 2004.
Enterprises.Enterprises classified the assets and liabilities of certain Services businesses as held for sale as of June 30, 2004 due to ongoing efforts to dispose of these businesses. These businesses are expected to be sold in 2004. See “Disposition of Enterprises Entities” above for further information.
Sithe is primarily engaged in the development, construction, ownership and operation of electric wholesale generating facilities in North America. At June 30, 2004, excluding assets held for sale, Sithe operated nine power plants with total average net capacity of 1,323 megawatts (MW). Sithe also has 49.5% interests in two 230-MW projects in Mexico, which commenced commercial operations during the second quarter of 2004.
The financial statements of all foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for the Consolidated Statements of Income and Comprehensive Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on the Consolidated Statements of Income and Comprehensive Income and accordingly have no effect on net income.
On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe (Generation owned 49.9% prior to November 25, 2003). Generation’s intent is to fully divest its interest in Sithe. See the 2003 Form 10-K for further details regarding these transactions.
Exelon and Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN No. 46-R. See Note 2 — New Accounting Principles for further discussion.
As a result of the series of transactions referred to above, the consolidation of Sithe at March 31, 2004 was accounted for as a step acquisition pursuant to purchase accounting policies. Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Exelon’s and Generation’s results of operations beginning April 1, 2004. Sithe has entered into tolling arrangements (Tolling Agreement) with Dynegy Power Marketing and its affiliates with respect to Sithe’s Independence Station. The Tolling Agreement commenced on July 1, 2001 and runs through 2014. Additionally, Sithe has entered into an energy purchase agreement (Energy Purchase Agreement) with Consolidated Edison Company relating to the Independence Station, which continues through 2014. As a result of the acquisition accounting described above, values were assigned to the Tolling Agreement and the Energy Purchase Agreement on March 31, 2004 of approximately $91 million and $282 million, respectively, which have been recorded as intangible assets on Exelon’s and Generation’s Consolidated Balance Sheets in deferred debits and other assets. These amounts were determined based on fair value techniques utilizing the contract terms and various other estimates including forward power prices, discount rates and option pricing models. The intangible assets representing the Tolling Agreement and the Energy Purchase Agreement are being amortized using a method that reflects the pattern in which the economic benefits of the intangible assets are consumed or used up in accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), not to exceed the
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terms of the related contracts. The allocation of fair value related to the valuation of long-lived assets is preliminary and is anticipated to be finalized in the third quarter of 2004.
Sithe’s intangible assets are subject to amortization and are included in other non-current assets on Generation’s Consolidated Balance Sheet. Amortization expense for intangible assets was $15 million for the three months ended June 30, 2004. The components of Sithe’s intangible assets at June 30, 2004 were as follows:
Annual amortization expense for intangible assets is estimated to be $43 million for 2004, $58 million for 2005, $56 million for 2006, $50 million for 2007, and $44 million for 2008.
In connection with the consolidation of Sithe, certain indemnification guarantees, which were previously recorded in accordance with the provisions of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45), at Generation on November 25, 2003 pursuant to the series of transactions referred to above, were reversed in accordance with FIN No. 45 as Generation can no longer record liabilities associated with guarantees for the performance of a consolidated entity. The reversal of the guarantees resulted in Exelon and Generation recording income of $32 million (net of income taxes) as a cumulative effect of a change in accounting principle. The condensed consolidating financial information included in Note 5 — Selected Pro Forma and Consolidating Financial Information presents the financial position of Exelon, Generation and Sithe, as well as consolidating entries related primarily to acquisition notes payables and receivables between Generation and Sithe.
The book value of Generation’s investment in Sithe immediately prior to its consolidation on March 31, 2004 was $49 million. For the three months ended June 30, 2004, Generation recorded no equity method income or loss as Sithe is consolidated in Generation’s results. For the three months ended June 30, 2003, Generation recorded $2 million of equity method losses. Generation recorded $2 million of equity method losses during the six months ended June 30, 2004 and no equity method income or losses for the six months ended June 30, 2003.
Substantially all of Sithe’s property, plant and equipment and project agreements secure Sithe’s outstanding long-term debt, which consists primarily of project debt. During 2003, Sithe entered into an agreement with Exelon and Generation under which Exelon would obtain letters of credit to support contractual obligations of Sithe and its subsidiaries. As of June 30, 2004, Exelon has obtained $60 million of letters of credit in support of Sithe’s obligations not including a $50 million letter of credit which is not guaranteed by Exelon. With the exception of the issuance of letters of credit to support contractual obligations, the creditors of Sithe have no recourse against the general credit of Exelon or Generation.
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The following table details the Sithe balance sheet classification of the mark-to-market energy contract net assets recorded as of June 30, 2004:
The following unaudited pro forma financial information gives effect to the acquisition of the remaining 50% interest in AmerGen by Generation and the sale of Boston Generating by Generation, in each case, as if the transaction had occurred on January 1, 2003 and was included in or excluded from Exelon’s results from that date.
The above unaudited pro forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if the transactions had actually occurred on January 1, 2003, nor of the results that might be obtained in the future.
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The following condensed consolidating financial information presents the financial position of Exelon and Sithe, as well as eliminating entries related primarily to acquisition notes payables and receivables between Generation and Sithe.
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The following unaudited pro forma financial information gives effect to the acquisition of the remaining 50% interest in AmerGen, the transfer of Exelon Energy Company to Generation and the sale of Boston Generating, in each case, as if the transaction had occurred on January 1, 2003 and was included in or excluded from Generation’s results from that date.
The above unaudited pro forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if these acquisitions had actually occurred on January 1, 2003, nor of the results that might be obtained in the future.
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The following condensed consolidating financial information presents the financial position of Generation, Sithe and Exelon Energy, as well as eliminating entries related primarily to acquisition notes payables and receivables between Generation and Sithe.
Exelon accounts for its stock-based compensation plans under the intrinsic method prescribed by Accounting Principles Board No. 25, “Accounting for Stock Issued to Employees” and related interpretations and follows the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.” The tables below show the effect on net income
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and earnings per share for Exelon had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123 for the three and six months ended June 30, 2004 and 2003:
The net income of ComEd, PECO and Generation for the three and six months ended June 30, 2004 and 2003 would not have been significantly affected had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123.
PJM Integration. On April 1, 2003, ComEd received approval from the FERC to transfer control of its transmission assets to PJM Interconnection (PJM). The FERC also accepted for filing the amended PJM Tariff to reflect the inclusion of the transmission assets of ComEd and other new members, subject to a compliance filing and hearing on certain issues. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. On March 18, 2004, the FERC approved ComEd’s plan to complete its integration into PJM, subject to the North American Electric Reliability Council (NERC) approval of the
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PJM and Midwest ISO reliability plans to assure no adverse effects. The NERC granted the required approval on April 2, 2004. On April 27, 2004, the FERC issued its order approving ComEd’s application, subject to certain stipulations, including a provision to hold certain other utilities harmless from the impacts of ComEd joining PJM. ComEd agreed to these stipulations and fully integrated into PJM on May 1, 2004.
Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. However, because of the Illinois retail rate freeze and the method for calculating competitive transition charges, the increase is not expected to have a significant effect on operating revenues until after December 31, 2006. ComEd began charging the new rates May 1, 2004. ComEd’s management believes an adequate reserve for any required refunds has been established in the event that the new rates are adjusted based on rehearing or settlement negotiations.
Service Life Extension. Effective January 1, 2004, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities. The estimated service lives were extended by 20 years for the three AmerGen stations. These changes were based on engineering and economic feasibility analyses performed by Generation. The service life extensions are subject to approval by the Nuclear Regulatory Commission (NRC) extensions of the existing NRC operating licenses. Generation has not applied for license extensions at the AmerGen facilities, but has announced its plan to file an extension request for the Oyster Creek Nuclear Generating Station (Oyster Creek), and is planning on filing for license extensions at Unit 1 at the Three Mile Island Nuclear Station (TMI) and the Clinton Nuclear Power Station (Clinton) on a timeline consistent and integrated with the other planned extension filings for the Generation nuclear fleet.
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As of June 30, 2004 and December 31, 2003, Exelon had recorded goodwill of approximately $4.7 billion. Under the provisions of SFAS No. 142, goodwill is tested for impairment at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. Exelon will perform its annual goodwill impairment assessment in the fourth quarter of 2004. The changes in the carrying amount of goodwill by reportable segment (see Note 17 — Segment Information for further information regarding Exelon’s segments) for the periods ended June 30, 2004 and December 31, 2003 were as follows:
As of June 30, 2004 and December 31, 2003, ComEd had recorded goodwill of approximately $4.7 billion. Under the provisions of SFAS No. 142, goodwill is tested for impairment at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. ComEd will perform its annual goodwill impairment assessment in the fourth quarter of 2004. The changes in the carrying amount of goodwill for the periods ended June 30, 2004 and December 31, 2003 were as follows:
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Approximately $1.0 billion of debt was outstanding under the non-recourse Boston Generating Credit Facility at December 31, 2003, all of which was reflected in the Consolidated Balance Sheets of Exelon and Generation as a current liability due to certain events of default under the Boston Generating Credit Facility.
The outstanding debt under the Boston Generating Credit Facility was eliminated from the financial statements of Exelon and Generation upon the sale of Generation’s ownership interest in Boston Generating in May 2004. See Note 3 — Acquisitions and Dispositions for additional information regarding the sale.
Issuance of Long-Term Debt. During the six months ended June 30, 2004, the following long-term debt was issued:
Debt Retirements and Redemptions. During the six months ended June 30, 2004, the following debt was retired or redeemed:
During the three and six months ended June 30, 2004, ComEd made payments of $86 million and $179 million, respectively, related to its obligation to the ComEd Transitional Funding Trust, and PECO made payments of $78 million and $166 million, respectively, related to its obligation to the PETT. Additionally, Exelon made payments on other long-term debt obligations of $22 million.
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Sithe Long-Term Debt. At June 30, 2004, the following long-term debt of Sithe was consolidated in Exelon’s and Generation’s Consolidated Balance Sheets as a result of the adoption of FIN No. 46-R. See Note 2 — New Accounting Principles and Note 4 — Sithe for further information regarding the consolidation of Sithe.
Additionally, $3 million of Sithe’s long-term debt was classified as liabilities held for sale at June 30, 2004.
Aggregate maturities of Sithe’s long-term debt relating to continuing operations are as follows:
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Exelon, ComEd, PECO and Generation provide severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each employee’s years of service with Exelon and compensation level. The registrants account for their ongoing severance plans in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43,” and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.
In conjunction with The Exelon Way, a company-wide effort to define how Exelon will conduct business in years to come, Exelon, ComEd, PECO and Generation have collectively identified 1,650 positions for elimination through June 30, 2004. Exelon, ComEd, PECO and Generation based their estimates of the number of positions to be eliminated on management’s current plans and ability to determine the appropriate staffing levels to effectively operate the businesses. Exelon, ComEd, PECO and Generation may incur further severance costs associated with The Exelon Way if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be first reasonably estimated.
The following table presents, by segment, Exelon’s total salary continuance severance costs for the three and six months ended June 30, 2004. There were no significant salary continuance severance costs recorded during the three and six months ended June 30, 2003.
The following table provides total salary continuance severance costs for ComEd, PECO and Generation for the three and six months ended June 30, 2004. There were no significant salary continuance severance costs recorded during the three and six months ended June 30, 2003.
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The following tables provide a roll forward of the salary continuance severance obligations from January 1, 2003 through June 30, 2004 for Exelon, ComEd, PECO and Generation:
Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans applicable to essentially all ComEd, PECO, Generation and Exelon Business Services Company (BSC) employees and certain employees of Enterprises. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in Exelon-sponsored cash balance pension plans. Substantially all non-union employees hired prior to January 1, 2001 were offered a choice to remain in Exelon’s traditional pension plan or transfer to a cash balance pension plan for management employees. Employees of AmerGen participate in separate defined benefit pension plans and postretirement welfare benefit plans sponsored by AmerGen.
The defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions,” and are disclosed in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits — an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003). The costs of providing benefits under these plans are dependent on historical information, such as employee age, length of service and level of compensation, and the actual rate of return on plan assets, in addition to assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increase and the anticipated rate of increase in health care costs. The effects of changes in these factors on pension and other postretirement welfare benefit obligations are generally recognized over the expected remaining service life of the employees rather than immediately recognized in the income statement. Exelon uses a December 31 measurement date for the majority of its plans.
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Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans, and Exelon has submitted applications to the IRS for rulings on the tax-qualification of the form of each plan. By letters dated April 21, 2004, the IRS notified Exelon that the rulings on its applications for the traditional and management cash balance plans were delayed pending advice from its National Office, pursuant to a previously announced moratorium on rulings with respect to plans involved in so called cash balance “conversions.” On June 1, 2004, the IRS issued a favorable ruling on the union cash balance plan.
On June 15, 2004, the U.S. Treasury Department announced the withdrawal of its proposed regulations covering cash balance plans in order to provide Congress an opportunity to consider proposed legislation. In addition, various methods used by other employers to accrue and calculate benefits under cash balance plans have been challenged in recent lawsuits. The design of Exelon’s cash balance plans differs in certain material respects from the cash balance plans involved in the cases decided to date, and the courts have not reached uniform decisions on certain issues. As a result, considerable uncertainty remains regarding the application of the Employee Retirement Income Security Act of 1974, the Internal Revenue Code and federal employment laws to cash balance plans. Exelon does not know how the current uncertainty will be resolved and cannot determine at this time what impact, if any, future developments in this area will have on its pension plans or the funding of its pension obligations.
During the second quarter of 2004, Exelon early adopted FSP FAS 106-2. See Note 2 — New Accounting Principles for information regarding the adoption of FSP FAS 106-2 and the effect on the net periodic benefit cost of the other postretirement benefits plans included in the tables below.
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The following tables present the components of Exelon’s net periodic benefit costs recognized for the three and six months ended June 30, 2004 and 2003, including the net periodic benefit costs of AmerGen’s pension and postretirement plans for 2004. The expected long-term rates of return on plan assets used to estimate 2004 pension and other postretirement benefit costs are 9.00% and 8.33%, respectively. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.
