10-K 1 d10k.htm FORM 10-K Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-K

 


 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Fiscal Year Ended December 31, 2004

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File

        Number


  

Name of Registrant; State of Incorporation; Address of

Principal Executive Offices; and Telephone Number


   IRS Employer
Identification Number


1-16169

  

EXELON CORPORATION

(a Pennsylvania corporation)

10 South Dearborn Street—37th Floor

P.O. Box 805379

Chicago, Illinois 60680-5379

(312) 394-7398

   23-2990190

1-1839

  

COMMONWEALTH EDISON COMPANY

(an Illinois corporation)

10 South Dearborn Street—37th Floor

P.O. Box 805379

Chicago, Illinois 60680-5379

(312) 394-4321

   36-0938600

1-1401

  

PECO ENERGY COMPANY

(a Pennsylvania corporation)

P.O. Box 8699

2301 Market Street

Philadelphia, Pennsylvania 19101-8699

(215) 841-4000

   23-0970240

333-85496

  

EXELON GENERATION COMPANY, LLC

(a Pennsylvania limited liability company)

300 Exelon Way

Kennett Square, Pennsylvania 19348

(610) 765-6900

   23-3064219

 

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

 

Title of Each Class


   Name of Each Exchange on
Which Registered


EXELON CORPORATION:

    

Common Stock, without par value

   New York, Chicago and
Philadelphia

PECO ENERGY COMPANY:

    

Cumulative Preferred Stock, without par value: $4.68 Series, $4.40 Series, $4.30 Series and $3.80 Series

   New York

Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company

   New York

 

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

 

COMMONWEALTH EDISON COMPANY:

Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants


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

 

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

 

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

 

Exelon Corporation

   Yes  x        No  ¨

Commonwealth Edison Company

   Yes  ¨        No  x

PECO Energy Company

   Yes  ¨        No  x

Exelon Generation Company, LLC

   Yes  ¨        No  x

 

The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2004, was as follows:

 

Exelon Corporation Common Stock, without par value

   $22,048,288,415

Commonwealth Edison Company Common Stock, $12.50 par value

   No established market

PECO Energy Company Common Stock, without par value

   None

Exelon Generation Company, LLC

   Not applicable

 

The number of shares outstanding of each registrant’s common stock as of January 31, 2005 was as follows:

 

Exelon Corporation Common Stock, without par value

   664,807,122

Commonwealth Edison Company Common Stock, $12.50 par value

   127,016,502

PECO Energy Company Common Stock, without par value

   170,478,507

Exelon Generation Company, LLC

   Not applicable

 

 

 



TABLE OF CONTENTS

 

          Page No.

FILING FORMAT

   1

FORWARD-LOOKING STATEMENTS

   1

WHERE TO FIND MORE INFORMATION

   1

PART I

         

ITEM 1.

  

BUSINESS

   2
    

General

   2
    

Energy Delivery

   4
    

Exelon Generation Company, LLC

   11
    

Enterprises

   22
    

Employees

   22
    

Environmental Regulation

   23
    

Security

   29
    

Other Subsidiaries of ComEd and PECO with Publicly Held Securities

   30
    

Executive Officers of the Registrants

   31

ITEM 2.

  

PROPERTIES

   34
    

Energy Delivery

   34
    

Exelon Generation Company, LLC

   35

ITEM 3.

  

LEGAL PROCEEDINGS

   37
    

Commonwealth Edison Company

   37
    

PECO Energy Company

   37
    

Exelon Generation Company, LLC

   37

ITEM 4.

  

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

   38

PART II

         

ITEM 5.

  

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

   39

ITEM 6.

  

SELECTED FINANCIAL DATA

   41
    

Exelon Corporation

   41
    

Commonwealth Edison Company

   43
    

PECO Energy Company

   44
    

Exelon Generation Company, LLC

   45

ITEM 7.

  

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

   46
    

Exelon Corporation

   55
    

Commonwealth Edison Company

   225
    

PECO Energy Company

   282
    

Exelon Generation Company, LLC

   330

ITEM 7A.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   121
    

Exelon Corporation

   121
    

Commonwealth Edison Company

   244
    

PECO Energy Company

   297
    

Exelon Generation Company, LLC

   349

ITEM 8.

  

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   131
    

Exelon Corporation

   131
    

Commonwealth Edison Company

   245
    

PECO Energy Company

   298
    

Exelon Generation Company, LLC

   350

 

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          Page No.

ITEM 9.

  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   411

ITEM 9A.

  

CONTROLS AND PROCEDURES

   411
    

Exelon Corporation

   411
    

Commonwealth Edison Company

   411
    

PECO Energy Company

   411
    

Exelon Generation Company, LLC

   411

PART III

         

ITEM 10.

  

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

   412
    

Exelon Corporation

   412
    

Commonwealth Edison Company

   414
    

PECO Energy Company

   415
    

Exelon Generation Company, LLC

   416

ITEM 11.

  

EXECUTIVE COMPENSATION

   417
    

Exelon Corporation

   417
    

Commonwealth Edison Company

   422
    

PECO Energy Company

   427
    

Exelon Generation Company, LLC

   432

ITEM 12.

  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

   449
    

Exelon Corporation

   449
    

Commonwealth Edison Company

   450
    

PECO Energy Company

   452
    

Exelon Generation Company, LLC

   453

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   453
    

Exelon Corporation

   453
    

Commonwealth Edison Company

   453
    

PECO Energy Company

   454
    

Exelon Generation Company, LLC

   453

ITEM 14.

  

PRINCIPAL ACCOUNTING FEES AND SERVICES

   454
    

Exelon Corporation

   454
    

Commonwealth Edison Company

   455
    

PECO Energy Company

   455
    

Exelon Generation Company, LLC

   455

PART IV

         

ITEM 15.

  

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

   457

SIGNATURES

   474
    

Exelon Corporation

   474
    

Commonwealth Edison Company

   475
    

PECO Energy Company

   476
    

Exelon Generation Company, LLC

   477

 

ii


FILING FORMAT

 

This combined Form 10-K is being filed separately by Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.

 

FORWARD-LOOKING STATEMENTS

 

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, including those discussed in (a) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Business Outlook and the Challenges in Managing the Business for each of Exelon, ComEd, PECO and Generation, (b) ITEM 8. Financial Statements and Supplementary Data: Exelon—Note 21, ComEd—16, PECO—Note 15 and Generation—Note 17 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 a registrant files 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. Information contained on Exelon’s website shall not be deemed incorporated into, or to be a part of, this Report.

 

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

 

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PART I

 

ITEM 1. BUSINESS

 

General

 

Exelon, a registered public utility holding company, through its subsidiaries, operates in three business segments—Energy Delivery, Generation and Enterprises—as described below. See Note 22 of Exelon’s Notes to Consolidated Financial Statements for further segment information. In addition to Exelon’s three business segments, Exelon Business Services Company (BSC), a subsidiary of Exelon, provides Exelon and its subsidiaries with financial, human resource, legal, information technology, supply management and corporate governance services.

 

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

 

Proposed Merger with Public Service Enterprise Group Incorporated

 

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), the holding company for an electric and gas utility company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2004, PSEG’s market capitalization was over $12 billion. Additionally, PSEG, on a consolidated basis, has approximately $14 billion of outstanding debt which is currently anticipated to become part of Exelon’s consolidated debt.

 

The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million and (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. The parties have made certain of the regulatory filings to obtain necessary regulatory approvals. It is anticipated that this approval process will be completed and the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004. Further information concerning the proposed Merger is included in the preliminary joint proxy statement/prospectus contained in the registration statement on Form S-4 filed by Exelon in connection with the Merger. For additional information related to the Merger, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Executive Overview—Proposed Merger with PSEG and Note 2 of Exelon’s Notes to Consolidated Financial Statements.

 

Energy Delivery

 

Exelon’s energy delivery business consists of the purchase and regulated sale of electricity and distribution and transmission services by ComEd in northern Illinois, including the City of Chicago, and by PECO in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia (collectively, Energy Delivery).

 

ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation named Commonwealth Edison Company, which was

 

2


incorporated in 1907. ComEd’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-4321. PECO was incorporated in Pennsylvania in 1929. PECO’s principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19103 and its telephone number is 215-841-4000.

 

Generation

 

At December 31, 2004, Exelon’s generation business consists of the owned and contracted-for electric generating facilities and energy marketing operations of Generation, a 50% interest in Sithe Energies, Inc. (Sithe), 49.5% interests in two power stations in Mexico and the competitive retail sales business of Exelon Energy Company (Exelon Energy). On January 31, 2005, Exelon purchased the remaining 50% of Sithe and immediately sold its entire interest in Sithe.

 

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

 

Enterprises

 

Exelon’s enterprises business is comprised of infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises) and other investments weighted towards the communications and energy services industries. During 2004 and 2003, Enterprises exited a significant number of businesses and investments. Exelon plans to divest or wind down the remaining assets of Enterprises during 2005.

 

Federal and State Regulation

 

Exelon, a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA), is subject to Federal and state regulation. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the Illinois Commerce Commission (ICC). PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the Pennsylvania Public Utility Commission (PUC). ComEd, PECO and Generation are electric utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). Specific operations of Exelon are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the United States Nuclear Regulatory Commission (NRC).

 

Exelon is subject to a number of restrictions under PUHCA. These restrictions generally involve financing, investments and affiliate transactions. Under PUHCA, Exelon cannot issue debt or equity securities or guarantees without approval of the United States Securities and Exchange Commission (SEC) or, in the case of ComEd and PECO, the ICC and the PUC, respectively. On April 1, 2004, Exelon obtained a new order under 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 the Exelon holding company and Generation at December 31, 2003. No securities have been issued under the above described limit as of December 31, 2004. Exelon is also authorized to issue up to $6.0 billion in guarantees or letters of credit or otherwise provide credit support with respect to the obligations of their subsidiaries and non-affiliated third parties in the normal course of business. As of December 31, 2004, Exelon had $2.0 billion of guarantees and letters of credit outstanding pursuant to SEC authorization.

 

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PUHCA also limits the businesses in which Exelon may engage and the investments that Exelon may make. With limited exceptions, Exelon may only engage in traditional electric and gas utility businesses and other businesses that are reasonably incidental or economically necessary or appropriate to the operations of the utility business. The exceptions include Exelon’s ability to invest in exempt telecommunications companies, exempt wholesale generating businesses and foreign utility companies (these investments are capped at $4 billion in the aggregate), energy-related companies (as defined in SEC rules and subject to a cap on these investments of 15% of Exelon’s consolidated capitalization), and other businesses, subject to SEC approval. In addition, PUHCA requires that all of a registered holding company’s utility subsidiaries constitute a single system that can be operated in an efficient, coordinated manner.

 

For additional information about restrictions on the payment of dividends and other effects of PUHCA on Exelon and its subsidiaries, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon.

 

Energy Delivery

 

Energy Delivery consists of Exelon’s regulated energy delivery operations conducted by ComEd and PECO.

 

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

 

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

 

ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generally nonexclusive rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights have stated expiration dates ranging from 2005 to 2060 and subsequent years. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements upon expiration.

 

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

 

PECO’s retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.8 million. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.7 million, including 1.5 million in Philadelphia. Natural gas service is supplied in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 460,000 customers.

 

4


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

 

Energy Delivery’s kilowatthour (kWh) sales and load of electricity are generally higher during the summer periods and winter periods, when temperature extremes create demand for either summer cooling or winter heating. ComEd’s highest peak load occurred on August 21, 2003 and was 22,054 megawatts (MWs); its highest peak load during a winter season occurred on December 22, 2004 and was 15,222 MWs. PECO’s highest peak load occurred on August 14, 2002 and was 8,164 MWs; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MWs.

 

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

 

Retail Electric Services

 

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

 

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

 

ComEd. All of ComEd’s customers are eligible to choose an alternative electric supplier and most non-residential customers can also elect the power purchase option (PPO) that allows the purchase of electric energy from ComEd at market-based prices. As of December 31, 2004, no alternative electric supplier had approval from the ICC, and no electric utilities had chosen to enter the residential market for the supply of electricity in ComEd’s service territory. At December 31, 2004, approximately 22,100 non-residential customers, representing approximately 35% of ComEd’s annual retail kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier or had chosen the PPO. Customers who receive energy from an alternative electric supplier and customers who have elected the PPO continue to pay a delivery charge to ComEd, which generally includes a CTC. ComEd is unable to predict the long-term impact of customer choice on its results of operations.

 

On November 14, 2002, the ICC allowed ComEd, by operation of law, to revise its POLR obligation to be the back-up energy supplier at market-based rates for certain customers with energy demands of at least three MWs. About 370 of ComEd’s largest energy customers are affected,

 

5


representing an aggregate of approximately 2,500 MWs. These customers will not have a right to take bundled service after June 2006 or to return to bundled rates if they choose an alternative supplier prior to June 2006. On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff for non-residential customers, including those with energy demands of at least three MWs who choose hourly energy supply for their electric power and energy. These ICC orders were affirmed on appeal.

 

In addition to retail competition for generation services, the Illinois legislation provided for residential base rate reductions, a sharing with customers of any earnings over a defined threshold and a base rate freeze, reflecting the residential base rate reductions, through January 1, 2007. A 15% residential base rate reduction became effective on August 1, 1998, and a further 5% residential base rate reduction became effective October 1, 2001. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility’s financial viability. Under the Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on a two-year average of the Monthly Treasury Bond Long-Term Average Rates (20 years and above) plus 8.5% in the years 2000 through 2006. Earnings for purposes of ComEd’s threshold include ComEd’s net income calculated in accordance with accounting principles generally accepted in the United States (GAAP) and reflect the amortization of regulatory assets. Under the Illinois statue, any impairment of goodwill has no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2004, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $87 million, which it expects to fully recover and amortize by the end of 2006. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered in amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The earned return on common equity and the threshold return on common equity for ComEd are each calculated on a two-year average basis. ComEd has not triggered the earnings sharing provision through 2004 and does not currently expect to trigger the earnings sharing provision in 2005 or 2006.

 

ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2005. The base rate freeze, coupled with other provisions of the Illinois restructuring law, generally precludes rate recovery of and on such incremental investments prior to January 1, 2007. Unless ComEd can offset the additional carrying costs against cost reductions, its return on investment will be reduced during the remaining period of the rate freeze and until rate increases are approved authorizing a return of and on this new investment.

 

The rates for the generation service provided by ComEd under bundled rates are subject to a rate freeze during the transition period ending December 31, 2006. ComEd has entered into a power purchase agreement (PPA) with Generation under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation.

 

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

 

6


ComEd’s market value energy credit is used to determine the price for specified market-based rate offerings and the amount of the CTC that ComEd is allowed to collect from customers who select an alternative electric supplier or the PPO. The credit was adjusted upwards through agreed upon “adders” which took effect in June 2003 and has had and will continue to have the effect of reducing ComEd’s CTCs to customers. Prior to 2003, all CTCs were subject to annual mid-year adjustments based on the forward market prices for on-peak energy and historical market prices for off-peak energy. The current annual market price adjustment reflects forward, rather than historical, market prices for off-peak energy and allows customers to lock in current levels of CTCs for multi-year periods during the regulatory transition period ending in 2006. These changes provide customers and suppliers greater price certainty and have resulted in an increase in the number of customers electing to purchase energy from alternate suppliers.

