EX-99.3 6 dex993.htm MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OP. Management's Discussion and Analysis of Financial Condition and Results of Op.

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

(Dollars in millions, unless otherwise noted)

 

GENERAL BUSINESS

 

Exelon Corporation (Exelon) is a registered public utility holding company that, through its subsidiaries, operates in three business segments—Energy Delivery, Generation and Enterprises—as described below. See Note 21 of the Notes to Consolidated Financial Statements for further segment information. In addition to our three business segments, Exelon Business Services Company (BSC) provides Exelon and its subsidiaries with financial, human resource, legal, information technology, supply management and corporate governance services.

 

Energy Delivery

 

Our energy delivery business consists of the regulated sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and by PECO Energy Company (PECO) in southeastern Pennsylvania and the regulated sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.

 

ComEd. 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 regulated by the Illinois Commerce Commission (ICC) as to rates, the issuance of securities and certain other aspects of ComEd’s operations. ComEd is also subject to regulation by the Federal Energy Regulatory Commission (FERC) as to transmission rates and certain other aspects of its 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 (Chicago), an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.6 million customers.

 

PECO. PECO is engaged principally in the purchase, transmission, distribution and sale of electricity and in the purchase, distribution and sale of natural gas to residential, commercial and industrial customers. PECO is regulated by the Pennsylvania Public Utility Commission (PUC) as to electric and gas rates, the issuances of 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 its business.

PECO’s retail service territory covers approximately 2,100 square miles in southeastern Pennsylvania. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.9 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in an approximate 1,900 square mile area in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.4 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 460,000 customers.

 

Generation

 

Our generation business consists of the owned and contracted for electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation) and a 50% interest in Sithe Energies Inc. (Sithe) and, effective January 1, 2004, the competitive retail sales business of Exelon Energy Company.

Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled megawatts (MWs). Generation combines its large generation fleet with an experienced wholesale power marketing operation. Generation owns generation assets in the Northeast, Mid-Atlantic, Midwest and Texas regions with a net capacity of 28,492 MWs, including 16,959 MWs of nuclear capacity, and controls another 12,703 MWs of capacity in the Midwest, Southeast and South Central regions through long-term contracts. Generation’s ownership interests include 3,145 MWs of capacity owned by Boston Generating, LLC (Boston Generating), a project subsidiary of Exelon New England, formerly known as Exelon Boston Generating, LLC. In July 2003, Generation commenced the process of an orderly transition out of the ownership of Boston Generating. This transition is anticipated to occur in 2004.

In addition to its owned generating facilities, Generation owns a 50% interest in Sithe with another entity, with put and call options that could result in either party owning all of Sithe outright. While Exelon’s intent is to fully divest Sithe, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors, such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise (see further discussion of Sithe in Contractual Obligations and Off-Balance Sheet Arrangements section below and in Note 3 of the Notes to Consolidated Financial Statements). Sithe develops, owns and operates 12 generation stations consisting of 15 units in North America. Currently, Sithe has a total generating capacity of 1,097 MWs in operation and 228 MWs under construction.

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 energy, or “load,” requirements of ComEd and PECO.

 

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Power Team markets any remaining energy in the wholesale bilateral and spot markets.

 

Enterprises

 

Our enterprise business consists primarily of the energy services business of Exelon Services, Inc. (Exelon Services), the district cooling business of Exelon Thermal Holdings, Inc. (Thermal), the electrical contracting business of F&M Holdings, Inc., a communications joint venture and other investments weighted towards the communications, energy services and retail services industries. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. We continue to pursue opportunities to sell other Enterprises businesses.

 

EXECUTIVE SUMMARY

 

2003 has been a year of operating accomplishments and painful investment write-offs. We have focused on living up to our reliability and safety commitments while pursuing greater productivity, quality and innovation.

 

Financial Results. We experienced an overall decline in diluted earnings per average common share of 38% in 2003. This decline was primarily due to a charge of $573 million (after-tax) related to the impairment of the long-lived assets of Boston Generating. In addition, we incurred impairment and transaction-related charges of $180 million (after-tax) related to our investment in Sithe and severance and severance-related charges approximating $159 million (after-tax) associated with The Exelon Way. Our energy delivery business experienced a decline in kilowatthour deliveries due to moderate weather, and the operating margins at our Enterprises business were lower due to the sale of the majority of the InfraSource Inc. business in the third quarter of 2003. Our 2003 results were favorably affected by modest improvements in wholesale energy prices, which increased Generation’s energy margins, and by lower interest expense and a lower effective income tax rate. We also recorded an after-tax gain of $112 million upon the adoption of a new accounting standard that has a significant impact on how we account for our nuclear decommissioning obligation.

 

The Exelon Way. We implemented The Exelon Way, an aggressive plan defining how we will conduct business in years to come. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Our targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. In addition to the severance and severance-related charges we recorded during 2003, we anticipate incurring additional charges associated with The Exelon Way in future periods.

 

Investment Strategy. We continued to follow a disciplined approach to investing to maximize the earnings and cash flows from our assets and businesses and to sell those that do not meet our goals. Our 2003 highlights include:

 

– We announced our transition out of our ownership of Boston Generating in July 2003 because our internal financial analysis clearly showed that we would be obliged to make significant equity infusions to preserve the projects with little prospect of adequate return.
– We completed a series of transactions in November 2003 that restructured the ownership of Sithe, with Generation continuing to own a 50% interest in Sithe. We continue to pursue the divestiture of our investment in Sithe.
– We purchased British Energy plc’s 50% interest in AmerGen Energy Company, LLC (AmerGen) in December 2003. AmerGen, which owns the Clinton Power Station, Three Mile Island Nuclear Station Unit 1 and the Oyster Creek Generating Station representing about 2,500 megawatts of capacity, is now our wholly owned subsidiary.
– We attempted to purchase Illinois Power Company and to resolve certain rate issues following the end of the current rate freeze at ComEd in 2006. Since the latter could not be accomplished at this time, the proposed Illinois Power transaction was abandoned.
– We continued to execute our divestiture strategy for Enterprises by selling the electric construction and services, underground and telecom businesses of InfraSource in September 2003 and entering into agreements in December 2003 to sell the Chicago operations and the Aladdin thermal facility of Thermal and certain direct investments held by Enterprises.

 

Financing Activities. We refinanced $2.4 billion of outstanding debt and equity securities in 2003 and repaid approximately $580 million of transitional trust notes and $260 million of long-term debt, resulting in expected annual interest savings of $96 million. We met all of our capital resource commitments with internally generated cash and expect to do so in the foreseeable future, absent new acquisitions. We increased our dividend rate by 20% over the past twelve months.

 

Operational Achievements. Our energy delivery and generation businesses focused on the core fundamentals of providing reliable delivery service and efficient generation to our customers. Energy Delivery, Generation’s nuclear business and BSC combined resources to minimize the aftermath of Hurricane Isabel that affected the Philadelphia area and helped to prevent the potentially detrimental cascading effects of the August 14, 2003 blackout in the Northeastern United States and Canada (August Blackout) to our system

 

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and to our customers. Following several years of continued reliability improvement, Energy Delivery’s performance dipped slightly in 2003 due to Hurricane Isabel and also due to a series of severe storms across Northern Illinois—two of which were the worst since 1998. Generation’s nuclear fleet achieved a 93.4% capacity factor in 2003 compared to 92.7% in 2002 while reducing the costs of nuclear generation to 1.25 cents per kilowatthour.

 

Outlook for 2004 and Beyond. In the short term, our financial results will be affected by a number of factors, including weather conditions, wholesale market prices, successful implementation of The Exelon Way and our ability to generate electricity at low costs. If weather is warmer than normal in the summer months or colder than normal in the winter months, operating revenues at Energy Delivery generally will be favorably affected. Operating revenues will also be favorably affected by increases in wholesale market prices. In addition, we are required annually to assess the goodwill recorded at ComEd to determine if it is impaired. Based on certain anticipated reductions to cash flows subsequent to the restructuring transition period (primarily competitive transition charges that, under the current restructuring statute, will not be collected after 2006), we believe there is a reasonable possibility that goodwill will be impaired at ComEd in 2004 or later periods, and such impairment may be significant. Under current accounting standards, a goodwill impairment at ComEd may not affect Exelon’s consolidated financial results.

Longer term, restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, with continuing debate at the FERC on regional transmission organization (RTO) and standard market platform issues and in many states on the “post transition” format. Some states abandoned failed transition plans (like California), some states are adjusting current transition plans (like New Jersey and 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. We 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 our investors.

As we look towards the end of the restructuring transition periods and related rate caps or freezes in Illinois and Pennsylvania, we 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. We will strive to ensure that future rate structures recognize the substantial improvements we have made, and will continue to make, in our transmission and distribution systems. We will also work to ensure that ComEd’s and PECO’s rates adequately compensate our suppliers, which could include Generation, for the costs associated with procuring full-load following capacity energy supplies given Energy Delivery’s Provider of Last Resort (POLR) obligations. As in the past, by working together with all interested parties, we believe we can successfully meet these objectives and obtain fair recovery of our costs for providing service to our customers. However, if we are unsuccessful, our results of operations and cash flows could be negatively affected after the transition periods.

While the U.S. economic recovery appears underway, our current plans are based on moderate kilowatthour sales growth (1% to 2%) and continued softness in wholesale power markets. Successful implementation of The Exelon Way is needed to offset labor and material cost escalation, especially the double digit increases in health care costs. Despite these challenges, our 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 we will strive to meet these challenges.

 

BUSINESS OUTLOOK AND THE CHALLENGES IN MANAGING OUR BUSINESS

 

Substantially all of our businesses are in the electric generation, transmission and distribution industry in the United States. That industry is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. Our energy delivery business remains highly regulated while our generation and enterprises businesses operate in competitive environments. All of our businesses are capital intensive.

The challenges affecting our businesses are discussed below. There are several factors, such as weather, economic activity and regulatory actions that affect our businesses in different ways. Also, there are several factors that affect our business as a whole, such as environmental compliance and the ability to access capital on a cost-effective basis. Further discussion of our liquidity and capital resources and related challenges is included in the Liquidity and Capital Resources section.

 

Energy Delivery

 

Our energy delivery business is comprised of two utility transmission and distribution companies, ComEd and PECO, which provide electricity and, in the case of PECO, natural gas to customers in Illinois and Pennsylvania, respectively. Energy Delivery focuses on providing safe and reliable serv -

 

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ices to customers. Energy Delivery continues to make improvements to its delivery systems to minimize the frequency and duration of service interruptions, while working more efficiently to lower their costs. We believe that Energy Delivery will continue to provide a significant and steady source of earnings and cash flows over the next several years.

Both Illinois and Pennsylvania have adopted restructuring legislation designed to foster competition in the retail sale of electricity. As a result of these restructuring initiatives, both ComEd and PECO are subject to rate freezes or caps through mandated restructuring transition periods. During these periods, the results of operations of ComEd and PECO will depend on our ability to deliver energy in a cost-efficient manner and to offset infrastructure investments and inflation with cost savings initiatives. ComEd and PECO each expect to continue to have long-term, full-requirements supply contracts with Generation, helping to mitigate the risk of changing energy supply costs during their respective transition periods. We are also managing operations and maintenance costs by implementing The Exelon Way business model, while maintaining our focus on both reliability and safety in operating our business.

We cannot currently predict the frameworks that will be used by the Illinois and Pennsylvania state regulators to establish rates after the transition periods. We also cannot predict the outcome of any new laws that may impact our business. Nevertheless, we expect ComEd and PECO will retain significant POLR obligations, whereby each utility is required to provide service to customers in its service area. ComEd and PECO therefore must continue to ensure adequate supplies of electricity and gas are available at reasonable costs. While ComEd and PECO do not have their own generation capabilities, their ongoing relationship with Generation will serve to lessen the supply and price risks associated with their expected ongoing power procurement responsibilities.

More detailed explanations for each of these and other challenges in managing our energy delivery business are as follows:

 

We must comply with numerous regulatory requirements in managing our energy delivery business, which affect our costs and responsiveness to changing events and opportunities.

Our energy delivery business is subject to regulation at the state and Federal levels. ComEd is regulated by the ICC, and PECO is regulated by the PUC. These state commissions regulate the rates, terms and conditions of service; various business practices and transactions; financing; and transactions between the utilities and our affiliates. Both ComEd and PECO are also subject to regulation by the FERC, which regulates their transmission rates, certain other aspects of their businesses and, for PECO, gas pipelines. The regulations adopted by these state and Federal agencies affect the manner in which we do business, our ability to undertake specified actions, the costs of our operations, and the level of rates we may charge to recover such costs.

 

We must manage Energy Delivery’s costs due to the rate and equity return limitations imposed on its revenues.

Rate freezes or caps in effect at ComEd and PECO currently limit our ability to recover increased expenses and the costs of investments in new transmission and distribution facilities. As a result, our future results of operations will depend on the ability of ComEd and PECO to deliver electricity and, in the case of PECO, natural gas, in a cost-efficient manner and to realize cost savings under The Exelon Way to offset increased infrastructure investments and inflation.

 

Rate limitations. ComEd is subject to a legislatively mandated rate freeze on bundled retail rates that will remain in effect until January 1, 2007. Pursuant to a Merger-related settlement agreement with the PUC, PECO is subject to agreed-upon rate reductions of $200 million, in aggregate, for the period 2002 through 2005, including $80 million, in aggregate, for the years 2004 and 2005, and caps (subject to limited exceptions for significant increases in Federal or state income taxes or other significant changes in law or regulation that do not allow PECO to earn a fair rate of return) on its transmission and distribution rates through December 31, 2006, and on its generation rates through December 31, 2010.

 

Equity return limitation. ComEd is subject to a legislatively mandated cap on its return on common equity through the end of 2006. The cap is based on a two-year average of the U.S. Treasury long-term rates (25 years and above) plus 8.5% and is compared to a two-year average return on ComEd’s common equity. The legislation requires customer refunds equal to one-half of any excess earnings above the cap. ComEd is allowed to include regulatory asset amortization in the calculation of earnings. ComEd has not triggered the earnings provision and currently does not expect to trigger the earnings sharing provision in the years 2004 through 2006.

 

Energy Delivery’s long-term purchased power agreements provide a hedge to its customers’ demand.

To effectively manage its obligation to provide power to meet its customers’ demand, Energy Delivery has established full-requirements, power supply agreements with Generation which reduce exposure to the volatility of customer demand and market prices through 2006 for ComEd and through 2010 for PECO. Market prices relative to Energy Delivery’s regulated rates still influence switching behavior among retail customers.

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Effective management of capital projects is important to our business.

Energy Delivery’s business is capital intensive and requires significant investments in energy transmission and distribution facilities and in other internal infrastructure projects.

We expect to continue to make significant capital expenditures to improve the reliability of our transmission and distribution systems in order to provide a high level of service to its customers. We further expect Energy Delivery’s capital expenditures to exceed depreciation on its plant assets. Energy Delivery’s base rate freeze and caps will generally preclude incremental rate recovery on any of these incremental investments prior to January 1, 2007.

 

Our business may be significantly affected by the end of the Illinois and Pennsylvania regulatory transition periods.

Illinois electric utilities are allowed to collect competitive transition charges (CTCs) from customers who choose an alternative supplier of electric generation service or choose ComEd’s power purchase option (PPO). CTCs were intended to assist electric utilities, such as ComEd, in recovering stranded costs that might not otherwise be recoverable in a fully competitive market. The CTC charge represents the difference between the market value of delivered energy (the sum of generation service at market-based prices and the regulated price of energy delivery) and recoveries under historical bundled rates, reduced by a mitigation factor. The CTC charges are updated annually. Over time, to facilitate the transition to a competitive market, the mitigation factor increases, thereby reducing the CTC charge.

In 2003 and 2002, ComEd collected approximately $300 million of CTC revenue annually. 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, we anticipate that this revenue source will decline to approximately $180 million to $200 million in each of the years 2004 through 2006. Under the current restructuring statute, no CTCs will be collected after 2006.

Through 2006, ComEd will continue to have an obligation to offer bundled service to all customers (except certain large customers with demand of three megawatts or more) at frozen price levels, under which a majority of ComEd’s residential and small commercial customers are expected to continue to receive service. ComEd’s current bundled service is generally provided under an all-inclusive rate that does not separately break out charges for energy generation service and energy delivery service, but charges a single set of prices. After the transition ends in 2006, ComEd’s bundled rates may be reset through a regulatory approval process, which may include traditional or innovative pricing, including performance-based incentives to ComEd.

 

In order to address post-transition uncertainty, we are continually working with Illinois state and business community leadership to facilitate the development of a competitive electricity market while providing system reliability. Transparent and liquid markets will help to minimize litigation over electricity prices and provide consumers assurance of equitable pricing. At the same time, we are attempting to establish a regulatory framework for the post-2006 timeframe and we are pursuing measures that will provide greater productivity, quality and innovation in our work practices across Exelon. Currently, it is difficult to predict the framework for or the outcome of a potential regulatory proceeding to establish rates after 2006.

In Pennsylvania, the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act) provides for the imposition and collection of non-bypassable CTCs on customers’ bills as a mechanism for utilities to recover their allowed stranded costs. CTCs are assessed to and collected from virtually all retail customers who access PECO’s transmission and distribution systems. These CTCs are assessed regardless of whether the customer purchases electricity from PECO or an alternative electric generation supplier. The Competition Act provides, however, that PECO’s right to collect CTCs 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%. At December 31, 2003, approximately $4.3 billion had yet to be recovered. Recovery of transition charges for stranded costs and PECO’s allowed return on its recovery of stranded costs are included in revenues. Amortization of PECO’s stranded cost recovery, which is a regulatory asset, is included in depreciation and amortization expense. PECO’s results will be adversely affected over the remaining transition period ending December 31, 2010 by the steadily increasing amortization of stranded costs. The following table (amounts in millions) indicates the estimated revenues and amortization expense associated with CTC collection and stranded cost recovery through 2010.

Year  

Estimated

CTC Revenue

   

Estimated Stranded

Cost Amortization

2004

   $ 812    $ 367

2005

     808      404

2006

     903      550

2007

     910      619

2008

     917      697

2009

     924      783

2010

     932      880

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

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By the end of 2010, PECO will have fully recovered all of the stranded costs authorized by the PUC. As a result, PECO expects that both its revenues and expenses will decrease in 2011. The end of the transition period involves uncertainties, including the nature of PECO’s POLR obligations and the source and pricing of generation services to be provided by PECO. PECO expects to pursue resolution of these uncertainties during the remaining transition period.

 

Our ability to successfully manage the end of the transition period may affect our capital structure.

ComEd has approximately $4.7 billion of goodwill recorded at December 31, 2003. This goodwill was recognized and recorded in connection with the Merger. Under accounting principles generally accepted in the Unites States (GAAP), the goodwill will remain at its recorded amount unless it is determined to be impaired, which is based upon an annual analysis prescribed by SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142) that compares the implied fair value of the goodwill to its carrying value. If an impairment is determined at ComEd, the amount of the impaired goodwill will be written off and expensed at ComEd. Under Illinois statute, any impairment of goodwill has no impact on the determination of ComEd’s rate cap through the transition period.

ComEd’s goodwill has not been impaired to date. However, based on certain anticipated reductions to cash flows (primarily CTCs) subsequent to ComEd’s regulatory transition period, we believe there is a reasonable possibility that goodwill will be impaired at ComEd in 2004 or later periods. The actual timing and amounts of any goodwill impairments in future years, if any, will depend on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, ComEd’s capital structure, market power prices, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors, some not yet known. A goodwill impairment charge at ComEd may not affect Exelon’s results of operations as the goodwill impairment test for Exelon would consider cash flows of the entire Energy Delivery business segment, including both ComEd and PECO, and not just of ComEd. See Critical Accounting Policies and Estimates for further discussion on goodwill impairments.

 

We are and will continue to be involved in regulatory proceedings as a part of the process of establishing the terms and rates for Energy Delivery’s services.

These regulatory proceedings typically involve multiple parties, including governmental bodies, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings also involve various contested issues of law and fact and have a bearing upon the recovery of Energy Delivery’s costs through regulated rates. During the course of the proceedings, we look for opportunities to resolve contested issues in a manner that grants some certainty to all parties to the proceedings as to rates and energy costs.

 

We must maintain the availability and reliability of Energy Delivery’s delivery systems to meet customer expectations.

Increases in both customers and the demand for energy require expansion and reinforcement of delivery systems to increase capacity and maintain reliability. Failures of the equipment or facilities used in those delivery systems could potentially interrupt energy delivery services and related revenues and increase repair expenses and capital expenditures. Such failures, including prolonged or repeated failures, also could affect customer satisfaction and may increase regulatory oversight and the level of our maintenance and capital expenditures. We cannot predict what impact these failures, or failures that impact other utilities such as the August Blackout, will have on our anticipated capital expenditures.

Although neither ComEd nor PECO was directly affected by the August Blackout, we may be indirectly affected going forward. Regulated utilities that are required to provide service to all customers within their service territory have generally been afforded liability protections against claims by customers relating to failure of service. Following the August Blackout, significant claims have been asserted against various other utilities on behalf of both customers and non-customers for damages resulting from the blackout. We cannot predict whether these claims will be upheld or whether they or legislative or regulatory initiatives in response to the August Blackout will change the traditional liability protections of utilities in providing regulated service. In addition, under Illinois law, ComEd can be required to pay damages to its customers in the event of extended outages affecting large numbers of its customers.