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The following table presents the allocation by registrant of Exelon’s pension and post-retirement benefit costs, excluding curtailment and special termination benefits costs, during the three and six months ended June 30, 2004 and 2003:
Exelon sponsors savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon matches a percentage of the employee contribution up to certain limits. The following table presents, by registrant, the matching contribution to the savings plans during the three and six months ended June 30, 2004 and 2003:
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Exelon’s effective income tax rate varied from the U.S. Federal statutory rate principally due to the following:
ComEd’s effective income tax rate varied from the U.S. Federal statutory rate principally due to the following:
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PECO’s effective income tax rate varied from the U.S. Federal statutory rate principally due to the following:
Generation’s effective income tax rate varied from the U.S. Federal statutory rate principally due to the following:
SFAS No. 143 provides accounting guidance for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Liabilities for SFAS No. 143 asset retirement obligations (AROs) have been recorded at Generation in connection with its obligation to decommission its nuclear power plants as well as legal obligations associated with the closing of its fossil power plants. Based on the extended license lives of the nuclear plants, decommissioning expenditures are expected to occur primarily during the period 2029 through 2056. Exelon, through its regulated subsidiary utility companies, ComEd and PECO, currently recovers costs for decommissioning Generation’s nuclear generating stations, excluding the AmerGen plants, through regulated rates. The amounts recovered from
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customers are deposited into trust accounts and invested for funding the future decommissioning costs of the nuclear generating stations.
Exelon and Generation had $4,890 million and $4,721 million as of June 30, 2004 and December 31, 2003, respectively, recorded as nuclear decommissioning trust funds on Exelon’s and Generation’s Consolidated Balance Sheets which represent decommissioning assets in trust accounts. Generation anticipates that all trust fund assets will ultimately be used to decommission Generation’s nuclear plants.
The following table presents a roll forward of the ARO reflected on the Exelon and Generation Consolidated Balance Sheets from January 1, 2003 to June 30, 2004:
Generation is currently evaluating changes in estimated future cash flows related to the decommissioning of its nuclear units that will impact the recorded amount of the ARO. This evaluation is expected to be completed by the end of 2004.
On January 27, 2004, the Board of Directors of Exelon approved a 2-for-1 stock split of Exelon’s common stock. The distribution date was May 5, 2004. The authorized common stock was increased from 600,000,000 shares with no par value to 1,200,000,000 shares with no par value. The share and per-share amounts included in Exelon’s consolidated financial statements and combined notes to consolidated financial statements have been adjusted for all periods presented to reflect the stock split.
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Diluted earnings per share are calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options outstanding under Exelon’s stock option plans considered to be common stock equivalents. The following table sets forth the computation of basic and diluted earnings per share and shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share:
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 1 million and 10 million for the three months ended June 30, 2004 and 2003, respectively, and 1 million and 10 million for the six months ended June 30, 2004 and 2003, respectively.
In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The share repurchase program has no specified limit on the number of shares that may be repurchased and no specified termination date. Any shares repurchased are held as treasury shares
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unless cancelled or reissued at the discretion of Exelon’s management. Treasury shares are recorded at cost. During the three and six months ended June 30, 2004, 2.3 million shares of common stock were purchased under the share repurchase program for $75 million.
The following table summarizes the changes in shareholders’ equity for the six months ended June 30, 2004:
For information regarding capital commitments, nuclear decommissioning and spent fuel storage at December 31, 2003, see the Commitments and Contingencies and Nuclear Decommissioning and Spent Fuel Storage notes in the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation in the 2003 Form 10-K.
At June 30, 2004, Generation’s long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from unaffiliated utilities and others, including the Midwest Generation contract, did not change significantly from December 31, 2003, except for the following:
Exelon, ComEd, PECO and Generation’s commercial commitments as of June 30, 2004, representing commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payments on behalf of other parties and financing arrangements to secure obligations, did not change significantly from December 31, 2003, except for the following:
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Exelon, ComEd, PECO and Generation accrue amounts for environmental investigation and remediation costs that can be reasonably estimated, including amounts for manufactured gas plant (MGP) investigation and remediation. Exelon has identified 69 sites where former MGP activities have or may have resulted in actual site contamination. Of these 69 sites, the Illinois Environmental Protection Agency has approved the clean up of 4 sites and the Pennsylvania Department of Environmental Protection has approved the clean up of 8 sites. Pursuant to a Pennsylvania Public Utility Commission (PUC) order, PECO is currently recovering a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset (see Note 16 — Supplemental Financial Information). As of June 30, 2004 and December 31, 2003, Exelon, ComEd, PECO and Generation had accrued the following amounts for environmental liabilities:
Exelon, ComEd, PECO and Generation cannot predict the extent to which they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by environmental agencies or others, or whether such costs may be recoverable from third parties.
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Retail Rate Law. In 1996, three 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 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 and for breach of contract. On November 25, 2002, the court granted the developers’ 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 each appealed the ruling. On March 9, 2004, the Illinois Appellate Court reversed the trial court. The Appellate Court held that the 1996 law does apply to the developers’ facilities and, therefore, they are not entitled to subsidized payments. The Court expressly ruled that the breach of contract claims against ComEd are dismissed with prejudice. Two of the developers sought review of the Appellate Court’s decision by the Illinois Supreme Court. On May 26, 2004, the Supreme Court declined to hear the earlier-filed of the two appeals. There is no set date by which the Court must decide if it will hear the remaining appeal. While ComEd cannot currently predict the ultimate outcome of this action, it does not believe that the action will have a material adverse effect on its results of operations or its cash flows.
Real Estate Tax Appeals. PECO and Generation each have been challenging real estate taxes assessed on nuclear plants. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA), and has appealed local real estate assessments for 1998 and 1999 on the Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants. Generation is involved in real estate tax appeals for 2000 through 2004, also regarding the valuation of its Limerick and Peach Bottom plants, its Quad Cities Station (Rock Island County, IL) and, through its wholly owned subsidiary AmerGen, Three Mile Island Nuclear Station (Dauphin County, PA) and Oyster Creek Nuclear Generating Station (Forked River, NJ).
PECO and Generation believe their reserve balances for exposures associated with the real estate taxes as of June 30, 2004 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies.” The ultimate outcome of such matters, however, could result in additional unfavorable or favorable adjustments to the consolidated financial statements of Exelon, PECO and Generation and such adjustments could be material.
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. Several of these actions resulted in nominal jury verdicts or were settled or dismissed. One action resulted in an award for the plaintiffs of a more substantial amount, but was reversed on April 22, 2003 by the Tenth Circuit Court of Appeals and remanded for retrial. An appeal by the plaintiffs to the United States Supreme Court was denied on November 10, 2003. No date has been set for a new trial.
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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. Generation cannot predict the ultimate outcome of the cases.
The U.S. 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 the anticipated remediation strategy for the site may range up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.
Raytheon and Mitsubishi Litigation. In connection with the February 2004 settlement among Exelon, Generation and the lenders under the Boston Generating Credit Facility more fully described in Note 3 — Acquisitions and Dispositions, Exelon, Generation, the lenders and Raytheon, the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities. Under the global settlement, Generation agreed to pay approximately $31.1 million to Raytheon and approximately $1.4 million to Boston Generating. Raytheon released Exelon, Generation, their affiliates and the lenders from construction claims related to the projects. Raytheon also resolved all of the pending Mitsubishi Heavy Industries, LTD (MHI) and Mitsubishi Heavy Industries of America (MHIA) claims relating to work performed on the projects prior to the settlement, and has indemnified Exelon, Generation, their affiliates and the lenders from certain subcontractor claims relating to the projects. In return, Exelon, Generation, their affiliates and the lenders released all of their claims against Raytheon. All litigation by and between Raytheon, MHI, MHIA and the project companies relating to the projects has been dismissed. Raytheon has also ceased all construction activities related to the Mystic 8 and 9 and Fore River generating facilities and assigned subcontracts to the project companies, and will cooperate with the transition of construction to a new contractor. In the event that the transfer of plant operations and power marketing activities are not completed by September 1, 2004, under the settlement documents among Exelon and the lenders, Generation will be reimbursed for the $32.5 million paid in connection with the settlement through a first claim against any payments otherwise payable to the lenders on account of their interests in the projects.
Oyster Creek. On April 7, 2004, AmerGen entered into settlements with the State of New Jersey relating to an environmental incident on September 23, 2002 at Oyster Creek. The incident resulted in a fishkill from heated water discharged from the plant. The State alleged that the plant had violated its water discharge permit. The settlements with the State of New Jersey settled all claims without any admission of liability for payments aggregating $1 million.
Exelon, ComEd, PECO and Generation are involved in various other litigation matters that are being defended and handled in the ordinary course of business. Exelon, ComEd, PECO and Generation maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate
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outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on their respective financial condition, results of operations or cash flows.
Dynegy. Generation is counterparty to Dynegy, Inc. (Dynegy) in various energy transactions. The credit ratings of Dynegy are below investment grade. As of June 30, 2004, Generation has credit risk associated with Dynegy through Generation’s investment in Sithe. Sithe is a 100% owner of the Independence generating station, a 1,028-MW gas-fired facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of March 31, 2004, Generation consolidated the assets and liabilities of Sithe in accordance with the provisions of FIN No. 46-R. As a result, Generation has recorded an asset of $114 million on its Consolidated Balance Sheets related to the fair market value of the financial swap agreement with Dynegy that is marked-to-market under the terms of SFAS No. 133, “Accounting for Derivatives and Hedging Activities.” If Dynegy were unable to fulfill the terms the financial swap agreement, Generation would be required to impair the related asset. Exelon estimates, as a 50% owner of Sithe, that the impairment would result in an after-tax reduction of its net income of approximately $21 million.
In addition to the asset impairment, if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation would likely incur an impairment of the intangible asset associated with the tolling agreement associated with the Independence plant. Depending upon the timing of Dynegy’s failure to fulfill its obligations and the outcome of any restructuring initiatives, Generation could realize an after-tax charge of up to $50 million. In the event of a sale of Generation’s investment in Sithe to a third party, proceeds from the sale could be negatively affected by up to $84 million, which would represent an after-tax loss of up to $50 million. Additionally, the future economic value of AmerGen’s purchased power arrangement with Illinois Power Company (Illinois Power), a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. In February 2004, Dynegy announced an agreement to sell Illinois Power to a third party, which, upon closing of the transaction, would reduce Generation’s credit risk associated with Dynegy.
ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. ComEd and PECO previously made refundable prepayments to the tax consultant of $11 million and $5 million, respectively. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds to be recovered from the IRS, if any. The ultimate net cash outflow to ComEd and PECO related to all the agreements will either be positive or neutral depending upon the outcome of the refund claims with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (Merger), would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. ComEd and PECO cannot predict the timing of the final resolution of the refund claims.
During the three months ended June 30, 2004, the IRS granted preliminary approval for one of ComEd’s refund claims. As such, ComEd believes that it is probable that a fee will ultimately be paid to the tax consultant. Therefore, ComEd has recorded an expense of $5 million (pretax), which resulted in a decrease to the prepayment from $11 million to $6 million. The charge represents an estimate of the fee to the tax
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consultant which may be adjusted upward or downward depending on the IRS’ final calculation of the tax and interest benefit. ComEd has not reflected the tax benefit associated with the refund claim pending final approval of the IRS. However, as described above, the net income statement impact for ComEd is not anticipated to be material.
On January 28, 2004, the NRC issued a letter requesting PSE&G to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSE&G responded to the letter on February 28, 2004, and had independent assessments of the work environment at the facility performed. Assessment results were provided to the NRC in May. The assessments concluded that Salem was safe for continued operation, but also identified issues that need to be addressed. At an NRC public meeting on June 16, 2004, PSE&G outlined its action plans to address these issues, which focus on safety conscious work environment, the corrective action program, and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004.
In June 2001, the NJDEP issued a renewed NPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published FWPCA Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless the agency grants additional time to collect information to comply with the new regulations. NJDEP advised PSE&G in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSE&G has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations require the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit would result in material costs of compliance to the owners of the facility.
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The following tables provide additional information regarding the regulatory assets and liabilities of ComEd and PECO:
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The following tables provide supplemental balance sheet information as of June 30, 2004 and December 31, 2003:
Exelon operates in three business segments: Energy Delivery (ComEd and PECO), Generation and Enterprises. Exelon evaluates the performance of its business segments on the basis of net income.
ComEd, PECO and Generation each operate in a single business segment; as such, no separate segment information is provided for these registrants.
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Exelon’s segment information for the three months ended June 30, 2004 and 2003 is as follows:
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Exelon’s segment information for the six months ended June 30, 2004 and 2003 and at June 30, 2004 and December 31, 2003 is as follows:
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Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding, LLC and ComEd Transitional Funding Trust were deconsolidated from the financial statements of Exelon and ComEd in conjunction with the adoption of FIN No. 46-R. Prior periods were not restated in accordance with FIN No. 46-R.
The financial statements of Exelon and ComEd include related-party transactions with its unconsolidated affiliates as presented in the tables below.
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In addition to the transactions described above, ComEd’s financial statements include related-party transactions as presented in the tables below.
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Effective July 1, 2003, PECO Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements of Exelon and PECO in conjunction with the adoption of FIN No. 46. Additionally, effective December 31, 2003, PECO Trust III and the PETT were deconsolidated from the financial statements of Exelon and PECO in conjunction with the adoption of FIN No. 46-R. Prior periods were not restated.
The financial statements of Exelon and PECO include related-party transactions with unconsolidated financing subsidiaries as presented in the tables below.
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In addition to the transactions described above, PECO’s financial statements include related-party transactions as presented in the tables below.
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The financial statements of Exelon and Generation include related-party transactions with unconsolidated affiliates as presented in the tables below. Generation accounted for its investment in AmerGen as an equity method investment prior to the acquisition of British Energy’s 50% interest in December 2003 and its investment in Sithe as an equity method investment prior to its consolidation as of March 31, 2004. Additionally, effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation.
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an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services at cost.
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At June 30, 2004, Exelon Corporate, along with ComEd, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. The terms of the new facilities are consistent with the previous facilities. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon Corporate, ComEd, PECO and Generation and to issue letters of credit.
In July 2004, Exelon purchased an interest in a limited partnership that indirectly owns four synthetic fuel-producing facilities. Exelon’s purchase price for these facilities included a combination of cash, a note payable and contingent consideration dependent upon the production levels of the facilities. These facilities are not consolidated within Exelon’s financial statements because Exelon does not have a controlling financial interest in these facilities. The note payable recorded for the purchase of the facilities was $22 million. Exelon’s right to acquire its share of tax credits generated by the facilities was recorded as an intangible asset and will be amortized as the tax credits are earned. Private letter rulings have been received by the partnership that indicate these facilities qualify for tax credits under Section 29 of the Internal Revenue Code.