 

In 2004 and 2003, ComEd collected $169 million and $304 million in CTC revenues, respectively. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, ComEd estimates that CTC revenue will amount to approximately $90 million to $110 million in each of the years 2005 and 2006.

 

The Illinois legislation provides that an electric utility, such as ComEd, will be liable for actual damages suffered by customers in the event of a continuous power outage of four hours or more affecting 30,000 or more customers and provides for reimbursement of governmental emergency and contingency expenses incurred in connection with any such outage. The legislation bars recovery of consequential damages. The legislation also allows an affected utility to seek relief from these provisions from the ICC when the utility can show that the cause of the outage was unpreventable due to weather events or conditions, customer tampering or third-party causes. During the years 2002, 2003 and 2004, ComEd did not have any outages that triggered the reimbursement requirement.

 

PECO. Under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), all of PECO’s retail electric customers have the right to choose their generation suppliers. At December 31, 2004, approximately 4% of PECO’s residential load, 23% of its small commercial and industrial load and 6% of its large commercial and industrial load were purchasing generation service from alternative generation suppliers. Customers who purchase energy from an alternative electric supplier continue to pay a delivery charge to PECO.

 

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

 

Under the 1998 settlement, PECO’s distribution rates were capped through June 30, 2005 at the level in effect on December 31, 1996. Generation rates, consisting of the charge for stranded cost recovery and a shopping credit or capacity and energy charge, were capped through December 31, 2010. For 2004, the generation rate cap was $0.0698 per kWh, increasing to $0.0751 per kWh in 2006 and $0.0801 per kWh in 2007. The rate caps are subject to limited exceptions, including significant increases in Federal or state taxes or other significant changes in law or regulations that would not allow PECO to earn a fair rate of return. Under the settlement agreement entered into by PECO in 2000 relating to the PUC’s approval of the merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (PECO / Unicom Merger), PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005 and extended the rate cap on distribution rates through December 31, 2006. The remaining required rate reductions are $40 million in 2005.

 

7


As a mechanism for utilities to recover their allowed stranded costs, the Competition Act provides for the imposition and collection of non-bypassable transition charges on customers’ bills. Transition charges are assessed to and collected from all retail customers who have been assigned stranded cost responsibility and access the utility’s transmission and distribution systems. As the transition charges are based on access to the utility’s transmission and distribution system, they are assessed regardless of whether the customer purchases electricity from the utility or an alternative electric supplier. The Competition Act provides, however, that the utility’s right to collect transition charges is contingent on the continued operation, at reasonable availability levels, of the assets for which the stranded costs were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.

 

PECO has been authorized by the PUC to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010, with a return on the unamortized balance of 10.75%. See the “Business Outlook and the Challenges Managing the Business” section of ITEM 7 of this Form 10-K for the estimated revenues and amortization expense associated with CTC collection and stranded cost recovery through 2010.

 

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

 

PECO has entered into a PPA with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

 

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

 

Transmission Services

 

Energy Delivery provides wholesale and unbundled retail transmission service under rates established by the FERC. The FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. Under the FERC’s open transmission access policy promulgated in Order No. 888, ComEd and PECO, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. Under the FERC’s Order No. 889, ComEd and PECO are required to comply with the FERC’s Standards of Conduct regulation, as amended, governing the communication of non-public information between the transmission owner’s transmission employees and wholesale merchant employees or the employees of any energy affiliate of the transmission owner. The FERC recently issued Order No. 2004, amending the Standards of Conduct regulation. The amendments do not detrimentally affect Exelon’s business.

 

8


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

 

The FERC has attempted to expand the development of regional markets, which has generated substantial opposition from some state regulators and other governmental bodies. In addition, efforts to develop an RTO have been abandoned in certain regions. Notwithstanding these difficulties, the Midwest Independent System Operator, Inc. (MISO), has been certified as an RTO by FERC. MISO is attempting to develop central generation dispatch and transmission operations across the Midwestern United States, contiguous to PJM’s footprint. The FERC has ordered the elimination of rate barriers and protocol differences between MISO and PJM. Exelon supports the development of RTOs and implementation of standard market protocols, but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The development of large competitive wholesale electricity markets would facilitate an auction to meet ComEd’s and PECO’s POLR load obligations with reliable wholesale electricity supply when their PPAs with Generation expire.

 

In November 2004, the FERC issued two orders authorizing ComEd and PECO to recover from various entities revenue representing amounts ComEd and PECO will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across ComEd’s and PECO’s transmission systems, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of the T&O charges, ComEd and PECO collected net T&O charges of approximately $50 million and $3 million, respectively. As a result of the proceeding, ComEd may see reduced net collections and PECO may become a net payer of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s and PECO’s financial condition, results of operations or cash flows.

 

Certain PJM transmission owners, including ComEd and PECO, are subject to a rate design proceeding before the FERC. The issues in this proceeding involve the methodology used by PJM to charge customers for each PJM transmission owner’s regulated revenue requirement associated with its electric transmission facilities. On January 31, 2005, certain PJM transmission owners, including ComEd and PECO, made two separate filings in which the transmission owners jointly proposed to retain the present modified zonal rate design applicable within PJM and to implement three separate rate options for recovery of the revenue requirement associated with their new and existing facilities. As part of the group of PJM transmission owners, both ComEd and PECO proposed to retain the present rate design through January 2008, at which time the FERC could reevaluate the continuation of the rate design in PJM. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s and PECO’s financial condition, results of operations or cash flows.

 

ComEd. 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 April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration

 

9


into PJM, subject to certain stipulations including a provision to hold certain utilities in Michigan and Wisconsin harmless from the associated impacts for ComEd to join PJM. ComEd agreed to these stipulations and transferred functional control of its transmission assets to PJM and integrated fully into PJM’s energy market structures on May 1, 2004. In the fourth quarter of 2004, ComEd entered into settlement agreements with all such Michigan and Wisconsin utilities requiring a total payment of approximately $4 million by ComEd. FERC has approved these agreements and payment is expected to be made in the first quarter of 2005.

 

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 improvements 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. During the third quarter of 2004, a settlement agreement was reached which was approved by the FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.

 

PECO. PECO provides regional transmission service pursuant to PJM’s regional open-access transmission tariff. PECO and the other transmission owners in PJM have turned over control of their transmission facilities to PJM.

 

Gas

 

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

 

PECO’s gas customers have the right to choose their gas suppliers or to purchase their gas supply from PECO at cost. Approximately 32% of PECO’s current total yearly throughput is provided by gas suppliers other than PECO. Gas transportation service provided to customers by PECO remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services.

 

PECO’s natural gas supply is provided by purchases from a number of suppliers for terms of up to eight years. These purchases are delivered under several long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 47.7 million dekatherms. Peak gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 22.0 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 29% of PECO’s 2004-2005 heating season planned supplies.

 

Construction Budget

 

Energy Delivery’s business is capital intensive and requires significant investments in energy transmission and distribution facilities, and in other internal infrastructure projects. The following table shows Exelon’s most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2005:

 

(in millions)


   ComEd

   PECO

Transmission and distribution

   $ 716    $ 210

Gas

     —        62

Other

     26      9
    

  

Total

   $ 742    $ 281
    

  

 

10


Approximately 50% of ComEd’s and 65% of PECO’s 2005 budgeted capital expenditures are for additions to or upgrades of existing facilities, including improvements to reliability. The remainder of the capital expenditures support customer and load growth.

 

Generation

 

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

 

At December 31, 2004, Generation owned generation assets with a net capacity of 25,756 MWs, including 16,751 MWs of nuclear capacity. Generation controls another 8,701 MWs of capacity through long-term contracts.

 

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

 

Exelon Energy Company became part of Generation effective as of January 1, 2004. Exelon Energy provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Michigan and Ohio. Exelon Energy’s business is dependent upon continued deregulation of retail electric and gas markets and its ability to obtain supplies of electricity and gas at competitive prices in the wholesale market. The low-margin nature of the business makes it important to service customers with higher volumes so as to manage costs.

 

Generating Resources

 

At December 31, 2004, the generating resources of Generation consisted of the following:

 

Type of Capacity


   MWs

Owned generation assets (a)

    

Nuclear

   16,751

Fossil (b)

   7,372

Hydroelectric

   1,633
    

Owned generation assets

   25,756

Long-term contracts (c)

   8,701

TEG and TEP (d)

   230
    

Total generating resources

   34,687
    

(a) See ITEM 1. Business—Generation “Fuel” for sources of fuels used in electric generation.
(b) Included 663 MWs related to directly owned generating assets of Sithe and 222 MWs related to the total capacity of the Southeast Chicago Energy Project. See Note 25 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding the 2005 sale of Sithe.
(c) Contracts range from 4 to 29 years.
(d) Generation, through its investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), owns 49.5% interests in two facilities in Mexico, each with a capacity of 230 MWs.

 

The owned generating resources of Generation are located in the Mid-Atlantic region (approximately 45% of capacity), the Midwest region (approximately 43% of capacity), the Southern

 

11


region (approximately 10%), and the Northeast region (approximately 2% of capacity). The 8,701 MWs of capacity that Generation controls through long-term contracts are in the Midwest, Southeast and South Central regions.

 

In December 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen), making AmerGen a wholly owned subsidiary of Generation. The final purchase price was $267 million after working capital adjustments.

 

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 with put and call options that could result in either party owning Sithe outright. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe and, on November 1, 2004, Generation entered into an agreement to sell Sithe to Dynegy Inc. The acquisition of Reservoir’s 50% interest in Sithe and the subsequent sale of 100% of Sithe to Dynegy occurred on January 31, 2005. The sale did not include Sithe International Inc. (Sithe International), which was sold to a subsidiary of Generation on October 13, 2004. Sithe International, through its subsidiaries, has 49.5% interests in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International Inc. See further discussion of these transactions in Notes 3 and 25 of Exelon’s Notes to Consolidated Financial Statements.

 

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. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity and its contractors on September 1, 2004. See Note 2 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding the sale of Boston Generating.

 

Nuclear Facilities

 

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with 16,751 MW of capacity. For additional information, see ITEM 2. Properties. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at the Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC, an indirect, wholly owned subsidiary of PSEG. AmerGen operates the Clinton Nuclear Power Station, Three Mile Island (TMI) Unit 1 and Oyster Creek Nuclear Generating Station facilities.

 

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

 

In 2004, over 67% of Generation’s electric supply was generated from the nuclear generating facilities. During 2004 and 2003, the nuclear generating facilities operated by Generation operated at weighted average capacity factors of 93.5% and 93.4%, respectively.

 

Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for the Peach Bottom Units 2 and 3, Dresden

 

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Units 2 and 3, and the Quad Cities Units. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal is expected to be filed by August 2005 in order to comply with this agreement. Generation is currently evaluating the other nuclear units for possible license renewal. The operating license renewal process takes approximately four to five years from the commencement of the project until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the current license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which assume the renewal of the operating licenses for all of Generation’s operating nuclear generating stations.

 

In 2004, Generation joined a consortium of eleven companies, NuStart Energy Development, LLC, which was formed for the purpose of seeking a license to build a new nuclear facility under the NRC’s new permitting process.

 

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

 

Station


   Unit

   In-Service
Date


   Current License
Expiration


Braidwood

   1    1988    2026
     2    1988    2027

Byron

   1    1985    2024
     2    1987    2026

Clinton

   1    1987    2026

Dresden

   2    1970    2029
     3    1971    2031

LaSalle

   1    1984    2022
     2    1984    2023

Limerick

   1    1986    2024
     2    1990    2029

Oyster Creek

   1    1969    2009

Peach Bottom

   2    1974    2033
     3    1974    2034

Quad Cities

   1    1973    2032
     2    1973    2032

Salem

   1    1977    2016
     2    1981    2020

Three Mile Island

   1    1974    2014

 

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

 

NRC reactor oversight results for the fourth quarter of 2004 indicate that the performance indicators for the nuclear plants operated by Generation are all in the highest performance band.

 

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

 

As of December 31, 2004, Generation had 43,156 SNF assemblies (10,360 tons) stored on site in SNF pools or dry cask storage. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites. The following table describes the current status of Generation’s SNF storage facilities.

 

Site


   Date for loss of full core reserve (a)

Dresden

   Dry cask storage in operation

Quad Cities (b)

   2004

Byron

   2011

LaSalle

   2012

Braidwood

   2013

Clinton (c)

   2006

Peach Bottom

   Dry cask storage in operation

Limerick

   2009

Oyster Creek

   Dry cask storage in operation

Three Mile Island

   Life of plant storage capable in SNF pool

Salem

   2011

(a) The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to discharge a full complement of fuel from the reactor core.
(b) Dry cask storage to begin operation in 2005.
(c) A modification to the on-site storage pool is in progress to increase the amount of SNF that can be stored in the pool. This will move the date for loss of full core reserve at Clinton out to approximately 2012.

 

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE’s current estimate for opening a SNF permanent disposal facility is 2012. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Peach Bottom and Oyster Creek Stations and its consideration of dry cask storage at other stations. See Note 14 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding spent fuel storage claims and issues.

 

During the third quarter of 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement of a suit originally commenced by ComEd in 1998. Under the settlement, the government will reimburse Exelon for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfilment of its obligations to take possession of SNF. Under the settlement agreement, Generation received $80 million in gross reimbursements for storage

 

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costs already incurred ($53 million net, after considering amounts due from Exelon to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

 

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to pay the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2004, the unfunded liability for the one-time fee with interest (which has been assumed by Generation) was $878 million. Interest accrues at the 13-week Treasury Rate, which was 1.987% at December 31, 2004. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owner. The Clinton unit has no outstanding obligation.

 

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

 

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

 

The National Energy Policy Act of 1992 requires that the owners of nuclear reactors pay for the decommissioning and decontamination of the DOE uranium enrichment facilities. The total cost to all domestic utilities covered by this requirement was originally $150 million per year through 2006, of which Generation’s share was approximately $20 million per year. Payments are adjusted annually to reflect inflation. Including the effect of inflation, Generation paid $26 million in 2004.

 

Nuclear Insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of December 31, 2004, the current limit was $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.46 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.

 

The Price-Anderson Act expired on August 1, 2002 and was subsequently extended to the end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to the expiration of the Price-Anderson Act are affected by the expiration of the Price-Anderson Act. Existing commercial

 

15


generating facilities, such as those owned and operated by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration. However, new licenses are not covered under the Price-Anderson Act and any new plant initiatives would need to address this exposure.

 

See “Nuclear Insurance” within Note 16 of Generation’s Notes to Consolidated Financial Statements for a description of nuclear-related insurance coverage.

 

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

 

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

 

In connection with the transfer of ComEd’s nuclear generating stations to Generation, ComEd asked the ICC to approve the continued recovery of decommissioning costs after the transfer. On December 20, 2000, the ICC issued an order finding that the ICC has the legal authority to permit ComEd to continue to recover decommissioning costs from customers for the six-year term of the PPA between ComEd and Generation. Under the ICC order, ComEd was permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd is permitted to recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from Generation. Because ComEd is not expected to take all of the output of these stations, actual collections are expected to be less than $73 million annually in 2005 and 2006. Under the ICC order, subsequent to 2006, there will be no further recoveries though rates of decommissioning costs from ComEd’s customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to ComEd’s customers. The ICC order has been upheld on appeal.