 

Energy Delivery has lost and may continue to lose energy customers to other generation suppliers, although it continues to provide delivery services and may have an obligation to provide generation service to those customers.

The revenues of our energy delivery business will vary because of customer choice of generation suppliers. As a result of restructuring initiatives in Illinois and Pennsylvania, all of Energy Delivery’s retail electric customers may purchase their generation supply from alternative electric generation suppliers. In addition, since market share thresholds (MST) for customers taking service from alternative generation suppliers agreed to by PECO were not met, PECO has been required to assign both commercial and residential customers to alternative generation suppliers. ComEd and PECO are each generally obligated to provide generation and delivery

 

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service to customers in their service territories at fixed rates, or in some instances, market-derived rates. In addition, customers who take service from an alternative generation supplier may later return to ComEd or PECO, provided, however, that under Illinois law, ComEd’s obligation to provide generation may be eliminated over time if the ICC finds that competitive supply options are available to certain classes of customers. ComEd and PECO remain obligated to provide transmission and distribution service to all customers regardless of their generation suppliers. The number of customers taking service from alternative generation suppliers depends in part on the prices being offered by those suppliers relative to the fixed prices that ComEd and PECO are authorized to charge by their state regulatory commissions. To the extent that customers leave traditional bundled tariffs and select a different generation supplier, Energy Delivery’s revenues are likely to decline, and our revenues and gross margins could vary from period to period.

 

Energy Delivery continues to serve as the POLR for energy for all customers in its service territories. Since ComEd and PECO customers can “switch,” that is, within limits they can choose an alternative generation supplier and then return to us and then go back to an alternative supplier, and so on, planning for Energy Delivery has a higher level of uncertainty than that traditionally experienced due to weather and the economy. Energy Delivery has no obligation to purchase power reserves to cover the load served by others. We manage our POLR obligation through full-requirements contracts with Generation, under which Generation supplies the power requirements of ComEd and PECO.

ComEd has received ICC approval to phase out its obligation to provide fixed-price energy under bundled rates to approximately 350 of its largest energy customers, which ComEd believes partially mitigates its risk. These are commercial and industrial customers, including heavy industrial plants, large office buildings, government facilities and a variety of other businesses with demands of at least three MWs representing an aggregate of approximately 2,500 MWs of load. These customers accounted for 10% of ComEd’s 2003 MWh deliveries.

 

Weather affects electricity and gas usage and, consequently, Energy Delivery’s results of operations.

Temperatures above normal levels in the summer tend to further increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to further increase winter heating electricity and gas demand and revenues. Because of seasonal pricing differentials, coupled with higher consumption levels, we typically report higher revenues in the third quarter of our fiscal year. However, extreme summer conditions or storms may stress our transmission and distribution systems, resulting in increased maintenance costs and limiting our ability to meet peak customer demand. These extreme conditions may have detrimental effects on our operations.

 

Economic conditions and activity in Energy Delivery’s service territories directly affect the demand for electricity.

Higher levels of development and business activity generally increase the number of customers and their average use of energy. Periods of recessionary economic conditions may adversely affect our results of operations. In the near term, retail sales growth on an annual basis is expected to be 1.2% and 1.3% in the service territories of ComEd and PECO, respectively. Long-term retail sales growth for electricity is expected to be 1.5% and 1.0% per year for ComEd and PECO, respectively.

 

Energy Delivery’s business is affected by the restructuring of the energy industry.

The electric utility industry in the United States is in transition. As a result of both legislative initiatives as well as competitive pressures, the industry has been moving from a fully regulated industry, consisting primarily of vertically integrated companies that combine generation, transmission and distribution, to a partially restructured industry, consisting of competitive wholesale generation markets and continued regulation of transmission and distribution. These developments have been somewhat uneven across the states as a result of the reaction to the problems experienced in California in 2000, the August Blackout and the publicized problems of some energy companies. Both Illinois and Pennsylvania have adopted restructuring legislation designed to foster competition in the retail sale of electricity. A large number of states have not changed their regulatory structures.

 

Regional Transmission Organizations and Standard Market Platform. The FERC has required jurisdictional utilities to provide open access to their transmission systems. It has also sought the voluntary development of RTOs and the elimination of trade barriers between regions. The FERC also proposed rulemakings to implement protocols to create a standard wholesale market platform for the wholesale markets for energy and capacity. The RTO would become the provider of the transmission service, and the transmission owners would recover their revenue requirements through it. The transmission owners would remain responsible for maintaining and physically operating their transmission facilities. The wholesale market platform proposal would also require RTOs to operate an organized bid-based wholesale market for those who wish to sell their generation through the market and to manage congestion on transmission lines preferably by means of a financially based system known as “locational marginal pricing.” FERC is likely to finalize its wholesale market platform rule during 2004.

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

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PECO is a member of PJM Interconnection, LLC (PJM), an approved RTO operating in the Mid-Atlantic region. ComEd and other Midwestern utilities are seeking to become fully integrated into the PJM RTO in 2004. When ComEd integrates into PJM, ComEd will recover its current transmission revenues through the PJM open-access transmission tariff (OATT), instead of ComEd’s own OATT.

The FERC’s RTO and standard market platform initiatives have generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop an RTO have been abandoned in certain regions. We support both of these FERC initiatives but cannot predict whether they will be successful, what impact they may ultimately have on our transmission rates, revenues and operation of our transmission facilities, or whether they will ultimately lead to the development of large, successful regional wholesale markets. To the extent that ComEd and PECO have POLR obligations and may at some point no longer have long-term supply contracts with Generation, the ability of ComEd and PECO to cost effectively serve their POLR load obligations may depend on successful spot markets in their franchised service territories.

Proposed Federal Energy Legislation. One of the principal legislative initiatives of the Bush administration is the adoption of comprehensive Federal energy legislation. In 2003, an energy bill was passed by the U.S. House of Representatives but was not voted on by the U.S. Senate. The energy bill, as currently written, would repeal the Public Utility Holding Company Act of 1935 (PUHCA), create incentives for the construction of transmission infrastructure, encourage but not mandate standardized competitive markets and expand the authority of the FERC to include overseeing the reliability of the bulk power system. We cannot predict whether comprehensive energy legislation will be adopted and, if adopted, the final form of that legislation. We would expect that comprehensive energy legislation would, if adopted, significantly affect the electric utility industry and our businesses.

 

Generation

 

Generation is focused on providing low-cost and reliable power through a generation portfolio with fuel and dispatch diversity. Generation’s direction is to continue to increase fleet output and to improve fleet efficiency while sustaining operational safety. Generation’s Power Team manages the output of Generation’s assets and energy sales to reduce the volatility of Generation’s earnings and cash flows. We believe that Generation will provide a steady source of earnings through its low-cost operations and will take advantage of higher wholesale prices when they can be realized.

 

Generation must effectively manage its power portfolio to meet its contractual commitments and to handle changes in the wholesale power markets.

The majority of Generation’s portfolio is used to provide power under long-term purchased power agreements with ComEd and PECO. To the extent the portfolio is not needed for that purpose, Generation’s output is sold on the wholesale market. Generation’s financial results are dependent upon its ability to cost-effectively meet the load requirements of ComEd and PECO, to manage its power portfolio and to effectively handle the changes in the wholesale power markets.

 

The scope and scale of our nuclear generating resources provide a cost advantage in meeting our contractual commitments and enable us to sell power in the wholesale markets.

Generation’s resources include interests in 11 nuclear generation stations, consisting of 19 units. Generation’s nuclear fleet, excluding AmerGen’s three units, generated 117,502 GWhs, or more than half of our total available generating capacity, as of December 31, 2003. As the largest generator of nuclear power in the United States, Generation can take advantage of its scale and scope to negotiate favorable terms for the materials and services that our business requires. Generation’s nuclear plants benefit from stable fuel costs, minimal environmental impact from operations and a safe operating history.

 

Our financial performance may be affected by liabilities arising from Generation’s ownership and operation of nuclear facilities.

The ownership and operation of nuclear facilities involve risks, including:

 

– mechanical or structural problems;
– inadequacy or lapses in maintenance protocols;
– impairment of reactor operation and safety systems due to human error;
– costs of storage, handling and disposal of nuclear materials;
– limitations on the amounts and types of insurance coverage commercially available; and
– uncertainties regarding both technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.

 

The material risks known or currently anticipated by us that could affect our ability to sustain our current levels of profitability are:

 

Nuclear capacity factors. Capacity factors, particularly nuclear capacity factors, significantly affect our results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs

 

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due to low fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear generating facilities at high capacity factors. Lower capacity factors would increase Generation’s operating costs and could require Generation to generate additional energy from its fossil or hydroelectric facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to ComEd and PECO and other committed third-party sales. These sources generally are at a higher cost than Generation otherwise would have to incur to generate energy from its nuclear stations.

 

Refueling outages. Outages at nuclear stations to replenish fuel require the station to be “turned off.” Refueling outages are planned to occur once every 18 to 24 months and currently average approximately 26 days in duration. Generation has significantly decreased the length of refueling outages in recent years. However, when refueling outages last longer than anticipated or Generation experiences unplanned outages, Generation faces lower margins due to higher energy replacement costs and/or lower energy sales. Each twenty-six day outage, depending on the capacity of the station, will decrease the total nuclear annual capacity factor between 0.3% and 0.5%. The number of refueling outages, including AmerGen, will increase to ten in 2004 from nine in 2003. Maintenance expenditures are expected to increase by approximately $20 million in 2004 as compared to 2003 as a result of increased nuclear refueling outages.

 

Nuclear fuel quality. The quality of nuclear fuel utilized by Generation can affect the efficiency and costs of our operations. Certain of Generation’s nuclear units have been identified as having a limited number of fuel performance issues. Remediation actions, including those required to address performance issues, have resulted in increased costs due to accelerated fuel amortization and/or increased outage costs and could continue to do so. It is difficult to predict the total cost of these remediation procedures.

 

Life extensions. Generation’s nuclear facilities are currently operating under 40-year Nuclear Regulatory Commission (NRC) licenses. Generation has applied for 20-year extensions for the licenses that will be expiring in the next ten years, excluding licenses for the AmerGen facilities. We anticipate filing a request for a license extension for Oyster Creek and are evaluating the other AmerGen facilities for possible extension. Generation has received a 20-year extension of the license for the Peach Bottom units, but Generation cannot predict whether any of the other pending extensions will be granted. Generation intends to evaluate opportunities, as permitted by the NRC, to apply for life extensions to some or all of the remaining licenses. If the extensions are granted, Generation cannot be sure that it will be willing to operate the facilities for all or any portion of the extended license. If the NRC does not extend the operating licenses for Generation’s nuclear stations, our results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning payments.

 

Regulatory risk. The NRC may modify, suspend or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and significantly affect our results of operation or financial position. Events at nuclear plants owned by others, as well as those owned by Generation, may cause the NRC to initiate such actions.

 

Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners.

 

Nuclear accident risk. Although the safety record of nuclear reactors, including Generation’s, generally has been very good, accidents and other unforeseen problems have occurred both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident may exceed our resources, including insurance coverages, and significantly affect our results of operation or financial position.

 

Nuclear liability insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The limit as of January 1, 2004 is $10.9 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, we carry the maximum available amount of nuclear liability insurance (currently $300 million for each operating site). Claims exceeding that amount are covered through mandatory participation in a financial protection pool. 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 expiration of the Price-Anderson Act

 

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are affected. Existing commercial 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.

 

Decommissioning. Generation has an obligation to decommission its nuclear power plants. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, other than AmerGen facilities, the ICC permits ComEd, and the PUC permits PECO, to collect from their customers and deposit in nuclear decommissioning trust funds maintained by Generation amounts which, together with earnings thereon, will be used to decommission such nuclear facilities. The ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004, and, depending upon the portion of the output of certain generating stations taken by ComEd, up to $73 million annually in 2005 and 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. Effective January 1, 2004, PECO will be permitted to recover $33 million annually for nuclear decommissioning. We expect that these collections will continue through the operating license life of each of the former PECO units, with adjustments every five years to reflect changes in cost estimates and decommissioning trust fund performance. Decommissioning expenditures are expected to occur primarily after the plants are retired and are currently estimated to begin in 2029 for plants currently in operation. To fund future decommissioning costs, Generation held $4.7 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2003.

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. Generation is required to provide to the NRC a biennial report by unit (annually for Generation’s four retired units) addressing Generation’s ability to meet the NRC estimated funding levels (NRC Funding Levels) with scheduled contributions to and earnings on the decommissioning trust funds. As of December 31, 2003, Generation had a number of units, which, at current market levels, are being funded at a rate less than anticipated with respect to the NRC’s Funding Levels. Generation will submit its next biennial report to the NRC at the end of March 2005. At that time, Generation will address potential actions, in accordance with NRC requirements, to assure that Generation will remain adequately funded compared to the NRC Funding Levels.

In 2003, the General Accounting Office (GAO) published a study on the NRC’s need for more effective analyses to ensure the adequate accumulation of funds to decommission nuclear power plants in the United States. As it has in the past, the GAO concluded that accumulated and future proposed funding was inadequate to achieve NRC Funding Levels at a number of U.S. nuclear plants, including a number of Generation’s plants. Generation has reviewed the GAO’s report and believes that, in reaching its conclusions, the GAO did not consider all aspects of Generation’s decommissioning strategy, such as fund growth during the decommissioning period. The inclusion of estimated earnings growth on Generation’s nuclear trust funds during the decommissioning period virtually eliminates any funding shortfalls identified in the GAO report.

In spite of any temporary shortfall in NRC Funding Levels, Generation currently believes that the amounts in nuclear decommissioning trust funds and future collections from ratepayers, together with earnings thereon, will provide adequate funding to decommission its nuclear facilities in accordance with regulatory requirements. Forecasting investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from our current estimates. Ultimately, when decommissioning activities are initiated, if the investments held by Generation’s nuclear decommissioning trusts are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to identify other means of funding its decommissioning obligations.

 

Generation relies on electric transmission facilities that it does not own or control. If operations at these facilities are disrupted or do not provide Generation with adequate transmission capacity, it may not be able to deliver its wholesale electric power to the purchasers of the power.

Generation depends on transmission facilities owned and operated by other companies, including ComEd and PECO, to deliver the power that it sells at wholesale. If transmission at these facilities is disrupted, or transmission capacity is inadequate, Generation may not be able to sell and deliver its wholesale power. While Generation was not significantly affected by the failure in the transmission grid that served a large portion of the Northeastern United States and Canada during the August Blackout, the North American transmission grid is highly interconnected and, in extraordinary circumstances, disruptions at a point within the grid can cause a systemic response that results in an extensive power outage. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. In addition, if restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

 

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The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

 

Generation is directly affected by price fluctuations and other risks of the wholesale power market.

Generation fulfills its energy commitments from the output of the generating facilities that it owns as well as through buying electricity in both the wholesale bilateral and spot markets. The excess or deficiency of energy owned or controlled by Generation compared to its obligations exposes Generation to the risks of rising and falling prices in those markets, and Generation’s cash flows may vary accordingly. Generation’s cash flows from its generation portfolio that is not used to meet its commitments to ComEd and PECO are largely dependent on wholesale prices of electricity and Generation’s ability to successfully market energy, capacity and ancillary services. In the event that lower wholesale prices of electricity reduce Generation’s current or forecasted cash flows, the carrying value of Generation’s generating units may be determined to be impaired and Generation would be required to incur an impairment loss.

The wholesale spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. Many times, the next unit of electricity supplied would be supplied from generating stations fueled by fossil fuels, primarily natural gas. Consequently, the open-market wholesale price of electricity may reflect the cost of natural gas plus the cost to convert natural gas to electricity. Therefore, changes in the supply and cost of natural gas generally impact the open market wholesale price of electricity.

 

Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or energy will not perform their obligations. For example, energy supplied by third-party generators, including Sithe, under long-term agreements represents a significant portion of Generation’s overall capacity. These generators face operational risks, such as those that Generation faces, and their ability to perform depends on their financial condition. In the event the counterparties to these arrangements fail to perform, Generation might be forced to purchase or sell power in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to the risks of whatever default mechanisms exist in that market, some of which attempt to spread the risk across all participants, which may or may not be an effective way of lessening the severity of the risk and the amounts at stake. We are also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties.

In order to evaluate the viability of Generation’s counterparties, Generation has implemented credit risk management procedures designed to mitigate the risks associated with these transactions. These policies include counterparty credit limits and, in some cases, require deposits or letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties. These agreements reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

 

Immature Markets. The wholesale spot markets are new and evolving markets that vary from region to region and are still developing practices and procedures. While the FERC has proposed initiatives to standardize wholesale spot markets, we cannot predict whether that effort will be successful, what form any of these markets will eventually take or what roles we will play in them. Problems in or the failure of any of these markets, as was experienced in California in 2000, could adversely affect our business.

 

Hedging. The Power Team buys and sells energy and other products in the wholesale markets and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolios. This activity, along with the effects of any specialized accounting for trading contracts, may cause volatility in our future results of operations.

 

Weather. Generation’s operations are affected by weather, which affects demand for electricity as well as operating conditions. Generation plans its business based upon normal weather assumptions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation may require greater resources to meet its contractual requirements to ComEd and PECO. Extreme summer conditions or storms may affect the availability of generation capacity and transmission, limiting Generation’s ability to source or send power to where it is sold. These

 

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conditions, which may not have been fully anticipated, may have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when those markets are weak. Generation incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet summer loads at levels representative of warmer-than-normal weather conditions.

 

Excess capacity. Energy prices are also affected by the amount of supply available in a region. In the markets where Generation sells power, there has been a significant increase in the number of new power plants commencing commercial operations which has driven down power prices over the last few years. In fact, an excess supply situation currently exists in many parts of the country which has reduced prices in the wholesale markets and adversely affected Generation’s profitability. We cannot predict when these regions will return to more normal levels in the supply-demand balance.

 

Generation’s business is also affected by the restructuring of the energy industry.

Regional Transmission Organizations and Standard Market Platform. Generation is dependent on wholesale energy markets and open transmission access and rights by which Generation delivers power to its wholesale customers, including ComEd and PECO. Generation uses the wholesale regional energy markets to sell power that Generation does not need to satisfy its long-term contractual obligations, to meet long-term obligations not provided by its own resources and to take advantage of price opportunities.

Wholesale markets have only been implemented in certain areas of the country and each market has unique features which may create trading barriers among the markets. The FERC has proposed initiatives, including FERC Order No. 2000 and the proposed wholesale market platform rule, to encourage the development of large regional, uniform markets and to eliminate trade barriers. These initiatives, however, have not yet led to the development of such markets in all areas of the country. PJM’s and the New England markets strongly resemble the FERC’s proposal, and the New York Independent System Operator (ISO) is implementing market reforms. We support the development of standardized energy markets and the FERC’s standardization efforts as being essential to wholesale competition in the energy industry and to Generation’s ability to compete on a national basis and to meet its long-term contractual commitments efficiently.

Approximately 27% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the region encompassed by PJM. If the PJM market is expanded to the Midwest, 79% of Generation’s generating resources would be located within that market. The PJM market has been the most successful and liquid regional market. Our future results of operations may be affected by the successful expansion of that market to the Midwest and the implementation of any market changes mandated by the FERC.

 

Provider of Last Resort. As discussed above, ComEd and PECO each have POLR obligations that they have effectively transferred to Generation through full-requirements contracts. Because the choice of electricity generation supplier lies with the customer, planning to meet these obligations has a higher level of uncertainty than that traditionally experienced due to weather and the economy. It is difficult for Generation to plan the energy demand of ComEd and PECO customers. The uncertainty regarding the amount of ComEd and PECO load for which Generation must prepare increases our costs and may limit our sales opportunities. A significant under-estimation of the electric-load requirements of ComEd and PECO could result in Generation not having enough power to cover its supply obligation, in which case Generation would be required to buy power from third parties or in the spot markets at prevailing market prices. Those prices may not be as favorable or as manageable as Generation’s long-term supply expenses and thus could increase our total costs.

 

Effective management of capital projects is important to Generation’s business.

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. The inability of Generation to effectively manage its capital projects could adversely affect our results from operations.

In 2002, Generation purchased the assets of Sithe New England Holdings, LLC (now known as Exelon New England), a subsidiary of Sithe, and related power marketing operations. Due to the reduction in power prices and delays in construction completion, in July 2003, we commenced the process of an orderly transition out of the ownership of the Boston Generating assets.

We recorded an impairment charge of $945 million before income taxes related to the long-lived assets of Boston Generating as a result of our decision to exit these facilities. Charges could result from decisions to exit other investments or projects in the future. These charges could have a significant impact on our results of operations.

 

The interaction between our energy delivery and generation businesses provides us a partial hedge of wholesale energy market prices.

The price of power purchased and sold in the open wholesale energy markets can vary significantly in response to market conditions. The amounts of power that Generation provides

 

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to ComEd and PECO vary from month to month; however, delivery requirements are generally highest in the summer when wholesale power prices are also generally highest. Therefore, energy committed by Generation to serve ComEd and PECO customers is not exposed to the price uncertainty of the open wholesale energy market. Generally, between 60% and 70% of our generation supply serves ComEd and PECO customers. Consequently, we have limited our earnings exposure from the volatility of the wholesale energy market to the energy generated in excess of the ComEd and PECO requirements, as well as any other contracted longer term obligations.