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(Dollars in millions except per share data, unless otherwise noted)
General
Exelon Corporation (Exelon), a registered public utility holding company, through its subsidiaries, operates in three business segments:
See Note 17 of the Combined Notes to Consolidated Financial Statements for further segment information. Exelon’s corporate operations, through its business services subsidiary, Exelon Business Services Company (BSC), provide the business segments a variety of support services, including legal, human resources, financial, information technology, supply management and corporate governance services. Additionally, in 2004, due to the centralization of certain functions, certain employees were transferred from ComEd and PECO to BSC. As a result, ComEd and PECO now receive additional services from BSC, including planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems, and management of other support services. These costs are allocated to the business segments. Additionally, the results of Exelon’s corporate operations include costs for strategic long-term planning, certain governmental affairs, and interest costs and income from various investment and financing activities.
Critical Accounting Policies and Estimates
Management of each of the registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in the 2003 Form 10-K for a discussion of the estimates and judgments necessary in the registrants’ accounting for derivative instruments, regulatory assets and liabilities, nuclear decommissioning, depreciable lives of property, plant and equipment, asset impairments, severance accounting, defined benefit pension and other postretirement welfare benefits, taxation, unbilled energy revenues and environmental costs. Set forth below is an update to the 2003 Form 10-K.
Exelon, through Generation, has a 50% interest in Sithe. In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), Exelon and Generation consolidated Sithe within their financial statements as of March 31, 2004. The determination that Sithe qualified as a variable interest entity and that
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In addition to Sithe, management reviewed other entities with which Exelon and its subsidiaries have business relationships to determine if those entities were variable interest entities that should be consolidated under FIN No. 46-R and concluded that those entities should not be consolidated within the financial statements of Exelon, ComEd, PECO and Generation.
New Accounting Pronouncements
See Note 2 of the Combined Notes to Consolidated Financial Statements for discussion of new accounting pronouncements.
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Executive Overview
Financial Results.Exelon’s diluted earnings per average common share increased by 37% for the three months ended June 30, 2004 as compared to the same period in 2003, primarily as a result of decreased losses at Enterprises, an increase in net income at Generation and favorable tax effects from investments in synthetic fuel-producing facilities. Enterprises recorded a gain on the sale of Exelon Thermal Holdings, Inc. (Exelon Thermal) of $36 million (before income taxes and net of debt prepayment penalties), while Enterprises’ 2003 income reflected a goodwill impairment charge of $47 million (before income taxes) and investment-related impairment charges of $35 million (before income taxes). The increase in Generation’s net income reflects an $85 million gain (before income taxes) on the sale of Boston Generating, LLC (Boston Generating) during the second quarter of 2004. Exelon’s investments in synthetic fuel-producing facilities provided a tax benefit of $48 million and increased Exelon’s net income for the three months ended June 30, 2004 by $15 million.
Exelon’s diluted earnings per average common share increased by 25% for the six months ended June 30, 2004 as compared to the same period in 2003, primarily as a result of decreased losses at Enterprises, an increase in net income at Generation and favorable tax effects from investments in synthetic fuel-producing facilities. Enterprises results were affected by the 2004 gain recorded on the sale of Thermal and the 2003 goodwill and investment impairment charges discussed above. The increase in Generation’s net income reflects a 2003 impairment charge of $200 million (before income taxes) related to Generation’s investment in Sithe and an $85 million gain (before income taxes) on the sale of Boston Generating during the second quarter of 2004. In the first quarter of 2004, Exelon recorded an after-tax gain of $32 million in accordance with FIN No. 46-R and the resulting consolidation of Sithe. In the first quarter of 2003, Exelon recorded an after-tax gain of $112 million upon the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Asset Retirement Obligations” (SFAS No. 143).
The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Exelon — Executive Summary” in the 2003 Form 10-K for a discussion of Exelon’s implementation of The Exelon Way.
Investment Strategy.Exelon continued to follow a disciplined approach in investing to maximize the earnings and cash flows from its assets and businesses and to divest those assets and businesses that do not meet its goals. Highlights in the first half of 2004 include:
Enterprises continues to pursue the divestiture of other businesses and investments; however, it may be unable to fully divest certain businesses and investments for a number of reasons, including an inability to locate appropriate buyers or negotiate acceptable terms for the transactions. In addition, the amount that Enterprises may realize from a divestiture is subject to market conditions that may contribute to pricing and other terms that are materially less than expected and could result in a loss on the sale. Timing of any divestitures may positively or negatively affect the results of operations. As of June 30, 2004, Enterprises had total assets and liabilities of $592 million and $200 million, respectively.
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Financing Activities. Exelon made payments of approximately $345 million for the purpose of retiring PECO and ComEd transition trust long-term debt and repaid approximately $237 million of other net long-term debt during the six months ended June 30, 2004. Exelon met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions. In January 2004, Exelon announced a 10% increase in its quarterly dividend on its common stock and approved a 2-for-1 split of its common stock. The distribution date was May 5, 2004. The share and per-share amounts included in this Form 10-Q have been adjusted for all periods presented to reflect the stock split. In the second quarter of 2004, Exelon’s Board of Directors approved a discretionary share repurchase program. Exelon purchased common stock, held as treasury shares as of June 30, 2004, totaling $75 million during the second quarter of 2004. Exelon also replaced its $750 million 364-day unsecured revolving credit agreement with a $1 billion five-year facility and reduced its $750 million three-year facility to $500 million in a transaction that closed on July 16, 2004.
Regulatory Developments. On May 1, 2004, ComEd fully integrated its transmission facilities into PJM Interconnection (PJM). PECO and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of electric energy and capacity. Upon joining PJM, ComEd began incurring administrative fees, which are expected to approximate $30 million annually. Exelon believes such costs will ultimately be partially offset by the benefits of full access to a wholesale competitive marketplace, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on Exelon.
ComEd currently earns approximately $66 million annually from through and out (T&O) rates for energy flowing across ComEd’s transmission system. On March 19, 2004, the Federal Energy Regulatory Commission (FERC) issued an order to eliminate these rates effective May 1, 2004, which was subsequently deferred until December 1, 2004. The T&O rates are to be replaced by a new long-term transmission pricing structure that will eliminate seams in the PJM and Midwest ISO regions. Transmission owners in PJM and Midwest ISO and other parties must file one or more pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. While Exelon and ComEd cannot predict the outcome of the FERC’s final determination of a new long-term transmission pricing structure, such pricing structure could adversely impact Exelon’s and ComEd’s results of operations.
See ComEd’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Executive Overview” for further information regarding Regulatory Developments.
Operations.Generation’s nuclear fleet achieved a 93.3% capacity factor for the six months ended June 30, 2004 compared to 94.2% in the same period of 2003 primarily as a result of increased planned outage days.
Outlook for the Remainder of 2004 and Beyond. Exelon’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Exelon — Executive Summary” in the 2003 Form 10-K.
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Results of Operations — Exelon Corporation
Operating Revenues. Operating revenues decreased for the three months ended June 30, 2004 as compared to the same period in 2003 primarily due to decreased revenues at Enterprises due to the sale of the majority of the businesses of InfraSource, Inc. (InfraSource) during the third quarter of 2003, decreased competitive transition charge (CTC) collections at ComEd and Generation’s adoption of Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’ ” (EITF 03-11) in 2004. Generation’s adoption of EITF 03-11 during 2004 changed the presentation of certain power transactions and decreased operating revenues by $239 million for the three months ended June 30, 2004 but had no effect on net income. The decreases in operating revenues were partially offset by higher delivery volume and favorable weather conditions at Energy Delivery and an increase in market sales at Generation due to the acquisition of the remaining 50% of AmerGen Energy Company, LLC (AmerGen) and the consolidation of Sithe. See further discussion of operating revenues by segment below.
Purchased Power and Fuel Expense.Purchased power and fuel expense decreased during the three months ended June 30, 2004 as compared to the same period in 2003 primarily due to Generation’s adoption of EITF 03-11 during 2004, which resulted in a decrease in purchased power and fuel expense of $239 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense. Purchased power represented 23% of Generation’s total supply for the three months ended June 30, 2004 compared to 36% for the same period in 2003. See further discussion of purchased power and fuel expense by segment below.
Operating and Maintenance Expense. Operating and maintenance expense decreased for the three months ended June 30, 2004 as compared to the same period in 2003 primarily due to decreased expenses at Enterprises due to the sale of the majority of the businesses of InfraSource during the third quarter of 2003 and a goodwill impairment charge recorded during 2003, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen, the consolidation of Sithe and increased costs at Boston Generating. Investments made by Exelon in the fourth quarter of 2003 in synthetic fuel-producing facilities increased operating and maintenance expense by $24 million. See further discussion of operating and maintenance expenses by segment below.
Operating Income. The change in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was primarily the result of increased depreciation expense due to additional plant placed in service after the second quarter of 2003 and increased amortization expense due to investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. Taxes other than income were higher in 2004 as compared to 2003, primarily at Energy Delivery, as a result of a refund of Illinois Electricity Distribution taxes at ComEd and the reversal of a use tax accrual resulting from an audit settlement at PECO, both in 2003.
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Other Income and Deductions. Other income and deductions changed primarily due to 2004 gains on the sales of Boston Generating and Exelon Thermal and 2003 investment impairments of $35 million recorded by Enterprises. Equity in earnings of unconsolidated affiliates decreased by $46 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. Interest expense and distributions on preferred securities of subsidiaries collectively increased $17 million, primarily due to increased interest expense at Generation.
Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 37% for the three months ended June 30, 2003 to 31% for the same period in 2004, primarily due to investments made in synthetic fuel-producing facilities during the fourth quarter of 2003. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Exelon evaluates its performance on a business segment basis. The comparisons of operating results and other statistical information for the three months ended June 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.
n.m. — not meaningful
Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. The information for the three months ended June 30, 2003 related to the Enterprises and Generation segments discussed below has not been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy Company’s results for the three months ended June 30, 2003 were as follows:
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Operating Revenues.The changes in Energy Delivery’s operating revenues for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Volume. Both ComEd’s and PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large commercial and industrial customers for ComEd and across all customer classes for PECO.
ComEd’s Integration into PJM. Energy Delivery’s operating revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. The increases relate to the change in control of the transmission assets from ComEd to PJM as a result of which ComEd receives revenues for its proportionate share of the transmission revenues generated by PJM, but also pays PJM for the use of its transmission assets. This is consistent with how PECO accounts for its PJM transmission revenues and expenses. For 2004, ComEd’s operating revenues are estimated to increase by approximately $180 million, offset by a corresponding and equal increase in purchased power expense. Starting in 2005, on an annual basis, ComEd’s operating revenues and purchased power expense are estimated to increase between $200 to $250 million. However, there is no expected effect on revenues net of purchased power expense.
Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. Energy Delivery’s electric revenues were positively affected by favorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 68% and 66% higher, respectively. Heating degree-days in the ComEd and PECO service territories were 18% lower and 32% lower, respectively.
Energy Delivery’s gas revenues were negatively affected by unfavorable weather conditions.
Rate Changes and Mix. ComEd’s CTC is reset in the second quarter of each year to reflect market price adjustments. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component decreased the collection of CTCs as compared to the
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Decreased average rates paid by ComEd’s residential customers resulted in a $10 million decrease in revenues. Although residential rates are frozen through 2006, ComEd’s average effective residential rates fluctuate due to the usage patterns of customers.
Electric revenues increased $17 million at PECO as a result of $12 million of favorable rate mix due to changes in monthly usage patterns in all customer classes and $5 million related to a scheduled phase-out of merger-related rate reductions. In connection with the Pennsylvania Public Utility Commission’s (PUC) approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005.
Energy Delivery’s gas revenues reflect increases in rates through PUC approved changes to the purchased gas adjustment clause that became effective June 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for the three months ended June 30, 2004 was 30% higher than the rate for the same period in 2003. PECO’s purchased gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. PECO has asked the PUC for a decrease in its rates through the purchased gas adjustment clause effective December 1, 2004 as a result of lower current gas costs. This proposed decrease would have no impact on PECO’s operating income.
Customer Choice. For the three months ended June 30, 2004 and 2003, 29% and 25%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by alternative electric suppliers (AES) or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $51 million from customers in Illinois electing to purchase energy from an AES or under ComEd’s PPO and a decrease in revenues of $16 million from customers in Pennsylvania being assigned to or selecting an AES.
Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Volume. ComEd’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather and customer choice, in the number of customers and average usage per customer, primarily residential and large commercial and industrial customers. PECO’s electric purchased power and fuel expense increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to increased customer growth and usage per customer across all customer classes.
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ComEd’s Integration into PJM. Energy Delivery’s operating revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.
Prices. Energy Delivery’s electric purchased power increased primarily due to an increase at PECO as a result of higher wholesale market prices associated with certain large commercial and industrial customers whose billing rates are tied to wholesale market prices for energy. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.
Weather. Energy Delivery’s purchased power and fuel expense increased due to the effect of favorable weather conditions.
Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an AES or ComEd’s PPO and PECO’s residential and small commercial and industrial customers selecting or being assigned to purchase energy from an AES.
Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $7 million at PECO and increased depreciation of $5 million due to capital additions across Energy Delivery.
Operating Income. The change in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was the result of increased taxes other than income. This increase was primarily attributable to $12 million related to the reversal of a PECO use tax accrual resulting from an audit settlement in 2003 and a 2003 ComEd refund of $5 million for Illinois Electricity Distribution Taxes.
Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments.
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Energy Delivery’s electric sales statistics and revenue detail were as follows:
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Energy Delivery’s gas sales statistics and revenue detail were as follows:
Operating Revenues. The changes in Generation’s operating revenues for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Retail Gas Revenue.Retail gas revenue increased $84 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.
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Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the three months ended June 30, 2004 compared to the same period in 2003, consisted of the following:
The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. See Note 2 of the Combined Notes to Consolidated Financial Statements for further discussion of EITF 03-11. The sale of Boston Generating in May 2004 resulted in less revenues from this entity compared to the same period in the prior year. The acquisition of Exelon Energy and AmerGen resulted in increased wholesale and retail electric sales of approximately $104 million compared to the same period in the prior year.
The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, and in the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.
Electric Revenue from Affiliates. Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004 as a result of which sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the three months ended June 30, 2003 was $44 million.
The decrease in revenue from sales to affiliates was partially offset by $15 million in higher sales to Energy Delivery. The higher sales to Energy Delivery were primarily due to overall increased usage per customer and favorable weather conditions.
Other. Certain other revenues increased for the three months ended June 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s operations beginning April 1, 2004.
Purchased Power and Fuel Expense. The changes in Generation’s purchased power and fuel expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $238 million and fuel expense of $1 million.
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Boston Generating.The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding Boston Generating.