 

Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be recovered currently through rates charged by PECO to customers. Amounts recovered, currently $33 million per year, are remitted to Generation as allowed by the PUC.

 

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

 

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

 

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Zion, a two-unit nuclear generation station, Peach Bottom Unit 1 and Dresden Unit 1 have permanently ceased power generation. SNF at Zion and Dresden Unit 1 is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. All of Peach Bottom Unit 1’s SNF has been moved off site. Generation has recorded a liability totaling $762 million at December 31, 2004, which represents the estimated cost of decommissioning Zion, Peach Bottom Unit 1 and Dresden Unit 1 in current year dollars. Certain decommissioning costs are currently being incurred; however, the majority of decommissioning expenditures are expected to occur primarily after 2013, 2033 and 2030 for Zion, Peach Bottom Unit 1 and Dresden Unit 1, respectively.

 

Fossil and Hydroelectric Facilities

 

Generation operates various fossil and hydroelectric facilities and maintains ownership interest in several other facilities such as La Porte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2004, approximately 8% of Generation’s electric supply was generated from Generation’s owned fossil and hydroelectric generating facilities. The majority of this output was dispatched to support Generation’s power marketing activities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. Properties—Generation.

 

Licenses. Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. Hydroelectric plants are licensed by the FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is considering applying to the FERC for license renewals of 40 years for the Muddy Run and Conowingo plants, but the duration of any license renewal will depend on then-current policies at the FERC. The processing of a renewal to a hydroelectric license generally takes at least eight years.

 

Insurance. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. For its other types of insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon and Generation’s financial condition and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. Properties—Generation.

 

Long-Term Contracts

 

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

 

Seller


  Location

  Expiration

  Capacity (MWs)

Kincaid Generation, LLC

  Kincaid, Illinois   2013   1,108

Tenaska Georgia Partners, LP

  Franklin, Georgia   2030       925

Tenaska Frontier, Ltd

  Shiro, Texas   2020       830

Green Country Energy, LLC

  Jenks, Oklahoma   2022       795

Elwood Energy, LLC

  Elwood, Illinois   2012       772

Lincoln Generating Facility, LLC

  Manhattan, Illinois   2011       664

Reliant Energy Aurora, LP

  Aurora, Illinois   2008       600

Others

  Various   2005 to 2021   3,007
           

Total

          8,701
           

 

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Federal Power Act

 

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

 

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

 

In December 1999, the FERC issued Order No. 2000 to encourage the voluntary formation of RTOs which would provide transmission service across multiple transmission systems. The intended benefits of establishing these entities includes the development of larger wholesale markets and the elimination or reduction of transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity. Order No. 2000 and the FERC’s effort to promote RTOs throughout the states have generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop a RTO have been abandoned in certain regions.

 

PJM has been approved as a RTO, as has the Midwest ISO. ISO New England, the system operator for New England where Generation also owns facilities, was approved as a RTO on February 2, 2005.

 

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

 

The FERC recently announced new market power tests for suppliers to qualify to sell power at market-based rates. These new tests, the market share test and the pivotal supplier test, must both be passed by Generation, or market power mitigation must be imposed for Generation to continue to make sales of capacity and energy in the wholesale market at market based rates. Generation filed its analysis of the application of the tests on September 27, 2004, which proposed that Generation passed the market power screens. The FERC allows the relevant geographic market to include a RTO’s footprint, and Generation used an expanded PJM footprint as the relevant market. Because ComEd and PECO, which purchase most of Generation’s power, are members of PJM, Generation, for the most part, is selling into the PJM market. On January 5, 2005, the FERC issued a deficiency letter to Generation requesting a response to twelve separate questions relating to Generation’s filing. On January 26, 2005, Generation filed an initial response to the deficiency letter, answering certain questions and requesting until February 14, 2005 to complete the response to the deficiency letter. The FERC continues to process Generation’s application and market power analysis, as well as other applicants’ filings. Management expects that Generation will eventually pass the market power

 

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screens; however, there is no certainty as to what final determination will be made by the FERC in regard to Generation’s filing and the filings of other applicants.

 

Currently, a significant portion of Generation’s capacity is located within the PJM RTO area. If the FERC were to suspend Generation’s market-based rate authority, Generation would be required to supply and implement a plan for mitigation of market power. FERC’s default mitigation would require Generation to file and obtain FERC acceptance of cost-based rate schedules or schedules tied to a public index. In addition, the loss of market-based rate authority would subject Generation to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules.

 

Fuel

 

The following table shows sources of electric supply in gigawatthours (GWhs) for 2004 and estimated for 2005:

 

     Source of Electric Supply

     2004

   2005 (Est.)

Nuclear units

   136,621    137,870

Purchases—non-trading portfolio

   48,968    44,479

Fossil and hydroelectric units

   17,010    21,325
    
  

Total supply

   202,599    203,674
    
  

 

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

 

The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2007. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2007. All of Generation’s enrichment requirements have been contracted through 2007. Contracts for fuel fabrication have been obtained through 2007. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for its nuclear units.

 

Generation obtains approximately 25% of its uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. alleging dumping in the United States against European enrichment services suppliers. In January 2002, the U.S. International Trade Commission determined that USEC, Inc. was “materially injured or threatened with material injury” by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC, Inc. and the European suppliers have appealed these decisions. Generation is uncertain at this time as to the outcome of the pending appeals; however, as a result of these actions, Generation may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.

 

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

 

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

 

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

 

Power Team

 

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

 

Power Team also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. The maximum length of time over which cash flows related to energy commodities are currently being hedged is three years. Generation’s hedge ratio in 2005 for its energy marketing portfolio is approximately 90%. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. During peak periods, the amount hedged declines to assure Generation’s commitment to meet Energy Delivery’s demand, for which the peak demand is during the summer. For the portion of generation supply that is unhedged, fluctuations in market price of energy will cause volatility in Generation’s results of operations.

 

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

 

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At December 31, 2004, Generation’s long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from and to unaffiliated utilities and others were as follows:

 

(in millions)


   Net Capacity
Purchases (a)


   Power Only
Sales


   Power Only Purchases
from Non-Affiliates


  

Transmission Rights
Purchases (b)


2005

   $ 578    $ 2,551    $ 1,446    $ 31

2006

     581      961      605      3

2007

     533      167      254      —  

2008

     462      9      195      —  

2009

     437      9      194      —  

Thereafter

     3,664      343      548      —  
    

  

  

  

Total (c)

   $ 6,255    $ 4,040    $ 3,242    $ 34
    

  

  

  


(a) Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2004. Expected payments include certain capacity charges which are conditional on plant availability.
(b) Transmission rights purchases include estimated commitments in 2005 and 2006 for additional transmission rights that will be required to fulfill firm sales contracts.
(c) Included in the totals are $395 million of power only sales commitments related to Sithe, which were not retained by Generation following the sale of Sithe. See Note 3 and Note 25 of Exelon’s Notes to Consolidated Financial Statements for further discussion of these transactions.

 

In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, Generation has a PPA with PECO under which Generation has agreed to supply PECO with substantially all of PECO’s electric supply needs through 2010. PECO has also assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies power to PECO from the transferred generation assets, assigned PPAs and other market sources. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

 

When AmerGen acquired Clinton Nuclear Power Station (Clinton), AmerGen entered into a power sales agreement with the seller, Illinois Power Company (Illinois Power). The agreement with Illinois Power was for 68.8% of Clinton’s output for a term that expired on December 31, 2004. Generation has subsequently entered into a separate agreement with Illinois Power to provide fixed quantities of power under a power sales agreement over future periods beginning January 1, 2005. This agreement is included in the commitment table presented above.

 

Capital Expenditures

 

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2005 are as follows:

 

(in millions)


    

Production plant

   $ 575

Nuclear fuel

     498
    

Total

   $ 1,073
    

 

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Enterprises

 

During 2004 and 2003, Enterprises exited a significant number of businesses and investments, as described below. As of December 31, 2004, Enterprises consisted primarily of the remaining electrical contracting business of F&M Holdings, LLC. Enterprises is continuing to pursue opportunities to sell its remaining businesses.

 

Exelon Energy Company. Effective January 1, 2004, Enterprises competitive retail sales business, Exelon Energy Company, was transferred to Generation.

 

InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. for cash proceeds of approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale plus a $30 million subordinated note. Enterprises recorded a net pre-tax loss and minority interest of $4 million associated with the sale and goodwill impairment charge in 2003.

 

Exelon Services, Inc. During 2004, Enterprises disposed of or wound down all of the operating businesses of Exelon Services, Inc. (Exelon Services), including Exelon Solutions, the mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the pre-tax net gain on sale recorded in 2004 related to the disposition of the Exelon Services businesses were $61 million and $9 million, respectively.

 

Exelon Thermal Holdings, Inc. On June 30, 2004, Enterprises sold its Chicago businesses of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million and expected proceeds of $2 million from a working capital settlement, resulting in a pre-tax gain of $36 million, net of debt prepayment penalties. On September 29, 2004, Enterprises closed on the sale of ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, subject to working capital adjustments. Enterprises recorded a pre-tax loss of $3 million related to the disposition. On October 28, 2004, Northwind Windsor, of which Enterprises owns a 50% interest, sold substantially all of its assets, providing Enterprises with cash proceeds of $8 million, resulting in a pre-tax gain of $2 million.

 

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, resulting in a pre-tax gain of $9 million.

 

Exelon Capital Partners Holdings, LLC. During 2004, Enterprises sold its direct investments and investments in three of its four venture capital funds.

 

Employees

 

As of December 31, 2004, Exelon and its subsidiaries had approximately 17,300 employees in the following companies:

 

ComEd

   5,600

PECO

   2,100

Generation

   7,500

Enterprises

   100

Corporate (a)

   2,000
    

Total

   17,300
    

(a) Includes shared services employees.

 

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Approximately 5,500 employees, including 3,800 employees of ComEd, 1,600 employees of Generation and 100 employees of BSC, are covered by collective bargaining agreements (CBAs) with Local 15 of the International Brotherhood of Electrical Workers (IBEW Local 15). AmerGen has separate CBAs for each of its nuclear facilities, which cover an aggregate of approximately 700 employees. The Generation CBA with IBEW Local 15 has been extended to September 30, 2007. The CBA for ComEd and BSC expires on September 30, 2008. The Clinton, Oyster Creek and TMI CBAs expire on December 15, 2005, January 31, 2006 and February 28, 2009, respectively. Exelon Power, an operating unit of Generation, has negotiated and ratified its first agreement with IBEW Local 614. The agreement expires on January 31, 2008 and covers approximately 200 employees.

 

In addition to IBEW Local 15, IBEW Local 614 and the four IBEW locals covering the AmerGen facilities, approximately 50 Generation employees are represented by the Utility Workers Union of America.

 

During 2004, two elections were held at PECO which resulted in union representation for approximately 1,100 employees in the Philadelphia service territory. PECO and IBEW Local 614 will begin negotiations for an initial agreement in the first quarter of 2005.

 

The employees of the Limerick and Peach Bottom nuclear stations are not currently covered by a CBA. IBEW 614 has filed a petition with the National Labor Relations Board to hold a certification election at these sites. The election will be held in the first quarter of 2005.

 

Environmental Regulation

 

General

 

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

 

Water

 

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

 

In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be

 

23


implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility, and performing environmental and economic cost benefit evaluation of the potential compliance alternatives in accordance with the requirements. Generation is also subject to the jurisdiction of certain other state and interstate agencies, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.

 

In June 2001, the New Jersey Department of Environmental Protection (NJDEP) issued a renewed National Pollutant Discharge Elimination System 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 Federal Water Pollution Control Act Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless NJDEP grants additional time to collect information to comply with the new regulations. NJDEP advised PSEG 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. PSEG 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 requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit and an resulting cost of interim replacement power could result in material costs of compliance to the owners of the facility.

 

Solid and Hazardous Waste

 

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

 

ComEd, PECO and Generation and their subsidiaries are or are likely to become parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including manufactured gas plant (MGP) sites, or may

 

24


undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third party.

 

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

 

By notice issued in December 1987, the EPA notified several entities, including PECO, that they may be PRPs under CERCLA with respect to wastes resulting from the treatment and disposal of transformers and miscellaneous electrical equipment at a site located in Philadelphia, Pennsylvania (Metal Bank of America site). Several of the PRPs, including PECO, formed a steering committee to investigate the nature and extent of possible involvement in this matter. On May 29, 1991, a Consent Order was issued by the EPA pursuant to which the members of the steering committee agreed to perform the remedial investigation and feasibility study as described in the work plan issued with the Consent Order. PECO’s share of the cost of the study was approximately 30%. On July 19, 1995, the EPA issued a proposed plan for remediation of the site, which involves removal of contaminated soil, sediment and groundwater and which the EPA estimated would cost approximately $17 million to implement. On June 26, 1998, the EPA issued an order to the non-de minimis PRP group members, and others, including the owner, to implement the remedial design and remedial action.

 

The PRP group has conducted the remedial design and submitted to the EPA the revised final design on January 15, 2003. During the design process, the PRP group proposed certain revisions to the EPA’s preferred remedy, in response to which the EPA has issued two explanations of significant differences that are expected to reduce the costs of the preferred remedy. The final design estimates for the cost to implement the remedial action range from $14 million to $17 million. Significant progress has been made in settlement discussions between the EPA, the PRP group and the former owners and operators of the site. Exelon now believes that it is probable that the parties will agree to a settlement within the remedial range and that Exelon’s share of such settlement will be approximately 30%. This amount does not include Exelon’s share of the PRP group’s future legal and technical expenses, which are not expected to be material. The settlement amount will also not include any damages for natural resource damages that the EPA or state environmental agencies may seek to obtain in the future, and at this time PECO cannot predict with reasonable certainty the likelihood that such damages will be sought or the amount of any such damages.

 

Cotter Corporation

 

The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700

 

25


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

 

MGP Sites

 

MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to 1950. ComEd and PECO generally did not operate MGPs as corporate entities but did, however, acquire MGP sites as part of the absorption of smaller utilities. Approximately half of the ComEd sites were transferred to Nicor Gas as part of a general conveyance in 1954. ComEd also acquired former MGP sites as vacant real estate on which ComEd facilities have been constructed. To date, ComEd has identified 42 former MGP sites for which it may be liable for remediation. Of these 42 sites, the Illinois Environmental Protection Agency has approved the clean-up of four sites. Similarly, PECO has identified 27 sites where former MGP activities may have resulted in site contamination. Of these 27 sites, the PDEP has approved the clean-up of nine sites. With respect to these sites, ComEd and PECO are presently engaged in performing various levels of activities, including initial evaluation to determine the existence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation. ComEd and PECO are working closely with regulatory authorities in the various jurisdictions to develop and implement appropriate plans and schedules for evaluation, risk ranking, detailed study and remediation activities on an individual site and overall program basis. The status of each of the sites in the program varies and is reviewed periodically with the regulatory authorities. At December 31, 2004, ComEd and PECO had accrued $55 million (discounted) and $41 million (discounted), respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. ComEd and PECO believe that they could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at this time. PECO has settled in principle with all of the insurers in the insurance litigation lawsuit for remediation costs associated with former MGP sites. PECO expects to finalize all settlement agreements in the first quarter of 2005. ComEd is in settlement negotiations with one insurance carrier for remediation costs associated with former MGP sites. Additionally, PECO is currently collecting through regulated gas rates, revenues to offset expenditures on MGP site remediation.