 

Our financial performance depends on our ability to respond to competition in the energy industry.

As a result of industry restructuring, numerous generation companies created by the disaggregation of vertically integrated utilities have become active in the wholesale power generation business. In addition, independent power producers (IPP) have become prevalent in the wholesale power industry. In recent years, IPPs and the generation companies of disaggregated utilities have installed new generating capacity at a pace greater than the growth of electricity demand. These new generating facilities may be more efficient than our facilities. The introduction of new technologies could increase competition, which could lower prices and have an adverse effect on our results of operations or financial condition. Our financial performance depends on our ability to respond to competition in the energy industry.

 

Power Team’s risk management policies cannot fully eliminate the risk associated with its power trading activities.

Power Team’s power trading (including fuel procurement and power marketing) activities expose us to risks of commodity price movements. We attempt to manage our exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not always be followed or may not work as planned and cannot eliminate the risks associated with these activities. Even when our policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be wrong or inaccurate. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, we cannot predict the impact that our power trading and risk management decisions may have on our business, operating results or financial position.

 

Our results of operations may be affected by our ability to strategically divest certain businesses.

We are actively pursuing opportunities to dispose of businesses, such as our investment in Sithe, which are either unprofitable or do not advance our strategic goals. We may incur significant costs in divesting these businesses. We also may be unable to successfully implement our divestiture strategy of certain businesses for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for the transactions. The inability to divest certain businesses could negatively affect our results of operations. In addition, the amounts that we may realize from a divestiture are subject to fluctuating market conditions that may contribute to pricing and other terms that may be materially different than expected and could result in losses on sales.

 

Enterprises

 

Enterprises is focused on maximizing the earnings and cash flows of its investments and is not currently contemplating any acquisitions. Enterprises expects to continue to divest businesses that are not consistent with our strategic direction. This does not necessarily mean an immediate exit from all Enterprises’ businesses, but rather, we may retain businesses for a period of time if we believe that this course of action will increase their value.

 

Enterprises’ results of operations may be affected by its ability to strategically divest certain businesses.

Enterprises may be unable to successfully implement its divestiture strategy of certain businesses for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for transactions. In addition, the amount that Enterprises may realize from a divestiture is subject to fluctuating market conditions that may contribute to pricing and other terms that may be materially different than expected and could result in losses on sales. Enterprises also faces risks in managing these businesses prior to their divestitures due to potential turnover of key employees and operating the businesses through their transition.

 

Enterprises may incur further impairment charges.

Enterprises recorded impairment charges totaling $140 million during 2003 associated with investments, goodwill and other assets.

At December 31, 2003, Enterprises had total assets of $831 million, of which $214 million are under contract to be sold in 2004. Enterprises may incur further impairment charges in connection with the ultimate disposition of these assets.

 

Enterprises’ results of operations may be affected by its ability to manage its projects.

Enterprises includes certain businesses that utilize long-term fixed-price contracts. At the beginning of the contract,

 

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we estimate the total costs and profits of the contract; if the actual costs vary significantly from the estimates, our results of operations will be adversely affected. Along with our ability to manage our projects, results may also be affected by economic conditions, weather conditions, the inability to attract and retain qualified management due to planned divestiture of these businesses and the regulatory environment. In connection with the sale or wind down of certain businesses of Enterprises in 2003, Enterprises has retained risk of loss for certain long-term fixed-price contracts that have been subcontracted to third parties. If unanticipated losses are incurred on these contracts in future periods, our results of operations may be adversely affected.

 

General Business

 

Our financial performance will be affected by our ability to achieve the targeted cash savings under The Exelon Way business model.

We have begun to implement The Exelon Way business model, which is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Our targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. We have incurred and are considering whether there are additional expenses, including employee severance costs, associated with reaching these annual cash savings levels. Our targeted annual cash savings do not reflect any expenses that may be incurred in future periods. Our inability to realize these annual cash savings levels in the targeted timeframes could adversely affect our future financial performance.

 

Our results of operations are affected by inflation.

Inflation affects us through increased operating costs and increased capital costs for plant and equipment. As a result of the rate freezes and caps under which our Energy Delivery businesses operate and price pressures due to competition, we may not be able to pass the costs of inflation through to our customers.

 

Market performance affects our decommissioning trust funds and benefit plan asset values.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy our future obligations under our pension and postretirement benefit plans and to decommission our nuclear generation plants. We have significant obligations in these areas and hold significant assets in these trusts. A decline in the market value of those assets, as was experienced from 2000 to 2002, may increase our funding requirements of these obligations.

 

Regulations imposed by the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935 affect our business operations.

We are subject to regulation by the Securities and Exchange Commission (SEC) under PUHCA as a result of our ownership of ComEd and PECO. That regulation affects our ability to:

 

– diversify, by generally restricting our investments to traditional electric and gas utility businesses and related businesses;
– issue securities, by requiring the prior approval of the SEC and for ComEd and PECO, requiring the approval of state regulatory commissions;
– engage in transactions among our affiliates without the SEC’s prior approval and, then, only at cost, since the PUHCA regulates business between affiliates in a utility holding company system; and
– make dividend payments in specified situations.

 

Our financial performance is affected by increasing costs associated with additional security measures and obtaining adequate liability insurance.

Security. We do not know the impact that future terrorist attacks or threats of terrorism may have on our industry in general and on us in particular. We have initiated security measures to safeguard our employees and critical operations from threats of terrorism and are actively participating in industry initiatives to identify methods to maintain the reliability of our energy production and delivery systems. We fully expect to meet or exceed all NRC-mandated measures on or before the dates specified by requirements promulgated in 2003. These requirements will necessitate additional security expenditures in 2004. Additionally, we are in full compliance with all pre-2003 NRC security measures. On a continuing basis, we are evaluating enhanced security measures at certain critical locations, enhanced response and recovery plans and assessing long-term design changes and redundancy measures. 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 expense to develop and implement but will provide increased assurances as to our ability to continue to operate under difficult times.

The electric and gas industries have also developed additional security guidelines as the result of various terrorist attacks or threats of terrorism. The electric industry, through the North American Electric Reliability Council, developed physical security guidelines, which were accepted by the U.S. Department of Energy. In 2003, the FERC issued minimum

 

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standards to safeguard the electric grid system control. These standards are expected to be effective in 2004 and fully implemented by January 2005. The gas industry, through the American Gas Association, developed physical security guidelines that were accepted by the U.S. Department of Transportation. We participated in the development of these guidelines and are using them as a model for our security program.

 

Insurance. In addition to nuclear liability insurance, we also carry property damage and liability insurance for our properties and operations. As a result of significant changes in the insurance marketplace, due in part to terrorist acts, the available coverage and limits may be less than the amount of insurance obtained in the past, and the recovery for losses due to terrorist acts may be limited. We are self- insured for deductibles and to the extent that any losses may exceed the amount of insurance maintained.

A claim that exceeds the amounts available under our property damage and liability insurance, together with the deductible, would negatively affect our results of operations. Nuclear Electric Insurance Limited (NEIL), a mutual insurance company to which we belong, provides property and business interruption insurance for our nuclear operations. In recent years, NEIL has made distributions to its members. Our distribution for 2003 was $32 million, which was recorded as a reduction to operating and maintenance expenses in our Consolidated Statement of Income. We cannot predict the level of future distributions or if they will continue at all.

 

We may incur substantial costs to fulfill our obligations related to environmental matters.

Our businesses are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which we conduct our operations and make our capital expenditures. These regulations affect how we handle air and water emissions and solid waste disposal and are an important aspect of our operations. In addition, we are subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances we generate. We believe that we have a responsible environmental management and compliance program; however, we have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with manufactured gas plant operations conducted by predecessor companies will be one component of such costs. Also, we are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

 

As of December 31, 2003, our reserve for environmental investigation and remediation costs was $129 million, exclusive of decommissioning liabilities. We have accrued and will continue to accrue amounts that we believe are prudent to cover these environmental liabilities, but we cannot predict with any certainty whether these amounts will be sufficient to cover our environmental liabilities. We cannot predict whether we will incur other significant liabilities for any additional investigation and remediation costs at additional sites not currently identified by us, environmental agencies or others, or whether such costs will be recoverable from third parties.

 

Taxation has a significant impact on our results of operations.

Tax reserves and the recoverability of our deferred tax assets. We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes and ongoing appeals related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that we have taken. We must also assess our ability to generate capital gains in future periods to realize tax benefits associated with capital losses 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. As of December 31, 2003, we have not recorded an allowance against our deferred tax assets associated with impairment losses which will become capital losses when realized for income tax purposes. We believe these deferred tax assets will be realized in future periods. The ultimate outcome of such matters could result in adjustments to our consolidated financial statements and such adjustments could be material.

 

Increases in state income taxes. Due to the revenue needs of the states in which we operate, various state income tax and fee increases have been proposed or are being contemplated. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. If enacted, these changes could increase our state income tax expense and could have a negative impact on our results of operations and cash flows.

 

The introduction of new technologies could increase competition within our markets.

While demand for electricity is generally increasing throughout the United States, the rate of construction and develop -

 

17

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

ment of new, more efficient, electric generating facilities and distribution methodologies may exceed increases in demand in some regional electric markets. The introduction of new technologies could increase competition, which could lower prices and have an adverse effect on our results of operations or financial condition.

 

We may make acquisitions that do not achieve the intended financial results.

We continue to opportunistically pursue investments that fit our strategic objectives and improve our financial performance. Our future performance will depend in part upon a variety of factors related to these investments, including our ability to successfully integrate them into existing operations. These new investments, as well as our existing investments, may not achieve the financial performance that we anticipate.

 

RESULTS OF OPERATIONS

 

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

Exelon Corporation   2003     2002     Variance     % Change

Operating revenues

   $ 15,812     $ 14,955     $ 857     5.7%

Purchased power and fuel expense

     6,375       5,262       1,113     21.2%

Operating and maintenance expense

     5,532       4,345       1,187     27.3%

Operating income

     2,198       3,299       (1,101 )   (33.4%)

Other income and deductions

     (1,074 )     (631 )     (443 )   70.2%

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

     1,124       2,668       (1,544 )   (57.9%)

Income before cumulative effect of changes in accounting principles

     793       1,670       (877 )   (52.5%)

Net income

     905       1,440       (535 )   (37.2%)

Diluted earnings per share

     2.75       4.44       (1.69 )   (38.1%)
 
  

 

Net Income. Net income for 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143, “Asset Retirement Obligations” (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 the 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 83,565 GWhs in 2002 to 107,267 GWhs in 2003, and the average revenue per MWh on Generation’s market sales, excluding the trading portfolio, increased from $31.01 in 2002 to $35.99 in 2003. This increase 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 retail electric supplier (ARES) or ComEd’s PPO. Enterprises also experienced a $276 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 $20.49 in 2002 to $22.79 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.

 

Operating and Maintenance Expense. Operating and maintenance expense increased in 2003 primarily due to a change in the accounting methodology for nuclear decommissioning, severance and severance-related costs associated with The Exelon Way, and increased costs at Generation associated with generating assets acquired in 2002. Partially offsetting these increases was an overall reduction in operating and maintenance expenses at 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 and operating and maintenance expense discussed above, was primarily due to an impairment charge of $945 million before income taxes recorded by Generation related to the long-lived assets of Boston Generating. Operating income was favorably affected by a decrease of $214 million in depreciation and amortization

 

18

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

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).

 

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 our consolidated financial statements.

 

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

    2003     2002     Variance     % Change

Energy Delivery

   $ 1,170     $ 1,268     $ (98 )   (7.7%)

Generation

     (241 )     387       (628 )   (162.3%)

Enterprises

     (135 )     65       (200 )   n.m.

Corporate

     (1 )     (50 )     49     (98.0%)
  
 
 
   

Total

   $ 793     $ 1,670     $ (877 )   (52.5%)
  
 
 
   
n.m. – not meaningful

 

Net Income (Loss) by Business Segment

    2003     2002     Variance     % Change

Energy Delivery

   $ 1,175     $ 1,268     $ (93 )   (7.3%)

Generation

     (133 )     400       (533 )   (133.3%)

Enterprises

     (136 )     (178 )     42     (23.6%)

Corporate

     (1 )     (50 )     49     (98.0%)
  
 
 
   

Total

   $ 905     $ 1,440     $ (535 )   (37.2%)
  
 
 
   

 

Results of Operations–Energy Delivery

Energy Delivery   2003   2002   Variance     % Change

Operating revenues

   $ 10,202   $ 10,457   $ (255 )   (2.4%)

Purchased power and fuel expense

     4,597     4,602     (5 )   (0.1%)

Operating and maintenance expense

     1,669     1,486     183     12.3%

Depreciation and amortization expense

     873     978     (105 )   (10.7%)

Taxes other than income

     440     531     (91 )   (17.1%)

Operating income

     2,623     2,860     (237 )   (8.3%)

Interest expense

     747     854     (107 )   (12.5%)

Income before income taxes and cumulative effect of a change in accounting principle

     1,888     2,033     (145 )   (7.1%)

Income before cumulative effect of a change in accounting principle

     1,170     1,268     (98 )   (7.7%)

Net income

     1,175     1,268     (93 )   (7.3%)
 
  

 

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

 

19

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

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

Energy Delivery   Electric     Gas     Total
Variance		  
  

Customer choice

   $ (167 )   $ –     $ (167 )

Weather

     (229 )     71       (158 )

Resales and other

     –       (22 )     (22 )

Rate changes and mix

     (58 )     51       (7 )

Volume

     118       (3 )     115  

Other effects

     (15 )     (1 )     (16 )

(Decrease) increase in operating revenues

   $ (351 )   $ 96     $ (255 )

 

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

 

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

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

 

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

 

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

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

 

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

 

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

 

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

Energy Delivery   Electric     Gas    

Total

Variance

  
  

Customer choice

   $ (143 )   $ –     $ (143 )

Weather

     (119 )     49       (70 )

Resales and other

     –       (28 )     (28 )

Prices

     74       39       113  

Volume

     73       6       79  

Decommissioning

     62       –       62  

Other

     (23 )     5       (18 )

(Decrease) increase in purchased power and fuel expense

   $ (76 )   $ 71     $ (5 )

 

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 ARES or ComEd’s PPO and PECO’s non-residential customers electing or being assigned to purchase energy from alternative energy suppliers.

 

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

 

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

 

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

 

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

 

Decommissioning. ComEd changed its presentation for accounting for decommissioning collections upon the adop -

 

20

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

tion of SFAS No. 143 (see Note 13 of the Notes to Consolidated Financial Statements). Decommissioning collections, which are remitted to Generation, were previously recorded as amortization expense and are recorded as purchased power expense in 2003.

 

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

 

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

Energy Delivery   Variance  
  

Severance, pension and postretirement benefit costs associated with The Exelon Way

   $ 167  

Charge recorded at ComEd in 2003 associated with a regulatory settlement (a)

     41  

Increased storm costs

     36  

Increased employee fringe benefits primarily due to increased health care costs

     23  

Decreased payroll expense due to fewer employees

     (93 )

Decreased costs associated with the initial implementation of automated meter reading services at PECO in 2002

     (13 )

Other

     22  

Increase in operating and maintenance expense

   $ 183  
   
  

 

(a) For more information regarding the settlement, see Note 4 of the Notes to Consolidated Financial Statements.

 

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

 

Taxes Other Than Income. The reduction in taxes other than income was primarily due to a reversal of real estate tax accruals recorded by PECO of $58 million during the third quarter of 2003 and a favorable settlement of coal use tax at ComEd of $25 million. See Note 19 of the Notes to Consolidated Financial Statements for further information regarding the reversal of real estate tax accruals recorded by PECO.

 

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

 

21

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Energy Delivery Operating Statistics and Revenue Detail

 

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

Retail Deliveries—(in gigawatthours (GWhs))(a)    2003    2002    Variance     % Change  
  

Bundled deliveries(b)

                       

Residential

    37,564    37,839    (275 )   (0.7% )

Small commercial & industrial

    28,165    29,971    (1,806 )   (6.0% )

Large commercial & industrial

    20,660    22,652    (1,992 )   (8.8% )

Public authorities & electric railroads

    6,022    7,332    (1,310 )   (17.9% )
   
  
  
     

Total bundled deliveries

    92,411    97,794    (5,383 )   (5.5% )
   
  
  
     

Unbundled deliveries(c)

                       

Alternative energy suppliers

                       

Residential

    900    1,971    (1,071 )   (54.3% )

Small commercial & industrial

    7,461    5,634    1,827     32.4%  

Large commercial & industrial

    10,689    7,652    3,037     39.7%  

Public authorities & electric railroads

    1,402    913    489     53.6%  
   
  
  
     
     20,452    16,170    4,282     26.5%  
   
  
  
     

PPO (ComEd only)

                       

Small commercial & industrial

    3,318    3,152    166     5.3%  

Large commercial & industrial

    4,348    5,131    (783 )   (15.3% )

Public authorities & electric railroads

    1,925    1,346    579     43.0%  
   
  
  
     
     9,591    9,629    (38 )   (0.4% )
   
  
  
     

Total unbundled deliveries

    30,043    25,799    4,244     16.5%  
   
  
  
     

Total retail deliveries

    122,454    123,593    (1,139 )   (0.9% )
   
  
  
     
(a) One gigawatthour is the equivalent of one million kilowatthours (kWh).
(b) Bundled service reflects deliveries to customers taking electric service under tariffed rates.
(c) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier or ComEd’s PPO. See Note 4 of the Notes to Consolidated Financial Statements for further discussion of ComEd’s PPO.
Electric Revenue   2003   2002   Variance     % Change  
  

Bundled revenues(a)

                          

Residential

   $ 3,715   $ 3,719   $ (4 )   (0.1% )

Small commercial & industrial

     2,421     2,601     (180 )   (6.9% )

Large commercial & industrial

     1,394     1,496     (102 )   (6.8% )

Public authorities & electric railroads

     396     456     (60 )   (13.2% )
  
 
 
     

Total bundled revenues

     7,926     8,272     (346 )   (4.2% )
  
 
 
     

Unbundled revenues(b)

                          

Alternative energy suppliers

                          

Residential

     65     145     (80 )   (55.2% )

Small commercial & industrial

     214     159     55     34.6%  

Large commercial & industrial

     196     170     26     15.3%  

Public authorities & electric railroads

     33     28     5     17.9%  
  
 
 
     
      508     502     6     1.2%  
  
 
 
     

PPO (ComEd only)

                          

Small commercial & industrial

     225     204     21     10.3%  

Large commercial & industrial

     240     278     (38 )   (13.7% )

Public authorities & electric railroads

     103     71     32     45.1%  
  
 
 
     
      568     553     15     2.7%  
  
 
 
     

Total unbundled revenues

     1,076     1,055     21     2.0%  
  
 
 
     

Total electric retail revenues

     9,002     9,327     (325 )   (3.5% )
  
 
 
     

Wholesale and miscellaneous revenue(c)

     555     581     (26 )   (4.5% )
  
 
 
     

Total electric revenue

   $ 9,557   $ 9,908   $ (351 )   (3.5% )
  
 
 
     

 

22

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

(a) Bundled 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 charge. See Note 4 of the Notes to Consolidated Financial Statements for a discussion of CTC.
(b) Unbundled revenue reflects revenue from customers electing to receive electric generation service from an alternative energy supplier or ComEd’s PPO. Revenue from customers choosing an alternative energy supplier includes a distribution charge and a CTC. Revenues from customers choosing ComEd’s PPO includes an energy charge at market rates, transmission and distribution charges, and a CTC. Transmission charges received from alternative energy suppliers are included in wholesale and miscellaneous revenue.
(c) Wholesale and miscellaneous revenues include transmission revenue, 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)    2003    2002    Variance     % Change  
  

Retail sales

      61,858      54,782      7,076     12.9%  

Transportation

      26,404      30,763      (4,359 )   (14.2% )
   
  
  
     

Total

      88,262      85,545      2,717     3.2%  
   
  
  
     
Revenue    2003    2002    Variance     % Change  
  

Retail sales

    $ 609    $ 490    $ 119     24.3%  

Transportation

      18      19      (1 )   (5.3% )

Resales and other

      18      40      (22 )   (55.0% )
   
  
  
     

Total

    $ 645    $ 549    $ 96     17.5%  
   
  
  
     

 

Results of Operations–Generation

Generation    2003      2002    Variance      % Change  
  

Operating revenues

    $ 8,135      $ 6,858    $ 1,277      18.6%  

Purchased power and fuel expense

      5,120        4,253      867      20.4%  

Operating and maintenance expense(a)

      2,890        1,656      1,234      74.5%  

Depreciation and amortization expense

      199        276      (77 )    (27.9% )

Operating income (loss)

      (194 )      509      (703 )    (138.1% )

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

      (420 )      604      (1,024 )    (169.5% )

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

      (241 )      387      (628 )    (162.3% )

Net income (loss)

      (133 )      400      (533 )    (133.3% )
   
  

 

(a) Includes an impairment charge of $945 million before income taxes related to the long-lived assets of Boston Generating.