Midwest Generation.The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation.
AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $97 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense.
Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $86 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results.
Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).
Sithe Energies, Inc.Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of Sithe.
Price. The increase reflects higher market energy prices due to increased natural gas, oil and coal prices.
Hedging Activity.Mark-to-market gains on hedging activities were $21 million for the three months ended June 30, 2004 compared to gains of $32 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating accounted for a gain of $6 million and hedging activities relating to other Generation operations in 2004 accounted for a gain of $15 million.
Other. Other decreases in purchased power and fuel expense were primarily due to $21 million of lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM during the second quarter of 2004 and $10 million of nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.
The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen, Exelon Energy Company and Sithe in Generation’s consolidated financial results for 2004. The increase in operating and maintenance expenses attributable to Boston Generating was due to the Mystic 8 and 9 and Fore River facilities commencing commercial operation at the end of the second quarter of 2003 and in the third quarter of 2003, respectively, which more than offset the reduction in operating and maintenance expenses resulting
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Depreciation and Amortization. The increase in depreciation and amortization expense for the three months ended June 30, 2004 as compared to the same period in 2003 includes the impact of capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities as the assets were classified as held for sale during the period.
Effective Income Tax Rate. The effective income tax rate was 38% for the three months ended June 30, 2004 compared to 39% for the same period in 2003. This decrease is primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe which resulted in a pre-tax loss. This impairment charge was taxed at a rate different than the overall generation effective income tax rate. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Generation’s sales and the supply of these sales, excluding the trading portfolio, were as follows:
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Trading volumes of 5,324 GWhs and 7,919 GWhs for the three months ended June 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.
Generation’s supply mix changed primarily as a result of the sale of Boston Generating in May 2004.
Generation’s average margin and other operating data for the three months ended June 30, 2004 and 2003 were as follows:
Generation’s average margin, excluding the trading portfolio, increased primarily due to decreased average supply cost as a result of forward hedging of fuel at lower costs during the three months ended June 30, 2004 as compared to the same period in the prior year. Also, Generation experienced a decrease in purchased power due to reducing the capacity purchased from Midwest Generation and the affect of acquiring the remaining 50% of AmerGen in 2003. The increase in nuclear generation during the quarter, which is
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Higher nuclear capacity factors and lower nuclear production costs were primarily due to nine fewer planned refueling outage days, resulting in a $14 million decrease in planned outage costs for the three months ended June 30, 2004 as compared to the same period in 2003. There was one planned refueling outage that began in late March 2004 and was completed during the three months ended June 30, 2004, while there was one refueling outage that began and was completed during the three months ended June 30, 2003. The three months ended June 30, 2004 included seven unplanned outages compared to nine unplanned outages during the same period in 2003.
In the three months ended June 30, 2004 as compared to the three months ended June 30, 2003, the Quad Cities units operated at pre-Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.
Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. Enterprises’ results for the three months ended June 30, 2004 compared to the three months ended June 30, 2003 were significantly affected by the following transactions:
InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource.
Exelon Energy Company. Effective January 1, 2004, the operations and assets of Enterprises’ competitive retail sales business, Exelon Energy Company, were transferred to Generation. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of this transfer.
Exelon Services, Inc. During the three months ended June 30, 2004, Enterprises disposed of certain businesses of Services, including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale recorded during the three months ended June 30, 2004 related to the disposition of these Services businesses were $16 million and $12 million,
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In addition, during the three months ended June 30, 2004, Enterprises disposed of the following business and investment. These dispositions and the transactions described above will affect Enterprises future results of operations.
Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Exelon Thermal for proceeds of $134 million, subject to working capital adjustments. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, which resulted in prepayment penalties of $9 million, which were recorded as interest expense. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income.
PECO Telcove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003.
Operating Revenues. The changes in Enterprises’ operating revenues for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Purchased Power and Fuel Expense. Purchased power and fuel expense decreased as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004.
Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
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Depreciation and Amortization. Depreciation and amortization expense decreased primarily as a result of the sale of the majority of the InfraSource businesses in the third quarter of 2003 and property, plant and equipment classified as held for sale.
Other Income and Deductions. The increase in other income and deductions was primarily due to 2004 gains on the sales of Exelon Thermal, the Services businesses and Enterprises’ investment in PECO Telcove of an aggregate of $66 million (before income taxes and debt prepayment penalties) and income of $18 million recorded during the second quarter of 2004 related to the collection of a note receivable prior to its maturity. Other income and deductions in 2003 included impairment charges of energy-related and communications investments of $35 million.
Effective Income Tax Rate. The effective income tax rate was 47% for the three months ended June 30, 2004 compared to 36% for the same period in 2003. The increase in the effective tax rate was primarily attributable to state tax impact on the Thermal divestiture and tax adjustments resulting from various income tax related items.
Operating Revenues. Operating revenues decreased for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to decreased revenues at Enterprises due to the sale of the majority of the businesses of InfraSource during the third quarter of 2003 and Generation’s adoption of EITF 03-11 in the first quarter of 2004 which changed the presentation of certain power transactions and decreased operating revenues by $452 million. The adoption of EITF 03-11 had no impact on net income. See further discussion of operating revenues by segment below.
Purchased Power and Fuel Expense.Purchased power and fuel expense decreased during the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to Generation’s adoption of EITF 03-11 during 2004 which resulted in a decrease in purchased power expense and fuel expense of $452 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense, and the consolidation of Sithe. Purchased power represented 23% of Generation’s total supply for the six months ended June 30, 2004 compared to 36% for the same period in 2003. See further discussion of purchased power and fuel expense by segment below.
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Operating and Maintenance Expense. Operating and maintenance expense decreased slightly for the six months ended June 30, 2004 as compared to the same period in 2003 primarily due to decreased expenses at Enterprises due to the sale of the majority of the businesses of InfraSource during the third quarter of 2003 and decreased expenses at Energy Delivery due to a charge recorded in 2003 related to an agreement with various Illinois retail market participants and other interested parties, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen and generating assets placed in service after the first quarter of 2003. Operating and maintenance expense increased $48 million due to investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. See further discussion of operating and maintenance expenses by segment below.
Operating Income. The slight decrease in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was primarily due to an increase of $67 million in depreciation expense and increased taxes other than income at Energy Delivery. The increase in depreciation and amortization expense was primarily related to assets placed in service after the second quarter of 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities.
Other Income and Deductions. Other income and deductions changed primarily due to an impairment charge of $200 million (before income taxes) recorded during the first quarter of 2003 related to Generation’s investment in Sithe, an $85 million gain (before income taxes) on the sale of Boston Generating and a $36 million gain on the sale of Exelon Thermal (before income taxes and net of debt prepayment penalties). Equity in earnings of unconsolidated affiliates decreased by $88 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. Interest expense and distributions on preferred securities of subsidiaries collectively increased $6 million, primarily due to increased interest expense at Generation, partially offset by lower outstanding debt and refinancings at lower rates at Energy Delivery.
Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 37% for the six months ended June 30, 2003 to 30% for the same period in 2004, primarily due to investments made in synthetic fuel-producing facilities during the fourth quarter of 2003. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Cumulative Effect of Changes in Accounting Principles. Net income for the six months ended June 30, 2004 reflects income of $32 million, net of income taxes, related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, while net income for the six months ended June 30, 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN No. 46-R and SFAS No. 143.
The comparisons of operating results and other statistical information for the six months ended June 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.
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Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. The information for the six months ended June 30, 2003 related to the Enterprises and Generation segments discussed below has not been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy Company’s results for the six months ended June 30, 2003 were as follows:
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Operating Revenues.The changes in Energy Delivery’s operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
ComEd’s Integration into PJM. Energy Delivery’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.
Rate Changes and Mix. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component decreased the collection of CTCs as compared to the respective prior year period. As a result, ComEd’s CTC revenues decreased by $120 million for the six months ended June 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under ComEd’s PPO by $47 million.
Customer Choice. For the six months ended June 30, 2004 and 2003, 28% and 24%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by an AES or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $107 million from customers in Illinois electing to purchase energy from an AES or ComEd’s PPO and a decrease in revenues of $42 million from customers in Pennsylvania being assigned to or selecting an AES.
For the six months ended June 30, 2004 and June 30, 2003, ComEd collected approximately $87 million and $207 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy
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Electric revenues increased $2 million at PECO as a result of $9 million related to a scheduled phase-out of merger-related rate reductions, largely offset by a $7 million decrease reflecting a change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 as compared to 2003. In connection with the PUC’s approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005
Energy Delivery’s gas revenues increased due to increases in rates through PUC approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for the six months ended June 30, 2004 was 39% higher than the rate for the same period in 2003.
Weather. Energy Delivery’s electric revenues were affected by favorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 68% higher and 66% higher, respectively, for the six months ended June 30, 2004 as compared to the same period in 2003. Heating degree-days were 8% lower in both the ComEd and PECO service territories for the six months ended June 30, 2004 as compared to the same period in 2003.
Energy Delivery’s gas revenues were affected by unfavorable weather conditions.
Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Prices. Energy Delivery’s purchased power expense remained constant. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.
Volume. ComEd’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather and customer choice, in the number of customers and average usage per customer, primarily residential and large commercial and industrial customers at ComEd. PECO’s electric purchased power and fuel expense increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to increased customer growth and usage per customer across all customer classes.
ComEd’s Integration into PJM. Energy Delivery’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.
Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an AES or
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Weather. Energy Delivery’s purchased power and fuel expense were affected by unfavorable weather conditions.
Operating and Maintenance Expense. The changes in operating and maintenance expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $14 million at PECO and increased depreciation of $10 million due to capital additions across Energy Delivery.
Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments and refinancings at lower rates.
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Operating Revenues. The changes in Generation’s operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Retail Gas Revenue.Retail gas revenue increased as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.
Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company’s assets and operations to Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the six months ended June 30, 2003 was $108 million.
The decrease in revenue from affiliates included $40 million in lower sales to Energy Delivery. The lower sales to Energy Delivery were primarily due to customers purchasing energy from alternative electric suppliers and unfavorable weather conditions in the ComEd and PECO service territories compared to the prior year.
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Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the six months ended June 30, 2004 compared to the same period in 2003, consisted of the following:
The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004.
Other. Certain other revenues increased for the six months ended June 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s results of operations beginning April 1, 2004.
Purchased Power and Fuel Expense. The changes in Generation’s purchased power and fuel expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Effects of the Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power expense of $444 and fuel expense of $8 million.
Midwest Generation.The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.
Price. The decrease primarily reflects lower average fossil fuel costs of $47 million during the six months ended June 30, 2004 as compared to the same period in 2003.
Volume. Generation experienced increased purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).
AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $160 million. In prior periods,
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Boston Generating.The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May of 2004. The Mystic 8 and 9 generating facilities began commercial operations at the end of the second quarter of 2003, and the Fore River generating facilities began commercial operations during the third quarter of 2003.
Hedging Activity.Mark-to-market losses on hedging activities were $18 million for the six months ended June 30, 2004 compared to gains of $1 million for the same period in 2003. Hedging activities in 2004 related to Boston Generating operations accounted for a gain of $4 million and hedging activities for other Generation operations in 2004 accounted for a loss of $22 million.
Other. Other decreases in purchased power and fuel were primarily due to $46 million in lower transmission expense resulting from reduced inter-region transmission as a result of ComEd’s integration into PJM in the second quarter of 2004, offset by $16 million of nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.
Depreciation and Amortization.The increase in depreciation and amortization expense for the six months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to the impact of capital additions and the consolidation of Sithe Energies, AmerGen, and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities as the assets were classified as held for sale during the period.
Effective Income Tax Rate. The effective income tax rate was 38% for the six months ended June 30, 2004 compared to 44% for the same period in 2003. The decrease was primarily attributable to the impairment charge recorded in 2003 related to Generation’s investment in Sithe that resulted in a pre-tax loss. The impairment charge was taxed at a rate different than the overall Generation effective tax rate. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Cumulative Effect of Changes in Accounting Principles. The cumulative effect of changes in accounting principles recorded during the six months ended June 30, 2004 and 2003 included $32 million, net of income taxes, recorded in 2004 related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from
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Trading volumes of 10,437 GWhs and 17,446 GWhs for the six months ended June 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.
Generation’s supply mix changed as a result of increased fossil generation due to Boston Generating’s Mystic units 8 and 9 and Fore River generating facilities becoming operational in the second and third quarter of 2003, which in total account for an increase of 2,688 GWhs.
Generation’s average margin and other operating data for the six months ended June 30, 2004 and 2003 were as follows:
Generation’s average margin, excluding the trading portfolio, increased primarily due to decreased average supply cost as a result of forward hedging of fuel at lower costs than prior periods. Also, Generation experienced a decrease in purchased power due to reducing the capacity purchased from Midwest Generation and the impact of consolidating AmerGen in 2003. The increase in nuclear generation during the period, which is generally less expensive than purchased power, along with the effect of the adoption of EITF 03-11, contributed to the increase in average margin. The increase in nuclear generation is due primarily to the consolidation of AmerGen.
Lower nuclear capacity factors and increased nuclear production costs were primarily due to 55 additional planned refueling outage days, resulting in a $46 million increase in planned outage costs in the six months ended June 30, 2004 as compared to the same period in 2003. There were five planned outages during the six months ended June 30, 2004, compared to three planned outages during the same period in 2003. The six months ended June 30, 2004 included twelve unplanned outages compared to eleven unplanned outages during the same period in 2003. Nuclear capacity factors were also affected by Quad Cities operating at lower than anticipated capacity levels.
The Quad Cities units have intermittently been operating at pre-EPU generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.
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Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. Enterprises’ result for the six months ended June 30, 2004 compared to the six months ended June 30, 2003 were significantly affected by the following transactions:
Exelon Services, Inc. During the six months ended June 30, 2004, Enterprises disposed of certain businesses of Services, including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale recorded during the six months ended June 30, 2004 related to the disposition of these Services businesses were $34 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of June 30, 2004, Services had assets and liabilities of $58 million and $90 million, respectively, which primarily represented the corporate operations and the remaining businesses of the Mechanical and Integrated Technology Group.
In addition, during the six months ended June 30, 2004, Enterprises disposed of the following business and investment. These dispositions and the transactions described above will affect Enterprises future results of operations.
Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Thermal for proceeds of $134 million, subject to working capital adjustments. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, which resulted in prepayment penalties of $9 million, which were recorded in interest expense. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income.