 

Air

 

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

 

The Amendments establish a comprehensive and complex national program to substantially reduce air pollution. The Amendments include a two-phase program to reduce acid rain effects by significantly reducing emissions of SO2 and NOx from electric power plants. Flue-gas desulphurization systems (scrubbers) have been installed at all of Generation’s coal-fired units other than the Keystone Station. Keystone is subject to, and in compliance with, the Phase II SO2 and NOx limits of the

 

26


Amendments, which became effective January 1, 2000. Generation and the other Keystone co-owners are purchasing SO2 emission allowances to comply with the Phase II limits.

 

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

 

Generation has evaluated options for compliance with the new NOx regulations and installed controls on the two coal-fired units at the Eddystone Generating Station (Selective Non-Catalytic Reduction) and installed controls on the two coal-fired units (Selective Catalytic Reduction) at the Keystone Generating Station. Generation’s NOx compliance program will be supplemented with the purchase of additional NOx allowances on an as-needed basis. The eight new peaking units commissioned during 2002 at the Southeast Chicago Generating Station are equipped with NOx controls that meet requirements for new sources. The Handley and Mountain Creek stations in the Dallas/Fort Worth (DFW) area are required to comply with the DFW NOx State Implementation Plan (SIP) that commenced on May 1, 2003, with full implementation on May 1, 2005. Additionally, beginning May 1, 2003, these plants were required to comply with the Emission Banking and Trading of Allowances (EBTA) program established by the State of Texas for the purpose of achieving substantial reductions in NOx from grandfathered electric generating facilities. To comply with both the DFW NOx SIP and EBTA program, Generation, as of June 30, 2004, had installed Selective Catalytic Reduction technology on Handley Units 3, 4 and 5, as well as Mountain Creek Unit 8. Additionally, Induced Flue Gas Recirculation Technology was installed on Mountain Creek Unit 6. Induced Flue Gas Recirculation Technology will be installed on Mountain Creek Unit 7 in 2005 prior to the DFW NOx SIP program being fully implemented on May 1, 2005. This will complete all NOx control technology upgrades planned for the DFW plants.

 

Many other provisions of the Amendments affect activities of Exelon’s businesses, primarily Generation. The Amendments establish stringent control measures for geographical regions that have been determined by the EPA not to meet National Ambient Air Quality Standards (NAAQS); establish limits on the purchase and operation of motor vehicles and require increased use of alternative fuels; establish stringent controls on emissions of toxic air pollutants and provide for possible future designation of some utility emissions as toxic; establish new permit and monitoring requirements for sources of air emissions; and provide for significantly increased enforcement power, and civil and criminal penalties.

 

Several other legislative and regulatory proposals regarding the control of emissions of air pollutants from a variety of sources, including generating plants, are under active consideration. On the Federal legislative front, several multi-pollutant bills have been introduced in Congress that would reduce generating plant emissions of NOx, SO2, mercury and/or carbon dioxide starting late this decade. On the Federal regulatory front, the EPA issued several new proposed rulemakings during 2004 to reduce powerplant emissions of SO2, NOx and mercury. In its proposed “Clean Air Interstate Rule (CAIR)” rulemaking, the EPA has proposed NOx and SO2 emission caps in 29 eastern states, to be phased-in during 2010 and 2015, that are substantially below current industry emission levels. The CAIR rule is intended to support regional attainment of Federal ground-level ozone (eight-hour) and fine particulate (PM2.5) NAAQS. In a separate hazardous air pollutant-related rulemaking, the EPA has also proposed several options to regulate mercury emissions from coal-fired power plants under either

 

27


Section 112 or Section 111 of the CAA. Regulation of nickel emissions from oil-fired power plants is also contemplated as part of this latter proposed rulemaking. Exelon is unable at this time to ascertain which proposals may take effect, what requirements they may contain, or how they may affect Exelon’s businesses. At this time, Exelon can provide no assurance that these proposals if adopted will not have a significant effect on Generation’s operations and cash flows.

 

Global Climate Change

 

The United States is currently not a party to the United Nations’ Kyoto Protocol (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas (GHG) emissions at certain levels during the 2008-2012 time period. Although it is not a signatory to the Protocol, the United States may adopt a national, mandatory GHG program at some point in the future. At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legislative or regulatory requirements on its businesses.

 

In the absence of a mandatory national program, Exelon has joined the U.S. EPA Climate Leaders Partnership (Climate Leader). As a Climate Leader partner, Exelon is conducting an annual inventory of its GHG emissions, developing a GHG emission reduction goal, and annually reporting its GHG emissions and progress toward achieving GHG reductions.

 

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

 

Renewable and Alternative Energy Portfolio Standards

 

Approximately 17 states have adopted some form of renewable portfolio standard (RPS) legislation. On November 30, 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act). The AEPS Act mandates that two years after its effective date (February 28, 2005) at least 1.5% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from Tier I alternative energy resources. The Tier I requirement escalates to 8.0% by the 15th year after the effective date of the AEPS Act. The AEPS Act also establishes a Tier II requirement of 4.2% for years one through four. This requirement grows to 10.0% by the 15th year.

 

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

 

The AEPS Act provides an exemption for electric distribution companies that have not reached the end of their cost recovery period during which competitive transition charges or intangible transition charges are being recovered. At the conclusion of the electric distribution company’s cost recovery period, this exemption no longer applies and compliance by the electric distribution company is required at the percentages in effect at that time. PECO’s cost recovery period expires December 31, 2010.

 

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

 

The PUC is required to establish regulations to implement the AEPS Act. These regulations will be material to a complete assessment of the effects of the AEPS Act on PECO. While Generation is not directly affected from a compliance perspective, increased deployment of renewable and alternative energy resources within the regional power pool resulting from the AEPS Act will have some influence on regional energy markets.

 

In addition to the AEPS Act, similar legislation has been, and may be, considered by the United States Congress. Also, states that currently do not have RPS requirements, including Illinois, may determine to adopt such legislation in the future.

 

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

 

Costs

 

At December 31, 2004, ComEd, PECO and Generation had accrued $61 million, $47 million and $16 million, respectively, for various environmental investigation and remediation. These costs include approximately $55 million at ComEd and $41 million at PECO for former MGP sites as described above. ComEd, PECO and Generation cannot currently predict whether they will incur other significant liabilities for additional investigation and remediation costs at sites presently identified or additional sites which may be identified by ComEd, PECO and Generation, environmental agencies or others, or whether all such costs will be recoverable through rates or from third parties.

 

The budgets for expenditures in 2005 at ComEd, PECO and Generation for compliance with environmental requirements total approximately $8 million, $8 million and $7 million, respectively. In addition, ComEd, PECO and Generation may be required to make significant additional expenditures not presently determinable.

 

Security

 

Exelon does not know the impact that future terrorist attacks or threats of terrorism may have on the electric and gas industry in general and on Exelon in particular. Exelon has initiated security measures to safeguard its employees and critical operations from threats of terrorism and is actively participating in industry initiatives to identify methods to maintain the reliability of Exelon’s energy production and delivery systems. Additionally, the energy industry is working with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems. These measures will involve additional expenses to develop and implement, but will provide increased assurances as to Exelon’s ability to maintain critical operations.

 

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

 

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Other Subsidiaries of ComEd and PECO with Publicly Held Securities

 

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

 

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

 

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

 

PECO Energy Transition Trust (PETT), a Delaware statutory trust wholly owned by PECO, was formed on June 23, 1998 pursuant to a trust agreement among PECO, as grantor, First Union Trust Company, National Association, now Wachovia Bank, National Association, as issuer trustee, and two beneficiary trustees appointed by PECO. PETT was created for the sole purpose of issuing transition bonds to securitize a portion of PECO’s authorized stranded cost recovery. On March 25, 1999, PETT issued $4 billion of its Series 1999-A Transition Bonds. On May 2, 2000, PETT issued $1 billion of its Series 2000-A Transition Bonds and on March 1, 2001, PETT issued $805 million of its Series 2001-A Transition Bonds to refinance a portion of the Series 1999-A Transition Bonds. The Transition Bonds are solely obligations of PETT secured by intangible transition property, representing the right to collect transition charges sufficient to pay the principal and interest on the Transition Bonds.

 

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

 

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December 31, 2004, PEC L.P. held $81 million aggregate principal amount of the Subordinated Debentures.

 

PECO Energy Capital Trust III (PECO Trust III), a Delaware statutory trust, was formed by PECO in April 1998. PECO Trust III was created solely for the purpose of issuing $78 million trust receipts (Trust III Receipts) each representing a 7.38% Cumulative Preferred Security, Series D (Series D Preferred Securities) of PEC L.P. PEC L.P. is the sponsor of PECO Trust III. As of December 31, 2004, PECO Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2004, the assets of PECO Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $81 million.

 

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

 

The financing trusts discussed above were deconsolidated from the financial statements of Exelon, ComEd and PECO in 2003. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for additional information.

 

Executive Officers of the Registrants at December 31, 2004

 

Exelon

 

Name


   Age

  

Position


Rowe, John W.

   59    Chairman, Chief Executive Officer and President

Clark, Frank M.

   59    Executive Vice President and Chief of Staff

McLean, Ian P.

   55    Executive Vice President

Mehrberg, Randall E.

   49    Executive Vice President and General Counsel

Moler, Elizabeth A.

   55    Executive Vice President

Shapard, Robert S.

   49    Executive Vice President and Chief Financial Officer

Skolds, John L.

   54    Executive Vice President

Snodgrass, S. Gary

   53    Executive Vice President and Chief Human Resources Officer

Strobel, Pamela B.

   52    Executive Vice President and Chief Administrative Officer

Young, John F.

   48    Executive Vice President

Hilzinger, Matthew F.

   41    Vice President and Corporate Controller

 

ComEd

 

Name


   Age

  

Position


Rowe, John W.

   59    Chairman, Chief Executive Officer and President, Exelon, and Chair and Director

Shapard, Robert S.

   49    Executive Vice President and Chief Financial Officer, Exelon, and Director

Snodgrass, S. Gary

   53    Executive Vice President and Chief Human Resources Officer, Exelon, and Director

Skolds, John L.

   54    President, Exelon Energy Delivery, and Director

Clark, Frank M.

   59    President and Director

Gillis, Ruth Ann M.

   50    Executive Vice President

Mitchell, J. Barry

   56    Senior Vice President, Treasurer and Chief Financial Officer

Hilzinger, Matthew F.

   41    Vice President and Corporate Controller, Exelon

 

31


PECO

 

Name


   Age

  

Position


Rowe, John W.

   59    Chairman, Chief Executive Officer and President, Exelon, and Director

Shapard, Robert S.

   49    Executive Vice President and Chief Financial Officer, Exelon, and Director

Skolds, John L.

   54    President, Exelon Energy Delivery, and Director

O’Brien, Denis P.

   44    President and Director

Mitchell, J. Barry

   56    Senior Vice President, Treasurer and Chief Financial Officer

Hilzinger, Matthew F.

   41    Vice President and Corporate Controller, Exelon

 

Generation

 

Name


   Age

  

Position


Rowe, John W.

   59    Chairman, Chief Executive Officer and President, Exelon

Shapard, Robert S.

   49    Executive Vice President and Chief Financial Officer, Exelon

Young, John F.

   48    Executive Vice President, Exelon, and President

McLean, Ian P.

   55    Executive Vice President, Exelon, and President, Power Team

Crane, Christopher M.

   46    Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear

Schiavoni, Mark A.

   49    Senior Vice President and President, Exelon Power

Mitchell, J. Barry

   56    Senior Vice President, Treasurer and Chief Financial Officer

Veurink, Jon D.

   40    Vice President and Controller

 

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

 

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

 

Prior to his election to his listed position, Mr. Clark was Senior Vice President, Distribution Customer and Marketing Services and External Affairs of ComEd; Senior Vice President of ComEd and Unicom; Vice President of ComEd; Governmental Affairs Vice President; and Governmental Affairs Manager. Mr. Clark was elected as an officer of Exelon effective October 20, 2000.

 

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

 

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

 

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

 

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Prior to his election to his listed position, Mr. Shapard was Executive Vice President and Chief Financial Officer of Covanta Energy Corporation; Executive Vice President and Chief Financial Officer of Ultramar Diamond Shamrock; Chief Executive Officer of TSU Australia, Ltd., and Vice President, Finance and Treasurer at TXU. Mr. Shapard was elected as an officer effective October 21, 2002.

 

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

 

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

 

Prior to her election to her listed position, Ms. Strobel was Vice Chairman of ComEd; Vice Chairman of PECO; Executive Vice President and General Counsel of ComEd and Unicom; Senior Vice President and General Counsel of ComEd and Unicom; and Vice President and General Counsel of ComEd. Ms. Strobel was elected as an officer effective October 20, 2000.

 

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

 

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

 

Prior to her election to her listed position, Ms. Gillis was Senior Vice President of Exelon; President of Business Services Company; Chief Financial Officer of Exelon; and Senior Vice President and Chief Financial Officer of Unicom Corporation. Ms. Gillis was elected as an officer effective October 20, 2000.

 

Prior to his election to his listed position, Mr. Mitchell was Vice President and Treasurer of Exelon; and Vice President, Treasury and Evaluation, and Treasurer of PECO. Mr. Mitchell was elected as an officer of Exelon effective October 20, 2000.

 

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

 

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

 

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

 

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

 

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ITEM 2. PROPERTIES

 

Energy Delivery

 

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

 

Transmission and Distribution

 

Energy Delivery’s higher voltage electric transmission lines owned and in service at December 31, 2004 were as follows:

 

     Voltage (Volts)

   Circuit Miles

 

ComEd

   765,000    90  
     345,000    2,600  
     138,000    2,866  
     69,000    149  

PECO

   500,000    188  (a)
     220,000    541  
     132,000    156  
     66,000    153  

(a) In addition, PECO has a 22.00% ownership of 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership of 151 miles of 500,000 voltage lines located in Delaware and New Jersey.

 

ComEd’s electric distribution system includes 43,700 circuit miles of overhead lines and 32,900 cable miles of underground lines. PECO’s electric distribution system includes 12,150 circuit miles of overhead lines and 15,389 cable miles of underground lines.