 

Net Income (Loss). The decrease in Generation’s net income in 2003 as compared to 2002 was primarily due to an impairment charge of $945 million before income taxes recorded in 2003 related to the long-lived assets of Boston Generating, impairment and other transaction-related charges of $280 million before income taxes recorded in 2003 related to Generation’s investment in Sithe, and increased operating and maintenance expenses, partially offset by an increase in operating revenues net of purchased power and fuel expense. Generation also experienced an increase in its effective tax rate.

Cumulative effect of changes in accounting principles recorded in 2003 and 2002 included income of $108 million, net of income taxes, recorded in 2003 related to the of adoption of SFAS No. 143 and income of $13 million, net of income taxes, recorded in 2002 related to the adoption of SFAS No. 142. See Note 1 of the Notes to Consolidated Financial Statements for further discussion of these effects.

 

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

Generation   Variance  
  

Market sales

   $ 1,270  

Trading margins

     30  

Energy Delivery and Exelon Energy Company

     (177 )

Other

     154  
   
  

Increase in operating revenues

   $ 1,277  
   
  

 

Market Sales. Sales volume in the wholesale spot and bilateral markets increased primarily due to the acquisition of Exelon New England in November 2002 and the commencement of commercial operations in 2003 of the Boston Generating facilities, Mystic 8 and 9 and Fore River. In addition, average market prices were $5/MWh higher than 2002.

 

Trading Margins. Trading activity increased revenue by $1 million in 2003 compared to a reduction in revenue of $29 million in 2002 due to an increase in gas prices in April 2002, which negatively affected Generation’s trading positions.

 

23

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Energy Delivery and Exelon Energy Company. Sales to affiliates decreased primarily due to lower volume sales to ComEd, offset by slightly higher prices. Sales to PECO were lower, primarily due to lower prices, offset slightly by higher volumes. Sales to Exelon Energy Company decreased primarily due to the discontinuance of Exelon Energy Company operations in the PJM region.

 

Other. Revenues also increased in 2003 as compared to 2002, as a result of a $76 million increase in sales of excess fossil fuel. The increased excess fossil fuel is a result of generating plants in the Texas and New England regions operating at less than projected levels. Also, revenue increased by $62 million due to higher decommissioning revenue received from ComEd in 2003 compared to 2002.

 

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

Generation   Variance

Exelon New England

   $ 429

Prices

     350

Volume

     46

Hedging activity

     22

Other

     20
 
  

Increase in purchased power and fuel expense

   $ 867
 
  

 

Exelon New England. Generation acquired Exelon New England in November 2002 and Mystic units 8 and 9 began commercial operations during the second quarter of 2003, and Fore River began commercial operations during the third quarter of 2003.

 

Prices. The increase reflects higher market prices in 2003.

 

Volume. Purchased power increased in 2003 due to an increase in purchased power from AmerGen under a June 2003 PPA to purchase 100% of the output of Oyster Creek. Prior to the June 2003 PPA, Generation did not purchase power from Oyster Creek. Fuel expense increased due to increases in fossil fuel generation required to meet the increased market demand for energy and the acquisition of generating plants in Texas in April 2002.

 

Hedging Activity. Mark-to-market losses on hedging activities were $16 million in 2003 compared to a gain of $6 million in 2002.

 

Other. Other increases in purchased power and fuel were primarily due to additional nuclear fuel amortization of $16 million in 2003 resulting from under-performing fuel which was completely replaced in May 2003, at the Quad Cities Unit 1, and $10 million due to the writedown of coal inventory in 2003 as a result of a fuel burn analysis.

 

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

 

Generation   Variance  
  

2003 asset impairment charge related to long-lived assets of Boston Generating

   $ 945  

Adoption of SFAS No. 143(a)

     197  

Increased costs due to generating asset acquisitions made in 2002

     78  

Severance, pension and postretirement benefit costs associated with The Exelon Way

     60  

Increased employee fringe benefits primarily due to increased health care costs

     54  

Decreased refueling outage costs(b)

     (49 )

2002 executive severance

     (19 )

Other

     (32 )
   
  

Increase in operating and maintenance expense

   $ 1,234  
   
  

 

(a) Due to a reclassification of decommissioning-related expenses upon the adoption of SFAS No. 143.
(b) Includes cost savings of $19 million related to one of Generation’s co-owned facilities. Refueling outage days, not including Generation’s co-owned facilities, decreased from 202 in 2002 to 157 in 2003.

 

Depreciation and Amortization. The decrease in depreciation and amortization expense in 2003 as compared to 2002 was primarily attributable to a $130 million reduction in decommissioning expense net of ARC depreciation, as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143 and a $12 million decrease due to life extensions of assets acquired in 2002. The decrease was partially offset by $65 million of additional depreciation expense on capital additions placed in service in 2002, of which $18 million of expense is related to plant acquisitions made after the third quarter of 2002.

 

Effective Income Tax Rate. The effective income tax rate was 42.6% for 2003 compared to 35.9% for 2002. This increase was primarily attributable to the impairments recorded in 2003 related to the long-lived assets of Boston Generating and Generation’s investment in Sithe which resulted in a pre-tax loss. Other adjustments that affected income taxes include a decrease in tax-exempt interest recorded in 2003 and an increase in nuclear decommissioning investment income for 2003.

 

Generation Operating Statistics

 

Generation’s sales and the supply of these sales, excluding the trading portfolio, were as follows:

Sales (in GWhs)   2003   2002   % Change

Energy Delivery and Exelon Energy Company

   117,405   123,975   (5.3%)

Market sales

   107,267   83,565   28.4%
  
   

Total sales

   224,672   207,540   8.3%
  
 
   
Supply of Sales (in GWhs)   2003   2002   % Change

Nuclear generation(a)

   117,502   115,854   1.4%

Purchases–non-trading portfolio(b)

   82,860   78,710   5.3%

Fossil and hydroelectric generation

   24,310   12,976   87.3%
  
 
   

Total supply

   224,672   207,540   8.3%
  
 
   

 

(a) Excluding AmerGen.
(b) Including purchased power agreements with AmerGen.

 

24

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Trading volumes of 32,584 GWhs and 69,933 GWhs for 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2003, which are set by the Risk Management Committee (RMC) and approved by the Exelon Board of Directors.

Generation’s average revenue for the years ended December 31, 2003 and 2002 were as follows:

($/MWh)(a)   2003   2002   % Change

Average revenue

                

Energy Delivery and Exelon Energy Company

   $ 34.38   $ 33.98   1.2%

Market sales

     35.99     31.01   16.1%

Total–excluding the trading portfolio

     35.15     32.78   7.2%

 

(a) One megawatthour (MWh) is the equivalent of one thousand kWhs.
    2003     2002

Nuclear fleet capacity factor(a)

     93.4 %     92.7%

Nuclear fleet production cost per MWh(a)

   $ 12.53     $ 13.00

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

   $ 43.29     $ 41.85

 

(a) Including AmerGen and excluding Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G).
(b) Including PPAs with AmerGen.

 

Generation’s supply mix changed as a result of:

 

– increased nuclear generation due to a lower number of refueling and unplanned outages during 2003 as compared to 2002,
– increased fossil generation due to the Exelon New England plants acquired in November 2002, including plants under construction which became operational in the second and third quarters of 2003 and account for an increase of 8,426 GWhs, and
– additional purchase power of 3,320 GWhs from the addition of Exelon New England, a new PPA with AmerGen which increased purchased power by 3,049 GWhs in the second quarter of 2003, as well as 11,989 GWhs of other miscellaneous power purchases which more than offset a 14,208 GWh reduction in purchased power from Midwest Generation.

 

The higher nuclear capacity factor and decreased production costs are primarily due to 56 fewer planned refueling outage days, resulting in a $36 million decrease in refueling outage costs, including a $6 million decrease related to AmerGen, in 2003 as compared to 2002. The years ended December 31, 2003 and 2002 included 30 and 26 unplanned outages, respectively, resulting in a $2 million increase in non-refueling outage costs in 2003 as compared to 2002.

 

Results of Operations–Enterprises

Enterprises   2003     2002     Variance     % Change

Operating revenues

   $ 1,757     $ 2,033     $ (276 )   (13.6%)

Purchased power and fuel expense

     834       658       176     26.7%

Operating and maintenance expense

     1,047       1,327       (280 )   (21.1%)

Operating income (loss)

     (162 )     (14 )     (148 )   n.m.

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

     (216 )     134       (350 )   n.m.

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

     (135 )     65       (200 )   n.m.

Net income (loss)

     (136 )     (178 )     42     (23.6%)

 

n.m.—not meaningful.

 

Net Income (Loss). The decrease in Enterprises’ net income (loss) before cumulative effect of changes in accounting principles in 2003 was primarily due to a decrease in operating revenues and an increase in purchased power and fuel expense, partially offset by a decrease in operating and maintenance expense. Depreciation and amortization expense decreased $29 million before income taxes from 2002 to 2003 primarily as a result of property, plant and equipment classified as held for sale in 2003 and accelerated asset depreciation in the PJM region in 2002. In 2003, Enterprises recorded impairment charges of investments of $46 million before income taxes due to other-than-temporary declines

in value and an impairment charge of $8 million before income taxes for its equity method investment in a district cooling business joint venture, partially offset by 2002 charges for impairment of investments of $41 million before income taxes and a net impairment of other assets of $4 million before income taxes. In 2002, Enterprises recorded a pre-tax gain of $198 million on the sale of its investment in AT&T Wireless. The adoption of SFAS No. 143 reduced 2003 net income by $1 million, net of income taxes. The adoption of SFAS No. 142 reduced 2002 net income by $243 million, net of income taxes. See Note 1 of the Notes to Consolidated Financial Statements for further discussion of the adoptions of SFAS No. 143 and SFAS No. 142.

 

25

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

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

Enterprises   Variance

InfraSource

   $ (359)

Exelon Services

     (60)

Exelon Energy Company

     137

Other

     6
  

Decrease in operating revenues

   $ (276)
  

 

InfraSource. Operating revenues decreased $256 million at InfraSource due to the sale of the majority of the InfraSource businesses in the third quarter of 2003. For the remaining InfraSource businesses, operating revenues decreased $103 million as a result of the closing of certain businesses and the reduction of new business as a result of wind-down efforts and margin deterioration for these businesses.

 

Exelon Services. Operating revenues decreased $79 million at Exelon Services due to poor economic conditions in the construction market. This decrease was partially offset by improved performance contracting activities of $19 million.

 

Exelon Energy Company. Operating revenues increased $97 million at Exelon Energy Company due to higher gas prices in 2003. In addition, customer growth in the gas and electric markets increased operating revenues by $69 million and $40 million, respectively. These increases were partially offset by the discontinuance of retail sales in the PJM region of $40 million and the wind-down of the Northeast operations of $29 million.

 

Purchased Power and Fuel Expense. Purchased power and fuel expense increased primarily due to increased fuel costs at Exelon Energy Company due to higher gas prices and increased customer volume. Higher gas prices accounted for $92 million of the overall increase and increases in customer growth in the gas and electric markets accounted for $67 million and $35 million, respectively. In addition, purchased power and fuel expense increased $31 million from the impact of mark-to-market accounting. These increases were partially offset by reduced costs from the discontinuance of retail sales in the PJM region of $46 million and the wind-down of the Northeast operations of $8 million.

 

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

Enterprises   Variance

InfraSource

   $ (267)

Exelon Energy Company

     (10)

Exelon Services

     (6)

Other

     3
  

Decrease in operating and maintenance expense

   $ (280)

 

InfraSource. Operating and maintenance expense decreased $222 million at InfraSource primarily due to the sale of the majority of the InfraSource businesses in the third quarter of 2003. For the remaining InfraSource businesses, operating and maintenance expense decreased $80 million as a result of wind-down efforts for these businesses. These decreases were partially offset by increased expense of $30 million due to margin deterioration on various construction projects.

 

During 2003, Enterprises recorded a net charge to operating and maintenance expense of $4 million (before income taxes and minority interest) associated with the sale of the majority of the InfraSource businesses. Pursuant to the sales agreement, certain working capital adjustments to the purchase price will be made in 2004.

 

Exelon Energy Company. Operating and maintenance expense decreased at Exelon Energy Company primarily due to lower general and administrative costs from the discontinuance of retail sales in the PJM region and the wind-down of Northeast operations of $9 million.

 

Exelon Services. Operating and maintenance expense decreased $56 million at Exelon Services due primarily to delays on mechanical construction projects resulting from poor economic conditions in the construction market. This decrease was partially offset by additional costs from increased performance contracting activities of $13 million, a goodwill impairment charge of $24 million and other asset impairments of $15 million.

 

Effective Income Tax Rate. The effective income tax rate was 37.5% for 2003 compared to 50.4% for 2002. This decrease in the effective tax rate was primarily attributable to the AT&T Wireless sale and tax adjustments resulting from various income tax related items of $21 million during 2002.

 

26

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Year Ended December 31, 2002 Compared To Year Ended December 31, 2001

Exelon Corporation   2002     2001     Variance     % Change

Operating revenues

   $ 14,955     $ 14,918     $ 37     0.2%

Purchased power and fuel expense

     5,262       5,090       172     3.4%

Operating and maintenance expense

     4,345       4,394       (49 )   (1.1%)

Operating income

     3,299       3,362       (63 )   (1.9%)

Other income and deductions

     (631 )     (1,015 )     384     (37.8%)

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

     2,668       2,347       321     13.7%

Income before cumulative effect of changes in accounting principles

     1,670       1,416       254     17.9%

Net income

     1,440       1,428       12     0.8%

Diluted earnings per share

     4.44       4.43       0.01     0.2%
  
 
 
 

 

Net Income. Net income for 2002 reflects a $230 million after-tax charge for the cumulative effect of changes in accounting principles as a result of the adoption of SFAS No. 142, while net income for 2001 reflects $12 million of after-tax income for the cumulative effect of changes in accounting principles as a result of the adoption of SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). See Note 1 of the Notes to Consolidated Financial Statements for further information regarding the adoptions of SFAS No. 142 and SFAS No. 133.

 

Operating Revenues. Operating revenues were comparable from 2001 to 2002. Energy Delivery experienced an increase of $286 million primarily due to increases in weather normalized volumes and positive weather impacts which was partially offset by a $259 million decrease at Enterprises primarily due to the discontinuance of retail sales in the PJM region at Exelon Energy Company and lower construction revenues at Exelon Services. See further discussion of operating revenues by segment below.

 

Purchased Power and Fuel Expense. Purchased power and fuel expense increased in 2002 compared to 2001 primarily due to an increase in purchased power associated with increased power supplied by Generation. Total GWhs supplied by Generation, exclusive of trading activity, was 207,540 GWhs in 2002 compared to 196,126 GWhs in 2001. The average supply cost per MWh supplied by Generation was consistent from 2001 to 2002. See further discussion of purchased power and fuel expense by segment below.

 

Operating and Maintenance Expense. Operating and maintenance expense was consistent from 2001 to 2002. An increase in operating and maintenance expense at Generation of $128 million primarily due to increased refueling outages and generating asset acquisitions in April and November 2002 was partially offset by reduced operating maintenance expenses at Energy Delivery and Enterprises. See further discussion of operating and maintenance expenses by segment below.

 

Operating Income. Operating income decreased in 2002 as compared to 2001 primarily due to the increase in purchased power and fuel expense discussed above, partially offset by a decrease in depreciation and amortization expense primarily due to the cessation of goodwill amortization.

 

Other Income and Deductions. Other income and deductions changed primarily due a gain on the sale of Enterprises’ investment in AT&T Wireless of $198 million recorded in 2002, an increase in income on Generation’s nuclear decommissioning trust funds and a reduction in interest expense at Energy Delivery due to less debt outstanding and the refinancing of existing debt at lower rates.

 

27

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Results of Operations by Business Segment

 

The comparisons of 2002 and 2001 operating results and other statistical information set forth below reflect intercompany transactions, which are eliminated in our consolidated financial statements.

 

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

    2002     2001     Variance     % Change

Energy Delivery

   $ 1,268     $ 1,022     $ 246     24.1%

Generation

     387       512       (125 )   (24.4%)

Enterprises

     65       (85 )     150     176.5%

Corporate

     (50 )     (33 )     (17 )   (51.5%)
  
 
 
   

Total

   $ 1,670     $ 1,416     $ 254     17.9%
  
 
 
   

 

Net Income (Loss) by Business Segment

    2002     2001     Variance     % Change

Energy Delivery

   $ 1,268     $ 1,022     $ 246     24.1%

Generation

     400       524       (124 )   (23.7%)

Enterprises

     (178 )     (85 )     (93 )   (109.4%)

Corporate

     (50 )     (33 )     (17 )   (51.5%)
  
 
 
   

Total

   $ 1,440     $ 1,428     $ 12     0.8%
  
 
 
   

 

Results of Operations–Energy Delivery

Energy Delivery   2002   2001   Variance     % Change

Operating revenues

   $ 10,457   $ 10,171   $ 286     2.8%

Purchased power and fuel expense

     4,602     4,472     130     2.9%

Operating and maintenance expense

     1,486     1,568     (82 )   (5.2%)

Depreciation and amortization expense

     978     1,081     (103 )   (9.5%)

Taxes other than income

     531     457     74     16.2%

Operating income

     2,860     2,593     267     10.3%

Interest expense

     854     973     (119 )   (12.2%)

Income before income taxes

     2,033     1,725     308     17.9%

Net income

     1,268     1,022     246     24.1%
  
 
 
 

 

Net Income. The increase in Energy Delivery’s net income was primarily due to an increase in operating revenues net of purchased power and fuel expense and decreases in operating and maintenance, depreciation and amortization and interest expenses, partially offset by increased taxes other than income, lower interest income on its note receivable from Unicom Investments, Inc., an Exelon subsidiary.

 

Operating Revenues. The changes in Energy Delivery’s operating revenues for 2002 compared to 2001 consisted of the following:

Energy Delivery   Electric     Gas     Total
Variance		  
  

Volume

   $ 224     $ 15     $ 239  

Weather

     151       2       153  

Customer choice

     95       –       95  

Rate changes

     (54 )     (108 )     (162 )

Resales and other

     –       (15 )     (15 )

Other effects

     (25 )     1       (24 )
  
 
 

Increase (decrease) in operating revenues

   $ 391     $ (105 )   $ 286  
  
 
 

 

28

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Volume. Energy Delivery’s electric revenues increased as a result of increases, exclusive of weather impacts, in the number of customers and additional average usage per customer, primarily in the residential customer class.

Exclusive of weather impacts, higher delivery volume increased gas revenue. Total deliveries to customers increased 5% in 2002 compared to 2001, primarily as a result of customer growth and higher transportation volumes.

 

Weather. Energy Delivery’s electric revenues experienced favorable weather impacts, primarily as a result of warmer than usual summer weather. Cooling degree-days in the ComEd and PECO service territories were 29% higher and 15% higher in 2002 as compared to 2001, respectively. Heating degree-days in the ComEd and PECO service territories were 3% higher and 1% higher, respectively, in 2002 compared to 2001.

 

Customer Choice. Energy Delivery’s electric revenues increased from 2001 to 2002 as a result of customer choice activity. The increase includes increased revenues of $226 million from customers in Pennsylvania who selected or returned to PECO as their energy supplier. The increase was partially offset by a decrease in revenues of $131 million from ComEd’s customers electing to purchase energy from alternative energy suppliers or electing ComEd’s PPO.

 

Rate Changes. The decrease in electric revenues attributable to rate changes reflect $99 million for the 5% ComEd residential rate reduction, effective October 1, 2001, required by the Illinois restructuring legislation and the timing of a $60 million PECO rate reduction in effect for 2001 and 2002, partially offset by $50 million related to an increase in PECO’s gross receipts tax effective January 1, 2002 and the expiration of a 6% reduction in PECO’s rates during the first quarter of 2001. The decrease in gas revenues was primarily attributable to a decrease in rates through the purchased gas adjustment clause that became effective in December 2001. The average rate per mmcf in 2002 was 22% lower than the rate in 2001.

 

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

 

Other Effects. The reduction in revenue from other effects is primarily a result of a $38 million decrease in off-system sales due to an expiration of wholesale contracts that were offered by ComEd from June 2000 to May 2001 to support the open access program in Illinois and a $15 million reversal for revenue refunds in 2001 related to certain of ComEd’s municipal customers as a result of a favorable FERC ruling, partially offset by a reimbursement from Generation of $12 million at ComEd and an $11 million settlement of CTCs by a large PECO customer in the first quarter of 2001.

 

Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for 2002 compared to 2001 consisted of the following:

Energy Delivery   Electric     Gas     Variance

Weather

   $ 69     $ –     $ 69

Customer choice

     65       –       65

Volume

     54       –       54

PJM ancillary charges

     41       –       41

Prices

     18       (108 )     (90)

Other

     (15 )     6       (9)
  
 
 

Increase (decrease) in purchased power and fuel expense

   $ 232     $ (102 )   $ 130
  
 
 

 

Weather. Energy Delivery’s purchased power and fuel expense increased in 2002 compared to 2001 due to the impacts of warmer than usual summer weather.

 

Customer Choice. Customer choice activity resulted in an increase of purchased power and fuel expense, including $210 million due to customers selecting or returning to PECO as their electric supplier, partially offset by $145 million due to ComEd’s customers electing to purchase energy from alternative energy suppliers or electing ComEd’s PPO.