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Operating Revenues. The changes in Enterprises’ operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Other Income and Deductions. The increase in other income and deductions was primarily due to 2004 gains on the sale of Exelon Thermal and Enterprises’ investment in PECO Telcove of $54 million (before income taxes and net of debt prepayment penalties) and income of $18 million recorded during the second quarter of 2004 related to the collection of a note receivable prior to its maturity. Other income and deductions in 2003 included impairment charges of energy, software and communications investments of $40 million.
Effective Income Tax Rate. The effective income tax rate was 58% for the six months ended June 30, 2004 compared to 38% for the same period in 2003. The increase in the effective tax rate was primarily attributable to state tax impact on the Thermal divestiture and a 16.4% increase of tax expense resulting from various income tax related items.
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Liquidity and Capital Resources
Exelon’s businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from Energy Delivery’s and Generation’s operations. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon’s access to external financing at reasonable terms depends on Exelon and its subsidiaries’ credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Exelon no longer has access to the capital markets at reasonable terms, Exelon has access to revolving credit facilities with aggregate bank commitments of $1.5 billion that it currently utilizes to support its commercial paper programs. See the “Credit Issues” section of “Liquidity and Capital Resources” for further discussion. Exelon primarily uses its capital resources to fund capital requirements, including construction, to repay maturing debt, to pay common stock dividends, to fund its pension obligations and to invest in new and existing ventures. Future acquisitions that Exelon may undertake may require external financing, which might include issuing Exelon common stock.
Energy Delivery’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the third quarter. Energy Delivery’s future cash flows will be affected by its ability to achieve cost savings in operations and the impact of the economy, weather, customer choice and future regulatory proceedings on its revenues. Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Energy Delivery. Generation’s future cash flows from operating activities will be affected by future demand and market prices for energy and its ability to continue to produce and supply power at competitive costs.
Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements for the foreseeable future. Operating cash flows after 2006 could be negatively affected by changes in the rate regulatory environments of ComEd and PECO, although any effects are not expected to hinder Exelon’s ability to fund its business requirements.
Cash flows from operations for the six months ended June 30, 2004 and 2003 were $1,907 million and $1,292 million, respectively. Changes in Exelon’s cash flows from operations are generally consistent with changes in its results of operations, and further adjusted by changes in working capital in the normal course of business.
In addition to the items mentioned in “Results of Operations,” the following items affected Exelon’s operating cash flows for the six months ended June 30, 2004 and 2003:
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Exelon expects to contribute up to approximately $419 million to its pension plans in 2004. These contributions exclude benefit payments expected to be made directly from corporate assets. Of the $419 million expected to be contributed to the pension plans during 2004, $11 million is estimated to be needed to satisfy Internal Revenue Service (IRS) minimum funding requirements.
Exelon, through its ComEd subsidiary, 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 June 30, 2004, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s Consolidated Balance Sheets with the majority allocated to the Consolidated Balance Sheets of ComEd and the remainder to the Consolidated Balance Sheets of Generation. The 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. Any required payments could be significant to the cash flows of Exelon. Exelon’s management believes Exelon’s reserve for interest, which has been established in the event that such positions are not sustained, has been appropriately recorded in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5). However, the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.
Cash flows used in investing activities for the six months ended June 30, 2004 and 2003 were $669 million and $1,016 million, respectively. The $347 million reduction of cash used in investing activities in 2004 versus 2003 is primarily attributable to the following:
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Capital expenditures by business segment for the six months ended June 30, 2004 and 2003 were as follows:
Energy Delivery’s capital expenditures for the six months ended June 30, 2004 reflect continuing efforts to improve the reliability of its transmission and distribution systems and capital additions to support new business and customer growth. ComEd estimates that it will spend up to approximately $715 million in total capital expenditures for 2004. This represents an increase of approximately $100 million more than had been previously planned, primarily as a result of expansion of the ComEd distribution system to support new business and customer growth. However, Exelon is continuing to evaluate its total capital spending requirements and potential mitigating opportunities across the company. Exelon anticipates that Energy Delivery’s capital expenditures will be funded by internally generated funds, borrowings and the issuance of debt or preferred securities or capital contributions from Exelon.
Generation’s capital expenditures for the six months ended June 30, 2004 reflect additions and upgrades to existing facilities (including nuclear refueling outages), nuclear fuel and increases in capacity at existing plants. Generation’s capital expenditures for the six months ended June 30, 2003 reflected the construction of the Mystic 8 and 9 and Fore River Boston Generating facilities. During 2003, Boston Generating received $86 million of liquidated damages from Raytheon Company (Raytheon) as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with Raytheon’s construction of these generating facilities. Exelon anticipates that Generation’s capital expenditures will be funded by internally generated funds, Generation’s borrowings or capital contributions from Exelon.
Cash flows used in financing activities for the six months ended June 30, 2004 were $937 million compared to $255 million for the same period in 2003. The increase in cash used in financing activities is primarily attributable to the net retirement of $582 million of long-term debt during the six months ended June 30, 2004 versus the net issuance of long-term debt of $334 million during the six months ended June 30, 2003. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information regarding debt issuances and retirements during the six months ended June 30, 2004. During the six months ended June 30, 2004, Exelon repaid $65 million of commercial paper and received cash proceeds of $31 million from the settlement of interest-rate swaps. During the six months ended June 30, 2003, Exelon repaid $100 million of commercial paper and paid $51 million to settle an interest-rate swap. Additionally, Exelon purchased treasury shares totaling $75 million during the second quarter of 2004 and received proceeds from employee stock plans of $140 million and $91 million for the six months ended June 30, 2004 and 2003, respectively.
The cash dividend payments on common stock for the six months ended June 30, 2004 increased $79 million over the six months ended June 30, 2003, reflecting a 9% increase in the common stock dividend in the third quarter of 2003 and a 10% increase in the first quarter of 2004. Payment of future dividends is subject to approval and declaration by the Board.
From time to time and as market conditions warrant, Exelon may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of Exelon’s balance sheet.
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Exelon Credit Facility. Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by Exelon corporate holding company (Exelon Corporate) and by ComEd, PECO and Generation. At June 30, 2004, Exelon Corporate, along with ComEd, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility, and the $750 million three-year facility was reduced to $500 million. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon Corporate, ComEd, PECO and Generation and to issue letters of credit. At June 30, 2004, Exelon Corporate, ComEd, PECO and Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:
Interest rates on the advances under the credit facility are based on either the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing or prime. The maximum LIBOR adder would be 175 basis points. For the six months ended June 30, 2004, the average interest rate on notes payable was approximately 1.05%.
The credit agreements require Exelon Corporate, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon Corporate and Generation, revenues from Exelon New England Holding Company, LLC (Exelon New England) and Sithe and interest on the debt of their project subsidiaries. Exelon Corporate is measured at the Exelon consolidated level. The following table summarizes the minimum thresholds reflected in the credit agreements for the twelve-month period ended June 30, 2004:
At June 30, 2004, each of Exelon Corporate, ComEd, PECO and Generation were in compliance with the foregoing thresholds.
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Capital Structure.At June 30, 2004, Exelon’s, ComEd’s, PECO’s and Generation’s capital structure consisted of the following:
Boston Generating Project Debt. Boston Generating had a $1.25 billion credit facility (Boston Generating Credit Facility), which was entered into primarily to finance the development and construction of the Mystic 8 and 9 and Fore River generating facilities. On May 25, 2004, Exelon and Generation completed the sale, transfer and assignment of ownership of Boston Generating to a special purpose entity owned by the lenders under the Boston Generating Credit Facility. Accordingly, the Boston Generating Credit Facility was eliminated from the consolidated financial statements of Exelon and Generation during the second quarter of 2004.
See Note 3 of the Combined Notes to Consolidated Financial Statements for information regarding the sale of Generation’s ownership interest in Boston Generating to the lenders under the Boston Generating Credit Facility.
Intercompany Money Pool. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by Exelon’s corporate treasurer. ComEd and its subsidiary, Commonwealth Edison of Indiana, Inc. (ComEd of Indiana), PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate and Unicom Investment, Inc., a wholly owned subsidiary of Exelon, may participate as lenders. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During 2004, ComEd, ComEd of Indiana and PECO had various
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Sithe Long-Term Debt. At June 30, 2004, $852 million of Sithe’s long-term debt, including current maturities, was included in Exelon and Generation’s Consolidated Balance Sheets. See Note 2 and Note 4 of the Combined Notes to Consolidated Financial Statements for information regarding the consolidation of Sithe and see Note 9 of the Combined Notes to Consolidated Financial Statements for information regarding Sithe’s long-term debt and the annual maturities.
Security Ratings.Exelon’s access to the capital markets, including the commercial paper market, and its financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. On July 22, 2004, Standard & Poor’s Ratings Services lowered the ratings on PECO’s First Mortgage Bonds from A to A-. None of the other securities ratings of Exelon, PECO or Exelon subsidiaries has changed. None of Exelon’s borrowings is subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under Exelon’s credit facilities.
Shelf Registration.As of June 30, 2004, Exelon, ComEd and PECO have current shelf registration statements for the sale of $2.0 billion, $555 million and $550 million, respectively, of securities that are effective with the SEC. Exelon’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, the current financial condition of the company, its securities ratings and market conditions.
PUHCA Restrictions.On April 1, 2004, Exelon obtained a new order from the SEC under the Public Utilities Holding Company Act of 1935 (PUHCA) authorizing, through April 15, 2007, financing transactions, including the issuance of common stock, preferred securities, equity-linked securities, long-term debt and short-term debt in an aggregate amount not to exceed $8.0 billion above the amount outstanding for Exelon Corporate and Generation at December 31, 2003 with no separate sublimit for short-term debt. The new financing order replaced a prior SEC order that expired on March 31, 2004 that had authorized up to $4.0 billion of financing. No securities have been issued under the above described limit. The prior order also authorized Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. The new order gives Exelon an additional $1.5 billion of guaranty authority. At June 30, 2004, Exelon had provided $1.9 billion of guarantees under the SEC order. See “Contractual Obligations and Off-Balance Sheet Arrangements” in this section for further discussion of guarantees. The SEC order requires Exelon to maintain a ratio of common equity to total capitalization (including securitization debt) of not less than 30%. At June 30, 2004, Exelon’s common equity ratio was 38%. Exelon expects that it will maintain a common equity ratio of at least 30%.
Exelon is also limited by order of the SEC under PUHCA to an aggregate investment of $4.0 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). At June 30, 2004, Exelon had invested $1.9 billion in EWGs, leaving $2.1 billion of investment authority under the order. In its April 1, 2004 financing order, the SEC authorized Exelon to invest $4 billion in EWGs and reserved jurisdiction over an additional $3.0 billion in investments in EWGs.
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Under applicable law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO or Generation may limit the dividends that these companies can distribute to Exelon. At June 30, 2004, Exelon had retained earnings of $2.9 billion, including ComEd’s retained earnings of $1,064 million (all of which had been appropriated for future dividend payments), PECO’s retained earnings of $597 million and Generation’s undistributed earnings of $773 million.
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Exelon’s, ComEd’s, PECO’s and Generation’s contractual obligations and commercial commitments as of June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:
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ComEd operates in a single business segment and its operations consist of the regulated sale of electricity and distribution and transmission services in northern Illinois.
Financial Results.ComEd’s net income was consistent for the three months ended June 30, 2004 as compared to the same period in 2003.
ComEd experienced an overall decline in net income of 3% during the six months ended June 30, 2004. This decline primarily reflects lower collections of CTCs, partially offset by lower operating and maintenance expense compared to the corresponding period in 2003 in which ComEd recorded charges associated with an agreement with various Illinois retail market participants and other interested parties.
The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd — Executive Summary” in the 2003 Form 10-K for a discussion of ComEd’s implementation of The Exelon Way.
Financing Activities. During the six months ended June 30, 2004, ComEd repaid $178 million of long-term debt and made a $179 million payment on long-term debt to ComEd Transitional Funding Trust. ComEd met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions.
Regulatory Developments — PJM Integration. On April 1, 2003, ComEd received approval from the FERC to transfer control of its transmission assets to PJM. The FERC also accepted for filing the amended PJM Tariff to reflect the inclusion of the transmission assets of ComEd and other new members, subject to a compliance filing and hearing on certain issues. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. On March 18, 2004, the FERC approved ComEd’s plan to complete its integration into PJM, subject to the North American Electric Reliability Council (NERC) approval of the PJM and Midwest ISO reliability plans to assure no adverse effects. The NERC granted the required approval on April 2, 2004. On April 27, 2004, the FERC issued its order approving ComEd’s application, subject to certain stipulations, including a provision to hold certain other utilities harmless from the impacts of ComEd joining PJM. ComEd agreed to these stipulations and fully integrated into PJM on May 1, 2004.
PECO and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of electric energy and capacity. Upon joining PJM, ComEd began incurring administrative fees, which are expected to approximate $30 million annually. ComEd believes such costs will ultimately be partially offset by the benefits of full access to a wholesale competitive marketplace, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on ComEd.
Through and Out Rates. ComEd currently earns approximately $66 million annually from T&O rates for energy flowing across ComEd’s transmission system. On March 19, 2004, the FERC issued an order to eliminate these rates effective May 1, 2004, which was subsequently deferred until December 1, 2004. The T&O rates are to be replaced by a new long-term transmission pricing structure that will eliminate seams in the PJM and Midwest ISO regions. Transmission owners in PJM and Midwest ISO and other parties must file one or more pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. While Exelon and ComEd cannot predict the outcome of the FERC’s final determination of a new long-term transmission pricing structure, such pricing structure could adversely impact Exelon’s and ComEd’s after-tax results of operations.
Delivery Services Rates. On March 3, 2003, ComEd entered into, and the ICC subsequently entered orders, which are now final, that effectuated an agreement (Agreement) with various Illinois retail market
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Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. However, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to have a significant effect on operating revenues until after December 31, 2006. ComEd began charging the new rates May 1, 2004. ComEd’s management believes an adequate reserve for any required refunds has been established in the event that the new rates are adjusted based on rehearing or settlement negotiations.
Outlook for the Remainder of 2004 and Beyond. ComEd’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd — Executive Summary” in the 2003 Form 10-K.
Results of Operations
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ComEd’s electric sales statistics were as follows:
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The changes in electric retail revenues for the three months ended June 30, 2004, as compared to the same period in 2003, are attributable to the following:
Volume. Revenues from higher delivery volume, exclusive of weather, increased $61 million due to increased residential customer growth and an increased usage per customer, primarily residential and large commercial and industrial.
Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather conditions for the three months ended June 30, 2004 were favorable compared to the same period in 2003. Cooling degree-days increased 68% for the three months ended June 30, 2004 compared to the same period in 2003, and were 14% lower than normal. Heating degree-days decreased 18% for the three months ended June 30, 2004 compared to the same period in 2003, and were 13% lower than normal.