 

Gas

 

The following table sets forth PECO’s gas pipeline miles at December 31, 2004:

 

     Pipeline Miles

Transmission

   31

Distribution

   6,457

Service piping

   5,282
    

Total

   11,770
    

 

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

 

Mortgages

 

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

 

34


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

 

Insurance

 

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

 

Generation

 

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2004. The table does not include properties held by equity method investments:

 

Station


 

Location


  No. of
Units


  Percent
Owned (a)


 

Primary

Fuel Type


 

Primary

Dispatch

Type (f)


  Net
Generation (b)
Capacity (MW)


 

Nuclear (c)

                         

Braidwood

  Braidwood, IL   2       Uranium   Base-load   2,363  

Byron

  Byron, IL   2       Uranium   Base-load   2,336  

Clinton

  Clinton, IL   1       Uranium   Base-load   1,030  

Dresden

  Morris, IL   2       Uranium   Base-load   1,742  

LaSalle

  Seneca, IL   2       Uranium   Base-load   2,288  

Limerick

  Limerick Twp., PA   2       Uranium   Base-load   2,309  

Oyster Creek

  Forked River, NJ   1       Uranium   Base-load   625  

Peach Bottom

  Peach Bottom Twp., PA   2   50.00   Uranium   Base-load   1,131  (d)

Quad Cities

  Cordova, IL   2   75.00   Uranium   Base-load   1,121  (d)

Salem

  Hancock’s Bridge, NJ   2   42.59   Uranium   Base-load   969 (d)

Three Mile Island

  Londonderry Twp, PA   1       Uranium   Base-load   837  
                       

                        16,751  

Fossil (Steam Turbines)

                         

Batavia

  Batavia, NY   1   50.00   Gas   Intermediate   26 (e)

Conemaugh

  New Florence, PA   2   20.72   Coal   Base-load   352 (d)

Cromby 1

  Phoenixville, PA   1       Coal   Base-load   144  

Cromby 2

  Phoenixville, PA   1       Oil/Gas   Intermediate   201  

Eddystone 1, 2

  Eddystone, PA   2       Coal   Base-load   581  

Eddystone 3, 4

  Eddystone, PA   2       Oil/Gas   Intermediate   760  

Fairless Hills

  Falls Twp, PA   2       Landfill Gas   Peaking   60  

Handley 1, 2, 4, 5

  Fort Worth, TX   4       Gas   Peaking   1,041  

Handley 3

  Fort Worth, TX   1       Gas   Intermediate   400  

Keystone

  Shelocta, PA   2   20.99   Coal   Base-load   358 (d)

Independence

  Oswego, NY   1   50.00   Gas   Base-load   514 (e)

Massena

  Massena, NY   1   50.00   Oil/Gas   Intermediate   34 (e)

Mountain Creek 2, 3, 6, 7

  Dallas, TX   4       Gas   Peaking   343  

Mountain Creek 8

  Dallas, TX   1       Gas   Intermediate   550  

New Boston 1

  South Boston, MA   1       Gas   Intermediate   353  

Ogdensburg

  Ogdensburg, NY   1   50.00   Oil/Gas   Intermediate   36 (e)

Schuylkill

  Philadelphia, PA   1       Oil   Peaking   166  

Sterling

  Sherrill, NY   1   50.00   Gas   Intermediate   28 (e)

Wyman

  Yarmouth, ME   1   5.89   Oil   Intermediate   36 (d)
                       

                        5,983  

 

(continued on next page)

 

35


Station (continued)


 

Location


  No. of
Units


  Percent
Owned (a)


 

Primary

Fuel Type


 

Primary

Dispatch

Type (f)


  Net
Generation (b)
Capacity (MW)


 

Fossil (Combustion Turbines)

                     

Chester

  Chester, PA   3       Oil   Peaking   39  

Croydon

  Bristol Twp., PA   8       Oil   Peaking   384  

Delaware

  Philadelphia, PA   4       Oil   Peaking   56  

Eddystone

  Eddystone, PA   4       Oil   Peaking   60  

Falls

  Falls Twp., PA   3       Oil   Peaking   51  

Framingham

  Framingham, MA   3       Oil   Peaking   30  

LaPorte

  Laporte, TX   4       Gas   Peaking   160  

Medway

  West Medway, MA   3       Oil   Peaking   110  

Moser

  Lower Pottsgrove Twp., PA   3       Oil   Peaking   51  

New Boston

  South Boston, MA   1       Gas   Peaking   13  

Pennsbury

  Falls Twp., PA   2       Landfill Gas   Peaking   6  

Richmond

  Philadelphia, PA   2       Oil   Peaking   96  

Salem

  Hancock’s Bridge, NJ   1   42.59   Oil   Peaking   16 (d)

Schuylkill

  Philadelphia, PA   2       Oil   Peaking   30  

Southeast Chicago

  Chicago, IL   8   71.00   Gas   Peaking   222 (d)

Southwark

  Philadelphia, PA   4       Oil   Peaking   52  
                       

                        1,376  

Fossil (Internal Combustion/Diesel)

                     

Conemaugh

  New Florence, PA   4   20.72   Oil   Peaking   2 (d)

Cromby

  Phoenixville, PA   1       Oil   Peaking   3  

Delaware

  Philadelphia, PA   1       Oil   Peaking   3  

Keystone

  Shelocta, PA   4   20.99   Oil   Peaking   2 (d)

Schuylkill

  Philadelphia, PA   1       Oil   Peaking   3  
                       

                        13  

Hydroelectric

                         

Conowingo

  Harford Co. MD   11       Hydroelectric   Base-load   536  

Muddy Run

  Lancaster, PA   8       Hydroelectric   Intermediate   1,072  

Allegheny

  Ford City, PA   4   50.00   Hydroelectric   Intermediate   25 (e)
                       

                        1,633  
       
             

Total

      138               25,756  
       
             


(a) 100%, unless otherwise indicated.
(b) For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating.
(c) All nuclear stations are boiling water reactors except Braidwood, Byron, Salem and Three Mile Island, which are pressurized water reactors.
(d) Net generation capacity is stated at proportionate ownership share.
(e) Properties are owned by Sithe. Sithe was consolidated by Generation in accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46-R) and capacity is shown at Generation’s percentage of ownership as of December 31, 2004. See Note 3 of Exelon’s and Generation’s Notes to Consolidated Financial Statements for additional information related to Sithe. As of January 31, 2005, Generation no longer holds an interest in Sithe. See Note 25 of Exelon’s and Note 20 of Generation’s Notes to Consolidated Financial Statements for further information regarding the sale of the investment in Sithe.
(f) Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system, and consequently produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the day time higher load hours, and consequently produce electricity by cycling on and off daily. Peaking units are plants that usually house low-efficiency, quick response steam units, gas turbines, diesels, or pumped-storage hydroelectric equipment normally used during the maximum load periods.

 

36


The net generating capability available for operation at any time may be less due to regulatory restrictions, fuel restrictions, efficiency of cooling facilities and generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.

 

Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. Business—Generation. For its insured losses, Generation is self-insured to the extent that losses are within the property deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition and results of operations.

 

ITEM 3. LEGAL PROCEEDINGS

 

ComEd

 

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. 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. On October 6, 2004, the Supreme Court declined to hear the final appeal. The time for further appeals has now passed. Related claims remain pending in the trial court.

 

PECO and Generation

 

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). Generation is involved in real estate tax appeals for 2000 through 2004, also regarding the valuation of its Limerick and Peach Bottom plants and Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) and Oyster Creek Nuclear Generating Station (Forked River, NJ).

 

Generation

 

Cotter Corporation Litigation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, 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. 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. 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.

 

 

37


Several of the 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. In October 2004, a settlement of the claims of all Cotter plaintiffs was reached and approved by the Federal District Court in Colorado. This settlement amount approximated Generation’s reserve for this matter. Settlements with the two primary Cotter insurers were also concluded, under which they paid Generation approximately $20 million, which covered the amount previously reserved as well as certain other costs incurred by Generation related to this matter. Neither of these settlements affects the environmental liability associated with the West Lake Landfill. For additional information, see ITEM 1. Environmental Regulation.

 

General

 

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 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.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

Exelon, ComEd, PECO and Generation

 

None.

 

38


PART II

 

(Dollars in million except per share data, unless otherwise noted)

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Exelon

 

Exelon’s common stock is listed on the New York Stock Exchange. See Note 24 of Exelon’s Notes to Consolidated Financial Statements for the high and low sales prices, closing prices and dividends for Exelon’s common stock for 2004 and 2003 on a per share basis. As of January 31, 2005, there were 664,807,122 shares of common stock outstanding and approximately 166,575 shareholders of common stock of record.

 

On January 27, 2004, the Exelon Board of Directors 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 related to Exelon included in this Form 10-K have been adjusted for all periods presented to reflect the stock split.

 

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock.

 

Period


   Total Number of
Shares Purchased (a)


   Average Price
Paid per Share


   Total Number of
Shares Purchased
As Part of Publicly
Announced Plans
or Programs (b)


   Maximum Number
(or Approximate
Dollar Value) of
Shares that May
Yet Be Purchased
Under the Plans
or Programs


 

October 1—October 31, 2004

   11,396    $ 36.85    —      (b )

November 1—November 30, 2004

   220,287      40.47    —      (b )

December 1—December 31, 2004

   1,750      41.87    —      (b )
    
                  

Total

   233,433      40.31    —      (b )
    
                  

(a) Shares other than those purchased as a part of a publicly announced plan primarily represent restricted shares surrendered by employees to satisfy tax obligations arising upon the vesting of restricted shares and shares repurchased from an executive upon retirement from Exelon.
(b) 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 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 direct cash proceeds from purchases of stock and tax benefits associated with exercises of stock options. The share repurchase program has no specified limit and no specified termination date.

 

ComEd

 

As of January 31, 2005, there were outstanding 127,016,502 shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held by Exelon. At January 31, 2005, in addition to Exelon, there were 275 holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

 

39


PECO

 

As of January 31, 2005, there were outstanding 170,478,507 shares of common stock, without par value, of PECO, all of which were held by Exelon.

 

Generation

 

As of January 31, 2005, Exelon held the entire membership interest in Generation.

 

Exelon, ComEd, PECO and Generation

 

Dividends

 

Under applicable Federal 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.

 

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. At December 31, 2004, Exelon had retained earnings of $3.3 billion, which includes ComEd’s retained earnings of $1,102 million (all of which had been appropriated for future dividends), PECO’s retained earnings of $607 million and Generation’s undistributed earnings of $761 million.

 

The following table sets forth Exelon’s quarterly cash dividends paid during 2004 and 2003:

 

     2004

   2003

(per share)


   4th
Quarter


   3rd
Quarter


   2nd
Quarter


   1st
Quarter


   4th
Quarter


   3rd
Quarter


   2nd
Quarter


   1st
Quarter


Exelon

   $ 0.400    $ 0.305    $ 0.275    $ 0.275    $ 0.250    $ 0.250    $ 0.230    $ 0.230

 

The following table sets forth ComEd’s and PECO’s quarterly common dividend payments and Generation’s quarterly distributions:

 

     2004

   2003

(in millions)


   4th
Quarter


   3rd
Quarter


   2nd
Quarter


   1st
Quarter


   4th
Quarter


   3rd
Quarter


   2nd
Quarter


   1st
Quarter


ComEd

   $ 137    $ 113    $ 104    $ 103    $ 95    $ 95    $ 90    $ 121

PECO

     115      96      90      90      79      79      75      90

Generation

     335      61      55      54      73      71      45      —  

 

On January 27, 2004, the Exelon Board of Directors declared a quarterly dividend of $0.275 per share on Exelon’s common stock. On July 27, 2004, the Exelon Board of Directors declared a quarterly dividend of $0.305 per share on Exelon’s common stock and approved a policy of targeting a dividend payout ratio of 50 to 60% of ongoing earnings and authorized a plan to achieve that level of payout for the full year of 2005. The actual dividend payout rate depends on Exelon achieving its objectives, including meeting cash flow targets and strengthening its balance sheet. On October 19, 2004 and January 25, 2005, the Exelon Board of Directors approved quarterly dividends of $0.40 per share, reflecting an annual dividend of $1.60 per share. The Board of Directors must approve the dividends each quarter after review of Exelon’s financial condition at that time.

 

The Merger Agreement between Exelon and PSEG provides that, subject to applicable law and the fiduciary duties of its board of directors, Exelon will increase its quarterly dividend so that the first

 

40


dividend paid after completion of the Merger is an amount equal, on an exchange ratio adjusted basis, to the dividend PSEG shareholders received in the quarter immediately prior to completion of the Merger, up to a maximum of $0.47 per share of Exelon common stock (the lesser of $0.47 and the amount required to equal PSEG’s dividend on an exchange ratio adjusted basis being referred to as the threshold amount (threshold amount)). Exelon has agreed that as close to 30 days prior to the anticipated closing of the Merger as reasonably practicable, it will notify PSEG of what it believes its first quarterly dividend following completion of the Merger will be. If that dividend is less than the threshold amount, PSEG may make a one time special cash dividend to its shareholders equal to the amount of the difference between the dividend Exelon has informed PSEG it will pay and the threshold amount on an exchange ratio adjusted basis.

 

ComEd may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities which were issued to ComEd Financing II and ComEd Financing III (the Financing Trusts); (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of the Financing Trusts; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued (see ITEM 1. Business—Other Subsidiaries of ComEd and PECO with Publicly Held Securities). As of December 31, 2004, ComEd had appropriated $1,102 million of retained earnings for future dividend payments.

 

PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 2004, such capital was $2.8 billion and amounted to about 32 times the liquidating value of the outstanding preferred stock of $87 million.

 

PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued (see ITEM 1. Business—Other Subsidiaries of ComEd and PECO with Publicly Held Securities).

 

ITEM 6. SELECTED FINANCIAL DATA

 

 

Exelon

 

The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.

 

41


Results for 2000 reflect the effects of the merger of Exelon Corporation, Unicom and PECO on October 20, 2000. That merger was accounted for using the purchase method of accounting with PECO as the acquiring company. Accordingly, financial results for 2000 consist of PECO’s results for 2000 and Unicom’s results after October 20, 2000.

 

     For the Years Ended December 31,

in millions, except for per share data


   2004

   2003

   2002

    2001

   2000

Statement of Income data:

                                   

Operating revenues

   $ 14,515    $ 15,812    $ 14,955     $ 14,918    $ 7,499

Operating income

     3,433      2,277      3,299       3,362      1,527

Income before cumulative effect of changes in accounting principles

   $ 1,841    $ 793    $ 1,670     $ 1,416    $ 562

Cumulative effect of changes in accounting principles (net of income taxes)

     23      112      (230 )     12      24
    

  

  


 

  

Net income

   $ 1,864    $ 905    $ 1,440     $ 1,428    $ 586
    

  

  


 

  

Earnings per average common share (diluted):

                                   

Income before cumulative effect of changes in accounting principles

   $ 2.75    $ 1.21    $ 2.57     $ 2.19    $ 1.38

Cumulative effect of changes in accounting principles (net of income taxes)

     0.03      0.17      (0.35 )     0.02      0.06
    

  

  


 

  

Net income

   $ 2.78    $ 1.38    $ 2.22     $ 2.21    $ 1.44
    

  

  


 

  

Dividends per common share

   $ 1.26    $ 0.96    $ 0.88     $ 0.91    $ 0.46
    

  

  


 

  

Average shares of common stock outstanding—diluted

     669      657      649       645      408
    

  

  


 

  

 

     December 31,

in millions


   2004

   2003

   2002

   2001

   2000

Balance Sheet data:

                                  

Current assets

   $ 3,926    $ 4,561    $ 4,125    $ 3,735    $ 4,151

Property, plant and equipment, net

     21,482      20,630      17,957      14,665      15,914

Noncurrent regulatory assets

     4,790      5,226      5,546      5,774      6,045

Goodwill

     4,705      4,719      4,992      5,335      5,186

Other deferred debits and other assets

     7,867      6,800      5,249      5,460      5,378
    

  

  

  

  

Total assets

   $ 42,770    $ 41,936    $ 37,869    $ 34,969    $ 36,674
    

  

  

  

  

Current liabilities

   $ 4,882    $ 5,720    $ 5,874    $ 4,370    $ 4,993

Long-term debt, including long-term debt to financing trusts (a)

     12,148      13,489      13,127      12,879      12,958

Regulatory liabilities

     2,204      1,891      486      225      1,888

Other deferred credits and other liabilities

     13,984      12,246      9,968      8,749      8,959

Minority interest

     42      —        77      31      31

Preferred securities of subsidiaries (a)

     87      87      595      613      630

Shareholders’ equity

     9,423      8,503      7,742      8,102      7,215
    

  

  

  

  

Total liabilities and shareholders’ equity

   $ 42,770    $ 41,936    $ 37,869    $ 34,969    $ 36,674
    

  

  

  

  


 

(a) The mandatorily redeemable preferred securities of ComEd and PECO were reclassified as long-term debt to financing trusts in 2003 in accordance with FIN 46-R and FIN 46, “Consolidation of Variable Interest Entities” (FIN 46).