 

Volume. Energy Delivery’s purchased power and fuel expense increased due to increases, exclusive of weather impacts, in the number of customers and additional average usage per customer, primarily in the residential customer class.

 

Prices. Fuel expense for gas decreased due to PECO’s higher gas prices, which was partially offset by increases in the weighted average on-peak/off-peak cost of electricity at ComEd.

 

Operating and Maintenance Expense. The changes in operating and maintenance expense for 2002 compared to 2001 consisted of the following:

Energy Delivery   Variance  
  

Decreased employee fringe benefits primarily due to fewer employees

   $ (39 )

Decreased payroll expense due to fewer employees

     (32 )

Reduced costs due to cost management initiatives

     (16 )

Change in bad debt reserve estimate

     (14 )

Decreased storm costs

     (12 )

Increased costs for manufactured gas plant investigation and remediation

     16  

Increased costs associated with the initial implementation of automated meter reading services at PECO in 2002

     12  

Other

     3  
  

Decrease in operating and maintenance expense

   $ (82 )
  

 

Depreciation and Amortization Expense. The reduction in depreciation and amortization expense was primarily due to the cessation of goodwill amortization at ComEd and a $48

 

29

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

million decrease due to changes in ComEd’s depreciation rates in 2002. During 2001, $126 million of goodwill was amortized at ComEd. These decreases were partially offset by $34 million of increased depreciation due to capital additions across Energy Delivery and increased competitive transition charge amortization of $37 million at PECO.

 

Taxes Other Than Income. The increase in taxes other than income was primarily due to $72 million of additional gross receipts tax at PECO related to additional revenues and an increase in the gross receipts tax rate on electric revenue effective January 1, 2002.

 

Interest Expense. The reduction in interest expense was primarily due to refinancing existing debt at lower rates and the pay down of ComEd’s and PECO’s Transitional Trust Notes.

 

Effective Income Tax Rate. Energy Delivery’s effective income tax rate was 37.6% for 2002, compared to 40.8% for 2001. The decrease in the effective tax rate was primarily attributable to a reduction in state income taxes and the discontinuation of goodwill amortization as of January 1, 2002, which was not deductible for income tax purposes in 2001.

 

Energy Delivery Operating Statistics and Revenue Detail

 

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

Retail Deliveries—(in gigawatthours (GWhs))(a)   2002   2001   Variance     % Change  
  

Bundled deliveries(b)

                    

Residential

   37,839   33,355   4,484     13.4%  

Small commercial & industrial

   29,971   29,433   538     1.8%  

Large commercial & industrial

   22,652   23,265   (613 )   (2.6% )

Public authorities & electric railroads

   7,332   8,645   (1,313 )   (15.2% )
  
 
 
     

Total bundled deliveries

   97,794   94,698   3,096     3.3%  
  
 
 
     

Unbundled deliveries(c)

                    

Alternative energy suppliers

                    

Residential

   1,971   3,105   (1,134 )   (36.5% )

Small commercial & industrial

   5,634   4,471   1,163     26.0%  

Large commercial & industrial

   7,652   7,810   (158 )   (2.0% )

Public authorities & electric railroads

   913   372   541     145.4%  
  
 
 
     
    16,170   15,758   412     2.6%  
  
 
 
     

PPO (ComEd only)

                    

Small commercial & industrial

   3,152   3,279   (127 )   (3.9% )

Large commercial & industrial

   5,131   5,750   (619 )   (10.8% )

Public authorities & electric railroads

   1,346   987   359     36.4%  
  
 
 
     
    9,629   10,016   (387 )   (3.9% )
  
 
 
     

Total unbundled deliveries

   25,799   25,774   25     0.1%  
  
 
 
     

Total retail deliveries

   123,593   120,472   3,121     2.6%  
  
 
 
     

 

(a) One gigawatthour is the equivalent of one million kilowatthours (kWh).
(b) Bundled service reflects deliveries to customers taking electric service under tariffed rates.
(c) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier or ComEd’s PPO. See Note 4 of the Notes to Consolidated Financial Statements for further discussion of ComEd’s PPO.

 

30

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Electric Revenue   2002   2001   Variance     % Change

Bundled revenues(a)

                        

Residential

   $ 3,719   $ 3,336   $ 383     11.5%

Small commercial & industrial

     2,601     2,503     98     3.9%

Large commercial & industrial

     1,496     1,452     44     3.0%

Public authorities & electric railroads

     456     502     (46 )   (9.2%)
  
 
 
   

Total bundled revenues

     8,272     7,793     479     6.1%
  
 
 
   

Unbundled revenues(b)

                        

Alternative energy suppliers

                        

Residential

     145     235     (90 )   (38.3%)

Small commercial & industrial

     159     129     30     23.3%

Large commercial & industrial

     170     138     32     23.2%

Public authorities & electric railroads

     28     6     22     n.m.
  
 
 
   
      502     508     (6 )   (1.2%)
  
 
 
   

PPO (ComEd 0nly)

                        

Small commercial & industrial

     204     220     (16 )   (7.3%)

Large commercial & industrial

     278     343     (65 )   (19.0%)

Public authorities & electric railroads

     71     59     12     20.3%
  
 
 
   
      553     622     (69 )   (11.1%)
  
 
 
   

Total unbundled revenues

     1,055     1,130     (75 )   (6.6%)
  
 
 
   

Total electric retail revenues

     9,327     8,923     404     4.5%
  
 
 
   

Wholesale and miscellaneous revenue(c)

     581     594     (13 )   (2.2%)
  
 
 
   

Total electric revenue

   $ 9,908   $ 9,517   $ 391     4.1%
  
 
 
   

 

(a) Bundled 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 charge. See Note 4 of the Notes to Consolidated Financial Statements for a discussion of CTC.
(b) Unbundled revenue reflects revenue from customers electing to receive electric generation service from an alternative energy supplier or ComEd’s PPO. Revenue from customers choosing an alternative energy supplier includes a distribution charge and a CTC. Revenues from customers choosing ComEd’s PPO includes an energy charge at market rates, transmission, and distribution charges and a CTC. Transmission charges received from alternative energy suppliers are included in wholesale and miscellaneous revenue.
(c) Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.
n.m.—not meaningful

 

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

Deliveries to customers in mmcf   2002   2001   Variance     % Change

Retail sales

     54,782     54,075     707     1.3%

Transportation

     30,763     27,453     3,310     12.1%
  
 
 
   

Total

     85,545     81,528     4,017     4.9%
  
 
 
   
Revenue   2002   2001   Variance     % Change

Retail sales

   $ 490   $ 581   $ (91 )   (15.7%)

Transportation

     19     18     1     5.6%

Resale and other

     40     55     (15 )   (27.3%)
  
 
 
   

Total

   $ 549   $ 654   $ (105 )   (16.1%)
  
 
 
   

 

Results of Operations–Generation

 

In the second quarter of 2002, Generation early adopted Emerging Issues Task Force (EITF) Issue 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). EITF 02-3 was issued by the FASB EITF in June 2002 and required revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement. For comparative purposes, energy costs related to energy trading have been reclassified as revenue for prior periods to conform to the net basis of presentation required by EITF 02-3.

Generation   2002   2001   Variance     % Change

Operating revenues

   $ 6,858   $ 6,826   $ 32     0.5%

Purchased power and fuel expense

     4,253     3,995     258     6.5%

Operating and maintenance expense

     1,656     1,528     128     8.4%

Depreciation and amortization expense

     276     282     (6 )   (2.1%)

Operating income

     509     872     (363 )   (41.6%)

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

     604     839     (235 )   (28.0%)

Income before cumulative effect of changes in accounting principles

     387     512     (125 )   (24.4%)

Net income

     400     524     (124 )   (23.7%)
  
 
 
 

 

31

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Net Income. The decrease in Generation’s net income was primarily due to a decrease in operating revenues net of purchased power and fuel expense and an increase in operating and maintenance expense, partially offset by an increase in income on its nuclear decommissioning trust fund investments.

Cumulative effect of changes in accounting principles recorded in 2002 and 2001 included income of $13 million, net of income taxes, recorded in 2002 related to the adoption of SFAS No. 142, and income of $12 million, net of income taxes, recorded in 2001 related to the adoption of SFAS No. 133. See Note 1 of the Notes to Consolidated Financial Statements for further discussion of these effects.

 

Operating Revenues. The changes in Generation’s operating revenues for 2002 compared to 2001 consisted of the following:

Generation   Variance

Energy Delivery and Exelon Energy Company

   $ 124

Market sales

     (85)

Trading margins

     (36)

Other

     29
  

Increase in operating revenues

   $ 32
  

 

Energy Delivery and Exelon Energy Company. Sales to affiliates increased primarily due to higher prices. In addition, the increase was a result of higher volume sales to ComEd, offset by lower volume sales to PECO and Exelon Energy Company.

 

Market Sales. Revenue from market sales decreased primarily due to a $6/MWh decrease in average market prices in 2002 compared to 2001. The decrease was partially offset by an increase in market sales volume.

 

Trading Margins. Trading margins decreased $36 million, reflecting a $29 million loss for the year ended December 31, 2002 compared to a $7 million gain in the same period in 2001. The increase is primarily related to an increase in gas prices in April 2002, which negatively affected Generation’s trading positions.

 

Other. Revenues also increased $29 million in 2002 compared to the same period in 2001, primarily as a result of increased gas sales resulting from the Texas asset acquisition in April 2002.

 

Purchased Power and Fuel Expense. Purchased power and fuel expense increased $258 million, or 6% in 2002. The increase is primarily due to increased purchased power and fossil fuel volume. The increase in purchased power and fuel was partially offset by a decrease in the average purchased cost attributed to lower wholesale market prices and reduced transmission costs.

 

Operating and Maintenance Expense. The changes in operating and maintenance expense for 2002 compared to 2001 consisted of the following:

Generation   Variance

Increased refueling outage costs(a)

   $ 80

Increased costs due to asset acquisitions made in 2002

     21

2002 executive severance

     19

Decreased payroll expense due to fewer number of employees

     (8)

Other

     16
  

Decrease in operating and maintenance expense

   $ 128
  

 

(a) Refueling outage days, not including co-owned facilities, increased from 95 in 2001 to 202 in 2002.

 

Depreciation and Amortization. The decrease in depreciation and amortization expense in 2002 as compared to 2001 was due to a $42 million reduction in depreciation expense arising from the extension of the useful lives on certain generation facilities in 2001, partially offset by $32 million of additional depreciation expense on capital additions placed in service, including the Southeast Chicago Energy Project in July 2002, and two generating plants acquired in April 2002.

 

Effective Income Tax Rate. Generation’s effective income tax rate was 35.9% for 2002 compared to 39.0% for 2001. This decrease was primarily attributable to an increase in tax-exempt interest in 2002 and other tax benefits recorded in 2002.

 

Generation Operating Statistics

 

Generation’s sales and the supply of these sales, excluding the trading portfolio, were as follows:

Sales (in GWhs)   2002   2001   % Change

Energy Delivery and Exelon Energy Company

   123,975   123,793   0.1%

Market sales

   83,565   72,333   15.5%
  
 
   

Total sales

   207,540   196,126   5.8%
  
 
   

 

Supply of Sales (in GWhs)   2002   2001   % Change

Nuclear generation(a)

   115,854   116,839   (0.8%)

Purchases—non-trading portfolio(b)

   78,710   67,942   15.8%

Fossil and hydroelectric generation

   12,976   11,345   14.4%
  
 
   

Total supply

   207,540   196,126   5.8%
  
 
   

 

(a) Excluding AmerGen.
(b) Including purchased power agreements with AmerGen.

 

Trading volumes of 69,933 GWhs and 5,754 GWhs for 2002 and 2001, respectively, are not included in the table above.

 

32

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Generation’s average revenue per MWh sold for 2002 and 2001 were as follows:

($/MWh)   2002   2001   % Change

Average revenue

                

Energy Delivery and Exelon Energy Company

   $ 33.98   $ 33.05   2.8%

Market sales

     31.01     37.00   (16.2%)

Total—excluding the trading portfolio

     32.78     34.51   (5.0%)
  
 
 

 

The factors below contributed to the overall reduction in Generation’s average margin for 2002.

Generation’s GWh deliveries increased 6% in 2002 primarily due to favorable weather conditions, which increased demand for Energy Delivery and increased market sales attributable to the availability of increased supply from acquired generation and power uprates at existing facilities, slightly offset by a decrease in sales to Exelon Energy Company, Enterprises’ retail energy unit, due to lower demand in the eastern energy markets.

Generation’s supply mix changed due to:

 

– increased purchases resulting from the supply agreement with AmerGen’s Unit No. 1 at Three Mile Island Nuclear Station facility which was new in 2002,
– decreased nuclear generation due to an increase in the number of refueling outages during 2002, slightly offset by power uprates,
– increased fossil and hydroelectric net generation due to the acquisition of two generating plants in April, a peaking facility placed in service in July and the Sithe New England plants acquired in November, which in total accounted for an increase of 2,500 GWhs, and strong waterflows which increased the hydroelectric output by 400 GWhs, and
– lower production in our Mid-Atlantic coal and oil units due to cooler summer weather conditions and lower power prices in 2002.

 

Generation’s average revenue was affected by:

 

– increased weighted average on and off peak prices per MWh for supply agreements with ComEd,
– higher contracted prices from Exelon Energy Company, affected by lower actual volumes to those customers, and
– lower market prices.
    2002     2001

Nuclear fleet capacity factor(a)

     92.7 %     94.4%

Nuclear fleet production cost per MWh(a)

   $ 13.00     $ 12.78

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

   $ 41.85     $ 45.94
  
 

 

(a) Including AmerGen and excluding Salem, which is operated by PSE&G.
(b) Including PPAs with AmerGen.

 

The lower nuclear capacity factor and increased nuclear production costs are primarily due to 260 days of planned outage time in 2002 versus 153 days in 2001. Nuclear production cost increased from $12.78 to $13.00 primarily due to an $80 million increase in outage costs and the number of refueling outages in 2002 as compared to 2001. These decreases are slightly offset by a $25 million decrease in payroll costs due to headcount reductions and $4 million in lower project expenditures. The decrease in purchased power costs was primarily due to depressed wholesale power market prices.

 

Results of Operations–Enterprises

Enterprises   2002     2001     Variance     % Change

Operating revenues

   $ 2,033     $ 2,292     $ (259 )   (11.3%)

Purchased power and fuel expense

     658       854       (196 )   (23.0%)

Operating and maintenance expense

     1,327       1,436       (109 )   (7.6%)

Operating income (loss)

     (14 )     (77 )     63     (81.8%)

Income (loss) before income taxes and cumulative effect of change in accounting principle

     134       (128 )     262     n.m.

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

     65       (85 )     150     (176.5%)

Net income (loss)

     (178 )     (85 )     (93 )   109.4%
  
 
 
 

n.m. —not meaningful

 

Net Income (Loss). The increase in Enterprises’ income (loss) before cumulative effect of change in accounting principles was primarily due to a pre-tax gain of $198 million recorded in 2002 on the sale of its investment in AT&T Wireless and decreases in purchased power and fuel expense and operating and maintenance expense, partially offset by a decrease in operating revenues. Depreciation and amortization expense decreased $14 million from 2001 to 2002 primarily as a result of the discontinuance of goodwill amortization upon the adoption of SFAS No. 142 on January 1, 2002, partially offset by 2002 accelerated depreciation in the PJM region. In 2002, Enterprises recorded impairment charges of investments of $41 million before income taxes due to other-than- temporary declines in value and a net impairment of other assets of $4 million, as compared to 2001 charges for investment impairments of $13 million and a net impairment of other assets of $2 million before income taxes. In 2002, Enterprises had higher equity in earnings of uncon -

 

33

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

solidated affiliates of $16 million resulting from the discontinuance of losses on its investment in AT&T Wireless as a result of its sale and $9 million resulting from the recovery of trade receivables previously considered uncollectible from a communications joint venture. The adoption of SFAS No. 142 reduced 2002 net income by $243 million, net of income taxes. See Note 1 of the Notes to Consolidated Financial Statements for further discussion of the adoption of SFAS No. 142.

 

Operating Revenues. The changes in Enterprises’ operating revenues for 2002 compared to 2001 consisted of the following:

Enterprises   Variance

Exelon Energy Company

   $ (172)

Exelon Services

     (65)

InfraSource

     (20)

Other

     (2)
  

Decrease in operating revenues

   $ (259)
  

 

Exelon Energy Company. Operating revenues decreased $168 million at Exelon Energy Company due to the discontinuance of retail sales in the PJM region and lower gas prices of $112 million in 2002. These decreases were partially offset by higher electric sales of $74 million and increased customer growth in the gas market of $33 million.

 

Exelon Services. Operating revenues decreased primarily as a result of reduced construction projects.

 

InfraSource. Operating revenues decreased $117 million at InfraSource as a result of the continued decline in the telecommunications industry, partially offset by higher infrastructure and construction services of $97 million from an increase in the electric line of business.

 

Purchased Power and Fuel Expense. Purchased power and fuel expense at Exelon Energy Company decreased due to reduced costs from the discontinuance of retail sales in the PJM region of $174 million, decreased fuel costs due to lower gas prices of $115 million and $16 million from favorable impacts of mark-to-market accounting relating to Northeast operations. These decreases were partially offset by increased electric costs of $72 million and increased gas costs from customer growth of $32 million.

 

Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for 2002 compared to 2001 consisted of the following:

Enterprises   Variance

Exelon Services

   $ (57)

InfraSource

     (43)

Exelon Energy Company

     (11)

Other

     2
  

Decrease in operating and maintenance expense

   $ (109)
  

 

Exelon Services. Operating and maintenance expense decreased $51 million at Exelon Services due to lower construction costs and $2 million from general and administrative cost reduction initiatives.

 

InfraSource. Operating and maintenance expense decreased at InfraSource primarily due to lower construction costs as a result of the decline of the telecommunications industry of $80 million and $16 million from general and administrative cost reduction initiatives, partially offset by higher infrastructure and construction costs of $53 million.

 

Exelon Energy Company. Operating and maintenance expense decreased at Exelon Energy Company primarily due to lower general and administrative costs from the discontinuance of retail sales in the PJM region.

 

Effective Income Tax Rate. The effective income tax rate was 50.4% for 2002 compared to 33.3% for 2001. This increase in the effective tax rate was primarily attributable to the AT&T Wireless sale and tax adjustments resulting from various income tax related items of $21 million, partially offset by the discontinuation of goodwill amortization as of January 1, 2002, which was not deductible for income tax purposes in 2001.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Our businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from Energy Delivery and Generation’s operations. Our working capital deficit is expected to be cured with our anticipated continuance of positive operating cash flows and the eventual elimination of our Boston Generating debt balance upon the transfer of our ownership of Boston Generating. We anticipate that the transfer of Boston Generating will be accomplished on a non-cash basis. When necessary, we obtain funds from external sources in the capital markets and through bank borrowings. Our access to external financing at reasonable terms depends on our and our subsidiaries’ credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where we no longer have access to external financing sources at reasonable terms, we have access to $1.5 billion through revolving credit facilities that we currently utilize to support our commercial paper programs. See the Credit Issues section of Liquidity and Capital Resources for further discussion. We primarily use our capital resources to fund capital requirements, including construction, to invest in new and existing ventures, to repay maturing debt, to pay common stock dividends and to fund our pension obligations. Future acquisitions that we may undertake may require external financing, which might include issuing our common stock.

 

34

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

We are in the process of implementing its new business model referred to as The Exelon Way. This business model is focused on improving operating cash flows while meeting service and financial commitments through integration of operations and consolidation of support functions. We have targeted approximately $300 million of annual cash savings beginning in 2004 and increasing the annual cash savings to $600 million in 2006.

As part of the implementation of The Exelon Way, we identified approximately 1,500 positions for elimination by the end of 2004 and recorded a charge for salary continuance severance of $130 million before income taxes during 2003, which we anticipate that the majority will be paid in 2004 and 2005. We are considering whether there are additional positions to be eliminated in 2005 and 2006. We may incur further severance costs associated with The Exelon Way if additional positions are identified to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.

 

Cash Flows from Operating Activities

Energy Delivery’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the third quarter. Energy Delivery’s future cash flows will depend upon the ability to achieve cost savings in operations and the impact of the economy, weather, customer choice and future regulatory proceedings on its revenues. Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Energy Delivery and Enterprises. Generation’s future cash flows from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs.

Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements for the foreseeable future. Operating cash flows after 2006 could be negatively affected by changes in the rate regulatory environments of ComEd and PECO, although any effects are not expected to hinder our ability to fund our business requirements. See Business Outlook and the Challenges in Managing our Business for further information regarding the regulatory transition periods.

Cash flows provided by operations in 2003 and 2002 were $3.4 billion and $3.6 billion, respectively. Changes in our cash flows provided by operations are generally consistent with changes in our results of operations, and further adjusted by changes in working capital in the normal course of business.

 

In addition to the items mentioned in Results of Operations, the following items affected our operating cash flows in 2003 and 2002:

 

– Purchases of natural gas at higher prices as well as slightly increased volumes during 2003 resulted in an increase in natural gas inventories of $54 million at Generation and PECO and an increase in deferred natural gas costs of $50 million at PECO, resulting in a reduction to operating cash flows of $104 million. During 2002, changes in deferred natural gas costs of $25 million and a decrease in natural gas inventories during the year of $37 million, resulted in a $62 million increase in operating cash flows.
– Discretionary tax-deductible pension plan payments of $367 million in 2003 compared to $202 million in 2002. Additionally, we contributed $134 million and $73 million to the postretirement welfare benefit plans in 2003 and 2002, respectively.