Customer Choice. All ComEd customers have the choice to purchase energy from an AES. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd. As of June 30, 2004, no AES has sought approval from the ICC, and no electric utilities have chosen to enter the ComEd residential market for the supply of electricity. ComEd competes with AESs in the commercial market.
For the three months ended June 30, 2004, the energy provided by AESs was 5,257 GWhs, or 25%, as compared to 3,632 GWhs, or 18%, for the same period in 2003.
The decrease in revenues reflects customers in Illinois electing to purchase energy from an AES or the PPO. As of June 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,400 as compared to 22,000 as of the same period in 2003, representing less than 1% of total customers in each period. MWhs delivered to such customers increased from approximately 6.3 million for the three months ended June 30, 2003 to 7.6 million for three months ended June 30, 2004, or from 32% to 36% of total quarterly retail deliveries.
Rate Changes.ComEd’s CTC is reset in the second quarter of each year to reflect market price adjustments. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component, decreased the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased $44 million for the three months ended June 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under ComEd’s PPO by $28 million.
Decreased average rates paid by residential customers resulted in a $10 million decrease. Although residential rates are frozen through 2006, average residential rates fluctuate due to the usage patterns of customers.
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ComEd’s Integration into PJM. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. The increase relates to the change in control of the transmission assets from ComEd to PJM whereby ComEd receives revenues for its proportionate share of the transmission revenues generated by PJM, but also pays PJM for the use of its transmission assets. For 2004, ComEd’s operating revenues are estimated to increase by approximately $180 million, offset by a corresponding and equal increase in purchased power expense. Starting in 2005, on an annual basis, ComEd’s operating revenues and purchased power expense are estimated to increase between $200 to $250 million; however, there is no expected impact on revenues net of purchased power expense.
The increase in purchased power expense was primarily attributable to an increase of $28 million due to higher volume and a $10 million increase due to favorable weather conditions offset by a $40 million decrease as a result of non-residential customers choosing to purchase energy from an AES. ComEd’s operating revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.
The changes in operating and maintenance expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
The increase in depreciation expense is primarily due to capital additions.
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Recoverable transition costs amortization remained constant in the three months ended June 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of $109 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.
Taxes other than income increased for three months ended June 30, 2004 as compared to the same period in 2003 as a result of a 2003 refund of $5 million for Illinois Electricity Distribution Taxes.
The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased as a result of scheduled principal payments and refinancings at lower rates. Effective December 31, 2003, upon the adoption of FIN No. 46-R, ComEd deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). ComEd no longer records distributions on mandatorily redeemable preferred securities but records interest expense to affiliates related to ComEd’s obligations to the financing trusts.
In 2004, ComEd has $6 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.
The change in Other, net is primarily related to the 2003 $2 million gain on sale of non-utility property and $1 million decrease in interest income on the long-term receivable from Unicom Investments, Inc. as a result of a lower principal balance.
The effective income tax rate was 39% for the three months ended June 30, 2004, compared to 40% for the three months ended June 30, 2003. The decrease in the effective tax rate was primarily attributable to the adoption of FSP FAS 106-2 and other items. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
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The changes in electric retail revenues for the six months ended June 30, 2004, as compared to the same period in 2003, are attributable to the following:
Customer Choice. As noted, all ComEd customers have the choice to purchase energy from an AES. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd.
For the six months ended June 30, 2004, the energy provided by AESs was 10,457 GWhs, or 25%, as compared to 7,095 GWhs, or 17%, for the same period in 2003.
The decrease in revenues reflects customers in Illinois electing to purchase energy from an AES or the PPO. As of June 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,400 as compared to 22,000 as of June 30, 2003, representing less than 1% of total customers in each period. MWhs delivered to such customers increased from approximately 12.6 million for the six months ended June 30, 2003 to approximately 14.7 million for six months ended June 30, 2004, or from 30% to 34% of total quarterly retail deliveries.
Rate Changes.Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component, decreases the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased by $120 million for the six months ended June 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under ComEd’s PPO by $47 million. For the six months ended June 30, 2004 and June 30, 2003, ComEd collected approximately $87 million and $207 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, and increases in ComEd’s OATT effective May 1, 2004, ComEd anticipates that this revenue source will decline to approximately $180 million for 2004 and range from $100 million to $180 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.
Volume. ComEd’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large commercial and industrial.
Weather. The weather conditions for the six months ended June 30, 2004 were favorable compared to the same period in 2003. Cooling degree-days increased 68% for the six months ended June 30, 2004 compared to the same period in 2003 and were 14% lower than normal. Heating degree-days decreased 8% for the six months ended June 30, 2004 compared to the same period in 2003, and were 4% lower than normal.
ComEd’s Integration into PJM. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.
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The decrease in purchased power expense was primarily attributable to a $92 million decrease as a result of customers choosing to purchase energy from an AES and an $8 million decrease due to the mix of average pricing related to ComEd’s PPA with Generation partially offset by an increase of $50 million due to higher volume. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.
The changes in operating and maintenance expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Recoverable transition costs amortization remained constant in the six months ended June 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of $109 million by 2006. Consistent with the provision of the Illinois legislation,
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Taxes other than income increased for six months ended June 30, 2004 as compared to the same period in 2003 as a result of a 2003 refund of $5 million for Illinois Electricity Distribution taxes.
The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased as a result of scheduled principal payments and refinancings at lower rates. Effective December 31, 2003, upon the adoption of FIN No. 46-R, ComEd deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). ComEd no longer records distributions on mandatorily redeemable preferred securities, but records interest expense to affiliates related to ComEd’s obligations to the financing trusts. This decrease was offset by $3 million of less allowance for funds used during construction (AFUDC) debt recorded during the six months ended June 30, 2004 as a result of lower construction work in process balances.
In 2004, ComEd has $9 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.
The change in Other, net is primarily related to the reversal of a $12 million reserve for potential plant disallowance in 2003 as a result of the Agreement (see “Operating and Maintenance” above), a reduction in AFUDC equity of $4 million during 2004 as a result of lower construction work in process balances and a $3 million decrease in interest income on the long-term receivable from Unicom Investments, Inc. as a result of a lower principal balance.
The effective income tax rate was 40% for the six months ended June 30, 2004, compared to 40% for the six months ended June 30, 2003. The reduction in the effective tax rate is primarily attributable to the adoption of FSP FAS 106-2. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of $5 million.
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where ComEd no longer has access to the capital markets at reasonable terms, ComEd has access to a revolving credit facility that ComEd currently utilizes to support its commercial paper program. See the “Credit Issues” section of “Liquidity and Capital Resources” for further discussion. Capital resources are used primarily to fund ComEd’s capital requirements, including construction, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans.
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ComEd’s cash flows from operating activities primarily results from sales of electricity to a stable and diverse base of retail customers at fixed prices. ComEd’s future cash flows will be affected by its ability to achieve operating cost reductions and the impact of the economy, weather and customer choice on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements. Operating cash flows after 2006 could be negatively affected by changes in ComEd’s rate regulatory environment, although any effects are not expected to hinder ComEd’s ability to fund its business requirements.
Cash flows from operations for the six months ended June 30, 2004 and 2003 were $602 million and $369 million, respectively. Changes in ComEd’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.
In addition to the items mentioned in “Results of Operations,” ComEd’s operating cash flows for the six months ended June 30, 2004 and 2003 were affected by the following items:
ComEd participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including $11 million to satisfy IRS minimum funding requirements. Of the $419 million, $216 million is expected to be funded by ComEd.
ComEd has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of June 30, 2004, the majority of the deferred tax liabilities related to the fossil plant sale are reflected in ComEd’s Consolidated Balance Sheets with the remainder having been allocated to the Consolidated Balance Sheets of Generation in connection with Exelon’s 2001 corporate restructuring. The total 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. Any required payments could be significant to the cash flows of ComEd. ComEd’s management believes ComEd’s reserve for interest, which has been established in the event that such positions are not sustained, has been appropriately recorded in accordance with SFAS No. 5. However, the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.
Cash flows used in investing activities were $133 million for the six months ended June 30, 2004 compared to cash flows used in investing activities of $524 million for the same period in 2003. The change in cash flows from investing activities was primarily attributable to $372 million of net proceeds from an investment in the Exelon intercompany money pool and $36 million of net changes in restricted cash. ComEd’s investing activities for the six months ended June 30, 2004 were funded primarily through operating activities.
ComEd’s capital expenditures for the six months ended June 30, 2004 and 2003 were $369 million and $355 million, respectively. ComEd estimates that it will spend up to approximately $715 million in total
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Cash flows used in financing activities for the six months ended June 30, 2004 were $476 million as compared to cash flows from financing activities of $173 million in 2003. The decrease in cash flows from financing activities is primarily attributable to the retirement of long-term debt of $357 million during the six months ended June 30, 2004 versus the net proceeds from the issuance of long-term debt of $473 million during the same period in 2003. During the six months ended June 30, 2003, ComEd also repaid $71 million of commercial paper and paid $51 million to settle interest-rate swaps. During the six months ended June 30, 2004, ComEd received $26 million from the settlement of interest-rate swaps. Additionally, ComEd paid $207 million in dividends to Exelon during the six months ended June 30, 2004 compared to $211 million in dividends during the same period in 2003.
From time to time and as market conditions warrant, ComEd may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of ComEd’s balance sheet.
Exelon Credit Facility. ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. ComEd, along with Exelon Corporate, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and ComEd’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”
Capital Structure.ComEd’s capital structure at June 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”
Intercompany Money Pool. A description of the intercompany money pool, and ComEd’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” During the six months ended June 30, 2004, ComEd earned $2 million in interest on its investments in the intercompany money pool.
Security Ratings.See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in the 2003 Form 10-K for a discussion of ComEd’s security ratings.
Shelf Registration.As of June 30, 2004, ComEd has a current shelf registration statement for the sale of $555 million of securities that is effective with the SEC. ComEd’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, ComEd’s current financial condition, its securities ratings and market conditions.
Fund Transfer Restrictions. At June 30, 2004, ComEd had retained earnings of $1,064 million, which had been appropriated for future dividend payments. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd” in the 2003 Form 10-K for information regarding restrictions under
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Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. ComEd’s contractual obligations and commercial commitments as of June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:
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PECO operates in a single business segment, and its operations consist of the regulated sale of electricity and distribution and transmission services in southeastern Pennsylvania and the sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
Financial Results.PECO’s net income increased 14% for the three months ended June 30, 2004 as compared to the same period in 2003. This increase reflects higher electric revenues, partially offset by higher operating expenses.
PECO’s net income increased 4% for the six months ended June 30, 2004 as compared to the same period in 2003 and is generally comparable between periods.
The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO — Executive Summary” in the 2003 Form 10-K for a discussion of PECO’s implementation of The Exelon Way.
Financing Activities. During the six months ended June 30, 2004, PECO refinanced $75 million of First and Refunding Mortgage Bonds and repaid $166 million of long-term debt to PECO Energy Transition Trust. PECO met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions.
Outlook for the Remainder of 2004 and Beyond. PECO’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO — Executive Summary” in the 2003 Form 10-K.
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PECO’s electric sales statistics were as follows:
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The changes in electric retail revenues for the three months ended June 30, 2004, as compared to the same period in 2003, were as follows:
Volume. Exclusive of the effect of weather conditions and customer choice, higher delivery volume related primarily to increased customer growth and increased usage by all customer classes.
Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather impact was favorable compared to the prior year. Cooling degree-days increased 66% and heating degree-days decreased 32%.
Rate Mix. The increase in revenues from rate mix was due to changes in monthly usage patterns in all customer classes.
Rate change.Revenues increased $5 million due to a scheduled phase-out of merger-related rate reductions. In connection with the PUC’s approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005.
Customer Choice. All PECO customers may choose to purchase energy from an AES. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.
For the three months ended June 30, 2004, the energy provided by AESs was 1,111 GWhs, or 12%, as compared to 701 GWhs, or 8%, for the three months ended June 30, 2003. As of June 30, 2004, the number of customers served by AESs was 292,100, or 19%, as compared to 125,000, or 8%, as of June 30, 2003. The increases in both the energy provided by AESs and the number of customers served by AESs were due to the assignment of small commercial and industrial customers and residential customers to AESs in May and December 2003, respectively, as required by the PUC and PECO’s final electric restructuring order.
Electric wholesale and miscellaneous revenue includes PECO’s proportionate share of the transmission revenues generated by PJM’s control of the PJM network transmission assets, including PECO’s. Additionally, PECO pays PJM for its use of these transmission assets, and this expense is recorded in purchased power.
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PECO’s gas sales statistics for the three months ended June 30, 2004 as compared to the same period in 2003 were as follows:
The changes in gas retail revenue for the three months ended June 30, 2004 as compared to the same period in 2003, were as follows:
Rate Changes. The favorable variance in rates was attributable to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective June 1, 2003 and March 1, 2004. The average rate per mmcf for the three months ended June 30, 2004 was 30% higher than the rate for the same period in 2003. PECO’s gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. PECO has asked the PUC for a decrease in its rates through the purchased gas adjustment clause effective December 1, 2004 as a result of lower current gas costs. This proposed decrease would have no impact on PECO’s operating income.
Volume. Exclusive of the effect of weather conditions, revenues were higher due primarily to increased sales in the residential and small commercial and industrial classes.
Weather. The weather conditions were unfavorable compared to the prior year. Heating degree-days decreased 32%.
Resales and other revenue increased $6 million primarily due to increased off-system sales.
The increase in purchased power expense was attributable to $16 million of increased sales exclusive of the effect of weather conditions, $14 million of higher prices, and $6 million related to higher sales due to favorable weather conditions, offset by $16 million from customers in Pennsylvania assigned to or selecting an AES and $4 million of lower PJM transmission expense.
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The increase in fuel expense was attributable to $13 million of higher gas costs, $10 million related to increased off-system sales, and $3 million related to increased sales exclusive of weather conditions, partially offset by a $10 million decrease associated with lower sales due to unfavorable weather conditions.
The additional amortization of the CTC is in accordance with PECO’s original settlement under the Pennsylvania Competition Act.
The increase in taxes other than income was primarily attributable to $12 million related to the reversal of a use tax accrual resulting from an audit settlement in 2003.
The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased primarily due to lower outstanding debt and refinancings at lower rates. Effective December 31, 2003, with the adoption of FIN No. 46-R, PECO deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). PECO no longer records distributions on mandatorily redeemable preferred securities of subsidiaries but records interest expense to affiliates related to PECO’s obligations to the financing trusts.