 

42


ComEd

 

The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.

 

ComEd was the principal subsidiary of Unicom prior to the merger with Exelon on October 20, 2000. The merger was accounted for using the purchase method of accounting in accordance with GAAP. The effects of the purchase method were reflected in the consolidated financial statements of ComEd as of October 20, 2000. Accordingly, ComEd’s consolidated financial statements presented for the period after that merger reflect a new basis of accounting. The information for the year ended 2000 is presented for the periods before and after the merger.

 

     For the Years Ended December 31,

  

Oct. 20 -

Dec. 31

2000


  

Jan. 1 -

Oct. 19

2000


(in millions)


   2004

   2003

   2002

   2001

     

Statement of Income data:

                                         

Operating revenues

   $ 5,803    $ 5,814    $ 6,124    $ 6,206    $ 1,310    $ 5,702

Operating income

     1,617      1,567      1,766      1,594      338      1,048

Income before cumulative effect of changes in accounting principles

   $ 676    $ 702    $ 790    $ 607    $ 133    $ 599

Cumulative effect of a change in accounting principle (net of income taxes)

     —        5      —        —        —        —  
    

  

  

  

  

  

Net income

   $ 676    $ 707    $ 790    $ 607    $ 133    $ 599
    

  

  

  

  

  

 

     December 31,

(in millions)


   2004

   2003

   2002

   2001

   2000

Balance Sheet data:

                                  

Current assets

   $ 1,196    $ 1,313    $ 1,049    $ 1,025    $ 2,172

Property, plant and equipment, net

     9,463      9,096      8,689      8,243      10,655

Goodwill, net

     4,705      4,719      4,916      4,902      4,766

Other deferred debits and other assets

     2,077      2,837      1,662      1,682      4,493
    

  

  

  

  

Total assets

   $ 17,441    $ 17,965    $ 16,316    $ 15,852    $ 22,086
    

  

  

  

  

Current liabilities

   $ 1,764    $ 1,557    $ 2,023    $ 1,797    $ 1,723

Long-term debt, including long-term debt to financing trusts (a)

     4,282      5,887      5,268      5,850      6,882

Regulatory liabilities

     2,204      1,891      486      225      1,888

Other deferred credits and other liabilities

     2,451      2,288      2,451      2,568      5,082

Mandatorily redeemable preferred securities of subsidiary trusts (a)

     —        —        330      329      328

Shareholders’ equity

     6,740      6,342      5,758      5,083      6,183
    

  

  

  

  

Total liabilities and shareholders’ equity

   $ 17,441    $ 17,965    $ 16,316    $ 15,852    $ 22,086
    

  

  

  

  


(a) Due to the adoption of FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts as of December 31, 2003.

 

43


PECO

 

The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,

(in millions)


   2004

   2003

   2002

   2001

   2000

Statement of Income data:

                                  

Operating revenues

   $ 4,487    $ 4,388    $ 4,333    $ 3,965    $ 5,950

Operating income

     1,014      1,056      1,093      999      1,222

Income before cumulative effect of a change in accounting principle

   $ 455    $ 473    $ 486    $ 425    $ 483

Cumulative effect of a change in accounting principle (net of income taxes)

     —        —        —        —        24
    

  

  

  

  

Net income

   $ 455    $ 473    $ 486    $ 425    $ 507
    

  

  

  

  

Net income on common stock

   $ 452    $ 468    $ 478    $ 415    $ 497
    

  

  

  

  

     December 31,

(in millions)


   2004

   2003

   2002

   2001

   2000

Balance Sheet data:

                                  

Current assets

   $ 773    $ 696    $ 927    $ 813    $ 1,779

Property, plant and equipment, net

     4,329      4,256      4,159      4,039      5,138

Noncurrent regulatory assets

     4,790      5,226      5,546      5,774      6,046

Other deferred debits and other assets

     241      232      88      112      1,813
    

  

  

  

  

Total assets

   $ 10,133    $ 10,410    $ 10,720    $ 10,738    $ 14,776
    

  

  

  

  

Current liabilities

   $ 794    $ 713    $ 1,538    $ 1,335    $ 2,974

Long-term debt, including long-term debt to financing trusts (a)

     4,628      5,239      4,951      5,438      6,002

Deferred credits and other liabilities

     3,313      3,442      3,342      3,358      3,860

Mandatorily redeemable preferred securities of subsidiary trusts (a)

     —        —        128      128      128

Mandatorily redeemable preferred stock

            —        —        19      37

Shareholders’ equity

     1,398      1,016      761      460      1,775
    

  

  

  

  

Total liabilities and shareholders’ equity

   $ 10,133    $ 10,410    $ 10,720    $ 10,738    $ 14,776
    

  

  

  

  


(a) Due to the adoptions of FIN 46 and FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts in 2003.

 

44


Generation

 

The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.

 

The consolidated financial statements of Generation as of December 31, 2000 and for the year then ended present the financial position, results of operations and net cash flows of the generation- related business of Exelon prior to its corporate restructuring on January 1, 2001. The results of operations for Exelon Energy Company are not included in periods prior to 2004.

 

     For the Years Ended December 31,

(in millions)


   2004

   2003

    2002

   2001

   2000

Statement of Income data:

                                   

Operating revenues

   $ 7,938    $ 8,135     $ 6,858    $ 6,826    $ 3,274

Operating income (loss)

     1,030      (115 )     509      872      441

Income (loss) before cumulative effect of changes in accounting principles

   $ 641    $ (241 )   $ 387    $ 512    $ 260

Cumulative effect of changes in accounting principles (net of income taxes)

     32      108       13      12      —  
    

  


 

  

  

Net income (loss)

   $ 673    $ (133 )   $ 400    $ 524    $ 260
    

  


 

  

  

     December 31,

(in millions)


   2004

   2003

    2002

   2001

   2000

Balance Sheet data:

                                   

Current assets

   $ 2,321    $ 2,438     $ 1,805    $ 1,435    $ 1,793

Property, plant and equipment, net

     7,536      7,106       4,698      2,003      1,727

Deferred debits and other assets

     6,581      5,105       4,402      4,700      4,742
    

  


 

  

  

Total assets

   $ 16,438    $ 14,649     $ 10,905    $ 8,138    $ 8,262
    

  


 

  

  

Current liabilities

   $ 2,416    $ 3,553     $ 2,594    $ 1,097    $ 2,176

Long-term debt

     2,583      1,649       2,132      1,021      205

Deferred credits and other liabilities

     8,356      6,488       3,226      3,212      3,271

Minority interest

     44      3       54      —        —  

Member’s equity

     3,039      2,956       2,899      2,808      2,610
    

  


 

  

  

Total liabilities and member’s equity

   $ 16,438    $ 14,649     $ 10,905    $ 8,138    $ 8,262
    

  


 

  

  

 

45


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

 

Exelon, ComEd, PECO and Generation

 

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

 

Critical Accounting Policies and Estimates

 

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

 

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

 

Nuclear Decommissioning (Exelon and Generation)

 

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

 

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

 

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

 

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

 

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

 

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

 

Changes in the assumptions underlying the foregoing items could materially affect the decommissioning obligation recorded and could affect future updates to the decommissioning obligation to be recorded in the consolidated financial statements. For example, the 20-year average cost escalation rates used in the current ARO calculation approximate 3% to 4%. A uniform increase in these escalation rates of 25 basis points would increase the total ARO recorded by Exelon by

 

46


approximately 11% or more than $400 million. Under SFAS No. 143, the nuclear decommissioning obligation is adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimate of undiscounted cash flows. For more information regarding the adoption and ongoing application of SFAS No. 143, see Note 1 and Note 14 of Exelon’s Notes to Consolidated Financial Statements.

 

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

 

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

 

Asset Impairments (Exelon, ComEd, PECO and Generation)

 

Goodwill (Exelon and ComEd)

 

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

 

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

 

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

 

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

 

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

 

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Investments (Exelon, ComEd, PECO and Generation)

 

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

 

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

 

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

 

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

 

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

 

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

 

Change in Actuarial Assumption


 

Impact on

Projected Benefit

Obligation at

December 31, 2004


 

Impact on

Pension Liability at

December 31, 2004


 

Impact on

2005

Pension Cost


Pension benefits

                 

Decrease discount rate by 0.5%

    $626     $535     $40

Decrease rate of return on plan assets by 0.5%

    —       —         35
 

Change in Actuarial Assumption


 

Impact on

Other Postretirement

Benefit Obligation

at December 31, 2004


 

Impact on

Postretirement

Benefit Liability

at December 31, 2004


 

Impact on 2005

Postretirement

Benefit Cost


Postretirement benefits

                 

Decrease discount rate by 0.5%

  $ 174   $ —     $ 17

Decrease rate of return on plan assets by 0.5%

    —       —       5

 

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

 

Effect of a one percentage point increase in assumed health care cost trend

        

on total service and interest cost components

   $ 34  

on postretirement benefit obligation

   $ 327  

Effect of a one percentage point decrease in assumed health care cost trend

        

on total service and interest cost components

   $ (28 )

on postretirement benefit obligation

   $ (276 )

 

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

 

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

 

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Regulatory Accounting (Exelon, ComEd and PECO)

 

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

 

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

 

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

 

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

 

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

 

The Registrants enter into derivatives to manage their exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation utilizes derivatives with respect to energy transactions to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the

 

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market price risk associated with forward energy commodity contracts. Additionally, Generation enters into energy-related derivatives for trading purposes. All of the Registrant’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Taxation

 

The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and ongoing operations to estimate their obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes, including taxes that are subject to ongoing appeals. Judgments include estimating reserves for potential adverse outcomes regarding tax positions that they have taken. The Registrants must also assess their ability to generate capital gains in future periods to realize tax benefits associated with capital losses previously generated or expected to be generated in future periods. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the three prior or five succeeding years. The Registrants do not record valuation allowances for deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. Generation has recorded valuation allowances against certain deferred assets associated with capital losses due to the consolidation of Sithe. While the Registrants believe the resulting tax reserve balances as of December 31, 2004 reflect the probable expected outcome of these tax matters in accordance with SFAS No. 5, “Accounting for Contingencies,” and SFAS No. 109, “Accounting for Income Taxes,” the ultimate outcome of such matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material.

 

Environmental Costs

 

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

 

52


timing and costs of expenditures can be reliably estimated, amounts are discounted. These amounts represent $96 million, $55 million and $41 million, respectively, of the total accrued for Exelon, ComEd and PECO. Where timing and amounts cannot be reliably estimated, amounts are recognized on an undiscounted basis. Such amounts represent $28 million, $6 million, $6 million and $16 million, respectively, of the total accrued liabilities for Exelon, ComEd, PECO and Generation. Estimates can be affected by the factors noted above as well as by changes in technology, regulations or the requirements of local governmental authorities.

 

Severance Accounting (Exelon, ComEd, PECO and Generation)

 

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

 

Revenue Recognition (Exelon, ComEd, PECO and Generation)

 

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

 

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

 

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

 

At December 31, 2004, Exelon, through Generation, had a 50% interest in Sithe. In accordance with FIN 46-R, Exelon and Generation consolidated Sithe within their financial statements as of

 

53


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

 

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

 

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Exelon

 

Executive Overview

 

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

 

    Increased net income at Generation—Generation provided net income of $673 million in 2004 compared to a net loss of $151 million in 2003. The increase in Generation’s net income reflects improved wholesale prices in 2004, the inclusion of a full year of AmerGen’s results in 2004, and impairment charges in 2003 of $945 million and $255 million (before income taxes) related to the long-lived assets of Boston Generating and Generation’s investment in Sithe, respectively. Generation’s 2004 income also includes an after-tax gain of $52 million on the sale of Boston Generating during the second quarter of 2004. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Generation.”

 

    Decreased losses at Enterprises—Enterprises reported a net loss of $22 million in 2004 compared to a net loss of $118 million in 2003. Enterprises’ comparative results reflect net pre-tax gains of $41 million recorded in 2004 related to the dispositions of certain businesses and investments, as well as investment impairment charges of $54 million recorded in 2003. See further discussion under “Investment Strategy” below and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Exelon Corporation—Results of Operations—Enterprises.”

 

    Favorable tax effects from investments in synthetic fuel-producing facilities—Exelon’s investments in synthetic fuel-producing facilities increased 2004 after-tax earnings by $65 million as compared to 2003.

 

    Decreased net income at Energy Delivery—Energy Delivery provided net income of $1,128 million in 2004 compared to $1,175 million in 2003. This decrease was primarily attributable to unfavorable weather conditions and charges recorded in connection with the early retirement of debt, partially offset by growth in Energy Delivery’s retail customer base and reduced severance and other charges in 2004 as compared to 2003. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Energy Delivery.”

 

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

 

    Proposed Merger with PSEG—On December 20, 2004, Exelon entered into the Merger Agreement with PSEG, the holding company for an electric and gas utility company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon. Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2004, PSEG’s market capitalization was over $12 billion. Additionally, PSEG, on a consolidated basis, has approximately $14 billion of outstanding debt which is currently anticipated to become part of Exelon’s consolidated debt.

 

The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus

 

55


PSEG’s transaction expenses up to $40 million and (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. On February 4, 2005, Exelon and PSEG filed for approval of the merger with the FERC, the New Jersey Board of Public Utilities (BPU) and the PUC. Exelon also filed a notice of the Merger with the ICC.

 

Exelon anticipates that the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004, subject to shareholder and regulatory approvals which cannot be assured.

 

    OSC with PSEG—Concurrent with the Merger Agreement, Generation entered into the OSC with PSEG Nuclear, LLC which commenced on January 17, 2005 relating to the operation of the Salem and Hope Creek nuclear generating stations. The OSC provides for Generation to provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon operating model. PSEG Nuclear, LLC will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities.

 

    Boston Generating—On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns directly or indirectly the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility, resulting in an after-tax gain of $52 million. On September 1, 2004, Generation completed the transfer of plant operations and power marketing arrangements to the lenders’ special purpose entity and its contractors under Boston Generating’s credit facility.

 

    Sithe—On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million and, on November 1, 2004, Generation entered into an agreement to sell its anticipated 100% interest in Sithe to Dynegy Inc. for $135 million in cash. Generation closed on the call exercise and the sale of the resulting 100% interest in Sithe on January 31, 2005. The sale did not include Sithe International, Inc. (Sithe International), which was sold to a subsidiary of Generation on October 13, 2004.