 

We expect to contribute up to approximately $419 million to our pension plans in 2004. These contributions exclude benefit payments expected to be made directly from corporate assets. Of the $419 million expected to be contributed to the pension plans during 2004, $17 million is estimated to be needed to satisfy IRS minimum funding requirements.

 

Cash Flows from Investing Activities

Cash flows used in investing activities in 2003 and 2002 were $2.1 billion and $2.6 billion, respectively. Cash used in investing activities decreased from 2002 due to lower capital expenditures of $288 million, net of liquidated damages received during 2003 of $92 million, a reduction in cash used to acquire businesses of $173 million, a net increase over 2002 in amounts contributed into the nuclear decommissioning trust funds of $11 million and a decrease from 2002 in the proceeds from the sale of businesses in the current year of $24 million.

Capital expenditures by business segment for 2003 and projected amounts for 2004 are as follows:

    2003   2004

Energy Delivery

   $ 962   $ 855

Generation

     953     972

Enterprises

     14     1

Corporate and other

     25     35
  
 

Total capital expenditures

     1,954     1,863

Acquisition of businesses, net of cash acquired

     272     –
  
 

Total capital expenditures and acquisition of businesses

   $ 2,226   $ 1,863
  
 

 

Internally generated cash flow in 2004 is expected to meet capital requirements excluding acquisitions. Our pro -

 

35

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

posed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Investing activities in 2003 exclude the non-cash issuance of a $238 million note payable for the November 2003 investment in two synthetic fuel-producing facilities. Exelon expects this investment to provide more than $200 million of net cash benefits from 2003 through 2008, with peak net cash of approximately $80 million in 2007. The cash flow impact in 2003 was not material.

 

Energy Delivery

Energy Delivery’s estimated capital expenditures for 2004 reflect the continuation of efforts to improve the reliability of its transmission and distribution systems and capital additions to support new business and customer growth. Approximately 47% of the budgeted 2004 expenditures is for growth and the remainder is for additions to or upgrades of existing facilities. We anticipate that Energy Delivery’s capital expenditures will be funded by internally generated funds, borrowings, and the issuance of debt or preferred securities or capital contributions made by us.

 

Generation

On November 25, 2003, Generation, Reservoir, and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. See Contractual Obligations and Off-Balance Sheet Arrangements—Variable-Interest Entities below for further information regarding this transaction. In December 2003, Generation purchased the 50% interest in AmerGen held by British Energy plc for $240 million, net of cash acquired of $36 million. The acquisition was funded with cash provided by operations.

In April 2002, Generation purchased two natural-gas and oil-fired generating plants from TXU for $443 million. The purchase was funded with commercial paper, which Exelon issued and Generation repaid with cash flows from operations. Investing activities in 2002 also include the November 1, 2002 purchase of Exelon New England, which resulted in a use of cash of $2 million, net of $12 million of cash acquired. The remainder of the purchase was financed with a $534 million note payable to Sithe, which was subsequently increased to $536 million. At December 31, 2003, Generation has repaid $446 million of the note payable to Sithe, leaving a balance of $90 million, which is payable on the earlier of December 1, 2004, certain liquidity needs, or a change of control.

Generation’s capital expenditures for 2003 reflected the construction of three Boston Generating facilities with capacity of 2,288 MWs of energy, additions to and upgrades of existing facilities (including nuclear refueling outages), and nuclear fuel. During 2003, Boston Generating received $92 million of liquidated damages from Raytheon Company (Raytheon) as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with Raytheon’s construction of Boston Generating’s Mystic 8 and 9 and Fore River generating facilities. We project that Generation’s capital expenditures in 2004 will be higher than they were in 2003, and the majority of these expenditures will be used for additions and upgrades to existing facilities, nuclear fuel and increases in capacity at existing plants. Generation is planning on ten nuclear refueling outages in 2004, compared to eight during 2003. However, we project that the total capital expenditures for nuclear refueling outages will decrease in 2004 from 2003 by $18 million. We anticipate that Generation’s capital expenditures will be funded by internally generated funds, Generation’s borrowings or capital contributions from us.

 

Enterprises

In September 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource for cash of $175 million, net of transaction costs and cash transferred to the buyer upon sale. In April 2002, Enterprises sold its 49% interest in AT&T Wireless for $285 million in cash.

Enterprises’ capital expenditures were $14 million in 2003. Enterprises’ capital expenditures for 2003 were primarily for additions to or upgrades of existing facilities. We project that Enterprises’ capital expenditures for 2004 will be approximately $1 million.

 

Cash Flows from Financing Activities

Cash flows used in financing activities for the years ended December 31, 2003 and 2002 were $1.2 billion and $1.1 billion, respectively. See Note 11—Long-Term Debt of the Notes to Consolidated Financial Statements for further information regarding the 2003 debt issuances and retirements. See Note 24—Subsequent Events of the Notes to Consolidated Financial Statements for further information regarding 2004 redemptions of debt.

The 2003 cash dividend payments on common stock were $620 million as compared to $563 million in 2002. On January 28, 2003, the Exelon Board of Directors increased the quarterly dividend on Exelon’s common stock to $0.46 per share. On July 29, 2003, the Exelon Board of Directors increased the quarterly dividend to $0.50 per share. On January 27, 2004, the Exelon Board of Directors approved a 10% increase in the quarterly dividend rate to $0.55 per share and approved a 2-for-1 stock split contingent upon receipt of all required regulatory approvals. Payment of future dividends is subject to approval and declaration by the Board.

Financing activities exclude the non-cash issuance of a $534 million note to Sithe for the November 1, 2002 acqui-

 

36

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

sition of Exelon New England, which was subsequently increased to $536 million.

 

Credit Issues

 

Exelon Credit Facility

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by Exelon corporate holding company (Exelon Corporate) and by ComEd, PECO and Generation. In October 2003, Exelon, ComEd, PECO and Generation replaced their $1.5 billion bank unsecured revolving credit facility with a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit. The 364-day agreement includes a term-out option provision that allows a borrower to extend the maturity of revolving credit borrowings outstanding at the end of the 364-day period for one year.

At December 31, 2003, aggregate sublimits under the credit agreements were $1.0 billion, $100 million, $150 million and $250 million for Exelon Corporate, ComEd, PECO, and Generation, respectively. Sublimits under the credit agreements can change upon written notification to the bank group. Exelon Corporate, ComEd, PECO and Generation had approximately $955 million, $80 million, $148 million and $170 million of unused bank commitments under the credit agreements, respectively, at December 31, 2003. At December 31, 2003, commercial paper outstanding was $280 million and $46 million at Exelon Corporate and PECO, respectively. ComEd and Generation did not have any commercial paper outstanding at December 31, 2003. Interest rates on the advances under the credit facility are based on either the London Interbank Offering Rate (LIBOR) or prime plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum adder would be 175 basis points.

The credit agreements require Exelon Corporate, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon Corporate and Generation, revenues from Exelon New England and interest on the debt of Exelon New England’s project subsidiaries. Exelon Corporate is measured at the Exelon consolidated level. At December 31, 2003, Exelon Corporate, ComEd, PECO and Generation were in compliance with the credit agreement thresholds. The following table summarizes the minimum thresholds reflected in the credit agreement for the twelve-month period ended December 31, 2003:

    Exelon
Corporate		   ComEd   PECO   Generation

Credit agreement threshold

   2.65 to 1   2.25 to 1   2.25 to 1   3.25 to 1
  
 
 
 

 

At December 31, 2003, our capital structure consisted of 62% of long-term debt, including long-term debt to financing trusts, 35% common equity, 3% notes payable and less than 1% preferred securities of subsidiaries. Total debt included $6.2 billion owed to unconsolidated affiliates of ComEd and PECO that qualify as special purpose entities under FIN No. 46-R. These special purpose entities were created for the sole purpose of issuing debt obligations to securitize intangible transition property and CTCs of Energy Delivery or mandatorily redeemable preferred securities. See Note 1 of the Notes to Consolidated Financial Statements for further information regarding FIN No. 46-R.

 

Boston Generating Project Debt

Boston Generating has a $1.25 billion credit facility (Boston Generating Facility), which was entered into primarily to finance the development and construction of the Mystic 8 and 9 and Fore River generating facilities. Approximately $1.0 billion of debt was outstanding under the credit facility at December 31, 2003, all of which was reflected in our Consolidated Balance Sheet as a current liability due to certain events of default described below. The Boston Generating Facility is non-recourse to us and an event of default under the Boston Generating Facility does not constitute an event of default under any other of our debt instruments or the debt instruments of our subsidiaries.

The Boston Generating Facility required that all of the projects achieve “Project Completion,” as defined in the Boston Generating Facility (Project Completion) by July 12, 2003. Project Completion was not achieved by July 12, 2003, resulting in an event of default under the Boston Generating Facility. Mystic 8 and 9 and Fore River have begun commercial operation, although they have not yet achieved Project Completion.

We have commenced the process of an orderly transition out of the ownership of Boston Generating and the Mystic 8 and 9 and Fore River generating projects. Our decision to transition out of the projects was made as a result of our evaluation of the projects and discussions with the lenders under the Boston Generating Facility. We anticipate that this transition will occur in 2004.

 

37

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Generation Revolving Credit Facilities

On September 29, 2003, Generation closed on an $850 million revolving credit facility that replaced a $550 million revolving credit facility that had originally closed on June 13, 2003. Generation used the facility to make the first payment to Sithe relating to the $536 million note that was used to purchase Exelon New England. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003, payment of $236 million of the principal on the earlier of December 1, 2003 or upon a change of control of Generation, and payment of the remaining principal on the earlier of December 1, 2004, upon reaching certain Sithe liquidity requirements, or upon a change of control of Generation. Generation paid $446 million on the note to Sithe in 2003. Generation terminated the $850 million revolving credit facility on December 22, 2003.

 

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, we operate an intercompany money pool. Participation in the money pool is subject to authorization by our corporate treasurer. ComEd and its subsidiary, Commonwealth Edison of Indiana, Inc. (ComEd of Indiana), PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During 2003, ComEd and PECO had various contributions to the money pool, and Generation and BSC had various loans from the money pool as described in the attached table:

    

Maximum

Invested

   

Maximum

Borrowed

  

December 31, 2003

Contributed
(Borrowed)

  
  

ComEd

    $ 483    $ –   $ 405  

PECO

      59      –     –  

Generation

      –      395     (301 )

BSC

      –      104     (104 )
   
  
 

 

Security Ratings

Our access to the capital markets, including the commercial paper market, and our financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. In the fourth quarter of 2003, Standard & Poor’s Ratings Services affirmed our corporate credit ratings but revised its outlook to negative from stable. None of our borrowings is subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase fees and interest charges under our two $750 million credit agreements and certain other credit facilities.

 

The following table shows our securities ratings at December 31, 2003:

    Securities   Moody’s
Investors Service		   Standard & Poors
Corporation		  

Fitch Investors

Service, Inc.

Exelon

   Senior unsecured debt   Baa2   BBB+   BBB+
    Commercial paper   P2   A2   F2

ComEd

   Senior secured debt   A3   A-   A-
    Commercial paper   P2   A2   F2
    Transition bonds (a)   Aaa   AAA   AAA

PECO

   Senior secured debt   A2   A   A
    Commercial paper   P1   A2   F1
    Transition bonds (b)   Aaa   AAA   AAA

Generation

   Senior unsecured debt   Baa1   A-   BBB+
    Commercial paper   P2   A2   F2
  
 
 
 

 

(a) Issued by ComEd Transitional Funding Trust, an unconsolidated affiliate of ComEd.
(b) Issued by PECO Energy Transition Trust, an unconsolidated affiliate of PECO.

 

A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.

As part of the normal course of business, we routinely enter into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit our counterparties and us to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if Exelon or Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our

 

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net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Exelon or Generation’s situation at the time of the demand. If we can reasonably claim that we are willing and financially able to perform our obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

 

Shelf Registration

On September 25, 2003, we filed a shelf registration statement, to register the sale by Exelon of $2.0 billion of unsecured senior debt securities; common stock; stock purchase contracts; stock purchase units; preferred stock in one or more series; subordinated debt securities to be purchased by Exelon Capital Trust I, Exelon Capital Trust II and/or Exelon Capital Trust III; and guarantees of trust preferred securities sold by Exelon Capital Trust I, Exelon Capital Trust II, and Exelon Capital Trust III. The registration statement became effective on February 11, 2004. As of the date of this filing, no securities have been issued under this registration statement.

 

PUHCA Restrictions

We obtained an order from the SEC under PUHCA authorizing through March 31, 2004, financing transactions, including the issuance of common stock, preferred securities, long-term debt and short-term debt in an aggregate amount not to exceed $4.0 billion. On December 22, 2003, we filed an application (Financing Application) requesting financing authority in an aggregate amount not to exceed $8 billion for the new authorization period, April 1, 2004 through April 15, 2007. The Financing Application is still pending. As of December 31, 2003, there was $2.0 billion of financing authority remaining under the SEC order. The current order limits our short-term debt outstanding to $3.0 billion of the $4.0 billion total financing authority. The Financing Application requests that the short-term debt sub-limit restriction be eliminated. The SEC order also authorized us to issue guarantees of up to $4.5 billion outstanding at any one time. In the Financing Application, we requested an additional $1.5 billion of guaranty authority. At December 31, 2003, Exelon had provided $1.9 billion of guarantees under the SEC order. See Contractual Obligations and Off-Balance Sheet Arrangements in this section for further discussion of guarantees. The SEC order requires us to maintain a ratio of common equity to total capitalization (including securitization debt) of not less than 30%. At December 31, 2003, Exelon’s common equity ratio was 35%. Exelon expects that it will maintain a common equity ratio of at least 30%.

Under applicable law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless “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. Furthermore, a significant loss recorded at ComEd may limit the dividends that ComEd can distribute to Exelon. At December 31, 2003, Exelon had retained earnings of $2.3 billion, including ComEd’s retained earnings of $883 million (of which $709 million had been appropriated for future dividend payments), PECO’s retained earnings of $546 million and Generation’s undistributed earnings of $602 million. We are also limited by order of the SEC under PUHCA to an aggregate investment of $4.0 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). At December 31, 2003, we had invested $2.5 billion in EWGs, leaving $1.5 billion of investment authority under the order. In the Financing Application, we requested EWG authority in an aggregate amount not to exceed $7 billion.

 

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For additional information about:

 

– long-term debt, see Note 11 of the Notes to Consolidated Financial Statements
– notes payable, see Note 10 of the Notes to Consolidated Financial Statements
– operating leases, energy commitments, fuel purchase agreements and other purchase obligations, see Note 19 of the Notes to Consolidated Financial Statements
– regulatory commitments, see Note 4 of the Notes to Consolidated Financial Statements
– the spent nuclear fuel obligation, see Note 13 of the Notes to Consolidated Financial Statements
– the obligation to minority shareholders, see Note 19 of the Notes to Consolidated Financial Statements
– the contribution required to our pension plans to satisfy IRS minimum funding requirements, see Note 14 of the Notes to Consolidated Financial Statements

 

Two affiliates of Exelon New England have long-term supply agreements through December 2022 with Distrigas of Massachusetts, LLC (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreements, prices are indexed to New England gas markets. Exelon New England has guaranteed these entities’ financial obligations to Distrigas under the Distrigas agreements. It is currently anticipated that Exelon New England’s guaranty to Distrigas will continue following the eventual transfer of the owner -

 

Contractual Obligations and Off-Balance Sheet Arrangements

The following table summarizes our future estimated cash payments under existing contractual obligations, including payments due by period.

        Payment due within   Due 2009
and beyond
       
 
    Total   2004   2005-2006   2007-2008  

Long-term debt

   $ 9,284   $ 1,385   $ 1,159   $ 1,207   $ 5,533

Long-term debt to financing trusts

     6,070     470     1,629     1,950     2,021

Notes payable to Sithe

     90     90     –     –     –

Commercial paper

     326     326     –     –     –

Operating leases

     744     49     97     86     512

Power purchase obligations

     10,475     2,635     1,827     1,410     4,603

Fuel purchase agreements

     3,034     476     825     582     1,151

Other purchase obligations

     145     31     71     38     5

Chicago agreement(a)

     54     6     12     12     24

Regulatory commitments

     30     10     20     –     –

Spent nuclear fuel obligation

     867     –     –     –     867

Obligation to minority shareholders

     51     3     6     6     36

Pension IRS minimum funding requirement

     17     17     –     –     –

Decommissioning(b)

     2,997     –     –     –     2,997
  
 
 
 
 

Total contractual obligations

   $ 34,184   $ 5,498   $ 5,646   $ 5,291   $ 17,749
  
 
 
 
 

 

(a) On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation (Midwest Agreement). Under the terms of the agreement with Chicago, ComEd will pay Chicago $60 million over ten years to be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd’s fossil stations in 1999, to build a 500-MW generation facility.
(b) Represents the present value of our obligation to decommission nuclear plants.

 

ship interests in Boston Generating. This guaranty is non-recourse to Generation. At December 31, 2003, Exelon New England had net assets of approximately $70 million, exclusive of the Boston Generating net assets.

Exelon has committed to pay down approximately $30 million of the Exelon New England note during the first six months of 2004 to fund Sithe’s expected acquisition of the 40% of Sithe/Independence Power Partners, L.P. that it does not currently own.

Generation has an obligation to decommission its nuclear power plants. 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. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, the ICC permits ComEd, and the PUC permits PECO, to collect from their customers and deposit in nuclear decommissioning trust funds maintained by Generation amounts which, together with earnings thereon, will be used to decommission such nuclear facilities. Upon adoption of SFAS No. 143, Generation was required to re-measure its decommissioning liabilities at fair value and recorded an asset retirement obligation of $2.4 billion on January 1, 2003. Increases in the asset retirement obligation are recorded as operating and maintenance expense. At December 31, 2003, the asset retirement obligation recorded

 

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within Generation’s Consolidated Balance Sheet was $3.0 billion. Decommissioning expenditures are expected to occur primarily after the plants are retired and are currently estimated to begin in 2029 for plants currently in operation. To fund future decommissioning costs, Generation held $4.7 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2003. See Note 13 of the Notes to Consolidated Financial Statements for further discussion of Generation’s decommissioning obligation.

See Note 19 of the Notes to Consolidated Financial Statements for discussion of Exelon’s commercial commitments as of December 31, 2003.

 

IRS Refund Claims

ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS) and have made refundable prepayments of $11 million and $5 million, respectively, for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash flows to Exelon related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to our financial position, results of operations and cash flows. ComEd’s tax benefits for periods prior to the Merger would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. We cannot predict the timing of the final resolution of these refund claims.

 

Variable Interest Entities

Sithe. We are a 50% owner of Sithe and account for the investment as an unconsolidated equity investment. Based on our interpretation of FIN No. 46-R, it is reasonably possible that we will consolidate Sithe as of March 31, 2004. At December 31, 2003, Sithe had total assets of $1.5 billion (including the $90 million note from Generation) and total debt of $1.0 billion. The $1.0 billion of debt includes $588 million of subsidiary debt incurred in prior years primarily to finance the construction of six new generating facilities, $419 million of subordinated debt, $43 million of current portion of long-term debt, but excludes $469 million of non-recourse project debt associated with Sithe’s equity investments. For the year ended December 31, 2003, Sithe had revenues of $690 million and incurred a net loss of approximately $72 million. As of December 31, 2003, we had a $47 million investment in Sithe. We contractually do not own any interest in Sithe International, a subsidiary of Sithe. As such, a portion of Sithe’s net assets and results of operations would be eliminated from our Consolidated Balance Sheets and Consolidated Statements of Income through a minority interest if Sithe is consolidated under FIN No. 46-R as of March 31, 2004.

On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. This series of transactions is described below. Immediately prior to these transactions, Sithe was owned 49.9% by Generation, 35.2% by Apollo Energy, LLC (Apollo), and 14.9% by subsidiaries of Marubeni Corporation (Marubeni).

On November 25, 2003, entities controlled by Reservoir purchased certain Sithe entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, in exchange for $37 million ($21 million in cash and a $16 million two-year note); and entities controlled by Marubeni purchased all of Sithe’s entities and facilities outside of North America (other than Sithe Energies Australia (SEA) of which it purchased a 49% interest on November 24, 2003 for separate consideration) for $178 million. Marubeni agreed to acquire the remaining 51 % of SEA in 90 days if a buyer is not found, although discussions regarding an extension are ongoing.

Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company. The subsidiary holding the Sithe investment acquired the remaining Sithe interests from Apollo and Marubeni for $612 million using proceeds from a $580 million bridge financing and available cash. Generation sold a 50% interest in the newly formed holding company for $76 million to an entity controlled by Reservoir on November 25, 2003. On November 26, 2003, Sithe distributed $580 million of available cash to its parent, which then utilized the distributed funds to repay the bridge financing.

In connection with this transaction, Generation recorded obligations related to $39 million of guarantees in accordance with FIN No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others”. These guarantees were issued to protect Reservoir from credit exposure of certain counter-parties through 2015 and other indemnities. In determining the value of the FIN No. 45 guarantees, we utilized a probabilistic model to assess the possibilities of future payments under the guarantees.