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In 2004, PECO has $7 million of equity in net losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.
The increase was attributable to a $2 million increase in interest income.
The effective tax rate was 33% for the three months ended June 30, 2004 as compared to 37% for the same period in 2003. The decrease in the effective tax rate was primarily attributable to plant-related differences. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
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The changes in electric retail revenues for the six months ended June 30, 2004, as compared to the same period in 2003, were as follows:
Rate change.Revenues increased $9 million due to a scheduled phase-out of merger-related rate reductions.
Weather. The weather impact was favorable compared to the prior year. Cooling degree-days increased 66% and heating degree-days decreased 8%.
Customer Choice. As noted, all PECO customers may choose to purchase energy from an AES. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.
For the six months ended June 30, 2004, the energy provided by AESs was 2,267 GWhs, or 12%, as compared to 1,377 GWhs, or 8%, for the six months ended June 30, 2003. As of June 30, 2004, the number of customers served by AESs was 292,100, or 19%, as compared to 125,000, or 8%, as of June 30, 2003. The increases in both the energy provided by AESs and the number of customers served by AESs were due to the assignment of small commercial and industrial customers and residential customers to AESs in May and December 2003, respectively, as required by the PUC and PECO’s final electric restructuring order.
Rate Mix. The decrease in revenues from rate mix was due to changes in monthly usage patterns in all customer classes during the six months ended June 30, 2004 as compared to the same period in 2003.
Electric wholesale and miscellaneous revenue includes PECO’s proportionate share of the transmission revenues generated by PJM’s control of the PJM network transmission assets, including PECO’s. Additionally, PECO pays PJM for its use of these transmission assets, and this expense is recorded in purchased power. Electric wholesale and miscellaneous revenue decreased $5 million primarily due to lower PJM transmission revenue.
PECO’s gas sales statistics for the six months ended June 30, 2004 as compared to the same period in 2003 were as follows:
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The changes in gas retail revenue for the six months ended June 30, 2004 as compared to the same period in 2003, were as follows:
Rate Changes. The favorable variance in rates was attributable to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003, and March 1, 2004. The average rate per mmcf for the six months ended June 30, 2004 was 39% higher than the rate for the same period in 2003.
Weather. The weather conditions were unfavorable compared to the prior year. Heating degree-days decreased 8% compared to the same period in 2003.
Volume. Exclusive of the effect of weather conditions, revenues were lower in the six months ended June 30, 2004 compared to the same period in 2003 due primarily to decreased sales in the residential and small commercial and industrial classes.
The decrease in purchased power expense was attributable to $42 million from customers in Pennsylvania assigned to or selecting an AES and a $9 million decrease in PJM transmission expense, partially offset by an increase of $31 million related to increased sales exclusive of weather conditions, $8 million of higher prices, and a $3 million increase associated with higher sales due to favorable weather conditions.
The increase in fuel expense was attributable to $82 million of higher gas costs and $13 million related to increased off-system sales, partially offset by a $16 million decrease associated with lower sales due to unfavorable weather conditions and a decrease of $4 million related to decreased sales exclusive of the effect of weather conditions.
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The increase in taxes other than income was primarily attributable to $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $6 million of lower capital stock tax.
In 2004, PECO recorded $13 million of equity in net losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.
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The decrease was attributable to a $2 million decrease in interest income and a $4 million favorable settlement of a customer contract in 2003.
The effective tax rate was 33% for the six months ended June 30, 2004 as compared to 35% for the same period in 2003. The decrease in the effective tax rate was primarily attributable to plant-related differences. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility that PECO currently utilizes to support its commercial paper program. See the “Credit Issues” section of “Liquidity and Capital Resources” for further discussion. Capital resources are used primarily to fund PECO’s capital requirements, including construction, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans.
PECO’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices. PECO’s future cash flows will be affected by its ability to achieve operating cost reductions and the impact of the economy and weather on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements for the foreseeable future.
Cash flows from operations for the six months ended June 30, 2004 and 2003 were $509 million and $425 million, respectively. Changes in PECO’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.
In addition to the items mentioned in “Results of Operations,” PECO’s operating cash flows for the six months ended June 30, 2004 and 2003 were affected by the following items:
PECO participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including $11 million to satisfy IRS minimum funding requirements. Of the $419 million, $8 million is expected to be funded by PECO.
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Cash flows used in investing activities for the six months ended June 30, 2004 and 2003 were $137 million and $98 million, respectively. The $39 million increase in cash used in investing activities was primarily attributable to a $35 million investment in the Exelon intercompany money pool in 2004 and a change in restricted cash which provided cash flows of $28 million in 2003, partially offset by lower construction expenditures of $27 million in 2004. PECO’s investing activities during the six months ended June 30, 2004 were funded by operating activities.
PECO’s projected capital expenditures for 2004 are $233 million. Approximately 60% of the budgeted 2004 expenditures are for additions to or upgrades of existing facilities, including reliability improvements. The remainder of the capital expenditures support customer and load growth. PECO anticipates that it will obtain financing, when necessary, through borrowings, the issuance of preferred securities, or capital contributions from Exelon. PECO’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Cash flows used in financing activities for the six months ended June 30, 2004 were $317 million compared to $329 million for the same period in 2003. The decrease in cash flows used in financing activities is primarily due to a decrease in the retirement of preferred securities of $100 million and an increase in contributions received from Exelon of $54 million, partially offset by an increase in net retirements of long-term debt of $124 million. Additionally, PECO paid dividends of $182 million and $168 during the six months ended June 30, 2004 and 2003, respectively, of which $180 million and $165 million, respectively, were common dividends paid to Exelon.
From time to time and as market conditions warrant, PECO may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of PECO’s balance sheet.
Exelon Credit Facility. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. PECO participates, along with Exelon Corporate, ComEd and Generation, in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and PECO’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”
Capital Structure.PECO’s capital structure at June 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”
Intercompany Money Pool. A description of the intercompany money pool, and PECO’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” During the six months ended June 30, 2004, PECO earned less than $1 million in interest from its investments in the intercompany money pool.
Security Ratings.PECO’s access to the capital markets, including the commercial paper market, and its financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. On July 22, 2004, Standard & Poor’s Ratings Services lowered the ratings on PECO’s First Mortgage Bonds from A to A-. None of PECO’s other securities ratings has changed. None of PECO’s borrowings is subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under Exelon’s credit facilities.
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Shelf Registration.As of June 30, 2004, PECO has a current shelf registration statement for the sale of $550 million of securities that is effective with the SEC. PECO’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, PECO’s current financial condition, its securities ratings and market conditions.
Fund Transfer Restrictions. At June 30, 2004, PECO had retained earnings of $597 million. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO” in the 2003 Form 10-K for information regarding fund transfer restrictions.
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. PECO’s contractual obligations and commercial commitments as of June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:
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Generation operates as a single segment and consists of electric generating facilities, energy marketing operations, a 50% interest in Sithe and, effective January 1, 2004, the competitive retail sales business of Exelon Energy Company.
Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. Generation’s results of operations have not been adjusted to reflect Exelon Energy Company as a part of Generation for 2003. Exelon Energy Company’s results for the three and six months ended June 30, 2003 were as follows:
Financial Results.Generation reported an overall increase in net income of $36 million for the quarter ended June 30, 2004 as compared to the prior year, due primarily to the gain of $52 million, net of income taxes, recorded on the sale of Boston Generating, partially offset by operating net losses of $10 million for Boston Generating, incurred during the second quarter of 2004. Generation reported an overall increase in net income of $83 million for the six months ended June 30, 2004 as compared to the same period in 2003. This increase was primarily attributable to a gain of $52 million, net of income taxes, recorded on the sale of Boston Generating, partially offset by operating net losses of $28 million for Boston Generating incurred during the first five months of 2004, $43 million attributable to the incremental results of AmerGen, Exelon Energy and Sithe and $32 million of net income for the cumulative effect of a change in accounting principle. Generation also experienced improved results due to increased realized margins as a result of its successful forward hedging strategy and increased market prices. Generation’s results of operations for the six months ended June 30, 2003 included the pre-tax impairment charge on Generation’s investment in Sithe of $200 million and a $108 million net gain resulting from the cumulative effect of a change in accounting principle for the adoption of SFAS 143.
The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation — Executive Summary” in the 2003 Form 10-K for a discussion of Generation’s implementation of The Exelon Way.
Divestiture Activities. During the second quarter, Generation completed the sale and transfer of the assets of Boston Generating to a special purpose entity formed by the lenders of the Boston Generating credit facility.
In connection with the consolidation of Sithe, Generation recorded assets held for sale related to Sithe’s investments in certain hydroelectric facilities. At June 30, 2004, Generation’s consolidated balance sheets reflect $9 million of assets, and $3 million of liabilities held for sale related to these investments. Generation continues to explore various transactional strategies related to its investment in Sithe.
Financing Activities. On June 30, 2004, Generation had $211 million of commercial paper outstanding and $198 million in outstanding money pool loans to fund operations. Also, Generation increased its distributions to Exelon by approximately $64 million during the first six months of 2004 compared to the same period in the prior year. Generation continues to meet its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions.
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Operations.Generation’s nuclear fleet achieved a 93.3% capacity factor during the six months ended June 30, 2004 compared to 94.2% during the same period in 2003, primarily as a result of an increased number of planned outages in 2004 as compared to 2003. Generation anticipates transferring plant operations and power marketing activities of Boston Generating to a special purpose entity designated by the lenders of the Boston Generating credit facility during the third quarter of 2004.
Outlook for the Remainder of 2004 and Beyond. Generation’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation — Executive Summary” in the 2003 Form 10-K.
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For the three months ended June 30, 2004 and 2003, Generation’s sales were as follows:
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Generation’s average margin and other operating data for the three months ended June 30, 2004 and 2003 are as follows:
The changes in Generation’s operating revenues for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The sale of Boston Generating in May 2004 resulted in less revenues from this entity compared to the same period in the prior year. The acquisition of Exelon Energy and AmerGen resulted in increased market and retail electric sales of approximately $104 million compared to the same period in the prior year.
The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, and in the Mid-Atlantic region market prices were driven by higher oil and gas prices.
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Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the three months ended June 30, 2003 was $44 million.
The decrease in revenue from sales to affiliates was partially offset by $15 million in higher sales to Energy Delivery. The higher sales to Energy Delivery were primarily due to an overall increased usage per customer and favorable weather conditions.
Other. Certain other revenues increased for the three months ended June 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s results of operations beginning April 1, 2004.
Generation’s supply source is summarized below:
Generation’s supply mix changed as a result of the sale of Boston Generating in May 2004.
Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation below for further information).
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Boston Generating.The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004.
AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $97 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $86 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results.
Hedging Activity.Mark-to-market gains on hedging activities were $21 million for the three months ended June 30, 2004 compared to gains of $32 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $6 million and hedging activities relating to other Generation operations in 2004 accounted for a gain of $15 million.
The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen, Exelon Energy Company and Sithe in Generation’s consolidated results for 2004. The increase in operating and maintenance expenses attributable to Boston Generating was due to Mystic 8 and 9 and Fore River commencing commercial operation at the end of the second quarter of 2003 and in the third quarter of 2003, respectively, which more than offset the reduction in operating and maintenance expenses resulting from their sale in May 2004. Decommissioning accretion costs increased primarily due to the inclusion of AmerGen in this period compared to the prior year. The reduction in payroll-related costs associated with the implementation of the programs associated with The Exelon Way partially offset the other increases to operating and maintenance expense.
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Nuclear fleet operating data and purchased power costs data for the three months ended June 30, 2004 and 2003 were as follows:
In the three months ended June 30, 2004 as compared to the three months ended June 30, 2003, the Quad Cities units operated at pre-EPU generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.
The increase in depreciation and amortization expense for the three months ended June 30, 2004 as compared to the same period in 2003 includes the impact of capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities as the assets were classified as held for sale during the period.
The increase in interest expense was primarily due to the issuance of $500 million of Senior Notes in December 2003 and interest expense related to Sithe long-term debt.
The decrease in equity in earnings of unconsolidated affiliates was primarily due to a $20 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of Generation’s purchase of British Energy’s 50% interest in AmerGen.
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The components of other, net for the three months ended June 30, 2004 as compared to the same period in the prior year, are as follows:
The effective income tax rate was 38% for the three months ended June 30, 2004 compared to 39% for the same period in 2003. This decrease was primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe that resulted in a pre-tax loss. In addition, the rate increased due to the additional nuclear decommissioning investment income associated with AmerGen and its related taxes. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
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For the six months ended June 30, 2004 and 2003, Generation’s sales were as follows:
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Generation’s average margin and other operating data for the six months ended June 30, 2004 and 2003 are as follows:
The changes in Generation’s operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The acquisition of Exelon Energy and AmerGen resulted in increased market and retail electric sales of approximately $182 million compared to the same period in the prior year.
The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, while the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.
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Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of Exelon Energy Company’s assets and operations being transferred to Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the six months ended June 30, 2003 was $108 million.
The decrease in revenue from sales to affiliates included $40 million in lower sales to Energy Delivery. The lower sales to Energy Delivery was primarily due to customers purchasing energy from alternative electric suppliers and unfavorable weather conditions in the ComEd and PECO service territories compared to the prior year.
Generation’s supply mix changed as a result of increased fossil generation due to Boston Generating’s Mystic units 8 and 9 and Fore River generating facilities becoming operational in the second and third quarter of 2003, which in total accounted for an increase of 2,688 GWhs offset by decreases in other fossil generating facilities.
The changes in Generation’s purchased power and fuel expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:
Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $444 million and fuel expense of $8 million.
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Price. The decrease primarily reflects lower average fossil fuel costs of $47 million during the six months ended June 30, 2004 as compared to the same period in 2003. Natural gas, oil and coal prices all decreased during this period.
AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $160 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $261 million as fuel purchases made by Exelon Energy Company did not previously impact Generation’s results.
Boston Generating.The increase in fuel and purchased power expense for Boston Generating is due primarily to the Mystic 8 and 9 generating facilities which began commercial operations at the end of the second quarter of 2003, and the Fore River generating facilities which began commercial operations during the third quarter of 2003. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding Boston Generating. The increase was offset by a decrease of $13 million related to the effects of adopting EITF 03-11.
Hedging Activity.Mark-to-market losses on hedging activities were $18 million for the six months ended June 30, 2004 compared to gains of $1 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $4 million and hedging activities for other Generation operations in 2004 accounted for a loss of $22 million.