 

    Enterprises—Exelon continued its divestiture strategy for Enterprises by selling or winding down substantially all components of Enterprises. At December 31, 2004, Enterprises’ remaining assets totaled approximately $274 million in comparison to $697 million at December 31, 2003. Enterprises expects to receive aggregate proceeds of $268 million and recorded a net pre-tax gain of $41 million related to the dispositions of assets and investments in 2004.

 

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

 

    ComEd retired $1.2 billion of its outstanding debt, including $1.0 billion prior to its maturity and $206 million at maturity, pursuant to an accelerated liability management plan. In connection with these retirements, ComEd recorded pre-tax charges totaling $130 million related to debt prepayment premiums and the write-off of previously deferred debt financing fees.

 

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    In addition to the accelerated liability management plan, payments of approximately $728 million were made for the purpose of retiring PECO and ComEd transition trust long-term debt and approximately $176 million of other net long-term debt during 2004.

 

    Exelon replaced its $750 million 364-day unsecured revolving credit agreement with a $1 billion five-year facility and reduced its $750 million three-year facility to $500 million.

 

    Exelon’s Board of Directors approved a discretionary share repurchase program under which Exelon purchased common stock, now held as treasury shares, totaling $75 million during 2004.

 

    Exelon’s Board of Directors approved a policy of targeting a dividend payout ratio of 50% to 60% of ongoing earnings, and Exelon expects a dividend payout in that range for the full year of 2005. The actual dividend payout rate depends on Exelon achieving its objectives, including meeting cash flow targets and strengthening its balance sheet. On October 29, 2004, the Exelon Board of Directors approved an increased quarterly dividend of $0.40 per share, which was consistent with the dividend policy approved in 2004. The Board of Directors must approve the dividends each quarter after review of Exelon’s financial condition at the time, and there can be no guarantees that this targeted dividend payout ratio will be achieved.

 

 

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

 

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

 

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

 

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

 

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

 

57


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

 

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

 

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

 

58


Results of Operations

 

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

 

Significant Operating Trends—Exelon

 

Exelon Corporation


   2004

    2003

   

Favorable

(unfavorable)

variance


 

Operating revenues

   $ 14,515     $ 15,812     $ (1,297 )

Purchased power and fuel expense

     5,082       6,375       1,293  

Impairment of Boston Generating, LLC long-lived assets

     —         945       945  

Operating and maintenance expense

     3,976       4,508       532  

Depreciation and amortization expense

     1,305       1,126       (179 )

Operating income

     3,433       2,277       1,156  

Other income and deductions

     (921 )     (1,148 )     227  

Income before income taxes, minority interest and cumulative effect of changes in accounting principles

     2,512       1,129       1,383  

Income before cumulative effect of changes in accounting principles

     1,841       793       1,048  

Income taxes

     692       331       (361 )

Net income

     1,864       905       959  

Diluted earnings per share

     2.78       1.38       1.40  

 

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

 

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

 

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased primarily due to Generation’s adoption of EITF 03-11 during 2004 which resulted in a decrease in purchased power expense and fuel expense of $980 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense, and the sale of Boston Generating. Purchased power represented 24% of Generation’s total supply in 2004 compared to 37% in 2003. Purchased power

 

59


also decreased due to Energy Delivery’s unfavorable weather conditions and customer choice initiatives, partially offset by volume growth and transmission costs paid to PJM. See further discussion of purchased power and fuel expense by segment below.

 

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

 

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

 

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

 

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

 

Other Income and Deductions. Other income and deductions reflects interest expense of $905 million, equity in losses of unconsolidated affiliates of $153 million, debt retirement charges of $130 million (before income taxes) recorded at ComEd in 2004 associated with an accelerated liability management plan, impairment charges of $255 million (before income taxes) recorded during 2003 related to Generation’s investment in Sithe, an $85 million gain (before income taxes) on the 2004 sale of Boston Generating and a $35 million aggregate net gain on the sale of investments and assets of Thermal in 2004 (before income taxes and net of debt prepayment penalties). Equity in earnings of unconsolidated affiliates decreased by $186 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004.

 

Effective Income Tax Rate. The effective income tax rate was 27.5% for 2004 compared to 29.3% for 2003. The decrease in the effective rate was primarily attributable to investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004.

 

60


Results of Operations by Business Segment

 

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

 

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

 

Total revenues

   $ 834  

Intersegment revenues

     4  

Operating revenue and purchased power from affiliates

     209  

Depreciation and amortization

     2  

Operating expenses

     857  

Interest expense

     1  

Loss before income taxes

     (29 )

Income taxes

     (11 )

Net loss

     (18 )

 

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

 

     2004

    2003

   

Favorable

(unfavorable)

variance


 

Energy Delivery

   $ 1,128     $ 1,170     $ (42 )

Generation

     641       (259 )     900  

Enterprises

     (13 )     (117 )     104  

Corporate

     85       (1 )     86  
    


 


 


Total

   $ 1,841     $ 793     $ 1,048  
    


 


 


 

Net Income (Loss) by Business Segment

 

     2004

    2003

    Favorable
(unfavorable)
variance


 

Energy Delivery

   $ 1,128     $ 1,175     $ (47 )

Generation

     673       (151 )     824  

Enterprises

     (22 )     (118 )     96  

Corporate

     85       (1 )     86  
    


 


 


Total

   $ 1,864     $ 905     $ 959  
    


 


 


 

61


Results of Operations—Energy Delivery

 

     2004

    2003

   

Favorable

(Unfavorable)

variance


 

OPERATING REVENUES

   $ 10,290     $ 10,202     $ 88  

OPERATING EXPENSES

                        

Purchased power and fuel expense

     4,760       4,597       (163 )

Operating and maintenance

     1,444       1,669       225  

Depreciation and amortization

     928       873       (55 )

Taxes other than income

     527       440       (87 )
    


 


 


Total operating expense

     7,659       7,579       (80 )
    


 


 


OPERATING INCOME

     2,631       2,623       8  
    


 


 


OTHER INCOME AND DEDUCTIONS

                        

Interest expense

     (672 )     (747 )     75  

Distributions on mandatorily redeemable preferred securities

     (3 )     (39 )     36  

Equity in losses of unconsolidated affiliates

     (44 )     —         (44 )

Other, net

     (78 )     51       (129 )
    


 


 


Total other income and deductions

     (797 )     (735 )     (62 )
    


 


 


INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

     1,834       1,888       (54 )

INCOME TAXES

     706       718       12  
    


 


 


INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

     1,128       1,170       (42 )

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

     —         5       (5 )
    


 


 


NET INCOME

   $ 1,128     $ 1,175     $ (47 )
    


 


 


 

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

 

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

 

     Electric

    Gas

   

Total

increase

(decrease)


 

Volume

   $ 326     $ 3     $ 329  

PJM transmission

     149       —         149  

Rate changes and mix

     (74 )     111       37  

Weather

     (176 )     (21 )     (197 )

Customer Choice

     (182 )     —         (182 )

T&O Charges

     (41 )     —         (41 )

Other

     (17 )     10       (7 )
    


 


 


(Decrease) increase in operating revenues

   $ (15 )   $ 103     $ 88  
    


 


 


 

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

 

62


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

 

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

 

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

 

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

 

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

 

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

 

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

 

63


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

 

     Electric

    Gas

    Total
increase
(decrease)


 

Volume

   $ 163     $ (2 )   $ 161  

PJM transmission

     149       —         149  

Prices

     11       111       122  

PJM administrative fees

     15       —         15  

Customer choice

     (165 )     —         (165 )

Weather

     (84 )     (15 )     (99 )

T&O Charges

     (22 )     —         (22 )

Other

     (13 )     15       2  
    


 


 


Increase in purchased power and fuel expense

   $ 54     $ 109     $ 163  
    


 


 


 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

64


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

 

     Increase
(decrease)


 

Severance and severance-related expenses

   $ (132 )

Charge recorded at ComEd in 2003 (a)

     (41 )

Payroll expense (b)

     (36 )

Incremental storm costs

     (21 )

Contractors

     (18 )

Automated meter reading system implementation costs at PECO in 2003

     (16 )

Allowance for uncollectible accounts expense

     (13 )

FERC annual fees (c)

     (11 )

Environmental charges

     (10 )

Corporate allocations (d)

     77  

Other

     (4 )
    


Decrease in operating and maintenance expense

   $ (225 )
    



(a) In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties.
(b) Energy Delivery had fewer employees in 2004 compared to 2003.
(c) After joining PJM on May 1, 2004, ComEd is no longer directly charged annual fees by the FERC. PJM pays the annual FERC fees.
(d) Higher corporate allocations primarily result from centralization of information technology, supply, human resources, communications, and finance functions into BSC from all of the Exelon operating companies, and changes in the corporate governance allocation calculation. Corporate governance allocations increased overall as a result of higher centralized costs distributed out of BSC, the sale of the Enterprises companies resulting in Energy Delivery comprising a greater base percentage of Exelon, and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.

 

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

 

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

 

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

 

Distributions on Preferred Securities of Subsidiaries. Effective July 1, 2003, upon the adoption of FIN 46 and effective December 31, 2003, upon the adoption of FIN 46-R, ComEd and

 

65


PECO deconsolidated their financing trusts (see Note 1 of Exelon’s Notes to Consolidated Financial Statements). ComEd and PECO no longer record distributions on mandatorily redeemable preferred securities, but record interest expense to affiliates related to their obligations to the financing trusts.

 

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

 

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

 

Energy Delivery Operating Statistics and Revenue Detail

 

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

 

Retail Deliveries – (in GWhs) (a)


   2004

   2003

   Variance

    % Change

Full service (b)

                    

Residential

   36,812    37,564    (752 )   (2.0%)

Small commercial & industrial

   26,914    28,165    (1,251 )   (4.4%)

Large commercial & industrial

   20,969    20,660    309     1.5%

Public authorities & electric railroads

   5,135    6,022    (887 )   (14.7%)
    
  
  

   

Total full service

   89,830    92,411    (2,581 )   (2.8%)
    
  
  

   

Delivery only (c)

                    

Residential

   2,158    900    1,258     139.8%

Small commercial & industrial

   8,794    7,461    1,333     17.9%

Large commercial & industrial

   13,182    10,689    2,493     23.3%

Public authorities & electric railroads

   1,410    1,402    8     0.6%
    
  
  

   
     25,544    20,452    5,092     24.9%
    
  
  

   

PPO (ComEd only)

                    

Small commercial & industrial

   3,594    3,318    276     8.3%

Large commercial & industrial

   4,223    4,348    (125 )   (2.9%)

Public authorities & electric railroads

   1,670    1,925    (255 )   (13.2%)
    
  
  

   
     9,487    9,591    (104 )   (1.1%)
    
  
  

   

Total delivery only and PPO

   35,031    30,043    4,988     16.6%
    
  
  

   

Total retail deliveries

   124,861    122,454    2,407     2.0% 
    
  
  

   

(a) One gigawatthour is the equivalent of one million kilowatthours (kWh).
(b) Full service reflects deliveries to customers taking electric service under tariffed rates.
(c) Delivery only service reflects customers electing to receive electric generation service from an alternative electric supplier, which rates include a distribution charge and a CTC.

 

66


Electric Revenue


   2004

   2003

   Variance

   % Change

Full service (a)

                         

Residential

   $ 3,612    $ 3,715    $ (103)    (2.8%)

Small commercial & industrial

     2,360      2,421      (61)    (2.5%)

Large commercial & industrial

     1,403      1,394      9    0.6%

Public authorities & electric railroads

     341      396      (55)    (13.9%)
    

  

  

    

Total full service

     7,716      7,926      (210)    (2.6%)
    

  

  

    

Delivery only (b)

                         

Residential

     164      65      99    152.3%

Small commercial & industrial

     220      214      6    2.8%

Large commercial & industrial

     190      196      (6)    (3.1%)

Public authorities & electric railroads

     28      33      (5)    (15.2%)
    

  

  

    
       602      508      94    18.5%
    

  

  

    

PPO (ComEd only) (c)

                         

Small commercial & industrial

     246      225      21    9.3%

Large commercial & industrial

     240      240      —      —  

Public authorities & electric railroads

     92      103      (11)    (10.7%)
    

  

  

    
       578      568      10    1.8%
    

  

  

    

Total delivery only and PPO

     1,180      1,076      104    9.7%
    

  

  

    

Total electric retail revenues

     8,896      9,002      (106)    (1.2%)
    

  

  

    

Wholesale and miscellaneous revenue (d)

     646      555      91    16.4%
    

  

  

    

Total electric revenue

   $ 9,542    $ 9,557    $ (15)    (0.2%)
    

  

  

    

(a) Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO’s tariffed rates also include a CTC. See Note 5 of Exelon’s Notes to Consolidated Financial Statements for a discussion of CTC.
(b) Delivery only revenue reflects revenue under tariffed rates from customers electing to receive electric generation service from an alternative electric supplier, which rates include a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from alternative electric suppliers are included in wholesale and miscellaneous revenue.
(c) Revenues from customers choosing ComEd’s PPO include an energy charge at market rates, transmission and distribution charges, and a CTC.
(d) Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

 

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

 

Deliveries to customers in million cubic feet (mmcf)


   2004

   2003

   Variance

   % Change

Retail sales

     59,949      61,858      (1,909)    (3.1%)

Transportation

     27,148      26,404      744    2.8%
    

  

  

    

Total

     87,097      88,262      (1,165)    (1.3%)
    

  

  

    

Revenue


   2004

   2003

   Variance

   % Change

Retail sales

   $ 702    $ 609    $ 93    15.3%

Transportation

     18      18      —      —  

Resales and other

     28      18      10    55.6%
    

  

  

    

Total

   $ 748    $ 645    $ 103    16.0%
    

  

  

    

 

67


Results of Operations—Generation

 

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

 

     2004

    2003

    Favorable
(Unfavorable)


 

OPERATING REVENUES

   $ 7,938     $ 8,760     $ (822 )

OPERATING EXPENSES

                        

Purchased power

     2,325       3,630       1,305  

Fuel

     1,845       2,115       270  

Operating and maintenance

     2,273       1,886       (387 )

Impairment of Boston Generating, LLC long-lived assets

     —         945       945  

Depreciation and amortization

     294       201       (93 )

Taxes other than income

     171       121       (50 )
    


 


 


Total operating expense

     6,908       8,898       1,990  
    


 


 


OPERATING INCOME (LOSS)

     1,030       (138 )     1,168  
    


 


 


OTHER INCOME AND DEDUCTIONS

                        

Interest expense

     (167 )     (89 )     (78 )

Equity in earnings (losses) of unconsolidated affiliates

     (14 )     49       (63 )

Other, net

     143       (267 )     410  
    


 


 


Total other income and deductions

     (38 )     (307 )     269  
    


 


 


INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

     992       (445 )     1,437  

INCOME TAXES

     372       (190 )     (562 )
    


 


 


INCOME BEFORE MINORITY INTEREST AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

     620       (255 )     875  

MINORITY INTEREST

     21       (4 )     25  
    


 


 


INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

     641       (259 )     900  

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes)

     32       108       (76 )
    


 


 


NET INCOME (LOSS)

   $ 673     $ (151 )   $ 824  
    


 


 


 

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

 

Cumulative effect of changes in accounting principles recorded in 2004 included a benefit of $32 million, net of income taxes, related to the adoption of FIN 46-R and in 2003 included income of

 

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$108 million, net of income taxes related to the of adoption of SFAS No. 143. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of these effects.