Both Generation and Reservoir’s 50% interests in Sithe are subject to put and call options that could result in either party owning 100% of Sithe. While our intent is to fully divest Sithe, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors, such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. Any closing under either the put or

 

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call options is conditioned upon obtaining state and Federal regulatory approvals.

 

Financing Trusts of ComEd and PECO. During June 2003, PECO issued $103 million of subordinated debentures to PECO Energy Capital Trust IV (PECO Trust IV) in connection with the issuance by PECO Trust IV of $100 million of preferred securities (see Note 16 of the Notes to Consolidated Financial Statements). Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with FIN No. 46. The $103 million of subordinated debentures issued by PECO to PECO Trust IV was recorded as long-term debt to financing trusts within the Consolidated Balance Sheets.

Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding, LLC, ComEd Transitional Funding Trust, PECO Trust III and PECO Energy Transition Trust were deconsolidated from the financial statements of Exelon in conjunction with the adoption of FIN No. 46-R. Amounts of $6.1 billion owed by ComEd and PECO to these financing trusts was recorded as debt to financing trusts within the Consolidated Balance Sheets as of December 31, 2003.

 

Other. Exelon continues to review entities with which Exelon and its subsidiaries have business arrangements to determine if those entities are variable interest entities under FIN No. 46-R and, if so, whether consolidation of these entities will be required as of March 31, 2004.

 

PECO Accounts Receivable Agreement

PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. PECO entered into this agreement to diversify its funding sources at favorable floating interest rates. At December 31, 2003, PECO had sold a $225 million interest in accounts receivable, consisting of a $176 million interest in accounts receivable, which we accounted for as a sale under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities—a Replacement of FASB Statement No. 125,” and a $49 million interest in special agreement accounts receivable, which we accounted for as a long-term note payable. PECO must continue to service these receivables and must maintain the level of the accounts receivable at $225 million. If PECO fails to maintain that level, the cash that would otherwise be received by PECO under this program must be held in escrow until the level is met. At December 31, 2003 and 2002, PECO met this requirement and was not required to make any cash deposit.

 

Nuclear Insurance Coverage

We carry property damage, decontamination and premature decommissioning insurance for each station loss resulting from damage to our nuclear plants. Additionally, through our subsidiaries, we are a member of an industry mutual insurance company that provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. Finally, we participate in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. See Note 19 of the Notes to Consolidated Financial Statements for further discussion of nuclear insurance.

 

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 following areas require significant management judgment regarding the application of an accounting policy or in making estimates and assumptions to describe matters that are inherently uncertain and that may change in subsequent periods: accounting for derivative instruments, regulatory accounting, nuclear decommissioning, depreciable lives of property, plant and equipment, impairment of assets including goodwill, severance accounting, defined benefit pension and other postretirement welfare benefits, taxation, unbilled energy revenues and environmental costs. Further discussion of the application of these accounting policies can be found in the Notes to Consolidated Financial Statements.

 

Accounting for Derivative Instruments

We generally account for derivative financial instruments on our balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception or unless specific hedge accounting criteria are met. How such instruments are classified affects how they are reported in our financial statements. If the normal purchases and normal sales exception applies, then gains and losses are recognized when the underlying physical transaction affects earnings. If the derivative qualifies as a cash-flow hedge, changes in the fair value of the derivative are recorded in other comprehensive income in shareholders’ equity. If neither applies, then changes in the fair value of the derivative are recognized in our earnings.

The availability of the normal purchases and normal sales exception is based upon our assessment of the ability and intent to deliver or take delivery, which is based on internal models that forecast customer demand and electricity

 

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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.

Identification of an energy contract as a qualifying cash-flow hedge requires us to determine that the contract is in accordance with our Risk Management Policy, 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. We reassess these cash-flow hedges on a regular basis to determine if they continue to be effective and that the forecasted future transactions are probable. When the contract does not meet the effective or probable criteria of SFAS No. 133, hedge accounting is discontinued and the fair value of the derivative is recorded through earnings.

As a part of our accounting for derivatives, we 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 changes in the fair value we expect in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. We use 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, we use internal models to determine the fair value. These internal models include assumptions of the future prices of energy based on the specific energy market the energy is being purchased in using externally available forward market pricing curves for all periods possible under the pricing model. We use the Black model, a standard industry valuation model, to determine the fair value of energy derivative contracts that are marked-to-market. To determine the fair value of our outstanding interest-rate swap agreements we use external broker quotes or calculate the fair value internally using the Bloomberg swap valuation tool. This tool uses the most recent market inputs and is a widely accepted valuation methodology.

 

Regulatory Accounting

We account for our 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 us to reflect the effects of rate regulation in our financial statements. Use of SFAS No. 71 is applicable to our 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, 2003, we have concluded that the operations of ComEd and PECO meet the criteria. If we conclude in a future period that a separable portion of our business no longer meets the criteria, we are required to eliminate the financial statement effects of regulation for that part of our business, which would include the elimination of any regulatory assets and liabilities that had been recorded within our Consolidated Balance Sheets. The impact of not meeting the criteria of SFAS No. 71 could be material to our financial statements as a one time extraordinary item and through impacts on continuing operations. See Note 4 of the Notes to Consolidated Financial Statements 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, 2003, we had recorded $5.3 billion and $1.9 billion of regulatory assets and regulatory liabilities, respectively, within our Consolidated Balance Sheets. See Note 20 of the Notes to Consolidated Financial Statements for further information regarding our significant regulatory assets and liabilities.

For each regulatory jurisdiction where we conduct business, we 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 our 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 us 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 in the states where we 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

 

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current period earnings. A write-off of regulatory assets could impact our ability to pay dividends under PUHCA and state law.

 

Nuclear Decommissioning

We account for our obligation to decommission our nuclear generating plants under SFAS No. 143, “Asset Retirement Obligations” (SFAS No. 143), which requires that we make significant estimates of decommissioning costs to be incurred in future periods. We adopted SFAS No. 143 on January 1, 2003 and recorded income of $112 million (net of income taxes) as a cumulative effect of a change in accounting principle. For more information regarding the adoption and ongoing application of SFAS No. 143, see Note 1 and Note 13 of the Notes to Consolidated Financial Statements.

Upon the adoption of SFAS No. 143, we were required to estimate the fair value of our obligation for the future decommissioning of our nuclear generating plants. To estimate the fair value of the decommissioning obligation, we used a probability-weighted, discounted cash flow model with multiple scenarios. Key assumptions used in the determination of fair value included the following:

 

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

 

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

 

Probabilistic Cash Flow Models. Our probabilistic cash flow models included the assignment of probabilities to various cost levels and various timing scenarios. The probability of various timing scenarios incorporated the factors of current license lives and life extensions and the timing of Department of Energy (DOE) acceptance for disposal of spent nuclear fuel.

 

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

 

Changes in the assumptions underlying the items discussed above could have materially affected the decommissioning obligation recorded upon the adoption of SFAS No. 143 and could affect future costs related to decommissioning recorded in our consolidated financial statements. Under SFAS No. 143, the fair value of the nuclear decommissioning obligation is adjusted on an ongoing basis as the model input factors change.

 

Depreciable Lives of Property, Plant and Equipment

We 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. Effective July 1, 2002, ComEd decreased its depreciation rates based on a depreciation study, resulting in an annualized reduction in depreciation expense of $96 million. Effective April 1, 2001 and July 1, 2001, Generation extended the estimated service lives of certain non-AmerGen generating stations primarily based on service life extensions applied for with regulatory agencies, resulting in an annualized reduction in depreciation expense of $132 million. We anticipate extending the depreciable lives of the AmerGen stations beginning in January 2004 concurrent with our initial full month of 100% ownership. Additional changes to depreciation estimates in future periods could have a significant impact on the amount of depreciation charged to the financial statements. Depreciation expense for the year ended December 31, 2003 was $667 million.

 

Asset Impairments

 

Long-Lived Assets and Investments

We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The review of assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows. A variation in an assumption could result in a different conclusion regarding the realizability of the asset. The potential impact of recognizing an impairment of the assets reported within our Consolidated Balance Sheets, as well as on net income, could be and has been material to our consolidated financial statements.

In 2003, we recorded an impairment charge of $945 million (before income taxes) related to the long-lived assets of Boston Generating, an indirect wholly owned subsidiary of Generation, due to our decision to transition out of our ownership of Boston Generating. See Note 2 of the Notes to Consolidated Financial Statements for further information. In determining the amount of the impairment charge, we compared the carrying value of Boston Generating’s long-lived assets to their estimated fair value. The fair value was determined using estimated future discounted cash flows from those assets, which incorporated assumptions relative to the period of time that we will continue to own and operate Boston Generating. The time required to fully transition

 

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out of ownership of Boston Generating was uncertain and subject to change at the time the impairment charge was recorded. We utilized a discount rate based upon valuations of the business developed at the purchase date. A change in our assumptions, including estimated cash flows and the discount rate, could have had a significant impact on the amount of the impairment charge recorded.

In 2003, we recorded impairment charges totaling $255 million (before income taxes) associated with a decline in the fair value of Generation’s investment in Sithe. In reaching that decision, we considered various factors, including negotiations to sell our investment in Sithe, which indicated an other-than-temporary decline in fair value.

In 2003, we recorded impairment charges related to investments held by Enterprises of approximately $54 million (before income taxes). We had determined that an other-than-temporary decline in the fair value of these investments had occurred and considered various factors in our decision to record an impairment of the investments, including recent third-party valuations of the investments. The other-than-temporary determination was significant because any increase in fair value of these investments will not be recoverable until they are sold. Had we determined that the impairment was temporary, no impairment charge would have been recorded. The valuations of these investments, which formed the basis for the impairment charge, required assumptions regarding the future earnings potential of these investments. Actual results from these investments have fluctuated in the past and are expected to continue.

 

Goodwill

We have approximately $4.7 billion of goodwill recorded at December 31, 2003, which relates entirely to the ComEd goodwill within the Energy Delivery reporting unit. As described below, we recorded charges of $72 million (before income taxes) during 2003 to fully impair the goodwill that had been recorded within the Exelon Services and InfraSource reporting units of our Enterprises segment. We perform an assessment for impairment of our goodwill at least annually, or more frequently, if events or circumstances indicate that goodwill might be impaired. Application of the goodwill impairment test requires judgment, 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.

 

Energy Delivery. Our annual assessment of goodwill impairment at the Energy Delivery reporting unit was performed as of November 1, 2003 and this assessment determined that goodwill was not impaired. In our assessment, to estimate the fair value of the Energy Delivery reporting unit, we used a probability-weighted, discounted cash flow model with multiple scenarios. The determination of the fair value is dependent on many sensitive, interrelated and uncertain variables including changing interest rates, utility sector market performance, ComEd’s capital structure, market power prices, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors. Changes in these variables or in how they interrelate could result in a future impairment of goodwill at Energy Delivery, which could be material. Based on Energy Delivery’s expected cash flows, we do not anticipate a goodwill impairment at Exelon through the end of ComEd’s transition period in 2006. However, a hypothetical decrease of approximately 15% in Energy Delivery’s expected discounted cash flows could trigger an impairment of goodwill.

 

Exelon Services and InfraSource. Our annual assessment of goodwill impairment at the Exelon Services reporting unit (within our Enterprises segment) was also performed as of November 1, 2003. As we are actively negotiating to sell entities within the Exelon Services reporting unit, we used these negotiations as the basis for the fair value of the Exelon Services reporting unit used in Step I of the analysis. Our assumptions regarding estimated sales prices are subject to change as we continue to negotiate these transactions.

The first step of the annual impairment analysis, comparing the fair value of a reporting unit to its carrying value, including goodwill, indicated an impairment of the Exelon Services goodwill. The second step of the analysis, which compared the implied fair value of Exelon Services’ goodwill to the carrying value, indicated that the total goodwill of $24 million recorded at the Exelon Services reporting unit was impaired.

Due to the sale of certain of our InfraSource businesses, we performed an interim assessment of the goodwill recorded at the InfraSource reporting unit during the second quarter of 2003 and in advance of the annual assessment, which would have been performed as of November 1. Based upon this interim assessment, we recorded an impairment charge of approximately $48 million (before minority interest and income taxes) to fully impair this goodwill. We primarily considered the negotiated sales price of InfraSource in determining the need for an interim assessment and the amount of the goodwill impairment charge.

We recorded our 2003 goodwill impairment charges related to the Exelon Services and InfraSource reporting units as operating and maintenance expense within our Consolidated Statements of Income. As of December 31, 2003, there was no goodwill recorded within our Consolidated Balance Sheets related to the reporting units of the Enterprises segment.

 

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Severance Accounting

As part of the implementation of The Exelon Way, we identified approximately 1,500 positions for elimination by the end of 2004 and we are considering whether there are additional positions for elimination in 2005 and 2006. We provide severance benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with us and compensation level. We recorded charges in 2003 related to severance benefits that were considered probable and could 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 calculating the severance charge was the determination of the number of positions to be eliminated. We based our estimates on our current plans and our ability to determine the appropriate staffing levels to effectively operate the businesses. We may incur further severance costs associated with The Exelon Way if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.

 

Defined Benefit Pension and Other

Postretirement Welfare Benefits

We sponsor 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 14 of the Notes to Consolidated Financial Statement for further information regarding the accounting for our 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, we utilize assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increase and the anticipated rate of increase in health care costs.

The 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 2003 pension cost was 9.00% compared to 9.50% for 2002 and 2001. The weighted average EROA assumption used in calculating 2003 other postretirement benefit costs was 8.40% compared to 8.80% for 2002 and 2001. 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 6.25% at December 31, 2003 compared to 6.75% at December 31, 2002 and 7.35% at December 31, 2001. The reduction in discount rate is due to the decline in Moody’s Aa Corporate Bond Index in 2003 and 2002.

 

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, 2003

      Impact on
Pension Liability at
December 31, 2003		     

Impact on

2004

Pension Cost

Pension benefits

                        

Decrease discount rate by 0.5%

   $ 548      $ 481      $ 37

Decrease rate of return on plan assets by 0.5%

     –        –        34
 
  
Change in Actuarial Assumption  

Impact on

Other Postretirement

Benefit Obligation at
December 31, 2003

      Impact on
Postretirement
Benefit Liability at
December 31, 2003		      Impact on 2004
Postretirement
Benefit Cost

Postretirement benefits

                        

Decrease discount rate by 0.5%

   $ 178      $ –      $ 20

Decrease rate of return on plan assets by 0.5%

     –        –        5
 
  

 

The assumptions are reviewed at the beginning of each year during our 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.

 

We incurred approximately $320 million in costs in 2003 associated with our pension and postretirement benefit plans, inclusive of curtailment costs of $80 million associated with The Exelon Way. Although 2004 pension and postretirement benefit costs will depend on market conditions, our estimate is that our pension and postretirement benefit costs will not change significantly in 2004 as compared to 2003.

 

46

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

Taxation

We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes and ongoing appeals related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that we have taken. We must also assess our ability to generate capital gains in future periods to realize tax benefits associated with capital losses 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. As of December 31, 2003, we have not recorded an allowance against our deferred tax assets associated with impairment losses which will become capital losses when realized for income tax purposes. We believe these deferred tax assets will be realized in future periods. While we believe the resulting tax reserve balances as of December 31, 2003 reflect the most likely 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 additional adjustments to our consolidated financial statements and such adjustments could be material.

 

Unbilled Energy Revenues

Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of Energy Delivery 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 during the month 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 demand 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 as of December 31, 2003 included an estimate of $452 million for unbilled revenue as a result of unread meters at Energy Delivery and Exelon Energy Company. Increases in volumes delivered to the utilities’ customers 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 unchanged.

The determination of Generation’s energy sales 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 and corresponding unbilled revenue are recorded. Customer accounts receivable as of December 31, 2003 include unbilled energy revenues of $366 million at Generation. Increases in volumes delivered to the wholesale customers in the period would increase unbilled revenue.

 

Environmental Costs

As of December 31, 2003, we had accrued liabilities of $129 million for environmental investigation and remediation costs. These liabilities are based upon estimates with respect to the number of sites for which we will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties and the timing of the remediation work. Where timing and costs of expenditures can be reliably estimated, amounts are discounted. These amounts represent $105 million of the accrued liabilities total above. Where timing and amounts cannot be reliably estimated, amounts are recognized on an undiscounted basis. Such amounts represent $24 million of the accrued liabilities total above. Estimates can be affected by the factors noted above as well as by changes in technology, regulations or the requirements of local governmental authorities.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are exposed to market risks associated with commodity prices, credit, interest rates and equity prices. The inherent risk in market-sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, interest rates and equity security prices. Our RMC sets forth risk management policy and objectives and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning, vice president of strategy, vice president of audit services and officers from each of the business units. The RMC reports to the Exelon Board of Directors on the scope of our derivative and risk management activities.

 

Commodity Price Risk

Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and other factors. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity, energy and fossil fuels, including oil, gas, coal and emission allowances. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such

 

47

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

as weather, governmental environmental policies, changes in supply and demand, state and Federal regulatory policies and other events. Additionally, we have exposure to commodity price in relation to CTC revenues we collect from ComEd customers.

 

Normal Operations and Hedging Activities. Electricity available from our owned or contracted generation supply in excess of our obligations to customers, including Energy Delivery’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, we enter into physical contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge our anticipated exposures. The maximum length of time over which cash flows related to energy commodities are currently being hedged is three years. We have an estimated 89% hedge ratio in 2004 for our energy marketing portfolio. This hedge ratio represents the percentage of our forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. Energy Delivery’s retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. During peak periods our amount hedged declines to meet our commitment to Energy Delivery. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for our non-trading portfolio associated with a ten percent reduction in the annual average around-the-clock market price of electricity is approximately a $32 million decrease in net income. This sensitivity assumes an 89% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. We expect to actively manage our portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in our portfolio.

 

Proprietary Trading Activities. We began to use financial contracts for proprietary trading purposes in the second quarter of 2001. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to our energy marketing portfolio but represent a very small portion of our overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than one percent of our owned and contracted supply of electricity. 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 Exelon risk management group and Exelon’s RMC monitor the financial risks of the power marketing activities.

Our energy contracts are accounted for under SFAS No. 133. Most non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in Critical Accounting Policies and Estimates. Those that do not are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 and the ineffective portion of hedge contracts are recognized in earnings on a current basis.

The following detailed presentation of our trading and non-trading marketing activities at Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. We do not consider our proprietary trading to be a significant activity in our business; however, we believe it is important to include these risk management disclosures.

The following tables describe the drivers of our energy trading and marketing business and gross margin included in the income statement for the years ended December 31, 2003 and 2002. Normal operations and hedging activities represent the marketing of electricity available from Generation’s owned or contracted generation, including Energy Delivery’s retail load, sold into the wholesale market. As the information in these tables highlights, mark-to-market activities represent a small portion of the overall gross margin for Generation. Accrual activities, including normal purchases and sales, account for the majority of the gross margin. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices. Further delineation of gross margin by the type of accounting treatment typically afforded each type of activity is also presented (i.e., mark-to-market vs. accrual accounting treatment).

 

48

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

For the year ended December 31, 2003  

Normal Operations and

Hedging Activities (a)

    

Proprietary

Trading

     Total  
  

Mark-to-market activities:

                        

Unrealized mark-to-market gain/(loss)

                        

Origination unrealized gain/(loss) at inception

   $ –     $ –     $ –  

Changes in fair value prior to settlements(b)

     207       1       208  

Changes in valuation techniques and assumptions

     –       –       –  

Reclassification to realized at settlement of contracts

     (223 )     (4 )     (227 )

Total change in unrealized fair value

     (16 )     (3 )     (19 )

Realized net settlement of transactions subject to mark-to-market

     223       4       227  
  
 
 

Total mark-to-market activities gross margin

   $ 207     $ 1     $ 208  
  
 
 

Accrual activities:

                        

Accrual activities revenue

   $ 5,187     $ –     $ 5,187  

Hedge gains reclassified from OCI

     2,358       –       2,358  

Total revenue—accrual activities

     7,545       –       7,545  
   
  

Fuel and purchased power

     2,107       –       2,107  

Hedges of fuel and purchased power reclassified from OCI

     2,631       –       2,631  
   
  

Total fuel and purchased power

     4,738       –       4,738  
   
  

Total accrual activities gross margin

     2,807       –       2,807  
   
  

Total gross margin(c)

   $ 3,014     $ 1     $ 3,015  
   
  

 

(a) Normal operations and hedging activities only include derivative contracts Power Team enters into to hedge anticipated exposures related to our owned and contracted generation supply, but excludes our owned and contracted generating assets as well as Enterprises’ derivative contracts.
(b) Includes hedge ineffectiveness, recorded in earnings of $1 million.
(c) Total gross margin represents revenue, net of purchased power and fuel expense for Generation. This excludes a minimal amount of activity at Enterprises. See Note 15 of the Notes to Consolidated Financial Statements for further information.