Other. Other decreases in purchased power and fuel were primarily due to $46 million in lower transmission expense resulting from reduced inter-region transmission as a result of ComEd’s integration into PJM in the second quarter of 2004, offset by $16 million of additional nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.
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The increase in operating and maintenance expense is due primarily to the inclusion of AmerGen, Exelon Energy Company and Sithe in 2004. Also, operating and maintenance expenses increased at Boston Generating due to Mystic 8 and 9 and Fore River commencing commercial operations in the second and third quarters of 2003. Decommissioning accretion costs also increased primarily due to the inclusion of AmerGen in this period as compared to the prior year. A reduction in payroll-related costs associated with the implementation of the programs associated with The Exelon Way partially offset the other increases to operating and maintenance expense.
Nuclear fleet operating data and purchased power costs data for the six months ended June 30, 2004 and 2003 were as follows:
The increase in depreciation and amortization expense for the six months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to the impact of capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities as the assets were classified as held for sale during the period.
The decrease in equity in earnings of unconsolidated affiliates was primarily due to a $37 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of Generation’s purchase of British Energy’s 50% interest in AmerGen.
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The components of other, net for the six months ended June 30, 2004 as compared to the same period in the prior year, are as follows:
The effective income tax rate was 38% for the six months ended June 30, 2004 compared to 44% for the same period in 2003. This decrease was primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe that resulted in a pre-tax loss. In addition, the rate decreased due to the additional nuclear decommissioning investment income associated with AmerGen and its related taxes. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Net income for the six months ended June 30, 2004 reflects income of $32 million, net of income taxes, related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, while net income for the six months ended June 30, 2003 reflects income of $108 million, net of income taxes, for the adoption of SFAS No. 143. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN No. 46-R and SFAS No. 143.
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to a revolving credit facility. See the “Credit Issues” section of “Liquidity and Capital Resources” for further discussion. Capital resources are used primarily to fund Generation’s capital requirements, including construction, repayments of maturing debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.
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Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Generation’s affiliated companies. Generation’s future cash flows from operating activities will be affected by future demand and market prices for energy and its ability to continue to produce and supply power at competitive costs. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flows, sufficient to meet operating and capital expenditures requirements for the foreseeable future.
Cash flows from operations for the six months ended June 30, 2004 and 2003 were $616 million and $539 million, respectively. Changes in Generation’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business and non-cash charges.
In addition to the items mentioned in “Results of Operations,” Generation’s operating cash flows for the six months ended June 30, 2004 and 2003 were affected by the following items:
Generation participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including $11 million to satisfy IRS minimum funding requirements. Of the $419 million, $170 million is expected to be funded by Generation during 2004.
Cash flows used in investing activities were $438 million and $534 million for the six months ended June 30, 2004 and 2003, respectively. Generation’s capital expenditures for the six months ended June 30, 2004 and 2003 were $366 million and $424 million, respectively. Generation’s capital expenditures represent additions to nuclear fuel and additions and upgrades to existing facilities. Capital expenditures for the six months ended June 30, 2003 are stated net of proceeds from liquidated damages of $86 million. Generation estimates that it will spend approximately $972 million in total capital expenditures in 2004. Generation anticipates that nuclear refueling outages will increase from eight in 2003 to nine in 2004. Generation’s capital expenditures are expected to be funded by internally generated funds.
Cash flows used in financing activities were $141 million for the six months ended June 30, 2004, compared to cash flows provided by financing activities of $11 million for the same period in 2003. The increase in cash flows used in financing activities was primarily a result of a net repayment of intercompany borrowings of $218 million during the six months ended June 30, 2004, compared to a $58 million net increase in intercompany borrowings during the same period in 2003 and a $64 million increase in distributions to Exelon during the six months ended June 30, 2004 as compared to the same period in 2003. This use of cash was partially offset by the issuance of $211 million of commercial paper during the six months ended June 30, 2004 and the partial repayment of the acquisition note payable to Sithe of $27 million during the six months ended June 30, 2004, compared a $210 million payment during the same period in 2003.
From time to time and as market conditions warrant, Generation may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of Generation’s balance sheet.
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Exelon Credit Facility. Generation meets its short-term liquidity requirements primarily through the issuance of commercial paper and intercompany borrowings from Exelon’s intercompany money pool. Generation participates, along with Exelon Corporate, ComEd and PECO, in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and Generation’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”
Capital Structure.Generation’s capital structure at June 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”
Intercompany Money Pool. A description of the intercompany money pool, and Generation’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” For the six months ended June 30, 2004, Generation paid $1.5 million in interest to the money pool.
Sithe Long-Term Debt. A description of the Sithe long-term debt consolidated as a result of the adoption of FIN No. 46-R is set forth above under “Credit Issues — Sithe Long-Term Debt” in “Exelon Corporation — Liquidity and Capital Resources.”
Security Ratings.See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in the 2003 Form 10-K for a discussion of Generation’s security ratings.
Fund Transfer Restrictions. At June 30, 2004, Generation had undistributed earnings of $773 million. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation” in the 2003 Form 10-K for information regarding fund transfer restrictions.
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Generation’s contractual obligations and commercial commitments as of June 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:
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Exelon is exposed to market risks associated with commodity prices, credit, interest rates and equity prices. The inherent risk in market-sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, interest rates and equity security prices. Exelon’s Risk Management Committee (RMC) sets forth risk management policy and objectives and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning, vice president of strategy, vice president of audit services and officers from each of the business units. The RMC reports to the Exelon Board of Directors on the scope of Exelon’s derivative and risk management activities.
Commodity Price Risk
Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and other factors. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity, energy and fossil fuels, including oil, gas, coal, and emission allowances. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, governmental environmental policies, changes in supply and demand, state and federal regulatory policies and other events.
Electricity available from Generation’s owned or contracted generation supply in excess of its obligations to customers, including Energy Delivery’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge its anticipated exposures. Generation has an estimated 90% hedge ratio in 2004 for its energy marketing portfolio. This hedge ratio represents the percentage of Generation’s forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. Energy Delivery’s retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. During peak periods the amount hedged declines to meet Generation’s commitment to Energy Delivery. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for Generation’s non-trading portfolio associated with a 10% reduction in the annual average around-the-clock market price of electricity is approximately a $19 million decrease in net income. This sensitivity assumes a 90% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.
Generation uses financial contracts for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of its overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than one percent of Generation’s owned and contracted supply of electricity. Generation expects this level of proprietary trading activity to continue in the future. The results of the trading portfolio for the six months ended June 30, 2004 was a loss $2 million (before taxes) which included a $1 million unrealized mark-to-market loss. The daily Value-at-Risk (VaR) on proprietary trading activity averaged $200,000 of exposure
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Generation’s energy contracts are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). Most non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in Exelon’s 2003 Form 10-K. Those that do not are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in Other Comprehensive Income (OCI), and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 and the ineffective portion of hedge contracts are recognized in earnings on a current basis.
The following detailed presentation of the proprietary trading and non-trading marketing activities of Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. Generation does not consider its proprietary trading to be a significant activity of its business; however, Generation believes it is important to include these risk management disclosures.
The following tables describe the drivers of Generation’s energy trading and marketing business and gross margin included in the income statement for the three and six months ended June 30, 2004 and 2003. Normal operations and hedging activities represent the marketing of electricity available from Generation’s owned or contracted generation, including generation used to serve Energy Delivery’s retail load, sold into the wholesale market. As the information in these tables highlights, mark-to-market activities represent a small portion of the overall gross margin for Generation. Accrual activities, including normal purchases and sales, account for the majority of the gross margin. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices. Further delineation of gross margin by the type of accounting treatment typically afforded each type of activity is also presented (i.e., mark-to-market vs. accrual accounting treatment).
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The following table provides detail on changes in Generation’s mark-to-market net asset or liability balance sheet position from January 1, 2004 to June 30, 2004. It indicates the drivers behind changes in the
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The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of June 30, 2004 and December 31, 2003:
The majority of Generation’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of June 30, 2004 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds or sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
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The following table, which presents maturity and source of fair value of mark-to-market energy contract net liabilities, provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Generation’s total mark-to-market asset or liability. Second, the table provides the maturity, by year, of Generation’s net assets/liabilities, giving an indication of when the mark-to-market amounts will settle and either generate or require cash.
The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of June 30, 2004. The table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s hedges. The table also includes a roll-forward of accumulated other comprehensive income related to cash-flow hedges for the six months ended June 30, 2004, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest-rate hedging activities.
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Credit Risk
Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment. Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits or letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The following tables provide information on Generation’s wholesale credit exposure, net of collateral, as of June 30, 2004. The tables further delineate that exposure by the credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of Generation’s credit risk by credit rating of its counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through Independent System Operators, which are discussed below.
Dynegy. Generation is counterparty to Dynegy, Inc. (Dynegy) in various energy transactions. The credit ratings of Dynegy are below investment grade. As of June 30, 2004, Generation has credit risk
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Collateral. As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of express contractual provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Generation’s situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.
ISOs. Generation participates in the following established, real-time energy markets, which are administered by ISOs: PJM, ISO New England, New York ISO, California ISO, Midwest ISO, Inc., Southwest Power Pool, Inc. and Texas, which is administered by the Electric
Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the ISOs. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by the ISOs, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on Generation’s financial condition, results of operations or net cash flows.
Interest Rate Risk
ComEd uses a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Interest-rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. ComEd
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In 2004, ComEd entered into fixed-to-floating interest-rate swaps in order to maintain its targeted percentage of variable-rate debt associated with fixed-rate debt issuances in the aggregate amount of $240 million. At June 30, 2004, these interest-rate swaps, designated as fair-value hedges, had an aggregate fair market value of $1 million based on the present value difference between the contract and market rates at June 30, 2004. If these derivative instruments had been terminated at June 30, 2004, this estimated fair value represents the amount that would be paid by the counterparties to ComEd.
The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at June 30, 2004 is estimated to be $8 million in ComEd’s favor. If the derivative instrument had been terminated at June 30, 2004, this estimated fair value represents the amount the counterparties would pay ComEd.
The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at June 30, 2004 is estimated to be $7 million in the counterparties’ favor. If the derivative instrument had been terminated at June 30, 2004, this estimated fair value represents the amount ComEd would pay the counterparties.
In April 2004, ComEd settled certain interest-rate swaps designated as fair-value hedges in the aggregate amount of $485 million for total proceeds of approximately $32 million, which included the $26 million settlement amount and $6 million of accrued interest. The $26 million settlement amount will be amortized as a reduction to interest expense over the remaining life of the related debt.
In March 2004, PECO entered into a forward-starting interest rate swap in the aggregate amount of $75 million to lock in interest rate levels in anticipation of a future financing. The debt issuance that this swap was hedging was considered probable in March 2004 and closed in April 2004; therefore, PECO accounted for this interest-rate swap transaction as a hedge. In April 2004, PECO settled this interest-rate swap designated as a cash-flow hedge for net proceeds of approximately $5 million. The proceeds were recorded in other comprehensive income and are being amortized over the life of the debt issuance.
Generation uses a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Generation also uses interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. These strategies are employed to achieve a lower cost of capital. As of June 30, 2004, a hypothetical 10% increase in the interest rates associated with variable- rate debt would not have a material impact on Generation’s pre-tax earnings.
Equity Price Risk
Generation maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of decommissioning its nuclear plants. As of June 30, 2004, decommissioning trust funds are reflected at fair value on Generation’s Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $308 million reduction in the fair value of the trust assets.
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During the second quarter of 2004, each registrant’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarization and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake.
Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Each registrant’s controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. A registrant’s access and ability to apply its disclosure controls and procedures to unconsolidated entities and entities that are consolidated under FIN No. 46-R may be more limited than is the case for majority-owned subsidiaries.
Accordingly, as of June 30, 2004, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives. Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant.
PART II — OTHER INFORMATION
ComEd
See “Retail Rate Law” within the litigation section of Note 15 of the Combined Notes to Consolidated Financial Statements for a discussion of legal proceeding developments.
Generation
See “Raytheon and Mitsubishi Litigation” and “Oyster Creek” within the litigation section of Note 15 of the Combined Notes to Consolidated Financial Statements for a discussion of legal proceeding developments.
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The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock. All share and per-share amounts included in the table below have been adjusted to reflect the stock split.
Exelon
Exelon held its 2004 Annual Meeting of Shareholders on April 27, 2004.
Proposal 1 was the election of four Class I directors to serve three-year terms expiring in 2007. The following directors were elected:
Proposal 2 was the ratification of PricewaterhouseCoopers LLP as independent accountants for Exelon and its subsidiaries for 2004. The shareholders approved the proposal with 262,663,675 votes cast for, 784,220 votes cast against and 2,308,210 votes abstaining.
Proposal 3 was the approval of the Exelon Corporation Annual Incentive Plan (the Plan) for Senior Executives effective January 1, 2004, as described in the proxy statement. The shareholders approved the Plan with 246,985,526 votes cast for, 18,996,405 votes cast against and 4,804,174 votes abstaining.
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PECO
PECO held its 2004 Annual Meeting of Shareholders on May 27, 2004. At the PECO annual meeting, the only proposal was the election of two Class III directors to serve three-year terms expiring in 2007. Denis P. O’Brien and Robert S. Shapard were elected with 170,478,507 votes cast for each director, no votes cast against and no votes abstaining.
(a) ComEd, PECO and Generation
See Note 7 of the Combined Notes to Consolidated Financial Statements and ComEd’s “Management’s Discuss and Analysis of Financial Condition and Results of Operations — Executive Overview” for a discussion of regulatory developments.
As previously reported in the 2003 Form 10-K, on August 15, 2002, the International Brotherhood of Electrical Workers (IBEW) filed a petition with the National Labor Relations Board (NLRB) to conduct a unionization vote of certain of PECO’s employees. On May 21, 2003, the PECO union election was held and a majority of PECO workers voted against union representation. The results of the election were not certified due to pending challenges and objections. On March 22, 2004, the IBEW withdrew its objections to the May 21, 2003 election, and asked the NLRB to allow for a new election at PECO. On April 22, 2004, the NLRB granted IBEW’s request. A new election was held on July 21, 2004, and a majority of PECO employees eligible to vote voted in favor of representation by the IBEW. The NLRB will certify the election on July 29, 2004.
(b) Exelon, ComEd, PECO and Generation
None.
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(a) Exhibits:
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 filed by the following officers for the following companies:
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 filed by the following officers for the following companies:
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(b) Reports on Form 8-K:
Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during the three months ended June 30, 2004 regarding the following items:
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SIGNATURES
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
July 28, 2004
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