 

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

 

Revenue (in millions)


   2004

   2003

   Variance

    % Change

Electric sales to affiliates

   $ 3,749    $ 3,831    $ (82 )   (2.1%)

Wholesale and retail electric sales

     3,227      4,107      (880 )   (21.4%)
    

  

  


   

Total energy sales revenue

     6,976      7,938      (962 )   (12.1%)
    

  

  


   

Retail gas sales

     456      588      (132 )   (22.4%)

Trading portfolio

     —        1      (1 )   (100.0%)

Other revenue (a)

     506      233      273     117.2%
    

  

  


   

Total revenue

   $ 7,938    $ 8,760    $ (822 )   (9.4%)
    

  

  


   

Sales (in GWhs)


   2004

   2003

   Variance

    % Change

Electric sales to affiliates

     110,465      112,688      (2,223 )   (2.0%)

Wholesale and retail electric sales

     92,134      112,816      (20,682 )   (18.3%)
    

  

  


   

Total sales

     202,599      225,504      (22,905 )   (10.2%)
    

  

  


   

(a) Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

 

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

 

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

 

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

 

Generation


  

Increase

(decrease)


 

Effects of EITF 03-11 adoption (a)

     $(966 )

Sale of Boston Generating

     (370 )

Addition of AmerGen operations

     189  

Other operations

     267  
    


Decrease in wholesale and retail electric sales

   $ (880 )
    



(a) Does not include $14 million of EITF 03-11 reclassifications related to fuel sales that are included in other revenues.

 

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

 

69


resulted in less revenues from this entity in 2004 compared to the prior year. The acquisition of AmerGen resulted in increased market and retail electric sales of approximately $189 million in 2004.

 

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

 

Retail Gas Sales. Retail gas sales decreased $132 million as a result of the wind-down of Exelon Energy’s northeast business.

 

Other revenue. Other revenues in 2004 include $235 million of revenue related to the results of Sithe Energies, Inc. The remaining increase in other revenue includes sales from tolling agreement, fossil fuel and decommissioning revenue.

 

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

 

Supply of Sales (in GWhs)


   2004

   2003

   % Change

 

Nuclear generation (a)

   136,621    117,502    16.3 %

Purchases—non-trading portfolio (b)

   48,968    83,692    (41.5 %)

Fossil and hydroelectric generation (c, d)

   17,010    24,310    (30.0 %)
    
  
      

Total supply

   202,599    225,504    (10.2 %)
    
  
      

(a) Excludes AmerGen for 2003. AmerGen generated 20,135 GWhs during the year ended December 31, 2004.
(b) Sales in 2004 do not include 25,464 GWhs that were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 12,667 GWhs in 2003.
(c) Fossil and hydroelectric supply mix changed as a result of decreased fossil fuel generation due to the sale of Boston Generating in May 2004.
(d) Excludes Sithe and Generation’s investment in TEG and TEP.

 

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

 

Generation


  

Increase

(decrease)


 

Effects of the adoption of EITF 03-11

   $ (980 )

Addition of AmerGen operations

     (344 )

Sale of Boston Generating

     (290 )

Midwest Generation

     (122 )

Price

     (13 )

Mark-to-market adjustments on hedging activity

     (14 )

Volume

     267  

Sithe Energies, Inc.

     165  

Other

     (244 )
    


Decrease in purchased power and fuel expense

   $ (1,575 )
    


 

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

 

70


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

 

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

 

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

 

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

 

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

 

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

 

Sithe Energies, Inc. Under the provisions of FIN 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further discussion of Sithe.

 

Other. Other decreases in purchased power and fuel expense were primarily due to $157 million of lower fuel expense due to the wind-down of Exelon Energy’s northeast business and $97 million of lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM.

 

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

 

($/MWh)


   2004

   2003

   % Change

Average revenue

                  

Electric sales to affiliates

   $ 33.94    $ 34.00    (0.2%)

Wholesale and retail electric sales

     35.03      36.40    (3.8%)

Total—excluding the trading portfolio

     34.43      35.20    (2.2%)

Average supply cost—excluding the trading portfolio (a)

     20.59      25.48    (19.2%)

Average margin—excluding the trading portfolio

     13.84      9.72    42.4%

(a) Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003.

 

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

 

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

 

Generation


  

Increase

(decrease)


 

Addition of AmerGen operations

   $ 331  

Sithe Energies, Inc.

     71  

Decommissioning related costs (a)

     50  

Refueling outage costs (b)

     50  

Pension, payroll and benefit costs, primarily associated with The Exelon Way

     (84 )

DOE Settlement (c)

     (52 )

Sale of Boston Generating

     (12 )

Other

     33  
    


Increase in operating and maintenance expense

   $ 387  
    



(a) Includes $40 million due to AmerGen asset retirement obligation accretion.
(b) Includes refueling outage cost of $43 million at AmerGen.
(c) See Note 14 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the spent nuclear fuel storage settlement agreement with the DOE.

 

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

 

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

 

Generation


   2004

   2003

Nuclear fleet capacity factor (a)

     93.5%      93.4%

Nuclear fleet production cost per MWh (a)

   $ 12.43    $ 12.53

Average purchased power cost for wholesale operations per MWh (b)

   $ 47.48    $ 43.17

(a) Includes AmerGen and excludes Salem, which is operated PSEG Nuclear.
(b) Includes PPAs with AmerGen in 2003.

 

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

 

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

 

72


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

 

Effective Income Tax Rate. The effective income tax rate was 37.5% for 2004 compared to 42.7% for 2003. The decrease in the effective rate was primarily attributable to income taxes associated with nuclear decommissioning trust activity, income tax deductions related to non-taxable employee benefits and the dilution of the permanent income tax benefits due to the increase in pre-tax income in 2004.

 

Results of Operations—Enterprises

 

As previously described, effective January 1, 2004, Enterprises contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises segment. For comparative discussion and analysis, the results of Exelon Energy Company have been excluded from Enterprises’ 2003 results of operations discussed below.

 

     2004

    2003

    Favorable
(unfavorable)
variance


 

Operating revenues

   $ 155     $ 923     $ (768 )

Operating and maintenance expense

     211       1,027       816  

Operating loss

     (62 )     (139 )     77  

Loss before income taxes, minority interest and cumulative effect of changes in accounting principles

     (7 )     (187 )     180  

Loss before cumulative effect of changes in accounting principles

     (13 )     (117 )     104  

Net loss

     (22 )     (118 )     96  

 

Divestiture of Businesses and Investments. In 2004, Exelon continued to execute its divestiture strategy for Enterprises by selling or winding down substantially all components of Enterprises. Enterprises expects to receive aggregate proceeds of $268 million and recorded a net pre-tax gain on the disposition of assets and investments of $41 million in 2004.

 

Enterprises’ results for 2004 compared to 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. Cash proceeds to Enterprises from the sale were approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale, plus a $30 million subordinated note receivable maturing in 2011. At the time of closing, the present value of the note receivable was approximately $12 million. The note was collected in full during the second quarter of 2004, resulting in income of $18 million.

 

Exelon Services, Inc. During 2004, Enterprises disposed of or wound down all of the operating businesses of Exelon Services, Inc. (Exelon Services), including Exelon Solutions, all mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the net gain

 

73


on sale recorded during 2004 related to the disposition of these businesses were $61 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income. As of December 31, 2004, Exelon Services had assets and liabilities of $74 million and $22 million, respectively, which primarily consist of tax assets, affiliate receivables and payables, and sales proceeds to be collected.

 

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, 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.

 

On September 29, 2004, Enterprises sold ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, subject to working capital adjustments. A pre-tax loss of $3 million was recorded in other income and deductions within Exelon’s Consolidated Statements of Income inclusive of the acquisition and sale of Northwind Aladdin’s third-party debt associated with the transaction.

 

On October 28, 2004, Northwind Windsor, of which Enterprises owns a 50% interest, sold substantially all of its assets, providing Enterprises with cash proceeds of $8 million. A pre-tax gain of $2 million was recorded in other income and deductions on Exelon’s Consolidated Statements of 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.

 

At December 1, 2004, the remaining assets of Enterprises totaled approximately $274 million in comparison to $697 million at December 31, 2003.

 

Net Loss. The decrease in Enterprises’ net loss before cumulative effect of changes in accounting principles in 2004 was primarily due to a decrease in operating and maintenance expense, partially offset by a decrease in operating revenues. Depreciation and amortization expense decreased $23 million before income taxes from 2003 to 2004 primarily as a result of the sale of the majority of property, plant and equipment since September 2003. In 2004, Enterprises recorded impairment charges of investments of $15 million before income taxes due to other-than-temporary declines in value, partially offset by 2003 charges for impairment of investments of $46 million before income taxes and a net impairment of other assets of $8 million before income taxes. The adoption of EITF 03-16 increased the 2004 net loss by $9 million. The adoption of SFAS No. 143 increased the 2003 net loss by $1 million, net of income taxes. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the adoption of EITF 03-16 and SFAS No. 142.

 

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

 

     Variance

 

F & M Holdings, LLC / InfraSource businesses (a)

   $ (493 )

Exelon Services (a)

     (259 )

Exelon Thermal (a)

     (17 )

Other

     1  
    


Decrease in operating revenues

   $ (768 )
    



(a) Operating revenues decreased as a result of the sale of certain businesses and wind-down efforts.

 

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

 

     Variance

 

F & M Holdings, LLC / InfraSource businesses (a)

   $ (503 )

Exelon Services (a)

     (276 )

Exelon Thermal (a)

     (10 )

Other

     (27 )
    


Decrease in operating and maintenance expense

   $ (816 )
    



(a) Operating and maintenance expense decreased as a result of the sale of certain businesses and wind-down efforts.

 

Effective Income Tax Rate. The effective income tax rate was (85.7%) for 2004 compared to 37.4% for 2003. This change in the effective tax rate was primarily attributable to the reversal of a large income tax receivable at F&M Holdings, LLC in the fourth quarter of 2004, the state tax impact on the gains on the sales of Exelon Thermal’s Chicago businesses and certain investments, and various other income tax adjustments primarily associated with the sale of Enterprise businesses.

 

75


Results of Operations—Exelon Corporation

 

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

 

Significant Operating Trends—Exelon

 

Exelon Corporation


   2003

    2002

    Favorable
(unfavorable)
variance


 

Operating revenues

   $ 15,812     $ 14,955     $ 857  

Purchased power and fuel expense

     6,375       5,262       (1,113 )

Impairment of Boston Generating, LLC long-lived assets

     945       —         (945 )

Operating and maintenance expense

     4,508       4,345       (163 )

Operating income

     2,277       3,299       (1,022 )

Other income and deductions

     (1,148 )     (627 )     (521 )

Income before income taxes, minority interest and cumulative effect of changes in accounting principles

     1,129       2,672       (1,543 )

Income before cumulative effect of changes in accounting principles

     793       1,674       (881 )

Income taxes

     331       998       667  

Net income

     905       1,440       (535 )

Diluted earnings per share

     1.38       2.22       (0.84 )

 

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

 

Operating Revenues. Operating revenues increased in 2003 primarily due to increased market sales at Generation due to generating assets acquired in 2002 and higher wholesale market prices in 2003. Total market sales at Generation, excluding the trading portfolio, increased from 88,985 GWhs in 2002 to 112,816 GWhs in 2003, and the average revenue per MWh on Generation’s market sales, excluding the trading portfolio, increased from $32.36 in 2002 to $35.20 in 2003. This increase in operating revenues was partially offset by a decrease in Energy Delivery’s revenues of $255 million primarily due to unfavorable weather impacts and an increase in customers selecting an alternative electric supplier or ComEd’s PPO. Enterprises also experienced a $413 million reduction in operating revenues from 2002 to 2003, primarily due to the sale of InfraSource during the third quarter of 2003. See further discussion of operating revenues by segment below.

 

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

 

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

 

Operating and Maintenance Expense. Operating and maintenance expense increased in 2003 primarily due to a change in the accounting methodology for nuclear decommissioning, severance and severance-related costs associated with The Exelon Way, and increased costs at Generation

 

76


associated with generating assets acquired in 2002. Partially offsetting these increases was an overall reduction in operating and maintenance expenses at Enterprises, primarily due to the sale of InfraSource during the third quarter of 2003. See further discussion of operating and maintenance expenses by segment below.

 

Operating Income. The decrease in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense, Boston Generating long-lived asset impairment charge and operating and maintenance expense discussed above, was primarily due to a decrease of $214 million in depreciation and amortization expense primarily due to the adoption of SFAS No. 143 and lower depreciation and amortization expense in the Energy Delivery segment. In addition, taxes other than income also decreased by $128 million primarily due to a reduction in reserves for real estate taxes within the Energy Delivery and Generation segments.

 

Other Income and Deductions. Other income and deductions changed primarily due to impairment and other transaction-related charges of $280 million recorded in 2003 related to Generation’s investment in Sithe. Interest expense decreased 9% from $966 million in 2002 to $881 million in 2003 primarily due to less outstanding debt and refinancing of existing debt at lower interest rates at Energy Delivery partially offset by increased interest expense at Generation due to debt related to 2002 acquisitions and reduced capitalized interest in 2003. In 2002, Enterprises recorded a gain on the sale of its investment in AT&T Wireless of $198 million (before income taxes).

 

Effective Income Tax Rate. The effective income tax rate was 29.3% for 2003 compared to 37.4% for 2002. The decrease in the effective rate was primarily attributable to a decrease in state income taxes, net of Federal income tax benefit, and investments in synthetic fuel-producing facilities made in the fourth quarter of 2003.

 

Results of Operations by Business Segment

 

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

 

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

 

     2003

    2002

 

Total revenues

   $ 834     $ 697  

Intersegment revenues

     4       8  

Operating revenue and purchased power from affiliates

     209       235  

Depreciation and amortization

     2       16  

Operating expenses

     857       700  

Interest expense

     1       4  

Cumulative effect of changes in accounting principles

     —         (11 )

Loss before income taxes

     (29 )     (6 )

Income taxes

     (11 )     16  

Net loss

     (18 )     (33 )

 

77


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

 

     2003

    2002

    Favorable
(unfavorable)
variance


 

Energy Delivery

   $ 1,170     $ 1,268     $ (98 )

Generation

     (259 )     365       (624 )

Enterprises

     (117 )     87       (204 )

Corporate

     (1 )     (50 )     49  
    


 


 


Total

   $ 793     $ 1,670     $ (877 )
    


 


 


 

Net Income (Loss) by Business Segment

 

     2003

    2002

    Favorable
(unfavorable)
variance


 

Energy Delivery

   $ 1,175     $ 1,268     $ (93 )

Generation

     (151 )     367       (518 )

Enterprises

     (118 )     (145 )     27  

Corporate

     (1 )     (50 )     49  
    


 


 


Total

   $ 905     $ 1,440     $ (535 )
    


 


 


 

Results of Operations—Energy Delivery

 

     2003

    2002

    Favorable
(unfavorable)
variance


 

OPERATING REVENUES

   $ 10,202     $ 10,457     $ (255 )

OPERATING EXPENSES

                        

Purchased power and fuel expense

     4,597       4,602       5  

Operating and maintenance

     1,669       1,486       (183 )

Depreciation and amortization

     873       978       105  

Taxes other than income