 

For the year ended December 31, 2002   Normal Operations and
Hedging Activities (a)		     Proprietary
Trading		     Total  
  

Mark-to-market activities:

                        

Unrealized mark-to-market gain/(loss)

                        

Origination unrealized gain/(loss) at inception

   $ –     $ –     $ –  

Changes in fair value prior to settlements

     26       (29 )     (3 )

Changes in valuation techniques and assumptions

     –       –       –  

Reclassification to realized at settlement of contracts

     (20 )     20       –  
  
 
 

Total change in unrealized fair value

     6       (9 )     (3 )

Realized net settlement of transactions subject to mark-to-market

     20       (20 )     –  
  
 
 

Total mark-to-market activities gross margin

   $ 26     $ (29 )   $ (3 )
  
 
 

Accrual activities:

                        

Accrual activities revenue

   $ 6,785     $ –     $ 6,785  

Hedge gains reclassified from OCI

     76       –       76  
  
 
 

Total revenue—accrual activities

     6,861       –       6,861  
  
 
 

Fuel and purchased power

     4,230       –       4,230  

Hedges of fuel and purchased power reclassified from OCI

     23       –       23  
  
 
 

Total fuel and purchased power

     4,253       –       4,253  
  
 
 

Total accrual activities gross margin

     2,608       –       2,608  
  
 
 

Total gross margin(b)

   $ 2,634     $ (29 )   $ 2,605  
  
 
 

 

(a) Normal operations and hedging activities only include derivative contracts Power Team enters into to hedge anticipated exposures related to our owned and contracted generation supply, but excludes our owned and contracted generating assets as well as Enterprises’ derivative contracts.
(b) Total gross margin represents revenue, net of purchased power and fuel expense for Generation. This excludes a minimal amount of activity at Enterprises. See Note 15 of the Notes to Consolidated Financial Statements for further information.

 

49

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

The following table provides detail on changes in Generation’s mark-to-market net asset or liability balance sheet position from January 1, 2002 to December 31, 2003. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings, as shown in the previous table, as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets.

 

    Normal Operations and
Hedging Activities		     Proprietary
Trading		     Total  
  

Total mark-to-market energy contract net assets at January 1, 2002

   $ 78     $ 14     $ 92  

Total change in fair value during 2002 of contracts recorded in earnings

     26       (29 )     (3 )

Reclassification to realized at settlement of contracts recorded in earnings

     (20 )     20       –  

Reclassification to realized at settlement from OCI

     (53 )     –       (53 )

Effective portion of changes in fair value–recorded in OCI

     (210 )     –       (210 )

Purchase/sale of existing contracts or portfolios subject to mark-to-market

     11       –       11  
  
 
 

Total mark-to-market energy contract net assets (liabilities) at December 31, 2002

     (168 )     5       (163 )

Total change in fair value during 2003 of contracts recorded in earnings

     206       –       206  

Reclassification to realized at settlement of contracts recorded in earnings

     (223 )     (4 )     (227 )

Reclassification to realized at settlement from OCI

     273       –       273  

Effective portion of changes in fair value–recorded in OCI

     (305 )     –       (305 )
  
 
 

Total mark-to-market energy contract net assets (liabilities) at December 31, 2003

   $ (217 )   $ 1     $ (216 )
  
 
 

 

The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2003:

 

    Normal Operations and
Hedging Activities		     Proprietary
Trading		     Total  
  

Current assets

   $ 319     $ 3     $ 322  

Noncurrent assets

     99       1       100  
  
 
 

Total mark-to-market energy contract assets

     418       4       422  
  
 
 

Current liabilities

     (502 )     (3 )     (505 )

Noncurrent liabilities

     (133 )     –       (133 )
  
 
 

Total mark-to-market energy contract liabilities

     (635 )     (3 )     (638 )
  
 
 

Total mark-to-market energy contract net assets (liabilities)

   $ (217 )   $ 1     $ (216 )
  
 
 

 

The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2002:

    Normal Operations and
Hedging Activities		     Proprietary
Trading		     Total  
  

Current assets

   $ 186     $ 6     $ 192  

Noncurrent assets

     46       –       46  
  
 
 

Total mark-to-market energy contract assets

     232       6       238  
  
 
 

Current liabilities

     (276 )     –       (276 )

Noncurrent liabilities

     (124 )     (1 )     (125 )
  
 
 

Total mark-to-market energy contract liabilities

     (400 )     (1 )     (401 )
  
 
 

Total mark-to-market energy contract net assets (liabilities)

   $ (168 )   $ 5     $ (163 )
  
 
 

 

50

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

The majority of our contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that we believe provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, region and product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2003 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

The following table, which presents maturity and source of fair value of mark-to-market energy contract net liabilities, provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Generation’s total mark-to-market asset or liability. Second, this table provides the maturity, by year, of Generation’s net assets/liabilities, giving an indication of when these mark-to-market amounts will settle and either generate or require cash.

 

     Maturities within       
   
     
     2004     2005     2006     2007     2008    2009
and
Beyond		    Total Fair
Value		  
  
Normal Operations, qualifying cash-flow hedge contracts(1):                                                       

Actively quoted prices

    $ 32     $ –     $ –     $ –     $ –    $ –    $ 32  

Prices provided by other external sources

      (219 )     (23 )     (8 )     –       –      –      (250 )
   
 
 
 
 
  
  

Total

    $ (187 )   $ (23 )   $ (8 )   $ –     $ –    $ –    $ (218 )
   
 
 
 
 
  
  
Normal Operations, other derivative contracts(2):                                                       

Actively quoted prices

    $ 23     $ –     $ –     $ –     $ –    $ –    $ 23  

Prices provided by other external sources

      (26 )     9       5       –       –      –      (12 )

Prices based on model or other valuation methods

      7       (5 )     (9 )     (3 )     –      –      (10 )
   
 
 
 
 
  
  

Total

    $ 4     $ 4     $ (4 )   $ (3 )   $ –    $ –    $ 1  
   
 
 
 
 
  
  
Proprietary Trading, other derivative contracts(3):                                                       

Actively quoted prices

    $ 1     $ –     $ –     $ –     $ –    $ –    $ 1  

Prices provided by other external sources

      (1 )     1       –       –       –      –      –  

Prices based on model or other valuation methods

      –       –       –       –       –      –      –  
   
 
 
 
 
  
  

Total

    $ –     $ 1     $ –     $ –     $ –    $ –    $ 1  
   
 
 
 
 
  
  

Average tenor of proprietary trading portfolio(4)

                                                    1.0 years  
   
 
 
 
 
  
  

 

(1) Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in other comprehensive income.
(2) Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.
(3) Mark-to-market gains and losses on trading contracts are recorded in earnings.
(4) Following the recommendations of the Committee of Chief Risk Officers, the average tenor of the proprietary trading portfolio measures the average time to collect value for that portfolio. We measure the tenor by separating positive and negative mark-to-market values in our proprietary trading portfolio, estimating the mid-point in years for each and then reporting the highest of the two mid-points calculated. In the event that this methodology resulted in significantly different absolute values of the positive and negative cash flow streams, we would use the mid-point of the portfolio with the largest cash flow stream as the tenor.

 

 

 

51

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXELON CORPORATION AND SUBSIDIARY COMPANIES

 

The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of December 31, 2003. The data in the table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s hedges. The table also includes a roll-forward of Accumulated Other Comprehensive Income related to cash-flow hedges for the years ended December 31, 2003 and December 31, 2002, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest-rate hedging activities.

 

   

Total Cash-Flow Hedge Other Comprehensive Income Activity,

Net of Income Tax

  
   
    Power Team
Normal Operations and
Hedging Activities		    

Interest-Rate and

Other Hedges(1)

    

Total Cash-

Flow Hedges

  
  

Accumulated OCI, January 1, 2002

   $ 47     $ (2 )   $ 45  

Changes in fair value

     (128 )     (3 )     (131 )

Reclassifications from OCI to net income

     (33 )     –       (33 )
  
 
 

Accumulated OCI, December 31, 2002

     (114 )     (5 )     (119 )

Changes in fair value

     (186 )     (8 )     (194 )

Reclassifications from OCI to net loss

     167       –       167  
  
 
 

Accumulated OCI derivative loss at December 31, 2003

   $ (133 )   $ (13 )   $ (146 )
  
 
 
(1) Includes interest-rate hedges at Generation.

 

We use a Value-at-Risk (VaR) model to assess the market risk associated with financial derivative instruments entered into for proprietary trading purposes. The measured VaR represents an estimate of the potential change in value of our proprietary trading portfolio.

The VaR estimate includes a number of assumptions about current market prices, estimates of volatility and correlations between market factors. These estimates, however, are not necessarily indicative of actual results, which may differ because actual market rate fluctuations may differ from forecasted fluctuations and because the portfolio may change over the holding period.

We estimate VaR using a model based on the Monte Carlo simulation of commodity prices that captures the change in value of forward purchases and sales as well as option values. Parameters and values are backtested daily against daily changes in mark-to-market value for proprietary trading activity. Value-at-Risk assumes that normal market conditions prevail and that there are no changes in positions. We use a 95% confidence interval, one-day holding period, one-tailed statistical measure in calculating our VaR. This means that we may state that there is a one in 20 chance that, if prices move against our portfolio positions, our pre-tax loss in liquidating our portfolio in a one-day holding period would exceed the calculated VaR. To account for unusual events and loss of liquidity, we use stress tests and scenario analysis.

For financial reporting purposes only, we calculate several other VaR estimates. The higher the confidence interval, the less likely the chance that the VaR estimate would be exceeded. A longer holding period considers the effect of liquidity in being able to actually liquidate the portfolio. A two-tailed test considers potential upside in the portfolio in addition to the potential downside in the portfolio considered in the one-tailed test. The following table provides the VaR for all proprietary trading positions of Generation as of December 31, 2003.

    Proprietary Trading VaR
2003		  
  

95% Confidence level, one-day holding period, one-tailed

        

Period end

   $ –  

Average for the period

     (0.1 )

High

     (0.2 )

Low

     –  

95% Confidence level, ten-day holding period, two-tailed

        

Period end

   $ (0.1 )

Average for the period

     (0.5 )

High

     (0.9 )

Low

     (0.1 )

99% Confidence level, one-day holding period, two-tailed

        

Period end

   $ –  

Average for the period

     (0.2 )

High

     (0.3 )

Low

     –  
  

 

ComEd’s CTC Revenues. We have exposure to commodity price risk in relation to revenue collected from customers who elect to purchase energy from an ARES or the ComEd PPO. Revenues collected from customers electing the PPO include commodity charges at market-based prices and CTC revenues which are calculated to provide the customer with a credit for the market price for electricity. Because the change in revenues from customers electing the PPO is significantly offset by the change in CTC revenues, we do not believe that our exposure to such a market price decrease would be material.

 

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ComEd’s CTC revenues are also collected from customers who elect to purchase energy from an ARES. ComEd’s CTC rates are reset once a year in the spring, and customers can elect to lock in their CTC rates for a one-, two- or three-year term. Based on the current customers who have elected the one-year CTC rates, we have performed a sensitivity analysis to determine the net impact of a 10% increase in the average market price of electricity which would result in a $14 million decrease in CTC revenues. A 10% decrease in market prices would result in a $14 million increase in CTC revenues. The result may be significantly affected if additional customers elect to purchase energy from an ARES or if customers elect to purchase their energy from us.

 

Credit Risk

Credit risk for Energy Delivery is managed by the credit and collection policies of ComEd and PECO, which are consistent with state regulatory requirements. ComEd and PECO are each currently obligated to provide service to all electric customers within their respective franchised territories. For the year ended December 31, 2003, ComEd’s ten largest customers represented approximately 2% of its retail electric revenues and PECO’s ten largest customers represented approximately 7% of its retail electric and gas revenues. We record a provision for uncollectible accounts, based upon historical experience and third-party studies, to provide for the potential loss from nonpayment by these customers.

 

Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment. Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits and letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation’s credit exposure, net of collateral, as of December 31, 2003 and 2002. They further delineate that exposure by the credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through ISOs which are discussed below.

 

 

Rating as of December 31, 2003    Total
Exposure
Before Credit
Collateral		    Credit
Collateral		    Net
Exposure		    Number Of
Counterparties
Greater than 10%
of Net Exposure		    Net Exposure Of
Counterparties
Greater than 10%
of Net Exposure

Investment grade

    $ 116    $ –    $ 116    1    $ 20

Non-investment grade

      22      7      15    –      –

No external ratings

                                 

Internally rated–investment grade

      13      –      13    –      –

Internally rated–non-investment grade

      1      –      1    –      –
   
  
  
  
  

Total

    $ 152    $ 7    $ 145    1    $ 20
   
  
  
  
  

 

Rating as of December 31, 2002    Total
Exposure
Before Credit
Collateral		    Credit
Collateral		    Net
Exposure		    Number Of
Counterparties
Greater than
10% of Net
Exposure		    Net Exposure Of
Counterparties
Greater than
10% of Net
Exposure

Investment grade

    $ 156    $ –    $ 156    2    $ 71

Non-investment grade

      17      11      6    –      –

No external ratings

                                 

Internally rated–investment grade

      27      4      23    4      16

Internally rated–non-investment grade

      4      2      2    –      –
   
  
  
  
  

Total

    $ 204    $ 17    $ 187    6    $ 87
   
  
  
  
  

 

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     Maturity of Credit Risk Exposure
   
Rating as of December 31, 2003    Less than
2 Years		    2-5 Years    Exposure
Greater than
5 Years		    Total Exposure
Before Credit
Collateral

Investment grade

    $ 101    $ 15    $ –    $ 116

Non-investment grade

      22      –      –      22

No external ratings

                            

Internally rated–investment grade

      13      –      –      13

Internally rated–non-investment grade

      1      –      –      1
   
  
  
  

Total

    $ 137    $ 15    $ –    $ 152
   
  
  
  

 

Dynegy. Generation is a counterparty to Dynegy in various energy transactions. In early July 2002, the credit ratings of Dynegy were downgraded to below investment grade by two credit rating agencies. Generation has credit risk associated with Dynegy through Generation’s equity investment in Sithe. Sithe is a 60% owner of the Independence generating station, a 1,028-MW gas-fired facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. Sithe has entered into a contract to purchase the remaining 40% interest of the Independence generating station. As of December 31, 2003, Sithe had recognized an asset on its balance sheet related to the fair market value of the financial swap agreement with Dynegy that is marked-to-market under the terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. We estimate, as a 50% owner of Sithe, that the impairment would result in an after-tax reduction of our equity earnings of approximately $5 million.

In addition to the impairment of the financial swap asset, if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Sithe would likely incur a further impairment associated with the Independence plant. Depending upon the timing of Dynegy’s failure to fulfill its obligations and the outcome of any restructuring initiatives, Exelon could realize an after-tax charge of up to $30 million, net of a FIN No. 45 guarantee recorded in connection with Generation’s sale of 50% of Sithe to Reservoir. In the event of a sale of Exelon’s investment in Sithe to a third party, proceeds from the sale could be negatively affected by up to $74 million, which would represent an after-tax loss of up to $43 million. Additionally, the future economic value of AmerGen’s purchased power arrangement with Illinois Power Company, a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. On February 3, 2004, Dynergy announced an agreement to sell its subsidiary Illinois Power Company to a third party, which, upon closing of the transaction, would reduce Generation’s credit risk associated with Dynergy.

 

Midwest Generation. ComEd and Generation are parties to various transactions with Midwest Generation, a subsidiary of Edison Mission Energy (EME) and Edison Mission Midwest Holdings (EMMH). Although earlier public filings in 2003 by EME indicated credit issues, a filing in December 2003 indicated that EMMH has secured financing and re-paid its significant current debts. Thus, Exelon’s credit contingency risk associated with Midwest Generation has decreased during the fourth quarter of 2003.

 

Collateral. As part of the normal course of business, we routinely enter into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit our counterparties and us to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of our situation at the time of the demand. If we can reasonably claim that we are willing and financially able to perform our obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

 

ISOs. Generation participates in the following established, real-time energy markets, which are administered by ISOs: PJM, ISO New England, New York ISO, California ISO, Midwest ISO, Inc., Southwest Power Pool, Inc. and Texas, which is administered by the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are

 

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operated by the ISOs. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by the ISOs, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on our financial condition, results of operations or net cash flows.

 

Direct Financing Leases. Our consolidated balance sheet included a $465 million net investment in direct financing leases as of December 31, 2003. The investment in direct financing leases represents future minimum lease payments due at the end of the thirty-year lives of the leases of $1,492 million, less unearned income of $1,027 million. The future minimum lease payments are supported by collateral and credit enhancement measures including letters of credit, surety bonds and credit swaps issued by high credit quality financial institutions. Management regularly evaluates the credit worthiness of our counterparties to these direct financing leases.

 

Interest-Rate Risk

We use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. We also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, we use forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financing. These strategies are employed to achieve a lower cost of capital. As of December 31, 2003, a hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a $1 million decrease in pre-tax earnings for 2004.

ComEd has entered into fixed-to-floating interest-rate swaps in order to maintain its targeted percentage of variable-rate debt associated with fixed-rate debt issuances in the aggregate amount of $485 million. At December 31, 2003, these interest-rate swaps, designated as fair-value hedges, had an aggregate fair market value of $33 million based on the present value difference between the contract and market rates at December 31, 2003. If these derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount that would be paid by the counterparties to ComEd.

The aggregate fair value of our interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2003 is estimated to be $39 million. If the derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount the counterparties would pay us.

The aggregate fair value of our interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2003 is estimated to be $28 million. If the derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount the counterparties would pay us.

In 2003, ComEd entered into forward-starting interest-rate swaps in the aggregate notional amount of $440 million to lock in interest-rate levels in anticipation of future financings. The debt issuances that these swaps were hedging were considered probable; therefore, ComEd accounted for these interest-rate swap transactions as hedges. In connection with the 2003 issuances of First Mortgage Bonds, forward-starting interest-rate swaps with an aggregate notional amount of $1,070 million were settled with net cash proceeds to counterparties of $45 million that has been deferred in regulatory assets and is being amortized over the life of the First Mortgage Bonds as a net increase to interest expense. At December 31, 2003, ComEd has settled all of its interest-rate swaps, designated as cash-flow hedges.

In 2003, PECO entered into forward-starting interest-rate swaps in the aggregate notional amount of $360 million to lock in interest-rate levels in anticipation of future financings, in connection with the issuance of First and Refunding Mortgage Bonds. The debt issuances that these swaps were hedging were considered probable; therefore, PECO accounted for these interest-rate swap transactions as hedges. PECO settled these swaps for net cash proceeds of $1 million, which was recorded in other comprehensive income and is being amortized over the life of the debt issuance.

PETT has entered into floating to fixed interest-rate swaps to manage interest rate exposure associated with the floating rate series of transition bonds issued to securitize PECO’s stranded cost recovery. These interest-rate swaps were designated as cash-flow hedges. These interest-rate swaps had an aggregate fair market value exposure of $11 million at December 31, 2003. As of December 31, 2003 PETT, a wholly owned subsidiary, was deconsolidated from the financial statements of PECO.

Under the terms of the Boston Generating Facility, Boston Generating is required to effectively fix the interest rate on 50% of borrowings under the facility through its maturity in 2007. As of December 31, 2003, Boston Generating had entered into interest-rate swap agreements that effectively fixed the interest-rate on $861 million of notional principal, or approximately 83% of borrowings outstanding under the Boston Generating Facility at December 31, 2003. The fair market value exposure of these swaps, designated as cash-flow hedges, was $77 million based on the present value dif -

 

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ferences between the contract and market rates at December 31, 2003.

The aggregate fair value exposure of our interest-rate swaps designated as cash-flow hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2003 is estimated to be $89 million. If the derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount we would pay to the counterparties.

The aggregate fair value exposure of our interest-rate swaps designated as cash-flow hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2003 is estimated to be $65 million. If the derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount we would pay to the counterparties.

In January 2004, the counterparties terminated the interest-rate swaps with Boston Generating. The total net value of these swaps as of the respective termination dates was $82 million, which is a net payable to the counterparties.

In 2003, Generation entered into forward-starting interest-rate swaps in the aggregate notional amount of $500 million to lock in interest-rate levels in anticipation of future financings. The debt issuances that these swaps are hedging were considered probable; therefore, Generation accounted for these interest-rate swap transactions as hedges. In connection with Generation’s 2003 issuance of Senior Notes, Generation settled swaps with an aggregate notional amount of $500 million for net cash proceeds of $1 million, which was recorded in other comprehensive income and is being amortized over the life of the debt issuance.

 

Equity Price Risk

We maintain trust funds, as required by the NRC, to fund certain costs of decommissioning our nuclear plants. As of December 31, 2003, our decommissioning trust funds are reflected at fair value on our Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs. However, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocation in accordance with our nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $303 million reduction in the fair value of the trust assets. See Defined Benefit Pension and Other Postretirement Welfare Benefits in the Critical Accounting Estimates section for information regarding the pension and other postretirement benefit trust assets.

 

NEW ACCOUNTING PRONOUNCEMENTS

 

See Note 1 of the Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

 

FORWARD-LOOKING STATEMENTS

 

Except for the historical information contained in this report, certain of the matters discussed in this Report are forward- looking statements that are subject to risks and uncertainties. The factors that could cause actual results to differ materially include those we have discussed in this report as well as those listed in Note 19 of the Notes to Consolidated Financial Statements and other factors discussed in our filings with the SEC. Readers should not place undue reliance on these forward-looking statements, which speak only as of the date of this Report. We undertake no obligation to publicly release any revision to these forward-looking statements to reflect events or circumstances after the date of this Report.